United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q
X QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the quarterly period ended June 30, 2002.
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 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
---------- ----------
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the last practicable date.
Class Outstanding at July 31, 2002
Common stock, $1.00 par value 26,858,241 shares
BLACK HILLS CORPORATION
I N D E X
Page
Number
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Statements of Income- 3
Three, Six and Twelve Months
Ended June 30, 2002 and 2001
Condensed Consolidated Balance Sheets- 4
June 30, 2002, December 31, 2001
and June 30, 2001
Condensed Consolidated Statements of Cash Flows- 5
Six Months Ended
June 30, 2002 and 2001
Notes to Condensed Consolidated Financial Statements 6-22
Item 2. Management's Discussion and Analysis of 23-45
Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about 45
Market Risk
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 46
Item 4. Submission of Matters to a Vote of Security Holders 46
Item 6. Exhibits and Reports on Form 8-K 47
Signatures 48
2
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
Three Months Six Months Twelve Months
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands, except per share amounts)
Operating revenues $ 394,309 $ 404,401 $ 686,374 $ 952,081 $ 1,233,742 $ 1,972,409
--------- --------- ---------- ---------- ----------- -----------
Operating expenses:
Fuel and purchased power 304,382 285,275 514,797 719,248 905,319 1,567,944
Operations and maintenance 15,386 15,399 29,798 28,183 63,073 57,303
Administrative and general 18,054 22,398 30,852 45,520 67,932 79,031
Depreciation, depletion and
amortization 17,972 12,584 34,336 24,404 63,747 43,630
Taxes, other than income taxes 5,621 5,410 11,906 10,981 24,251 19,000
--------- --------- ---------- ---------- ---------- -----------
361,415 341,066 621,689 828,336 1,124,322 1,766,908
--------- --------- ---------- ---------- ----------- -----------
Operating income 32,894 63,335 64,685 123,745 109,420 205,501
--------- --------- ---------- ---------- ----------- -----------
Other income (expense):
Interest expense (10,530) (9,318) (20,151) (20,201) (39,732) (39,729)
Interest income 723 1,008 1,321 1,647 2,478 4,231
Other expense (498) (181) (574) (311) (4,652) (2,875)
Other income 1,853 3,170 3,744 4,745 13,481 11,392
--------- --------- ---------- ---------- ----------- -----------
(8,452) (5,321) (15,660) (14,120) (28,425) (26,981)
--------- --------- ---------- ---------- ----------- -----------
Income from continuing operations
before minority interest, income taxes
and change in accounting principle 24,442 58,014 49,025 109,625 80,995 178,520
Minority interest (1,836) (2,611) (4,102) (4,571) (3,717) (15,909)
Income taxes (7,887) (20,875) (15,311) (39,090) (26,046) (61,386)
--------- --------- ---------- ---------- ----------- -----------
Income from continuing operations
before change in accounting principle 14,719 34,528 29,612 65,964 51,232 101,225
Income (Loss) from discontinued
operations, net of taxes (912) 325 (2,637) 980 (3,124) 1,444
Change in accounting principle, net of
taxes - - 896 - 896 -
--------- --------- ---------- ---------- ----------- -----------
Net income 13,807 34,853 27,871 66,944 49,004 102,669
Preferred stock dividends (56) (300) (112) (342) (297) (420)
--------- --------- ---------- ---------- ----------- -----------
Net income available for common stock $ 13,751 $ 34,553 $ 27,759 $ 66,602 $ 48,707 $ 102,249
========= ========= ========== ========== =========== ===========
Weighted average common shares outstanding:
Basic 26,804 25,502 26,749 24,245 26,610 23,550
========= ========= ========== ========== ============ ===========
Diluted 27,126 25,978 27,045 24,691 26,930 24,014
========= ========= ========== ========== =========== ===========
Earnings per share:
Basic-
Continuing operations $ 0.55 $ 1.34 $ 1.10 $ 2.71 $ 1.91 $ 4.28
Discontinued operations (0.04) 0.01 (0.09) 0.04 (0.11) 0.06
Change in accounting principle - - 0.03 - 0.03 -
--------- --------- ---------- ---------- ------------ -----------
Total $ 0.51 $ 1.35 $ 1.04 $ 2.75 $ 1.83 $ 4.34
========= ========= ========== ========== ============ ===========
Diluted-
Continuing operations $ 0.54 $ 1.33 $ 1.09 $ 2.67 $ 1.90 $ 4.22
Discontinued operations (0.03) 0.01 (0.09) 0.04 (0.11) 0.06
Change in accounting principle - - 0.03 - 0.03 -
--------- --------- --------- --------- ------------ -----------
Total $ 0.51 $ 1.34 $ 1.03 $ 2.71 $ 1.82 $ 4.28
========= ========= ========= ========= ============ ===========
Dividends paid per share of common stock $ 0.29 $ 0.28 $ 0.58 $ 0.56 $ 1.14 $ 1.10
========= ========= ========= ========= ============ ===========
The accompanying notes to condensed consolidated financial statements are an
integral part of these condensed consolidated financial statements.
3
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
June 30 December 31 June 30
2002 2001 2001
---- ---- ----
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 54,346 $ 29,956 $ 36,040
Securities available-for-sale - 3,550 3,263
Receivables (net of allowance for doubtful accounts of $5,145,
$5,913 and $6,452, respectively) - 153,873 110,831 145,839
Derivative assets 50,336 38,144 48,991
Other assets 43,099 29,992 27,546
Assets of discontinued operations 4,927 10,230 15,954
---------- ---------- ----------
306,581 222,703 277,633
---------- ---------- ----------
Investments 19,520 59,895 60,274
---------- ---------- ----------
Property, plant and equipment 1,763,873 1,564,664 1,302,728
Less accumulated depreciation and depletion (389,561) (328,325) (301,759)
---------- ---------- ----------
1,374,312 1,236,339 1,000,969
---------- ---------- ----------
Other assets:
Derivatives assets 1,987 6,407 3,699
Goodwill 30,185 28,693 29,655
Intangible assets 93,760 86,528 15,447
Other 16,219 18,202 17,081
---------- ---------- ----------
142,151 139,830 65,882
---------- ---------- ----------
$1,842,564 $1,658,767 $1,404,758
========== ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 127,756 $ 96,218 $ 137,167
Accrued liabilities 58,904 39,085 47,954
Current maturities of long-term debt 36,457 35,904 14,470
Notes payable 406,109 360,450 71,400
Derivative liabilities 53,852 42,681 54,487
Liabilities of discontinued operations 6,294 8,960 13,613
---------- ---------- ----------
689,372 583,298 339,091
---------- ---------- ----------
Long-term debt, net of current maturities 476,024 415,798 434,332
---------- ---------- ----------
Deferred credits and other liabilities:
Federal income taxes 77,672 75,162 62,193
Derivative liabilities 7,669 7,119 2,694
Other 40,202 42,693 39,348
---------- ---------- ----------
125,543 124,974 104,235
---------- ---------- ----------
Minority interest in subsidiaries 22,546 19,533 27,246
---------- ---------- ----------
Stockholders' equity:
Preferred stock - no par Series 2000-A; 21,500 shares authorized;
Issued and Outstanding: 5,177; 5,177 and 4,893 shares, respectively 5,549 5,549 5,175
---------- ---------- ----------
Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized;
Issued: 27,026,112; 26,890,943 and 26,769,144 shares, respectively 27,026 26,891 26,769
Additional paid-in capital 242,604 240,454 236,956
Retained earnings 262,741 250,515 244,406
Treasury stock, at cost (1,756) (4,503) (8,841)
Accumulated other comprehensive loss (7,085) (3,742) (4,611)
---------- ---------- ----------
523,530 509,615 494,679
---------- ---------- ----------
Total stockholders' equity 529,079 515,164 499,854
---------- ---------- ----------
$1,842,564 $1,658,767 $1,404,758
========== ========== ==========
The accompanying notes to condensed consolidated financial statements are an
integral part of these condensed consolidated financial statements.
4
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Six Months
June 30
2002 2001
---- ----
(in thousands)
Operating activities:
Net income available for common $ 27,759 $ 66,602
Adjustments to reconcile net income available for common to net cash
provided by operating activities:
(Income) loss from discontinued operations 2,637 (980)
Depreciation, depletion and amortization 34,336 24,404
Net change in derivative assets and liabilities (485) (1,786)
Deferred income taxes 4,132 (486)
Undistributed earnings in associated companies (3,964) (7,342)
Minority interest 4,102 4,571
Accounting change (896) -
Change in operating assets and liabilities-
Accounts receivable and other current assets (51,732) 146,012
Accounts payable and other current liabilities 50,390 (106,193)
Other, net (6,428) (5,272)
---------- ----------
59,851 119,530
---------- ----------
Investing activities:
Property, plant and equipment additions (109,920) (235,915)
Payment for acquisition of net assets, net of cash acquired (23,229) (10,410)
Other, net 1,751 (57)
---------- ----------
(131,398) (246,382)
---------- ----------
Financing activities:
Dividends paid on common stock (15,533) (13,429)
Treasury stock sold, net 2,747 226
Common stock issued 2,285 165,160
Increase (decrease) in short-term borrowings, net 45,659 (139,600)
Long-term debt - issuance 71,003 135,689
Long-term debt - repayments (10,224) (7,939)
Subsidiary distributions to minority interests - (1,505)
---------- ----------
95,937 138,602
---------- ----------
Increase in cash and cash equivalents 24,390 11,750
Cash and cash equivalents:
Beginning of period 29,956 24,290
---------- ----------
End of period $ 54,346 $ 36,040
========== ==========
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $ 20,437 $ 19,954
Income taxes $ 725 $ 34,800
Non-cash net assets acquired through issuance of common and preferred
stock $ - $ 2,747
The accompanying notes to condensed consolidated financial statements are an
integral part of these condensed consolidated financial statements.
5
BLACK HILLS CORPORATION
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company's 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 Securities and Exchange Commission. Certain
information and footnote disclosures normally included in financial
statements prepared in accordance with accounting principles generally
accepted in the United States 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 2001 Annual
Report on Form 10-K filed with the Securities and Exchange Commission.
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 June 30, 2002,
December 31, 2001 and June 30, 2001, financial information and are of a
normal recurring nature. The results of operations for the three, six
and twelve months ended June 30, 2002, 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) RECLASSIFICATIONS
Certain 2001 amounts in the financial statements have been reclassified
to conform to the 2002 presentation. These reclassifications did not
have an effect on the Company's total stockholders' equity or net
income available for common stock as previously reported.
(3) RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" (SFAS 143). SFAS 143 requires that the
fair value of a liability for an asset retirement obligation be
recognized in the period in which it is incurred with the associated
asset retirement costs being capitalized as part of the carrying amount
of the long-lived asset. Over time, the liability is accreted to its
present value each period and the capitalized cost is depreciated over
the useful life of the related asset. Management expects to adopt SFAS
143 effective January 1, 2003 and is currently evaluating the effects
adoption will have on the Company's consolidated financial statements.
6
During June 2002, the Emerging Issues Task Force (EITF) reached a
consensus on Issues 1 and 3 of EITF Issue No. 02-3, "Recognition and
Reporting of Gains and Losses on Energy Trading Contracts under EITF
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities," and No. 00-17, "Measuring the Fair
Value of Energy-Related Contracts in Applying Issue No. 98-10."
Under EITF 02-3, Issue 1 of the consensus requires mark-to-market gains
and losses on energy trading contracts to be shown net on the income
statement whether or not physically settled in financial statements
issued for periods ending after July 15, 2002. Issue 3 requires
entities involved in energy trading activities to include certain
additional disclosures in financial statements issued for fiscal years
ending after July 15, 2002. EITF 02-3 also requires that all
comparative financial statements be reclassified to conform to EITF
02-3. Although EITF 02-3 will require the Company's mark-to-market
gains and losses on energy trading contracts to be shown net on the
income statement, it is not expected to impact the Company's net
income, stockholders' equity or cash flows. The Company will adopt the
guidance of Issue 1 during the third quarter, but has not yet
quantified the financial statement effect from this adoption.
(4) RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
In June 2001, the FASB issued Statement of Financial Accounting
Standards No. 141, "Business Combinations," (SFAS 141) and No. 142,
"Goodwill and Other Intangible Assets" (SFAS 142). The Company has
adopted SFAS 141, which requires all business combinations initiated
after June 30, 2001 to be accounted for using the purchase method of
accounting. Under SFAS 142, goodwill and intangible assets with
indefinite lives are no longer amortized but the carrying values are
reviewed annually (or more frequently if impairment indicators arise)
for impairment. If the carrying value exceeds the fair value, an
impairment loss shall be recognized. A discounted cash flow approach
was used to determine fair value of the Company's businesses for the
purposes of testing for impairment. Intangible assets with a defined
life will continue to be amortized over their useful lives (but with no
maximum life). The Company adopted SFAS 142 on January 1, 2002.
