United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 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 registrant's classes of
common stock as of the latest practicable date.
Class Outstanding at October 31, 2001
Common stock, $1.00 par value 26,510,053 shares
1
BLACK HILLS CORPORATION
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Income- 3
Three, Nine and Twelve Months
Ended September 30, 2001 and 2000
Consolidated Balance Sheets- 4
September 30, 2001, December 31, 2000
and September 30, 2000
Consolidated Statements of Cash Flows- 5
Nine Months Ended September 30, 2001 and 2000
Notes to Consolidated Financial Statements 6-18
Item 2. Management's Discussion and Analysis of 19-28
Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about 28
Market Risk
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 29
Item 2. Changes in Securities and Use of Proceeds 29
Item 6. Exhibits and Reports on Form 8-K 29-30
Signatures 31
Exhibit Index 32
2
PART 1 - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
Three Months Ended Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands, except per share amounts)
Operating revenues $ 302,398 $ 453,231 $1,283,140 $1,038,191 $1,868,869 $1,255,890
--------- --------- ---------- ---------- ---------- ----------
Operating expenses:
Fuel and purchased power 224,637 373,613 969,384 878,660 1,461,566 1,055,491
Operations and maintenance 15,252 13,859 43,051 31,483 59,538 40,221
Administrative and general 13,153 10,468 60,122 20,231 82,397 27,535
Depreciation, depletion and amortization 14,261 8,978 38,785 22,465 49,208 28,092
Taxes, other than income taxes 5,656 3,794 16,637 10,678 20,860 14,442
--------- --------- ---------- ----------- ---------- ---------
272,959 410,712 1,127,979 963,517 1,673,569 1,165,781
--------- --------- ---------- ----------- ---------- ---------
Operating income 29,439 42,519 155,161 74,674 195,300 90,109
--------- --------- ---------- ----------- ---------- ---------
Other income (expense):
Interest expense (9,255) (9,608) (29,300) (19,886) (39,814) (23,917)
Interest income 725 1,681 1,810 5,685 3,179 6,851
Other, net 5,453 578 10,026 (524) 13,397 573
--------- --------- ---------- ----------- ---------- ---------
(3,077) (7,349) (17,464) (14,725) (23,238) (16,493)
--------- --------- ---------- ----------- ---------- ---------
Income before minority interest
and income taxes 26,362 35,170 137,697 59,949 172,062 73,616
Minority interest 163 (10,276) (4,408) (10,211) (5,470) (9,255)
Income taxes (10,159) (8,572) (49,978) (16,294) (64,042) (20,364)
--------- ---------- ---------- --------- --------- ---------
Net income 16,366 16,322 83,311 33,444 102,550 43,997
Preferred stock dividends (131) (37) (473) (37) (513) (37)
--------- ---------- ---------- --------- --------- ---------
Net income available for common stock $ 16,235 $ 16,285 $ 82,838 $ 33,407 $ 102,037 $ 43,960
========= ========== ========== ========= ========= =========
Weighted average common shares outstanding:
Basic 26,425 22,835 24,988 21,872 24,466 21,809
========= ========== ========== ========= ========= =========
Diluted 26,802 23,067 25,404 21,977 24,896 21,926
========= ========== ========== ========= ========= =========
Earnings per share of common stock:
Basic $ 0.61 $ 0.71 $ 3.32 $ 1.53 $ 4.17 $ 2.02
========== ========== =========== ========= ========= =========
Diluted $ 0.61 $ 0.71 $ 3.28 $ 1.52 $ 4.12 $ 2.01
========== ========== =========== ========= ========= =========
Dividends paid per share of common stock $ 0.28 $ 0.27 $ 0.84 $ 0.81 $ 1.11 $ 1.07
========== ========== =========== ========= ========= =========
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
September 30 December 31 September 30
2001 2000 2000
---- ---- ----
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 51,735 $ 24,913 $ 12,102
Securities available-for-sale 3,770 2,113 3,493
Receivables (net of allowance for doubtful accounts of $5,226,
$3,631 and $412, respectively) -
Customers 115,981 278,436 174,167
Other 7,069 21,283 11,585
Materials, supplies and fuel 27,302 16,545 13,816
Prepaid expenses 9,848 7,428 6,570
Derivatives at market value 67,287 68,292 5,158
------------ ----------- -----------
282,992 419,010 226,891
------------ ----------- -----------
Investments 73,909 63,965 114,204
------------ ----------- -----------
Property and equipment 1,501,231 1,072,129 878,044
Less accumulated depreciation and depletion (312,178) (277,848) (265,226)
------------ ------------ -----------
1,189,053 794,281 612,818
------------ ------------ -----------
Other assets:
Derivatives at market value 1,752 - -
Other, principally goodwill and other intangibles 99,062 43,064 36,771
------------ ------------ -----------
100,814 43,064 36,771
------------ ------------ -----------
$ 1,646,768 $1,320,320 $ 990,684
============ ============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt $ 20,513 $ 13,960 $ 7,052
Notes payable 320,037 211,679 170,775
Accounts payable 109,298 247,596 161,712
Accrued liabilities 55,850 49,661 29,736
Derivatives at market value 68,175 65,960 5,158
------------- ------------ -----------
573,873 588,856 374,433
------------- ------------ -----------
