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 September 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 October 31, 2002
Common stock, $1.00 par value 26,903,626 shares
1
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 and Nine Months
Ended September 30, 2002 and 2001
Condensed Consolidated Balance Sheets- 4
September 30, 2002, December 31, 2001
and September 30, 2001
Condensed Consolidated Statements of Cash Flows- 5
Nine Months Ended
September 30, 2002 and 2001
Notes to Condensed Consolidated Financial Statements 6-23
Item 2. Management's Discussion and Analysis of 24-44
Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about 44
Market Risk
Item 4. Controls and Procedures 44
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 45
Item 6. Exhibits and Reports on Form 8-K 45
Signatures 47
2
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands, except per share amounts)
Operating revenues $ 112,572 $ 94,813 $ 312,215 $ 365,800
---------- ---------- ----------- -----------
Operating expenses:
Fuel and purchased power 22,426 18,680 52,695 64,994
Operations and maintenance 16,670 15,252 47,296 43,051
Administrative and general 15,264 12,165 46,118 58,262
Depreciation, depletion and amortization 17,691 14,201 52,027 38,605
Taxes, other than income taxes 5,983 5,656 17,889 16,637
---------- ---------- ----------- -----------
78,034 65,954 216,025 221,549
---------- ---------- ----------- -----------
Equity in earnings of unconsolidated affiliates 907 1,958 4,187 11,066
---------- ---------- ----------- -----------
Operating income 35,445 30,817 100,377 155,317
---------- ---------- ----------- -----------
Other income (expense):
Interest expense (10,020) (9,213) (30,171) (29,181)
Interest income 428 725 1,748 1,804
Other expense (864) (713) (206) (1,024)
Other income 385 5,807 2,654 10,133
---------- ---------- ------------ ----------
(10,071) (3,394) (25,975) (18,268)
---------- ---------- ----------- ----------
Income from continuing operations before minority
interest, income taxes and change in accounting principle 25,374 27,423 74,402 137,049
Minority interest 1,488 163 (2,614) (4,408)
Income taxes (9,413) (10,582) (24,725) (49,672)
---------- ---------- ----------- ----------
Income from continuing operations before change in
accounting principle 17,449 17,004 47,063 82,969
Income (Loss) from discontinued operations, net of taxes - (638) (2,637) 342
Change in accounting principle, net of taxes - - 896 -
---------- ---------- ----------- ----------
Net income 17,449 16,366 45,322 83,311
Preferred stock dividends (56) (131) (168) (473)
---------- ---------- ----------- ----------
Net income available for common stock $ 17,393 $ 16,235 $ 45,154 $ 82,838
========== ========== =========== ==========
Weighted average common shares outstanding:
Basic 26,835 26,425 26,778 24,988
========== ========== =========== ==========
Diluted 27,078 26,802 27,052 25,404
========== ========== =========== ==========
Earnings per share:
Basic-
Continuing operations $ 0.65 $ 0.64 $ 1.75 $ 3.30
Discontinued operations - (0.03) (0.09) .02
Change in accounting principle - - 0.03 -
--------- --------- ---------- -----------
Total $ 0.65 $ 0.61 $ 1.69 $ 3.32
========= ========= ========== ===========
Diluted-
Continuing operations $ 0.64 $ 0.63 $ 1.74 $ 3.27
Discontinued operations - (0.02) (0.09) 0.01
Change in accounting principle - - 0.03 -
--------- --------- ---------- -----------
Total $ 0.64 $ 0.61 $ 1.68 $ 3.28
========= ========= ========== ===========
Dividends paid per share of common stock $ 0.29 $ 0.28 $ 0.87 $ 0.84
========= ========= ========== ===========
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)
September 30 December 31 September 30
2002 2001 2001
---- ---- ----
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 74,778 $ 29,956 $ 52,057
Securities available-for-sale - 3,550 3,770
Receivables (net of allowance for doubtful accounts of $3,361,
$5,913 and $5,226, respectively) - 157,754 110,831 116,898
Derivative assets 44,244 38,144 62,383
Other assets 40,571 29,992 36,455
Assets of discontinued operations - 10,090 12,971
----------- ----------- -----------
317,347 222,563 284,534
----------- ----------- -----------
Investments 19,920 59,895 61,284
----------- ----------- -----------
Property, plant and equipment 1,829,247 1,564,664 1,499,231
Less accumulated depreciation and depletion (398,137) (328,325) (312,109)
----------- ----------- ------------
1,431,110 1,236,339 1,187,122
----------- ----------- ------------
Other assets:
Derivatives assets 2,244 6,407 1,752
Goodwill 30,182 28,693 30,169
Intangible assets 79,369 86,528 65,083
Other 23,750 18,342 16,824
----------- ----------- -------------
135,545 139,970 113,828
----------- ----------- ------------
$ 1,903,922 $ 1,658,767 $1,646,768
=========== =========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 142,464 $ 96,218 $ 103,627
Accrued liabilities 41,912 39,085 54,835
Current maturities of long-term debt 17,306 35,904 20,513
Notes payable 383,521 360,450 319,000
Derivative liabilities 47,831 42,681 64,121
Liabilities of discontinued operations - 8,820 11,777
----------- ----------- ------------
633,034 583,158 573,873
----------- ----------- ------------
Long-term debt, net of current maturities 561,399 415,798 434,993
----------- ----------- ------------
Deferred credits and other liabilities:
Federal income taxes 104,855 75,302 64,629
Derivative liabilities 10,897 7,119 1,636
Other 42,294 42,693 39,690
----------- ----------- ------------
158,046 125,114 105,955
----------- ----------- ------------
Minority interest in subsidiaries 16,616 19,533 25,940
----------- ----------- ------------
Stockholders' equity:
Preferred stock - no par Series 2000-A; 21,500 shares
authorized; Issued and Outstanding: 5,177 shares 5,549 5,549 5,549
----------- ----------- ------------
Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized;
Issued: 27,056,390; 26,890,943 and 26,830,267 shares,
respectively 27,056 26,891 26,830
Additional paid-in capital 243,599 240,454 238,506
Retained earnings 272,339 250,515 253,240
Treasury stock, at cost (1,756) (4,503) (8,841)
Accumulated other comprehensive loss (11,960) (3,742) (9,277)
----------- ----------- ------------
529,278 509,615 500,458
----------- ----------- ------------
Total stockholders' equity 534,827 515,164 506,007
----------- ----------- ------------
$1,903,922 $ 1,658,767 $ 1,646,768
=========== =========== ============
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)
Nine Months Ended
September 30
2002 2001
---- ----
(in thousands)
Operating activities:
Net income available for common $ 45,154 $ 82,838
Adjustments to reconcile net income available for common to net cash
provided by operating activities:
(Income) loss from discontinued operations 2,637 (342)
Depreciation, depletion and amortization 52,027 38,605
Net change in derivative assets and liabilities (5,286) (10,978)
Deferred income taxes 34,237 1,950
Undistributed earnings in associated companies (4,328) (8,580)
Minority interest 2,614 4,408
Accounting change (896) -
Change in operating assets and liabilities-
Accounts receivable and other current assets (53,085) 166,045
Accounts payable and other current liabilities 48,012 (132,854)
Other, net (6,361) 873
--------- ----------
114,725 141,965
--------- ----------
Investing activities:
Property, plant and equipment additions (174,946) (441,778)
Payment for acquisition of net assets, net of cash acquired (23,229) (10,410)
Payment for intangible assets, including goodwill - (50,413)
Payment for acquisition of minority interest (3,617) -
--------- ----------
(201,792) (502,601)
--------- ----------
Financing activities:
Dividends paid on common stock (23,326) (20,752)
Treasury stock sold, net 2,747 226
Common stock issued 3,310 167,980
Increase in short-term borrowings, net 23,071 108,000
Long-term debt - issuance 156,133 145,649
Long-term debt - repayments (29,130) (11,195)
Subsidiary distributions to minority interests (916) (1,505)
--------- ----------
131,889 388,403
--------- ----------
Increase in cash and cash equivalents 44,822 27,767
Cash and cash equivalents:
Beginning of period 29,956 24,290
--------- ----------
End of period $ 74,778 $ 52,057
========= ==========
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $ 31,240 $ 28,776
Income taxes $ 754 $ 34,800
Non-cash net assets acquired through issuance of common and preferred $ - $ 3,628
stock
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 September 30,
2002, December 31, 2001 and September 30, 2001, financial information
and are of a normal recurring nature. The results of operations for the
three and nine months ended September 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
Realized and unrealized gains and losses under energy trading contracts
in the energy marketing segment have been reclassified to be presented
on a net basis in Operating revenues on the accompanying Condensed
Consolidated Statements of Income in accordance with Emerging Issues
Task Force (EITF) Issue No. 98-10, "Accounting for Contracts Involved
in Energy Trading and Risk Management Activities. If the company had
reported these items on a gross basis, both operating revenues and fuel
and purchased power costs would have been $264.4 million and $195.0
million higher for the three months ended September 30, 2002 and 2001,
respectively, and $752.7 million and $879.3 million more for the nine
months ended September 30, 2002 and 2001, respectively. The net
presentation of these items rather than a gross presentation has no
impact on operating income or net income.