7
The pro forma effects of adopting SFAS No. 142 for the three, six and
twelve month periods ended June 30, 2002 and 2001 are as follows (in
thousands):
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Net income as reported $13,807 $34,853 $27,871 $66,944 $49,004 $102,669
Cumulative effect of change in
accounting principle, net of tax - - (896) - (896) -
Cumulative effect of change in
accounting principle included in
"Discontinued operations," net
of tax - - 755 - 755 -
------- ------- ------- ------- ------- --------
Income excluding cumulative
effect of change in accounting
principle 13,807 34,853 27,730 66,944 48,863 102,669
Add: goodwill amortization - 463 - 871 447 2,051
------- ------- ------- ------- ------- --------
Adjusted net income $13,807 $35,316 $27,730 $67,815 $49,310 $104,720
======= ======= ======= ======= ======= ========
The cumulative effect adjustment recognized upon adoption of SFAS 142
was $0.1 million (after tax), which had only a nominal impact on
earnings per share. The adjustment consisted of income from the
after-tax write-off of negative goodwill from prior acquisitions in our
power generation segment of $0.9 million, offset by a $0.8 million
after-tax write-off for the impairment of goodwill related to our
discontinued coal marketing operations (Note 5). The goodwill
impairment was a result of changes in the criteria for the measurement
of impairments from an undiscounted to a discounted cash flow method.
If SFAS 142 had been adopted on January 1, 2001, net income would have
been lower for the six month period ended June 30, 2002 by $0.1
million, or 1 cent per share and higher for the twelve month period
ended June 30, 2002 by $0.3 million, or 1 cent per share, respectively.
The three, six and twelve month periods ended June 30, 2001 would have
been higher by $0.5 million, or 2 cents per share, $0.9 million, or 4
cents per share, and $2.1 million, or 9 cents per share, respectively.
The substantial majority of the Company's goodwill and intangible
assets are contained within the Power Generation segment. Changes to
goodwill and intangible assets during the six-month period ended June
30, 2002, including the effects of adopting SFAS No. 142, but excluding
amounts from discontinued operations, are as follows (in thousands):
Goodwill Other Intangible Assets
-------- -----------------------
Balance at December 31, 2001, net of
accumulated amortization $28,693 $86,528
Change in accounting principle 1,492 -
Additions - 9,504
Amortization expense - (2,272)
------- -------
Balance at June 30, 2002, net of
accumulated amortization $30,185 $93,760
======= =======
8
On June 30, 2002, intangible assets totaled $93.8 million, net of
accumulated amortization of $6.7 million. Intangible assets are
primarily related to site development fees and above-market long-term
contracts, and all have definite lives ranging from 5 to 40 years, over
which they continue to be amortized. Amortization expense for existing
intangible assets is expected to be approximately $5.1 million to $4.5
million for each year from 2003 to 2007.
Intangible assets increased during the six month period ended June 30,
2002 as a result of a $9.5 million addition related to preliminary
purchase allocations in the acquisition of additional ownership
interest in the Harbor Cogeneration Facility (See Note 13). This
intangible asset primarily relates to an acquired ownership of
additional interest in a contract termination payment stream at the
Facility.
In addition, during the first quarter of 2002, the Company had a $0.4
million (pre-tax) impairment loss of certain intangibles at the
Company's discontinued coal marketing business as a result of a weak
coal market. The intangible assets are included in "Assets of
discontinued operations" on the accompanying Condensed Consolidated
Balance Sheets and the related impairment loss is included in "(Loss)
Income from discontinued operations" on the accompanying Condensed
Consolidated Statements of Income.
In August 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". SFAS 144 supersedes FASB
Statement 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of" (SFAS 121) and the accounting
and reporting provisions of Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations - Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions" (APB 30). SFAS 144
establishes a single accounting model for long-lived assets to be
disposed of by sale as well as resolves implementation issues related
to SFAS 121. The Company adopted SFAS 144 effective January 1, 2002.
Adoption did not have a material impact on the Company's consolidated
financial position, results of operations or cash flows.
(5) DISCONTINUED OPERATION
During the second quarter of 2002, the Company adopted a plan to
dispose of its coal marketing subsidiary, Black Hills Coal Network. The
sale and disposal was finalized in July 2002. In connection with the
plan of disposal, the Company determined that the carrying values of
some of the underlying assets exceeded their fair values and a charge
to operations was required.
Consequently, the Company recorded an after-tax charge of approximately
$1.0 million, which represents the difference between the carrying
values of the assets and liabilities of the subsidiary versus their
fair values, less cost to sell. The disposition has been accounted for
under the provisions of Statement of Financial Accounting Standards No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
Accordingly, results of operations and the related charge have been
classified as "Discontinued operations" in the accompanying Condensed
Consolidated Statements of Income, and prior periods have been
restated. For business segment reporting purposes, the coal marketing
business results were previously included in the segment "Fuel
Marketing."
9
Revenues and net income from the discontinued operation are as follows
(in thousands):
Three Months Six Months Twelve Months
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Revenues $7,736 $14,648 $17,697 $28,661 $47,990 $47,294
------ ------- ------- ------- ------- -------
Pre-tax income (loss) from
discontinued operation 130 617 (2,744) 1,709 (3,567) 2,499
Pre-tax loss on disposal (1,523) - (1,523) - (1,523) -
Income tax benefit (expense) 481 (292) 1,630 (729) 1,966 (1,055)
------ -------- ------- -------- ------- -------
Net (loss) income from
discontinued operations $ (912) $ 325 $(2,637) $ 980 $(3,124) $ 1,444
====== ======== ======= ======== ======= =======
Assets and liabilities of the discontinued operation are as follows (in
thousands):
June 30 December 31 June 30
2002 2001 2001
---- ---- ----
Current assets $ 4,927 $7,878 $14,184
Non-current assets - 2,352 1,770
Current liabilities (5,345) (8,724) (13,613)
Non-current liabilities (949) (236) -
-------- ------ -------
Net assets (liabilities) of
discontinued operations $ (1,367) $1,270 $ 2,341
======== ====== =======
(6) EARNINGS PER SHARE
Basic earnings per share is computed by dividing net income by the
weighted average number of common shares outstanding during the period.
Diluted earnings per share gives effect to all dilutive potential
common shares outstanding during a period. A reconciliation of "Income
from continuing operations" and basic and diluted share amounts is as
follows:
Periods ended June 30, 2002 Three Months Six Months Twelve Months
------------ ---------- -------------
(in thousands) Average Average Average
Income Shares Income Shares Income Shares
------ ------ ------ ------ ------ ------
Income from continuing
operations $14,719 $29,612 $51,232
Less: preferred stock
dividends (56) (112) (297)
------- ------- -------
Basic - available for common
shareholders 14,663 26,804 29,500 26,749 50,935 26,610
Dilutive effect of:
Stock options - 148 - 122 - 146
Convertible preferred stock 56 148 112 148 297 148
Others - 26 - 26 - 26
------- ------ ------- ------ ------- ------
Diluted - available for
common shareholders $14,719 27,126 $29,612 27,045 $51,232 26,930
======= ====== ======= ====== ======= ======
10
Periods ended June 30, 2001 Three Months Six Months Twelve Months
(in thousands) ------------ ---------- -------------
Average Average Average
Income Shares Income Shares Income Shares
------ ------ ------ ------ ------ ------
Income from continuing
operations $34,528 $65,964 $101,225
Less: preferred stock
dividends (300) (342) (420)
------- ------- --------
Basic - available for common
shareholders 34,228 25,502 65,622 24,245 100,805 23,550
Dilutive effect of:
Stock options - 306 - 278 - 301
Convertible preferred stock 300 140 342 140 420 137
Others - 30 - 28 - 26
------- ------ ------- ------ -------- ------
Diluted - available for
common shareholders $34,528 25,978 $65,964 24,691 $101,225 24,014
======= ====== ======= ====== ======== ======
(7) COMPREHENSIVE INCOME
The following table presents the components of the Company's
comprehensive income:
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Net income $13,807 $34,853 $27,871 $66,944 $49,004 $102,669
Other comprehensive income:
Unrealized gain (loss) on
available-for-sale securities - 127 (219) 1,151 68 (150)
Reclassification adjustment
for unrealized gain on
available-for-sale securities
included in net income (406) - (406) - (406) -
Initial impact of adoption of
SFAS 133, net of minority
interest - - - (7,518) - (7,518)
Fair value adjustment on
derivatives designated as
cash flow hedges (3,227) 5,005 (2,718) 2,569 (2,136) 2,569
------- ------- ------- ------- ------- --------
Comprehensive income $10,174 $39,985 $24,528 $63,146 $46,530 $97,570
======= ======= ======= ======= ======= ========
11
(8) CHANGES IN COMMON STOCK
Other than the following transactions, the Company had no other changes
in its common stock, as reported in Note 4 of the Company's 2001 Annual
Report on Form 10-K.
o The Company granted 95,220 stock options at a weighted average
exercise price of $34.64 per share.
o 110,864 stock options were exercised at a weighted average
exercise price of $20.84 per share.
o The Company issued 26,047 restricted shares of common stock to
certain officers. Pre-tax compensation cost related to the award
was $0.9 million, which is being expensed over the vesting period
ranging from two to three years.
o The Company issued 16,256 shares of common stock under its
dividend reinvestment plan.
o The Company issued 8,099 shares of common stock under its
employee stock purchase plan at a price of $27.08 per share.
o The Company issued 45,043 shares of common stock under the
short-term incentive compensation plan.
(9) CHANGES IN LONG-TERM DEBT AND NOTES PAYABLE
On January 4, 2002, the Company closed on a $50.0 million bridge credit
agreement. The credit agreement supplements our revolving credit
facilities in place at December 31, 2001 and has the same terms as
those facilities with an expiration date that has now been extended to
August 28, 2002. This bridge facility was fully drawn at June 30, 2002.
On March 15, 2002, the Company closed on $135 million of senior secured
financing for the Arapahoe and Valmont Facilities. These projects have
a total of 210 megawatts in service and under construction and are
located in the Denver, Colorado area. Proceeds from this financing were
used to refinance $53.8 million of an existing seven-year senior
secured term project-level facility, pay down approximately $50.0
million of short-term credit facility borrowings and approximately
$31.2 million will be used for future project construction. At June 30,
2002, $124.9 million of the $135 million financing has been utilized.
On June 18, 2002, we closed on a $75 million bridge credit agreement.
As of June 30, 2002, there were no borrowings outstanding under this
bridge credit agreement. This credit agreement bridges the issuance of
$75 million of Black Hills Power First Mortgage Bonds, which we issued
on August 13, 2002. The termination date of the bridge credit agreement
was August 13, 2002, the date on which the First Mortgage Bonds were
issued.
12
On June 28, 2002, Enserco Energy closed on a $135 million uncommitted,
discretionary credit facility, which became effective July 1, 2002 and
expires June 27, 2003. This facility replaced the $75 million Enserco
Energy facility.
Our credit facilities include certain restrictive covenants that are
common in such arrangements. Such covenants include a consolidated net
worth in an amount of not less than the sum of $375 million and 50
percent of the aggregate consolidated net income beginning June 30,
2001; a recourse leverage ratio not to exceed 0.65 to 1.00; an interest
coverage ratio of not less than 3.00 to 1.00; and restrictions on the
ability to dividend cash to the parent company at certain subsidiaries
with project level financing approximately $23 million at June 30,
2002. If these covenants are violated, it would be considered an event
of default entitling the lender to terminate the remaining commitment
and accelerate all principal and interest outstanding to become
immediately due. In addition, certain of our interest rate swap
agreements include cross-default provisions. These provisions would
allow the counterparty the right to terminate the swap agreement and
liquidate at a prevailing market rate, in the event of default. The
Company and its subsidiaries complied with all the covenants at June
30, 2002.
Some of the facilities previously had a covenant whereby we were
required to maintain a credit rating of at least "BBB-" from Standard &
Poor's or "Baa3" from Moody's Investor Service. The facilities that
contained the rating triggers were amended during the second quarter of
2002 to remove default provisions pertaining to our credit rating
status.
Other than the above transactions, the Company had no other material
changes in its consolidated indebtedness, as reported in Notes 6 and 7
of the Company's 2001 Annual Report on Form 10-K.