Long-term debt, net of current maturities 434,993 307,092 214,714
------------- ------------ -----------
Deferred credits and other liabilities:
Derivatives at market value 1,636 - -
Investment tax credits 2,168 2,530 2,653
Federal income taxes 64,629 62,679 56,961
Reclamation and regulatory liability 22,520 22,340 22,588
Other 15,002 16,516 12,583
------------- ------------ ------------
105,955 104,065 94,785
------------- ------------ ------------
Minority interest in subsidiaries 25,940 37,961 35,463
------------- ------------ ------------
Stockholders' equity:
Preferred stock - no par Series 2000-A; 21,500 shares authorized
Issued and Outstanding: 5,177; 4,000 and 4,000 shares, respectively 5,549 4,000 4,000
------------- ------------ ------------
Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized;
Issued: 26,830,267; 23,302,111 and 23,294,018 shares, respectively 26,830 23,302 23,294
Additional paid-in capital 238,506 73,442 73,276
Retained earnings 253,240 191,482 177,610
Treasury stock (8,841) (9,067) (7,460)
Accumulated other comprehensive income (loss) (9,277) (813) 569
------------- ------------ -----------
500,458 278,346 267,289
------------- ------------ -----------
Total stockholders' equity 506,007 282,346 271,289
------------- ------------ -----------
$1,646,768 $1,320,320 $ 990,684
============= ============ ===========
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)
Nine Months Ended
September 30
2001 2000
---- ----
(in thousands)
Operating activities:
Net income available for common stock $ 82,838 $ 33,407
Principal non-cash items-
Depreciation, depletion and amortization 38,785 22,465
Deferred income taxes and investment tax credits 1,588 1,309
Undistributed earnings of affiliates (8,580) (4,131)
Minority interest 4,408 10,211
Change in operating assets and liabilities-
Accounts receivable and other current assets 161,755 (96,766)
Accounts payable and other current liabilities (132,109) 79,846
Derivative fair value (10,919) -
Other, net 2,896 (5,242)
--------- ---------
140,662 41,099
--------- ---------
Investing activities:
Property additions (442,152) (95,891)
(Increase) decrease in investments 374 (10,181)
Payment for acquisition of net assets, net of cash acquired (10,410) -
Payment for intangible assets, including goodwill (50,413) -
Available-for-sale securities sold - 7,587
--------- ---------
(502,601) (98,485)
--------- ---------
Financing activities:
Dividends paid (20,752) (18,036)
Treasury stock sold, net 226 570
Common stock issued 167,980 3,680
Increase in short-term borrowings 108,358 8,507
Long-term debt - issuance 145,649 61,075
Long-term debt - repayments (11,195) (1,339)
Subsidiary distributions to minority interests (1,505) (1,451)
--------- ---------
388,761 53,006
--------- ---------
Increase (decrease) in cash and cash equivalents 26,822 (4,380)
Cash and cash equivalents:
Beginning of period 24,913 16,482
--------- ---------
End of period $ 51,735 $ 12,102
========= =========
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $ 28,776 $20,927
Income taxes $ 34,800 $12,118
Non-cash net assets acquired through issuance of common and preferred stock $ 3,628 $34,493
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 2000 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 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 September 30,
2001, December 31, 2000 and September 30, 2000, financial information
and are of a normal recurring nature. The results of operations for the
three, nine and twelve months ended September 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' equity 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
In June 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS
No. 143). SFAS No. 143 requires that the fair value of a liability for
an asset retirement obligation be recognized in the period in which it
is incurred with the associated asset retirement costs being
capitalized as part of the carrying amount of the long-lived asset.
Over time, the liability is accreted to its present value each period
and the capitalized cost is depreciated over the useful life of the
related asset. Management expects to adopt SFAS No. 143 effective
January 1, 2003 and is currently evaluating the effects adoption will
have on the Company's consolidated financial statements.
In August 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" (SFAS No. 144). SFAS No. 144 supersedes FASB
Statement 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of" (SFAS No. 121) and the
accounting and reporting provisions of APB 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." SFAS No. 144 establishes a single
accounting model for long-lived assets to be disposed of by sale as
well as resolve implementation issues related to SFAS No. 121.
Management expects to adopt SFAS No. 144 effective January 1, 2002
and is currently evaluating the effects adoption will have on the
Company's consolidated financial statements.
(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."
7
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
Long-term Debt
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
(4.96 percent at September 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.
