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Table of Contents

 

 

 

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, 2010

 

or

 

o         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  o 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).  o Yes  o 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 o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

 

Smaller reporting company o

(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).  o 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 July 30, 2010

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

 

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

27

Item 4.

Controls and Procedures

33

 

 

 

PART II OTHER INFORMATION

 

 

 

 

Item 1.

Legal Proceedings

33

Item 1A.

Risk Factors

34

Item 6.

Exhibits

35

 

 

 

SIGNATURES

36

 

 

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).  Additional information on Xcel Energy is available on various filings with the Securities and Exchange Commission (SEC).

 

2



Table of Contents

 

PART 1.  FINANCIAL INFORMATION

 

Item 1.  FINANCIAL STATEMENTS

 

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands of dollars)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

Operating revenues

 

 

 

 

 

 

 

 

 

Electric

 

$

 842,620

 

$

 787,584

 

$

 1,692,852

 

$

 1,656,666

 

Natural gas

 

68,227

 

74,516

 

340,620

 

403,783

 

Other

 

5,443

 

4,304

 

9,925

 

9,338

 

Total operating revenues

 

916,290

 

866,404

 

2,043,397

 

2,069,787

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

Electric fuel and purchased power

 

351,653

 

314,163

 

724,733

 

696,309

 

Cost of natural gas sold and transported

 

36,220

 

43,530

 

240,546

 

304,727

 

Cost of sales — other

 

2,869

 

2,547

 

5,570

 

5,015

 

Other operating and maintenance expenses

 

263,576

 

245,634

 

512,588

 

488,730

 

Conservation program expenses

 

15,965

 

12,742

 

35,451

 

27,403

 

Depreciation and amortization

 

99,258

 

97,108

 

195,540

 

201,117

 

Taxes (other than income taxes)

 

39,387

 

35,390

 

79,607

 

72,212

 

Total operating expenses

 

808,928

 

751,114

 

1,794,035

 

1,795,513

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

107,362

 

115,290

 

249,362

 

274,274

 

 

 

 

 

 

 

 

 

 

 

Other income (expense), net

 

21

 

(124

)

(357

)

(142

)

Allowance for funds used during construction — equity

 

8,056

 

7,665

 

17,501

 

14,371

 

 

 

 

 

 

 

 

 

 

 

Interest charges and financing costs

 

 

 

 

 

 

 

 

 

Interest charges — includes other financing costs of $1,413, $1,480, $2,811 and $2,947, respectively

 

49,352

 

49,827

 

99,533

 

99,912

 

Allowance for funds used during construction — debt

 

(4,135

)

(4,610

)

(9,477

)

(8,952

)

Total interest charges and financing costs

 

45,217

 

45,217

 

90,056

 

90,960

 

 

 

 

 

 

 

 

 

 

 

Income before income taxes

 

70,222

 

77,614

 

176,450

 

197,543

 

Income taxes

 

26,182

 

27,716

 

68,271

 

71,446

 

Net income

 

$

 44,040

 

$

 49,898

 

$

 108,179

 

$

 126,097

 

 

See Notes to Consolidated Financial Statements

 

3



Table of Contents

 

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

 

 

 

Six Months Ended June 30,

 

 

 

2010

 

2009

 

Operating activities

 

 

 

 

 

Net income

 

$

108,179

 

$

126,097

 

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

 

 

 

 

 

Depreciation and amortization

 

193,484

 

203,849

 

Nuclear fuel amortization

 

49,551

 

37,713

 

Deferred income taxes

 

68,773

 

57,515

 

Amortization of investment tax credits

 

(1,558

)

(1,752

)

Allowance for equity funds used during construction

 

(17,501

)

(14,371

)

Net realized and unrealized hedging and derivative transactions

 

(6,099

)

5,662

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

21,978

 

88,107

 

Accrued unbilled revenues

 

46,542

 

75,265

 

Inventories

 

36,142

 

126,879

 

Recoverable purchased natural gas and electric energy costs

 

(11,244

)

(13,764

)

Other current assets

 

(35,812

)

(3,327

)

Accounts payable

 

(116,181

)

(103,856

)

Net regulatory assets and liabilities

 

(394

)

8,721

 

Other current liabilities

 

(16,065

)

699

 

Change in other noncurrent assets

 

(194

)

(23

)

Change in other noncurrent liabilities

 

(9,838

)

(32,685

)

Net cash provided by operating activities

 

309,763

 

560,729

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

Utility capital/construction expenditures

 

(575,303

)

(495,972

)

Allowance for equity funds used during construction

 

17,501

 

14,371

 

Purchase of investments in external decommissioning fund

 

(3,001,198

)

(1,014,130

)

Proceeds from sale of investments in external decommissioning fund

 

3,006,616

 

1,012,705

 

Investments in utility money pool arrangement

 

(41,500

)

(55,500

)

Repayments from utility money pool arrangement

 

48,500

 

55,500

 

Advances to affiliate

 

(190,500

)

(33,200

)

Advances from affiliate

 

206,000

 

33,200

 

Other investments

 

2,007

 

(1,037

)

Net cash used in investing activities

 

(527,877

)

(484,063

)

 

 

 

 

 

 

Financing activities

 

 

 

 

 

Proceeds from (repayment of) short-term borrowings, net

 

45,000

 

(65,000

)

Borrowings under utility money pool arrangement

 

479,500

 

160,500

 

Repayments under utility money pool arrangement

 

(419,500

)

(186,000

)

Repayment of long-term debt

 

(91

)

(34

)

Capital contributions from parent

 

211,431

 

132,728

 

Dividends paid to parent

 

(116,091

)

(115,671

)

Net cash provided by (used in) financing activities

 

200,249

 

(73,477

)

 

 

 

 

 

 

Net (decrease) increase in cash and cash equivalents

 

(17,865

)

3,189

 

Cash and cash equivalents at beginning of period

 

46,303

 

12,343

 

Cash and cash equivalents at end of period

 

$

28,438

 

$

15,532

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

(91,308

)

$

(86,501

)

Cash paid for income taxes, net

 

(25,974

)

(14,430

)

Supplemental disclosure of non-cash investing transactions:

 

 

 

 

 

Property, plant and equipment additions in accounts payable

 

$

24,387

 

$

11,451

 

 

See Notes to Consolidated Financial Statements

 

4



Table of Contents

 

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

 

 

 

June 30, 2010

 

Dec. 31, 2009

 

Assets

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

28,438

 

$

46,303

 

Notes receivable from affiliates

 

 

15,500

 

Investments in utility money pool arrangement

 

 

7,000

 

Accounts receivable, net

 

273,736

 

300,103

 

Accounts receivable from affiliates

 

35,634

 

31,245

 

Accrued unbilled revenues

 

182,796

 

229,338

 

Inventories

 

219,777

 

255,919

 

Recoverable purchased natural gas and electric energy costs

 

41,672

 

30,428

 

Derivative instruments valuation

 

40,252

 

59,482

 

Prepayments and other

 

87,673

 

81,688

 

Total current assets

 

909,978

 

1,057,006

 

 

 

 

 

 

 

Property, plant and equipment, net

 

7,328,995

 

6,958,656

 

 

 

 

 

 

 

Other assets

 

 

 

 

 

Nuclear decommissioning fund and other investments

 

1,262,554

 

1,264,687

 

Regulatory assets

 

821,314

 

797,663

 

Derivative instruments valuation

 

109,168

 

117,216

 

Other

 

22,991

 

23,581

 

Total other assets

 

2,216,027

 

2,203,147

 

Total assets

 

$

10,455,000

 

$

10,218,809

 

 

 

 

 

 

 

Liabilities and Equity

 

 

 

 

 

Current liabilities

 

 

 

 

 

Current portion of long-term debt

 

$

175,027

 

$

175,037

 

Short-term debt

 

45,000

 

 

Borrowings under utility money pool arrangement

 

60,000

 

 

Accounts payable

 

317,074

 

407,500

 

Accounts payable to affiliates

 

48,219

 

83,759

 

Taxes accrued

 

102,727

 

125,650

 

Accrued interest

 

63,493

 

62,780

 

Dividends payable to parent

 

58,479

 

58,415

 

Derivative instruments valuation

 

23,030

 

24,661

 

Other

 

63,800

 

59,353

 

Total current liabilities

 

956,849

 

997,155

 

 

 

 

 

 

 

Deferred credits and other liabilities

 

 

 

 

 

Deferred income taxes

 

1,277,515

 

1,234,366

 

Deferred investment tax credits

 

35,576

 

37,134

 

Asset retirement obligations

 

818,820

 

797,476

 

Regulatory liabilities

 

464,139

 

469,769

 

Pension and employee benefit obligations

 

314,551

 

310,066

 

Derivative instruments valuation

 

202,629

 

209,528

 

Other

 

101,280

 

83,965

 

Total deferred credits and other liabilities

 

3,214,510

 

3,142,304

 

 

 

 

 

 

 

Commitments and contingent liabilities

 

 

 

 

 

Capitalization

 

 

 

 

 

Long-term debt

 

2,838,597

 

2,838,141

 

Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares

 

10

 

10

 

Additional paid-in capital

 

2,240,023

 

2,028,593

 

Retained earnings

 

1,202,919

 

1,210,894

 

Accumulated other comprehensive income

 

2,092

 

1,712

 

Total common stockholder’s equity

 

3,445,044

 

3,241,209

 

Total liabilities and equity

 

$

10,455,000

 

$

10,218,809

 

 

See Notes to Consolidated Financial Statements

 

5



Table of Contents

 

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, 2010 and Dec. 31, 2009; the results of its operations for the three and six months ended June 30, 2010 and 2009; and its cash flows for the six months ended June 30, 2010 and 2009.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after June 30, 2010 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, 2009 balance sheet information has been derived from the audited 2009 financial statements.  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 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, 2009, filed with the SEC on March 1, 2010.  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 NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

 

2.   Accounting Pronouncements

 

Recently Adopted

 

Consolidation of Variable Interest Entities — In June 2009, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the FASB Accounting Standards Codification (ASC or Codification) are effective for interim and annual periods beginning after Nov. 15, 2009.  NSP-Minnesota implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements.  For further information and required disclosures regarding variable interest entities, see Note 6 to the consolidated financial statements.

