UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

x

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

 

EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2007.

 

 

OR

 

 

 

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

 

EXCHANGE ACT OF 1934

 

For the transition period from __________ to __________.

 

 

 

Commission File Number 001-31303

 

Black Hills Corporation

Incorporated in South Dakota

IRS Identification Number 46-0458824

625 Ninth Street

Rapid City, South Dakota 57701

 

 

Registrant’s telephone number (605) 721-1700

 

 

Former name, former address, and former fiscal year if changed since last report

NONE

 

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.

Yes

x

 

No

o

 

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

 

Large accelerated filer

x

 

Accelerated filer

o

 

Non-accelerated filer

o

 

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).


Yes

o

 

No

x

 

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

Class

Outstanding at April 30, 2007

 

 

Common stock, $1.00 par value

37,668,388 shares

 

TABLE OF CONTENTS

 

 

 

Page

 

 

 

 

Glossary of Terms

3-4

 

 

 

PART I.

FINANCIAL INFORMATION

 

 

 

 

Item 1.

Financial Statements

 

 

 

 

 

Condensed Consolidated Statements of Income –

 

 

Three Months Ended March 31, 2007 and 2006

5

 

 

 

 

Condensed Consolidated Balance Sheets –

 

 

March 31, 2007, December 31, 2006 and March 31, 2006

6

 

 

 

 

Condensed Consolidated Statements of Cash Flows –

 

 

Three Months Ended March 31, 2007 and 2006

7

 

 

 

 

Notes to Condensed Consolidated Financial Statements

8-25

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and

 

 

Results of Operations

26-44

 

 

 

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

45-47

 

 

 

Item 4.

Controls and Procedures

48

 

 

 

PART II.

OTHER INFORMATION

 

 

 

 

Item 1.

Legal Proceedings

49

 

 

 

Item 1A.

Risk Factors

49

 

 

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

49

 

 

 

Item 5.

Other Information

50

 

 

 

Item 6.

Exhibits

51

 

 

 

 

Signatures

52

 

 

 

 

Exhibit Index

53

 

2

GLOSSARY OF TERMS

The following terms and abbreviations appear in the text of this report and have the definitions described below:

AFUDC

Allowance for Funds Used During Construction

Aquila

Aquila, Inc.

Bbl

Barrel

BHEP

Black Hills Exploration and Production, Inc., a direct, wholly-owned

 

subsidiary of Black Hills Energy, Inc.

BHER

Black Hills Energy Resources, Inc., a direct, wholly-owned subsidiary of

 

Black Hills Energy, Inc.

Black Hills Energy

Black Hills Energy, Inc., a direct, wholly-owned subsidiary of the Company

Black Hills Generation

Black Hills Generation, Inc., a direct, wholly-owned subsidiary of

 

Black Hills Energy, Inc.

Black Hills Power

Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company

Black Hills Wyoming

Black Hills Wyoming, Inc., an indirect, wholly-owned subsidiary of

 

Black Hills Energy, Inc.

Btu

British thermal unit

Cheyenne Light

Cheyenne Light, Fuel and Power Company, a direct, wholly-owned

 

subsidiary of the Company

Cheyenne Light Pension Plan

The Cheyenne Light, Fuel and Power Company Pension Plan

Dth

Dekatherms

EITF

Emerging Issues Task Force

Enserco

Enserco Energy Inc., a direct, wholly-owned subsidiary of Black Hills

 

Energy, Inc.

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

FIN 48

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes –

 

an Interpretation of FASB Statement 109”

GAAP

Generally Accepted Accounting Principles

GECC

General Electric Capital Corporation

Great Plains

Great Plains Energy Incorporated

Indeck

Indeck Capital, Inc.

LIBOR

London Interbank Offered Rate

LOE

Lease Operating Expense

Las Vegas I

Las Vegas I gas-fired power plant

Las Vegas II

Las Vegas II gas-fired power plant

LVC

Las Vegas Cogeneration Limited Partnership, an indirect, wholly-owned

 

subsidiary of Black Hills Energy, Inc.

Mbbl

One thousand barrels

Mcf

One thousand cubic feet

Mcfe

One thousand cubic feet equivalent

MMBtu

One million British thermal units

MMcf

One million cubic feet

MMcfe

One million cubic feet equivalent

Moody’s

Moody’s Investor Services, Inc.

MW

Megawatt

MWh

Megawatt-hour

Nevada Power

Nevada Power Company

PNM

PNM Resources

SAB

SEC Staff Accounting Bulletin

 

 

3

 

SAB 108

SAB 108, “Effects of Prior Year Misstatement on Current Year Financial

 

Statements”

SEC

U. S. Securities and Exchange Commission

SFAS

Statement of Financial Accounting Standards

SFAS 71

SFAS 71, “Accounting for the Effects of Certain Types of Regulation”

SFAS 109

SFAS 109, “Accounting for Income Taxes”

SFAS 133

SFAS 133, “Accounting for Derivative Instruments and Hedging Activities”

SFAS 144

SFAS 144, “Accounting for the Impairment of Long-lived Assets”

SFAS 157

SFAS 157, “Fair Value Measurements”

SFAS 158

SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other

 

Postretirement Plans, an Amendment of FASB Statements No. 87, 88, 106

 

and 132(R)”

SFAS 159

SFAS 159, “The Fair Value Option for Financial Assets and Financial

 

Liabilities”

S&P

Standard & Poor’s Rating Services

WPSC

Wyoming Public Service Commission

WRDC

Wyodak Resources Development Corporation, a direct, wholly-owned

 

subsidiary of Black Hills Energy, Inc.

 

 

4

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

(in thousands, except per share amounts)

 

 

 

 

 

Operating revenues

$

186,533

$

171,890

 

 

 

 

 

Operating expenses:

 

 

 

 

Fuel and purchased power

 

51,289

 

54,129

Operations and maintenance

 

20,559

 

22,003

Administrative and general

 

25,663

 

24,949

Depreciation, depletion and amortization

 

23,168

 

20,889

Taxes, other than income taxes

 

9,899

 

10,551

 

 

130,578

 

132,521

 

 

 

 

 

Operating income

 

55,955

 

39,369

 

 

 

 

 

Other income (expense):

 

 

 

 

Interest expense

 

(11,109)

 

(12,000)

Interest income

 

733

 

668

Allowance for funds used during

 

 

 

 

construction – equity

 

1,834

 

Other income, net

 

349

 

288

 

 

(8,193)

 

(11,044)

 

 

 

 

 

Income from continuing operations

 

 

 

 

before equity in earnings of

 

 

 

 

unconsolidated subsidiaries, minority

 

 

 

 

interest and income taxes

 

47,762

 

28,325

Equity in earnings of unconsolidated

 

 

 

 

subsidiaries

 

845

 

513

Minority interest

 

(94)

 

(86)

Income tax expense

 

(16,013)

 

(10,191)

 

 

 

 

 

Income from continuing operations

 

32,500

 

18,561

(Loss) income from discontinued operations,

 

 

 

 

net of taxes

 

(47)

 

7,590

 

 

 

 

 

Net income

$

32,453

$

26,151

 

 

 

 

 

Weighted average common shares

 

 

 

 

outstanding:

 

 

 

 

Basic

 

35,173

 

33,120

Diluted

 

35,577

 

33,460

 

 

 

 

 

Earnings per share:

 

 

 

 

Basic–

 

 

 

 

Continuing operations

$

0.92

$

0.56

Discontinued operations

 

 

0.23

Total

$

0.92

$

0.79

 

 

 

 

 

Diluted–

 

 

 

 

