SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended SEPTEMBER 30, 1999
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 0-368
OTTER TAIL POWER COMPANY
(Exact name of registrant as specified in its charter)
Minnesota 41-0462685
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
215 South Cascade Street, Box 496, Fergus Falls, Minnesota 56538-0496
(Address of principal executive offices) (Zip Code)
218-739-8200
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last
report.)
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 latest practicable date:
November 1, 1999 - 11,925,272 Common Shares ($5 par value)
OTTER TAIL POWER COMPANY
------------------------
INDEX
-----
Part I. Financial Information Page No.
Item 1. Financial Statements
Consolidated Balance Sheets - September 30, 1999 (Unaudited)
and December 31, 1998 2 & 3
Consolidated Statements of Income - Three Months and Nine Months
Ended September 30, 1999 and 1998 (Unaudited) 4
Consolidated Statements of Cash Flows - Three Months and Nine Months
Ended September 31, 1999 and 1998 (Unaudited) 5
Notes to Consolidated Financial Statements (Unaudited) 6-9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 9-16
Item 3. Quantitative and Qualitative Disclosures about
Market Risk 17
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 17
Signatures 17
PART I. FINANCIAL INFORMATION
------------------------------
ITEM 1. FINANCIAL STATEMENTS
--------------------
<TABLE>
OTTER TAIL POWER COMPANY
CONSOLIDATED BALANCE SHEETS
-ASSETS-
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
(Unaudited)
(Thousands of dollars)
<S> <C> <C>
PLANT:
Electric plant in service $ 774,176 $ 770,887
Subsidiary companies 104,813 89,094
--------- ---------
TOTAL 878,989 859,981
Less accumulated depreciation and amortization 383,151 370,290
--------- ---------
495,838 489,691
Construction work in progress 12,818 10,495
--------- ---------
NET PLANT 508,656 500,186
--------- ---------
INVESTMENTS 20,533 20,612
--------- ---------
INTANGIBLES -- NET 28,289 21,176
--------- ---------
OTHER ASSETS 5,213 3,968
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents 12,708 3,919
Accounts receivable:
Trade - net 42,699 41,249
Other 3,644 6,845
Materials and supplies:
Fuel 3,027 3,418
Inventory, materials and operating supplies 25,013 23,138
Deferred income taxes 3,160 2,730
Accrued utility revenues 7,008 11,179
Other 4,823 6,310
--------- ---------
TOTAL CURRENT ASSETS 102,082 98,788
--------- ---------
DEFERRED DEBITS:
Unamortized debt expense and reacquisition premiums 3,377 3,737
Regulatory assets 3,390 3,774
Other 1,222 3,371
--------- ---------
TOTAL DEFERRED DEBITS 7,989 10,882
--------- ---------
TOTAL $ 672,762 $ 655,612
========= =========
See accompanying notes to consolidated financial statements
- 2 -
</TABLE>
<TABLE>
OTTER TAIL POWER COMPANY
CONSOLIDATED BALANCE SHEETS
-LIABILITIES-
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
(Unaudited)
(Thousands of dollars)
<S> <C> <C>
CAPITALIZATION
Common shares, par value $5 per share - authorized
50,000,000 shares; outstanding 1999 -- 11,925,272
and 1998 -- 11,879,504 shares $ 59,626 $ 59,398
Premium on common shares 41,410 39,919
Retained earnings 132,789 125,462
Accumulated other comprehensive income - 297
--------- ---------
TOTAL 233,825 225,076
Cumulative preferred shares - authorized 1,500,000
shares without par value; outstanding 1999 -- 383,000
and 1998 -- 388,311 shares
Subject to mandatory redemption 18,000 18,000
Other 15,500 20,831
Cumulative preference shares - authorized 1,000,000
shares without par value; outstanding - none - -
Long-term debt 189,895 181,046
--------- ---------
TOTAL CAPITALIZATION 457,220 444,953
--------- ---------
CURRENT LIABILITIES
Short-term debt - 824
Sinking fund requirements and current maturities 6,940 5,794
Accounts payable 32,797 32,411
Accrued salaries and wages 4,684 3,946
Federal and state income taxes accrued 6,077 2,192
Other taxes accrued 9,514 11,119
Interest accrued 2,157 3,120
Other 6,060 3,826
--------- ---------
TOTAL CURRENT LIABILITIES 68,229 63,232
--------- ---------
NONCURRENT LIABILITIES 25,362 22,842
--------- ---------
DEFERRED CREDITS
Accumulated deferred income taxes 89,270 90,964
Accumulated deferred investment tax credit 16,611 17,481
Regulatory liabilities 11,312 11,692
Other 4,758 4,448
--------- ---------
TOTAL DEFERRED CREDITS 121,951 124,585
--------- ---------
TOTAL $ 672,762 $ 655,612
========= =========
See accompanying notes to consolidated financial statements
-3-
</TABLE>
<TABLE>
OTTER TAIL POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
1999 1998 1999 1998
------------- ----------- ----------- ------------
(in thousands, except share and per share amounts)
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric $ 60,860 $ 54,958 $ 178,811 $ 164,582
Manufacturing 26,261 24,861 70,719 68,292
Health services 15,281 16,802 49,124 50,183
Other business operations 21,398 16,305 49,187 34,652
----------- ----------- ----------- ------------
Total operating revenues 123,800 112,926 347,841 317,709
OPERATING EXPENSES
Production fuel 8,930 8,052 28,181 26,231
Purchased power 12,889 10,480 36,254 27,467
Other electric operation and maintenance expenses 19,182 16,435 53,975 52,723
Special charges - - - 9,522
Cost of goods sold 44,754 41,204 123,330 108,609
