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