 

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (Accounting Standards Update (ASU) No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010.  NSP-Minnesota implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements.  For further information and required disclosures, see Note 8 to the consolidated financial statements.

 

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Table of Contents

 

3.   Selected Balance Sheet Data

 

(Thousands of Dollars)

 

June 30, 2010

 

Dec. 31, 2009

 

Accounts receivable, net

 

 

 

 

 

Accounts receivable

 

$

291,836

 

$

322,778

 

Less allowance for bad debts

 

(18,100

)

(22,675

)

 

 

$

273,736

 

$

300,103

 

Inventories

 

 

 

 

 

Materials and supplies

 

$

113,097

 

$

105,508

 

Fuel

 

79,283

 

99,705

 

Natural gas

 

27,397

 

50,706

 

 

 

$

219,777

 

$

255,919

 

Property, plant and equipment, net

 

 

 

 

 

Electric plant

 

$

9,807,527

 

$

9,679,288

 

Natural gas plant

 

959,569

 

948,708

 

Common and other property

 

482,682

 

472,624

 

Construction work in progress

 

916,235

 

587,080

 

Total property, plant and equipment

 

12,166,013

 

11,687,700

 

Less accumulated depreciation

 

(5,145,039

)

(5,030,836

)

Nuclear fuel

 

1,793,249

 

1,737,469

 

Less accumulated amortization

 

(1,485,228

)

(1,435,677

)

 

 

$

7,328,995

 

$

6,958,656

 

 

4.   Income Taxes

 

Medicare Part D Subsidy Reimbursements In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.  Based on this provision, NSP-Minnesota is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.

 

NSP-Minnesota expensed approximately $3.3 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010.  NSP-Minnesota does not expect the $3.3 million of additional tax expense to recur in future periods.  However, the 2010 effective tax rate (ETR) will increase due to additional tax expense of approximately $0.8 million associated with current year retiree health care accruals.

 

Federal AuditNSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. During the first quarter of 2010, the Internal Revenue Service (IRS) completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expires on Aug. 28, 2010. The IRS audit of tax years 2008 and 2009 is expected to begin during the fourth quarter of 2010.

 

State AuditsNSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2010, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004.  In 2009, Xcel Energy received a request for information from the state of Minnesota relating to tax years 2002 through 2007 in order to determine whether to undertake an audit of those years.  During the second quarter of 2010, the state of Minnesota informed Xcel Energy that its information requests related to the years 2002 through 2007 had been fulfilled and that the state does not intend to perform an audit on these years at this time.  There currently are no state income tax audits in progress.

 

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

 

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Table of Contents

 

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

 

(Millions of Dollars)

 

June 30, 2010

 

Dec. 31, 2009

 

Unrecognized tax benefit - Permanent tax positions

 

$

2.6

 

$

2.7

 

Unrecognized tax benefit - Temporary tax positions

 

11.8

 

9.8

 

Unrecognized tax benefit balance

 

$

14.4

 

$

12.5

 

 

The unrecognized tax benefit balance was 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 were as follows:

 

(Millions of Dollars)

 

June 30, 2010

 

Dec. 31, 2009

 

Tax benefits associated with NOL and tax credit carryforwards

 

$

(2.9

)

$

(2.8

)

 

The increase in the unrecognized tax benefit balance of $1.0 million from March 31, 2010 to June 30, 2010 and $1.9 million from Dec. 31, 2009 to June 30, 2010 was due to the addition of similar uncertain tax positions related to ongoing activity. NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months when the IRS and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

 

5.   Rate Matters

 

Except to the extent noted below, the circumstances set forth in Note 13 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

 

Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

 

Base Rate

 

NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $16.2 million for 2010 based on a return on equity (ROE) of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million.  The overall request seeks an additional $3.5 million, effective Jan. 1, 2011, for recovery of pension funding costs necessary to comply with federal law.  In December 2009, the MPUC approved an interim rate increase of $11.1 million, subject to refund.  Interim rates went into effect on Jan. 11, 2010.

 

In May 2010, the Office of Energy Security (OES) filed direct testimony recommending a rate increase of $1.8 million based on a 9.67 percent ROE.  The Minnesota Office of Attorney General (OAG) made several adjustments.  In addition to ROE, both parties focused on adjustments to bad debt expense, distribution operating and maintenance expenses (O&M), cost of debt and pension expense.

 

Evidentiary hearings were held in June 2010.  By the end of the hearings, NSP-Minnesota made several adjustments to reflect more recent information, accepted the OES position on distribution O&M, and is currently seeking an increase of $10.0 million based on a 10.6 percent ROE.  The OES revised its case and is now recommending an increase of approximately $7.5 million based on a 10.09 percent ROE.  NSP-Minnesota and OAG agreed on treatment of pension issues, for future rate proceedings, and NSP-Minnesota is no longer seeking a 2011 step-in of pension expense.  The OAG continues to recommend further adjustments in bad debt expense, distribution O&M and the cost of debt.

 

The remaining procedural schedule is listed as follows:

 

·                  Reply briefs and proposed findings due Aug. 19, 2010; and

·                  Administrative law judge (ALJ) report due Oct. 1, 2010.

 

A decision from the MPUC in this proceeding is expected in the fourth quarter of 2010.

 

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Electric, Purchased Gas and Resource Adjustment Clauses

 

Transmission Cost Recovery (TCR) Rider — The MPUC has approved a TCR rider that allows annual adjustments to retail electric rates to provide recovery of certain incremental transmission investments between rate cases.  On April 27, 2010, the MPUC approved the 2010 TCR rider that will recover approximately $10.8 million in 2010, including initial costs associated with three of the four CapX 2020 transmission projects.  The MPUC did not allow 2010 recovery of $1.2 million in costs associated with the Brookings, S.D.-Hampton, Minn.  CapX 2020 transmission line because of uncertainty regarding cost allocation as the result of impending Midwest Independent Transmission System Operator, Inc. (MISO) tariff changes.  NSP-Minnesota filed a request to reconsider the MPUC’s determination regarding the Brookings S. D. project.  The reconsideration request is pending MPUC action.  MISO filed the proposed cost allocation tariff changes with the Federal Energy Regulatory Commission (FERC) on July 15, 2010.  The MPUC also expressed a desire to limit TCR to the initial project cost estimates and address any potential additional amounts in general rate cases.  This approach to rider administration does not impact the 2010 TCR request.

 

Renewable Energy Standard (RES) Rider — The MPUC has approved a rider to recover the costs for utility-owned projects implemented in compliance with the Minnesota RES.  On April 1, 2010, the MPUC approved the 2010 RES rider that will result in $45.6 million in revenue.  As noted with the TCR rider above, the MPUC also expressed a desire to limit recovery based on initial project estimates and address any potential additional amounts in general rate cases.  This approach to rider administration is not expected to have a material impact in 2010.

 

Annual Automatic Adjustment Report for 2008/2009 — In September 2009, NSP-Minnesota filed its annual electrical and natural gas automatic adjustment reports for July 1, 2008 through June 30, 2009.  During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the fuel clause adjustment (FCA).  In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered from Minnesota natural gas customers through the purchased gas adjustment (PGA).  On June 18, 2010, the OES filed comments recommending approval of the 2008/2009 natural gas automatic adjustment report.  Final MPUC action is pending.  Comments on NSP-Minnesota’s 2009 electric report are due in January 2011.  FCA and PGA recovery remains provisional and potentially subject to refund until the MPUC issues an order approving the automatic adjustment report for the period.

 

6.   Commitments and Contingent Liabilities

 

Except as noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 13, 14 and 15 to the consolidated financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 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.

 

Commitments

 

Variable Interest Entities — Effective Jan. 1, 2010, NSP-Minnesota adopted new guidance on consolidation of variable interest entities contained in ASC 810 Consolidation.  The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

 

Purchased Power Agreements — NSP-Minnesota has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

 

NSP-Minnesota has various pay-for-performance contracts with expiration dates through the year 2034.  In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments.  Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

 

NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

 

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Certain natural gas and biomass fueled purchased power agreements that either reimburse the independent power producing entities for fuel costs, or contain tolling arrangements under which NSP-Minnesota procures the fuel required to produce the energy it purchases, have been determined to be variable interest entities.

 

NSP-Minnesota has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over operations and maintenance, historical and estimated future fuel and electricity prices, and financing activities.  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.  As of June 30, 2010 and Dec. 31, 2009, NSP-Minnesota had approximately 1,064 megawatts (MW) of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.

 

Environmental Contingencies

 

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

 

Site Remediation NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including sites of former manufactured gas plants operated by NSP-Minnesota, its predecessors or other entities; and third party sites, such as landfills, for which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes.  At June 30, 2010, the liability for the cost of remediating these sites was estimated to be $0.3 million, of which $0.2 million was considered to be a current liability.

 

Third Party and Other Environmental Site Remediation

 

Asbestos Removal Some of NSP-Minnesota’s facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated.  NSP-Minnesota has recorded an estimate for final removal of the asbestos as an asset retirement obligation.  See additional discussion of asset retirement obligations in Note 14 of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2009.  It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

 

Other Environmental Requirements

 

Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Rulemaking — On Dec. 7, 2009, in response to the U. S. Supreme Court’s decision in Massachusetts v. EPA, 549 U. S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere.  This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty vehicles.  The EPA finalized GHG efficiency standards for light duty vehicles in spring of 2010 and has promulgated permitting requirements for GHGs for large new and modified stationary sources, such as power plants.  These regulations will become applicable in 2011.

 

Clean Air Interstate Rule (CAIR) — In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions.  The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota.  In 2008, the U. S. Court of Appeals for the District of Columbia vacated and remanded CAIR.  On July 6, 2010, the EPA issued the proposed Clean Air Transport Rule (CATR), which would replace CAIR by requiring SO2 and NOx reductions in 31 states and the District of Columbia.  The EPA is proposing to reduce these emissions through federal implementation plans for each affected state.  The EPA’s preferred approach would set emission limits for each state and allow limited interstate emissions trading.  As proposed, CATR will impact Minnesota for annual SO2 and NOx emissions.  NSP-Minnesota is analyzing the proposed rule to determine whether emission reductions are needed from its facilities.  Until CATR becomes final, NSP-Minnesota will continue activities to support CAIR compliance.  On Nov. 3, 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective Dec. 3, 2009.  Cost estimates are therefore not included at this time for NSP-Minnesota.