(10) 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 June 30, 2002, substantially all of the Company's
operations and assets are located within the United States. The
Company's operations are conducted through six reporting segments that
include: Electric group and segment, which supplies electric utility
service to western South Dakota, northeastern Wyoming and southeastern
Montana; Integrated Energy group consisting of the following segments:
Mining, which engages in the mining and sale of coal from its mine near
Gillette, Wyoming; Oil and Gas, which produces, explores and operates
oil and gas interests located in the Rocky Mountain region, Texas,
California and other states; Fuel Marketing, which markets natural gas,
oil and related services to customers in the Midwest, Southwest, Rocky
Mountain, West Coast and Northwest regions; Power Generation, which
produces and sells power to wholesale customers; and Communications
group and Others, which primarily markets communications and software
development services.
13
Segment information follows the same accounting policies as described
in Note 1 of the Company's 2001 Annual Report on Form 10-K. In
accordance with the provisions of SFAS No. 71, intercompany coal sales
are not eliminated. Segment information included in the accompanying
Condensed Consolidated Balance Sheets and Condensed Consolidated
Statements of Income is as follows (in thousands):
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
Quarter to Date
June 30, 2002
Fuel marketing $296,064 $ 2,642 $ 2,397
Power generation 39,099 - 4,174
Oil and gas 6,260 606 1,283
Mining 4,259 2,622 2,494
Electric 38,253 50 6,792
Communications 7,752 465 (2,049)
Corporate - - (365)
Intersegment eliminations - (3,763) (7)
-------- ------- -------
Total $391,687 $ 2,622 $14,719
======== ======= =======
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
Quarter to Date
June 30, 2001
Fuel marketing $297,432 $ 9,403 $11,468
Power generation 24,975 - 3,687
Oil and gas 8,251 1,024 2,963
Mining 5,237 2,644 2,307
Electric 61,280 321 16,784
Communications 4,582 1,117 (2,792)
Corporate - - 365
Intersegment eliminations - (11,865) (254)
-------- ------- -------
Total $401,757 $ 2,644 $34,528
======== ======= =======
14
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
Year to Date
June 30, 2002
Fuel marketing $498,165 $ 3,809 $ 3,903
Power generation 71,182 - 8,951
Oil and gas 11,651 1,304 2,161
Mining 9,709 5,374 4,829
Electric 75,362 132 14,614
Communications 14,933 830 (4,276)
Corporate - - (563)
Intersegment eliminations - (6,077) (7)
-------- ------- -------
Total $681,002 $ 5,372 $29,612
======== ======= =======
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
Year to Date
June 30, 2001
Fuel marketing $735,718 $12,994 $26,373
Power generation 43,020 - 2,582
Oil and gas 16,833 1,024 5,919
Mining 10,658 5,486 4,623
Electric 131,858 322 34,124
Communications 8,508 2,217 (6,682)
Corporate - - (467)
Intersegment eliminations - (16,557) (508)
-------- ------- -------
Total $946,595 $ 5,486 $65,964
======== ======= =======
15
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
12 Months Ended
June 30, 2002
Fuel marketing $ 872,572 $ 6,632 $12,095
Power generation 122,456 - 7,945
Oil and gas 25,436 3,069 6,439
Mining 19,602 11,136 11,798
Electric 155,859 665 25,730
Communications 26,683 2,862 (9,894)
Corporate - - (2,656)
Intersegment eliminations - (13,230) (225)
---------- ------- -------
Total $1,222,608 $11,134 $51,232
========== ======= =======
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
12 Months Ended
June 30, 2001
Fuel marketing $1,579,366 $ 26,170 $ 38,767
Power generation 82,193 329 5,694
Oil and gas 27,782 2,169 8,783
Mining 22,478 10,283 7,714
Electric 235,915 376 56,943
Communications 14,392 3,987 (14,495)
Corporate - - (1,390)
Intersegment eliminations - (33,031) (791)
---------- -------- --------
Total $1,962,126 $ 10,283 $101,225
========== ======== ========
Other than the following transactions, the Company had no other
material changes in total assets of its reporting segments, as reported
in Note 14 of the Company's 2001 Annual Report on Form 10-K, beyond
discontinuing the coal marketing operations (Note 5) previously
included in the "Fuel Marketing" segment and changes resulting from
normal operating activities.
The Power Generation segment had a net addition to non working capital
assets of approximately $75 million primarily related to ongoing
construction of the expansions at the Las Vegas Cogeneration and
Arapahoe facilities and the acquisition of additional ownership
interest at the Harbor Cogeneration facility (Note 13).
The Fuel Marketing segment acquired additional ownership interest in a
pipeline company for $11.0 million (Note 13).
16
(11) RISK MANAGEMENT ACTIVITIES
The Company actively manages its exposure to certain market risks as
described in Note 2 of the Company's 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:
Energy Marketing Activities
The Company's energy marketing operations fall under the purview of
Statement of Financial Accounting Standard No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities" and
Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy
Trading and Risk Management Activities" (EITF 98-10). As such, these
activities are accounted for under mark-to-market accounting. The
Company records the fair values of its trading derivatives as either
Derivative assets and/or Derivative liabilities on the accompanying
Condensed Consolidated Balance Sheet. The net mark-to-market gains or
losses are recorded as Revenues in the accompanying Condensed
Consolidated Statements of Income. During the second quarter 2002, the
Company's gas marketing subsidiary revised its estimates of fair values
for certain derivatives valued using market based prices which include
a "bid/offer" spread. The change in estimate resulted in a $0.8 million
reduction in net income versus amounts that would have been reported if
the change in estimate had not occurred.
The contract or notional amounts and terms of the Company's derivative
commodity instruments held for trading purposes are set forth below:
June 30, 2002 December 31, 2001 June 30, 2001
Maximum Maximum Maximum
Notional Term in Notional Term in Notional Term in
(thousands of MMBtu's) Amounts Years Amounts Years Amounts Years
------- ----- ------- ------- ------- -------
Natural gas basis swaps purchased 44,871 1 9,882 1 29,064 2
Natural gas basis swaps sold 53,504 1 10,696 1 29,284 2
Natural gas fixed-for float swaps purchased 20,783 1 10,646 2 15,470 1
Natural gas fixed-for-float swaps sold 24,723 1 11,815 2 11,728 1
Natural gas swing swaps purchased - - 465 1 1,045 1
Natural gas swing swaps sold - - 930 1 12,624 1
Natural gas physical purchases 40,431 1 13,159 1 22,184 1
Natural gas physical sales 46,909 1 19,339 1 26,945 1
Transport purchase 51,273 5 41,136 6 30,891 6
(thousands of barrels)
Crude oil purchased 4,002 1 3,139 1 2,655 1
Crude oil sold 4,038 1 3,142 1 2,538 1
(megawatthours)
Power purchased 30,400 1 - - - -
Power sold 30,400 1 - - - -
17
As required under SFAS 133 and EITF 98-10, derivatives and energy
trading activities were marked to fair value and the gains and/or
losses recognized in earnings. The amounts related to the accompanying
Condensed Consolidated Balance Sheets and Statements of Income as of
June 30, 2002, December 31, 2001, and June 30, 2001, are as follows (in
thousands):
Current Non-current Current Non-current
Derivative Derivative Derivative Derivative Unrealized
June 30, 2002 Assets Assets Liabilities Liabilities Gain
------ ------ ----------- ----------- ----
Natural gas $43,960 $ 1,831 $38,933 $1,146 $5,712
Crude Oil 5,724 - 4,959 - 765
Power 243 - 95 - 148
------- ------- ------- ------ ------
$49,927 $ 1,831 $43,987 $1,146 $6,625
======= ======= ======= ====== ======
December 31, 2001
Natural gas $29,755 $ 661 $25,437 $ 953 $4,026
Crude Oil 6,267 - 5,497 - 770
------- ------- ------- ------- ------
$36,022 $ 661 $30,934 $ 953 $4,796
======= ======= ======= ======= ======
June 30, 2001
Natural gas $40,555 $3,699 $38,960 $2,694 $2,600
Crude oil 7,153 - 6,475 - 678
------- ------ ------- ------ ------
$47,708 $3,699 $45,435 $2,694 $3,278
======= ====== ======= ====== ======
At June 30, 2002, the Company had a mark to fair value unrealized gain
of $6.6 million for its energy marketing activities. Of this amount,
$5.9 million was current and $0.7 million was non-current.
Substantially all of the unrealized gain at June 30, 2002 results from
"back to back" transactions. The Company anticipates that substantially
all of the current portion of unrealized gains for hedged transactions
will be realized during the next twelve months.
18
Non-trading Energy Activities
On June 30, 2002, December 31, 2001 and June 30, 2001, the Company had
the following swaps and related balances for its non-trading energy
operations (in thousands):
Pre-tax
Accumulated
Maximum Current Non-current Current Non-current Other Pre-tax
Terms in Derivative Derivative Derivative Derivative Comprehensive Income
Notional* Years Assets Assets Liabilities Liabilities Income (Loss) (Loss)
--------- ----- ------ ------ ----------- ----------- ------------- ------
June 30, 2002
Crude oil swaps 270,000 1 $ - $ - $ 739 $ - $ (556) $(183)
Natural gas swaps 1,320,000 1 409 - 336 - 71 2
------ ------- ------- ------- ------- ------
$ 409 $ - $ 1,075 $ - $ (485) $(181)
====== ======= ======= ======= ======= =====
December 31, 2001
Crude oil swaps 90,000 1 $ 529 $ - $ - $ - $ 529 $ -
Natural gas swaps 1,216,000 1 1,593 - - - 1,463 130
------ ------- ------- ------- ------- -----
$2,122 $ - $ - $ - $ 1,992 $ 130
====== ======= ======= ======= ======= =====
June 30, 2001
Crude oil swaps 192,000 1 $ 298 $ - $ - $ - $ 378 $ (80)
Crude oil options 60,000 1 92 - - - 75 17
Natural gas swaps 676,000 1 893 - - - 893 -
------ ------- ------- ------- ------- ------
$1,283 $ - $ - $ - $ 1,346 $ (63)
====== ======= ======= ======= ======= ======
- -----------------------
*crude in bbls, gas in MMBtu's
Based on June 30, 2002 market prices, $(0.5) million will be realized
and reported in earnings during the next twelve months. These estimated
realized losses for the next twelve months were calculated using June
30, 2002 market prices. Estimated and actual realized losses will
likely change during the next twelve months as market prices change.
19
Financing Activities
On June 30, 2002, December 31, 2001 and June 30, 2001, 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 Pre-tax
Notional Interest Terms in Derivative Derivative Derivative Derivative Comprehensive Income
Amount Rate Years Assets Assets Liabilities Liabilities Income (Loss) (Loss)
------ ---- ----- ------ ------ ----------- ----------- -------------- ------
June 30, 2002
Swaps on project
financing $215,017 6.00% 4 $ - $ 156 $ 7,514 $ 6,255 $(13,551) $ (62)
Swaps on corporate
debt 75,000 4.45% 2 - - 1,276 268 (1,544) -
-------- ----- ------ ------- ------- -------- ------
Total $290,017 $ - $ 156 $ 8,790 $ 6,523 $(15,095) $ (62)
======== ===== ====== ======= ======= ======== ======
December 31, 2001
Swaps on project
financing $316,397 5.85% 4 $ - $5,746 $10,212 $ 5,949 $(10,415) $ -
Swaps on corporate
debt 75,000 4.45% 3 - - 1,535 217 (1,752) -
-------- ----- ------ ------- ------- -------- ------
Total $391,397 $ - $5,746 $11,747 $ 6,166 $(12,167) $ -
======== ===== ====== ======= ======= ======== ======
June 30, 2001
Swaps on project
financing $126,161 7.36% 5 $ - $ - $ 8,603 $ - $ (8,603) $ -
Swaps on corporate
debt 50,000 5.19% 3 - - 449 - (449) -
-------- ----- ------ ------- ------- -------- ------
-
Total $176,161 $ - $ - $ 9,052 $ - $ (9,052) $ -
======== ===== ====== ======= ======= ======== ======
Based on June 30, 2002 market interest rates, approximately $8.8
million will be realized as additional interest expense during the next
twelve months. Estimated and realized amounts will likely change during
the next twelve months as market interest rates change.
At December 31, 2001, the Company had a $100 million forward starting
floating-to-fixed interest rate swap to hedge the anticipated floating
rate debt financing related to the Company's Las Vegas Cogeneration
expansion. This swap terminated during the second quarter 2002 and
resulted in a $1.1 million gain. This swap was treated as a cash flow
hedge and accordingly the resulting gain will continue to be carried in
Accumulated Other Comprehensive Income on the Condensed Consolidated
Balance Sheet and amortized over the life of the related long-term
financing.