In addition, certain other 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.
6
(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 will adopt SFAS 143
effective January 1, 2003 and is currently evaluating the effects
adoption will have on the Company's consolidated financial statements.
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."
At a meeting on October 25, 2002, the EITF reached new consensuses that
effectively supersede the consensus on EITF 02-3, reached at its June
2002 meeting. At its October 2002 meeting, the EITF reached a consensus
to rescind EITF 98-10, the impact of which is to preclude
mark-to-market accounting for all energy trading contracts not within
the scope of FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The EITF also reached a consensus
that gains and losses on derivative instruments within the scope of
Statement 133 should be shown net in the income statement if the
derivative instruments are held for trading purposes. The consensus
regarding the rescission of Issue 98-10 is applicable for fiscal
periods beginning after December 15, 2002. Energy trading contracts not
within the scope of Statement 133 entered into after October 25, 2002,
but prior to the implementation of the consensus are not permitted to
apply mark-to-market accounting. The Company has not yet quantified the
financial statement effect of this EITF action. The Company currently
reports its energy trading activities on a net basis.
(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 and nine
month periods ended September 30, 2002 and 2001 are as follows (in
thousands):
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
Net income as reported $17,393 $16,235 $45,154 $82,838
Cumulative effect of change in
accounting principle, net of tax - - (896) -
Cumulative effect of change in
accounting principle included in
"Discontinued operations," net
of tax - - 755 -
------- ------- ------- -------
Income excluding cumulative
effect of change in accounting
principle 17,393 16,235 45,013 82,838
Add: goodwill amortization - 384 - 1,179
------- ------- ------- -------
Adjusted net income $17,393 $16,619 $45,013 $84,017
======= ======= ======= =======
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 nine-month period ended September 30, 2002 by $0.1
million, or $0.01 per share. The three and nine-month periods ended
September 30, 2001 would have been higher by $0.4 million, or $0.01 per
share and $1.2 million, or $0.05 per share.
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 nine-month period ended
September 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 - 10,080
Adjustments (3) (14,108)
Amortization expense - (3,131)
------- -------
Balance at September 30, 2002, net of
accumulated amortization $30,182 $79,369
======= =======
8
On September 30, 2002, intangible assets totaled $79.4 million, net of
accumulated amortization of $7.6 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 for the next five years is expected to be
approximately $4.2 million a year.
Intangible asset additions during the nine month period ended September
30, 2002 were primarily the result of a $9.3 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.
Adjustments of intangible assets during the nine-month period ended
September 30, 2002 primarily relate to final adjustments to the
preliminary purchase price allocation of the Company's third quarter
2001 Las Vegas Cogeneration acquisition.
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 and 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, in the second quarter of 2002 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
9
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 "Energy marketing."
Gross margins on energy trading contracts and net income from the
discontinued operation are as follows (in thousands):
Three Months Nine Months
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
Gross margins on energy
trading contracts $ 190 $ 54 $ (235) $2,873
------ ------ ------- ------
Pre-tax income (loss) from
discontinued operation 65 (1,061) (2,679) 648
Pre-tax loss on disposal (65) - (1,588) -
Income tax benefit (expense) - 423 1,630 (306)
------ ------ ------- ------
Net (loss) income from
discontinued operations $ - $ (638) $(2,637) $ 342
====== ====== ======= ======
Assets and liabilities of the discontinued operation are as follows (in
thousands):
December 31 September 30
2001 2001
---- ----
Current assets $7,878 $11,429
Non-current assets 2,212 1,542
Current liabilities (8,724) (11,777)
Non-current liabilities (96) -
------ -------
Net assets of discontinued
operations $1,270 $ 1,194
====== =======
10
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 September 30, 2002 Three Months Nine Months
------------ -----------
(in thousands) Average Average
Income Shares Income Shares
Income from continuing operations $17,449 $47,063
Less: preferred stock dividends (56) (168)
------- -------
Basic - available for common
shareholders 17,393 26,835 46,895 26,778
Dilutive effect of:
Stock options - 69 - 100
Convertible preferred stock 56 148 168 148
Others - 26 - 26
------- ------ ------- ------
Diluted - available for common
shareholders $17,449 27,078 $47,063 27,052
======= ====== ======= ======
Periods ended September 30, 2001 Three Months Nine Months
------------ -----------
(in thousands) Average Average
Income Shares Income Shares
Income from continuing operations $17,004 $82,969
Less: preferred stock dividends (131) (473)
------- -------
Basic - available for common
shareholders 16,873 26,425 82,496 24,988
Dilutive effect of:
Stock options - 204 - 243
Convertible preferred stock 131 148 473 148
Others - 25 - 25
------- ------ ------- ------
Diluted - available for common
shareholders $17,004 26,802 $82,969 25,404
======= ====== ======= ======
11
(7) COMPREHENSIVE INCOME
The following table presents the components of the Company's
comprehensive income:
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Net income $17,449 $16,366 $45,322 $83,311
Other comprehensive income:
Unrealized gain (loss) on
available-for-sale securities - 507 (219) 1,657
Reclassification adjustment
for unrealized gain on
available-for-sale securities
included in net income - - (406) -
Initial impact of adoption of
SFAS 133, net of minority
interest - - - (7,518)
Fair value adjustment on
derivatives designated as
cash flow hedges (4,875) (5,173) (7,593) (2,603)
------- ------- ------- -------
Comprehensive income $12,574 $11,700 $37,104 $74,847
======= ======= ======= =======
(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 111,985 stock options at a weighted average
exercise price of $34.42 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. 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 41,840 shares of common stock under its
dividend reinvestment plan.
o The Company issued 12,743 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. Compensation cost related
to the award was $1.3 million which was accrued for in 2001.
12
(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 supplemented our revolving credit
facilities and had the same terms as those facilities. The bridge
credit agreement had an original expiration date of June 30, 2002,
which was subsequently extended to September 27, 2002. On September 27,
2002, this $50 million facility was replaced by a $50 million secured
financing for the expansion at our Las Vegas II project, a 224-megawatt
gas-fired generation facility located in North Las Vegas, Nevada which
expires on November 26, 2002. This financing is guaranteed by the
Company.
