United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q
X QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 2001.
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________.
Commission File Number 333-52664
Black Hills Corporation
Incorporated in South Dakota IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
Registrant's telephone number (605)-721-1700
Former name, former address, and former fiscal year if changed since last report
NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
---------- ----------
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the last practicable date.
Class Outstanding at July 31, 2001
Common stock, $1.00 par value 26,398,986 shares
1
BLACK HILLS CORPORATION
I N D E X
Page
Number
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Income- 3
Three, Six and Twelve Months
Ended June 30, 2001 and 2000
Consolidated Balance Sheets- 4
June 30, 2001, December 31, 2000
and June 30, 2000
Consolidated Statements of Cash Flows- 5
Three, Six and Twelve Months
Ended June 30, 2001 and 2000
Notes to Consolidated Financial Statements 6-16
Item 2. Management's Discussion and Analysis of 17-24
Financial Position and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about 25
Market Risk
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 26
Item 2. Changes in Securities and Use of Proceeds 26
Item 4. Submission of Matters to a Vote of Security Holders 26-27
Item 6. Exhibits and Reports on Form 8-K 27
Signatures 28
2
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
Three Months Six Months Twelve Months
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands, except per share amounts)
Operating revenues $ 419,049 $ 336,978 $ 980,742 $ 584,960 $ 2,019,703 $1,022,439
--------- --------- --------- --------- ------------ ----------
Operating expenses:
Fuel and purchased power 298,581 297,431 745,089 505,046 1,610,884 860,453
Operations and maintenance 15,399 8,970 28,183 17,690 57,303 35,067
Administrative and general 23,010 5,292 46,391 9,697 80,432 22,015
Depreciation, depletion and amortization 12,644 6,890 24,524 13,486 43,870 26,723
Taxes, other than income taxes 5,410 3,195 10,981 6,884 19,000 13,936
---------- --------- --------- --------- ----------- ----------
355,044 321,778 855,168 552,803 1,811,489 958,194
---------- --------- --------- --------- ----------- ----------
Operating income 64,005 15,200 125,574 32,157 208,214 64,245
---------- ---------- --------- --------- ----------- ----------
Other income (expense):
Interest expense (9,349) (6,264) (20,278) (11,706) (39,922) (19,651)
Interest income 1,010 2,590 1,652 4,631 4,240 6,826
Other, net 2,965 226 4,386 (302) 8,487 880
---------- ---------- --------- --------- ----------- ----------
(5,374) (3,448) (14,240) (7,377) (27,195) (11,945)
---------- ---------- --------- --------- ----------- ----------
Income before minority interest
and income taxes 58,631 11,752 111,334 24,780 181,019 52,300
Minority interest (2,611) - (4,571) 65 (15,909) 1,485
Income taxes (21,167) (3,691) (39,819) (7,723 (62,441) (16,389)
---------- ---------- --------- --------- ----------- ----------
Net income 34,853 8,061 66,944 17,122 102,669 37,396
Preferred stock dividends (300) - (342) - (420) -
---------- ---------- --------- --------- ----------- ----------
Net income available for common stock $ 34,553 $ 8,061 $ 66,602 $ 17,122 $ 102,249 $ 37,396
========== ========== ========= ========= =========== ==========
Weighted average common shares outstanding:
Basic 25,502 21,394 24,245 21,385 23,550 21,458
========== ========== ========= ========= =========== ==========
Diluted 25,978 21,449 24,691 21,429 24,014 21,503
========== ========== ========= ========= =========== ==========
Earnings per share of common stock:
Basic $ 1.35 $ 0.38 $ 2.75 $ 0.80 $ 4.34 $ 1.74
========== ========== ========= ========= =========== ==========
Diluted $ 1.34 $ 0.38 $ 2.71 $ 0.80 $ 4.28 $ 1.74
========== ========== ========= ========= =========== ==========
Dividends paid per share of common stock $ 0.28 $ 0.27 $ 0.56 $ 0.54 $ 1.10 $ 1.06
========== ========== ========= ========= =========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
3
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
Unaudited Unaudited
June 30 December 31 June 30
2001 2000 2000
---- ---- ----
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 35,588 $ 24,913 $ 13,644
Securities available-for-sale 3,263 2,113 4,552
Receivables (net of allowance for doubtful accounts of $6,452,
$3,631 and $325, respectively) -
Customers 142,214 278,436 134,117
Other 10,380 21,283 88,177
Materials, supplies and fuel 20,532 16,545 11,283
Prepaid expenses 7,701 7,428 3,384
Derivatives at market value 56,185 68,292 5,158
----------- ----------- -----------
275,863 419,010 260,315
----------- ----------- -----------
Investments 73,180 63,965 18,334
----------- ----------- -----------
Property and equipment 1,304,782 1,072,129 752,342
Less accumulated depreciation and depletion (301,822) (277,848) (255,127)
----------- ----------- -----------
1,002,960 794,281 497,215
----------- ----------- -----------
Other assets:
Derivatives at market value 3,868 - -
Regulatory asset 4,134 4,134 3,944
Other, principally goodwill 44,753 38,930 11,372
----------- ----------- -----------
52,755 43,064 15,316
----------- ----------- -----------
$1,404,758 $1,320,320 $ 791,180
=========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ 14,470 $ 13,960 $ 3,029
Notes payable 72,854 211,679 156,699
Accounts payable 143,393 247,596 133,155
Accrued liabilities 48,379 49,661 24,494
Derivatives at market value 59,995 65,960 5,158
----------- ------------ ------------
339,091 588,856 322,535
----------- ------------ ------------
Long-term debt, net of current maturities 434,332 307,092 159,260
----------- ------------ ------------
Deferred credits and other liabilities:
Derivatives at market value 2,694 - -
Investment tax credits 2,289 2,530 2,776
Federal income taxes 62,193 62,679 49,006
Reclamation and regulatory liability 22,468 22,340 26,326
Other 14,591 16,516 8,068
----------- ------------ ------------
104,235 104,065 86,176
----------- ------------ ------------
Minority interest in subsidiaries 27,246 37,961 -
----------- ------------ ------------
Stockholders' equity:
Preferred stock - no par Series 2000-A; 21,500 shares authorized;
Issued and Outstanding: 4,893; 4,000 and 0 shares, respectively 5,175 4,000 -
----------- ------------ ------------
Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized;
Issued: 26,769,144; 23,302,111 and 21,751,207 shares, respectively 26,769 23,302 21,751
Additional paid-in capital 236,956 73,442 40,909
Retained earnings 244,406 191,482 167,617
Treasury stock (8,841) (9,067) (7,556)
Accumulated other comprehensive income (loss) (4,611) (813) 488
----------- ------------ ------------
494,679 278,346 223,209
----------- ------------ ------------
Total stockholders' equity 499,854 282,346 223,209
----------- ------------ ------------
$1,404,758 $1,320,320 $791,180
=========== ============ ============
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
4
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Three Months Six Months Twelve Months
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Operating activities:
Net income available for common stock $34,553 $8,061 $66,602 $17,122 $102,249 $37,396
Principal non-cash items-
Depreciation, depletion and amortization 12,644 6,890 24,524 13,486 43,870 26,723