 

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Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants.  In February 2008, the U. S. Court of Appeals for the District of Columbia vacated CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules.  The EPA has agreed to finalize Maximum Achievable Control Technology emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace CAMR.  NSP-Minnesota anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter.

 

Minnesota Mercury Legislation — In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants.  For NSP-Minnesota, the Act covers units at the A. S. King and Sherco generating facilities.  NSP-Minnesota installed and is operating and maintaining continuous mercury emission monitoring systems at these generating facilities.

 

In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans.  A sorbent injection control system was installed at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled for December 2010.  In November 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.

 

In December 2009, NSP-Minnesota filed its mercury control plan at Sherco Units 1 and 2 with the MPUC and the Minnesota Pollution Control Agency (MPCA).  In June 2010, the MPCA filed its comments on the Sherco Unit 1 and 2 mercury plan and believes the plan to be appropriate under the Act.  The MPUC has 180 days to either approve or disapprove the plan.  Assuming that the plan is approved, NSP-Minnesota expects to file for recovery of the costs to implement the plan through the mercury cost recovery rider.

 

Regional Haze Rules  In June 2005, the EPA finalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.

 

NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006.  The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART.  The MPCA completed their BART determination and proposed SO2 and NOx limits in the draft state implementation plan (SIP) that are equivalent to the reductions made under CAIR.

 

In October 2009, the U. S. Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2.  The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and, if so, whether the level of controls proposed by MPCA is appropriate.

 

The MPCA determined that this certification does not alter the proposed SIP.  The SIP proposes BART controls for the Sherco generating facilities that are designed to improve visibility in the national parks, but does not require Selective Catalytic Reduction (SCR) on Units 1 and 2.  The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs.  In December 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval.  The EPA is expected to complete its review of the SIP, as well as the Sherco Units 1 and 2 BART determination before the end of 2010.

 

Federal Clean Water Act — The federal Clean Water Act (CWA) requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts.  In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants.  Several lawsuits were filed against the EPA challenging the phase II rulemaking.  In April 2009, the U. S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA.  The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules.  Until the EPA fully responds, the rule’s compliance requirements and associated deadlines will remain unknown.  As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

 

As part of NSP-Minnesota’s 2009 CWA permit renewal for the Black Dog plant, the MPCA required that the plant submit a plan for compliance with the CWA.  The compliance plan was submitted for MPCA review and approval in April 2010.  The MPCA is currently reviewing the proposal in consultation with the EPA.  NSP-Minnesota anticipates approval of the plan by the end of 2010.

 

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Proposed Coal Ash Regulation —  In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as a special waste (subject to many of the requirements for hazardous waste) or as a solid (nonhazardous) waste.  Coal ash is currently exempt from hazardous waste regulation.  The EPA’s proposal would result in more comprehensive and expensive requirements related to management and disposal of coal ash.  There is a 90-day comment deadline to submit comments on the rule, but requests for extension of time to submit comments have been submitted to the EPA.  The EPA is also seeking comment on what regulations are appropriate for the beneficial reuse of coal ash.  The timing, scope and potential cost of any final rule that might be implemented are speculative and not determinable at this time.

 

Legal Contingencies

 

Lawsuits and claims arise in the normal course of business.  Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material adverse effect on NSP-Minnesota’s financial position and results of operations.

 

Environmental Litigation

 

Carbon Dioxide (CO2) Emissions Lawsuit — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U. S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of NSP-Minnesota, to force reductions in CO2 emissions.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  The lawsuits allege that CO2 emitted by each company is a public nuisance.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds.  On appeal in September 2009, the U. S. Court of Appeals for the Second Circuit reversed the lower court decision.  Defendants anticipate filing a petition for review with the U. S. Supreme Court.

 

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of NSP-Minnesota, received notice of a purported class action lawsuit filed in U. S. District Court in the Southern District of Mississippi.  The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.  In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds.  Plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Fifth Circuit.  In October 2009, the U. S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court.  A subsequent petition by defendants, including Xcel Energy, for en banc review was granted.  On May 28, 2010, U. S. Court of Appeals for the Fifth Circuit ruled that it lacked an en banc quorum of nine active members to hear the case.  It dismissed the appeal, which resulted in the reinstatement of the district court’s opinion dismissing the case.

 

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U. S. District Court for the Northern District of California against Xcel Energy, the parent company of NSP-Minnesota, and 23 other utilities, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008.  In October 2009, the U. S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Ninth Circuit.  It is unknown when the Ninth Circuit will render a final opinion.

 

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United States vs. Xcel Energy Inc. et al. — In June 2010, the U. S. Department of Justice and the EPA filed a complaint in the U. S. District Court in Minnesota against Xcel Energy, alleging that Xcel Energy has failed to fully respond to certain information requests issued by the EPA.  Over the last ten years, Xcel Energy has responded to numerous information requests from the EPA pursuant to section 114 of the CAA.  The requests focused on projects undertaken at Xcel Energy’s Sherco and Black Dog plants to determine whether these projects were carried out in compliance with the New Source Review.  Xcel Energy has complied with these requests and produced thousands of pages of documents.  In June 2009, the EPA issued a supplemental information request which, among other things, asked for documents related to projects that may be undertaken in the future at the plants.  Xcel Energy believes that the request for future project information exceeds the EPA’s CAA authority and serves no legitimate investigative purpose.  The EPA’s information-request authority is limited to information that is necessary and appropriate to determine whether or not Xcel Energy is in compliance with the CAA.  Planned future projects, on which construction has not begun and which may never be implemented, cannot be the basis of a CAA violation.  Xcel Energy believes that it has complied with its obligation to provide information and has filed a motion to dismiss the lawsuit.

 

Employment, Tort and Commercial Litigation

 

Siewert vs. Xcel Energy — In 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems.  Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system.  Plaintiffs claim losses of approximately $7 million.  NSP-Minnesota denies all allegations.  In December 2008, the Court of Appeals issued a decision ordering dismissal of plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial.  The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review and heard oral arguments in December 2009.  It is uncertain when the Minnesota Supreme Court will render a decision.

 

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 U. S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota.  At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004.  In September 2007, the court awarded NSP-Minnesota $116.5 million in damages.  In December 2007, the court denied the DOE’s motion for reconsideration.  In February 2008, the DOE filed an appeal to the U. S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue.  It is uncertain when the Court will issue a decision.  Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved.  Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.

 

In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U. S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract.  This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel.  Per the court’s scheduling order, NSP-Minnesota believes that it has suffered damages in excess of $250 million.  The DOE claims NSP-Minnesota is entitled to at most approximately $55 million.  Trial is expected to take place in late 2011.

 

EnviroTech Remediation Services, Inc. vs. Brandenburg Industrial Services Co., NSP- Minnesota, et al. In 2009, a mechanic’s lien foreclosure lawsuit was served against NSP-Minnesota by EnviroTech Remediation Services, Inc. (EnviroTech), and other defendants.  EnviroTech’s claims against NSP-Minnesota arise out of mechanics’ liens recorded by EnviroTech and its subcontractors against NSP-Minnesota’s High Bridge generating plant property in St. Paul, Minnesota, in the amount of approximately $7.0 million plus attorneys’ fees and interest.  EnviroTech is a subcontractor to Brandenburg Industrial Services Co. (Brandenburg), a general construction company hired by NSP-Minnesota to perform demolition services and asbestos and lead abatement work at the old High Bridge generating plant.  Brandenburg subcontracted part of its asbestos and lead abatement work to EnviroTech.  EnviroTech claims it and its subcontractors furnished additional work and materials during performance of the Brandenburg/EnviroTech subcontract.  EnviroTech seeks additional compensation from Brandenburg and NSP-Minnesota for the claimed extra work and materials.  Further, EnviroTech notified NSP-Minnesota it intends to assert an additional $3.0 million claim in the lawsuit for destruction of business against Brandenburg and NSP-Minnesota.

 

At a hearing in February 2010, the court stayed the lawsuit to allow EnviroTech and Brandenburg to proceed to binding arbitration, as required by the Brandenburg/EnviroTech subcontract.  NSP-Minnesota is not a party to the arbitration, which is expected to occur later this year.  In June 2010, NSP-Minnesota participated in court-ordered mediation with EnviroTech and Brandenburg.  The parties did not reach resolution at the mediation.  NSP-Minnesota denies liability, believes the lawsuit and claims are without merit, and will vigorously defend itself in this matter.

 

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7.   Short-Term Borrowings and Other Financing Instruments

 

Commercial Paper — The following table presents commercial paper outstanding for NSP-Minnesota:

 

(Millions of Dollars)

 

June 30, 2010

 

Dec. 31, 2009

 

Commercial paper outstanding

 

$

45

 

$

 

Weighted average interest rate

 

0.40

%

N/A

%

Total commercial paper available for issuance

 

$

482

 

$

482

 

 

Money Pool Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other.  The holding company 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 the holding company.

 

The following table presents money pool investments (borrowings) for NSP-Minnesota:

 

(Millions of Dollars)

 

June 30, 2010

 

Dec. 31, 2009

 

Money pool (borrowings) investments

 

$

(60

)

$

7

 

Weighted average interest rate

 

0.40

%

0.36

%

Money pool borrowing limit

 

$

250

 

$

250

 

 

8.   Derivative Instruments and Fair Value Measurements

 

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices, vehicle fuel prices, as well as variances in forecasted weather.

 

Short-Term Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various short-term 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 the policy.

 

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 a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

 

At June 30, 2010, accumulated other comprehensive income (OCI) related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

 

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, gas for resale, and vehicle fuel.

 

At June 30, 2010, NSP-Minnesota had vehicle fuel related contracts designated as cash flow hedges extending through December 2012.  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 OCI or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanism.  NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2010 and 2009.

 

At June 30, 2010, accumulated OCI related to commodity derivative cash flow hedges included $1.0 million of net losses 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 income, subject to applicable customer margin-sharing mechanisms.