Continuing operations

$

0.91

$

0.55

Discontinued operations

 

 

0.23

Total

$

0.91

$

0.78

 

 

 

 

 

Dividends paid per share of common stock

$

0.34

$

0.33

 

The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

 

5

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

 

March 31,

December 31,

March 31,

 

2007

2006

2006

 

(in thousands, except share amounts)

ASSETS

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

$

77,836

$

36,939

$

42,150

Restricted cash

 

2,032

 

2,004

 

Receivables (net of allowance for doubtful accounts of $3,647;

 

 

 

 

 

 

$4,202 and $5,016, respectively)

 

237,335

 

263,109

 

148,620

Materials, supplies and fuel

 

110,129

 

92,560

 

102,995

Derivative assets

 

25,906

 

69,244

 

23,268

Other assets

 

8,876

 

9,221

 

7,791

Assets of discontinued operations

 

1,444

 

1,424

 

9,986

 

 

463,558

 

474,501

 

334,810

 

 

 

 

 

 

 

Investments

 

23,613

 

23,808

 

24,708

 

 

 

 

 

 

 

Property, plant and equipment

 

2,297,519

 

2,242,396

 

2,036,198

Less accumulated depreciation and depletion

 

(615,597)

 

(596,029)

 

(536,188)

 

 

1,681,922

 

1,646,367

 

1,500,010

Other assets:

 

 

 

 

 

 

Derivative assets

 

1,321

 

2,871

 

1,238

Goodwill

 

30,563

 

30,563

 

30,562

Intangible assets (net of accumulated amortization of

 

 

 

 

 

 

$26,632; $25,852 and $23,513, respectively)

 

23,650

 

24,429

 

26,768

Other

 

63,299

 

42,137

 

44,208

 

 

118,833

 

100,000

 

102,776

 

$

2,287,926

$

2,244,676

$

1,962,304

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable

$

237,789

$

224,009

$

120,859

Accrued liabilities

 

91,217

 

95,020

 

70,644

Derivative liabilities

 

18,159

 

24,041

 

9,845

Deferred income taxes

 

1,352

 

1,215

 

1,591

Notes payable

 

 

145,500

 

58,000

Current maturities of long-term debt

 

38,822

 

17,106

 

11,852

Accrued income taxes

 

12,489

 

19,561

 

12,827

Liabilities of discontinued operations

 

1,858

 

2,526

 

11,424

 

 

401,686

 

528,978

 

297,042

 

 

 

 

 

 

 

Long-term debt, net of current maturities

 

602,870

 

628,340

 

665,373

 

 

 

 

 

 

 

Deferred credits and other liabilities:

 

 

 

 

 

 

Deferred income taxes

 

197,937

 

174,332

 

140,904

Derivative liabilities

 

3,973

 

1,530

 

976

Other

 

126,411

 

116,297

 

95,352

 

 

328,321

 

292,159

 

237,232

 

 

 

 

 

 

 

Minority interest in subsidiaries

 

5,252

 

5,158

 

5,011

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

Common stock equity –

 

 

 

 

 

 

Common stock $1 par value; 100,000,000 shares authorized;

 

 

 

 

 

 

Issued 37,701,238; 33,404,902 and 33,281,278 shares,

 

 

 

 

 

 

respectively

 

37,701

 

33,405

 

33,281

Additional paid-in capital

 

554,040

 

409,826

 

405,214

Retained earnings

 

369,997

 

348,245

 

326,369

Treasury stock at cost – 37,128; 35,700 and 38,058

 

 

 

 

 

 

shares, respectively

 

(984)

 

(920)

 

(962)

Accumulated other comprehensive loss

 

(10,957)

 

(515)

 

(6,256)

 

 

949,797

 

790,041

 

757,646

 

 

 

 

 

 

 

 

$

2,287,926

$

2,244,676

$

1,962,304

 

The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

6

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

 

Three Months Ended

 

March 31,

 

2007

2006

 

(in thousands)

Operating activities:

 

 

 

 

Net income

$

32,453

$

26,151

Loss (income) from discontinued operations, net of taxes

 

47

 

(7,590)

 

 

 

 

 

Income from continuing operations

 

32,500

 

18,561

Adjustments to reconcile income from continuing operations

 

 

 

 

to net cash provided by operating activities:

 

 

 

 

Depreciation, depletion and amortization

 

23,168

 

20,889

Net change in derivative assets and liabilities

 

(3,948)

 

(2,040)

Deferred income taxes

 

13,842

 

5,028

Distributed earnings in associated companies

 

472

 

3,749

Allowance for funds used during construction – equity

 

(1,834)

 

Change in operating assets and liabilities:

 

 

 

 

Materials, supplies and fuel

 

11,838

 

7,383

Accounts receivable and other current assets

 

26,965

 

115,773

Accounts payable and other current liabilities

 

1,804

 

(103,131)

Other operating activities

 

(10,705)

 

4,635

Net cash provided by operating activities of continuing operations

 

94,102

 

70,847

Net cash (used in) provided by operating activities of discontinued operations

 

(1,387)

 

2,550

Net cash provided by operating activities

 

92,715

 

73,397

 

 

 

 

 

Investing activities:

 

 

 

 

Property, plant and equipment additions

 

(38,558)

 

(89,684)

Proceeds from sale of assets

 

 

40,735

Other investing activities

 

(305)

 

(899)

Net cash used in investing activities of continuing operations

 

(38,863)

 

(49,848)

Net cash provided by investing activities of discontinued operations

 

1,200

 

2,873

Net cash used in investing activities

 

(37,663)

 

(46,975)

 

 

 

 

 

Financing activities:

 

 

 

 

Dividends paid

 

(11,377)

 

(10,968)

Common stock issued

 

146,638

 

1,237

(Decrease) increase in short-term borrowings, net

 

(145,500)

 

3,000

Long-term debt – repayments

 

(3,753)

 

(4,739)

Other financing activities

 

(350)

 

804

Net cash used in financing activities of continuing operations

 

(14,342)

 

(10,666)

Net cash used in financing activities of discontinued operations

 

 

Net cash used in financing activities

 

(14,342)

 

(10,666)

 

 

 

 

 

Increase in cash and cash equivalents

 

40,710

 

15,756

 

 

 

 

 

Cash and cash equivalents:

 

 

 

 

Beginning of period

 

37,530 (b)

 

34,198 (d)

End of period

$

78,240 (a)

$

49,954 (c)

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

Non-cash investing and financing activities-

 

 

 

 

Property, plant and equipment acquired with accrued liabilities

$

25,892

$

20,378

Cash paid during the period for-

 

 

 

 

Interest (net of amounts capitalized)

$

9,282

$

11,549

Income taxes paid (net of amounts refunded)

$

6,538

$

3,609

_________________________

(a)

 Includes approximately $0.4 million at March 31, 2007 of cash included in the assets of discontinued operations.

(b)

 Includes approximately $0.6 million at December 31, 2006 of cash included in the assets of discontinued operations.

(c)

 Includes approximately $7.8 million at March 31, 2006 of cash included in the assets of discontinued operations.

(d)

 Includes approximately $2.4 million at December 31, 2005 of cash included in the assets of discontinued operations.

 

The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

 

7

BLACK HILLS CORPORATION

 

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2006 Annual Report on Form 10-K)

 

(1)

MANAGEMENT’S STATEMENT

 

The financial statements included herein have been prepared by Black Hills Corporation (the Company) without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in the Company’s 2006 Annual Report on Form 10-K filed with the SEC.