On March 14, 2002, the Company closed on $135 million five-year senior
secured project-level financing for the Arapahoe and Valmont
Facilities. These projects have a total of 210 megawatts in service
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 was used for project construction. At
September 30, 2002, all of the $135 million financing had been
utilized.
On June 18, 2002, the Company closed on a $75 million bridge credit
agreement. This credit agreement bridged the issuance of $75 million of
Black Hills Power First Mortgage Bonds, which were 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.
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.
On August 13, 2002, the Company's electric utility subsidiary, Black
Hills Power, Inc., issued $75 million of First Mortgage Bonds, Series
AE, due 2032. The First Mortgage Bonds have a 7.23 percent coupon with
interest payable semiannually, 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.
In August 2002, the Company closed on a $195 million unsecured
revolving credit facility that expires August 26, 2003. The credit
facility extended the Company's previous $200 million 364-day credit
facility that expired on August 27, 2002. Interest rates under the
facility vary and are based, at the option of the Company at the time
of loan origination, on either (i) a prime based borrowing rate varying
from prime rate to prime rate plus 0.40 percent, or (ii) on a London
Interbank Offered Rate (LIBOR) based borrowing rate varying from LIBOR
plus 0.420 percent to LIBOR plus 1.40 percent.
On September 25, 2002, the Company closed on a $35 million two-year
unsecured credit agreement. Proceeds were used to fund the Company's
working capital needs and for general corporate purposes. Interest
rates under the facility vary and are based, at the option of the
Company at the time of loan origination, on either (i) a prime based
borrowing rate varying from prime rate to prime rate plus 0.875
percent, or (ii) on a London Interbank Offered Rate (LIBOR) based
borrowing rate varying from LIBOR plus 1.0 percent to LIBOR plus 1.875
percent.
13
The Company's 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 or subsidiary credit
facilities. Approximately $46 million of the cash balance at September
30, 2002 was restricted by subsidiary debt agreements for such
purposes. 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. In
addition, certain of the Company's 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 complied
with all the covenants at September 30, 2002.
The $195 million 364-day credit facility, the $200 million three-year
credit facility, and the $35 million two-year credit facility contain a
liquidity covenant that requires the Company to have $30 million in
liquid assets as of the last day of each fiscal quarter beginning with
December 31, 2002. Liquid assets are defined as unrestricted cash and
available unused capacity under the Company's credit facilities.
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 September 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: 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; Energy Marketing, which markets
natural gas, oil and related services to customers in the Midwest,
Southwest, Rocky Mountain, West Coast and Northwest regions and
transports crude oil in Texas; Power Generation, which produces and
sells power to wholesale customers; Electric group and segment, which
supplies electric utility service to western South Dakota, northeastern
Wyoming and southeastern Montana; and Communications group and segment,
which primarily markets communications and software development
services.
14
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 fuel sales
to the electric utility 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
September 30, 2002
Energy marketing $ 9,388* $ - $ 3,130
Power generation 34,700 - 4,822
Oil and gas 6,561 - 1,066
Mining 5,531 2,778 2,103
Electric 45,220 71 8,304
Communications 8,392 - (1,453)
Corporate - - (518)
Intersegment eliminations - (69) (5)
---------- ------------ ----------
Total $ 109,792 $ 2,780 $ 17,449
========== ============ ==========
*Operating revenues presented for Energy marketing represent trading margins.
See Note 2.
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
Quarter to Date
September 30, 2001
Energy marketing $ 9,692* $ - $ 4,536
Power generation 21,544 - 1,246
Oil and gas 8,496 - 2,804
Mining 4,023 2,847 3,876
Electric 43,057 461 7,929
Communications 5,154 1,090 (2,661)
Corporate - - (614)
Intersegment eliminations - (1,551) (112)
--------- -------- --------
Total $ 91,966 $ 2,847 $ 17,004
========= ======== ========
*Operating revenues presented for Energy marketing represent trading margins.
See Note 2.
15
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
Year to Date
September 30, 2002
Energy marketing $ 21,722* $ - $ 7,033
Power generation 102,849 - 13,775
Oil and gas 19,515 - 3,227
Mining 15,241 8,150 6,932
Electric 120,583 203 22,918
Communications 24,155 - (5,729)
Corporate - - (1,081)
Intersegment eliminations - ( 203) (12)
-------- -------- ---------
Total $304,065 $ 8,150 $ 47,063
======== ======== =========
*Operating revenues presented for Energy marketing represent trading margins.
See Note 2.
External Inter-segment Income (loss) from
Operating Revenues Operating Revenues Continuing Operations
Year to Date
September 30, 2001
Energy marketing $ 71,795* $ - $30,910
Power generation 56,061 - 3,827
Oil and gas 26,353 - 8,723
Mining 14,681 8,333 8,499
Electric 174,915 783 42,053
Communications 13,662 3,307 (9,343)
Corporate - - (1,081)
Intersegment eliminations - (4,090) (619)
-------- --------- -------
Total $357,467 $ 8,333 $82,969
======== ========= =======
*Operating revenues presented for Energy marketing represent trading margins.
See Note 2.
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 "Energy Marketing" segment and changes resulting from
normal operating activities.
The Power Generation segment had a net addition to non working capital
assets of approximately $106 million primarily related to ongoing
construction of the expansions at the Las Vegas Cogeneration II and
Arapahoe facilities and the acquisition of additional ownership
interest at the Harbor Cogeneration facility (Note 13).
16
The Energy Marketing segment acquired additional ownership interests in
pipelines for $17.7 million (Note 13).
(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 gains or losses on all
energy trading contracts 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:
September 30, 2002 December 31, 2001 September 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 46,354 1 9,882 1 17,449 2
Natural gas basis swaps sold 54,686 1 10,696 1 18,940 2
Natural gas fixed-for float swaps purchased 15,295 1 10,646 2 13,102 1
Natural gas fixed-for-float swaps sold 21,054 1 11,815 2 13,279 1
Natural gas swing swaps purchased - - 465 1 2,635 1
Natural gas swing swaps sold - - 930 1 3,410 1
Natural gas physical purchases 48,273 2 13,159 1 12,925 1
Natural gas physical sales 43,296 1 19,339 1 19,896 1
Transport purchase 81,759 5 41,136 6 43,780 6
(thousands of barrels)
Crude oil purchased 4,173 1 3,139 1 2,335 1
Crude oil sold 4,172 1 3,142 1 2,312 1
(megawatt-hours)
Power purchased 30,475 1 - - - -
Power sold 84,800 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
September 30, 2002, December 31, 2001, and September 30, 2001, are as
follows (in thousands):
Current Non-current Current Non-current
Derivative Derivative Derivative Derivative Unrealized
September 30, 2002 Assets Assets Liabilities Liabilities Gain
------ ------ ----------- ----------- ----
Natural gas $37,009 $2,232 $30,443 $1,441 $7,357
Crude oil 6,624 - 5,849 - 775
Power generation 326 - 55 - 271
------- ------ ------- ------ ------
$43,959 $2,232 $36,347 $1,441 $8,403
======= ====== ======= ====== ======
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
======= ======= ======= ======= ======
September 30, 2001
Natural gas $44,998 $1,752 $41,869 $1,636 $5,650
Crude oil 6,148 - 5,393 - 755
------- ------ ------- ------ ------
$51,146 $1,752 $47,262 $1,636 $6,405
======= ====== ======= ====== ======
At September 30, 2002, the Company had a mark to fair value unrealized
gain of $8.4 million for its energy marketing activities. Of this
amount, $7.6 million was current and $0.8 million was non-current.