Gain on sales of assets - - - - (3,736) -
Deferred income taxes and investment tax credits 1,511 388 (727) (219) (10,087) 1,148
Undistributed earnings of affiliates (5,219) - (7,342) - (10,172) -
Minority interest 2,611 - 4,571 - 15,909 -
Change in operating assets and liabilities-
Accounts receivable and other current assets 28,241 (34,444) 141,050 (59,585) (9,549) (50,218)
Accounts payable and other current liabilities (36,835) 29,920 (105,485) 51,206 27,381 46,962
Derivative fair value adjustment 697 - (2,738) - (5,070) -
Other, net 612 351 (2,775) 5,381 5,758 (813)
--------- --------- --------- --------- --------- --------
38,815 11,166 117,680 27,391 156,553 61,198
--------- --------- --------- --------- --------- --------
Investing activities:
Property additions (206,967) (37,941) (235,915) (53,207) (321,338) (111,285)
(Increase) decrease in investments (1,602) (8,171) (57) (32,327) 22,624 (90,943)
Payment for acquisition of net assets, net of cash (10,410) - (10,410) - (39,098) -
acquired
Proceeds from sales of assets - - - - 5,500 -
Available-for-sale securities purchased - - - - - (2,691)
Available-for-sale securities sold - 1,853 - 6,935 1,139 14,740
--------- --------- --------- --------- --------- --------
(218,979) (44,259) (246,382) (78,599) (331,173) (190,179)
--------- --------- --------- --------- --------- --------
Financing activities:
Dividends paid (7,150) (5,876) (13,429) (11,746) (25,211) (23,050)
Treasury stock (purchased) sold, net - 96 226 474 (1,285) (1,025)
Common stock issued 164,606 103 165,160 263 168,751 437
Increase (decrease) in short-term borrowings (160,404) 37,425 (138,825) 59,120 (124,097) 151,086
Long-term debt - issuance 135,014 1,075 135,689 1,075 195,689 1,075
Long-term debt - repayments (4,808) (289) (7,939) (816) (9,446) (1,330)
Subsidiary distributions to minority interests (1,168) - (1,505) - (7,837) -
--------- --------- --------- --------- -------- --------
126,090 32,534 139,377 48,370 196,564 127,193
--------- --------- -------- --------- -------- --------
Increase (decrease) in cash and cash equivalents (54,074) (559) 10,675 (2,838) 21,944 (1,788)
Cash and cash equivalents:
Beginning of period 89,662 14,203 24,913 16,482 13,644 15,432
--------- --------- -------- --------- -------- --------
End of period $ 35,588 $ 13,644 $ 35,588 $ 13,644 $ 35,588 $ 13,644
========= ========= ======== ========= ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $ 8,144 $ 5,167 $ 19,954 $ 11,450 $ 39,876 $ 19,302
Income taxes $28,900 $ 7,750 $ 34,800 $ 7,750 $ 45,568 $ 13,751
Non-cash net assets acquired through issuance of common
and preferred stock $ 2,747 $ - $ 2,747 $ - $ 36,840 $ -
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
5
BLACK HILLS CORPORATION
Notes to Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company's Annual Report and 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 2000 Annual
Report on Form 10-K filed with the Securities and Exchange Commission.
Accounting methods historically employed require certain estimates as
of interim dates. The information furnished in the accompanying
financial statements reflects all adjustments which are, in the opinion
of management, necessary for a fair presentation of the June 30, 2001,
December 31, 2000 and June 30, 2000, financial information and are of a
normal recurring nature. The results of operations for the three, six
and twelve months ended June 30, 2001, are not necessarily indicative
of the results to be expected for the full year.
(2) RECLASSIFICATIONS
Certain 2000 amounts in the financial statements have been reclassified
to conform to the 2001 presentation. These reclassifications did not
have an effect on the Company's stockholders' investment or results of
operations as previously reported.
(3) NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (SFAS 141) and No. 142, "Goodwill and Other Intangible
Assets" (SFAS 142). SFAS 141 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 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). The amortization
provisions of SFAS 142 apply to goodwill and intangible assets acquired
after June 30, 2001. With respect to goodwill and intangible assets
acquired prior to July 1, 2001, the Company is required to adopt SFAS
142 effective January 1, 2002. Management is currently evaluating the
effect that adoption of the provisions of SFAS 142 that are effective
January 1, 2002 will have on the Company's consolidated financial
statements.
6
(4) CHANGE IN ACCOUNTING PRINCIPLE
In June 1998, the FASB issued SFAS No. 133 (SFAS 133), "Accounting for
Derivative Instruments and Hedging Activities." SFAS 133, as amended,
establishes accounting and reporting standards requiring that every
derivative instrument be recorded in the balance sheet as either an
asset or liability measured at its fair value. SFAS 133 requires that
changes in the derivative instrument's fair value be recognized
currently in earnings unless specific hedge accounting criteria are
met.
SFAS 133 allows special hedge accounting for fair value and cash flow
hedges. SFAS 133 provides that the gain or loss on a derivative
instrument designated and qualifying as a fair value hedging instrument
as well as the offsetting loss or gain on the hedged item attributable
to the hedged risk be recognized currently in earnings in the same
accounting period. SFAS 133 provides that the effective portion of the
gain or loss on a derivative instrument designated and qualifying as a
cash flow hedging instrument be reported as a component of other
comprehensive income and be reclassified into earnings in the same
period or periods during which the hedged forecasted transaction
affects earnings. The remaining gain or loss on the derivative
instrument, if any, must be recognized currently in earnings.
SFAS 133 requires that on date of initial adoption, an entity shall
recognize all freestanding derivative instruments in the balance sheet
as either assets or liabilities and measure them at fair value. The
difference between a derivative's previous carrying amount and its fair
value shall be reported as a transition adjustment. The transition
adjustment resulting from adopting this Statement shall be reported in
net income or other comprehensive income, as appropriate, as the effect
of a change in accounting principle in accordance with paragraph 20 of
Accounting Principles Board Opinion No. 20 (APB 20), "Accounting
Changes."
On January 1, 2001, the Company adopted SFAS 133. The Company had
certain non-trading energy contracts and interest rate swaps documented
as cash flow hedges, which upon adoption resulted in a decrease to
accumulated other comprehensive income of $10.1 million.
Upon adoption of SFAS 133, most of the Company's energy trading
activities previously accounted for under Emerging Issues Task Force
Issue No. 98-10, "Accounting for Energy Trading and Risk Management
Activities" (EITF 98-10) fell under the purview of SFAS 133. The effect
from this adoption on the energy trading companies and energy trading
activities was not material because, unless otherwise noted, the
trading companies do not designate their energy trading activities as
hedge instruments. This "no hedge" designation results in these
derivatives being measured at fair value and gains and losses
recognized currently in earnings. This treatment under SFAS 133 is
comparable to the accounting under EITF 98-10.