Other nonelectric expenses 9,825 9,360 27,263 26,424
Depreciation and amortization 6,326 6,398 18,835 19,239
Property taxes 2,852 2,675 8,510 8,318
----------- ----------- ----------- ------------
Total operating expenses 104,758 94,604 296,348 278,533
OPERATING INCOME
Electric 11,581 11,756 35,603 26,279
Manufacturing 2,577 3,561 6,107 8,136
Health services 569 1,563 4,111 5,670
Other business operations 4,315 1,442 5,672 (909)
----------- ----------- ----------- ------------
Total operating income 19,042 18,322 51,493 39,176
OTHER INCOME AND DEDUCTIONS - NET 470 414 983 1,510
INTEREST CHARGES 3,722 3,828 11,069 11,875
----------- ----------- ----------- -----------
INCOME BEFORE INCOME TAXES 15,790 14,908 41,407 28,811
INCOME TAXES 5,410 5,031 14,632 8,980
----------- ----------- ----------- -----------
Income before cumulative effect of change in accounting principle 10,380 9,877 26,775 19,831
Cumulative effect of change in accounting principle - net-of-tax - - - 3,819
----------- ----------- ----------- -----------
NET INCOME 10,380 9,877 26,775 23,650
Preferred dividend requirements 579 590 1,758 1,769
----------- ----------- ----------- -----------
EARNINGS AVAILABLE FOR COMMON SHARES $ 9,801 $ 9,287 $ 25,017 $ 21,881
=========== =========== =========== ===========
Basic and diluted earnings per average common share:
Before cumulative effect of change in accounting principle $ 0.82 $ 0.79 $ 2.10 $ 1.54
Cumulative effect of change in accounting principle - - - 0.32
----------- ----------- ----------- -----------
Basic and diluted earnings per average common share - net $ 0.82 $ 0.79 $ 2.10 $ 1.86
=========== =========== =========== ===========
Average number of common shares outstanding 11,924,877 11,818,460 11,912,460 11,778,724
Dividends per common share $0.495 $0.480 $1.485 $1.440
See accompanying notes to consolidated financial statements
</TABLE>
-4-
<TABLE>
OTTER TAIL POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
NINE MONTHS ENDED
SEPTEMBER 30,
1999 1998
--------- ---------
(Thousands of dollars)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $26,775 $23,650
Adjustments to reconcile net income to net cash
Provided by operating activities:
Depreciation and amortization 26,608 26,592
Deferred investment tax credit - net (870) (881)
Deferred income taxes (1,910) (5,322)
Change in deferred debits and other assets 687 5
Change in noncurrent liabilities and deferred credits 2,829 608
Allowance for equity (other) funds used during construction (38) (82)
(Gains)/Losses from investments and disposal of noncurrent assets (38) 432
Voluntary early retirement program charges - 6,305
Cumulative effect of change in accounting principle - (3,819)
Asset impairment losses - 3,217
Cash provided by (used for) current assets & current liabilities:
Change in receivables, materials and supplies 284 (9,013)
Change in other current assets 5,641 (2,684)
Change in payables and other current liabilities 1,754 6,561
Change in interest and income taxes payable 2,923 (3,416)
------- -------
NET CASH PROVIDED BY OPERATING ACTIVITIES 64,645 42,153
CASH FLOWS FROM INVESTING ACTIVITIES:
Gross capital expenditures (26,170) (19,795)
Proceeds from disposal of noncurrent assets 1,099 1,645
Purchase of businesses, net of cash acquired (16,000) (1,354)
Change in other investments (813) (1,042)
------- -------
NET CASH USED IN INVESTING ACTIVITIES (41,884) (20,546)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in short-term debt - net (824) (2,100)
Proceeds from issuance of common stock 1,719 4,123
Proceeds from issuance of long-term debt 13,752 2,943
Payments for debt and common stock issuance expense - (82)
Payments for retirement of long-term debt (3,840) (9,272)
Redemption of preferred stock (5,331) -
Dividends paid (19,448) (18,722)
------- -------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (13,972) (23,110)
NET CHANGE IN CASH AND CASH EQUIVALENTS 8,789 (1,503)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 3,919 5,301
------- -------
CASH AND CASH EQUIVALENTS AT SEPTEMBER 30 $12,708 $ 3,798
======= =======
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest and income taxes:
Interest (net of amount capitalized) $11,309 $12,376
Income taxes $13,601 $17,331
See accompanying notes to consolidated financial statements
- 5 -
</TABLE>
OTTER TAIL POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
(Unaudited)
The Company, in its opinion, has included all adjustments (including
normal recurring accruals) necessary for a fair presentation of the
results of operations for the periods. The financial statements for 1999
are subject to adjustment at the end of the year when they will be audited
by independent accountants. The financial statements and notes thereto
should be read in conjunction with the financial statements and notes for
the years ended December 31, 1998, 1997, and 1996 included in the
Company's 1998 Annual Report to the Securities and Exchange Commission on
Form 10-K. Certain prior year amounts have been reclassified to conform
to 1999 presentation. Because of seasonal and other factors, the earnings
for the three-month and nine-month periods ended September 30, 1999,
should not be taken as an indication of earnings for all or any part of
the balance of the year.