 

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the March 31, 2007, December 31, 2006 and March 31, 2006 financial information and are of a normal recurring nature. Some of the Company’s operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as changes in market price. The results of operations for the three months ended March 31, 2007, are not necessarily indicative of the results to be expected for the full year. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

 

(2)

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

 

FIN 48

 

The Company adopted FIN 48 on January 1, 2007 (see Note 8). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

 

8

SAB 108  

 

During September 2006, the staff of the SEC released SAB 108. SAB 108 provides guidance on how the effects of the carryover or reversal of prior year financial statement misstatements should be considered in quantifying a current year misstatement. Prior practice allowed the evaluation of materiality on the basis of (1) the error quantified as the amount by which the current year income statement was misstated (rollover method) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (iron curtain method). Reliance on either method in prior years could have resulted in misstatement of the financial statements. The guidance provided in SAB 108 requires both methods to be used in evaluating materiality. Immaterial prior year errors may be corrected with the first filing of prior year financial statements after adoption. The cumulative effect of the correction can either be reported in the carrying amounts of assets and liabilities as of the beginning of that fiscal year, and the offsetting adjustment made to the opening balance of retained earnings for that year, or by restating prior periods. Disclosure requirements include the nature and amount of each individual error being corrected in the cumulative adjustment, as well as a disclosure of when and how each error being corrected arose and the fact that the errors had previously been considered immaterial. SAB 108 was effective January 1, 2007. SAB 108 did not have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

 

(3)

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

 

SFAS 157

 

During September 2006, the FASB issued SFAS 157 and applies under other accounting pronouncements that require or permit fair value measurements. This Statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. Management is currently evaluating the impact SFAS 157 will have on the Company’s consolidated financial statements.

 

SFAS 159

 

During February 2007, the FASB issued SFAS 159, which establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. Management is currently evaluating the impact SFAS 159 will have on the Company’s consolidated financial statements.

 

9

(4)

MATERIALS, SUPPLIES AND FUEL

 

The amounts of materials, supplies and fuel included on the accompanying Condensed Consolidated Balance Sheets, by major classification, are provided as follows (in thousands):

 

Major Classification

March 31, 2007

December 31, 2006

March 31, 2006

 

 

 

 

 

 

 

Materials and supplies

$

33,303

$

31,946

$

28,042

Fuel

 

6,096

 

9,663

 

5,753

Gas and oil held by energy

 

 

 

 

 

 

marketing*

 

70,730

 

50,951

 

69,200

 

 

 

 

 

 

 

Total materials, supplies and fuel

$

110,129

$

92,560

$

102,995

___________________________

* As of March 31, 2007, December 31, 2006 and March 31, 2006, market adjustments related to natural gas held by Energy marketing and recorded in inventory were $2.4 million, $(31.5) million and $(5.4) million, respectively (see Note 12 for further discussion of Energy marketing trading activities).

 

The gas inventory held by the Company’s Energy marketing subsidiary primarily consists of gas held in storage and gas imbalances held on account with pipelines. Such gas is being held in inventory to capture the price differential between the time at which it was purchased and a sales date in the future. A substantial majority of the gas was economically hedged at the time of purchase either through a fixed price physical or financial forward sale.

 

(5)

LONG-TERM DEBT AND NOTES PAYABLE

 

Note Payable

 

During the first quarter of 2007, the Company repaid the $145.5 million borrowing balance outstanding on its revolving credit facility with proceeds from the Company’s February 22, 2007 equity issuance (see Note 9).

 

Long-term Debt

 

On April 30, 2007, the Company prepaid the outstanding balance of the GECC Financing. Accordingly, the December 31, 2006 long-term balance of $22.2 million has been classified as a current liability on the accompanying March 31, 2007 Condensed Consolidated Balance Sheet.

 

Amendments to Revolver

 

On March 13, 2007, the Company entered into a second amendment to its revolving bank facility. The second amendment (i) increased the limit for borrowings or other credit accommodations for the separate credit facility for the Company’s energy marketing subsidiary from $260 million to $300 million, (ii) increased the allowed total commitments under the facility without requiring amendment of the facility from $500 million to $600 million, (iii) effective with the acquisition of certain electric and gas utility assets from Aquila, will increase the recourse leverage ratio limit from 0.65 to 1.00 to 0.70 to 1.00 for the first year after completion of the Aquila asset acquisition, reverting to 0.65 to 1.00 thereafter, and (iv) allowed for other modifications to enable the Company to complete the Aquila asset acquisition.

 

10

(6)

EARNINGS PER SHARE

 

Basic earnings per share from continuing operations is computed by dividing income from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted earnings per share from continuing operations gives effect to all dilutive common shares potentially outstanding during a period. A reconciliation of “Income from continuing operations” and basic and diluted share amounts is as follows (in thousands):

 

Period ended March 31, 2007

Three Months

 

 

Average

 

Income

Shares

 

 

 

 

Income from continuing operations

$

32,500

 

 

 

 

 

Basic earnings

 

32,500

35,173

Dilutive effect of:

 

 

 

Stock options

 

102

Estimated contingent shares issuable

 

 

 

for prior acquisition

 

158

Others

 

144

Diluted earnings

$

32,500

35,577

 

 

 

Period ended March 31, 2006

Three Months

 

 

Average

 

Income

Shares

 

 

 

 

Income from continuing operations

$

18,561

 

 

 

 

 

Basic earnings

 

18,561

33,120

Dilutive effect of:

 

 

 

Stock options

 

83

Estimated contingent shares issuable

 

 

 

for prior acquisition

 

158

Others

 

99

Diluted earnings

$

18,561

33,460

 

 

11

(7)

COMPREHENSIVE INCOME

 

The following table presents the components of the Company’s comprehensive income

(in thousands):

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

 

 

 

 

Net income

$

32,453

$

26,151

Other comprehensive income (loss),

 

 

 

 

net of tax:

 

 

 

 

Fair value adjustment on derivatives

 

 

 

 

designated as cash flow hedges (net of

 

 

 

 

tax of $2,499 and $(2,255), respectively)

 

(4,691)

 

3,865

Reclassification adjustments on cash flow

 

 

 

 

hedges settled and included in net

 

 

 

 

income (net of tax of $3,065 and

 

 

 

 

$170, respectively)

 

(5,751)

 

(291)

 

 

 

 

 

Comprehensive income

$

22,011

$

29,725

 

(8)

INCOME TAXES

 

The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized an approximate $0.7 million benefit from a decrease in the liability for unrecognized tax benefits. This benefit was accounted for as an adjustment to the January 1, 2007 balance of retained earnings.

 

The total gross amount of unrecognized tax benefits at January 1, 2007 was approximately $72.6 million. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $2.0 million (net of the federal benefit on state issues and interest) at the date of adoption.

 

It is the Company’s continuing practice to recognize penalties and/or interest related to income tax matters in income tax expense. The Company had no penalties accrued and approximately $0.4 million for the accrual of interest income at the date of adoption of FIN 48.

 

The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and a foreign jurisdiction. The Company is no longer subject to U.S. federal examination for tax years before 2004. However, the Company is under examination by a state taxing authority for tax years 2001 through 2003 and remains subject to examination by foreign income tax authorities for tax years as early as 1999.

 

The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to March 31, 2008.

 

12

(9)

COMMON STOCK

 

Other than the following transactions, the Company had no other material changes in its common stock, as reported in Note 9 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

 

Private Placement of Common Stock

 

On February 22, 2007, the Company completed the issuance and sale of approximately 4.17 million shares of common stock at a price of $36.00 per share in a private placement offering. The Company used the approximate $145.6 million of net proceeds from this offering for debt reduction.