(5) CHANGES IN LONG-TERM DEBT AND NOTES PAYABLE
In conjunction with the closing of the Fountain Valley acquisition
(Note 11) the Company issued long-term non-recourse project level
financing. The debt matures July 1, 2006, has a floating interest rate
(5.13 percent at June 30, 2001), and is collateralized by a mortgage on
the project's land and facilities, leases and rights, including rights
to receive payments under long-term purchase power contracts. In
addition, during the second quarter of 2001 the Company used net
proceeds from its common stock offering (Note 10) to pay down
7
approximately $163 million of its borrowings under short-term credit
facilities.
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 2000 Annual Report on Form 10-K.
(6) COMPREHENSIVE INCOME
The following table presents the components of the Company's
comprehensive income:
Three Months Six Months Twelve Months Ended
Ended Ended June 30
June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Net income available for common stock $34,553 $8,061 $66,602 $17,122 $102,249 $37,396
Other comprehensive income:
Unrealized gain (loss) on available-
for-sale securities 127 488 1,151 488 (150) 488
Initial impact of adoption of SFAS
133, net of minority interest - - (7,518) - (7,518) -
Fair value adjustment on derivatives
designated as cash flow hedges net of
minority interest 5,005 - 2,569 - 2,569 -
------- ------ ------- ------- ------- -------
Comprehensive income $39,685 $8,549 $62,804 $17,610 $97,150 $37,884
======= ====== ======= ======= ======= =======
(7) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS
The Company's reportable segments are those that are based on the
Company's method of internal reporting, which generally segregates the
strategic business groups due to differences in products, services and
regulation. As of June 30, 2001, substantially all of the Company's
operations and assets are located within the United States. The
Company's operations are conducted through six business segments that
include: Electric group and segment, which supplies electric utility
service to western South Dakota, northeastern Wyoming and southeastern
Montana; Independent Energy group consisting of the following segments:
Mining, which engages in the mining and sale of coal from its mine near
Gillette, Wyoming; Oil and Gas, which produces, explores and operates
oil and gas interests located in the Rocky Mountain region, Texas,
California and other states; Fuel Marketing, which markets natural gas,
oil, coal and related services to customers in the East Coast, Midwest,
Southwest, Rocky Mountain, West Coast and Northwest regions markets;
Independent Power, which produces and sells power to wholesale
customers; and Communications group and Others, which primarily markets
communications and software development services.
Segment information follows the same accounting policies as described
in Note 1 of the Company's 2000 Annual Report on Form 10-K. In
accordance with the provisions of SFAS No. 71, intercompany coal sales
are not eliminated. Segment information included
8
in the accompanying Consolidated Balance Sheets and Consolidated
Statements of Income is as follows (in thousands):
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
Quarter to Date
June 30, 2001
Electric $ 61,280 $ 321 $16,626
Mining 5,237 2,644 2,211
Oil and gas 8,251 1,024 2,963
Fuel marketing 312,080 9,403 11,793
Independent power 24,975 - 3,687
Communications and others 4,582 1,117 (2,427)
Intersegment eliminations - (11,865) -
-------- -------- -------
Total $416,405 $ 2,644 $34,853
======== ======== =======
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
Quarter to Date
June 30, 2000
Electric $ 35,899 $ - $7,094
Mining 3,480 2,338 1,441
Oil and gas 4,272 - 1,226
Fuel marketing 289,461 - 593
Independent power 158 - 98
Communications and others 1,370 952 (2,391)
Intersegment eliminations - (952) -
-------- --------- ------
Total $334,640 $ 2,338 $8,061
======== ========= ======
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
Year to Date
June 30, 2001
Electric $ 131,858 $ 322 $33,964
Mining 10,658 5,486 4,275
Oil and gas 16,833 1,024 5,919
Fuel marketing 764,379 12,994 27,353
Independent power 43,020 - 2,582
Communications and others 8,508 2,217 (7,149)
Intersegment eliminations - (16,557) -
--------- -------- --------
Total $ 975,256 $ 5,486 $ 66,944
========= ======== ========
9
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
Year to Date
June 30, 2000
Electric $ 69,198 $ - $14,292
Mining 9,060 4,853 3,804
Oil and gas 8,234 - 2,116
Fuel marketing 491,514 - 1,161
Independent power 242 - 130
Communications and others 1,859 1,858 (4,381)
Intersegment eliminations - (1,858) -
-------- -------- -------
Total $580,107 $4,853 $17,122
======== ======== =======
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
12 Months Ended
June 30, 2001
Electric $ 235,915 $ 376 $ 56,776
Mining 22,478 10,283 7,174
Oil and gas 27,782 2,169 8,783
Fuel marketing 1,626,660 26,170 40,211
Independent power 82,193 329 5,694
Communications and others 14,392 3,987 (15,969)
Intersegment eliminations - (33,031) -
---------- -------- ---------
Total $2,009,420 $10,283 $102,669
========== ======== =========
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
12 Months Ended
June 30, 2000
Electric $ 138,615 $ - $29,782
Mining 22,452 7,800 8,291
Oil and gas 15,242 - 3,776
Fuel marketing 835,951 - 1,225
Independent power 242 - 87
Communications and others 2,137 3,623 (5,765)
Intersegment eliminations - (3,623) -
---------- -------- --------
Total $1,014,639 $ 7,800 $37,396
========== ======== ========
10
Other than the following transactions the Company had no other material
changes in total assets of its reporting segments, as reported in Note
13 of the Company's 2000 Annual Report on Form 10-K, beyond changes
resulting from normal operating activities.
o During the first quarter of 2001, as part of the Company's
reorganization plan associated with the new "holding company"
structure effected in the fourth quarter of 2000, the Company
transferred ownership interest in Wyodak Resources Development
Corp. between its wholly-owned subsidiaries Black Hills Power and
Black Hills Energy Ventures. This transaction had the effect of
reducing the "Electric" reporting segment's total assets by
approximately $89.6 million. Black Hills Energy Ventures is an
"intermediate level" holding company and is not included in a
reporting segment.
o The Independent Power segment had additions to its power
generation assets of approximately $200 million, primarily
related to the acquisition and construction of the Fountain
Valley facility, expansion of the Valmont and Arapahoe facilities
and construction of the Wyoming combustion turbine.
o The Oil and Gas segment had additions to its oil and gas
properties of approximately $16 million of which $10 million was
related to its acquisition of Stewart Petroleum.
o The Communications segment had additions to its communications
plant of approximately $12 million related to its continued
network build-out.
(8) LEGAL PROCEEDINGS
On April 3, 2001, we reached a settlement of ongoing litigation with
PacifiCorp filed in the United States District Court, District of
Wyoming, (File No. 00CV-155B). The litigation concerned the parties'
rights and obligations under the Further Restated and Amended Coal
Supply Agreement dated May 5, 1987, under which PacifiCorp purchased
coal from our coal mine to meet the coal requirements of the Wyodak
Power Plant. The Settlement Agreement provided for the dismissal of the
litigation, with prejudice, coupled with the execution of several new
coal-related agreements between the parties discussed below. We believe
the value of the Settlement Agreements is equal to the net present
value of the litigated Further Restated and Amended Coal Supply
Agreement.