In addition, the Company entered into a $50 million treasury lock to
hedge a portion of the Company's $75 million First Mortgage Bond
offering completed in August 2002 (Note 14). The treasury lock
effectively fixes, at current rates, the interest rate for the first
28.5 years of the 30-year bonds. The treasury lock cash settled on
August 8, 2002, the bond pricing date, and resulted in a loss which
will continue to be carried in Accumulated Other Comprehensive Income
on the Condensed Consolidated Balance Sheet and amortized over the life
of the related bonds as additional interest expense. At June 30, 2002,
the treasury lock had a fair market value of $0.
20
(12) LEGAL PROCEEDINGS
In June 2002, a forest fire damaged approximately 10,800 acres of
private and government land located near Deadwood and Lead, South
Dakota. The fire destroyed approximately 20 structures (seven houses
and 13 outbuildings) and caused the evacuation of the cities of Lead
and Deadwood for approximately 48 hours.
The cause of the fire was investigated by the State of South Dakota.
Sagging power lines owned by us were implicated as the cause. We have
initiated our own investigation into the cause of the fire, including
the hiring of expert fire investigators, and that investigation is
continuing.
Although we have been put on notice of potential claims, no civil
action or regulatory proceeding has been initiated against us at this
time. If, however, it is determined that sagging power lines owned by
us were the cause of the fire and that we were negligent in the
maintenance of those power lines, we could be liable for resultant
damages. Although we cannot predict the outcome of either our
investigation or of potential claims, management believes that any such
claims will not have a material adverse effect on our financial
condition or results of operations.
(13) ACQUISITIONS
On March 8, 2002, the Company acquired an additional 67 percent
ownership interest in Millennium Pipeline Company L.P., which owns and
operates a 200-mile pipeline. The pipeline has a capacity of
approximately 65,000 barrels of oil per day, and transports imported
crude oil from Beaumont, Texas to Longview, Texas, which is the
transfer point to connecting carriers. The Company also acquired
additional ownership interest in Millennium Terminal Company, L.P.,
which has 1.1 million barrels of crude oil storage connected to the
Millennium Pipeline at the Oil Tanking terminal in Beaumont. The
millennium system is presently operating near capacity through shipper
agreements. These acquisitions give the Company 100 percent ownership
in the Millennium companies. Total cost of the acquisitions was $11.0
million and was funded through borrowings under short-term revolving
credit facilities.
On March 15, 2002, the Company paid $25.7 million to acquire an
additional 30 percent interest in the Harbor Cogeneration Facility (the
Facility), a 98-megawatt gas-fired plant located in Wilmington,
California. This acquisition was funded through borrowings under
short-term revolving credit facilities and gives the Company an 83
percent ownership interest and voting control of the Facility.
The Company's investments in these entities prior to the above
acquisitions were accounted for under the equity method of accounting
and included in Investments on the accompanying Condensed Consolidated
Balance Sheets. Each of the above acquisitions gave the Company
majority ownership and voting control of the respective entities,
therefore, the Company now includes the accounts of each of the
entities in its consolidated financial statements.
21
The above acquisitions have been accounted for under the purchase
method of accounting and, accordingly, the purchase prices have been
allocated to the acquired assets and liabilities based on preliminary
estimates of the fair values of the assets purchased and the
liabilities assumed as of the date of acquisition. The estimated
purchase price allocations are subject to adjustment, generally within
one year of the date of the acquisition. The purchase prices and
related acquisition costs exceeded the fair values assigned to net
tangible assets by approximately $9.5 million, which was recorded as
long-lived intangible assets.
The impact of these acquisitions was not material in relation to the
Company's results of operations. Consequently, pro forma information is
not presented.
(14) SUBSEQUENT EVENT
During July 2002, the Company's integrated energy subsidiary, Black
Hills Energy Resources, purchased the assets of the Kilgore to Houston
Pipeline System from Equilon Pipeline Company, LLC. The Kilgore
pipeline transports crude oil from the Kilgore, Texas region south to
Houston, Texas, which is the transfer point to connecting carriers via
the Oiltanking Houston terminal facilities. The 10-inch pipeline is
approximately 190 miles long and has a capacity of up to approximately
35,000 barrels per day. In addition, the Kilgore system has
approximately 400,000 barrels of crude oil storage at Kilgore and
375,000 barrels of storage at the Texoma Tank Farm located in Longview,
Texas. Total cost of the acquisition was $6.7 million and was funded
through borrowings under short-term credit facilities.
On August 13, 2002, the Company issued $75 million of First Mortgage
Bonds, Series AE, due 2032. The Mortgage Bonds have a 7.23% coupon with
interest payable semi-annually, commencing February 15, 2003. Net
proceeds from the offering were and will be used to fund the Company's
portion of construction and installation costs for an AC-DC-AC
Converter Station; for general capital expenditures for the remainder
of 2002 and 2003; to repay a portion of current bank indebtedness; to
satisfy bond maturities for certain outstanding first mortgage bonds
due in 2003; and for general corporate purposes.
22
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
We are a growth oriented, diversified energy holding company operating
principally in the United States. Our unregulated and regulated businesses have
expanded significantly in recent years. Our integrated energy group, Black Hills
Energy, Inc., produces and markets electric power and fuel. We produce and sell
electricity in a number of markets, with a strong emphasis in the western United
States. We also produce coal, natural gas and crude oil, primarily in the Rocky
Mountain region, and market fuel products nationwide. Our electric utility,
Black Hills Power, Inc., serves approximately 59,200 customers in South Dakota,
Wyoming and Montana. Our communications group offers state-of-the-art broadband
communications services to residential and business customers in Rapid City and
the northern Black Hills region of South Dakota through Black Hills FiberCom,
LLC.
The following discussion should be read in conjunction with Item 7. -
Management's Discussion and Analysis of Financial Condition and Results of
Operations - included in our 2001 Annual Report on Form 10-K filed with the
Securities and Exchange Commission. Our business strategy, industry outlooks,
capital requirements and market risks as disclosed in that filing continue to be
consistent with management's current expectations and assessments.
Results of Operations
Consolidated Results
Revenue and net income (loss) from continuing operations provided by each
business group as a percentage of our total revenue and net income were as
follows:
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Revenues
Integrated energy 88% 84% 87% 85% 85% 87%
Electric utility 10 15 11 14 13 12
Communications 2 1 2 1 2 1
--- --- --- --- --- ---
100% 100% 100% 100% 100% 100%
=== === === === === ===
Net Income/(Loss) from
Continuing Operations
Integrated energy 69% 59% 66% 59% 71% 58%
Electric utility 46 48 49 51 49 56
Communications and other (15) (7) (15) (10) (20) (14)
--- --- --- --- --- ---
100% 100% 100% 100% 100% 100%
=== === === === === ===
23
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001.
Consolidated income from continuing operations for the three month period ended
June 30, 2002 were $14.7 million or $0.54 per share compared to $34.5 million or
$1.33 per share in the same period of the prior year.
The decrease in income from continuing operations was a result of substantial
decreases in prevailing prices for natural gas, crude oil and wholesale
electricity and in gross margins from natural gas marketing activities compared
to the same period in 2001. Unusual energy marketing conditions existed in the
second quarter of 2001 stemming primarily from gas and electricity shortages in
the West. More than half of the 2001 second quarter income from continuing
operations was attributed to the unusual market conditions that existed at that
time. Wholesale electricity average peak prices at Mid-Columbia were around $210
per megawatt-hour during the second quarter of 2001 compared to approximately
$18 per megawatt-hour during the second quarter of 2002. Average spot gas prices
in the West Coast region were approximately $9 per MMBtu in the second quarter
of 2001 compared to $3 in the second quarter of 2002. While the above factors
contributed negatively to income from continuing operations, we had an increase
in the production of coal, oil and natural gas, an increase in independent power
generation capacity and our communications business group showed a decrease in
its net loss attributable to a substantial expansion of its customer base.
Changes in commodity prices also resulted in unrealized gains recognized through
mark-to-market accounting at our Fuel Marketing segment having a positive impact
on 2002 income from continuing operations compared to 2001.
In addition, during the second quarter of 2002 we decided to discontinue
operations in our coal marketing business due primarily to challenges
encountered in marketing our Wyodak coal from the Powder River Basin of Wyoming
to midwestern and eastern coal markets. We sold the non-strategic assets
effective August 1, 2002. Income (loss) from discontinued operations were ($0.9)
million or ($0.03) per share for the three months ended June 30, 2002 compared
to $0.3 million or $0.01 per share for the same period of the prior year. Prior
year results of operations have been restated to reflect the discontinued
operations.
Consolidated revenues for the three-month period ended June 30, 2002 were $394.3
million compared to $404.4 million for the same period in 2001. The decrease in
revenues was a result of the high energy commodity prices in 2001, slightly
offset by increased revenue in the communications business unit and power
generation segment and increased production of coal, oil and gas.
Consolidated operating expenses for the three-month period increased from $341.1
million in 2001 to $361.4 million in 2002. The increase was due to an increase
in fuel and depreciation expense as a result of our increased investment in
independent power generation offset by a substantial decrease in gas prices as
discussed above. Administrative and general expense decreased 19 percent
primarily due to a decrease in incentive compensation.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001.
Consolidated income from continuing operations for the six month period ended
June 30, 2002 were $29.6 million or $1.09 per share compared to $66.0 million or
$2.67 per share in the same period of the prior year.
The decrease in income from continuing operations was a result of substantial
decreases in prevailing prices for natural gas, crude oil and wholesale
electricity and in gross margins from natural gas marketing activities compared
to the same period in 2001. Unusual energy marketing
24
conditions existed in the first half of 2001 stemming primarily from gas
and electricity shortages in the West. Approximately half of the 2001 year
to date income from continuing operations was attributed to the unusual
market conditions that existed at that time. Wholesale electricity average
peak prices at Mid-Columbia were around $250 per megawatt-hour during the
first half of 2001 compared to approximately $22 per megawatt-hour during
the first half of 2002. Average spot gas prices in the West Coast region
were approximately $11 per MMBtu in the first half of 2001 compared to $3
in the first half of 2002. While the above factors contributed negatively
to income from continuing operations, we had an increase in the production
of coal, oil and natural gas, an increase in independent power generation
capacity and our communications business group showed a decrease in its net
loss attributable to a substantial expansion of its customer base.
In addition, during the second quarter of 2002 we decided to discontinue
operations in our coal marketing business due to challenges encountered to
market its Wyodak coal from the Powder River Basin of Wyoming to East Coast
markets. We sold the non-strategic assets effective August 1, 2002. Income
(loss) from discontinued operations were $(2.6) million or $(0.09) per share for
the six months ended June 30, 2002 compared to $1.0 million or $0.04 per share
for the same period of the prior year. Prior year results of operations have
been restated to reflect the discontinued operations.
Consolidated revenues for the six-month period ended June 30, 2002 were $686.4
million compared to $952.1 million for the same period in 2001. The decrease in
revenues was a result of the high energy commodity prices in 2001, slightly
offset by increased revenue in the communications business unit and power
generation segment and increased production in coal, oil and gas.
Consolidated operating expenses for the six-month period decreased from $828.3
million in 2001 to $621.7 million in 2002. The decrease was due to a substantial
decrease in gas prices as discussed above. Administrative and general expenses
decreased 32 percent primarily due to a decrease in incentive compensation.
Depreciation, depletion and amortization expense increased from $24.4 million in
2001 to $34.3 million in 2002 primarily as a result of our increased investment
in independent power generation.
Twelve Months Ended June 30, 2002 Compared to Twelve Months Ended June 30, 2001.
Consolidated income from continuing operations for the twelve month period ended
June 30, 2002 were $51.2 million or $1.90 per share compared to $101.2 million
or $4.22 per share for the same period of the prior year.
The decrease in income from continuing operations for the twelve month period
ended June 30, 2002 was a result of the substantial decrease in prevailing
prices for natural gas, crude oil and wholesale electricity and in the gross
margins from natural gas marketing activities compared to the same period of
2001. We estimate approximately $1.80 of the earnings per share for the twelve
month period ended June 30, 2001 could have been attributable to high prices of
natural gas and electricity related to the volatile western markets during that
period of time.