 

These shares were not initially registered under the Securities Act of 1933, therefore restricting the purchasers’ ability to offer or sell the shares. The offering agreements required the Company to register the related securities with the SEC within a specified period of time, and the Company has performed this obligation. In addition, the Company must maintain an effective shelf registration statement with the SEC, allowing resale of the restricted shares, until all related shares have been resold or cease to be restricted. If the Company fails to maintain an effective shelf registration statement in accordance with the terms of the offering agreements, it may be required to pay damages to the purchasers at a per thirty-day rate of 1.0 percent of the related share purchase price until the default is cured. The total damage payments under the agreements are limited to 10.0 percent of the related share purchase price. The Company believes the likelihood of making any payments under the damage provisions is remote and accordingly has not recognized any liability within its consolidated financial statements.

 

Equity Compensation Plans

 

    Effective January 1, 2007, the Company granted 35,026 target performance shares to certain officers and business unit leaders of the Company for the January 1, 2007 through December 31, 2009 performance period. Performance shares are awarded based on the Company’s total shareholder return over the designated performance period as measured against a selected peer group. In addition, the Company’s stock price must also increase during the performance period.

 

Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50th percentile of the selected peer group. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50 percent in the form of cash and 50 percent in the form of common stock. The grant date fair value was $34.17 per share.

 

    50,514 stock options were exercised during the first quarter of 2007, at a weighted-average exercise price of $26.97 per share providing $1.4 million of proceeds to the Company.

 

    The Company granted 43,556 restricted common shares during the first quarter of 2007. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $1.6 million will be recognized over the three-year vesting period.

 

    The Company issued 33,143 shares of common stock under the short-term incentive compensation plan during the first quarter of 2007. Pre-tax compensation cost related to the award was approximately $1.2 million, which was accrued for in 2006.

 

 

13

(10)

EMPLOYEE BENEFIT PLANS

 

Defined Benefit Pension Plan

 

The Company has two non-contributory defined benefit pension plans (Plans). One Plan covers employees of the Company and the following subsidiaries who meet certain eligibility requirements: Black Hills Service Company, Black Hills Power, WRDC and BHEP. The other Plan covers employees of the Company’s subsidiary, Cheyenne Light, who meet certain eligibility requirements.

 

The components of net periodic benefit cost for the two Plans are as follows (in thousands):

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

 

 

 

 

Service cost

$

687

$

649

Interest cost

 

1,129

 

1,041

Expected return on plan assets

 

(1,374)

 

(1,247)

Prior service cost

 

38

 

38

Net loss

 

127

 

227

 

 

 

 

 

Net periodic benefit cost

$

607

$

708

 

The Company made a $0.5 million contribution to the Cheyenne Light Pension Plan in the first quarter of 2007; no additional contributions are anticipated to be made to the Plans during the 2007 fiscal year.

 

Supplemental Non-qualified Defined Benefit Plans

 

The Company has various supplemental retirement plans for key executives of the Company (Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.

 

The components of net periodic benefit cost for the Supplemental Plans are as follows (in thousands):

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

 

 

 

 

Service cost

$

103

$

87

Interest cost

 

289

 

270

Prior service cost

 

3

 

3

Net loss

 

178

 

199

 

 

 

 

 

Net periodic benefit cost

$

573

$

559

 

The Company anticipates that it will need to make contributions to the Supplemental Plans for the 2007 fiscal year of approximately $0.7 million. The contributions are expected to be made in the form of benefit payments.

 

14

Non-pension Defined Benefit Postretirement Healthcare Plans

 

Employees who are participants in the Company’s Postretirement Healthcare Plans (Healthcare Plans) and who meet certain eligibility requirements are entitled to postretirement healthcare benefits.

 

The components of net periodic benefit cost for the Healthcare Plans are as follows (in thousands):

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

 

 

 

 

Service cost

$

135

$

164

Interest cost

 

207

 

203

Net transition obligation

 

15

 

38

Prior service cost

 

 

(6)

Net gain

 

(4)

 

 

 

 

 

 

Net periodic benefit cost

$

353

$

399

 

The Company anticipates that it will make contributions to the Healthcare Plans for the 2007 fiscal year of approximately $0.3 million. The contributions are expected to be made in the form of benefits payments.

 

It has been determined that the Company’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was approximately $0.1 million for each of the three month periods ended March 31, 2007 and 2006.

 

(11)

SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY’S BUSINESS

 

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of March 31, 2007, substantially all of the Company’s operations and assets are located within the United States.

 

The Company conducts its operations through the following six reporting segments: Retail Services group consisting of the following segments: Electric utility, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Electric and gas utility, which supplies electric and gas utility service to Cheyenne, Wyoming and vicinity; and Wholesale Energy group, consisting of the following segments: Oil and gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region, Texas, California and other states; Power generation, which produces and sells power and capacity to wholesale customers with plants concentrated in Colorado, Nevada, Wyoming and California; Coal mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; and Energy marketing, which markets natural gas, crude oil and related services primarily in the western and central regions of the United States and Canada.

 

15

Segment information follows the same accounting policies as described in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K. In accordance with the provisions of SFAS 71, intercompany fuel sales to the electric utility are not eliminated.

 

Segment information included in the accompanying Condensed Consolidated Statements of Income is as follows (in thousands):

 

 

External

Inter-segment

Income (Loss) from

 

Operating

Operating

Continuing

 

Revenues

Revenues

Operations

Three Month Period Ended

 

 

 

 

 

 

March 31, 2007

 

 

 

 

 

 

 

 

 

 

 

 

 

Retail services:

 

 

 

 

 

 

Electric utility

$

47,356

$

411

$

6,699

Electric and gas utility

 

36,363

 

 

3,072

Wholesale energy:

 

 

 

 

 

 

Oil and gas

 

25,843

 

 

3,591

Power generation

 

39,566

 

 

4,979

Coal mining

 

6,217

 

3,528

 

1,615

Energy marketing

 

28,437

 

 

12,659

Corporate

 

1

 

 

(115)

Inter-segment eliminations

 

 

(1,189)

 

 

 

 

 

 

 

 

Total

$

183,783

$

2,750

$

32,500

 

 

 

External

Inter-segment

Income (Loss) from

 

Operating

Operating

Continuing

 

Revenues

Revenues

Operations

Three Month Period Ended

 

 

 

 

 

 

March 31, 2006

 

 

 

 

 

 

 

 

 

 

 

 

 

Retail services:

 

 

 

 

 

 

Electric utility

$

43,804

$

164

$

4,899

Electric and gas utility

 

43,699

 

 

1,397

Wholesale energy:

 

 

 

 

 

 

Oil and gas

 

25,185

 

 

5,390

Power generation

 

33,593

 

 

2,092

Coal mining

 

5,996

 

3,274

 

1,415

Energy marketing

 

16,957

 

 

6,247

Corporate

 

16

 

 

(2,879)

Inter-segment eliminations

 

 

(798)

 

 

 

 

 

 

 

 

Total

$

169,250

$

2,640

$

18,561

 

The Company had no material changes in the assets of its reporting segments, as reported in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

 

16

(12)

RISK MANAGEMENT ACTIVITIES

 

The Company actively manages its exposure to certain market risks as described in Note 2 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form

10-K. Details of derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are as follows:

 

Trading Activities

 

Natural Gas and Crude Oil Marketing

 

The contract or notional amounts and terms of the Company’s natural gas and crude oil marketing activities and derivative commodity instruments are as follows:

 

 

Outstanding at

Outstanding at

Outstanding at

 