New Restated and Amended Coal Supply Agreement: Effective January 1,
2001, the parties agreed to terminate the Further Restated and Amended
Coal Supply Agreement, and replace it with the New Restated and Amended
Coal Supply Agreement (New Agreement). The New Agreement begins on
January 1, 2001, and extends to December 31, 2022. Under the New
Agreement, we received an extension of sales beyond the June 8, 2013
term of the former Coal Supply Agreement. PacifiCorp will receive a
price reduction for each ton of coal purchased. The minimum purchase
obligation under the New Agreement increased to 1,500,000 tons of coal
for each calendar year of the contract term, subject to adjustment for
planned outages. The New Agreement further provides for a special
one-time payment by PacifiCorp in the amount of $7,374,000, to be paid
on or before September 1, 2001. This payment is being recognized as
revenue over the life of the New Agreement.
11
Coal Option Agreement: The term of this agreement begins no later than
October 1, 2001, and extends until December 31, 2010. The agreement
provides that PacifiCorp shall purchase 1,400,000 tons of coal during
the period of October 1, 2001 through December 31, 2002, and 1,000,000
tons of coal in 2003 at a fixed price. The agreement further provides
us with a "put" option for 2002 and 2003 under which we may put to
PacifiCorp up to 500,000 tons of coal from the Wyodak Mine at a market
based price. For each calendar year from January 1, 2004 through 2010,
the put option is increased to a maximum of 1,000,000 tons at a market
based price. The "put" tonnages will be reduced or offset for
quantities of K-Fuel purchased by PacifiCorp under the KFx Facility
Output Agreement. Additionally, for each calendar year during which we
are selling to PacifiCorp K-Fuel under the KFx Facility Output
Agreement described below, and in which we have not exercised our "put"
option, PacifiCorp may elect to purchase an equal amount of tonnage
from our coal reserves to use in a 50/50 blend with the K-Fuel, up to
500,000 tons per year in 2002 through 2007 at a market based price with
a fixed floor.
Asset Option Agreement: This agreement provides PacifiCorp an option to
purchase a 10% interest in the KFx facility or the legal entity that
owns the KFx facility at a market based price. Additionally, the
agreement provides to PacifiCorp an option to sell us PacifiCorp's
interest in the "In Pit" conveyor system currently owned by PacifiCorp
and utilized at the Wyodak Mine at a fixed price. If PacifiCorp
exercises its option to sell us the In Pit system, we have a
corresponding right to put to PacifiCorp the "North Conveyor System,"
which serves as the backup coal delivery system for the Wyodak Power
Plant at a fixed price.
KFx Facility Output Agreement: The KFx plant is a coal enhancement
facility we own located near our Wyodak Coal Mine. The KFx plant was
built to produce an enhanced coal known as "K-Fuel." Assuming the plant
becomes operational, PacifiCorp agrees to purchase K-Fuel for a term
beginning January 1, 2002, and extending to December 31, 2007. If the
plant is not operational on or before December 31, 2003, the agreement
will become void. Under this agreement, PacifiCorp agrees to purchase
the output of K-Fuel from the KFx plant, up to a maximum of 500,000
tons for each calendar year from 2002 through 2007 at fixed price with
market based escalation. Wyodak reserves the right to sell up to a
total of 100,000 tons from the output of the KFx plant to other
customers during the same time period.
(9) PRICE RISK MANAGEMENT
The Company is exposed to market risk stemming from changes in
commodity prices. These changes could cause fluctuations in the
Company's earnings and cash flows. In the normal course of business,
the Company actively manages its exposure to these market risks by
entering into various hedging transactions, which are authorized under
its Risk Management Policies and Procedures that place clear controls
on these activities. Hedging transactions involve the use of a variety
of derivative financial instruments.
The Company accounts for all energy trading activities at fair value as
of the balance sheet date and recognizes currently the net gains or
losses resulting from the revaluation of these contracts to fair value
in its results of operations. As a result, substantially all of the
energy trading activities of the Company's gas marketing, crude oil
marketing, and coal marketing operations are accounted for under fair
value accounting methodology as prescribed in SFAS 133 or EITF 98-10.
12
Energy Trading Activities
The Company, through its independent energy business group, utilizes
financial instruments for its fuel marketing services. These financial
instruments include fixed-for-float swap financial instruments, basis
swap financial instruments and costless collars traded in the
over-the-counter financial markets.
These derivatives are not held for speculative purposes but rather
serve to hedge the Company's exposure related to commodity purchases or
sales commitments. Under SFAS 133 and EITF 98-10, these transactions
qualify as derivatives or energy trading activities that must be
accounted for at fair value. As such, realized and unrealized gains and
losses are recorded as a component of income. Because the Company does
not, as a policy, permit speculation with "open" positions,
substantially all of its trading activities are back-to-back positions
where a commitment to buy/(sell) a commodity is matched with a
committed sale/(buy) or financial instrument. The quantities and
maximum terms of derivative financial instruments held for trading
purposes at June 30, 2001, December 31, 2000 and June 30, 2000 are as
follows:
Max. Term
June 30, 2001 Volume Covered (Years)
------------- -------------- -------
(MMBtus)
Natural gas basis swaps purchased 29,064,178 2
Natural gas basis swaps sold 29,283,500 2
Natural gas fixed-for-float swaps purchased 15,469,668 1
Natural gas fixed-for-float swaps sold 11,728,279 1
Natural gas swing swaps purchased 1,044,576 1
Natural gas swing swaps sold 12,623,950 1
(Tons)
Coal tons sold 961,046 1
Coal tons purchased 1,074,046 1
Max. Term
June 30, 2000 Volume Covered (Years)
------------- -------------- -------
(MMBtus)
Natural gas basis swaps purchased 26,692,328 3
Natural gas basis swaps sold 23,072,000 3
Natural gas fixed-for-float swaps purchased 8,390,437 1
Natural gas fixed-for-float swaps sold 10,312,447 1
Max. Term
December 31, 2000 Volume Covered (Years)
----------------- -------------- -------
(MMBtus)
Natural gas basis swaps purchased 25,577,894 2
Natural gas basis swaps sold 26,059,621 2
Natural gas fixed-for-float swaps purchased 6,476,222 1
Natural gas fixed-for-float swaps sold 7,360,560 1
(Tons)
Coal tons sold 988,000 1
Coal tons purchased 896,000 1
13
As required under SFAS 133 and EITF 98-10, derivatives and energy
trading activities were marked to fair value on June 30, 2001, and the
gains and losses recognized in earnings. The amounts related to the
accompanying consolidated balance sheet and income statement as of and
for the three, six and twelve month periods ended June 30, 2001 are as
follows (in thousands):
Three Month Six Month Twelve Month
Instrument Asset Liability Gain (Loss) Gain (Loss) Gain (Loss)
- ---------- ----- --------- ------------ ----------- -----------
Natural gas basis swaps $ 7,708 $11,272 $1,773 $7,029 $(1,439)
Natural gas
fixed-for-float swaps 16,424 22,765 (5,210) (3,869) (4,177)
Natural gas physical 20,104 4,944 3,532 1,197 9,882
Coal transactions 7,363 5,507 314 945 1,855
Crude oil transactions 7,153 6,475 23 155 678
-------- -------- ------- ------ -------
Totals $ 58,752 $ 50,963 $ 432 $5,457 $ 6,799
======== ======== ======= ====== =======
There were no significant differences between the fair values of
derivative assets and liabilities at June 30, 2000.