The decrease in income from continuing operations also reflects the
following special items for the twelve months ended June 30, 2002: a $4.4
million after-tax charge related to a long-term fuel swap with Enron Corporation
to provide natural gas to a power plant; a $2.0 million after-tax non-cash
charge related to the contribution of Black Hills Corporation Common Stock to
the newly formed Black Hills Corporation Foundation; a $1.1 million after-tax
non-cash employee
25
stock bonus taken in the form of Black Hills Corporation common stock;
a $1.7 million after-tax gain on the sale of mining equipment; a $3.6 million
after-tax benefit related to a coal contract settlement; and a $1.9 million
after-tax benefit related to the collection of amounts previously reserved for
California operations in the prior twelve month period.
In addition, during the second quarter of 2002 we decided to discontinue
operations in our coal marketing business due primarily to challenges
encountered in marketing our Wyodak coal from the Powder River Basin of Wyoming
to midwestern and eastern coal markets. We sold the non-strategic assets
effective August 1, 2002. Income from discontinued operations were ($3.1)
million or ($0.11) per share for the twelve months ended June 30, 2002 compared
to $1.4 million or $0.06 per share for the same period of the prior year. Prior
year results of operations have been restated to reflect the discontinued
operations.
Consolidated revenues for the twelve-month period ended June 30, 2002 were $1.2
billion compared to $2.0 billion for the same period in 2001. The decrease in
revenues was a result of the high energy commodity prices in late 2000 and the
first half of 2001.
Consolidated operating expenses for the twelve-month period decreased from $1.8
billion in 2001 to $1.1 billion in 2002. Fuel and purchased power costs
decreased 42 percent due to the substantial decrease in commodity prices as
discussed above. Administrative and general expense decreased 14 percent
primarily due to a decrease in incentive compensation. All other operating
expenses increased due to our growth primarily in the power generation segment
and communications business group.
The following business group and segment information does not include
intercompany eliminations:
Integrated Energy Group
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Revenue:
Fuel marketing $298,706 $306,835 $501,974 $748,712 $ 879,204 $1,605,536
Power generation 39,099 24,975 71,182 43,020 122,456 82,522
Oil and gas 6,866 9,275 12,955 17,857 28,505 29,951
Mining 6,881 7,881 15,083 16,144 30,738 32,761
-------- -------- -------- -------- ---------- ----------
Total revenue $351,552 $348,966 $601,194 $825,733 $1,060,903 $1,750,770
Expenses 329,301 312,141 558,857 753,390 993,165 1,630,138
-------- -------- -------- -------- ---------- ----------
Operating income $ 22,251 $ 36,825 $ 42,337 $ 72,343 $ 67,738 $ 120,632
Net income $ 10,119 $ 20,450 $ 20,308 $ 38,690 $ 37,370 $ 59,227
EBITDA $ 31,866 $ 43,551 $ 61,448 $ 83,787 $ 113,660 $ 133,163
EBITDA represents earnings before interest, income taxes, depreciation and
amortization. EBITDA is used by management and some investors as an
indicator of a company's historical ability to service debt. Management
believes that an increase in EBITDA is an indicator of improved ability to
service existing debt, to sustain potential future increases in debt and to
satisfy capital requirements. However, EBITDA is not intended to represent
cash flows for the period, nor has it been presented as an alternative to
either operating income, or as an indicator of
26
operating performance or cash flows from operating, investing and financing
activities, as determined by generally accepted accounting principles.
EBITDA as presented may not be comparable to other similarly titled
measures of other companies.
The following is a summary of sales volumes of our coal, oil and natural gas
production and various measures of power generation:
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Fuel production:
Tons of coal sold 843,500 775,000 1,844,700 1,592,800 3,770,100 3,264,400
Barrels of oil sold 115,357 110,350 229,633 209,017 466,076 380,617
Mcf of natural gas
sold 1,259,719 1,015,300 2,547,571 2,021,800 5,145,428 3,891,900
Mcf equivalent
sales 1,951,861 1,677,400 3,925,369 3,275,900 7,941,884 6,175,600
June 30
2002 2001
---- ----
Independent power capacity:
MWs of independent power capacity in service 646 327
MWs of independent power capacity under construction* 364 438
- -------------------
*includes a 90 MW plant under a lease arrangement
The following is a summary of average daily fuel marketing volumes:
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Natural gas - MMBtus
1,131,800 912,700 987,935 889,600 1,096,500 942,200
Crude oil - barrels 59,900 38,400 51,900 37,900 43,480 40,800
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001.
Net income for the integrated energy group for the three months ended June 30,
2002 was $10.1 million compared to $20.5 million in the same period of the prior
year. Net income decreased primarily due to a substantial decline in energy
prices. The power generation segment reported net income growth attributed to
additional generating capacity. A 16 percent increase in gas and oil production
sales partially offset a decrease in net income in the oil and gas segment
caused by lower prices. The fuel marketing segment's net income decreased
primarily due to a substantial decrease in margins received offset by unrealized
gains recognized through mark-to-market accounting as a result of changes in
commodity prices.
27
The integrated energy business group's revenues and expenses increased 1 percent
and 5 percent respectively for the three months ended June 30, 2002 compared to
the same period in 2001. The increase in revenue was a result of increased
generation capacity offset by the substantial decline in fuel and power prices.
Expenses increased due to higher fuel costs and depreciation expense resulting
from increased capacity.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001.
Net income for the integrated energy group for the six months ended June 30,
2002 were $20.3 million compared to $38.7 million in the same period of the
prior year. Net income decreased primarily due to a substantial decline in
energy prices. The power generation segment reported net income growth
attributed to additional generating capacity and the reporting of additional net
income relating to the collection in 2002 of receivables from California
operations that were reserved for in the prior period. A 20 percent increase in
gas and oil production sales partially offset an earnings decrease in the oil
and gas segment caused by lower prices. The fuel marketing segment's net income
decreased primarily due to a substantial decrease in margins received.
The integrated energy business group's revenues and expenses decreased 27
percent and 26 percent, respectively, for the six months ended June 30, 2002
compared to the same period in 2001. The decrease in revenue and expenses was a
direct result of the substantial decline in fuel and power prices.
Twelve Months Ended June 30, 2002 Compared to Twelve Months Ended June 30, 2001.
Net income for the integrated energy group for the twelve months ended June 30,
2002 were $37.4 million compared to $59.2 million for the same period of the
prior year, a 37 percent decrease. Increases in net income in the power
generation and mining segments were more than offset by a decrease in oil and
gas and fuel marketing net income. The power generation segment reported net
income growth attributed to additional generating capacity and the reporting of
additional net income relating to the collection in 2002 of receivables from
California operations that were reserved for in the prior twelve month period.
Net income from mining operations increased as a result of a 15 percent increase
in production, a coal contract settlement and a gain on the sale of mining
equipment offset by lower prices received. A 29 percent increase in gas and oil
production sales was offset by lower prices. The fuel marketing segments net
income decreased primarily due to a substantial decrease in margins received.
These decreases were partially offset by a 16 percent increase in the daily
volumes of natural gas marketed.
The integrated energy business group's revenues and expenses both decreased 39
percent, for the twelve months ended June 30, 2002 compared to the same period
in 2001. The decrease in revenue and expenses was a direct result of the
substantial decline in fuel and power prices.
28
Fuel Marketing
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $298,706 $306,835 $501,974 $748,712 $879,204 $1,605,536
Operating income $ 3,508 $ 18,144 $ 5,371 $ 42,352 $ 15,716 $ 63,219
Net income $ 2,397 $ 11,468 $ 3,903 $ 26,373 $ 12,095 $ 38,767
EBITDA $ 3,746 $ 18,580 $ 5,942 $ 43,207 $ 16,949 $ 63,945
Our fuel marketing companies generate large amounts of revenue and corresponding
expense related to buying and selling energy commodities. Fuel marketing is
extremely competitive, and margins are typically very small.
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001.
The decrease in revenues is attributed to a substantial decline in commodity
prices offset by a 24 percent increase in natural gas average daily volume
marketed and a 56 percent increase in crude oil average daily volume marketed.
Net income decreased 79 percent due to a substantial decline in commodity prices
and margins. Unusual energy marketing conditions existed in the second quarter
of 2001 stemming primarily from gas and electricity shortages in the West.
Average spot gas prices in the West Coast region were approximately $9 per MMBtu
in the second quarter of 2001 compared to $3 in the second quarter of 2002. As a
result of changing commodity prices, net income was impacted by unrealized gains
recognized through mark-to-market accounting treatment. Unrealized pre-tax
mark-to-market gains/(losses) for the three month periods ended June 30, 2002
and 2001 were $1.3 million and $(1.2) million, respectively, resulting in a
quarter over quarter net income increase of $1.5 million.
In addition, during the second quarter of 2002 we decided to discontinue
operations in our coal marketing business due primarily to challenges
encountered in marketing our Wyodak coal from the Powder River Basin of Wyoming
to midwestern and eastern coal markets. We sold the non-strategic assets
effective August 1, 2002. Net income from discontinued operations was ($0.9)
million or ($0.03) per share for the three months ended June 30, 2002 compared
to $0.3 million or $0.01 per share for the same period of the prior year. Prior
year results of operations have been restated to reflect the discontinued
operations and the coal marketing business is no longer reflected in the fuel
marketing segment.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001.
Revenues and net income decreased primarily due to a substantial decline in
commodity prices and margins received, offset by an 11 percent increase in
natural gas average daily volumes marketed and a 37 percent increase in crude
oil average daily volumes marketed. Unusual energy marketing conditions existed
in the first six months of 2001 stemming primarily from gas and electricity
shortages in the West. Average spot gas prices in the West Coast region were
approximately $11 per MMBtu in the first six months of 2001 compared to $3 in
the first six months of 2002.
Income (loss) from discontinued operations were ($2.6) million or ($0.09) per
share for the six months ended June 30, 2002 compared to $1.0 million or $0.04
per share for the same period of the prior year.
29
Twelve Months Ended June 30, 2002 Compared to Twelve Months Ended June 30, 2001.
Revenues and net income decreased 45 percent and 69 percent, respectively,
primarily due to a substantial decrease in margins received and a decline
in commodity prices, partially offset by a 16 percent increase in the daily
volumes of natural gas marketed. Unusual energy marketing conditions
existed for a substantial part of the twelve-month period ended June 30,
2001, stemming primarily from gas and electricity shortages in the West. As
a result of changing commodity prices, net income was impacted by
unrealized losses recognized through mark-to-market accounting treatment.
Unrealized pre-tax mark-to-market gains for the twelve month periods ended
June 30, 2002 and 2001 were $2.0 million and $2.6 million, respectively,
resulting in a year over year net income decrease of $0.4 million.
Net loss from discontinued operations was ($3.1) million or ($0.11) per share
for the twelve months ended June 30, 2002 compared to income from discontinued
operations of $1.4 million or $0.06 per share for the same period of the prior
year. Prior year numbers have been restated to reflect the discontinued
operations.
Power Generation
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $39,099 $24,975 $71,182 $43,020 $122,456 $82,522
Operating income $15,419 $12,024 $30,700 $17,565 $ 40,591 $37,835
Net income (loss) $ 4,174 $ 3,687 $ 9,847 $ 2,582 $ 8,841 $ 5,694
EBITDA $20,840 $15,176 $42,002 $22,344 $ 64,021 $39,997
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001.
Revenue, operating income and net income increased 57 percent, 28 percent and 13
percent, respectively, for the three-month period ended June 30, 2002 compared
to the same period in 2001 and is attributed to additional generating capacity.
As of June 30, 2002, we had 646 megawatts of independent power capacity in
service compared to 327 megawatts at June 30, 2001.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001.
Revenue, operating income and net income increased substantially for the
six-month period ended June 30, 2002 compared to the same period in 2001 and is
attributed to additional generating capacity. As of June 30, 2002, we had 646
megawatts of independent power capacity in service compared to 327 megawatts at
June 30, 2001.
The increase in net income for the six month period ended June 30, 2002 was also
benefited by a $1.9 million after-tax benefit relating to the collection of
receivables previously reserved for in the prior period for exposure to the
California market and a $0.9 million after-tax adjustment for negative goodwill
to reflect the impact of a change in accounting for goodwill in accordance with
the adoption of Statement of Financial Accounting Standards No. 142, "Goodwill
and Other Intangible Assets" (SFAS 142) effective January 1, 2002.
30
Twelve Months Ended June 30, 2002 Compared to Twelve Months Ended June 30, 2001.
Revenues increased 48 percent and net income increased 55 percent for the twelve
months ended June 30, 2002, compared to the same period of the prior year, due
to additional generating capacity and the recording of certain non-recurring
items. As of June 30, 2002, we had 646 megawatts of independent power capacity
in service with an additional 364 megawatts under construction (including a 90
MW plant under a lease arrangement).