Substantially all of the unrealized gain at September 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 September 30, 2002, December 31, 2001 and September 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 Pretax
Terms in Derivative Derivative Derivative Derivative Comprehensive Income
Notional* Years Assets Assets Liabilities Liabilities Income (Loss) (Loss)
--------- ----- --------- ------ ----------- ----------- ------------- ------
September 30, 2002
Crude oil swaps 420,000 1 $ 18 $ 12 $1,027 $ 73 $(1,003) $ (67)
Natural gas swaps 600,000 1 267 - 142 28 90 7
------- ----- ------ ----- ------- ------
$ 285 $ 12 $1,169 $ 101 $ (913) $ (60)
======= ===== ====== ===== ======= ======
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
======= ===== ====== ===== ======= ======
September 30, 2001
Crude oil swaps 141,000 1 $ 312 $ - $ - $ - $ 327 $ (15)
Crude oil options 60,000 1 35 - - - 105 (70)
Natural gas swaps 1,676,000 1 2,277 - - - 2,184 93
------- ----- ------ ----- ------- ------
$ 2,624 $ - $ - $ - $ 2,616 $ 8
======= ===== ====== ===== ======= ======
- -----------------------
*crude in bbls, gas in MMBtu's
Based on September 30, 2002 market prices, $(0.9) 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 September 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 September 30, 2002, December 31, 2001 and September 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 Loss (Loss)
----- ---- ----- ------ ------ ----------- ----------- ---- ------
September 30, 2002
Swaps on project
financing $213,636 5.99% 4 $ - $ - $ 9,114 $ 9,022 $(18,136) $ -
Swaps on corporate
debt 75,000 4.45% 2 - 1,201 333 (1,534) -
-------- ---- ---------- -------- -------- -------- --------
Total $288,636 $ - $ - $ 10,315 $ 9,355 $(19,670) $ -
======== ==== ========== ======== ======== ======== ========
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) $
======== ==== ========== ======== ======== ======== ========
September 30, 2001
Swaps on project
financing $318,906 5.86% 5 $ - $ - $15,101 $ - $(15,101) $ -
Swaps on corporate
debt 75,000 4.45% 3 - - 1,758 (1,758) -
-------- ---- ---------- -------- -------- -------- --------
Total $393,906 $ - $ - $ 16,859 $ - $(16,859) $ -
======== ==== ========== ======== ======== ======== ========
Based on September 30, 2002 market interest rates, approximately $10.3
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 in the second quarter of 2002 the resulting gain
was carried in Accumulated Other Comprehensive Income on the Condensed
Consolidated Balance Sheet and was to be amortized over the life of the
anticipated long-term financing. In the third quarter of 2002, this
cash flow hedge was determined to be ineffective due to uncertainties
about the eventual timing and form of financing for this project. As a
result, $1.1 million was taken into earnings. The gain was offset by
the expensing of approximately $1.0 million of deferred financing costs
related to the anticipated financing.
20
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 9). The treasury lock cash
settled on August 8, 2002, the bond pricing date, and resulted in a
$1.8 million loss. This treasury lock was treated as a cash flow hedge
and accordingly the resulting loss is carried in Accumulated Other
Comprehensive Loss on the Condensed Consolidated Balance Sheet and
amortized over the life of the related bonds as additional interest
expense.
(12) LEGAL PROCEEDINGS
In June 2002, a forest fire damaged approximately 11,000 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.
Alleged contact between power lines owned by the Company and
undergrowth were implicated as the cause. The Company has initiated its
own investigation into the cause of the fire, including the hiring of
expert fire investigators, and that investigation is continuing.
The Company has been put on notice of potential private civil claims
for property damage and business loss. In addition, the State of South
Dakota initiated a civil action in the Seventh Judicial Circuit Court,
Pennington County, South Dakota, seeking recovery of damages for fire
suppression costs, reclamation and remediation. If it is determined
that power line contact was the cause of the fire, and that the Company
was negligent in the maintenance of those power lines, the Company
could be liable for resultant damages. Management cannot predict the
outcome of either the Company's investigation, or the viability of
potential claims. Management believes that any such claims will not
have a material adverse effect on the Company's 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. At September 30, 2002 the
Company had an 88 percent ownership interest in the Facility.
21
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.
During July 2002, the Company 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.
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 $9.3 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
On October 1, 2002, the Company entered into a definitive merger
agreement to acquire Denver-based Mallon Resources Corporation. Total
cost of the acquisition is estimated to be $52 million, which includes
the Company's acquisition on October 1, 2002 of Mallon's debt to Aquila
Energy Capital Corporation and the settlement of outstanding hedges,
amounting to $30.5 million. The merger agreement, which has been
approved by both companies' Board of Directors, provides that Mallon
shareholders will receive 0.044 of a share of Black Hills for each
share of Mallon. Completion of the acquisition which is subject to
customary conditions, including approval by the shareholders of Mallon,
is expected in the first quarter of 2003.
Mallon Resources' proved reserves, as reported at December 31, 2001,
were 53.3 billion cubic feet of gas equivalent. The Company estimates
that Mallon's current proved reserves could be substantially higher
based on its independent review of the reserves and current oil and gas
prices. The reserves are located primarily on the Jicarilla Apache
Nation in the San Juan Basin of New Mexico and are comprised almost
entirely of natural gas in shallow sand formations. The oil and gas
leases of the acquisition total more than 66,500 gross acres (56,000
net), most of which is contained in a contiguous block that is in the
early stages of development. The Company believes it can recover
additional gas reserves from the shallow sands and from deeper horizons
that have yet to be explored but are productive elsewhere in the San
Juan Basin.
22
Current daily net production of the Mallon properties is nearly 13
million cubic feet of gas equivalent. Mallon operates 149 of 171 total
gas and oil wells, with working interests averaging 90 to 100 percent
in most of the wells and undeveloped acreage.
Upon closing, the acquisition is expected to increase gas and oil
production immediately by approximately 60 percent and more than double
our proven oil and gas reserves. After the acquisition is closed, the
Company plans to initiate a development and exploratory drilling
program on the properties. The acquisition is expected to have a
nominal earnings-per-share impact until production levels can be
increased.
23
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 transport crude oil in Texas. Our electric utility, Black
Hills Power, Inc., serves an average of 59,600 customers in South Dakota,
Wyoming and Montana. Our communications group offers state-of-the-art broadband
communications services to over 23,700 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.
Results of Operations
Consolidated Results
Revenue and Income (loss) from continuing operations provided by each
business group as a percentage of our total revenue and Income (loss)
from continuing operations were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
Revenues
Integrated energy 52% 49% 53% 48%
Electric utility 40 45 39 48
Communications 8 6 8 4
--- --- --- ---
100% 100% 100% 100%
=== === === ===
Income/(Loss) from
Continuing Operations
Integrated energy 62% 70% 64% 61%
Electric utility 48 47 49 50
Communications and other (10) (17) (13) (11)
--- --- --- ---
100% 100% 100% 100%
=== === === ===
24
Three Months Ended September 30, 2002 Compared to Three Months Ended September
30, 2001. Consolidated income from continuing operations for the three-month
period ended September 30, 2002 was $17.4 million or $0.64 per share compared to
$17.0 million or $0.63 per share in the same period of the prior year.
The increase in net income from continuing operations was a result of an
increase in power generation and electric utility net income and a decrease in
the net loss of our communications business group offset by decreases in net
income in the energy marketing, oil and gas production and coal mining segments.
The power generation segment's net income more than tripled due to its
additional generating capacity and increased earnings from additional ownership
of an energy partnership. Net income for the electric utility business group
increased due to an increase in off-system sales and the communications business
group showed a decrease in its net loss attributable to a substantial expansion
of its customer base and a $0.6 million after-tax collection of previously
reserved amounts. Net income from energy marketing decreased due to a
substantial decline in margins received offset by increased volumes marketed and
unrealized gains recognized through mark-to-market accounting. The oil and gas
production segment's net income decreased due to a 17 percent decrease in
production volumes and an 11 percent decrease in average prices received. Coal
mining had strong operational performance with production increasing 27 percent,
however net income decreased due to a $3.4 million after-tax gain related to a
coal contract settlement that was recognized in the third quarter of 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. Net loss from discontinued operations was $(0.6)
million or $(0.02) per share for the three months ended September 30, 2001.