Notes Payable
During the second quarter of 2001, the Company used net proceeds from
its common stock offering (Note 10) to pay down approximately $163
million of its borrowings under short-term credit facilities. In
addition, during the third quarter of 2001, the Company completed a
$400 million revolving credit facility. The facility replaces the
Company's previous short-term credit lines, which totaled $290 million.
The credit facility was arranged by ABN Amro Bank N.V., US Bank, N.A.
and Union Bank of California, N.A., with ten other banks participating.
The facility consists of two $200 million tranches, one of which has a
364-day term and the other a three-year term.
Outstanding borrowings under the Company's short-term credit facilities
have been used primarily to fund the acquisition and construction of
the Las Vegas co-generation facility (Note 11), construction costs on
other power generation projects and the continued network build-out in
its communications segment.
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.
8
(6) COMPREHENSIVE INCOME
The following table presents the components of the Company's
comprehensive income:
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Net income available for common stock $16,235 $16,285 $82,838 $33,407 $102,037 $43,960
Other comprehensive income:
Unrealized gain (loss) on available-
for-sale securities 507 81 1,657 569 275 569
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 (5,173) - (2,603) - (2,603) -
-------- -------- -------- -------- -------- -------
Comprehensive income $11,569 $16,366 $74,374 $33,976 $92,191 $44,529
======== ======== ======== ======== ======== =======
(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 September 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
electricity in a number of markets, with strong emphasis in the western
United States; 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 in the accompanying
Consolidated Balance Sheets and Consolidated Statements of
9
Income is as follows (in thousands):
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
Quarter to Date
September 30, 2001
Electric $ 43,057 $ 461 $ 7,914
Mining 4,023 2,847 3,779
Oil and gas 7,750 746 2,804
Fuel marketing 216,448 3,262 3,898
Independent power 23,119 - 1,246
Communications and others 5,154 1,090 (3,275)
Intersegment eliminations - (5,559) -
-------- ------- -------
Total $299,551 $2,847 $16,366
======== ====== =======
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
Quarter to Date
September 30, 2000
Electric $ 48,607 $ - $10,060
Mining 5,740 2,796 2,375
Oil and gas 5,259 - 1,634
Fuel marketing 361,111 - 2,319
Independent power 27,155 - 2,878
Communications and others 2,563 904 (2,944)
Intersegment eliminations - (904) -
-------- ------ -------
Total $450,435 $2,796 $16,322
======== ====== =======
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
Year to Date
September 30, 2001
Electric $ 174,915 $ 783 $41,878
Mining 14,681 8,333 8,055
Oil and gas 24,583 1,770 8,723
Fuel marketing 980,828 16,256 31,252
Independent power 66,138 - 3,827
Communications and others 13,662 3,307 (10,424)
Intersegment eliminations - (22,116) -
---------- -------- -------
Total $1,274,807 $ 8,333 $83,311
========== ======== =======
10
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
Year to Date
September 30, 2000
Electric $ 117,805 $ - $24,352
Mining 14,800 7,649 6,179
Oil and gas 13,493 - 3,750
Fuel marketing 852,625 - 3,482
Independent power 27,397 - 3,008
Communications and others 4,422 2,762 (7,327)
Intersegment eliminations - (2,762) -
---------- ------ -------
Total $1,030,542 $7,649 $33,444
========== ====== =======
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
12 Months Ended
September 30, 2001
Electric $ 230,419 $ 783 $ 54,593
Mining 20,761 10,334 8,579
Oil and gas 30,274 2,915 9,953
Fuel marketing 1,481,994 29,574 41,625
Independent power 78,156 329 4,062
Communications and others 16,929 4,228 (16,262)
Intersegment eliminations - (37,827) -
---------- ------- --------
Total $1,858,533 $10,336 $102,550
========== ======= ========
External Inter-segment
Operating Revenues Operating Revenues Net Income (loss)
12 Months Ended
September 30, 2000
Electric $ 150,796 $ - $31,651
Mining 22,706 8,006 8,145
Oil and gas 17,148 - 4,797
Fuel marketing 1,025,137 - 4,553
Independent power 27,397 - 2,992
Communications and others 4,700 3,736 (8,141)
Intersegment eliminations - (3,736) -
---------- ------ -------
Total $1,247,884 $8,006 $43,997
========== ====== =======
11
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 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 As part of the Company obtaining a new corporate revolving
line-of-credit (Note 5), certain segments' total assets were
realigned as a result of certain intercompany short-term
borrowings previously held at the subsidiary level now being held
at the "holding company" level.
o The Independent Power segment had additions to its power
generation assets of approximately $430 million, primarily related
to the acquisition and construction of the Fountain Valley and Las
Vegas Co-generation facilities, 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 $22 million related to its acquisition
of Stewart Petroleum and developmental drilling.
o The Communications segment had additions to its communications
plant of approximately $19 million related to its continued
network build-out.