Reclassification and reporting change
- -------------------------------------
Effective with the third quarter of 1999, the Company has reclassified
certain items previously listed as other income and deductions to
operating income. The reclassified items include gains/losses on the sale
of investments, and equity earnings/losses of unconsolidated equity
investees of the Company's telecommunication companies (included in the
other business operations segment). The telecommunication companies
actively maintain investments in telephony companies in order to support
their current line of business as well as advancements in the telephony
industry. Also reclassified to operating income were additional items of
revenue and expense of the health services and manufacturing segments that
are considered an integral part of the operations of these segments and
accordingly are recorded as part of operating income. All prior periods
have been reclassified to reflect this reporting change. There was no
impact on net income or earnings per share for the periods presented.
Common shares and earnings per share
- ------------------------------------
On February 23, 1999, the Company granted options that would allow the
purchase of 219,000 shares of common stock at an exercise price of
$38.375 per share to eligible employees under the Company's 1999 Stock
Incentive Plan (the "Plan") approved by shareholders on April 12, 1999. A
total of 1,300,000 shares of the Company's common stock are available for
granting of awards under the Plan. The exercise price of the stock options
is equal to the fair market value per share at the date of the grant.
The options vest over a four-year period at the rate of 25% per year and
will expire ten years after the date of the grant. The Company accounts
for the Plan under Accounting Principles Board Opinion No. 25, which does
not require recording of compensation expense. The effects of the common
stock options on the computation of diluted earnings per share were
immaterial for the three and nine-months ended September 30, 1999.
The Company issued 44,619 common shares for the nine months ended
September 30, 1999 under its Automatic Dividend Reinvestment and Share
Purchase Plan. Starting in June 1999, the Company began purchasing the
common shares needed for this plan from the open market instead of issuing
new shares. During 1998, the Company issued 38,173 and 115,012 common
shares for the three and nine-month periods ended September 30,
respectively, under the Automatic Dividend Reinvestment and Share Purchase
Plan.
Comprehensive income
- --------------------
Elements of comprehensive income for the three-month period ended
September 30, 1999, include net income of $10,380,000 along with a
$610,000 (net of $401,000 in deferred taxes) reduction in accumulated
other comprehensive income related to the reversal of previously recorded
unrealized gains on "available-for-sale" securities which were sold during
the third quarter of 1999. Comprehensive income for the nine-month period
ended September 30, 1999, includes net income of $26,775,000 along with a
$297,000 (net of $210,000 in deferred taxes) reduction in accumulated
other comprehensive income related to the reversal of previously recorded
unrealized gains on "available-for-sale" securities which were sold during
the third quarter of 1999.
Elements of comprehensive income for the three-month period ended
September 30, 1998, include net income of $9,877,000 along with a
reduction in accumulated other comprehensive income of $132,000 (net of
$93,000 in deferred taxes) related to a $225,000 reduction in the market
value of securities held as "available-for-sale". Comprehensive income for
the nine-month period ended September 30, 1998, includes net income of
$23,650,000 along with a $16,000 reduction in accumulated other
comprehensive income (net of $12,000 in deferred taxes) related to a $28,000
reduction in the market value of securities held as "available-for-sale".
Rate matters
- ------------
On October 6, 1999, the North Dakota Public Service Commission approved a
settlement agreement following an audit of the Company's electric
operations in North Dakota. The effect of this agreement was recorded
during the third quarter of 1999 and decreased earnings by approximately
$441,000 after taxes or $0.037 per share. In addition, the Company will be
allowed to retain all 1999 earnings from North Dakota regulated electric
operations up to a 12.5% return on equity and will be required to refund
to North Dakota customers any earnings over the 12.5% return. The Company
will also file a proposal for a performance-based ratemaking plan by year-
end. Based upon preliminary review it is possible that the Company's 1999
North Dakota regulated electric operations may exceed a 12.5% return on
equity. However due to a number of uncertainties, the Company at this time
is unable to determine whether or not any refund will be required.
As previously disclosed, due to the ongoing review of demand-side
management programs and related incentives by the Minnesota Public
Utilities Commission ("MPUC"), the Company has chosen not to record any
1999 conservation program incentives until approved by the MPUC. In 1998,
the Company recorded revenues related to 1998 lost margins and bonus
incentives of $1.7 million.
Arbitration settlement
- ----------------------
As previously disclosed, the Company and two of the other three co-owners
of the Coyote Station filed a Demand and Notice of Arbitration complaint
in 1996 against Knife River Coal Mining Company and MDU Resources Group,
Inc. This case was remanded to arbitration in 1997. During 1999, the
arbitrators issued a memorandum opinion that 1) reduced the price of coal
purchased, beginning March 26, 1999, from a mine-mouth Knife River
operation; 2) modified the price adjustment provisions of the contract for
the future; and 3) required Knife River to refund excess monies paid for
coal from September 13, 1996 through March 26, 1999. During the third
quarter of 1999, the Company received payment of $2.7 million in refunds,
representing the Company's share as a co-owner of Coyote station. These
refunds are included as a liability on the balance sheet pending
regulatory filings in each state to determine possible refunds to electric
retail customers.
Segment information and acquisitions
- ------------------------------------
On September 1, 1999, the Company acquired the flatbed trucking operations
of E. W. Wylie Corporation ("Wylie"). Wylie's annual revenues range from
$18 to $19 million. The acquisition was accounted for using the purchase
method of accounting. The excess of the purchase price over net assets
acquired of approximately $8 million is being amortized over 15 years.
Wylie is located in Fargo, North Dakota and owns approximately 104
tractors and 178 trailers and operates in 48 states and 6 Canadian
Provinces. Results from operations of this company are included in the
other business operations segment from the acquisition date.
The Company's business operations, which are based mainly in Minnesota,
North Dakota and South Dakota, are broken down into four segments based on
products and services. Electric operations include the electric utility
only. Manufacturing operations includes production of agricultural
equipment, plastic pipe, automobile and truck frame-straightening
equipment and accessories, contract machining and fabricated metal parts.