Prior year results of operations have been restated to reflect the discontinued
operations.
Consolidated revenues for the three-month period ended September 30, 2002 were
$112.6 million compared to $94.8 million for the same period in 2001. The
increase in revenues was a result of increased revenue in the communications
business unit and power generation segment and an increase in coal production
and volumes of energy marketed, partially offset by lower energy commodity
prices in 2002 and a decrease in the production of oil and gas.
Consolidated operating expenses for the three-month period increased from $66.0
million in 2001 to $78.0 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, partially offset by a substantial decrease in gas
prices as discussed above.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001. Consolidated income from continuing operations for the nine-month period
ended September 30, 2002 was $47.1 million or $1.74 per share compared to $83.0
million or $3.27 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
first half of 2001 stemming primarily from gas and electricity shortages in the
West. Approximately $1.40 per share 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
25
were approximately $182 per megawatt-hour during the first nine-months of 2001
compared to approximately $21 per megawatt-hour during the first nine months of
2002. Average spot gas prices in the West Coast region were approximately $8.60
per MMBtu in the first nine months of 2001 compared to $2.80 in the first nine
months of 2002. 2001 net income reflects a coal contract settlement which
resulted in a one-time gain of approximately $3.4 million or $0.13 per share.
While the above factors negatively impacted income from continuing operations,
they were offset in part by 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
the continued 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 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 was $(2.6) million or $(0.09)
per share for the nine months ended September 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 nine-month period ended September 30, 2002 were
$312.2 million compared to $365.8 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, increased production in coal, oil and gas and
increased marketing volumes.
Consolidated operating expenses for the nine-month period decreased from $221.5
million in 2001 to $216.0 million in 2002. The decrease was primarily due to
lower fuel costs and incentive compensation offset by increased expenses related
to our increased investment in independent power generation.
The following results of operations for the Integrated Energy Group and its
segments, Electric Utility Group and Communications Group, does not include
intercompany eliminations.
Integrated Energy Group
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Revenue:
Energy marketing $ 9,388 $ 9,692 $ 21,722 $ 71,795
Power generation 34,700 21,544 102,849 56,061
Oil and gas 6,561 8,496 19,515 26,353
Mining 8,309 6,870 23,391 23,014
---------- ---------- --------- ---------
Total revenue 58,958 46,602 167,477 177,223
---------- ---------- --------- ---------
Equity in investments of
unconsolidated
subsidiaries 907 1,958 4,187 11,066
---------- ---------- --------- ---------
Operating expenses 38,475 29,916 107,689 96,685
---------- ---------- --------- ---------
Operating income $ 21,390 $ 18,644 $ 63,975 $ 91,604
Net income $ 10,961 $ 12,029 $ 31,271 $ 50,718
26
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 Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
Fuel production:
Tons of coal sold 1,110,800 872,900 2,955,500 2,465,700
Barrels of oil sold 110,403 126,557 340,036 335,585
Mcf of natural gas sold 1,019,564 1,273,667 3,567,135 3,295,442
Mcf equivalent sales 1,681,982 2,033,000 5,607,351 5,309,000
September 30
2002 2001
---- ----
Independent power capacity:
MWs of independent power capacity in service 657 625
MWs of independent power capacity under construction* 364 360
- -------------------
*includes a 90 MW plant under a lease arrangement
The following is a summary of average daily energy marketing volumes:
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
Natural gas - MMBtus 1,140,200 1,062,600 1,039,200 947,900
Crude oil - barrels 57,200 35,100 53,700 37,000
Three Months Ended September 30, 2002 Compared to Three Months Ended September
30, 2001. Net income for the integrated energy group for the three months ended
September 30, 2002 was $11.0 million compared to $12.0 million in the same
period of the prior year. Net income decreased slightly due to a decrease in net
income from energy marketing, oil and gas production and coal mining, partially
offset by an increase in power generation net income. The power generation
segment's net income more than tripled due to its additional generating capacity
and increased earnings from additional ownership of an energy partnership. Net
income from energy marketing decreased due to a substantial decline in margins
received offset by increased volumes marketed, the addition of pipeline earnings
and unrealized gains recognized through mark-to-market accounting. The oil and
gas production segment's net income decreased due to a 17 percent decrease in
production volumes and an 11 percent decrease in average prices received. Coal
mining had strong operational performance with production increasing 27 percent,
however net income decreased due to a $3.4 million after-tax gain related to a
coal contract settlement that was recognized in the third quarter of 2001.
27
The integrated energy business group's revenues and expenses increased 27
percent and 29 percent respectively for the three months ended September 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 commodity
prices. Expenses increased due to higher fuel costs and depreciation
expense resulting from increased capacity.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001. Net income for the integrated energy group for the nine months ended
September 30, 2002 was $31.3 million compared to $50.7 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, additional ownership of an
energy partnership, the addition of pipeline earnings 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 6 percent
increase in gas and oil production sales partially offset an earnings decrease
in the oil and gas segment caused by a 34 percent decrease in the average price
received. The energy marketing segment's net income decreased primarily due to a
substantial decrease in margins received, partially offset by increased volumes
marketed. Net income for the coal mining segment decreased due to a $3.4 million
after-tax gain related to a coal contract settlement that was recognized in the
third quarter of 2001 which was partially offset by the increase in tons of coal
sold in 2002.
The integrated energy business group's revenues decreased 6 percent and expenses
increased 11 percent, respectively, for the nine months ended September 30, 2002
compared to the same period in 2001. The decrease in revenue was a direct result
of the substantial decline in commodity prices. The increase in expenses
was primarily due to higher fuel costs and depreciation expense resulting from
the increased generating capacity.
Energy Marketing
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Revenue* $ 9,388 $ 9,692 $ 21,722 $ 71,795
Operating income $ 4,860 $ 6,601 $ 10,479 $ 48,960
Net income $ 3,130 $ 4,536 $ 7,033 $ 30,910
*Revenues presented for Energy marketing represent trading margins. See Note 2.
Three Months Ended September 30, 2002 Compared to Three Months Ended September
30, 2001. The decrease in revenues is attributed to a decline in commodity
prices, partially offset by a 7 percent increase in natural gas average daily
volumes marketed and a 63 percent increase in crude oil average daily volumes
marketed. Net income decreased 31 percent due to a substantial decline in
commodity prices and margins. 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 for the
three-month periods ended September 30, 2002 and 2001 were $1.5 million and $0.5
million, respectively, resulting in a quarter over quarter net income increase
of $1.0 million.
28
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 loss from discontinued operations was $(0.6)
million or $(0.02) per share for the third quarter of 2001. Prior year results
of operations have been restated to reflect the discontinued operations and the
coal marketing business is no longer reflected in the energy marketing segment.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001. Revenues and net income decreased substantially primarily due to a
substantial decline in commodity prices and margins received, offset by a 10
percent increase in natural gas average daily volumes marketed and a 45 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 $8.60 per MMBtu in the first nine months of 2001
compared to $2.80 in the first nine months of 2002.
Income (loss) from discontinued operations was $(2.6) million or $(0.09) per
share for the nine months ended September 30, 2002 compared to $0.3 million or
$0.01 per share for the same period of the prior year.