March 31, 2007

December 31, 2006

March 31, 2006

 

 

 

Latest

 

 

Latest

 

 

Latest

 

 

Notional

Expiration

 

Notional

Expiration

 

Notional

Expiration

 

 

Amounts

(months)

 

Amounts

(months)

 

Amounts

(months)

(in thousands of MMBtus)

 

 

 

 

 

 

 

 

 

Natural gas basis

 

 

 

 

 

 

 

 

 

swaps purchased

 

169,341

21

 

138,111

22

 

92,737

19

Natural gas basis

 

 

 

 

 

 

 

 

 

swaps sold

 

178,563

21

 

148,720

22

 

103,437

19

Natural gas fixed - for - float

 

 

 

 

 

 

 

 

 

swaps purchased

 

40,323

24

 

38,239

16

 

17,889

20

Natural gas fixed - for - float

 

 

 

 

 

 

 

 

 

swaps sold

 

61,880

24

 

59,061

15

 

28,432

20

Natural gas physical

 

 

 

 

 

 

 

 

 

purchases

 

104,393

19

 

87,782

22

 

91,422

31

Natural gas physical sales

 

109,593

31

 

106,500

34

 

110,332

43

Natural gas options

 

 

 

 

 

 

 

 

 

purchased

 

33,839

9

 

22,373

15

 

6,373

18

Natural gas options sold

 

33,839

9

 

22,373

15

 

6,373

18

 

 

17

 

Outstanding at

Outstanding at

Outstanding at

 

March 31, 2007

December 31, 2006

March 31, 2006

 

 

 

Latest

 

 

Latest

 

 

Latest

 

 

Notional

Expiration

 

Notional

Expiration

 

Notional

Expiration

 

 

Amounts

(months)

 

Amounts

(months)

 

Amounts

(months)

 

 

 

 

 

 

 

 

 

 

(in thousands of Bbls)

 

 

 

 

 

 

 

 

 

Crude oil physical

 

 

 

 

 

 

 

 

 

purchases

 

1,806

6

 

1,600

4

 

-(a)

-

Crude oil physical sales

 

1,557

6

 

1,367

7

 

-(a)

-

 

 

 

 

 

 

 

 

 

 

(Dollars, in thousands)

 

 

 

 

 

 

 

 

 

Canadian dollars

 

 

 

 

 

 

 

 

 

purchased

$

13,817

1

$

44,000

1

$

17,000

1

Canadian dollars sold

$

$

$

32,500

8

_________________________

(a)

The Company began marketing crude oil in the Rocky Mountain region beginning May 2006.

 

Derivatives and certain natural gas and crude oil marketing activities were marked to fair value on March 31, 2007, December 31, 2006 and March 31, 2006, and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Statements of Income are as follows (in thousands):

 

 

Current

Non-current

Current

Non-current

 

 

Derivative

Derivative

Derivative

Derivative

Unrealized

 

Assets

Assets

Liabilities

Liabilities

Gain

 

 

 

 

 

 

 

 

 

 

 

March 31, 2007

$

20,090

$

149

$

14,696

$

514

$

5,029

 

 

 

 

 

 

 

 

 

 

 

December 31, 2006

$

53,728

$

4

$

23,296

$

377

$

30,059

 

 

 

 

 

 

 

 

 

 

 

March 31, 2006

$

20,590

$

215

$

7,034

$

32

$

13,739

 

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Condensed Consolidated Balance Sheets and the related unrealized gain/loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain/loss recognized on the associated derivative asset or liability described above. As of March 31, 2007, December 31, 2006 and March 31, 2006, the market adjustments recorded in inventory were $2.4 million, $(31.5) million and $(5.4) million, respectively.

 

18

Activities Other Than Trading

 

Oil and Gas Exploration and Production

 

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company had the following derivatives and related balances (in thousands):

 

 

 

 

 

 

 

 

Pre-tax

 

 

 

Maximum

 

Non-

 

Non-

Accumulated

 

 

 

Terms

Current

current

Current

current

Other

Pre-tax

 

 

in

Derivative

Derivative

Derivative

Derivative

Comprehensive

Income

 

Notional*

Years

Assets

Assets

Liabilities

Liabilities

Income (Loss)

(Loss)

March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps/options

450,000

1.00

$

649

$

$

934

$

546

$

(1,415)

$

584

Natural gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

11,613,000

1.17

 

5,049

 

276

 

2,260

 

2,151

 

1,638

 

(724)

 

 

 

$

5,698

$

276

$

3,194

$

2,697

$

223

$

(140)

December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps/options

240,000

1.00

$

524

$

$

362

$

$

36

$

126

Natural gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

10,588,000

1.25

 

13,485

 

2,000

 

309

 

175

 

15,339

 

(338)

 

 

 

$

14,009

$

2,000

$

671

$

175

$

15,375

$

(212)

March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

360,000

1.00

$

155

$

$

2,811

$

944

$

(3,755)

$

155

Natural gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

1,825,000

0.60

 

2,086

 

 

 

 

2,086

 

 

 

 

$

2,241

$

$

2,811

$

944

$

(1,669)

$

155

________________________

*crude in Bbls, gas in MMBtus

 

Based on March 31, 2007 market prices, a $2.0 million gain would be realized and reported in pre-tax earnings during the next twelve months related to hedges of production. Estimated and actual realized gains will likely change during the next twelve months as market prices change.

 

19

Fuel in Storage

 

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company had the following swaps and related balances (in thousands):

 

 

 

 

 

 

 

 

Pre-tax

 

 

 

 

 

Non-

 

Non-

Accumulated

 

 

 

Maximum

Current

current

Current

current

Other

 

 

 

Terms in

Derivative

Derivative

Derivative

Derivative

Comprehensive

Unrealized

 

Notional*

Years

Assets

Assets

Liabilities

Liabilities

Income (Loss)

Gain

March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

455,000

1.00

$

$

$

161

$

$

(161)

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

380,000

0.25

$

1,220

$

$

$

$

878

$

342

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

155,000

1.00

$

31

$

$

$

$

31

$

________________________

*gas in MMBtus

 

Based on March 31, 2007 market prices, a loss of $(0.2) million would be realized and reported in pre-tax earnings during the next twelve months related to the cash flow hedge. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

 

20

Financing Activities

 

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company’s interest rate swaps and related balances were as follows (in thousands):

 

 

 

Weighted

 

 

 

 

 

Pre-tax

 

 

 

Average

 

 

Non-

 

Non-

Accumulated

 

 

Current

Fixed

Maximum

Current

current

Current

current

Other

 

 

Notional

Interest

Terms in

Derivative

Derivative

Derivative

Derivative

Comprehensive

Pre-tax

 

Amount

Rate

Years

Assets

Assets

Liabilities

Liabilities

Income

Income

March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

$

150,000

5.04%

9.50

$

118

$

896

$

108

$

762

$

144

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

$

150,000

5.04%

9.75

$

287

$

867

$

74

$

978

$

102

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

swaps

$

75,000

4.93%

10.00

$

406

$

1,023

$

$

$

1,412

$

17

 

Based on March 31, 2007 market interest rates and balances, a gain of less than $0.1 million would be realized and reported in pre-tax earnings during the next twelve months. Estimated and realized gains will likely change during the next twelve months as market interest rates change.