(8) LEGAL PROCEEDINGS
On April 3, 2001, the Company 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 the Company's 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. The Company believes 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, the Company 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-
12
time payment by PacifiCorp in the amount of $7.3 million,
which was received in August, 2001. This payment primarily relates to
disputed billings under the previous agreement and a value transfer
premium. Of this payment, $5.6 million was recognized currently in
non-operating income, $1.0 million was previously recognized in
revenues and the remaining $0.7 million is being recognized as sales
are made under the New Agreement.
Coal Option Agreement: The term of this agreement began 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 the Company
with a "put" option for 2002 and 2003 under which the Company 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 the
Company is selling to PacifiCorp K-Fuel under the KFx Facility Output
Agreement described below, and in which the Company has not exercised
its "put" option, PacifiCorp may elect to purchase an equal amount of
tonnage from the Company's 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.
The agreement also provides PacifiCorp an option to sell to the Company
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 to the Company the "In Pit"
system, the Company has 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. In October 2001
both parties exercised their respective options.
KFx Facility Output Agreement: The KFx plant is a coal enhancement
facility the Company owns located near its 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. The hedging transactions
are
13
authorized under the Company's 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.
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 September 30, 2001, December 31, 2000 and September 30,
2000 are as follows:
Max. Term
September 30, 2001 Volume Covered (Years)
------------------ -------------- -------
(MMBtus)
Natural gas basis swaps purchased 17,449,482 2
Natural gas basis swaps sold 18,940,000 2
Natural gas fixed-for-float swaps purchased 13,101,810 1
Natural gas fixed-for-float swaps sold 13,278,943 1
Natural gas swing swaps purchased 2,635,000 1
Natural gas swing swaps sold 3,410,000 1
(Tons)
Coal tons sold 961,046 1
Coal tons purchased 1,074,046 1
Max. Term
September 30, 2000 Volume Covered (Years)
------------------ -------------- -------
(MMBtus)
Natural gas basis swaps purchased 33,644,595 2
Natural gas basis swaps sold 30,954,871 2
Natural gas fixed-for-float swaps purchased 8,379,581 1
Natural gas fixed-for-float swaps sold 9,817,438 1
14
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
As required under SFAS 133 and EITF 98-10, derivatives and energy
trading activities were marked to fair value on September 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, nine and twelve month periods ended September 30, 2001
are as follows (in thousands):
Three Nine Twelve
Month Month Month
Instrument Asset Liability Gain (Loss) Gain (Loss) Gain (Loss)
- ---------- ----- --------- ------------ ----------- -----------
Natural gas basis swaps $ 9,849 $10,283 $3,130 $10,138 $2,345
Natural gas
fixed-for-float swaps 20,517 26,738 120 (3,728) (4,721)
Natural gas physical 16,384 4,078 (2,854) (1,657) 5,822
Coal transactions 4,904 3,636 (587) 359 1,269
Crude oil transactions 6,148 5,393 77 232 755
-------- ------- ------ ------- ------
Totals $57,802 $50,128 $ (114) $ 5,344 $5,470
======== ======= ====== ======= ======
There were no significant differences between the fair values of
derivative assets and liabilities at September 30, 2000.
Non-trading Energy Activities
To reduce risk from fluctuations in the price of crude 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 elects hedge accounting as allowed under SFAS
133.
At September 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
15
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 September 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 $0.2
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 and 2002 natural gas production with fixed-for-float
swaps. At September 30, 2001, these natural gas swaps were for
1,676,000 MMBtus (4,232 MMBtus per day through October 2002) with a net
fair value of $2.3 million.
The effective portion of the gains and losses on these derivatives was
recorded in other comprehensive income. At September 30, 2001,
accumulated other comprehensive income for all non-trading energy swaps
and options was $2.6 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 was immaterial.
The Company acquired several fixed-for-float swaps as part of the Las
Vegas Co-generation acquisition (Note 11) completed on August 31, 2001.
These swaps fixed the price for an index price gas purchase agreement.
The swaps hedge the natural gas purchase price for 5,000 Mmbtus per day
through April 30, 2010. The fair value of these swaps at acquisition
closing was $8.6 million.
At acquisition closing, the swaps were designated as cash flow hedges,
properly documented, and effectiveness testing established. The
critical terms of the hedge match the critical terms of the hedged item
so no ineffectiveness can be expected. At quarter-end, the hedges met
effectiveness testing and retained their cash flow hedge status.
At September 30, 2001, the change in fair value of the swaps was not
significant. No adjustments were made to the fair value of the
derivative instrument on the balance sheet, no adjustments were made to
other comprehensive income, and no earnings impact was recorded.
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 elects hedge accounting as allowed under 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 September 30, 2001, the Company had interest rate
swaps with an average balance notional amount of $381.1 million, having
a maximum term of ten years and a fair value of $(16.9) million.