Power Generation
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Revenue $34,700 $21,544 $ 102,849 $56,061
Operating income $13,036 $ 7,752 $ 43,736 $25,316
Net income (loss) $ 4,822 $ 1,246 $ 14,670 $ 3,827
Three Months Ended September 30, 2002 Compared to Three Months Ended September
30, 2001. Revenue and operating income increased 61 percent and 68 percent,
respectively, and net income more than tripled for the three-month period ended
September 30, 2002 compared to the same period in 2001 and is attributed to
additional generating capacity and increased earnings from additional ownership
of an energy partnership. As of September 30, 2002, we had 657 megawatts of
independent power capacity in service compared to 625 megawatts at September 30,
2001. Approximately 300 megawatts of the 625 megawatts of capacity at September
30, 2001 were brought on during the third quarter of 2001. Additional
partnership equity was earned by the Company in July 2002 as a result of certain
performance measures being met at a consolidated energy partnership. The
earnings impact was approximately $1.6 million pre-tax and was recorded as a
reduction to "Minority interest" expense on the accompanying Condensed
Consolidated Statement of Income.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001. Revenue and operating income increased 83 percent and 73 percent,
respectively, and net income more than tripled for the nine-month period ended
September 30, 2002 compared to the same period in 2001 and is attributed to
additional generating capacity and increased earnings from additional ownership
of an energy partnership. As of September 30, 2002, we had 657 megawatts of
29
independent power capacity in service compared to 625 megawatts at September 30,
2001. Approximately 300 megawatts of the 625 megawatts of capacity at September
30, 2001 were brought on during the third quarter of 2001.
The increase in net income for the nine-month period ended September 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.
Oil and Gas
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Revenue $6,561 $8,496 $19,515 $26,353
Operating income $1,408 $4,305 $ 4,191 $12,929
Net income $1,066 $2,804 $ 3,227 $ 8,723
The following is a summary of our internally estimated economically recoverable
oil and gas reserves measured using constant product prices as of September 30,
2002 and 2001. Estimates of economically recoverable reserves are based on a
number of variables, which may differ from actual results.
September 30
2002 2001
---- ----
Barrels of oil (in millions) 4.9 4.2
Bcf of natural gas 32.3 25.7
Total in Bcf equivalents 61.7 50.9
Three Months Ended September 30, 2002 Compared to Three Months Ended September
30, 2001. Revenue and net income of the oil and gas production business segment
decreased 23 percent and 62 percent, respectively for the three-month period
ended September 30, 2002, compared to the same period in 2001 due to an 11
percent decrease in the average price received and a 17 percent decrease in
production volumes due in part to delayed drilling.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001. Revenue and net income of the oil and gas production business segment
decreased 26 percent and 63 percent respectively, for the nine-month period
ended September 30, 2002, compared to the same period in 2001 due to a 34
percent decrease in the average price received partially offset by a 6 percent
increase in production volumes.
30
Mining
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Revenue $8,309 $6,870 $23,391 $23,014
Operating income $2,503 $ 830 $ 6,937 $ 5,664
Net income $2,103 $3,876 $ 6,932 $ 8,499
Three Months Ended September 30, 2002 Compared to Three Months Ended September
30, 2001. Revenue from our mining segment increased 21 percent and net income
decreased 46 percent for the three-month period ended September 30, 2002,
compared to the same period in 2001. Revenues increased due to a 27 percent
increase in tons of coal sold, partially offset by lower prices received.
Net income decreased due to a $3.4 million after-tax gain related to a coal
contract settlement that was recognized in the third quarter of 2001 which was
partially offset by the increase in tons of coal sold in the third quarter of
2002.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001. Revenue from our mining segment increased 2 percent and net income
decreased 18 percent for the nine-month period ended September 30, 2002,
compared to the same period in 2001. Revenue increased due to a 20 percent
increase in tons of coal sold, partially offset by lower prices received.
Net income decreased due to a $3.4 million after-tax gain related to a coal
contract settlement that was recognized in the third quarter of 2001 which was
partially offset by the increase in tons of coal sold in 2002.
Electric Utility Group
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Revenue $45,291 $43,518 $120,786 $175,698
Operating expenses 29,316 28,272 77,131 102,477
------- ------- -------- --------
Operating income $15,975 $15,246 $ 43,655 $ 73,221
Net income $ 8,304 $ 7,929 $ 22,918 $ 42,053
The following table provides certain operating statistics:
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
Firm (system) sales - MWh 510,500 537,000 1,466,000 1,527,000
Off-system sales - MWh 317,600 211,000 688,700 761,000
31
Three Months Ended September 30, 2002 Compared to Three Months Ended September
30, 2001. Revenue, operating expenses and net income increased 4 percent, 4
percent and 5 percent, respectively for the three-month period ended September
30, 2002 compared to the same period in the prior year primarily due to a 51
percent increase in off-system electric megawatt-hour sales offset by a 22
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.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001. Revenue, operating expenses and net income decreased 31 percent, 25
percent and 46 percent, respectively for the nine-month period ended September
30, 2002 compared to the same period in the prior year primarily due to a 10
percent decrease in off-system electric megawatt-hour sales and a 69 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 operating
expenses attributable to lower fuel and purchased power costs.
Communications Group
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Revenue $ 8,392 $ 5,154 $24,155 $13,717
Operating expenses 9,770 8,101 30,203 23,237
------- ------- ------- -------
Operating loss $(1,378) $(2,947) $(6,048) $(9,520)
Net loss $(1,453) $(2,661) $(5,729) $(9,343)
September 30 June 30 December 31 September 30
2002 2002 2001 2001
---- ---- ---- ----
Business customers 2,960 2,970 2,250 1,940
Business access lines 8,772 8,380 6,836 6,180
Residential customers 20,760 19,450 15,660 13,780
Three Months Ended September 30, 2002 Compared to Three Months Ended September
30, 2001. The communications business group's net loss for the three-month
period ended September 30, 2002 was $(1.5) million, compared to $(2.7) million
in 2001. The performance improvement is due largely to a 63 percent increase in
revenue as a result of a larger customer base and a $0.6 million after-tax
collection of previously reserved amounts, partially offset by increased costs
of sales and administrative expenses.
The total number of customers exceeded 23,700 at the end of September 2002 - a 6
percent and 32 percent increase over the customer base at June 30, 2002 and
December 31, 2001, respectively, and a 51 percent increase compared to September
30, 2001.
32
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001. The communications business group's net loss for the nine month period
ended September 30, 2002 was $(5.7) million, compared to $(9.3) million in 2001.
The performance improvement is due largely to a 76 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 23,700 at the end of September 2002 - a 6
percent and 32 percent increase over the customer base at June 30, 2002 and
December 31, 2001, respectively, and a 51 percent increase compared to September
30, 2001.
We expect our communications group will sustain approximately $7.0 million in
net losses in calendar year 2002, with annual losses decreasing in 2003 and
profitability expected by 2004.
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. 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
Defined Benefit Pension Plan
We have a noncontributory defined benefit pension plan (Plan) covering our
employees and certain subsidiaries who meet eligibility requirements. The
benefits are based on years of service and compensation levels during the
highest five consecutive years of the last ten years of service. Our funding
policy is in accordance with the federal government's funding requirements. The
Plan's assets are held in trust and consist primarily of equity securities and
cash equivalents. The determination of our obligation and expense for pension
benefits is dependent on the use of certain assumptions by actuaries in
calculating the amounts. Those assumptions include, among others, the expected
long-term rate of return on Plan assets, the discount rate and the rate of
increase in compensation levels. The actuaries review the Plan annually and are
currently in the process of reviewing our Plan to determine our obligation and
our expense for next year. The market value of the Plan's assets has been
affected by declines in the equity market in the last year. As a result, we
could be required to recognize an additional minimum liability in the fourth
quarter of 2002 as prescribed by Statement of Financial Accounting Standards
(SFAS) No. 87 "Employers' Accounting for Pensions" and SFAS No. 132 "Employers'
Disclosure about Pensions and Postretirement Benefits." If required, the
liability would be recorded as a reduction to Other Comprehensive Income, and
would not affect net income. We do not expect this liability to be material, if
it is required. However, we currently anticipate the amount of our pre-tax
pension expense in 2003 will be in a range of $2.5 million to $3.5 million more
than the amount for 2002, which would have a negative effect on earnings per
share of $0.06 to $0.09 in 2003.