 

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The following table details the gross notional amounts of commodity forwards, options, and financial transmission rights at June 30, 2010 and Dec. 31, 2009:

 

(Amounts in Thousands) (a)(b)

 

June 30, 2010

 

Dec. 31, 2009

 

Megawatt hours (MWh) of electricity

 

67,127

 

34,374

 

MMBtu of natural gas

 

11,247

 

9,777

 

Gallons of vehicle fuel

 

1,120

 

2,021

 

 


(a) Amounts are not reflective of net positions in the underlying commodities.

(b) Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

 

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated OCI, included as a component of common stockholder’s equity, is detailed in the following table:

 

 

 

Three Months Ended June 30,

 

(Thousands of Dollars)

 

2010

 

2009

 

Accumulated other comprehensive income related to cash flow hedges at April 1

 

$

4,254

 

$

3,548

 

After-tax net unrealized (losses) gains related to derivatives accounted for as hedges

 

(144

)

684

 

After-tax net realized losses on derivative transactions reclassified into earnings

 

258

 

565

 

Accumulated other comprehensive income related to cash flow hedges at June 30

 

$

4,368

 

$

4,797

 

 

 

 

Six Months Ended June 30,

 

(Thousands of Dollars)

 

2010

 

2009

 

Accumulated other comprehensive income related to cash flow hedges at Jan. 1

 

$

3,941

 

$

3,053

 

After-tax net unrealized (losses) gains related to derivatives accounted for as hedges

 

(133

)

561

 

After-tax net realized losses on derivative transactions reclassified into earnings

 

560

 

1,183

 

Accumulated other comprehensive income related to cash flow hedges at June 30

 

$

4,368

 

$

4,797

 

 

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2010 and June 30, 2009.  Therefore, no gains or losses from fair value hedges or related hedged transactions for these periods were recognized.

 

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The following tables detail the impact of derivative activity during the three and six months ended June 30, 2010 and June 30, 2009, respectively, on OCI, regulatory assets and liabilities, and income:

 

 

 

Three Months Ended June  30, 2010

 

 

 

Fair Value Changes Recognized

 

Pre-Tax Amounts Reclassified into

 

 

 

 

 

During the Period in:

 

Income During the Period from:

 

Pre-Tax Gains (Losses)

 

 

 

Other

 

Regulatory

 

Other

 

Regulatory

 

Recognized

 

 

 

Comprehensive

 

Assets and

 

Comprehensive

 

Assets and

 

During the Period

 

(Thousands of Dollars)

 

Income (Loss)

 

Liabilities

 

Income (Loss)

 

Liabilities

 

in Income

 

Derivatives designated as cash flow hedges

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

$

 

$

 

$

(27

)(a)

$

 

$

 

Vehicle fuel and other commodity

 

(244

)

 

464

(e)

 

 

Total

 

$

(244

)

$

 

$

437

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Other derivative instruments

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

$

 

$

 

$

 

$

 

 

$

497

(b)

Electric commodity

 

 

7,597

 

 

(2,111

)(c)

 

Natural gas commodity

 

 

(800

)

 

 

 

Total

 

$

 

$

6,797

 

$

 

$

(2,111

)

$

497

 

 

 

 

Six Months Ended June  30, 2010

 

 

 

Fair Value Changes Recognized

 

Pre-Tax Amounts Reclassified into

 

 

 

 

 

During the Period in:

 

Income During the Period from:

 

Pre-Tax Gains (Losses)

 

 

 

Other

 

Regulatory

 

Other

 

Regulatory

 

Recognized

 

 

 

Comprehensive

 

Assets and

 

Comprehensive

 

Assets and

 

During the Period

 

(Thousands of Dollars)

 

Income (Loss)

 

Liabilities

 

Income (Loss)

 

Liabilities

 

in Income

 

Derivatives designated as cash flow hedges

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

$

 

$

 

$

(54

)(a)

$

 

$

 

Vehicle fuel and other commodity

 

(226

)

 

1,000

(e)

 

 

Total

 

$

(226

)

$

 

$

946

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Other derivative instruments

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

$

 

$

 

$

 

$

 

$

6,127

(b)

Electric commodity

 

 

(9,582

)

 

(4,838

)(c)

 

Natural gas commodity

 

 

(7,845

)

 

586

(d)

 

Total

 

$

 

$

(17,427

)

$

 

$

(4,252

)

$

6,127

 

 

16



Table of Contents

 

 

 

Three Months Ended June  30, 2009

 

 

 

Fair Value Changes Recognized

 

Pre-Tax Amounts Reclassified into

 

 

 

 

 

During the Period in:

 

Income During the Period from:

 

Pre-Tax Gains (Losses)

 

 

 

Other

 

Regulatory

 

Other

 

Regulatory

 

Recognized

 

 

 

Comprehensive

 

Assets and

 

Comprehensive

 

Assets and

 

During the Period

 

(Thousands of Dollars)

 

Income (Loss)

 

Liabilities

 

Income (Loss)

 

Liabilities

 

in Income

 

Derivatives designated as cash flow hedges

 

 

 

 

 

 

 

 

 

 

 

Electric commodity

 

$

 

$

957

 

$

 

$

(1,243

)(c)

$

 

Vehicle fuel and other commodity

 

1,157

 

 

1,010

(e)

 

 

Total

 

$

1,157

 

$

957

 

$

1,010

 

$

(1,243

)

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Other derivative instruments

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

$

 

$

 

$

 

$

 

$

(460)

(b)

Electric commodity

 

 

45,079

 

 

(706

)(c)

 

Natural gas commodity

 

 

(1,076

)

 

 

 

Other

 

 

 

 

 

200

(b)

Total

 

$

 

$

44,003

 

$

 

$

(706

)

$

(260

)

 

 

 

Six Months Ended June  30, 2009

 

 

 

Fair Value Changes Recognized

 

Pre-Tax Amounts Reclassified into

 

 

 

 

 

During the Period in:

 

Income During the Period from:

 

Pre-Tax Gains (Losses)

 

 

 

Other

 

Regulatory

 

Other

 

Regulatory

 

Recognized

 

 

 

Comprehensive

 

Assets and

 

Comprehensive

 

Assets and

 

During the Period

 

(Thousands of Dollars)

 

Income (Loss)

 

Liabilities

 

Income (Loss)

 

Liabilities

 

in Income

 

Derivatives designated as cash flow hedges

 

 

 

 

 

 

 

 

 

 

 

Electric commodity

 

$

 

$

(18,600

)

$

 

$

(4,755

)(c)

$

 

Natural gas commodity

 

 

(811

)

 

8,916

(d)

(6,951

)(d)

Vehicle fuel and other commodity

 

949

 

 

2,107

(e)

 

 

Total

 

$

949

 

$

(19,411

)

$

2,107

 

$

4,161

 

$

(6,951

)

 

 

 

 

 

 

 

 

 

 

 

 

Other derivative instruments

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

$

 

$

 

$

 

$

 

$

1,524

(b)

Electric commodity

 

 

43,341

 

 

 

 

Natural gas commodity

 

 

(1,076

)

 

(386

)(d)

 

Other

 

 

 

 

 

200

(b)

Total

 

$

 

$

42,265

 

$

 

$

(386

)

$

1,724

 

 


(a) Recorded to interest charges.

(b) Recorded to electric operating revenues.  Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c) 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.

(d)  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.

(e) Recorded to other O&M expenses.

 

17



Table of Contents

 

Credit Related Contingent Features Contract provisions of the derivative instruments that NSP-Minnesota enters into 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.  If the credit ratings at NSP-Minnesota at June 30, 2010 and Dec. 31, 2009 were downgraded below investment grade, no contracts underlying NSP-Minnesota’s derivative liabilities would require the posting of collateral or contract settlement upon the downgrade.

 

Certain of NSP-Minnesota’s 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.  As of June 30, 2010 and Dec. 31, 2009, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.

 

Fair Value Measurements

 

ASC 820 Fair Value Measurements and Disclosures provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. A hierarchal 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 reported 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 reported date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with discounted cash flow or option pricing models using highly observable inputs.

 

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

 

18



Table of Contents

 

Recurring Fair Value Measurements

 

The following table presents, for each of the hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis at June 30, 2010:

 

 

 

June 30, 2010

 

 

 

Fair Value

 

Fair Value

 

Counterparty

 

 

 

(Thousands of Dollars)

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Netting (c)

 

Total

 

Current derivative assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives designated as cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

 

 

Vehicle fuel and other commodity

 

$

 

$

13

 

$

 

$

13

 

$

(13

)

$

 

Other derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

443

 

22,805

 

(62

)

23,186

 

(13,977

)

9,209

 

Electric commodity

 

 

917

 

8,654

 

9,571

 

(3,728

)

5,843

 

Natural gas commodity

 

 

12

 

 

12

 

(12

)

 

Total current derivative assets

 

$

443

 

$

23,747

 

$

8,592

 

$

32,782

 

$

(17,730

)

15,052

 

Purchased power agreements (b)

 

 

 

 

 

 

 

 

 

 

 

25,200

 

Current derivative instruments valuation

 

 

 

 

 

 

 

 

 

 

 

$

40,252

 

Noncurrent derivative assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives designated as cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

 

 

Vehicle fuel and other commodity

 

$

 

$

46

 

$

 

$

46

 

$

 

$

46

 

Other derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

 

14,687

 

7,120

 

21,807

 

(2,218

)

19,589

 

Total noncurrent derivative assets

 

$

 

$

14,733

 

$

7,120

 

$

21,853

 

$

(2,218

)

19,635

 

Purchased power agreements (b)

 

 

 

 

 

 

 

 

 

 

 

89,533

 

Noncurrent derivative instruments valuation

 

 

 

 

 

 

 

 

 

 

 

$

109,168

 

Other recurring fair value assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning fund (a)

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash equivalents

 

$

 

$

211,252

 

$

 

$

211,252

 

$

 

$

211,252

 

Debt securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Government securities

 

 

198,365

 

 

198,365

 

 

198,365

 

U.S. corporate bonds

 

 

306,493

 

 

306,493

 

 

306,493

 

Foreign securities

 

 

2,152

 

 

2,152

 

 

2,152

 

Municipal bonds

 

 

79,114

 

 

79,114

 

 

79,114

 