Because these hedges are fully effective (no time value or basis risk),
the entire derivative fair value is recorded in
16
accumulated other comprehensive income.
At September 30, 2001, the Company had $618.0 million of outstanding,
floating-rate debt of which $224.0 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, to
fund various power plant construction costs and for general corporate
purposes.
(11) ACQUISITIONS
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 came on-line mid third quarter of
2001. The facility was purchased from Enron Corporation. Total cost of
the project is approximately $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.
On August 31, 2001, Black Hills Energy Capital closed on the purchase
of a 273 MW gas-fired co-generation power plant project located in
North Las Vegas, Nevada from Enron North America, a wholly-owned
subsidiary of Enron Corporation. The facility currently has a 51 MW
co-generation power plant in operation. Most of the power from that
facility is under a long-term contract expiring in 2024. The Company
has sold 50% of this power plant to another party, however, under
generally accepted accounting principles the Company is required to
consolidate 100% of this plant. The project also has a 222 MW combined-
cycle expansion under way, which is 100%-owned by the Company. The
facility is scheduled to be fully operational in the third quarter of
2002 and will utilize LM-6000
17
technology. The power of the expansion is also under a long-term
contract which expires in 2017. This contract for the expansion
requires the purchaser to provide fuel to the power plant when it is
dispatched. The cost for the entire facility is expected to be
approximately $330 million and the Company is in the process of
obtaining long-term financing, which is expected to be primarily non-
recourse project debt.
The acquisition has been accounted for under the purchase method of
accounting and, accordingly, the purchase price of approximately $205
million has 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. Fair values in
the allocation include assets acquired of approximately $157 million
(excluding goodwill and other intangibles) and liabilities assumed of
approximately $2 million. The estimated purchase price allocations are
subject to adjustment, generally within one year of the date of the
acquisition. Should new or additional facts about the acquisitions
become available within one year of the date of acquisition, any
changes to the preliminary estimates will be reflected as an adjustment
to goodwill. The purchase price and related acquisition costs exceeded
the fair values assigned to net tangible assets by approximately $50
million, which was recorded as long-lived intangible assets and
goodwill. Operating activities of the acquired company have been
included in the accompanying consolidated financial statements since
the acquisition date.
18
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 59,400 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.
Unless the context otherwise requires, references in this Form 10-Q to the
"Company", "we", "us" and "our" refer to Black Hills Corporation and all of its
subsidiaries collectively.
Results of Operations
Consolidated Results
Consolidated earnings for the three month period ended September 30, 2001 were
$16.2 million or $0.61 per share compared to $16.3 million or $0.71 per share in
the same period of the prior year. Consolidated earnings for the nine month
periods ended September 30, 2001 and 2000 were $82.8 million or $3.28 per share
and $33.4 million, or $1.52 per share respectively, and consolidated earnings
for the twelve month period ended September 30, 2001 were $102.0 million or
$4.12 per share compared to $44.0 million or $2.01 per share for the same period
of the prior year.
Consolidated earnings were level for the three month period ended September 30,
2001 compared to the same period in 2000. Financial results reflect the
substantial price decreases and reduction in demand experienced in energy
markets over the summer of 2001. The Company experienced record natural gas and
oil production and strong natural gas marketing volumes sold during the third
quarter of 2001. In addition, coal production increased and independent power
capacity increased significantly. Earnings for the Independent Energy business
group increased 29 percent over the same period in 2000 offset by a decrease in
the electric utility's earnings related to a significant decrease in prices
received for off-system sales and continued losses in the Communications
business group. Independent Energy business group's earnings included a $3.4
million after-tax gain related to a coal contract settlement, partially offset
by additional liabilities accrued for mining expenses.
Increases in consolidated earnings for the nine and twelve month periods ended
September 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.
19
Unusual energy market conditions stemming primarily from gas and electricity
shortages in the West contributed to our strong financial performance in the
last half of 2000 and the first half of 2001. We estimated that approximately
$0.40 of the reported $2.37 earnings per share in calendar year 2000 (including
approximately $0.10 in the third quarter of 2000) and more than half of the
reported $2.71 earnings per share for the six months ended June 30, 2001 could
be attributed to high prices of natural gas and electricity and high gas trading
margins. Energy prices decreased substantially beginning in June 2001, which has
resulted in an earnings stream returning to a pattern which is more consistent
with our longer-term baseline growth performance. Certain energy markets in
which we are active have continued to experience extreme volatility. Our fuel
production, fuel marketing and power sales exposure in these markets is
primarily indirect through sales to credit-worthy counterparties, including
neighboring utilities and gas and power marketing firms.
Consolidated revenues for the three, nine and twelve month periods ended
September 30, 2001 were $302.4 million, $1.3 billion and $1.9 billion,
respectively. Revenues for the same periods ended September 30, 2000 were $453.2
million, $1.0 billion and $1.3 billion, respectively.