Health services operations consists of businesses involved in the sale,
service, rental, refurbishing and operations of medical imaging equipment
and the sale of related supplies and accessories to various medical
institutions located in the Midwestern United States. Other business
operations consists of businesses diversified in such areas as electrical
and telephone construction contracting, entertainment, energy services,
natural gas marketing, telecommunications and transportation. The Company
evaluates the performance of its business segments and allocates resources
to them based on earnings contribution and return on investment.
Substantially all sales and long-lived assets of the Company are within
the United States.
Operating Income
----------------
Three months ended Nine months ended
September 30, September 30,
------------------ -----------------
(in thousands) 1999 1998 1999 1998
- ---------------------------------------------------------------------
Electric $ 11,581 $ 11,756 $ 35,603 $ 26,279
Manufacturing 2,577 3,561 6,107 8,136
Health Services 569 1,563 4,111 5,670
Other Business Operations 4,315 1,442 5,672 (909)
-------- -------- -------- --------
Total $ 19,042 $ 18,322 $ 51,493 $ 39,176
======== ======== ======== ========
Identifiable Assets
-------------------
As of As of
September 30, December 31,
(in thousands) 1999 1998
- ----------------------------------------------------------
Electric $ 520,976 $ 525,226
Manufacturing 50,963 41,579
Health Services 27,438 36,241
Other Business Operations 73,385 52,566
---------- ----------
Total $ 672,762 $ 655,612
---------- ----------
Subsequent Event
- ----------------
The Company completed the sale of certain assets of the radio stations and
video production company owned by KFGO and the radio stations owned by
Western Minnesota Broadcasting Company for $24 million in October 1999.
The Company expects to recognize a before tax gain of approximately $14.5
million in the fourth quarter.
Special charges
- ---------------
In the first quarter of 1998, the Company recorded special charges that
reflected three items: (1) a voluntary early retirement offer was
accepted by 55 of the 67 eligible employees resulting in a one-time
noncash charge of $6,305,000 ($3,783,000 net-of-tax or $0.32 per share);
(2) an impairment loss of $2,500,000 ($1,500,000 net-of-tax or $0.13 per
share) was recorded on the write-down of Quadrant Co.'s waste incineration
plant to an undepreciated carrying value of $0 under the requirements of
SFAS 121; and (3) as a result of an unfavorable court decision related to
the construction of a rail spur intended to serve Big Stone Plant, the
Company wrote off $717,000 ($430,000 net-of-tax or $0.04 per share) in
project related costs.
Cumulative effect of change in accounting principle
- ---------------------------------------------------
In the first quarter of 1998, the Company changed its method of revenue
recognition on the sale of electricity in Minnesota and South Dakota from
meter-reading dates to energy-delivery dates, resulting in the recognition
of $6,364,000 ($3,819,000 net-of-tax or $0.32 per share) in unbilled
revenue.
Forward Looking Information - Safe Harbor Statement Under the Private
Securities Litigation Reform Act of 1995
- ----------------------------------------
In connection with the "safe harbor" provisions of the Private Securities
Litigation Reform Act of 1995 (the "Act"), the Company has filed
cautionary statements identifying important factors that could cause the
Company's actual results to differ materially from those discussed in
forward-looking statements made by or on behalf of the Company. When used
in this Form 10-Q and in future filings by the Company with the Securities
and Exchange Commission, in the Company's press releases and in oral
statements, words such as "may", "will", "expect", "anticipate",
"continue", "estimate", "project", "believes" or similar expressions are
intended to identify forward-looking statements within the meaning of the
Act. Factors that might cause such differences include, but are not
limited to, governmental and regulatory action, the competitive
environment, economic factors, weather conditions, the Company's ability
to identify and address all year 2000 issues and other factors discussed
under "Factors affecting future earnings" on pages 22-25 of the Company's
1998 Annual Report to Shareholders, which is incorporated by reference in
the Company's Form 10-K for the fiscal year ended December 31, 1998.
These factors are in addition to any other cautionary statements, written
or oral, which may be made or referred to in connection with any such
forward-looking statement or contained in any subsequent filings by the
Company with the Securities and Exchange Commission.
Item 2. Management's Discussion and Analysis of Condition and
Results of Operations
---------------------
MATERIAL CHANGES IN FINANCIAL POSITION
- --------------------------------------
Cash provided by operating activities of $64.6 million as shown on the
Consolidated Statement of Cash Flows for the nine months ended September
30, 1999 allowed the Company to pay dividends, finance its capital
expenditures, redeem one series of preferred stock and fund a portion of
the Wylie acquisition. At September 30, 1999, the Company and its
subsidiaries had $37.6 million available in unused lines of credit, which
could be used to supplement cash needs.
The Company estimates that funds internally generated, combined with funds
on hand, will be sufficient to meet all sinking fund payments for First
Mortgage Bonds in the next five years and to provide for its estimated
1999-2003 consolidated capital expenditures. Additional short-term or
long-term financing will be required in the period 1999-2003 in connection
with the maturity of First Mortgage Bonds and other long-term debt and in
the event the Company decides to refund or retire early any of its
presently outstanding debt or cumulative preferred shares or for other
corporate purposes.