Asset-backed securities

 

 

 

40,067

 

40,067

 

 

40,067

 

Mortgage-backed securities

 

 

 

65,059

 

65,059

 

 

65,059

 

Equity securities (common stock)

 

346,111

 

 

 

346,111

 

 

346,111

 

Total

 

$

346,111

 

$

797,376

 

$

105,126

 

$

1,248,613

 

$

 

$

1,248,613

 

 

19



Table of Contents

 

 

 

June 30, 2010

 

 

 

Fair Value

 

Fair Value

 

Counterparty

 

 

 

(Thousands of Dollars)

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Netting (c)

 

Total

 

Current derivative liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives designated as cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

 

 

Vehicle fuel and other commodity

 

$

 

$

1,061

 

$

 

$

1,061

 

$

(13

)

$

1,048

 

Other derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

457

 

19,460

 

 

19,917

 

(18,437

)

1,480

 

Electric commodity

 

 

 

3,728

 

3,728

 

(3,728

)

 

Natural gas commodity

 

 

6,663

 

 

6,663

 

(12

)

6,651

 

Total current derivative liabilities

 

$

457

 

$

27,184

 

$

3,728

 

$

31,369

 

$

(22,190

)

9,179

 

Purchased power agreements (b)

 

 

 

 

 

 

 

 

 

 

 

13,851

 

Current derivative instruments valuation

 

 

 

 

 

 

 

 

 

 

 

$

23,030

 

Noncurrent derivative liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Other derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

$

 

$

8,273

 

$

2,777

 

$

11,050

 

$

(2,218

)

$

8,832

 

Total noncurrent derivative liabilities

 

$

 

$

8,273

 

$

2,777

 

$

11,050

 

$

(2,218

)

8,832

 

Purchased power agreements (b)

 

 

 

 

 

 

 

 

 

 

 

193,797

 

Noncurrent derivative instruments valuation

 

 

 

 

 

 

 

 

 

 

 

$

202,629

 

 


(a)  Reported in other investments on the consolidated balance sheet, which also includes $13.9 million of miscellaneous investments.

(b)     In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, NSP-Minnesota began recording several long-term purchased power agreements 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.

(c)   ASC 815 Derivatives and Hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

 

NSP-Minnesota recognizes transfers between levels as of the beginning of each period.  No transfers occurred between levels during the three and six months ended June 30, 2010.

 

20



Table of Contents

 

The following tables present, for each of the hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2009:

 

 

 

Dec. 31, 2009

 

 

 

Fair Value

 

Fair Value

 

Counterparty

 

 

 

(Thousands of Dollars)

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Netting (c)

 

Total

 

Current derivative assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Other derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

$

 

$

13,748

 

$

6,253

 

$

20,001

 

$

(11,640

)

$

8,361

 

Electric commodity

 

 

 

23,540

 

23,540

 

1,425

 

24,965

 

Natural gas commodity

 

 

1,580

 

 

1,580

 

54

 

1,634

 

Total current derivative assets

 

$

 

$

15,328

 

$

29,793

 

$

45,121

 

$

(10,161

)

34,960

 

Purchased power agreements (b)

 

 

 

 

 

 

 

 

 

 

 

24,522

 

Current derivative instruments valuation

 

 

 

 

 

 

 

 

 

 

 

$

59,482

 

Noncurrent derivative assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives designated as cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

 

 

Vehicle fuel and other commodity

 

$

 

$

85

 

$

 

$

85

 

$

 

$

85

 

Other derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

 

7,040

 

11,610

 

18,650

 

(4,193

)

14,457

 

Natural gas commodity

 

 

31

 

 

31

 

1

 

32

 

Total noncurrent derivative assets

 

$

 

$

7,156

 

$

11,610

 

$

18,766

 

$

(4,192

)

14,574

 

Purchased power agreements (b)

 

 

 

 

 

 

 

 

 

 

 

102,642

 

Noncurrent derivative instruments valuation

 

 

 

 

 

 

 

 

 

 

 

$

117,216

 

Other recurring fair value assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning fund (a)

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash equivalents

 

$

 

$

28,134

 

$

 

$

28,134

 

$

 

$

28,134

 

Debt securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Government securities

 

 

74,126

 

 

74,126

 

 

74,126

 

U.S. corporate bonds

 

 

312,844

 

 

312,844

 

 

312,844

 

Foreign securities

 

 

9,445

 

 

9,445

 

 

9,445

 

Municipal bonds

 

 

149,088

 

 

149,088

 

 

149,088

 

Asset-backed securities

 

 

 

11,918

 

11,918

 

 

11,918

 

Mortgage-backed securities

 

 

 

81,189

 

81,189

 

 

81,189

 

Equity securities (common stock)

 

581,995

 

 

 

581,995

 

 

581,995

 

Total

 

$

581,995

 

$

573,637

 

$

93,107

 

$

1,248,739

 

$

 

$

1,248,739

 

 

21



Table of Contents

 

 

 

Dec. 31, 2009

 

 

 

Fair Value

 

Fair Value

 

Counterparty

 

 

 

(Thousands of Dollars)

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Netting (c)

 

Total

 

Current derivative liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives designated as cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

 

 

Vehicle fuel and other commodity

 

$

 

$

1,905

 

$

 

$

1,905

 

$

 

$

1,905

 

Other derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

 

14,248

 

3,731

 

17,979

 

(15,503

)

2,476

 

Electric commodity

 

 

 

3,276

 

3,276

 

1,425

 

4,701

 

Natural gas commodity

 

 

640

 

 

640

 

54

 

694

 

Other commodity

 

 

 

360

 

360

 

 

360

 

Total current derivative liabilities

 

$

 

$

16,793

 

$

7,367

 

$

24,160

 

$

(14,024

)

10,136

 

Purchased power agreements (b)

 

 

 

 

 

 

 

 

 

 

 

14,525

 

Current derivative instruments valuation

 

 

 

 

 

 

 

 

 

 

 

$

24,661

 

Noncurrent derivative liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Other derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

Trading commodity

 

$

 

$

4,895

 

$

6,799

 

$

11,694

 

$

(4,197

)

$

7,497

 

Natural gas commodity

 

 

364

 

 

364

 

1

 

365

 

Total noncurrent derivative liabilities

 

$

 

$

5,259

 

$

6,799

 

$

12,058

 

$

(4,196

)

7,862

 

Purchased power agreements (b)

 

 

 

 

 

 

 

 

 

 

 

201,666

 

Noncurrent derivative instruments valuation

 

 

 

 

 

 

 

 

 

 

 

$

209,528

 

 


(a)  Reported in other investments on the consolidated balance sheet, which also includes $17.0 million of miscellaneous investments.

(b)     In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, NSP-Minnesota began recording several long-term purchased power agreements 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.

(c)      ASC 815 Derivatives and Hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

 

The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options.  Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers.  Electric commodity derivatives include financial transmission rights (FTRs), for which fair value is determined using complex predictive models and inputs including forward commodity prices as well as subjective forecasts of retail and wholesale demand, generation and resulting transmission system congestion.  Given the limited observability of management’s forecasts for several of these inputs, fair value measurements for FTRs have been assigned a Level 3.

 

NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts 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 commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

 

Cash equivalents are recorded at cost plus accrued interest to approximate fair value.  Changes in the observed trading prices and liquidity of cash equivalents, including money market funds, are also monitored as additional support for determining fair value.  Equity securities are valued using quoted prices in active markets.  Debt securities are primarily priced using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, which also require significant, subjective risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated prepayments.  Therefore, fair value measurements for asset-backed and mortgage-backed securities have been assigned a Level 3.

 

22



Table of Contents

 

The following tables present the changes in Level 3 recurring fair value measurements for the three and six months ended June 30, 2010 and 2009:

 

 

 

Three Months Ended June 30,

 

 

 

2010

 

2009

 

 

 

 

 

Nuclear Decommissioning Fund

 

 

 

Nuclear Decommissioning Fund

 

(Thousands of Dollars)

 

Commodity
Derivatives,
Net

 

Mortgage-Backed
Securities

 

Asset-Backed
Securities

 

Commodity
Derivatives,
Net

 

Mortgage-
Backed
Securities

 

Asset-Backed
Securities

 

Balance at April 1

 

$

3,614

 

$

109,044

 

$

44,125

 

$

1,544

 

$

90,257

 

$

15,295

 

Purchases and settlements, net

 

387

 

(45,329

)

(4,219

)

(45

)

(21,436

)

(1,878

)

Transfers out of Level 3

 

 

 

 

(19

)

 

 

Losses recognized in earnings

 

(1,787

)

 

 

(2,638

)

 

 

Gains recognized as regulatory assets and liabilities

 

6,993

 

1,344

 

161

 

47,795

 

3,409

 

690

 

Balance at June 30

 

$

9,207

 

$

65,059

 

$

40,067

 

$

46,637

 

$

72,230

 

$

14,107

 

 

 

 

Six Months Ended June 30,

 

 

 

2010

 

2009

 

 

 

 

 

Nuclear Decommissioning Fund

 

 

 

Nuclear Decommissioning Fund

 

(Thousands of Dollars)

 

Commodity
Derivatives,
Net

 

Mortgage-Backed
Securities

 

Asset-Backed
Securities

 

Commodity
Derivatives,
Net

 

Mortgage-
Backed
Securities

 

Asset-Backed
Securities

 

Balance at Jan. 1

 

$

27,237

 

$

81,189

 

$

11,918

 

$

23,247

 

$

98,461

 

$

10,962

 

Purchases and settlements, net

 

(896

)

(19,698

)

27,933

 

(52

)

(30,034

)

1,908

 

Transfers out of Level 3

 

 

 

 

(19

)

 

 

Losses recognized in earnings

 

(7,223

)

 

 

(4,831

)

 

 

(Losses) gains recognized as regulatory assets and liabilities

 

(9,911

)

3,568

 

216

 

28,292

 

3,803

 

1,237

 

Balance at June 30

 

$

9,207

 

$

65,059

 

$

40,067

 

$

46,637

 

$

72,230

 

$

14,107

 

 

Losses on Level 3 commodity derivatives recognized in earnings for the three and six months ended June 30, 2010 include $0.9 million of net unrealized gains and $1.8 million of net unrealized losses, respectively, relating to commodity derivatives held at June 30, 2010.  Losses on Level 3 commodity derivatives recognized in earnings for the three and six months ended June 30, 2009 include $0.3 million and $1.6 million of net unrealized gains, respectively, relating to commodity derivatives held at June 30, 2009.  Realized and unrealized gains and losses on commodity trading activities are included in electric revenues.  Realized and unrealized gains and losses on non-trading derivative instruments are recorded in OCI or deferred as regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.