The growth in revenues for the nine and twelve month periods ended September 30,
2001 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. The significant
decrease in energy commodity prices was the primary reason for the decline in
revenues for the quarter ended September 30, 2001 compared to the same quarter
in 2000.
Consolidated operating expenses decreased significantly during the three month
period ended September 30, 2001 compared to the same quarter in 2000 due to
significant decreases in purchased power costs and fuel costs related to the
operation of our combustion turbines.
Consolidated operating expenses have increased significantly during the nine and
twelve month periods ended September 30, 2001, primarily due to 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.
In addition, there were significant cost increases related to the 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.
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 Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Revenues
Independent energy 84% 89% 85% 88% 87% 88%
Electric utility 14 11 14 12 12 12
Communications 2 - 1 - 1 -
---- --- --- --- --- ---
100% 100% 100% 100% 100% 100%
=== === === === === ===
20
Net Income/(Loss)
Independent energy 72% 56% 62% 49% 63% 47%
Electric utility 48 62 50 73 53 72
Communications and other (20) (18) (12) (22) (16) (19)
--- --- --- --- --- ---
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 estimate net losses in 2001 of
approximately $12 million.
The following business group and segment information does not include
intercompany eliminations:
Independent Energy Group
Three Months Ended Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $ 258,195 $ 402,061 $1,112,589 $915,964 $1,654,337 $1,100,394
Expenses 239,972 375,323 1,018,886 878,798 1,536,752 1,059,044
--------- --------- ---------- -------- ---------- ----------
Operating income $ 18,223 $ 26,738 $ 93,703 $ 37,166 $ 117,585 $ 41,350
Net income $ 11,901 $ 9,206 $ 52,030 $ 16,419 $ 64,391 $ 20,487
EBITDA* $ 32,033 $ 20,559 $ 118,937 $ 33,843 $ 149,774 $ 40,495
*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.
21
The following table provides a summary of certain operating statistics of our
independent energy group:
Three Months Ended Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Fuel production:
Tons of coal sold 872,900 838,200 2,465,700 2,216,900 3,299,000 3,015,000
Mcf equivalent sales 2,033,000 1,320,700 5,309,000 3,698,000 6,888,600 4,895,000
Average price per
barrel of oil sold
(including hedge
transactions) $24.35 $22.53 $24.55 $21.35 $24.10 $20.17
Average price per Mcf
of natural gas sold
(including hedge
transactions) $ 3.28 $ 2.76 $ 4.48 $ 2.44 $ 4.29 $ 2.38
Fuel marketing
average daily volumes:
Natural gas - MMBtus 1,062,600 903,000 947,900 787,300 981,000 763,600
Crude oil - barrels 35,100 45,000 37,000 45,000 38,400 33,300
Coal - tons 5,600 2,700 6,000 4,400 5,500 4,300
Earnings from the Independent Energy business group increased from 2000 amounts
by $2.7 million, or $0.10 per share, and $35.6 million, or $1.40 per share, and
$43.9 million, or $1.76 per share, for the three, nine and twelve month periods
ended September 30, 2001, respectively. Natural gas volumes marketed increased
significantly for the three, nine and twelve month periods, compared to the same
periods of the previous year, while margins in the three month period returned
to levels approximating historical trends. Gas and oil production had
significant increases in volumes sold for the respective periods, and moderate
increases in natural gas and oil prices. Coal mining results increased due to a
recent coal contract settlement and increased tonnage sold, offset partially by
lower average prices. Independent power operations added over 300 MW in the
third quarter and has approximately 400 MW under construction. Independent power
operations were affected by lower power prices in the West and lower-than-normal
water flows at hydro power plants in New York.
The group's non-operating income for the quarter increased over the previous
year due to a portion of the coal mining subsidiaries recent coal contract
settlement that was recorded in non-operating income and lower charges for
minority interest in consolidated subsidiaries as a result of decreased earnings
from these subsidiaries and the Company's buy-out of certain minority interest.
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.
22
Coal Mining Segment
Three Months Ended Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $6,870 $8,536 $23,014 $22,449 $31,095 $30,712
Operating income $ 830 $3,223 $ 5,664 $ 8,426 $ 6,033 $11,659
Net income $3,779 $2,375 $ 8,055 $ 6,179 $ 8,579 $ 8,145
EBITDA $7,184 $3,839 $13,891 $10,114 $14,792 $12,695
Earnings for the three, nine and twelve month periods increased over the prior
year's periods, primarily as a result of a $3.4 million after-tax gain related
to a coal contract settlement with PacifiCorp, partially offset by additional
liabilities accrued for mining expenses. In addition, lower average prices
received were partially offset by moderate increases in production volumes.