Non-trading Energy Activities
To reduce risk from fluctuations in the price of oil and natural gas,
the Company enters into swaps and costless collar transactions. The
transactions are used to hedge price risk from sales of the Company's
forecasted crude oil and natural gas production. For such transactions,
the Company utilizes hedge accounting as allowed under SFAS 133.
At June 30, 2001, the Company had fixed-for-float swaps and costless
collars to hedge portions of its crude oil and natural gas production.
These transactions were identified as cash flow hedges, properly
documented, and effectiveness testing established. At quarter-end, the
hedges met the effectiveness testing criteria and retained their cash
flow hedge status. The crude oil hedges recorded ineffectiveness due to
basis risk and time value. The effective portion of the gain or loss on
these derivatives is reported in other comprehensive income and the
ineffective portion is reported in earnings.
At June 30, 2001, the Company had fixed-for-float swaps for 17,000
barrels of crude oil per month through December of 2001 with a net fair
value of $0.1 million and 10,000 barrels of crude oil per month for
January through September of 2002 with a net fair value of $0.1
million. The Company had costless collars (purchased put - sold call)
for 10,000 barrels of crude oil per month for 2001 with a net fair
value of $0.1 million. In addition, the Company hedged a portion of its
forecasted 2001 natural gas production with fixed-for-float swaps. At
June 30, 2001 these natural gas swaps were for 676,000 MMBtus with a
net fair value of $0.9 million.
14
The effective portion of the gains and losses on these derivatives was
recorded in other comprehensive income. At June 30, 2001, accumulated
other comprehensive income for all non-trading energy swaps and options
was approximately $1.2 million.
Derivative fair value gains and losses are recorded in other
comprehensive income for the effective portion of the hedge and in
earnings for the ineffective portion. The ineffective portion includes
both time value and basis risk. The net gain recognized in earnings
prior to actual cash settlement is $0.1 million.
Financing Activities
To reduce risk from fluctuations in interest rates, the Company enters
into interest rate swap transactions. These transactions are used to
hedge interest rate risk for variable rate debt financing. For such
transactions, the Company utilizes hedge accounting per the
requirements of SFAS 133. These transactions were identified as cash
flow hedges, properly documented, and effectiveness testing
established. At quarter-end, these hedges met effectiveness testing
criteria and retained their cash flow hedge status. At June 30, 2001,
the Company had interest rate swaps with an average balance notional
amount of $162.7 million, having a maximum term of six years and a fair
value of $(9.1) million. Because these hedges are fully effective (no
time value or basis risk), the entire derivative fair value is recorded
in accumulated other comprehensive income.
At June 30, 2001, the Company had $363.2 million of outstanding,
floating-rate debt of which $187.0 million was not offset with interest
rate swap transactions that effectively convert the debt to a fixed
rate.
Credit Risk
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's risk management activities. Credit risk
relates to the risk of loss resulting from non-performance of
contractual obligations by a counterparty. While the Company has not
experienced significant losses due to the credit risk associated with
these arrangements, the Company has off-balance sheet risk to the
extent that the counterparties to these transactions may fail to
perform as required by the terms of each such contract.
(10) COMMON STOCK OFFERING
During the first quarter of 2001, the Company announced the public
offering of 3 million shares of common stock with an option for the
underwriters to purchase 450,000 additional shares. Credit Suisse First
Boston, Lehman Brothers, CIBC World Markets and UBS Warburg acted as
the managers of the underwriting syndicate.
Early in the second quarter of 2001 the Company announced the offering
price was set at $52 per share and all 3 million shares were sold with
the underwriters exercising their over-allotment option to purchase an
additional 383,000 shares. Net proceeds were approximately $163 million
after commissions and expenses. The proceeds were used to repay a
portion of current indebtedness under revolving credit facilities.
15
(11) ACQUISITIONS
Early in the second quarter of 2001, the Company's independent power
subsidiary, Black Hills Energy Capital, closed on the purchase of the
Fountain Valley facility, a 240 megawatt generation facility located
near Colorado Springs, Colorado, featuring six LM-6000 simple-cycle,
gas-fired turbines. The facility is currently under construction and is
expected to come on-line early in the third quarter of 2001. The
facility was purchased from Enron Corporation. Total cost of the
project is expected to be $183 million and has been financed primarily
with non-recourse financing from Union Bank of California. The Company
has obtained an 11-year contract with Public Service of Colorado to
utilize the facility for peaking purposes. The contract is a tolling
arrangement in which the Company assumes no fuel risk.
(12) SUBSEQUENT EVENT
Early in the third quarter of 2001, Black Hills Energy Capital
announced it had signed a definitive agreement to purchase a 273 MW
gas-fired power generation complex located in North Las Vegas, Nevada
from Enron North America, a wholly-owned subsidiary of Enron
Corporation. The transaction is expected to close during the third
quarter 2001.
Expansion of the present 51 MW co-generation site near Las Vegas is now
under way. Construction of a new combined cycle generation facility
adjacent to the existing plant will add approximately 222 MW of
capacity to the existing plant site. The Company anticipates total
acquisition and construction costs for the 273 MW complex to be
approximately $330 million. The new generation is expected to phase in
operations in the third quarter of 2002. The facility will feature
LM-6000 gas-fired turbine technology comparable to the Company
facilities in Colorado and Wyoming. The Company has initiated
discussions with several banks and expects to finance the project
primarily with non-recourse debt.
As part of the transaction, the Company also has secured long-term
contracts for the output of the facility. Nearly all of the capacity
and energy produced by the existing 51 MW plant is under contract
through 2024 with the remainder being merchant power. The power of the
planned 222 MW combined-cycle plant is sold under a 15-year contract.
The contract requires the purchaser to provide fuel to the power plant
when the plant is dispatched.
16
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 regulated and unregulated businesses have
expanded significantly in recent years. Our independent energy group produces
and markets power and fuel. We produce and sell electricity in a number of
markets, with a strong emphasis in the western United States. We also produce
coal, natural gas and crude oil primarily in the Rocky Mountain region and
market fuel products nationwide. We also own Black Hills Power, Inc., an
electric utility serving approximately 58,600 customers in South Dakota, Wyoming
and Montana. Our communications group offers state-of-the-art broadband
communications services to residential and business customers in Rapid City and
the northern Black Hills region of South Dakota.
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 2000 Annual Report on Form 10-K filed with the
Securities and Exchange Commission. Our business and industry outlooks as
disclosed in that filing continue to be consistent with management's current
expectations and assessments.