Non-recurring items that affected net income include: a $1.9 million after-tax
benefit for the twelve month period ended June 30, 2002, relating to the
collection of receivables reserved for in the prior period for exposure to the
California market, a $0.9 million after-tax benefit for negative goodwill
recorded in the twelve month period ended June 30, 2002, to reflect the impact
of a change in accounting for goodwill in accordance with the adoption of SFAS
142, and a $4.4 million after-tax charge recorded in the twelve month period
ended June 30, 2002, related to our exposure to Enron.
Oil and Gas
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $6,866 $9,275 $12,955 $17,857 $28,505 $29,951
Operating income $1,765 $4,496 $ 2,783 $ 8,893 $ 8,759 $13,747
Net income $1,283 $2,963 $ 2,161 $ 5,919 $ 6,439 $ 8,783
EBITDA $3,847 $6,478 $ 6,882 $12,605 $16,986 $20,079
The following is a summary of our estimated economically recoverable oil and gas
reserves at June 30, 2002 measured using constant product prices at the end of
the respective period. Estimates of economically recoverable reserves are based
on a number of variables, which may differ from actual results.
2002 2001
---- ----
Barrels of oil (in millions) 4.6 4.5
Bcf of natural gas 23.2 25.6
Total in Bcf equivalents 50.5 52.6
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001.
Revenue and net income of the oil and gas production business segment decreased
26 percent and 57 percent, respectively for the three month period ended June
30, 2002, compared to the same period in 2001 due to a 42 percent decrease in
the average price received partially offset by a 16 percent increase in
production volumes.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001.
Revenue and net income of the oil and gas production business segment decreased
27 percent and 63 percent respectively, for the six month period ended June 30,
2002, compared to the same period in 2001 due to a 44 percent decrease in the
average price received partially offset by a 20 percent increase in production
volumes.
31
Twelve Months Ended June 30, 2002 Compared to Twelve Months Ended June 30, 2001.
Revenue and net income decreased 5 percent and 27 percent respectively for the
twelve month period ended June 30, 2002, compared to the same period in 2001 due
to a 28 percent decrease in the average price received partially offset by a 29
percent increase in production volumes.
Mining
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $6,881 $7,881 $15,083 $16,144 $30,738 $32,761
Operating income $2,054 $2,160 $ 4,434 $ 4,834 $ 6,186 $ 8,424
Net income $2,494 $2,307 $ 4,829 $ 4,623 $11,798 $ 7,714
EBITDA $3,926 $3,280 $ 7,571 $ 6,861 $18,985 $11,641
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001.
Revenue from our mining segment decreased 13 percent and net income increased 8
percent for the three-month period ended June 30, 2002, compared to the same
period in 2001. A 9 percent increase in tons of coal sold was offset by lower
prices received.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001.
Revenue from our mining segment decreased 7 percent and net income increased 4
percent for the six-month period ended June 30, 2002, compared to the same
period in 2001. A 16 percent increase in tons of coal sold was offset by lower
prices received.
Twelve Months Ended June 30, 2002 Compared to Twelve Months Ended June 30, 2001.
Revenue decreased 6 percent for the twelve month period ended June 30, 2002,
compared to the same period in the prior year due to a 15 percent increase in
tons of coal sold, partially offset by lower prices received.
Net income increased $4.1 million primarily as a result of a coal contract
settlement, a gain on the sale of mining equipment and the increase in tons of
coal sold. Tons of coal sold increased primarily due to the commencement of
sales through our train load-out facility.
In 2001, we reached a settlement of ongoing litigation with PacifiCorp
concerning rights and obligations under a coal supply agreement under which
PacifiCorp purchased coal from our coal mine to meet the coal requirements of
the Wyodak Power Plant. As a result of this settlement, we recognized $5.6
million pre-tax, non-operating income in the twelve month period ended June 30,
2002. In addition, we sold a conveyor system which resulted in a $2.6 million
pre-tax gain.
32
Electric Utility Group
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $38,303 $61,601 $75,494 $132,180 $156,524 $236,291
Operating expenses 24,950 32,291 47,814 74,206 102,711 136,733
------- ------- ------- -------- -------- --------
Operating income $13,353 $29,310 $27,680 $ 57,974 $ 53,813 $ 99,558
Net income $ 6,792 $16,784 $14,614 $ 34,124 $ 25,730 $ 56,943
EBITDA $17,845 $33,337 $36,471 $ 66,506 $ 66,155 $115,405
The following table provides certain operating statistics:
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Firm (system)
sales - MWh 462,000 464,000 968,000 990,000 1,990,000 2,005,000
Off-system sales -
MWh 210,000 293,000 371,000 550,000 787,000 1,006,000
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001.
Revenue, operating expenses and net income decreased 38 percent, 23 percent and
60 percent, respectively for the three month period ended June 30, 2002 compared
to the same period in the prior year primarily due to a 28 percent decrease in
off-system electric megawatt-hour sales and a 68 percent decrease in the average
price per megawatt-hour sold off-system. Firm residential and contracted
electricity sales increased, but were offset by a decline in industrial sales
due to the closing of the Homestake Gold Mine at year-end 2001. Revenue declines
were partially offset by lower fuel and purchased power costs.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001.
Revenue, operating expenses and net income decreased 43 percent, 36 percent and
57 percent, respectively for the six month period ended June 30, 2002 compared
to the same period in the prior year primarily due to a 33 percent decrease in
off-system electric megawatt-hour sales and a 75 percent decrease in the average
price per megawatt-hour sold off-system. Firm residential and contracted
electricity sales increased, but were offset by a decline in industrial sales
due to the closing of the Homestake Gold Mine at year-end 2001. Revenue declines
were partially offset by lower fuel and purchased power costs.
Twelve Months Ended June 30, 2002 Compared to Twelve Months Ended June 30, 2001.
Revenue, operating expenses and net income decreased 34 percent, 25 percent and
55 percent, respectively for the twelve month period ended June 30, 2002,
compared to the same period in the prior year primarily due to a 68 percent
decrease in the average price per megawatt-hour sold off-system and a 22 percent
decrease in off-system electric megawatt-hour sales.
33
The average price received for off-system sales for the twelve-month period
ended June 30, 2002, was approximately $35 per megawatt-hour compared to $108
per megawatt-hour for the same period in the prior year.
Communications Group
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Revenue-external* $ 7,752 $ 4,582 $14,933 $ 8,508 $ 26,683 $ 14,392
Revenue-intersegment* 465 1,117 830 2,217 2,862 3,987
Operating expenses 10,412 8,499 20,433 17,296 40,894 33,069
------- ------- ------- -------- -------- --------
Operating loss $(2,195) $(2,800) $(4,670) $ (6,571) $(11,349) $(14,690)
Net loss $(2,049) $(2,792) $(4,276) $ (6,682) $ (9,894) $(14,495)
EBITDA $ 957 $ (337) $ 1,471 $ (1,773) $ 102 $ (6,039)
- -------------
* External revenue is revenue from our broadband communications business.
Intersegment revenue is primarily revenue from our information services company
derived from providing services to our other business segments.
June 30 March 31 December 31
2002 2001 2002 2001 2001 2000
---- ---- ---- ---- ---- ----
Business customers 2,970 1,440 2,600 980 2,250 650
Residential customers 19,450 12,000 17,550 10,060 15,660 8,370
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001.
The communications business group reported EBITDA positive results in the second
quarter of 2002. The net loss for the three month period ended June 30, 2002 was
$(2.0) million, compared to $(2.8) million in 2001. The performance improvement
is due largely to a 67 percent increase in revenue as a result of a larger
customer base, partially offset by increased costs of sales and administrative
expenses.
The total number of customers exceeded 22,400 at the end of June 2002 - an 11
percent and 25 percent increase over the customer base at March 31, 2002 and
December 31, 2001, respectively, and a 67 percent increase compared to June 30,
2001.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001.
The communications business group reported EBITDA positive results in the first
six months of 2002. The net loss for the six month period ended June 30, 2002
was $(4.3) million, compared to $(6.7) million in 2001. The performance
improvement is due largely to a 74 percent increase in revenue as a result of a
larger customer base, partially offset by increased costs of sales and
administrative expenses.
The total number of customers exceeded 22,400 at the end of June 2002 - an 11
percent and 25 percent increase over the customer base at March 31, 2002 and
December 31, 2001, respectively, and a 67 percent increase compared to June 30,
2001.
34
Twelve Months Ended June 30, 2002 Compared to Twelve Months Ended June 30, 2001.
The net loss for the twelve month period ended June 30, 2002 was $(9.9) million,
compared to $(14.5) million for the same period in the prior year. The
performance improvement was the result of a 67 percent increase in our customer
base offset by increased cost of sales, administrative expenses, reserves for
inventory and carrier billings and increased interest expense.
We expect our communications group will sustain approximately $6.5 million in
net losses in calendar year 2002, with annual losses decreasing thereafter and
profitability expected by 2004. The recovery of capital investment and future
profitability are dependent primarily on our ability to attract new customers.
If we are unable to attract additional customers or technological advances make
our network obsolete, we could have a material write-down of assets.
Earnings Guidance
We reaffirm confidence in our ongoing business strategy, which seeks long-term
growth through the expansion of integrated, balanced and diverse competitive
energy operations supplemented by the strength and stability of our electric
utility and improving results from our communication business. The energy
industry has encountered challenging market conditions this year, including low
and volatile prices for natural gas and wholesale power. We previously indicated
a long-term earnings per share growth target in a range of 10 to 15 percent per
year based on historical performance. Until market conditions improve, we expect
annual earnings per share percentage growth to be in the 8 to 10 percent range.
We also expect recurring earnings for 2002 to be in the range of $2.25 to $2.30
per share. We recognize that sustained growth requires capital deployment to
continue expanding our integrated energy operations. We strongly believe that we
are strategically positioned to take advantage of opportunities to acquire and
develop energy assets consistent with our investment criteria.
Critical Accounting Policies
Goodwill and Other Intangible Assets
As required, on January 1, 2002 we adopted the provisions of Statement of
Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets"
(SFAS 142). Under SFAS 142, goodwill and intangible assets with indefinite lives
are no longer amortized but the carrying values are reviewed annually (or more
frequently if impairment indicators arise) for impairment. Intangible assets
with a defined life will continue to be amortized over their useful lives (but
with no maximum). Initial adoption of SFAS 142 did not have a material impact on
our financial position or results of operations. Adoption of SFAS 142 provisions
for non-amortization of goodwill and indefinite lived intangibles will impact
our future earnings results. Results for the three, six and twelve months ended
June 30, 2002 were approximately $0.5 million, $0.9 million and $1.6 million, or
2 cents per share, 3 cents per share and 6 cents per share, higher than the
comparable periods in 2001 due to non-amortization of goodwill.
Other than the above, there have been no material changes in our critical
accounting policies from those reported in our 2001 Annual Report on Form 10-K
filed with the Securities Exchange Commission. For more information on our
critical accounting policies, see Part II, Item 7 in our 2001 Annual Report on
Form 10-K.
35
Liquidity and Capital Resources
Cash Flow Activities
During the six month period ended June 30, 2002, we generated sufficient cash
flow from operations to meet our operating needs, to pay dividends on common and
preferred stock, to pay long-term debt maturities and to fund a portion of our
property additions. We continue to fund property and investment additions
primarily related to construction of additional electric generation facilities
for our integrated energy business group through a combination of operating cash
flow, increased short-term debt and long-term non-recourse project financing.
Cash flows from operations decreased $59.7 million for the six-month period
ended June 30, 2002 compared to the same period in the prior year primarily due
to the decrease in net income and cash provided by changes in working capital.
On March 8, 2002, we acquired an additional 67 percent interest in Millennium
Pipeline Company, L.P., which owns and operates a 200-mile pipeline and an
additional ownership interest in Millennium Terminal Company, L.P., which has
1.1 million barrels of crude oil storage connected to the Millennium Pipeline at
the Oil Tanking terminal in Beaumont, Texas. Total cost of the acquisition was
$11.0 million and was funded through borrowings under short-term revolving
credit facilities.
On March 15, 2002, we acquired an additional 30 percent interest in the Harbor
Cogeneration Facility, a 98-megawatt gas-fired plant located in Wilmington,
California for $25.7 million. This acquisition was also funded through
borrowings under short-term revolving credit facilities.
On March 15, 2002, we closed on $135 million of senior secured financing for the
Arapahoe and Valmont facilities, 210 megawatts in service and under construction
in the Denver, Colorado area. Proceeds from this financing were used to
refinance $53.8 million of an existing seven-year secured term project-level
facility, pay down approximately $50.0 million of short-term credit facility
borrowings with the remainder to be used for future project construction costs.