Oil and Gas Segment
Three Months Ended Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $8,496 $5,259 $26,353 $13,493 $33,189 $17,148
Operating income $4,035 $2,396 $12,929 $ 5,448 $15,387 $ 7,106
Net income $2,804 $1,634 $ 8,723 $ 3,750 $ 9,953 $ 4,797
EBITDA $5,723 $3,197 $18,328 $ 7,717 $22,605 $ 9,739
Earnings of the oil and gas production business segment increased for the three,
nine and twelve month periods due to increases in gas volumes sold of 61
percent, 50 percent and 51 percent, respectively, while average gas prices
realized after hedged transactions were 19 percent, 84 percent and 80 percent
higher than the same periods in the prior year, respectively. Barrels of oil
sold increased 43 percent, 34 percent and 26 percent for the three, nine and
twelve month periods while average prices realized after hedged transactions
were 8 percent, 15 percent and 20 percent higher than the same periods in the
prior year, respectively.
The following is a summary of our estimated oil and gas reserves at September 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.
2001 2000
---- ----
Barrels of oil (in millions) 4.2 5.3
Bcf of natural gas 25.7 18.8
Total in Bcf equivalents 50.9 50.6
23
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 Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $219,710 $361,111 $997,084 $852,625 $1,511,568 $1,025,137
Operating income $ 5,606 $ 3,320 $ 49,794 $ 5,304 $ 68,378 $ 4,622
Net income $ 3,898 $ 2,319 $ 31,252 $ 3,482 $ 41,625 $ 4,553
EBITDA $ 6,146 $ 4,049 $ 51,394 $ 6,323 $ 68,874 $ 8,397
The significant increase in earnings for the nine and twelve month periods
resulted from high margins which 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.
Margins in the third quarter 2001 returned to levels approximating historical
trends. In addition, natural gas volumes marketed increased 18 percent, 20
percent and 28 percent for the three, nine and twelve month periods compared to
the same periods of the previous year.
Independent Power Production Segment
Three Months Ended Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $23,119 $27,155 $66,138 $27,397 $78,485 $27,397
Operating income $ 7,752 $17,799 $25,316 $17,988 $27,787 $17,963
Net income $ 1,246 $ 2,878 $ 3,827 $ 3,008 $ 4,062 $ 2,992
EBITDA $12,980 $ 9,474 $35,324 $ 9,689 $43,503 $ 9,664
Over 300 MW were added to operations mid third quarter 2001 and approximately
400 MW are currently under construction. Earnings from Independent power
operations were affected by lower power prices in the West and lower-than-normal
water flows at hydro plants in New York.
24
Electric Utility Group
Three Months Ended Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $43,518 $48,607 $175,698 $117,805 $231,202 $150,796
Expenses 28,272 29,994 102,477 72,567 135,011 92,289
------- ------- -------- -------- -------- --------
Operating income $15,246 $18,613 $ 73,221 $ 45,238 $ 96,191 $ 58,507
Net income $ 7,914 $10,060 $ 41,878 $ 24,352 $ 54,593 $ 31,651
EBITDA $18,692 $22,465 $ 85,038 $ 56,867 $111,465 $ 74,098
Earnings from the electric utility decreased $2.2 million, or $0.08 per share
and increased $17.5 million, or $0.69 per share, and $22.9 million, or $0.92 per
share for the three, nine and twelve month periods ended September 30, 2001,
respectively. The decrease in third quarter earnings resulted from a significant
decrease in wholesale electricity prices in response to changes in western
energy market conditions. Average prices received for off-system sales decreased
32 percent and increased 105 percent and 136 percent for the three, nine and
twelve month periods in 2001 compared to the same periods in 2000. In addition,
off-system megawatt hours sold decreased 11 percent for the three months due to
changes in market conditions and increased 64 percent and 67 percent for the
nine and twelve month periods ended September 30, 2001 compared to the same
periods in 2000, due to higher market prices and the 40 MW generating capacity
added in 2001. The Electric Utility continued to have modest gains in firm
residential and commercial electric sales. These nine and twelve month period
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 Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Firm (system) sales - MWh 537,000 519,000 1,527,000 1,477,000 2,024,000 1,950,000
Off-system sales - MWh 211,000 237,000 761,000 465,000 980,000 588,000
Communications Group
Three Months Ended Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
(in thousands)
Revenue $ 5,154 $ 2,563 $13,717 $ 4,422 $ 16,984 $ 4,700
Expenses 8,101 5,121 23,237 11,349 32,062 13,455
------- ------- ------- ------- -------- -------
Operating loss $(2,947) $(2,558) $(9,520) $(6,927) $(15,078) $(8,755)
Net loss $(2,661) $(2,842) $(9,343) $(6,974) $(14,397) $(7,785)
EBITDA $ (362) $ (949) $(2,135) $(3,503) $ (5,536) $(4,082)
25
Losses in Communications for the three, nine and twelve month periods ended
September 30, 2001 were $(2.7) million, or $(0.10) per share, $(9.3) million, or
$(0.37) per share and $(14.4) million, or $(0.58) per share, compared to $(2.8)
million, or $(0.12) per share, $(7.0) million or $(0.32) per share and $(7.8)
million or $(0.36) per share for the same periods in the prior year,
respectively. The customer base continues to grow with an increase of 17 percent
in the third quarter of 2001, compared to the second quarter of 2001. Losses for
the nine and twelve month periods in 2001 increased due to increases in certain
reserves for inventory and carrier billings and increased interest expense.