Results of Operations
Consolidated Results
Consolidated earnings for the three month period ended June 30, 2001 were $34.6
million or $1.34 per share compared to $8.1 million or $0.38 per share in the
same period of the prior year. Consolidated earnings for the six month periods
ended June 30, 2001 and 2000 were $66.6 or $2.71 per share and $17.1 million, or
$0.80 per share respectively, and consolidated earnings for the twelve month
period ended June 30, 2001 were $102.2 million or $4.28 per share compared to
$37.4 or $1.74 per share for the same period of the prior year.
Increases in earnings for the three, six and twelve month periods ended June 30,
2001 were primarily driven by continued strong performance in our wholesale
natural gas marketing business and increased off-system wholesale electricity
sales. Strong results in our independent energy business group and electric
utility business group were partially offset by losses in our communications
group.
Unusual energy market conditions stemming primarily from gas and electricity
shortages in the West contributed to the strong financial performance in the
second quarter of 2001. The Company estimated that more than half of the
reported $1.34 earnings per share for the three months ended June 30, 2001 could
be attributed to high prices of natural gas and electricity and high gas trading
margins during April and May. Energy prices decreased substantially beginning in
June 2001.
Consolidated revenues for the three, six and twelve month periods ended June 30,
2001 were $419.0 million, $980.7 million and $2.0 billion, respectively.
Revenues for the same periods ended June 30, 2000 were $337.0 million, $585.0
million and $1.0 billion, respectively.
The growth in revenues was a result of high energy commodity prices through May
2001 and increased volumes of fuel marketed, primarily as a result of extreme
price volatility in the western markets, acquisitions and growth in the
independent energy business group and increases in off-system sales by our
electric utility.
17
Consolidated operating expenses have increased significantly during the three,
six and twelve month periods ended June 30, 2001, primarily due to operating
costs of acquired and expanded businesses, increased employee costs for growing
operations and higher commissions related to performance levels in our fuel
marketing and wholesale energy businesses. In addition, for the six and twelve
month periods there were significant increases in fuel costs associated with
operation of our combustion turbines and purchased power costs related to excess
capacity being sold to western markets.
Revenue and net income (loss) provided by each business group as a percentage of
our total revenue and net income were as follows:
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Revenues
Independent energy 84% 89% 86% 88% 87% 86%
Electric utility 15 11 13 12 12 14
Communications 1 - 1 - 1 -
--- --- --- --- --- ---
100% 100% 100% 100% 100% 100%
=== === === === === ===
Net Income/(Loss)
Independent energy 59% 42% 60% 42% 60% 36%
Electric utility 48 88 51 83 55 80
Communications and other (7) (30) (11) (25) (15) (16)
--- --- --- --- --- ---
100% 100% 100% 100% 100% 100%
=== === === === === ===
We expect that earnings growth from the independent energy group over the next
few years will be driven primarily by our continued expansion in the independent
power production segment. We also believe that strength in commodity prices and
increased volumes produced and marketed will provide the opportunity for strong
results in our fuel marketing and oil and gas production operations.
Our electric utility has continued to produce modest growth in revenue and
earnings from the retail business over the past two years. We believe that this
trend is stable and that, absent unplanned system outages, it will continue for
the next several years due to the extension of our electric utility's rate
freeze until January 1, 2005. The share of the utility's future earnings
generated from wholesale off-system sales will depend on many factors, including
native load growth, plant availability and commodity prices in available
markets.
Although our communications business continues to significantly increase
residential and business customers, losses are expected to continue as the group
proceeds with completing the network and increasing the customer base. Net
income is expected to be achieved by 2004. We have increased our previously
disclosed estimate of net losses in 2001 to $12 million due to an increase in
certain reserves for inventory and carrier billings.
18
The following business group and segment information does not include
intercompany eliminations:
Independent Energy Group
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $363,614 $299,709 $854,394 $513,903 $1,798,064 $881,687
Expenses 326,122 294,966 778,922 503,475 1,672,126 864,431
-------- -------- -------- -------- ---------- --------
Operating income $ 37,492 $ 4,743 $ 75,472 $ 10,428 $ 125,938 $ 17,256
Net income $ 20,654 $ 3,358 $ 40,129 $ 7,211 $ 61,862 $ 13,379
EBITDA $ 44,122 $ 6,227 $ 86,570 $ 13,283 $ 138,046 $ 26,558
EBITDA represents earnings before interest, income taxes, depreciation and
amortization. EBITDA is used by management and some investors as an indicator of
a company's historical ability to service debt. Management believes that an
increase in EBITDA is an indicator of improved ability to service existing debt,
to sustain potential future increases in debt and to satisfy capital
requirements. However, EBITDA is not intended to represent cash flows for the
period, nor has it been presented as an alternative to either operating income,
or as an indicator of operating performance or cash flows from operating,
investing and financing activities, as determined by accounting principles
generally accepted in the United States. EBITDA as presented may not be
comparable to other similarly titled measures of other companies.
The following table provides a summary of certain operating statistics of our
independent energy group:
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Fuel production:
Tons of coal sold 775,000 585,400 1,592,800 1,378,700 3,264,400 3,011,500
Mcf equivalent sales 1,677,400 1,186,900 3,275,900 2,378,000 6,175,600 4,717,500
Average price per
barrel of oil sold
(including hedge
transactions) $25.26 $20.95 $24.67 $20.71 $23.66 $18.39
Average price per Mcf
of natural gas sold
(including hedge
transactions) $5.09 $2.35 $5.24 $2.26 $4.31 $2.20
Fuel marketing
average daily volumes:
Natural gas - MMBtus 912,700 822,300 889,600 726,300 942,200 610,000
Crude oil - barrels 38,400 47,000 37,900 45,400 40,800 32,300
Coal - tons 6,300 4,200 6,200 4,400 5,300 4,500
19
The independent energy business group's revenues increased 21 percent, 66
percent and 104 percent for the three, six and twelve month periods,
respectively. Earnings from the Independent Energy business group increased from
2000 amounts by $17.3 million, or $0.67 per share, and $32.9 million, or $1.33
per share, and $48.5 million, or $2.02 per share for the three, six and twelve
month periods ended June 30, 2001, respectively. The revenue and earnings
increase for the periods were a direct result of increased volumes, increased
fuel and power prices related to gas and electricity shortages in the West Coast
markets, and the closing of various acquisitions. In addition, the increase in
the twelve-month period was aided by the sale of our ownership interest in a
power fund management company which resulted in a $3.7 million pre-tax gain.
Daily volumes of natural gas marketed increased 11 percent, 22 percent and 54
percent for the three, six and twelve month periods, respectively.
Coal Mining Segment
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $7,881 $5,818 $16,144 $13,913 $32,761 $30,252
Operating income $2,160 $1,890 $ 4,834 $ 5,204 $ 8,424 $11,557
Net income $2,211 $1,441 $ 4,275 $ 3,804 $ 7,174 $ 8,291
EBITDA $3,183 $2,474 $ 6,513 $ 6,275 $11,101 $12,995
A planned five-week overhaul of the Wyodak plant during the second quarter of
2000 resulted in lower coal earnings for the prior three and six month periods
compared to the current year.