The $8.5 million increase in net plant is due to an increase in
transmission and distribution construction in the electric utility,
expansion of plant within the manufacturing segment and acquisition of the
Wylie trucking assets offset by the normal increase in accumulated
depreciation. The $7.1 million increase in intangibles is primarily a
result of goodwill related to the Wylie acquisition. The decrease in
other accounts receivable of $3.2 million is mainly due to the timing of
payments from the joint owners for the operation of Big Stone Plant and
Coyote Station where the Company serves as operating agent. The $4.2
million decrease in accrued utility revenues reflects the reduction in
unbilled revenues due to the seasonal change in weather. Other deferred
debits decreased $2.1 million primarily as a result of timing differences
in the recording of the costs of conservation programs compared to the
recovery of these costs.
The combined increase in common shares, par value and premium on common
shares of $1.7 million is due to the issuance of 44,619 shares of common
stock under the Company's Automatic Dividend Reinvestment and Share
Purchase Plan. The decrease in other cumulative preferred shares relates
to the redemption of the Company's $9.00 exchangeable cumulative preferred
shares. During the third quarter, the Company redeemed all of its
outstanding $9.00 exchangeable cumulative preferred stock in an exchange
for 113,976 shares of common stock, purchased on the open market, and
$547,000 in cash. Long-term debt increased $8.8 million and sinking fund
requirements and current maturities increased $1.1 million primarily as a
result of the Wylie acquisition. The increase in federal and state income
taxes accrued of $3.9 million is related to the timing and amount of
estimated tax payments due to a change in the method of determining
estimated tax payments. The $1.6 million decrease in other taxes accrued
is the result of the timing of property tax payments. Interest accrued
decreased $1.0 million due to the timing of bond interest payments, the
majority of which are due in the first and third quarters of the calendar
year. The $2.2 million increase in other current liabilities relates to
the recording of the $2.7 million refund from the arbitration settlement
as discussed on page 7. The increase of $2.5 million in noncurrent
liabilities reflects the growth in the liability for postretirement
benefits.
MATERIAL CHANGES IN RESULTS OF OPERATIONS
- -----------------------------------------
Comparison of the Quarters Ended September 30, 1999 and 1998
------------------------------------------------------------
Electric Operations
-------------------
Three months ended
September 30,
--------------------- Percentage
(in thousands) 1999 1998 change
- -------------------------------------------------------------------------
Operating revenues $ 60,860 $ 54,958 10.7
Production fuel 8,930 8,052 10.9
Purchased power 12,889 10,480 23.0
Other operation and maintenance expenses 19,182 16,435 16.7
Depreciation and amortization 5,427 5,571 (2.6)
Property taxes 2,851 2,664 7.0
-------- -------- ----
Operating income $ 11,581 $ 11,756 (1.5)
-------- -------- ----
The increase in electric operating revenues for the quarter is due to a
$9.9 million (153%) increase in revenues from power pool sales offset by
decreases of $1.9 million (4.2%) in retail revenue and $2.1 million (68%)
in other electric revenue. Power pool sales and revenue per kwh sold were
up significantly due to peak summer demand for electricity in a large
geographic region as a result of unusually hot weather. As a result of
the high demand coupled with the availability of the Company's generating
stations, the Company was able to benefit from the high prices and hot
weather. The decrease in retail revenue reflects a reduction in kwh sales
to industrial customers, particularly pipeline customers, along with a
2.6% decrease in revenue per kwh sold to all retail customers. Decreased
kwh sales to industrial customers combined with the recording of the
impact of the North Dakota settlement as discussed on page 7 were
partially offset by increases in kwh sales to residential and commercial
customers. A decrease in electrical contract work done for other
utilities is the primary reason for the decrease in other electric
revenue.
The increase in production fuel and purchased power expense is
commensurate with the increase in power pool sales. Generation at the
Company's steam generating units increased by 14%. Fuel costs per kwh
generated decreased 5.7% due in part to the arbitration settlement. The
increase in other electric operation and maintenance expenses is due to
the recording of expenses related to new incentive programs, general wage
increases and increases in expenditures for consulting services and
insurance costs.
Manufacturing Operations
------------------------
Three months ended
September 30,
--------------------- Percentage
(in thousands) 1999 1998 change
- ----------------------------------------------------------
Operating revenues $ 26,261 $ 24,861 5.6
Cost of goods sold 19,630 17,812 10.2
Operating expenses 4,054 3,488 16.2
-------- -------- -----
Operating income $ 2,577 $ 3,561 (27.6)
-------- -------- -----
Three of the Company's seven manufacturing subsidiaries had increased
sales for the quarter. Even though operating revenues increased for the
quarter, operating income decreased 28%. The decline in operating income
for the manufacturing segment is due to decreases in gross margins,
increases in selling, general and administrative costs and a slight
increase in research and development costs.
Health Services Operations
--------------------------
Three months ended
September 30,
--------------------- Percentage
(in thousands) 1999 1998 change
- ----------------------------------------------------------
Operating revenues $ 15,281 $ 16,802 (9.1)
Cost of goods sold 12,631 12,942 (2.4)
Operating expenses 2,081 2,297 (9.4)
-------- -------- -----
Operating income $ 569 $ 1,563 (63.6)
-------- -------- -----
The decrease in operating revenues for the quarter is partially due to
decreases in sales volumes of medical equipment. Also contributing to the
decrease in operating revenues was an increase in the numbers of imaging
scans which was more than offset by a lower average fee per scan. The
decrease in cost of goods sold reflects the decrease in sales volumes.
Other Business Operations
-------------------------
Three months ended
September 30,
--------------------- Percentage
(in thousands) 1999 1998 change
- ----------------------------------------------------------
Operating revenues $ 21,398 $ 16,305 31.2
Cost of goods sold 12,493 10,450 19.6
Operating expenses 4,590 4,413 4.0
-------- -------- -----
Operating income $ 4,315 $ 1,442 199.2
-------- -------- -----
Operating income increased due to the $1.5 million gain from the sale of
an investment by the telecommunication subsidiary combined with higher
volumes of contracted work at the Company's construction subsidiaries.