33
Special Purpose Entities
As described more fully in the Management's Discussion and Analysis of Financial
Condition and Results of Operations in the Company's Annual Report on Form 10-K
for the year ended December 31, 2001, Black Hills Generation, a subsidiary in
our power generation segment, has entered into agreements with Wygen Funding,
Limited Partnership to lease the Wygen Plant, a 90 megawatt coal-fired power
plant under construction in Campbell County, Wyoming. Wygen Funding is a special
purpose entity that owns the Wygen Plant and has financed the project. Neither
Wygen Funding, its owners, nor its officers are related to us, and other than
the lease transaction and obligations incurred as a result of the transaction,
we have no obligation to provide additional funding or issue securities to Wygen
Funding. Lease payments are based on final construction and financing costs and
will begin after substantial completion of construction scheduled to occur in
the first quarter of 2003. The lease will be accounted for as an operating
lease.
The Financial Accounting Standards Board (FASB) expects to issue a new
accounting standard regarding the accounting treatment for special purpose
entities. The final provisions of this new standard may affect the accounting of
the lease arrangement. If the special purpose entity were to be consolidated
into our financial statements, we would record both the Wygen asset and its
related debt on our balance sheet. Total project costs are estimated to be in
the $130 - $140 million range. In addition, we would also have to recognize the
depreciation expense associated with the project which is estimated to be
approximately $3.5 million per year based upon a 40-year plant life and would
have reclassifications on the income statement primarily between operating
expenses and interest expense. We estimate the impact on earnings per share
would be approximately $(0.09) per share. We are monitoring this FASB project
and may consider other financing structures for the project in the future.
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 life). 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 and nine months
ended September 30, 2002 were approximately $0.4 million and $1.2 million, or
$0.01 per share and $0.05 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.
34
Liquidity and Capital Resources
Cash Flow Activities
During the nine-month period ended September 30, 2002, we generated sufficient
cash flow from operations to meet our operating needs, to pay dividends on
common and preferred stock, to pay a portion of our 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, long-term debt
and long-term non-recourse project financing.
Cash flows from operations decreased $27.2 million for the nine-month period
ended September 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 14, 2002, we closed on $135 million five-year senior secured
project-level financing for the Arapahoe and Valmont facilities. These projects
have a total of 210 megawatts in service and are located 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, and the remainder was
used for project construction.
During the first quarter of 2002, we completed a $50 million bridge credit
agreement. The credit agreement supplements our revolving credit facilities and
had the same terms as those facilities with an original expiration date of June
30, 2002, which subsequently was extended to September 27, 2002. On September
27, 2002 this $50 million facility was replaced by a $50 million secured
financing for the expansion at our Las Vegas II project, a 224 megawatt
gas-fired generation facility located in North Las Vegas, Nevada which expires
on November 26, 2002. This financing is guaranteed by the Company.
On June 18, 2002, we closed on a $75 million 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.
During July 2002, we 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 Oil Tanking Houston terminal
35
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, our electric utility subsidiary, Black Hills Power, Inc.,
issued $75 million of First Mortgage Bonds, series AE, due 2032. The Mortgage
Bonds have a 7.23 percent coupon with interest payable semiannually, commencing
February 15, 2003. Net proceeds from the offering were and will be used to fund
the utility'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.
In August 2002, we closed on a $195 million revolving unsecured credit facility
that expires August 26, 2003. The credit facility extended our previous $200
million 364-day credit facility that expired on August 27, 2002.
On September 25, 2002, we closed on a $35 million unsecured two-year credit
agreement. Proceeds were used to fund our working capital needs and for general
corporate purposes.
Dividends
Dividends paid on our common stock totaled $0.29 per share in each of the first
three 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 September 30, 2002 we had approximately
$75 million of cash and $480 million of bank facilities. Approximately $46
million of the cash balance at September 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 facility due November
26, 2002, a $195 million facility due August 26, 2003, a $200 million facility
due August 27, 2004 and a $35 million facility due September 30, 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 September 30, 2002, we had $383.5 million of bank borrowings
outstanding under these facilities. After inclusion of applicable letters of
credit, the remaining borrowing capacity under the bank facilities was $57.1
million at September 30, 2002.
Two significant cash events occurred subsequent to the third quarter. On October
1, 2002 we acquired Mallon Resources Corporation's debt to Aquila Energy Capital
Corporation and settled Mallon's outstanding hedges, amounting to $30.5 million,
as part of the definitive merger agreement to acquire Denver-based Mallon
Resources Corporation. The acquisition of this debt was funded with our
corporate credit facilities. Also, during October we received a $23.7 million
federal income tax refund as a result of filing our 2001 federal income tax
return. The refund was primarily due to accelerated depreciation and other plant
36
related timing differences for tax purposes. The income tax refund was used to
pay down our corporate credit facilities. At October 31, 2002, we had $403.0
million of bank borrowings outstanding under our corporate credit facilities
with $37.6 million of remaining borrowing capacity available after the inclusion
of applicable letters of credit.
The above bank facilities include covenants that are common in such
arrangements. Several of the facilities require that we maintain 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. The $35 million credit facility's covenants include
consolidated net worth in an amount of not less than the sum of $425 million and
50 percent of the aggregate consolidated net income beginning April 1, 2002; a
recourse leverage ratio not to exceed 0.65 to 1.00; and an interest coverage
ratio of not less than 1.50 to 1.00. In addition the $195 million 364 day credit
facility, the $200 million three-year credit facility and the $35 million
two-year credit facility contain a liquidity covenant that requires us to have
$30 million of liquid assets as of the last day of each fiscal quarter beginning
with December 31, 2002. Liquid assets are defined as unrestricted cash and
available unused capacity under our credit facilities. 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. 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. As of September 30, 2002, we were in compliance with
the above covenants.
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 $534.8 million at September 30, 2002. The
long-term debt component of our capital structure at September 30, 2002 was 51
percent and our total debt leverage (long-term debt and short-term debt) was 64
percent.
In addition, Enserco Energy, Inc., our gas marketing unit, has a $135 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
September 30, 2002, there were outstanding letters of credit issued under the
facility of $26.1 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 purchases of crude oil by Black Hills Energy Resources.
We provided no guarantee to the lender under this facility. At September 30,
2002, Black Hills Energy Resources had letters of credit outstanding of $18.9
million and no balance outstanding on its overdraft line.
We continue to seek non-recourse project-level financing for our independent
power projects. Due to creditworthiness concerns with counterparties, financing
arrangements for the Las Vegas Cogeneration power plant expansion, currently
under construction, have been delayed.
37
Allegheny Energy Supply Company (AESC), a subsidiary of Allegheny Energy Inc.,
has a contract to purchase all of the facility's capacity and all associated
energy and ancillary services. Both AESC and its parent, Allegheny Energy Inc.
have recently had their credit ratings downgraded below investment grade status
and have technically defaulted on some of their credit agreements with other
counterparties. The Las Vegas expansion is expected to be operational in the
fourth quarter of 2002 and has been funded with the corporate credit facilities.
Total construction and acquisition costs, including Las Vegas Cogeneration I,
are expected to be $330 million of which $302 million was expended as of
September 30, 2002.
If we are not successful in extending the $50 million facility that expires on
November 26, 2002 or in obtaining other financing, a deficiency in our liquidity
could occur.
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 can provide no assurance 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
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.