Oil and Gas Segment
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $9,275 $4,272 $17,857 $8,234 $29,951 $15,242
Operating income $4,496 $1,723 $ 8,893 $3,052 $13,747 $ 5,717
Net income $2,963 $1,226 $ 5,919 $2,116 $ 8,783 $ 3,776
EBITDA $6,478 $2,423 $12,605 $4,520 $20,079 $ 8,411
Revenue and earnings of the oil and gas production business segment increased
for the three, six and twelve month periods due to increases in gas volumes sold
of 48 percent, 44 percent and 41 percent, respectively, while average gas prices
realized after hedged transactions were 117 percent, 132 percent and 96 percent
higher than the same periods in the prior year, respectively. Barrels of oil
sold increased 33 percent, 29 percent and 17 percent for the three, six and
twelve month periods while average prices realized after hedged transactions
were 21 percent, 19 percent and 29 percent higher than the same periods in the
prior year, respectively.
The following is a summary of our estimated oil and gas reserves at June 30
determined using constant product prices at the end of the respective period.
Estimates of economically recoverable reserves are based on a number of
variables, which may differ from actual results.
20
2001 2000
---- ----
Barrels of oil (in millions) 4.5 4.3
Bcf of natural gas 25.6 17.9
Total in Bcf equivalents 52.6 43.7
During the first quarter we announced the acquisition of operating and
non-operating interests in 74 gas and oil wells from Stewart Petroleum for
approximately $10 million. The acquisition was closed early in the second
quarter of 2001 and increased our proved reserves by approximately 10 billion
cubic feet equivalent of which approximately 86 percent are natural gas.
Fuel Marketing Segment
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $321,483 $289,461 $777,373 $491,514 $1,652,830 $835,951
Operating income $ 18,812 $ 995 $ 44,180 $ 1,983 $ 65,932 $ (142)
Net income $ 11,793 $ 593 $ 27,353 $ 1,161 $ 40,211 $ 1,225
EBITDA $ 19,285 $ 1,323 $ 45,108 $ 2,512 $ 66,869 $ 5,240
Revenues and earnings increased primarily due to a significant increase in
natural gas volumes marketed during the current three, six and twelve month
periods while margins received also increased substantially.
The significant increases can, in part, be attributed to the unusual market
conditions in the western markets, which primarily stem from the natural gas and
electricity shortages in California and may not recur in the future. However, we
believe that the continued growth in demand for natural gas will create
opportunities for us to continue to generate strong fuel marketing operating
results in the future.
Independent Power Production Segment
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $24,975 $ 158 $43,020 $ 242 $82,522 $ 242
Operating income $12,024 $ 135 $17,565 $ 189 $37,835 $ 124
Net income $ 3,687 $ 98 $ 2,582 $ 130 $ 5,694 $ 87
EBITDA $15,176 $ 7 $22,344 $ (24) $39,997 $ (88)
Current periods results stem from our acquisition of Indeck Capital in the third
quarter of 2000.
Early in the second quarter of 2001, we closed on the purchase of the Fountain
Valley facility, a 240 megawatt generation facility located near Colorado
Springs, Colorado, featuring six LM-6000 simple-cycle, gas-fired turbines. The
facility is currently under construction and is expected to come on-line early
in the third quarter of 2001. In addition, we obtained an 11-year
21
contract with Public Service of Colorado to utilize the facility for peaking
purposes. The contract is a tolling arrangement in which the Company assumes no
fuel risk.
Electric Utility Group
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $61,601 $35,899 $132,180 $69,198 $236,291 $138,615
Expenses 32,291 22,919 74,206 42,573 136,733 83,435
------- ------- -------- -------- -------- --------
Operating income $29,310 $12,980 $ 57,974 $26,625 $ 99,558 $ 55,180
Net income $16,626 $ 7,094 $ 33,964 $14,292 $ 56,776 $ 29,782
EBITDA $33,179 $16,924 $ 66,346 $34,401 $115,238 $ 70,638
Electric utility revenues increased 72 percent, 91 percent and 70 percent for
the three, six and twelve month periods ended June 30, 2001, respectively,
compared to the same periods in the prior year. Earnings from the electric
utility increased $9.5 million, or $0.37 per share, $19.7 million, or $0.80 per
share, and $27.0 million, or $1.13 per share for the three, six and twelve month
periods ended June 30, 2001, respectively. Increased earnings continued to be
driven by off-system sales in the wholesale markets; average prices were
approximately double the three-month average price received and more than triple
the six and twelve month average price received compared to the same periods of
the prior year. However, in June 2001, wholesale electricity prices decreased in
response to changes in western energy market conditions. Off-system megawatt
hours sold increased 138 percent for the three months, 141 percent for the six
months and 111 percent for the twelve months ended June 30, 2001 compared to the
same periods in 2000, due to higher market prices and the 40 MW generating
capacity added in 2000. In addition, the electric utility had modest gains in
firm residential and commercial electric sales for all periods presented and a
reduction of reserves in the second quarter related to reduced exposure in the
stabilizing western markets. These increases were partially offset by higher
fuel and operating costs associated with operation of the gas turbines and other
power plant operations, and higher purchased power costs. The following table
provides certain operating statistics.
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Firm (system) sales - MWh 464,000 462,000 990,000 958,000 2,005,000 1,938,000
Off-system sales - MWh 293,000 123,000 550,000 228,000 1,006,000 478,000
22
Communications Group
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $ 4,637 $ 1,370 $ 8,563 $ 1,859 $ 14,392 $ 2,137
Expenses 7,437 3,577 15,134 6,228 29,082 9,246
------- -------- ------- -------- --------- --------
Operating income $(2,800) $(2,207) $(6,571) $(4,369) $(14,690) $(7,109)
Net income $(2,791) $(2,232) $(6,683) $(4,131) $(14,579) $(5,338)
EBITDA $ (337) $(1,088) $(1,773) $(2,553) $ (6,123) $(3,795)
As previously disclosed, communication losses are expected to continue as the
group proceeds with completing the network and increasing the customer base. Net
income is expected to be achieved by 2004. We have increased our previously
disclosed estimate of net losses in 2001 to $12 million due to an increase in
certain reserves for inventory and carrier billings. The following table
provides certain operating statistics:
June 30 March 31 December 31 June 30
2001 2001 2000 2000
---- ---- ---- ----
Business customers 1,440 980 650 270
Residential customers 12,000 10,060 8,370 3,960
Liquidity and Capital Resources
During the three, six and twelve month periods ended June 30, 2001, we generated
sufficient cash flow from operations to meet our operating needs, to pay
dividends on common and preferred stock, to pay long-term debt maturities and
substantially increase our cash position over June 30, 2000. We continue to fund
property and investment additions primarily related to construction of
additional electric generation facilities for our independent energy business
group through a combination of operating cash flow, increased short-term debt
and long-term non-recourse project financing. Investing and financing activities
increased primarily due to short and long-term borrowings related to project
financing.