Interest Charges and Income Taxes
---------------------------------
Interest charges decreased $106,000 (2.8%) during the third quarter due
primarily to lower average borrowing levels and lower interest rates. The
increase in income taxes of $379,000 (7.5%) primarily relates to the
increase in income before taxes during the third quarter.
Comparison of the Nine Months Ended September 30, 1999 and 1998
---------------------------------------------------------------
Electric Operations
-------------------
Nine months ended
September 30,
--------------------- Percentage
(in thousands) 1999 1998 change
- -------------------------------------------------------------------------
Operating revenues $178,811 $164,582 8.6
Production fuel 28,181 26,231 7.4
Purchased power 36,254 27,467 32.0
Other operation and maintenance expenses 53,975 52,723 2.4
Special charges - 7,022 -
Depreciation and amortization 16,291 16,576 (1.7)
Property taxes 8,507 8,284 2.7
-------- -------- ----
Operating income $ 35,603 $ 26,279 35.5
-------- -------- ----
The increase year-to-date in electric operating revenues is due to an
$18.8 million (92%) increase in revenues from power pool sales offset by a
$1.2 million (0.9%) decrease in retail revenue and a $3.4 million (44%)
decrease in other electric revenue. The increase in power pool sales is
related to increased demand in the power pool due to hot summer weather in
a large geographical area combined with an increase in energy available
for sale and increased power marketing sales efforts. Decreases in
electrical contract work done for other utilities combined with the
Company's decision not to record 1999 conservation program incentives
until approved by the MPUC are the primary reasons for the decrease in
other electric revenue.
Production fuel expenses for the nine months increased as a direct result
of a 10.2% increase in kwh generated offset by a 2.4% decrease in the fuel
costs per kwh generated at the Company's steam generating units.
Purchased power expense increased as a result of a 45% increase in kwh
purchased for power pool sales, partially offset by a 23% decrease in kwh
purchased for system use. The reduction in purchased power for system use
was due to greater plant availability coincidental with a reduction in
demand for retail sales.
The increase in other electric operation and maintenance expenses year-to-
date is primarily related to the recording of expenses related to new
incentive programs and increased expenditures for consulting services
offset by a reduction in material and supplies expenses due to less
contracted work for other utilities during 1999 and reduced expenses
resulting from the 1998 early retirement program.
The special charges recorded under electric operations in the first
quarter of 1998, represent two items: (1) a noncash charge of $6,305,000
associated with a voluntary early retirement program offered by the
Company and, (2) the write-off of $717,000 in accumulated costs related to
a rail spur project at Big Stone Plant. (See "Special charges" in notes
to consolidated financial statements on page 9 for further information
including the net-of-tax and earnings per share impact of these charges.)
Excluding the special charges, this business segment would have shown an
increase of $2.3 million (6.9%) in operating income for the nine months
ended September 30.
Manufacturing Operations
------------------------
Nine months ended
September 30,
--------------------- Percentage
(in thousands) 1999 1998 change
- ----------------------------------------------------------
Operating revenues $ 70,719 $ 68,292 3.6
Cost of goods sold 53,768 50,168 7.2
Operating expenses 10,844 9,988 8.6
-------- -------- -----
Operating income $ 6,107 $ 8,136 (24.9)
-------- -------- -----
Four of the Company's seven manufacturing subsidiaries had increased sales
year-to-date. The decline in operating income for the manufacturing
segment is primarily due to significantly lower gross margins on new
product lines at one of the manufacturing subsidiaries combined with
reduced gross margins at three other subsidiaries.
Health Services Operations
--------------------------
Nine months ended
September 30,
--------------------- Percentage
(in thousands) 1999 1998 change
- ----------------------------------------------------------
Operating revenues $ 49,124 $ 50,183 (2.1)
Cost of goods sold 38,892 38,410 1.3
Operating expenses 6,121 6,103 0.3
-------- -------- -----
Operating income $ 4,111 $ 5,670 (27.5)
-------- -------- -----
The decrease in operating revenues for the nine months reflects a
combination of decreases in sales volumes of medical equipment and an
increase in the number of medical imaging scans performed which was more
than offset by a decrease in the average fee per scan. Cost of goods sold
and operating expenses increased as a result of the increase in scans
performed combined with increases in the costs of repair and maintenance
on equipment used to serve customers.
Other Business Operations
-------------------------
Nine months ended
September 30,
--------------------- Percentage
(in thousands) 1999 1998 change
- ----------------------------------------------------------
Operating revenues $ 49,187 $ 34,652 41.9
Cost of goods sold 30,670 20,031 53.1
Special charges - 2,500 -
Operating expenses 12,845 13,030 (1.4)
-------- -------- -----
Operating income $ 5,672 $ (909) -
-------- -------- -----
The primary reasons for the increase in operating revenues and cost of
goods sold are: (1) larger volume of work contracted at the Company's
construction subsidiaries, (2) the PAM Natural Gas acquisition that
occurred on May 1, 1998 and (3) the Wylie acquisition that occurred on
September 1, 1999. Operating revenues also increased as a result of the
gain from the sale of an investment by the telecommunication subsidiary.
The special charges recorded during the first quarter of 1998 represent an
impairment loss associated with the Quadrant Co. waste incineration plant.
(See "Special charges" in notes to consolidated financial statements on
page 9 for further information including the net-of-tax and earnings per
share impact of these charges.) Excluding the Quadrant Co. impairment
loss, this business segment would have shown an increase of $4.1 million
(257%) in operating income for the nine months ended September 30.