Financing for construction requirements and operational needs is dependent upon
the cost and availability of external funds from capital markets and financial
institutions at both company and project levels. Access to funds is dependent
upon factors such as general economic conditions, regulatory authorizations and
policies, our credit rating, the operations of the projects funded, the credit
ratings of project counterparties, and the economics of the projects under
construction.
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. 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.
38
The credit ratings of the senior unsecured debt of Public Service Company of
Colorado (PSCo), Nevada Power Company and Allegheny Energy Supply Company,
counterparties under tolling agreements with our subsidiaries, have recently
been downgraded by one or more rating agencies. The credit ratings of Nevada
Power Company, its parent holding company, Sierra Pacific Resources, and
Allegheny Energy Supply Company, have all been downgraded to non-investment
grade status. In addition, project level financing arrangements in place for
projects in Colorado and New York provide for the potential acceleration of
payment obligations in the event of nonperformance by a counterparty under
related power purchase agreements. If these or other counterparties fail to
perform their obligations under their respective power purchase agreements,
our financial condition and results of operation may be adversely affected. We
may not be able to enter into agreements in replacement of our existing power
purchase agreements on terms as favorable as our existing agreements, or at all.
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.
Our broadband communications business is subject to significant competition for
its services and to rapid technological change.
Our communications group, which provides a full suite of communication
services, faces strong competition for its services from the incumbent local
exchange carrier as well as from long distance providers, Internet service
providers, the incumbent cable television provider and others.
39
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.
Our ability to recover our capital investment is dependent on our ability to
sustain our customer base and is subject to the risk that technological advances
may render our network obsolete. 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 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, and our rights under warranties or performance guarantees may
not be adequate to cover lost revenues, increased expenses or liquidated damage
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.
40
We face potential claims related to a forest fire in South Dakota.
In June 2002, a forest fire damaged approximately 11,000 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. Alleged
contact between power lines owned by us and undergrowth 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.
We have been put on notice of potential private civil claims for property damage
and business loss. In addition, the State of South Dakota initiated a civil
action in the Seventh Judicial Circuit Court, Pennington County, South Dakota,
seeking recovery of damages for fire suppression costs, reclamation and
remediation. If it is determined that power line contact was the cause of the
fire and that we were negligent in the maintenance of those power lines, we
could be liable for resultant damages. We cannot predict the outcome of either
our investigation or the viability of potential claims. Management believes that
any such claims will not have a material adverse effect on our financial
condition or results of operations.
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.
41
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. 02-3, "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."
At a meeting on October 25, 2002, the EITF reached new consensuses that
effectively supersede the consensuses on EITF 02-3, reached at its June 2002
meeting. At its October 2002 meeting, the EITF reached a consensus to rescind
EITF 98-10, the impact of which is to preclude mark-to-market accounting for all
energy trading contracts not within the scope of FASB Statement No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The EITF also
reached a consensus that gains and losses on derivative instruments within the
scope of Statement 133 should be shown net in the income statement if the
derivative instruments are held for trading purposes. The consensus regarding
the rescission of Issue 98-10 is applicable for fiscal periods beginning after
December 15, 2002. Energy trading contracts not within the scope of Statement
133 purchased after October 25, 2002, but prior to the implementation of the
consensus are not permitted to apply mark-to-market accounting. We have not yet
42
quantified the financial statement effect of this EITF action. We currently
report our energy trading activities on a net basis.
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 and
recover refunds for alleged price manipulation; (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
43
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 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 us from those
reported in our 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
our 2001 Annual Report on Form 10-K, and Notes to Condensed Consolidated
Financial Statements in this Form 10-Q.
ITEM 4. CONTROLS AND PROCEDURES
With the participation of management, our Chief Executive Officer and Chief
Financial Officer evaluated our disclosure controls and procedures within 90
days of the filing of this quarterly report. Based on this evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the disclosure
controls and procedures are effective in ensuring that information required to
be disclosed by us in the reports filed or submitted by us under the Exchange
Act is recorded, processed, summarized and reported within the time periods
specified in the Securities and Exchange Commission's rules and forms.
There have been no significant changes in our internal controls or other factors
that could significantly affect these controls subsequent to the date of our
evaluation, including any significant deficiencies or material weaknesses of
internal controls that would require corrective action.
44
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 6. Exhibits and Reports on Form 8-K
(a) Exhibits -
Exhibit 10.1 $195 million Amended and
Restated 364-day Credit Agreement
dated as of August 27, 2002, Among
Black Hills Corporation as Borrower,
the Financial Institutions Party
Hereto, as Banks, ABN Amro Bank
N.A., as Syndication Agent, Bank of
Montreal, as Co-Syndication Agent,
US Bank, National Association, as
Documentation Agent and Bank of Nova
Scotia, as Co-Documentation Agent.
Exhibit 10.2 $35 million Term Credit
Agreement dated as of September 25,
2002 among Black Hills Corporation
(Borrower), The Financial
Institutions Party Hereto (Banks),
and Credit Lyonnais New York Branch
(Administrative Agent).
Exhibit 10.3 The First Supplemental Indenture,
dated as of August 13, 2002,
between Black Hills Power, Inc. and
JPMorgan Chase Bank, as Trustee.
Exhibit 10.4 First Amendment to 3-year Credit
Agreement.
Exhibit 10.5 Second Amendment to 3-year Credit
Agreement.
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.
45
(b) Reports on Form 8-K
We have filed the following Reports on Form 8-K
during the quarter ended September 30, 2002.
Form 8-K dated August 12, 2002.
Reported under Item 9 the filing of sworn statements
by Daniel P. Landguth, Black Hills Corporation's
Principal Executive Officer and Mark T. Thies, Black
Hills Corporation's Principal Financial Officer
pursuant to Securities and Exchange
Commission Order No. 4-460.
Form 8-K dated October 1, 2002.
Reported under Item 5 that Black Hills Corporation
and Mallon Resources Corporation entered into a
definitive merger agreement for the acquisition of
Mallon Resources in a stock-for-stock transaction.
46
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/ Daniel P. Landguth
----------------------------------------
Daniel P. Landguth, Chairman and
Chief Executive Officer
/s/ Mark T. Thies
----------------------------------------
Mark T. Thies, Senior Vice President and
Chief Financial Officer
Dated: November 14, 2002
47
CERTIFICATION
I, Daniel P. Landguth, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Black Hills
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
48
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002
/s/ Daniel P. Landguth
------------------------
Chairman and
Chief Executive Officer
49
CERTIFICATION
I, Mark T. Thies, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Black Hills
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b. any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
50
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002
/s/ Mark T. Thies
-------------------------
Senior Vice President and
Chief Financial Officer
51
EXHIBIT INDEX
Exhibit Number Description
Exhibit 10.1 $195 million Amended and Restated 364-day Credit
Agreement dated as of August 27, 2002, Among Black
Hills Corporation as Borrower, the Financial
Institutions Party Hereto, as Banks, ABN Amro
Bank N.A., as Syndication Agent, Bank of Montreal, as
Co-Syndication Agent, US Bank, National Association,
as Documentation Agent and Bank of Nova Scotia,
as Co-Documentation Agent.
Exhibit 10.2 $35 million Term Credit Agreement dated as of
September 25, 2002 among Black Hills Corporation
(Borrower), The Financial Institutions Party Hereto
(Banks), and Credit Lyonnais New York Branch
(Administrative Agent).
Exhibit 10.3 The First Supplemental Indenture, dated as of
August 13, 2002, between Black Hills
Power, Inc. and JPMorgan Chase Bank, as Trustee.
Exhibit 10.4 First Amendment to 3-year Credit Agreement.
Exhibit 10.5 Second Amendment to 3-year Credit Agreement.
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.
52