During the first quarter of 2002, we completed a $50 million bridge credit
agreement. The credit agreement supplements our revolving credit facilities and
has the same terms as those facilities with an original expiration date of June
30, 2002. During the second quarter of 2002, the term was extended to August 28,
2002.
On June 18, 2002, we closed on a $75 million bridge credit agreement. As of June
30, 2002, there were no borrowings outstanding under this bridge credit
agreement. This credit agreement bridged the issuance of $75 million of Black
Hills Power First Mortgage bonds, which we issued on August 13, 2002. The
termination date of the bridge credit agreement was August 13, 2002, the date on
which the First Mortgage Bonds were issued.
36
Dividends
Dividends paid on our common stock totaled $0.29 per share in each of the first
and second quarters of 2002. This reflects a 3.6 percent increase, as approved
by our board of directors in January 2002, from the prior periods. The
determination of the amount of future cash dividends, if any, to be declared and
paid will depend upon, among other things, our financial condition, funds from
operations, the level of our capital expenditures, restrictions under our credit
facilities and our future business prospects.
Short-Term Liquidity and Financing Transactions
Our principal sources of short-term liquidity are our revolving bank facilities
and cash provided by operations. As of June 30, 2002 we had approximately $54
million of cash and $525 million of bank facilities. Approximately $23 million
of the cash balance at June 30, 2002 was restricted by subsidiary debt
agreements in regards to the ability to dividend the cash to the parent company.
The bank facilities consisted of a $50 million bridge facility due August 28,
2002, a $75 million bridge facility, which expired when our Electric Utility
issued the First Mortgage Bonds described above, a $200 million facility due
August 27, 2002 and a $200 million facility due August 27, 2004. These bank
facilities can be used to fund our working capital needs, for general corporate
purposes and to provide liquidity for a commercial paper program if implemented.
At June 30, 2002, we had $406 million of bank borrowings outstanding under these
facilities. The corresponding amount outstanding at July 31, 2002 was $421
million. After inclusion of applicable letters of credit, the remaining
borrowing capacity under the bank facilities was $79.6 million and $54.6 million
at June 30, 2002 and July 31, 2002, respectively.
The above bank facilities include covenants that are common in such
arrangements. Such covenants include a consolidated net worth in an amount of
not less than the sum of $375 million and 50 percent of the aggregate
consolidated net income beginning June 30, 2001; a recourse leverage ratio not
to exceed 0.65 to 1.00; and an interest coverage ratio of not less than 3.00 to
1.00. If these covenants are violated, it would be considered an event of
default entitling the lender to terminate the remaining commitment and
accelerate all principal and interest outstanding to become immediately due. In
addition, certain of our interest rate swap agreements include cross-default
provisions. These provisions would allow the counterparty the right to terminate
the swap agreement and liquidate at a prevailing market rate, in the event of
default.
Some of the facilities previously had a covenant whereby we were required to
maintain a credit rating of at least "BBB-" from Standard & Poor's or "Baa3"
from Moody's Investor Service. The facilities that contained the rating triggers
were amended during the second quarter of 2002 to remove default provisions
pertaining to our credit rating status.
Our consolidated net worth was $529.1 million at June 30, 2002. The long-term
debt component of our capital structure at June 30, 2002 was 47 percent and our
total debt leverage (long-term debt and short-term debt) was 63 percent.
In addition, Enserco Energy, Inc., our gas marketing unit, had a $75
million uncommitted, discretionary line of credit to provide support for
the purchase of natural gas. We provided no guarantee to the lender under
this facility. At June 30, 2002, there were outstanding letters of credit
issued under the facility of $39.7 million with no borrowing balances on
the facility. Similarly, Black Hills Energy Resources, Inc., our oil
marketing unit, had a $25 million uncommitted, discretionary credit
facility. This line of credit provided credit support for the
37
purchases of crude oil by Black Hills Energy Resources. We provided no
guarantee to the lender under this facility. At June 30, 2002, Black Hills
Energy Resources had letters of credit outstanding of $22.6 million and no
balance outstanding on its overdraft line.
On June 28, 2002, Enserco Energy closed on a $135 million uncommitted,
discretionary credit facility, which became effective July 1, 2002 and expires
June 27, 2003. This facility replaced the $75 million Enserco Energy facility.
We provide no guarantee to the lender under this facility.
We are currently seeking long-term project-level non-recourse financing in the
range of $160 million for the expansion at our Las Vegas Project, a 277 megawatt
gas-fired generation complex located in North Las Vegas, Nevada, prior to August
27, 2002. Total project costs are estimated to be $330 million of which
approximately $289 million was expended as of June 30, 2002 and was funded with
short-term credit facility borrowings. In addition to the $75 million First
Mortgage Bonds that our Electric Utility issued on August 13, 2002, we
anticipate renewing our $200 million credit facility that expires on August 27,
2002. If we are successful in completing the Las Vegas project financing and
renewing our credit facility, our liquidity position will substantially improve.
Although we believe these financings will be completed by August 27, 2002, we
can make no guarantee these financings will occur within the planned time frame,
on reasonable terms or at all. If we are not successful in obtaining either the
Las Vegas Project financing or renewing the $200 million credit facility by
August 27, 2002, we may have a deficiency in our liquidity. In that event, we
expect that we would remedy such a deficiency by seeking other forms of
financing, including seeking extensions on our short-term credit facilities.
Our ability to obtain additional financing will depend upon a number of factors,
including our future performance and financial results and capital market
conditions. We cannot be sure that we will be able to raise additional capital
on reasonable terms or at all.
There have been no other material changes in our forecasted changes in liquidity
and capital requirements from those reported in Item 7 of our 2001 Annual Report
on Form 10-K filed with the Securities Exchange Commission.
RISK FACTORS
Risks Relating to Our Business
We have substantial indebtedness and will require significant additional amounts
of debt and equity capital to grow our businesses and service our indebtedness.
Our future access to these funds is not certain, and our inability to access
funds in the future could adversely affect our liquidity.
As of June 30, 2002, we had $918.6 million of short- and long-term debt. Our
substantial debt presents the risk that we might not generate sufficient cash to
maintain our credit facilities or service our indebtedness. In addition, our
leveraged capital structure could limit our ability to finance the acquisition
and development of additional projects, to compete effectively, to operate
successfully under adverse economic conditions and to fully implement our
strategy. The terms of our debt may also restrict our flexibility in operating
our projects.
38
In order to access capital on a substantially non-recourse basis in the future,
we may have to make larger equity investments in, or provide more financial
support for, our project subsidiaries. We also may not be successful in
structuring future financing for our projects on a substantially non-recourse
basis.
The State of California's efforts to void or reform its long-term power purchase
contracts with various suppliers may adversely affect our contracts with these
suppliers and our independent power subsidiary's results of operations.
Our independent power subsidiary, Black Hills Energy Capital, Inc., indirectly
owns our Las Vegas Cogeneration II plant, which is currently under construction
and which we refer to as LV Cogen II. LV Cogen II is party to a 15-year tolling
agreement with Allegheny Energy Supply Company, LLC, or AESC, under which AESC
will deliver fuel to the facility and LV Cogen II will sell all of the
facility's capacity, and all associated energy and ancillary services produced
at the facility, to AESC.
The California Public Utilities Commission filed a complaint with the Federal
Energy Regulatory Commission, or FERC, in February 2002, seeking to void or, in
the alternative, reform a number of long-term power purchase contracts entered
into between the State of California/Department of Water Resources and several
suppliers in 2001. One of the suppliers named in the complaint was AESC. If
AESC's contract with the State of California/Department of Water Resources is
voided or reformed, AESC may seek to alter or cancel its contract with LV Cogen
II. Any such action by AESC, if successful, could adversely affect our
independent power subsidiary's results of operations.
Counterparty Credit Risk
We perform ongoing credit evaluations of our customers and adjust credit limits
based upon payment history and the customer's current creditworthiness, as
determined by our review of their current credit information. We continuously
monitor collections and payments from our customers and maintain a provision for
estimated credit losses based upon historical experience and any specific
customer collection issue that we have identified. While most credit losses have
historically been within our expectations and provisions established, we cannot
guarantee that we will continue to experience the same credit loss rates that we
have in the past or that an investment grade counterparty will not default, as
was the case with Enron in 2001.
Our agreements with counterparties that have recently experienced downgrades in
their credit ratings expose us to the risk of counterparty default, which could
adversely affect our cash flow and profitability.
Our independent power subsidiary, Black Hills Energy Capital, indirectly owns a
50% interest in the Las Vegas Cogeneration I plant, which is a 53-megawatt
gas-fired power plant located in North Las Vegas, Nevada. Under accounting
principles generally accepted in the United States, we consolidate 100% of the
entity. Most of the power from that facility is sold under a long-term contract
with Nevada Power Company, which expires in 2024. The credit ratings of Nevada
Power Company and its parent holding company, Sierra Pacific Resources, have
both been recently downgraded to non-investment grade status. Our independent
power subsidiary could experience lost revenues and increased expenses if Nevada
Power Company is unable to perform on its obligations under the power contract,
either as a result of a deterioration of its creditworthiness or for any other
reason.
39
Our rate freeze agreement with the South Dakota Public Utilities Commission,
which prevents us, absent extraordinary circumstances, from passing on to our
South Dakota retail customers cost increases we may incur during the rate freeze
period, could decrease our operating margins.
Our rate freeze agreement with the South Dakota Public Utilities Commission
provides that, until January 1, 2005, we may not apply to the Commission for any
increase in rates, except upon the occurrence of various extraordinary events.
Our utility's historically stable returns could be threatened by plant outages,
machinery failure, increases in purchased power costs over which we have no
control, acts of nature or other unexpected events that could cause our
operating costs to increase and our operating margins to decline. Moreover, in
the event of unexpected plant outages or machinery failures, we may be required
to purchase replacement power in wholesale power markets at prices, which exceed
the rates we are permitted to charge our retail customers.
Because wholesale power, fuel prices and other costs are subject to volatility,
our revenues and expenses may fluctuate.
A substantial portion of our growth in net income in recent years is
attributable to increasing wholesale sales into a robust market. The prices of
energy products in the wholesale power markets have declined significantly since
the first half of 2001. Power prices are influenced by many factors outside our
control, including fuel prices, transmission constraints, supply and demand,
weather, economic conditions, and the rules, regulations and actions of the
system operators in those markets. Moreover, unlike most other commodities,
electricity cannot be stored and therefore must be produced concurrently with
its use. As a result, wholesale power markets are subject to significant price
fluctuations over relatively short periods of time and can be unpredictable.
Increasing competition in our businesses may adversely affect our ability to
make investments or acquisitions on attractive terms.
We face increasing competition in each of our businesses. In particular, the
independent power industry is characterized by numerous strong and capable
competitors, some of which have more extensive experience in the operation,
acquisition and development of power generation facilities, larger staffs or
greater financial resources than we do. Many of our competitors are also seeking
favorable power generation opportunities. This competition may adversely affect
our ability to make investments or acquisitions on attractive terms.
Our broadband communications business is subject to significant competition for
its services and to rapid technological change.
Although our communications unit has achieved rapid penetration of our existing
market, we face strong competition for our services from the incumbent local
exchange carrier as well as from long distance providers, Internet service
providers, the incumbent cable television provider and others.
The communications industry is subject to rapid and significant changes in
technology. There can be no assurance that future technological developments
will not have a material adverse effect on our competitive position.
40
Our ability to recover our capital investment and achieve operating profits
is dependent on our ability to attract additional customers and is subject to
the risk that technological advances may render our network obsolete. No
assurance can be given that we will be successful in meeting our goals. If we
determine that we will be unable to recover our investment, we would be required
to take a non-cash charge to earnings in an amount that could be material in
order to write down a portion of our investment in our broadband communications
business.
Construction, expansion, refurbishment and operation of power generation
facilities involve significant risks that we cannot always cover by insurance or
contractual protections which could lead to lost revenues or increased expenses.
The construction, expansion and refurbishment of power generation and
transmission and resource recovery facilities involve many risks, including: the
inability to obtain required governmental permits and approvals; the
unavailability of equipment; supply interruptions; work stoppages; labor
disputes; social unrest; weather interferences; unforeseen engineering,
environmental and geological problems and unanticipated cost overruns.