Other Income and Deductions - net
---------------------------------
The $527,000 (35%) reduction in other income and deductions year-to-date
is due to decreases in incentives from demand-side management programs
offset by increased interest income.
Interest Charges and Income Taxes
---------------------------------
The $806,000 (6.8%) decrease in interest charges is due to a reduction in
average outstanding debt for the period and lower average interest rates
during 1999 combined with the payment of interest during 1998 on the
settlement of a Federal income tax audit. The $5.7 million (63%) increase
in income taxes is primarily due to the increase in income before taxes.
Year 2000 Readiness Disclosure
- ------------------------------
Many computer software systems, as well as certain hardware and equipment
containing date-sensitive data, were structured to utilize a two-digit
year field meaning that they may not be able to properly recognize dates
in the year 2000. The Company recognizes that the year 2000 occurrence
puts all of its electronic systems on all platforms at risk. Application
systems, information technology systems and technology that includes
embedded systems have been reviewed, in order, from highly critical to
less critical. These systems include the Company's financial software,
customer-information system, energy-management system, power plant control
systems, manufacturing processes and diagnostic medical imaging equipment.
In order to address the year 2000 issue from a total business
perspective, the Company is working with its major vendors, customers,
banks, regulatory and government agencies, and utility alliances.
In order to improve business information systems, the Company's operating
businesses began replacing major financial computer systems in 1996. The
electric utility has replaced its major in-house developed financial
computer systems with financial applications from Oracle Corporation,
while at the same time, replacing the hardware on which these applications
reside. Because of the recent implementation, these systems should
require minimal remediation efforts. The costs of replacing these major
financial computer systems are not included in the cost estimates
discussed below.
The Company's plan to resolve the year 2000 issues involves three phases:
inventory, assessment and remediation/testing. The inventory and
assessment phases were completed for the electric utility in December 1998
and February 1999, respectively. The remediation and testing phase for all
mission critical systems was completed in June 1999. On June 23, the
electric utility reported to the North American Electric Reliability
Council ("NERC") that based on NERC standards, the electric utility is
100% year 2000 ready. The electric utility will continue to perform
testing and administration of year 2000 readiness and to refine its
contingency plans through December 31, 1999. For the subsidiary companies,
the final portions of the inventory and assessment phases were completed
in September 1999. The remediation and testing phase for all mission
critical systems was completed as of September 30.
In addition, the Company's operating businesses are communicating with
critical external parties in order to determine the extent of
vulnerability to such parties' failure to resolve their own year 2000
issues. As of September 30, 1999, third party assessments were completed
at the subsidiary companies. As examples of third party communications,
the electric utility has received letters from the railroad indicating
that their systems are compliant. Sixty-five different communication
service providers were contacted. Letters were received back from thirty-
eight providers indicating year 2000 readiness or plans to be ready by
year-end. Web sites for the large communication vendors were reviewed for
their year 2000 readiness plans. The Company continues to develop plans
to alter business relationships in the event certain third parties fail to
become year 2000 compliant. There can be no guarantee that the third
parties of business importance to the Company will successfully reprogram
or replace and test all of their own computer hardware, software, and
process control systems in a timely manner. While the failure of a single
third party to achieve year 2000 readiness should not have a material
adverse effect on the Company's financial results or operations, the
failure of several key third parties could have such an effect.
The electric utility industry is unique in its dependence upon a complex
network of interrelated systems of the power pool grid in order to support
and maintain reliable, efficient operations. The Company's year 2000
readiness effort is linked to the readiness efforts of other utilities, as
well as those of major customers whose loads support the integrity of the
power pool grid. The Company is coordinating its year 2000 effort with
that of the Mid-Continent Area Power Pool and with plans established by
NERC under the direction of the U. S. Department of Energy. The Company
participated in the April 9, 1999 NERC drill to simulate loss of multiple
voice and data communications systems. On September 8 and 9, 1999 the
Company participated in the NERC sponsored drill that simulated as
realistically as practical the implementation of administrative,
operating, communications and contingency response plans for the year 2000
transition. While the Company is supporting these cooperative efforts, it
cannot guarantee the successful implementation of solutions of third
parties. A failure of a system within the power pool grid could have a
material impact on the Company and its customers.
The Company's medical subsidiary owns diagnostic imaging equipment which
has computer software that is vulnerable to year 2000 issues. One hundred
fifty-six pieces of equipment were assessed to be non-compliant. As of
September 30, 1999, 124 units have been upgraded and are now compliant.
Twenty-two machines are scheduled to be upgraded and the remaining ten
machines were previously scheduled to be replaced or retired. The medical
subsidiary has also identified 120 pieces of non-compliant medical
equipment, which had either been sold or leased to customers. All of the
customers have been contacted regarding this equipment with options for
compliance. A few of the customers have declined to upgrade the equipment
because it is either currently or scheduled to be taken out of service.
Some of the customers are considering purchasing new equipment rather than
upgrading. Forty-three units have been upgraded and twenty-five more are
scheduled. The medical subsidiary continues to contact the remaining
customers to get a decision from them regarding their plans for the
equipment.
The costs of the Company's year 2000 readiness effort are being funded
with cash flows from operations. These costs are not expected to be
substantially different from the normal, ongoing costs that are incurred
for systems development, implementation and maintenance due in part to the
use of internal resources and the deferral of other projects. Total
expenditures related to the Company's year 2000 readiness effort are
expected to be approximately $1 million for 1997 to 2000. Expenditures
incurred through September 30, 1999, most of which have occurred at the
electric utility, are estimated at $730,000. The Company does not track
year 2000 costs in a separate account.