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. The following table provides certain operating statistics:
September 30 June 30 March 31 December 31 September 30
2001 2001 2001 2000 2000
---- ---- ---- ---- ----
Business customers 1,940 1,440 980 650 490
Residential customers 13,780 12,000 10,060 8,370 6,700
Liquidity and Capital Resources
During the three, nine and twelve month periods ended September 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 September 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, to fund various power plant construction projects and for
general corporate purposes.
In addition, during the third quarter of 2001, the Company completed a $400
million revolving credit facility. The facility replaces the Company's previous
short-term credit lines, which totaled $290 million. The credit facility was
arranged by ABN Amro Bank N.V., US Bank, N.A. and Union Bank of California,
N.A., with ten other banks participating. The facility consists of two $200
million tranches, one of which has a 364-day term and the other a three-year
term.
26
Capital Requirements
During the third quarter 2001, we closed on the purchase of a gas-fired
generation complex in North Las Vegas, Nevada from Enron North America, a
wholly-owned 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
27
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.
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.
28
BLACK HILLS CORPORATION
Part II - Other Information
Item 1. Legal Proceedings
For information regarding legal proceedings, see Note 7 to the
Consolidated Financial Statements in this Form 10-Q, the Company's
2000 Annual Report on Form 10-K and the Company's quarterly
reports on Form 10-Q for the quarters ended March 31, 2001 and
June 30, 2001.
Item 2. Changes In Securities and Use of Proceeds
(c) On September 10, 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. Each of the
stockholders is an accredited investor.
Series 2000-A
Stockholder Common Shares Issued Preferred Stock Issued
Gerald R. Forsythe 7,029 178
John W. Salyer 1,360 34
Michelle R. Fawcett 736 18
Marsha Fournier 736 18
Monica Breslow 736 18
Melissa S. Forsythe 736 18
Item 6. Exhibits and Reports of Form 8-K
(a) Exhibits
The following documents are included as exhibits to this
Form 10-Q:
Exhibit
Number Description
------ -----------
10.1 3-Year Credit Agreement dated as of August 28, 2001
among Black Hills Corporation, as Borrower, The
Financial Institutions party, hereto, as Banks, ABN
AMRO BANK N.V., as Administrative Agent, Union Bank of
California, N.A., as Syndication Agent, Bank of
Montreal, as Co-Syndication Agent, U.S. Bank, National
Association, as Documentation Agent, and The Bank of
Nova Scotia, as Co-Documentation Agent.
29
10.2 364-Day Credit Agreement dated as of August 28, 2001
among Black Hills Corporation, as Borrower, The
Financial Institutions party, hereto, as Banks, ABN
AMRO BANK N.V., as Administrative Agent, Union Bank of
California, N.A., as Syndication Agent, Bank of
Montreal, as Co-Syndication Agent, U.S. Bank, National
Association, as Documentation Agent, and The Bank of
Nova Scotia, as Co-Documentation Agent.
(b) Reports on Form 8-K
On September 18, 2001, the Company filed a Form 8-K dated
August 31, 2001 reporting "Item 5 - Other Events" related to
the acquisition of a 273 MW gas-fired co-generation power
plant project located northeast of Las Vegas, Nevada from
Enron North America, a wholly-owned subsidiary of Enron
Corporation.
30
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
By: /s/ Roxann R. Basham
---------------------------------------------
Roxann R. Basham, Vice President - Controller
Principal Accounting Officer)
By: /s/ Mark T. Thies
---------------------------------------------
Mark T. Thies, Senior VP & CFO
(Principal Financial Officer)
Dated: November 14, 2001
31
EXHIBIT INDEX
Exhibit
Number Description
10.1 3-Year Credit Agreement dated as of August 28, 2001 among Black Hills
Corporation, as Borrower, The Financial Institutions party, hereto, as
Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of
California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication
Agent, U.S. Bank, National Association, as Documentation Agent, and The
Bank of Nova Scotia, as Co-Documentation Agent.
10.2 364-Day Credit Agreement dated as of August 28, 2001 among Black Hills
Corporation, as Borrower, The Financial Institutions party, hereto, as
Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of
California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication
Agent, U.S. Bank, National Association, as Documentation Agent, and The
Bank of Nova Scotia, as Co-Documentation Agent.