 

9.   Financial Instruments

 

The estimated fair values of NSP-Minnesota’s recorded financial instruments are as follows:

 

 

 

June 30, 2010

 

Dec. 31, 2009

 

 

 

Carrying

 

 

 

Carrying

 

 

 

(Thousands of Dollars)

 

Amount

 

Fair Value

 

Amount

 

Fair Value

 

Nuclear decommissioning fund

 

$

1,248,613

 

$

1,248,613

 

$

1,248,739

 

$

1,248,739

 

Other investments

 

50

 

50

 

695

 

695

 

Long-term debt, including current portion

 

3,013,624

 

3,409,681

 

3,013,178

 

3,238,854

 

 

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The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts.  The fair value of NSP-Minnesota’s nuclear decommissioning fund is based on published trading data and pricing models, generally using the most observable inputs available for each class of security.  The fair values of NSP-Minnesota’s other investments are estimated based on quoted market prices for those or similar investments.  The fair value of NSP-Minnesota’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

 

The fair value estimates presented are based on information available to management as of June 30, 2010 and Dec. 31, 2009.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date, and current estimates of fair values may differ significantly.

 

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, 2010 and Dec. 31, 2009, there were $6.4 million and $6.9 million of letters of credit outstanding, respectively.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

 

10.   Other Income (Expense), Net

 

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

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

(Thousands of Dollars)

 

2010

 

2009

 

2010

 

2009

 

Interest income

 

$

389

 

$

1,128

 

$

1,194

 

$

2,304

 

Other nonoperating income

 

2

 

42

 

22

 

55

 

Insurance policy expense

 

(351

)

(1,223

)

(1,552

)

(2,406

)

Other nonoperating expense

 

(19

)

(71

)

(21

)

(95

)

Other income (expense), net

 

$

21

 

$

(124

)

$

(357

)

$

(142

)

 

11.  Segment Information

 

NSP-Minnesota has two reportable segments: regulated electric utility and regulated natural gas utility.  Commodity trading operations are not a reportable segment and are included in the regulated electric segment.  All other revenues primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

 

 

 

Regulated

 

Regulated

 

All

 

Reconciling

 

Consolidated

 

(Thousands of Dollars)

 

Electric

 

Natural Gas

 

Other

 

Eliminations

 

Total

 

Three Months Ended June 30, 2010

 

 

 

 

 

 

 

 

 

 

 

Operating revenues from external customers

 

$

842,620

 

$

68,227

 

$

5,443

 

$

 

$

916,290

 

Intersegment revenues

 

110

 

2,406

 

 

(2,516

)

 

Total revenues

 

$

842,730

 

$

70,633

 

$

5,443

 

$

(2,516

)

$

916,290

 

Segment net income (loss)

 

$

45,934

 

$

(3,889

)

$

1,995

 

$

 

$

44,040

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30, 2009

 

 

 

 

 

 

 

 

 

 

 

Operating revenues from external customers

 

$

787,584

 

$

74,516

 

$

4,304

 

$

 

$

866,404

 

Intersegment revenues

 

62

 

405

 

 

(467

)

 

Total revenues

 

$

787,646

 

$

74,921

 

$

4,304

 

$

(467

)

$

866,404

 

Segment net income (loss)

 

$

50,836

 

$

(3,149

)

$

2,211

 

$

 

$

49,898

 

 

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Table of Contents

 

 

 

Regulated

 

Regulated

 

All

 

Reconciling

 

Consolidated

 

(Thousands of Dollars)

 

Electric

 

Natural Gas

 

Other

 

Eliminations

 

Total

 

Six Months Ended June 30, 2010

 

 

 

 

 

 

 

 

 

 

 

Operating revenues from external customers

 

$

1,692,852

 

$

340,620

 

$

9,925

 

$

 

$

2,043,397

 

Intersegment revenues

 

148

 

3,767

 

 

(3,915

)

 

Total revenues

 

$

1,693,000

 

$

344,387

 

$

9,925

 

$

(3,915

)

$

2,043,397

 

Segment net income

 

$

86,377

 

$

16,209

 

$

5,593

 

$

 

$

108,179

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended June 30, 2009

 

 

 

 

 

 

 

 

 

 

 

Operating revenues from external customers

 

$

1,656,666

 

$

403,783

 

$

9,338

 

$

 

$

2,069,787

 

Intersegment revenues

 

192

 

1,115

 

 

(1,307

)

 

Total revenues

 

$

1,656,858

 

$

404,898

 

$

9,338

 

$

(1,307

)

$

2,069,787

 

Segment net income

 

$

103,719

 

$

17,891

 

$

4,487

 

$

 

$

126,097

 

 

12.  Comprehensive Income

 

The components of total comprehensive income are shown below:

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

(Thousands of Dollars)

 

2010

 

2009

 

2010

 

2009

 

Net income

 

$

44,040

 

$

49,898

 

$

108,179

 

$

126,097

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

Unrealized gains (losses) — marketable securities

 

(108

)

338

 

(97

)

243

 

Changes in unrecognized amounts of pension and retiree medical benefits

 

27

 

28

 

50

 

65

 

After-tax net unrealized (losses) gains related to derivatives accounted for as hedges

 

(144

)

684

 

(133

)

561

 

After-tax net realized losses on derivative transactions reclassified into earnings

 

258

 

565

 

560

 

1,183

 

Other comprehensive income

 

33

 

1,615

 

380

 

2,052

 

Comprehensive income

 

$

44,073

 

$

51,513

 

$

108,559

 

$

128,149

 

 

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Table of Contents

 

13.  Benefit Plans and Other Postretirement Benefits

 

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota.

 

Components of Net Periodic Benefit Cost

 

 

 

Three Months Ended June 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

 

 

 

 

Postretirement Health

 

(Thousands of Dollars)

 

Pension Benefits

 

Care Benefits

 

Xcel Energy Inc.

 

 

 

 

 

 

 

 

 

Service cost

 

$

18,956

 

$

16,744

 

$

965

 

$

1,057

 

Interest cost

 

41,853

 

43,046

 

10,861

 

13,050

 

Expected return on plan assets

 

(58,035

)

(64,909

)

(7,131

)

(5,993

)

Amortization of transition obligation

 

 

 

3,611

 

3,726

 

Amortization of prior service cost (credit)

 

5,164

 

6,154

 

(1,233

)

(711

)

Amortization of net loss

 

13,134

 

3,299

 

3,113

 

4,779

 

Net periodic benefit cost

 

21,072

 

4,334

 

10,186

 

15,908

 

Costs not recognized and additional cost recognized due to the effects of regulation

 

(6,314

)

(959

)

973

 

973

 

Net benefit cost recognized for financial reporting

 

$

14,758

 

$

3,375

 

$

11,159

 

$

16,881

 

 

 

 

 

 

 

 

 

 

 

NSP-Minnesota

 

 

 

 

 

 

 

 

 

Net periodic benefit cost

 

$

9,428

 

$

959

 

$

2,833

 

$

2,971

 

Costs not recognized due to the effects of regulation

 

(6,314

)

(959

)

 

 

Net benefit cost recognized for financial reporting

 

$

3,114

 

$

 

$

2,833

 

$

2,971

 

 

 

 

Six Months Ended June 30,

 

 

 

2010

 

2009

 

2010

 

2009

 

 

 

 

 

 

 

Postretirement Health

 

(Thousands of Dollars)

 

Pension Benefits

 

Care Benefits

 

Xcel Energy Inc.

 

 

 

 

 

 

 

 

 

Service cost

 

$

36,574

 

$

32,730

 

$

2,003

 

$

2,333

 

Interest cost

 

82,505

 

84,895

 

21,390

 

25,206

 

Expected return on plan assets

 

(116,159

)

(128,269

)

(14,265

)

(11,388

)

Amortization of transition obligation

 

 

 

7,222

 

7,222

 

Amortization of prior service cost (credit)

 

10,328

 

12,309

 

(2,466

)

(1,363

)

Amortization of net loss

 

24,158

 

6,228

 

5,822

 

9,665

 

Net periodic benefit cost

 

37,406

 

7,893

 

19,706

 

31,675

 

Costs not recognized and additional cost recognized due to the effects of regulation

 

(13,640

)

(1,446

)

1,946

 

1,946

 

Net benefit cost recognized for financial reporting

 

$

23,766

 

$

6,447

 

$

21,652

 

$

33,621

 

 

 

 

 

 

 

 

 

 

 

NSP-Minnesota

 

 

 

 

 

 

 

 

 

Net periodic benefit cost

 

$

16,754

 

$

1,446

 

$

5,322

 

$

6,710

 

Costs not recognized due to the effects of regulation

 

(13,640

)

(1,446

)

 

 

Net benefit cost recognized for financial reporting

 

$

3,114

 

$

 

$

5,322

 

$

6,710

 

 

26



Table of Contents

 

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).

 

Forward-Looking Statements

 

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 the 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.

 

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 the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; 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; 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; environmental laws and regulations; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; 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, 2009, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2010.

 

Market Risks

 

NSP-Minnesota is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec. 31, 2009.  Commodity price and interest rate risks for NSP- Minnesota are mitigated in most jurisdictions due to cost-based rate regulation.

 

NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning.  Those investments are exposed to price fluctuations in equity markets and changes in interest rates.  However, because the costs of nuclear decommissioning are recovered through NSP-Minnesota rates, fluctuations in investment fair value do not affect NSP-Minnesota’s consolidated results of operations.  Distress in the financial markets may impact the fair value of the debt and equity securities in the nuclear decommissioning trust funds, and pension and postretirement health care plan trusts, as well as NSP-Minnesota’s ability to earn a return on short-term investments of excess cash.  As of June 30, 2010, there have been no material changes to market risks from that set forth in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009.