The ongoing operation of our facilities involves all of the risks described
above, in addition to risks relating to the breakdown or failure of equipment or
processes and performance below expected levels of output or efficiency. New
plants may employ recently developed and technologically complex equipment,
especially in the case of newer environmental emission control technology. Any
of these risks could cause us to operate below expected capacity levels, which
in turn could result in lost revenues, increased expenses, higher maintenance
costs and penalties. While we maintain insurance, obtain warranties from vendors
and obligate contractors to meet certain performance levels, the proceeds of
such insurance, warranties or performance guarantees may not be adequate to
cover lost revenues, increased expenses or liquidated damages payments.
Estimates of our proved reserves may materially change due to numerous
uncertainties inherent in estimating oil and natural gas reserves.
There are many uncertainties inherent in estimating quantities of proved
reserves and their values. The process of estimating oil and natural gas
reserves requires interpretations of available technical data and various
assumptions, including assumptions relating to economic factors. Any significant
inaccuracies in these interpretations or assumptions could materially affect the
estimated quantities and present value of our reserves. The accuracy of any
reserve estimate is a function of the quality of available data, engineering and
geological interpretations and judgement, and the assumptions used regarding
quantities of recoverable oil and gas reserves and prices for oil and natural
gas. Actual prices, production, development expenditures, operating expenses,
and quantities of recoverable oil and natural gas reserves will vary from those
assumed in our estimates, and these variances may be significant. Any
significant variance from the assumptions used could result in the actual
quantity of our reserves and future net cash flow being materially different
from the estimates in our reported reserves. In addition, results of drilling,
testing and production and changes in oil and natural gas prices after the date
of the estimate may result in substantial upward or downward revisions.
41
Potential Claim Related to Forest Fire in South Dakota
In June 2002, a forest fire damaged approximately 10,800 acres of private and
governmental land located near Deadwood and Lead, South Dakota. The fire
destroyed approximately 20 structures (seven houses and 13 outbuildings) and
caused the evacuation of the cities of Lead and Deadwood for approximately 48
hours.
The cause of the fire was investigated by the State of South Dakota. Sagging
power lines owned by us were implicated as the cause. We have initiated our own
investigation into the cause of the fire, including the hiring of expert fire
investigators and that investigation is continuing.
Although we have been put on notice of potential claims, no civil action or
regulatory proceeding has been initiated against us at this time. If, however,
it is determined that sagging power lines owned by us were the cause of the fire
and that we were negligent in the maintenance of those power lines, we could be
liable for resultant damages. Although we cannot predict the outcome of either
our investigation or of potential claims, management believes that any such
claims will not have a material adverse effect on our financial condition or
results of operations.
Risks Relating to Our Industry
Our business is subject to substantial governmental regulation and permitting
requirements as well as on-site environmental liabilities we assumed when we
acquired some of our facilities. We may be adversely affected by any future
inability to comply with existing or future regulations or requirements or the
potentially high cost of maintaining the compliance of our facilities.
In General. Our business is subject to extensive energy, environmental and other
laws and regulations of federal, state and local authorities. We generally are
required to obtain and comply with a wide variety of licenses, permits and other
approvals in order to operate our facilities. In the course of complying with
these requirements, we may incur significant additional costs. If we fail to
comply with these requirements, we could be subject to civil or criminal
liability and the imposition of liens or fines. In addition, existing
regulations may be revised or reinterpreted, new laws and regulations may be
adopted or become applicable to us or our facilities, and future changes in laws
and regulation may have a detrimental effect on our business.
Environmental Regulation. In acquiring some of our facilities, we assumed
on-site liabilities associated with the environmental condition of those
facilities, regardless of when such liabilities arose and whether known or
unknown, and in some cases agreed to indemnify the former owners of those
facilities for on-site environmental liabilities. We strive at all times to be
in compliance with all applicable environmental laws and regulations. However,
steps to bring our facilities into compliance, if necessary, could be expensive,
and thus could adversely affect our financial condition. Furthermore, with the
continuing trends toward stricter standards, greater regulation, more extensive
permitting requirements and an increase in the assets we operate, we expect our
environmental expenditures to be substantial in the future.
42
Ongoing changes in the United States utility industry, such as state and federal
regulatory changes, a potential increase in the number of our competitors or the
imposition of price limitations to address market volatility, could adversely
affect our profitability.
The United States electric utility industry is currently experiencing increasing
competitive pressures as a result of consumer demands, technological advances,
deregulation, greater availability of natural gas-fired generation and other
factors. The FERC has implemented and continues to propose regulatory changes to
increase access to the nationwide transmission grid by utility and non-utility
purchasers and sellers of electricity. In addition, a number of states have
implemented or are considering or currently implementing methods to introduce
and promote retail competition. Industry deregulation in some states has led to
the disaggregation of some vertically integrated utilities into separate
generation, transmission and distribution businesses, and deregulation
initiatives in a number of states may encourage further disaggregation. As a
result, significant additional competitors could become active in the
generation, transmission and distribution segments of our industry.
Proposals have been introduced in Congress to repeal the Public Utility Holding
Company Act of 1935, or PUHCA, and the FERC has publicly indicated support for
the PUHCA repeal effort. To the extent competitive pressures increase and the
pricing and sale of electricity assume more characteristics of a commodity
business, the economics of domestic independent power generation projects may
come under increasing pressure.
In addition, the independent system operators who oversee most of the wholesale
power markets have in the past imposed, and may in the future continue to
impose, price limitations and other mechanisms to address some of the volatility
in these markets. These types of price limitations and other mechanisms may
adversely affect the profitability of our generation facilities that sell energy
into the wholesale power markets. Given the extreme volatility and lack of
meaningful long-term price history in some of these markets and the imposition
of price limitations by independent system operators, we may not be able to
operate profitably in all wholesale power markets.
NEW ACCOUNTING PRONOUNCEMENTS
During June 2002, the Emerging Issues Task Force (EITF) reached a consensus on
Issues 1 and 3 of EITF Issue No. 02-03, "Recognition and Reporting of Gains and
Losses on Energy Trading Contracts under EITF Issue No. 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," and No.
00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue
No. 98-10."
Under EITF 02-3, Issue 1 of the consensus requires mark-to-market gains and
losses on energy trading contracts to be shown net on the income statement
whether or not physically settled in financial statements issued for periods
ending after July 15, 2002. Issue 3 requires entities involved in energy trading
activities to include certain additional disclosures in financial statements
issued for fiscal years ending after July 15, 2002. EITF 02-3 also requires that
all comparative financial statements be reclassified to conform to EITF 02-3.
Although EITF 02-3 will require our mark-to-market gains and losses on energy
trading contracts to be shown net on the income statement, it is not expected to
impact our net income, stockholders' equity or cash flows. We will adopt the
guidance of Issue 1 during the third quarter, but have not yet quantified the
financial statement effect from this adoption.
43
Other than the above, and the new pronouncements reported in our 2001 Annual
Report on Form 10-K filed with the Securities Exchange Commission, there have
been no new accounting pronouncements issued that when implemented would require
us to either retroactively restate prior period financial statements or record a
cumulative catch-up adjustment.
Forward Looking Statements
Some of the statements in this Form 10-Q include "forward-looking statements" as
defined by the Securities and Exchange Commission, or SEC. We make these
forward-looking statements in reliance on the safe harbor protections provided
under the Private Securities Litigation Reform Act of 1995. All statements,
other than statements of historical facts, included in this Form 10-Q that
address activities, events or developments that we expect, believe or anticipate
will or may occur in the future are forward-looking statements. These
forward-looking statements are based on assumptions, which we believe are
reasonable based on current expectations and projections about future events and
industry conditions and trends affecting our business. However, whether actual
results and developments will conform to our expectations and predictions is
subject to a number of risks and uncertainties that could cause actual results
to differ materially from those contained in the forward-looking statements,
including, among other things: (1) unanticipated developments in the western
power markets, including unanticipated governmental intervention, deterioration
in the financial condition of counterparties, default on amounts due from
counterparties, adverse changes in current or future litigation, adverse changes
in the tariffs of the California Independent System Operator, market disruption
and adverse changes in energy and commodity supply, volume and pricing and
interest rates; (2) prevailing governmental policies and regulatory actions with
respect to allowed rates of return, industry and rate structure, acquisition and
disposal of assets and facilities, operation and construction of plant
facilities, recovery of purchased power and other capital investments, and
present or prospective wholesale and retail competition; (3) the State of
California's efforts to reform its long-term power purchase contracts; (4)
changes in and compliance with environmental and safety laws and policies; (5)
weather conditions; (6) population growth and demographic patterns; (7)
competition for retail and wholesale customers; (8) pricing and transportation
of commodities; (9) market demand, including structural market changes; (10)
changes in tax rates or policies or in rates of inflation; (11) changes in
project costs; (12) unanticipated changes in operating expenses or capital
expenditures; (13) capital market conditions; (14) technological advances by
competitors; (15) competition for new energy development opportunities; (16)
legal and administrative proceedings that influence our business and
profitability; (17) the effects on our business, including the availability of
insurance, resulting from the terrorist actions on September 11, 2001, or any
other terrorist actions or responses to such actions; (18) the effects on our
business resulting from the financial difficulties of Enron and other energy
companies, including their effects on liquidity in the trading and power
industry, and their effects on the capital markets views of the energy or
trading industry, and our ability to access the capital markets on the same
favorable terms as in the past; (19) the effects on our business in connection
with a lowering of our credit rating (or actions we may take in response to
changing credit ratings criteria), including, increased collateral requirements
to execute our business plan, demands for increased collateral by our current
counterparties, refusal by our current or potential counterparties or customers
to enter into transactions with us and our inability to obtain credit or capital
in amounts or on terms favorable to us; (20) risk factors discussed in this Form
10-Q; and (21) other factors discussed from time to time in our filings with the
SEC. New factors that could cause actual results to differ materially from those
described in forward-looking statements emerge from time to time, and it is not
possible for us to predict all such factors, or the extent to which any such
factor or combination of factors may cause actual results to differ from those
44
contained in any forward-looking statement. We assume no obligation to update
publicly any such forward-looking statements, whether as a result of new
information, future events, or otherwise.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no material changes in market risk faced by the Company from
those reported in the Company's 2001 Annual Report on Form 10-K filed with the
Securities Exchange Commission. For more information on market risk, see Part
II, Item 7 in the Company's 2001 Annual Report on Form 10-K, and Notes to
Condensed Consolidated Financial Statements in this Form 10-Q.
45
BLACK HILLS CORPORATION
Part II - Other Information
Item 1. Legal Proceedings
-----------------
For information regarding legal proceedings, see Note 10 to
the Company's 2001 Annual Report on Form 10-K and Note 12 in
Item 1 of Part I of this Quarterly Report on Form 10-Q, which
information from Note 12 is incorporated by reference into
this item.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
(a) The Annual Meeting of Shareholders was held on May 29,
2002.
(b) The following Directors were elected to serve until the
Annual Meeting of Shareholders in 2005.
David S. Maney
Bruce B. Brundage
Kay S. Jorgensen
Other Directors whose term of office continues are:
David C. Ebertz
John R. Howard
Daniel P. Landguth
Adil M. Ameer
Everett E. Hoyt
Thomas J. Zeller
(c) Matters Voted Upon at the Meeting
1. Elected three Class II Directors to serve until the
Annual Meeting of Shareholders in 2005.
David S. Maney
Votes For 23,386,876
Votes Withheld 351,576
Bruce B. Brundage
Votes For 23,375,621
Votes Withheld 362,831
Kay S. Jorgensen
Votes For 23,355,775
Votes Withheld 382,677
46
2. Item 2, the ratification of the appointment of Arthur
Andersen LLP to serve as Black Hills Corporation's
independent public accountants in 2002 was withdrawn
and not voted on at the Annual Meeting.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits -
Exhibit 99.1 Certification pursuant to 18
U.S.C. Section 1350, as adopted
pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
Exhibit 99.2 Certification pursuant to 18
U.S.C. Section 1350, as adopted
pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K
We have filed the following Reports on Form 8-K during
the quarter ended June 30, 2002.
Form 8-K dated May 31, 2002.
Reported under item 4 the change in our independent
public accountants from Arthur Andersen LLP to
Deloitte & Touche LLP.
47
BLACK HILLS CORPORATION
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.
BLACK HILLS CORPORATION
/s/ Roxann R. Basham
----------------------------------------------
Roxann R. Basham, Vice President - Controller
(Principal Accounting Officer)
/s/ Mark T. Thies
----------------------------------------------
Mark T. Thies, Senior VP & CFO
(Principal Financial Officer)
Dated: August 14, 2002
48
EXHIBIT INDEX
Exhibit (99.1) Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit (99.2) Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.