 

(13)

LEGAL PROCEEDINGS

 

The Company is subject to various legal proceedings, claims and litigation as described in Note 18 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

 

Earn-Out Litigation

 

As disclosed in previous filings with the SEC, the Company has ongoing litigation with the former Indeck stockholders. On March 12, 2007, the Court granted, in part, the Company’s Motion to Dismiss the Amended Complaint. The Court dismissed Counts 1 and 5 of the Amended Complaint. Count 1 included all claims of fraud against individual defendants. Those individuals were not named in other counts of the Amended Complaint, so they were dismissed as parties to the lawsuit. Count 5 asserted a claim for breach of the covenant of good faith and fair dealing relating to the alleged destruction of evidence. The Court approved the amendment of the complaint on other theories. The Company expects to file Motions for Summary Judgment on these remaining claims. A status hearing is set for late June 2007, at which time we expect the Court to set a trial date if Motions for Summary Judgment are denied in whole or in part.

 

The outcome of this matter is uncertain, as is the amount of contingent merger consideration that could be awarded following arbitration and/or litigation. If any additional merger consideration is awarded, it would be recorded as additional goodwill. If an adverse outcome was to occur and punitive damages were awarded, the punitive damages would be recorded as an expense.

 

21

Las Vegas Cogeneration/Nevada Power Company Arbitration

 

On March 16, 2007, Nevada Power filed a Demand for Arbitration pursuant to a Power Purchase Agreement dated May 27, 1992, between Nevada Power and LVC for Las Vegas I. Nevada Power asserts that LVC is in breach of its obligation under the Agreement to maintain a reliable fuel supply throughout the term of the Agreement. Nevada Power also asserts that LVC failed to deliver the amounts of energy and capacity required by the Agreement. The relief Nevada Power requests include: (1) Determination and Order requiring LVC to provide reasonable assurance of its ability to supply fuel to the facility for the full remaining term of the Agreement; (2) Determination that LVC has breached the Agreement relating to fuel supply requirements, and therefore finding that Nevada Power is relieved of its obligation to purchase power under the Agreement; (3) Determination concerning the energy and capacity delivery requirements of the Agreement; and (4) Determination that LVC breached the performance requirements of the Agreement during the winter season of 2005-2006, and providing an award of damages incurred by Nevada Power by reason of the alleged breach.

 

LVC denies all these claims and filed its response to the Demand for Arbitration, asserting the following defenses: (1) That Nevada Power failed to honor its contractual obligation to properly negotiate in good faith before filing the demand for arbitration; (2) That LVC has complied with its obligations relating to fuel supply and transportation; (3) That LVC has fulfilled its obligations to deliver energy and capacity to Nevada Power, and did not breach the Agreement during the winter season of 2005-2006, when substantial mechanical problems required an extended outage to perform redesign and repair of generation equipment; and (4) That numerous other affirmative defenses preclude Nevada Power from receiving the relief requested.

 

The arbitration demand was filed with the American Arbitration Association, pursuant to its Commercial Arbitration Rules. The parties are in the process of selecting an arbitrator, who will establish the process and schedule for determination of this dispute. While the Company cannot predict the final timing or outcome of this action, it is not expected to have a material adverse impact on the Company’s consolidated financial position or results of operations.  

 

Except as described above, there have been no material developments in any previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first three months of 2007.

 

22

(14)

ACQUISITION OF UTILITY ASSETS

 

On February 7, 2007, the Company entered into a definitive agreement with Aquila for the asset acquisition of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The purchase price of the assets is $940.0 million, subject to closing adjustments. In conjunction with this agreement, the Company has entered into a binding agreement with a group of lenders for a committed acquisition credit facility (see Note 16).

 

The purchase is conditioned on the completion of the acquisition of the outstanding shares of Aquila by Great Plains immediately following the sale of the regulated utilities to the Company. The purchase is also subject to regulatory approvals from the Missouri Public Service Commission, the Kansas Corporation Commission, the Colorado Public Service Commission, the Nebraska Public Service Commission, the Iowa Utilities Board and FERC; Hart-Scott-Rodino antitrust review; as well as other customary conditions.

 

This transaction would add approximately 93,000 electric utility customers and 523,000 gas utility customers to the Company’s utility operations.

 

The Company is capitalizing certain incremental acquisition costs incurred in the current period related to this pending acquisition. Amounts capitalized in the three months ended March 31, 2007 were approximately $2.0 million.

 

(15)

DISCONTINUED OPERATIONS

 

The Company accounts for its discontinued operations under the provisions of SFAS 144. Accordingly, results of operations and the related charges for discontinued operations have been classified as “(Loss) income from discontinued operations, net of taxes” in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassifications on a consistent basis.

 

Sale of Crude Oil Marketing and Transportation Assets

 

On March 1, 2006, the Company sold the operating assets of BHER and related subsidiaries, its crude oil marketing and transportation business for approximately $41 million. Assets sold include the 200-mile Millennium and the 190-mile Kilgore Pipelines, oil marketing contracts and certain other ancillary assets. Following the sale, the Company closed the operations of the Houston, Texas based business. For business segment reporting purposes, BHER was included in the Energy marketing and transportation segment.

 

23

Revenues and net (loss) income from the discontinued operations were as follows (in thousands):

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

 

 

 

 

Operating revenues

$

$

171,869

 

 

 

 

 

Pre-tax loss from discontinued

 

 

 

 

operations (including

 

 

 

 

severance payments)

$

(73)

$

(1,762)

Pre-tax gain on sale of

 

 

 

 

assets

 

 

13,582

Income tax benefit (expense)

 

26

 

(4,230)

Net (loss) income from

 

 

 

 

discontinued operations

$

(47)

$

7,590

 

Losses incurred subsequent to the asset sale resulted from the settlement of certain contract disputes with the purchaser and other costs incurred in closing down the business operations.

 

Assets and liabilities of the crude oil marketing and transportation business were as follows (in thousands):

 

 

March 31, 2007

December 31, 2006

March 31, 2006

 

 

 

 

 

 

 

Current assets

$

1,294

$

1,424

$

9,879

Property, plant and equipment, net

 

 

 

34

Other non-current assets

 

150

 

 

73

Current liabilities

 

(1,514)

 

(2,352)

 

(10,585)

Other non-current liabilities

 

(344)

 

(174)

 

(839)

Net deficit

$

(414)

$

(1,102)

$

(1,438)

 

 

24

(16)

SUBSEQUENT EVENTS

 

Power Plant Project and Power Purchase Agreement

 

In April 2007, the Company entered into a power purchase agreement to provide electric power to Public Service Company of New Mexico, a regulated electric and natural gas utility subsidiary of PNM.

 

Under the terms of the agreement, the Company will provide the capacity and energy of a 149 MW, simple-cycle gas turbine generation facility to be located near Albuquerque, New Mexico. The project is expected to cost approximately $101 million, and has a commercial operation in-service date of June 1, 2008. The agreement is a customary tolling agreement, where the Company receives variable and fixed fees for the plant’s availability and operation, and Public Service Company of New Mexico will be responsible for providing fuel for the operation. In addition, the PPA affords us favorable “change of law” and “government impositions” pass throughs to Public Service Company of New Mexico. The duration of the power purchase agreement is 20 years. The agreement also allows Public Service Company of New Mexico the option to acquire an equity interest of up to 50 percent in this project.

>

 

Acquisition Credit Facility

 

On May 7, 2007, the Company entered into a senior unsecured $1.0 billion Acquisition Facility with ABN AMRO Bank N.V. as administrative agent and various other banks to provide for funding for the Company’s pending acquisition of Aquila assets. The Acquisition Facility is a committed facility to fund an acquisition term loan in a single draw in an amount of up to $1.0 billion. The commitment to fund the acquisition term loan terminates on August 5, 2008. Upon funding of the loan, the loan termination date is the earlier of the date which is 364 days from the loan funding date or February 5, 2009. The facility also includes certain customary affirmative and negative covenants which largely replicate the covenants under our existing revolving credit facility.