 

Results of Operations

 

NSP-Minnesota’s net income was approximately $108.2 million for the first six months of 2010, compared with approximately $126.1 million for the first six months of 2009. The decrease is largely due to higher O&M, partially offset by electric sales growth.

 

Electric Revenues and Margins

 

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power.  Due to fuel and purchased energy cost-recovery mechanisms for customers, fluctuations in these costs do not materially affect electric utility margin.

 

27



Table of Contents

 

Electric The following tables detail the electric revenues and margin:

 

 

 

Six Months Ended June 30,

 

(Millions of Dollars)

 

2010

 

2009

 

Electric revenues

 

$

1,693

 

$

1,657

 

Electric fuel and purchased power

 

(725

)

(696

)

Electric margin

 

$

968

 

$

961

 

 

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

 

Electric Revenues

 

(Millions of Dollars)

 

2010 vs. 2009

 

Fuel and purchased power cost recovery

 

$

23

 

Conservation revenue and incentive (partially offset by expenses)

 

13

 

Interchange agreement billing with NSP-Wisconsin

 

12

 

Non-fuel riders

 

7

 

Retail sales increase (excluding weather impact)

 

5

 

Retail rate increase (South Dakota)

 

5

 

Sales mix and demand revenue

 

2

 

NSP-Minnesota 2009 rate case adjustment for final rates (largely offset in depreciation expense)

 

(19

)

Firm wholesale

 

(12

)

Total increase in electric revenues

 

$

36

 

 

Electric Margin

 

(Millions of Dollars)

 

2010 vs. 2009

 

Conservation revenue and incentive (partially offset by expenses)

 

$

13

 

Non-fuel riders

 

7

 

Interchange agreement billing with NSP-Wisconsin

 

6

 

Retail sales increase (excluding impact of weather)

 

5

 

Retail rate increase (South Dakota)

 

5

 

Sales mix and demand revenue

 

2

 

NSP-Minnesota 2009 rate case adjustment for final rates (largely offset in depreciation expense)

 

(19

)

Firm wholesale

 

(6

)

Other, net

 

(6

)

Total increase in electric margin

 

$

7

 

 

Natural Gas Revenues and Margins

 

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases.  However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.

 

Natural Gas The following tables detail natural gas revenues and margin:

 

 

 

Six Months Ended June 30,

 

(Millions of Dollars)

 

2010

 

2009

 

Natural gas revenues

 

$

341

 

$

404

 

Cost of natural gas sold and transported

 

(241

)

(305

)

Natural gas margin

 

$

100

 

$

99

 

 

28



Table of Contents

 

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

 

Natural Gas Revenues

 

(Millions of Dollars)

 

2010 vs. 2009

 

Purchased natural gas adjustment clause recovery

 

$

(59

)

Estimated impact of weather

 

(6

)

Conservation revenue and incentive (partially offset by expenses)

 

3

 

Rate increase (Minnesota)

 

3

 

Other, net

 

(4

)

Total decrease in natural gas revenues

 

$

(63

)

 

Natural Gas Margin

 

(Millions of Dollars)

 

2010 vs. 2009

 

Conservation revenue and incentive (partially offset by expenses)

 

$

3

 

Rate increase (Minnesota)

 

3

 

Estimated impact of weather

 

(6

)

Other, net

 

1

 

Total increase in natural gas margin

 

$

1

 

 

Non-Fuel Operating Expense and Other Items

 

Other Operating and Maintenance Expenses Other operating and maintenance expenses for the first six months of 2010 increased $23.9 million, or 4.9 percent, compared with the first six months of 2009.  The following summarizes the components of the changes for the six months ended June 30:

 

(Millions of Dollars)

 

2010 vs. 2009

 

Nuclear outage costs, net of deferral

 

$

9

 

Higher plant generation costs

 

7

 

Higher labor costs

 

5

 

Higher nuclear plant operation costs

 

5

 

Other, net

 

(2

)

Total increase in other operating and maintenance expenses

 

$

24

 

 

·                  Higher nuclear outage costs are due to the timing and cost of nuclear refueling outages.

·                  Higher plant generation costs are primarily attributable to a higher level of scheduled maintenance and overhaul work.

·                  Higher labor costs are primarily due to annual wage increases that were effective in March 2010 and July 2009.

 

Conservation Program Expenses Conservation program expenses increased $8.0 million, or 29.4 percent, for the first six months of 2010, compared with the first six months of 2009.  The increase was primarily attributable to the expansion of programs and regulatory commitments.  Conservation program expenses are generally recovered in NSP-Minnesota concurrently through riders and base rates.

 

Depreciation and Amortization Depreciation and amortization expense decreased by approximately $5.6 million, or 2.8 percent, for the first six months of 2010, compared with the first six months of 2009.  The lower depreciation expense is primarily due to MPUC decisions that reduced depreciation and decommissioning expenses in June and October 2009.  These decreases were partially offset by normal system expansion.

 

Taxes (Other Than Income Taxes) Taxes (other than income taxes) increased by approximately $7.4 million, or 10.2 percent, for the first six months of 2010, compared with the first six months of 2009.  The increase was primarily due to increased property taxes.

 

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased by approximately $3.7 million, or 15.7 percent, for the first six months of 2010 compared with the same period in 2009.  NSP-Minnesota’s overall increase was primarily due to a slightly higher AFUDC equity rate.

 

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Table of Contents

 

Income Taxes — Income tax expense decreased by $3.2 million for the first six months of 2010, compared with the first six months of 2009.  The decrease in income tax expense was primarily due to a decrease in pretax income, partially offset by a write-off of tax benefits previously recorded related to Medicare Part D subsidies.  The effective tax rate was 38.7 percent for the first six months of 2010, compared with 36.2 percent for the same period in 2009.  The higher effective tax rate for the first six months of 2010 was primarily due to a higher forecasted annual effective tax rate and the write-off of tax benefits related to Medicare Part D subsidies.  The higher forecasted annual effective tax rate for 2010 as compared to 2009 was primarily due to increased state unitary tax expense in 2010, partially offset by increased plant-related deductions in 2010.

 

Factors Affecting Results of Continuing Operations

 

Public Utility Regulation

 

Aggregators of Retail Customers (ARCs) In 2009, the FERC adopted rules requiring MISO and other regional transmission organizations (RTOs) to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota, unless the relevant state regulatory agency prohibited the operation of ARCS.  Under MISO’ proposed tariff revisions, ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Minnesota.  MISO requested its tariff revisions be effective in June 2010, however FERC has not issued an order on MISO’s ARC-related tariff revisions.  In 2010, the MPUC opened an investigation regarding possible operation of ARCs in Minnesota.  In its response to an MPUC notice seeking comments, NSP-Minnesota requested the MPUC to prohibit ARCs.  NSP-Minnesota also filed requests with the North Dakota Public Service Commission (NDPSC) and South Dakota Public Utilities Commission (SDPUC) in March 2010 asking the regulatory agencies to prohibit operations of ARCs in their respective states.  In May 2010, the MPUC and SDPUC issued orders prohibiting, or temporarily prohibiting, the operation of ARCs.  In May 2010, the NDPSC issued a notice of opportunity for a hearing; no parties provided comments.  A NDPSC decision is expected in the third quarter of 2010.

 

Excelsior Energy In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba Energy Project.  The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior’s petition.  The contested case proceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.

 

In its August 2007 Phase 1 order, the MPUC disapproved the terms and conditions of Excelsior’s proposed power purchase agreement, and found that Excelsior and NSP-Minnesota should resume negotiations toward an acceptable purchase power agreement, with assistance from the OES and the guidance provided by the order.

 

In May 2009, the MPUC affirmed its previous order to deny Excelsior Energy’s Phase 2 request to approve a power purchase agreement related to its proposed second 600 MW IGCC generating facility, which closed the docket.  In August 2009, Excelsior appealed the MPUC decision to the Minnesota Court of Appeals.  On May 18, 2010, the Minnesota Court of Appeals affirmed the decision of the MPUC.  Excelsior did not file a petition for review by the Minnesota Supreme Court, making the Court of Appeals decision final.

 

2010 Minnesota Resource Decisions and Plan In May 2010, NSP-Minnesota signed new power purchase and exchange agreements with Manitoba Hydro that will extend purchases through 2025.  The existing agreements provide for the purchase of 850 MW, which start to expire April 30, 2015.  NSP-Minnesota filed for approval with the MPUC in June 2010.  NSP-Minnesota will file its next resource plan in August of 2010.

 

NSP-Minnesota Transmission Certificate of Need (CON) — In April 2009, the MPUC granted a CON to construct three 345 kilovolt (KV) electric transmission lines as part of the CapX 2020 project.  The project to build the three lines includes construction of approximately 600 miles of new facilities at a cost of approximately $1.7 billion.  The allocation of the project cost to NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900 million.  These cost estimates will be revised after the regulatory process is completed.  The MPUC also included a condition assuring a portion of the capacity of the Brookings, S.D. to Hampton, Minn. line is used for renewable energy.  In September 2009, two intervenors appealed the MPUC’s CON decisions in the Minnesota Court of Appeals.  On June 8, 2010, the court issued its decision affirming the MPUC’s order granting the CONs for the three 345 KV lines.  In May 2010, NSP-Minnesota and other CapX 2020 utilities notified the MPUC that the in-service date for the Brookings-Hampton project is expected to be delayed to 2015, more than one year after the date provided in the MPUC CON decision.  The MPUC set the notice of change for comments and a decision is expected during the third quarter of 2010.

 

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As part of the regulatory process for the CapX 2020 345 KV projects, NSP-Minnesota and Great River Energy have filed four route permit applications with the MPUC.  Permit applications for the remaining parts of the three lines are expected to be filed in adjoining states in 2010.  Two filed route permit applications have completed the evidentiary hearing processes, and the MPUC issued route permits for the Monticello to St. Cloud project and five of the six segments of the Brookings-Hampton project.  One segment of the Brookings-Hampton line was referred back to the ALJ to develop more information concerning the appropriate location to cross the Minnesota River.  The other two route applications are expected to be sent to an evidentiary hearing later in 2010 or early 2011.