During the first quarter of 2001, the Company announced the public offering of 3
million shares of common stock with an option for the underwriters to purchase
450,000 additional shares. Credit Suisse First Boston, Lehman Brothers, CIBC
World Markets and UBS Warburg acted as the managers of the underwriting
syndicate.
Early in the second quarter of 2001 the Company announced the offering price was
set at $52 per share and all 3 million shares were sold with the underwriters
exercising their over-allotment option to purchase an additional 383,000 shares.
Net proceeds were approximately $163 million after commissions and expenses. The
proceeds were used to repay a portion of current indebtedness under revolving
credit facilities.
Capital Requirements
Early in the third quarter 2001, we announced a definitive agreement to purchase
a gas-fired generation complex in North Las Vegas, Nevada from Enron North
America, a wholly-owned
23
subsidiary of Enron Corporation. We anticipate total acquisition and
construction costs for the 273 MW complex to be approximately $330 million. The
project is expected to be primarily financed with project-level non-recourse
debt. The capital necessary to fund this project was not included in our
forecasted capital requirements reported in our 2000 Annual Report on Form 10-K
filed with the Securities Exchange Commission.
There have been no additional material changes in our forecasted changes in
liquidity and capital requirements from those reported in Item 7 of our 2000
Annual Report on Form 10-K filed with the Securities Exchange Commission.
Forward Looking Statements
The above information includes "forward-looking statements" as defined by the
Securities and Exchange Commission. These statements concern the Company's
plans, expectations and objectives for future operations. All statements, other
than statements of historical facts, included above that address activities,
events or developments that the Company expects, believes or anticipates will or
may occur in the future are forward-looking statements. The words believe,
intend, anticipate, estimate, aim, project and similar expressions are also
intended to identify forward-looking statements. These forward-looking
statements may include, among others, such things as expansion and growth of the
Company's business and operations; future financial performance; future
acquisition and development of power plants; future production of coal, oil and
natural gas; reserve estimates; future communications customers; and business
strategy. These forward-looking statements are based on assumptions which the
Company believes are reasonable based on current expectations and projections
about future events and industry conditions and trends affecting the Company's
business. However, whether actual results and developments will conform to the
Company's expectations and predictions is subject to a number of risks and
uncertainties which could cause actual results to differ materially from those
contained in the forward-looking statements, including the following factors:
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; changes in and compliance with environmental
and safety laws and policies; weather conditions; population growth and
demographic patterns; competition for retail and wholesale customers; pricing
and transportation of commodities; market demand, including structural market
changes; changes in tax rates or policies or in rates of inflation; changes in
project costs; unanticipated changes in operating expenses or capital
expenditures; capital market conditions; counterparty credit risk; technological
advances; competition for new energy development opportunities; legal and
administrative proceedings that influence the Company's business and
profitability; and unanticipated developments in the western power markets,
including unanticipated governmental intervention, deterioration in the
financial condition of counterparties, default on amounts due, adverse changes
in current or future litigation and adverse changes in the tariffs of the
California Independent System Operator Corporation. Any such forward-looking
statements should be considered in conjunction with Black Hills Corporation's
most recent annual report on Form 10-K and its interim quarterly reports on Form
10-Q on file with the Securities and Exchange Commission. New factors that could
cause actual results to differ materially from those described in
forward-looking statements emerge from time to time, and it is not possible for
the Company to predict all such factors, or to 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. The Company assumes no obligation to
update publicly any such forward-looking statements, whether as a result of new
information, future events, or otherwise.
24
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Other than changes in price risk management activities as disclosed in Note 9 to
the Consolidated Financial Statements in this Form 10-Q, there have been no
material changes in market risk faced by the Company from those reported in the
Company's 2000 Annual Report on Form 10-K filed with the Securities Exchange
Commission. For more information on market risk, see Part II, Item 7 in the
Company's 2000 Annual Report on Form 10-K, and Notes to Consolidated Financial
Statements in this Form 10-Q.
25
BLACK HILLS CORPORATION
Part II - Other Information
Item 1. Legal Proceedings
On April 3, 2001, we reached a settlement of ongoing litigation
with PacifiCorp filed in the United States District Court,
District of Wyoming (File No. 00CV-155B). For more information on
this legal proceeding, see Note 8 - LEGAL PROCEEDINGS - of Notes
to Consolidated Financial Statements in this Form 10-Q.
Item 2. Changes In Securities and Use of Proceeds
(c) On April 20, 2001 we issued the following unregistered
securities pursuant to the 2000 earn-out consideration agreed
to in the acquisition of Indeck Capital, Inc. on July 7, 2000.
The unregistered securities were issued under Rule 506 of
Regulation D of the Securities Act of 1933.
Series 2000-A
Stockholder Common Shares Issued Preferred Stock Issued
Gerald R. Forsythe 21,786 554
John W. Salyer 4,216 107
Michelle R. Fawcett 2,284 58
Marsha Fournier 2,284 58
Monica Breslow 2,284 58
Melissa S. Forsythe 2,284 58
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
(a) The Annual Meeting of Shareholders was held on May 30, 2001.
(b) The following Directors were elected to serve until the
Annual Meeting of Shareholders in 2004.
Adil M. Ameer
Everett E. Hoyt
Thomas J. Zeller
Other Directors whose term of office continues are:
Bruce B. Brundage
David C. Ebertz
Gerald R. Forsythe
John R. Howard
Kay S. Jorgensen
Daniel P. Landguth
David S. Maney
26
(c) Matters Voted Upon at the Meeting
1. Elected three Class III Directors to serve until the
Annual Meeting of Shareholders in 2004.
Adil M. Ameer
Votes For 18,957,958
Votes Withheld 597,843
Everett E. Hoyt
Votes For 19,083,821
Votes Withheld 471,980
Thomas J. Zeller
Votes For 19,087,569
Votes Withheld 468,232
2. Approved an increase in authorized indebtedness from
$500 million to $2 billion.
Votes For 14,542,445
Votes Against 1,358,473
Abstain 312,657
Broker Non-Votes 3,292,225
3. Approved the Black Hills Corporation Omnibus Incentive
Compensation Plan.
Votes For 13,764,992
Votes Against 2,157,885
Abstain 340,699
Broker Non-Votes 3,292,225
4. Ratified the appointment of Arthur Andersen LLP to serve
as Black Hills Corporation's independent auditors in 2001.
Votes For 19,379,082
Votes Against 89,934
Abstain 86,785
Broker Non-Votes -0-
Item 6. Exhibits and Reports of Form 8-K
(a) Exhibits - None
(b) Reports on Form 8-K
We have filed the following Reports on Form 8-K since March 31
2001.
Form 8-K dated April 6, 2001.
Reported the Settlement of the PacifiCorp Litigation.
27
BLACK HILLS CORPORATION
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
BLACK HILLS CORPORATION
/s/ Roxann R. Basham
---------------------------------------------
Roxann R. Basham, Vice President - Controller
(Principal Accounting Officer)
/s/ Mark T. Thies
---------------------------------------------
Mark T. Thies, Senior VP & CFO
(Principal Financial Officer)
Dated: August 14, 2001
28