 

GECC

 

On April 30, 2007, the Company called its outstanding debt with GE Capital in the amount of $23.5 million. In conjunction with this, the Company expensed less than $0.1 million in unamortized deferred finance costs. The associated payment guarantees provided by the Company were also terminated.

 

 

25

ITEM 2.

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

 

We are a diversified energy company operating principally in the United States with two major business groups – retail services and wholesale energy. We report our business groups in the following segments:

 

Business Group

Financial Segment

 

 

Retail services group

Electric utility

 

Electric and gas utility

 

 

Wholesale energy group

Oil and gas

 

Power generation

 

Coal mining

 

Energy marketing

 

Our retail services group consists of our electric and gas utilities segments. Our electric utility, Black Hills Power, generates, transmits and distributes electricity to an average of approximately 64,200 customers in South Dakota, Wyoming and Montana. Our electric and gas utility, Cheyenne Light, serves approximately 38,900 electric and 32,600 natural gas customers in Cheyenne, Wyoming and vicinity. Our wholesale energy group engages in the production of coal, natural gas and crude oil primarily in the Rocky Mountain region; the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts; and the marketing of fuel products.

 

Pending Acquisition of Assets from Aquila

 

On February 7, 2007 the Company entered into a definitive agreement with Aquila for the asset acquisition of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The purchase price of the assets is $940 million, subject to closing adjustments. In conjunction with this agreement, the Company has entered into a binding agreement with a group of lenders for a committed acquisition credit facility as a bridge financing for the transaction. The Acquisition Credit Facility was completed on May 7, 2007.

 

The purchase is conditioned on the completion of the acquisition of the outstanding shares of Aquila by Great Plains immediately following the sale of the regulated utilities to us. The purchase is also subject to regulatory approvals from the Missouri Public Service Commission, the Kansas Corporation Commission, the Colorado Public Service Commission, the Nebraska Public Service Commission, the Iowa Utilities Board and FERC; Hart-Scott-Rodino antitrust review; as well as other customary conditions.

 

This transaction would add approximately 93,000 electric utility customers and 523,000 gas utility customers to our utility operations.

 

Disposition of Crude Oil Marketing and Transportation Business

 

In March 2006, we sold the operating assets of BHER and related subsidiaries, our crude oil marketing and pipeline transportation business headquartered in Houston, Texas. These activities were previously reported in our Energy marketing and transportation segment.

 

26

Results of Operations

 

Executive Summary

 

Results for the three months ended March 31, 2007 reflect solid utility performance, strong energy marketing results and improved power generation performance. Results also reflect the impacts of lower gas production and higher operating costs for the Oil and gas segment.

 

Increased retail services earnings resulted from overall steady operations at both of our utilities. Black Hills Power earnings benefited from a South Dakota rate increase. Cheyenne Light earnings were impacted by the effects of earnings from the AFUDC related to the construction of Wygen II. We also received additional permits on the Wygen III power plant project and expect to complete the permitting process and begin construction in late 2007 or early 2008.

 

Earnings from the oil and gas operations decreased due to lower production on an equivalent basis, driven by drilling permit delays in core operating areas, lower well performance in the Denver-Julesburg Basin and the effects of winter weather. Higher overall industry costs also affected results. Earnings were positively impacted by increased hedged natural gas and oil prices received compared to the prior year.

 

Increased earnings from power generation reflect plant availability of 96.1 percent compared to 85.7 percent in the three months ended March 31, 2006, primarily due to the return to service of the Las Vegas facilities after scheduled and unscheduled maintenance in the first quarter of 2006.

 

Strong earnings from energy marketing benefited from higher margins received and increased volumes. Lower overall market prices helped serve increased demand, and our storage, transportation and other marketing strategies were able to take advantage of natural gas price volatility and basis differentials in the Rocky Mountain and other regions.

 

On February 22, 2007 the Company completed the issuance and sale of approximately 4.17 million shares of common stock at a price of $36.00 per share in a private placement to institutional investors pursuant to a Securities Purchase Agreement dated as of February 14, 2007. We used the net proceeds from this offering for debt reduction. As a result of the use of a weighted average methodology to calculate the number of shares outstanding, the dilutive effect of the stock issuance will increase as the year progresses.

 

27

Consolidated Results

 

Revenues and Income (Loss) from Continuing Operations provided by each business group were as follows (in thousands):

 

 

Three Months Ended March 31,

 

2007

2006

Revenues

 

 

 

 

 

 

 

 

 

Retail services

$

83,719

$

87,503

Wholesale energy

 

102,813

 

84,371

Corporate

 

1

 

16

 

$

186,533

$

171,890

Income (Loss) from Continuing Operations

 

 

 

 

 

 

 

 

 

Retail services

$

9,771

$

6,296

Wholesale energy

 

22,844

 

15,144

Corporate

 

(115)

 

(2,879)

 

$

32,500

$

18,561

 

Discontinued operations in 2007 and 2006 represent the operations of our crude oil marketing and transportation business. The assets of this business were sold in March 2006.

 

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Revenues for the three months ended March 31, 2007 increased 9 percent, or $14.6 million, compared to the same period in 2006. Increased revenues were primarily driven by higher margins from our energy marketing activities, higher retail rates at Black Hills Power, and improved revenues from Power generation.

 

Operating expenses decreased 1 percent, or $1.9 million, primarily due to lower fuel and purchased power costs at the electric and gas utility, and lower operating and maintenance cost at Power generation due to the 2006 outages at the Las Vegas facility, partially offset by increased depreciation and depletion expense.

 

Income from continuing operations increased $13.9 million due primarily to the following:

 

            a $1.8 million increase in Electric utility earnings;

 

            a $1.7 million increase in Electric and gas utility earnings;

 

            a $6.4 million increase in Energy marketing earnings;

 

            a $2.9 million increase in Power generation earnings; and

 

            a $2.8 million decrease in unallocated corporate costs,

 

partially offset by:

 

            a $1.8 million decrease in Oil and gas earnings.

 

 

28

See the following discussion of our business segments under the captions “Retail Services Group” and “Wholesale Energy Group” for more detail on our results of operations.

 

The following business group and segment information does not include intercompany eliminations or discontinued operations.

 

Retail Services Group

 

Electric Utility

 

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

(in thousands)

 

 

 

 

 

Revenue

$

47,767

$

43,968

Operating expenses

 

35,222

 

33,871

Operating income

$

12,545

$

10,097

 

 

 

 

 

Income from continuing operations

 

 

 

 

and net income

$

6,699

$

4,899

 

The following tables provide certain operating statistics for the Electric utility segment:

 

 

Electric Revenue

 

(in thousands)

 

 

 

Three Months Ended

 

March 31,

 

 

Percentage

 

Customer Base

2007

Change

2006

 

 

 

 

 

 

Commercial

$

13,105

15%

$

11,422

Residential

 

12,407

16

 

10,663

Industrial

 

5,096

2

 

5,011

Municipal sales

 

579

11

 

520

Total retail sales

 

31,187

13

 

27,616

Contract wholesale

 

6,457

6

 

6,108

Wholesale off-system

 

6,582

(20)

 

8,234

Total electric sales

 

44,226

5

 

41,958

Other revenue

 

3,541

76

 

2,010

Total revenue

$

47,767

9%

$

43,968

 

 

29

 

Megawatt Hours Sold

 

 

 

Three Months Ended

 

March 31,

 

 

Percentage

 