 

In July 2009, the MPUC approved the CON application for a 230 KV CapX 2020 transmission line between Bemidji, Minn. and Grand Rapids, Minn.  Route permit hearings were concluded in May 2010, and an MPUC decision is anticipated in the third quarter of 2010.  The Bemidji-Grand Rapids line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million, with construction expected to be completed in 2012.  The estimated project cost to NSP-Minnesota is approximately $26 million.

 

Nuclear Power Operations and Waste Disposal — NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant, which has two units.  See additional discussion regarding the nuclear generating plants at Note 18 to the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2009.

 

High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes.  The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management.  This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility.  In 2002, the U. S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository over the objections of the Governor of Nevada.  In 2008, the DOE submitted an application to construct a deep geologic repository at Yucca Mountain to the NRC.

 

In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC to approve the withdrawal of the application.  In parallel with the action to stop the Yucca Mountain project, the Secretary of Energy convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposing of used nuclear fuel.  The final report containing recommendations from the Blue Ribbon Commission is expected in early 2012.  A number of parties have challenged the DOE’s authority to stop the Yucca Mountain project and to withdraw the application from the NRC.  The utility industry, including Xcel Energy, is represented in the challenges by the Nuclear Energy Institute (NEI).  In light of the DOE’s plan to stop the Yucca Mountain project and to withdraw its application from the NRC, Xcel Energy in a separate action has requested the Secretary of Energy to set the fee collection rate for the Nuclear Waste Fund to zero until a definitive program is in place.  In April 2010, the NEI, on behalf of its members, including Xcel Energy, filed a lawsuit against the DOE in federal court, requesting that the fee be suspended.

 

On June 30, 2010, the Atomic Safety and Licensing Board (ASLB) issued a ruling that the DOE could not withdraw the Yucca Mountain application.  The NRC has set appeal and comment dates to the three-judge NRC panel’s decision.  A decision from the NRC Commissioners could come in third quarter 2010.

 

To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel.  NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.  As of June 30, 2010, there were 26 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant.  See Note 6 to the consolidated financial statements for a discussion of the legal proceedings against the DOE related to the nuclear waste disposal matter.

 

Nuclear Plant Power Uprates and Life Extension

 

Prairie Island Life Extension — In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively.  The Prairie Island Indian Community (PIIC) filed contentions in the NRC’s license renewal proceeding in August 2008, which was referred to the ASLB for review.  The ASLB granted the PIIC hearing request and has admitted seven of the 11 contentions filed.  To date, all seven contentions that were originally admitted have been resolved and removed from the ASLB docket.  Subsequent to the NRC issuance of the final Safety Evaluation Report and the draft supplemental environmental impact statement, the PIIC filed four additional contentions.  The ASLB has admitted one of the contentions and has issued a decision denying the other three.  If the admitted contention is not resolved, the resulting adjudicatory process is expected to add approximately eight months onto the NRC’s standard 22 month review schedule, resulting in an anticipated decision on the Prairie Island license renewal in late 2010.

 

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Monticello Nuclear Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello facility.  The filing was placed in suspension by the ASLB, to allow NRC staff to address concerns related to two different uprate petitions, including Monticello raised by the Advisory Committee for Reactor Safety (ACRS) related to containment pressure associated with pump performance.  The industry submitted a white paper and the NRC staff recommended that the matter be addressed through specific filings to demonstrate any potential risk and mitigation measures.  In a letter to the NRC staff, the ACRS indicated that modifications to the plant should be evaluated and made where practical.  NSP-Minnesota is working with the NRC  to supplement its filing as necessary to address the issues and expects to complete the license proceeding in 2011.

 

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 utility 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, 2009.  In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

 

MISO Generation Interconnection Cost Allocation Tariff — In October 2009, the FERC approved a proposal by MISO and its transmission owners, including NSP-Minnesota and NSP-Wisconsin, to change the cost allocation procedures in the MISO tariff associated with interconnection of new generation.  The approved tariff required the interconnecting generator to fund 90 or 100 percent of the costs of network upgrades required for interconnection (depending on voltage) on an interim basis until MISO and its stakeholders develop a replacement tariff to be filed with FERC in July 2010.  On July 15, 2010, MISO and certain transmission owners, including NSP-Minnesota and NSP-Wisconsin, filed the required replacement tariff.  The cost allocation provisions of the tariff provide for (1) regional allocation of costs associated with projects identified through the MISO transmission planning process as Multi-Value Projects (MVPs), which are projects that meet certain key planning objectives and (2) the allocation to generators of most costs for network upgrades required to interconnect the generator to the MVPs or the existing transmission system.  MISO proposed the tariff changes be effective July 16, 2010.  Comments on the July 2010 MISO tariff filing are due at FERC by Sept. 10, 2010, and the filing is pending FERC action.

 

MISO vs. PJM Interconnection, L.L.C. (PJM) Complaint Proceedings — In March 2010, MISO filed two complaints against PJM at the FERC alleging that PJM violated generation redispatch requirements under the Joint Operating Agreement between the two RTOs, and alleging that incorrect modeling of certain generators by PJM resulted in underpayments by PJM of up to $135 million to generators in MISO (including the NSP System, whereby NSP-Minnesota and NSP-Wisconsin share all generation and transmission costs through the Interchange Agreement, which is a FERC-approved tariff) for redispatch provided from 2002 to 2009.  MISO asked the FERC to direct PJM to pay the underpaid amount, plus interest.  In April 2010, PJM filed a complaint against MISO, alleging that MISO dispatched generation in the MISO region improperly under the RTO Joint Operating Agreement, and requested that the FERC order MISO to pay PJM up to $25 million.  Xcel Energy intervened in the complaint proceedings in support of MISO.  Informal settlement discussions have failed to resolve the issues, and the FERC issued an order setting the disputes for hearing and formal settlement discussions.  The first settlement conference is scheduled for August 2010.  The outcome of the complaint proceedings is uncertain.  If MISO were to prevail, NSP-Minnesota could receive a portion of the payments to MISO from PJM.  If PJM were to prevail, NSP-Minnesota could be required to reimburse MISO for a portion of the payments to PJM.

 

Electric Reliability Standards Compliance

 

Compliance Audits

 

NSP-Minnesota and NSP-Wisconsin share all NSP System generation and transmission costs by means of a FERC-approved tariff commonly referred to as the Interchange Agreement.  In 2008, the NSP System filed a self-report with the Midwest Reliability Organization (MRO) regional entity relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain critical infrastructure protection (CIP) standards.  In 2009, the NSP System reached agreement with the MRO that would resolve all open audit findings and self reports by payment of a non-material penalty.  In April 2010, the NSP System executed a definitive settlement agreement.  The settlement agreement is pending approval at the NERC and will also need to be approved by the FERC.

 

In March 2010, the MRO conducted a compliance spot check to evaluate compliance with the NERC Critical Energy Infrastructure (CIP) standards, which were effective July 1, 2008.  The draft non-public report issued by the MRO in July 2010 found that the Xcel Energy utility subsidiaries may not be in compliance with several of the CIP standards.  Xcel Energy provided comments disagreeing with many of the conclusions of the draft report and is awaiting issuance of the final spot check audit report.  The CIP spot check report findings related to the NSP System will then proceed to the MRO enforcement process.  The extent the MRO or NERC may seek to impose penalties for violations of CIP standards is unknown at this time.

 

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NERC Compliance Investigations

 

As a result of a series of transmission line outages, on Sept. 18, 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection.  In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada.  The initial transmission line outages occurred on the NSP System.  In March 2008, NSP-Minnesota received notice that the MRO was commencing a compliance investigation of the September 2007 event.  Because the event affected more than one region, the NERC took over the investigation.  In January 2010, the NERC issued a preliminary report alleging the NSP System violated certain NERC reliability standards.  The report represents the preliminary conclusions of the NERC and is subject to additional procedures at NERC, and ultimately FERC review.  Xcel Energy disagrees with the many aspects of the preliminary report and filed its response with NERC in February 2010.  The final outcome of the NERC compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

 

In February 2010, the NERC notified NSP-Minnesota that it was commencing a non-public investigation of NSP-Minnesota maintenance practices associated with insulating oil levels in bulk electric system substations, as the result of an anonymous complaint received by the NERC.  NSP-Minnesota is fully cooperating with the investigation.  The final outcome of the NERC compliance investigation, and whether and to what extent NERC may seek to impose penalties for standards violations, is unknown at this time.

 

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 the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of June 30, 2010, 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

 

In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota.  After consultation with legal counsel, NSP-Minnesota has recorded an estimate of the probable cost of settlement or other disposition for such matters.

 

Additional Information

 

See Notes 5 and 6 of the consolidated financial statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference.  Reference also is made to Item 3 and Notes 13 and 14 of NSP-Minnesota’s consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2009 for a description of certain legal proceedings presently pending.

 

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Item 1A — RISK FACTORS

 

Except to the extent updated or described below, 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, 2009, which is incorporated herein by reference.

 

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

 

Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHG, and federal legislation has been introduced in both houses of Congress. Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

 

The EPA has taken steps to regulate GHGs under the CAA. On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. The EPA finalized GHG efficiency standards for light duty vehicles in spring 2010 and has promulgated  permitting requirements for GHGs for large new and modified stationary sources, such as power plants.  These regulations will become applicable in 2011.  We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 6, Commitments and Contingent Liabilities, in the notes to the consolidated financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

 

Many of the federal and state climate change legislative proposals, such as the American Clean Energy and Security Act and the proposed Kerry-Lieberman legislation, use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation will be enacted. The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

 

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Item 6.  EXHIBITS

 


*Indicates incorporation by reference

 

3.01*

 

Articles of Incorporation and Amendments of Northern Power Corp. (renamed NSP-Minnesota on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).

3.02*

 

By-Laws (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).

10.01*

 

Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2010).

10.02*

 

Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2010).

31.01

 

Principal Executive Officer’s and 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.

 

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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 on July 30, 2010.

 

Northern States Power Company (a Minnesota corporation)

(Registrant)

 

 

/s/ TERESA S. MADDEN

 

Teresa S. Madden

 

Vice President and Controller

 

 

 

/s/ DAVID M. SPARBY

 

David M. Sparby

 

Vice President and Chief Financial Officer

 

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