Customer Base

2007

Change

2006

 

 

 

 

Commercial

166,094

5%

158,593

Residential

152,736

8

141,794

Industrial

99,254

(4)

103,027

Municipal sales

7,420

5

7,059

Total retail sales

425,504

4

410,473

Contract wholesale

165,110

2

162,251

Wholesale off-system

133,849

(26)

180,163

Total electric sales

724,463

(4)%

752,887

 

 

Three Months Ended

 

March 31,

 

2007

2006

Regulated power

 

 

plant fleet availability:

 

 

Coal-fired plants

95.3%

97.2%

Other plants

99.9%

99.2%

Total availability

97.3%

98.1%

 

 

Three Months Ended

 

March 31,

 

 

Percentage

 

Resources

2007

Change

2006

 

 

 

 

MWhs generated:

 

 

 

Coal

440,518

(3)%

454,133

Gas

   5,698

158

   2,211

 

446,216

(2)%

456,344

 

 

 

 

MWhs purchased

294,463

(6)%

312,287

Total resources

740,679

(4)%

768,631

 

 

Three Months Ended

 

March 31,

 

2007

2006

Heating and cooling degree days:

 

 

Actual

 

 

Heating degree days

3,055

2,946

 

 

 

Percent of normal

 

 

Heating degree days

93%

90%

 

 

30

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $1.8 million primarily due to increased revenues, partially offset by increased fuel and purchased power costs and operating expenses. In addition, wholesale off-system gross margins were flat with the 2006 period.

 

Electric utility revenues increased 9 percent for the three month period ended March 31, 2007, compared to the same period in the prior year. Higher retail revenues were primarily due to increased rates in South Dakota that became effective January 1, 2007. Total retail MWh sales increased 4 percent compared to the three months ended March 31, 2006 due to colder weather conditions and customer growth. Heating degree days, which is a measure of weather trends, were 4 percent higher than the same period in the prior year. Wholesale off-system sales decreased 20 percent due to a 26 percent decrease in MWhs sold partially offset by an 8 percent increase in average price received. MWhs available for wholesale off-system sales decreased from the prior period due to scheduled plant outages and power transmission constraints to the east of our AC-DC transmission tie, and increased native load.

 

Electric operating expenses increased 4 percent for the three month period ended March 31, 2007, compared to the same period in the prior year. Fuel and purchased power costs increased 6 percent due to a 5 percent increase in purchased power at average prices that were 11 percent higher than the same period in the prior year and increased fuel production costs, primarily due to higher average coal prices. MWhs generated and purchased decreased 2 percent and 6 percent, respectively, for the three months ended March 31, 2007 compared to the same period in 2006. Operating expense for the three months ended March 31, 2007 was also affected by increased maintenance costs for scheduled outages and increased depreciation expense.

 

Electric and Gas Utility

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

(in thousands)

 

 

 

 

 

Revenue

$

36,363

$

43,699

Purchased gas and electricity

 

28,588

 

36,175

Gross margin

 

7,775

 

7,524

 

 

 

 

 

Operating expenses

 

5,328

 

5,624

Operating income

$

2,447

$

1,900

 

 

 

 

 

Income from continuing

 

 

 

 

operations and net income

$

3,072

$

1,397

 

 

31

The following tables provide certain operating statistics for the Electric and gas utility segment:

 

Electric Margins

(in thousands)

 

 

Three Months

 

Three Months

 

Ended

 

Ended

 

March 31,

Percentage

March 31,

Customer Base

2007

Change

2006

 

 

 

 

 

 

Commercial

$

1,816

17%

$

1,555

Residential

 

2,215

(2)

 

2,261

Industrial

 

84

(3)

 

87

Municipal

 

144

9

 

132

Total electric

 

4,259

6

 

4,035

Other

 

28

(70)

 

94

Total electric margins

$

4,287

4%

$

4,129

 

 

 

Gas Margins

(in thousands)

 

 

Three Months

 

Three Months

 

Ended

 

Ended

 

March 31,

Percentage

March 31,

Customer Base

2007

Change

2006

 

 

 

 

 

 

Commercial

$

926

8%

$

858

Residential

 

2,185

3

 

2,131

Industrial

 

165

(10)

 

184

Total gas

 

3,276

3

 

3,173

Other

 

212

(5)

 

222

Total gas margins

$

3,488

3%

$

3,395

 

 

 

 

Three Months

 

Three Months

 

Ended

 

Ended

 

March 31,

Percentage

March 31,

 

2007

Change

2006

 

 

 

 

Electric sales - MWh

241,830

4%

232,827

Gas sales-Dth

1,969,585

5%

1,870,454

 

 

32

 

Three Months Ended

 

March 31

 

2007

2006

Heating and cooling degree days:

 

 

Actual

 

 

Heating degree days

3,023

2,991

 

 

 

Percent of normal

 

 

Heating degree days

96%

95%

 

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $1.7 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. The increase in income from continuing operations was impacted by income related to AFUDC attributable to the construction of Wygen II, a 90 MW, coal-fired power plant sited at our Wyodak energy complex near Gillette, Wyoming.

 

Gross margin increased 3 percent primarily due to an increase in sales volumes. We consider gross margin to be a more useful performance measure when looking at our fluctuating financial and statistical figures related to revenue. These fluctuations are a direct result of cost recovery adjustments for electricity and natural gas due to volatile market prices and timing of revenue and expense recognition. Historically, Cheyenne Light has filed an annual adjustment for electricity and more frequent filings for natural gas to manage volatile market price impacts.

 

Operating expenses decreased 5 percent primarily due to decreased depreciation expense and benefit costs.

 

Rate Increase Requested. During March 2007, Cheyenne Light filed a rate request with the WPSC. The filing requests general rate increases of $8.4 million for electric rates and $4.6 million for gas rates, based upon rates in place at December 31, 2006. The requested increases also include placing into rate base Wygen II and other capital investments necessary for the expansion and maintenance of both electric and gas distribution systems to accommodate population and energy growth.

 

Wholesale Energy Group

 

A discussion of results from our Wholesale Energy group’s operating segments follows:

 

Oil and Gas

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

(in thousands)

 

 

 

 

 

Revenue

$

25,843

$

25,185

Operating expenses

 

18,499

 

15,901

Operating income

$

7,344

$

9,284

 

 

 

 

 

Income from continuing operations

$

3,591

$

5,390

 

 

33

The following tables provide certain operating statistics for our oil and gas segment:

 

 

Three Months Ended

 

March 31,

 

2007

2006

Fuel production:

 

 

Bbls of oil sold

   103,415

    90,460

Mcf of natural gas sold

2,678,290

2,959,100

Mcf equivalent sales

3,298,780

3,501,860

 

Production for the three months ended March 31, 2007 was affected by winter weather impacts and lower well performance in the Denver Julesburg Basin. We expect to increase production coming out of the winter season and through additional drilling activity. Drilling activity will be contingent on the issuance of drilling permits and our evaluation of rising costs. We still expect to increase annual production 4-6 percent over the previous year, which is a decrease from our December 31, 2006 estimated growth of 10 percent.

 

 

Three Months Ended

 

March 31,

 

2007

2006

 

 

 

 

 

Average price received*:

 

 

 

 

Gas/Mcf**

$

7.20

$

6.98

Oil/Bbl

$

52.63

$

45.33

 

 

 

 

 

Depletion expense/Mcfe

$

2.04

$

1.62

________________________

   *

Net of hedges

**

Exclusive of gas liquids

 

The following is a summary of LOE/Mcfe at March 31:

 

 

 

2007

 

 

2006