As part of its normal business practice, the electric utility maintains
emergency backup and recovery procedures to be followed in the event of
failure of a mission-critical system. These procedures were expanded to
include specific procedures for potential year 2000 issues. The business
critical processes contingency plans were approved in April of 1999. The
Company's electrical system contingency plan, which was completed and
approved in June 1999, used templates provided by the NERC. This plan
includes meeting with large customers to determine their operating plans
during critical dates. To date only one of the large customers contacted
has indicated that they may not be running under normal operations over
the year-end. The Company has plans to provide for additional staffing at
critical locations to respond to any year 2000 situations that might
arise. Communication contingency plans include using standby generators
to communicate with the power stations, locating people at critical
substations to relay information back to the control center and using HAM
radio technology to communicate with neighboring utilities. Contact is
ongoing with neighboring utilities to coordinate contingency plans,
operating plans, and the year 2000 backup communications drill.
At this time, the Company believes its worst case scenario is that key
customers could experience significant reductions in their power needs due
to their own year 2000 issues. Although the Company does not believe that
this scenario is likely to occur, the Company expects that such a scenario
would not have a material adverse affect on the Company's consolidated
financial position. The Company believes a more probable worst case
scenario is a temporary disruption of service to its electric customers,
including the effect of cascading disruptions caused by other entities
whose electrical systems are connected to the Company's. The Company has
assessed the risk of this scenario, and believes that contingency plans
would mitigate the long-term effect of such a scenario. In the event that
a temporary disruption in service does occur, the Company does not expect
that it would have a material adverse effect on its consolidated financial
position.
While the Company believes it will be able to resolve its year 2000 issues
in a timely manner, if it is unable to complete the required changes to
existing critical systems, or if those with whom the Company conducts
business are unsuccessful in implementing timely solutions, the year 2000
issue could have a material adverse effect upon the Company's consolidated
results of operations.
The costs of the project and the completion dates are based on
management's best estimates, which were derived from assumptions of future
events including the availability of resources, third party modification
plans, and other factors. There can be no guarantee that these estimates
will be achieved and actual results could vary due to uncertainties.
The forward looking statements contained in this section under the heading
"Year 2000 Readiness Disclosure" should be read in conjunction with the
Company's disclosure above under the heading "Forward Looking Information-
Safe Harbor Statement Under the Private Securities Litigation Reform Act
of 1995."
Item 3. Quantitative and Qualitative Disclosures About Market Risk
----------------------------------------------------------
The Company does not have material market risk exposure related to foreign
currency exchange rate risk, commodity price risk or interest rate risk.
PART II. OTHER INFORMATION
--------------------------
Item 6. Exhibits and Reports on Form 8-K.
---------------------------------
a) Exhibits:
10 Power Sales Agreement between the Company and Manitoba Hydro
Electric Board dated July 1, 1999.*
27 Financial Data Schedule
*Confidential information has been omitted from such Exhibit and
filed separately with the Commission pursuant to a confidential
treatment request under Rule 24b-2.
b) Reports on Form 8-K.
No reports on Form 8-K were filed during the fiscal quarter ended
September 30, 1999.
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.
OTTER TAIL POWER COMPANY
By: John Erickson
-----------------------
John Erickson
Vice President, Finance
(Chief Financial Officer/Authorized Officer)
Dated: November 10, 1999
-----------------
(*) Confidential information has been omitted and filed separately
with the Commission pursuant to Rule 24b-2.
MH-OTP
POWER SALES AGREEMENT
This MH-OTP POWER SALES AGREEMENT ("Agreement") is entered
into effective as of July 1, 1999, by and between Otter Tail
Power Company ("OTP"), a Minnesota corporation and The Manitoba
Hydro Electric Board ("MH"), a Manitoba Crown Corporation, (each
of the foregoing entities being sometimes referred to
individually as "Party" or collectively referred to as
"Parties").
RECITALS
0.01 WHEREAS, OTP is the owner and operator of electric
generation and transmission facilities in the United States of
America, and MH is the owner and operator of electric generation
and transmission facilities in Canada, and each Party is engaged
in the generation, transmission, distribution and sale of
electric energy;
0.02 WHEREAS, OTP and MH, among others, are parties to the
Mid-Continent Area Power Pool Restated Agreement ("MAPP Restated
Agreement"), dated January 12, 1996, and amended to date hereof;
0.03 WHEREAS, the Parties require governmental permits and
approvals for the import and export of electric energy; and
0.04 WHEREAS, OTP and MH, among others, are parties to the
Manitoba - United States Winnipeg - Grand Forks 230 kV
Interconnection Coordinating Agreement, dated January 16, 1969,
as amended.
NOW, THEREFORE, in consideration of the mutual promises and
covenants of each Party to the other contained in this Agreement
and other good and valuable consideration, the receipt of which
is hereby acknowledged, the Parties covenant and agree as
follows:
ARTICLE 1
DEFINITIONS
Section 1.01 Unless otherwise specified in this Agreement,
all definitions and references to and use of terms and their
abbreviations shall have the meanings which are set out in the
MAPP Restated Agreement, as amended to date hereof, or in the
Manitoba - United States Winnipeg - Grand Forks 230 kV
Interconnection Coordinating Agreement, dated January 16, 1969,
as amended. In the event of a discrepancy between the two
agreements, the Manitoba - United States Winnipeg - Grand Forks
230 kV Interconnection Coordinating Agreement shall take
precedence.
Firm Commitments - shall mean capacity and energy intended
to be available at all times during the period covered
by a commitment.
Minimum Monthly Energy - for each month of the contract
term, the Minimum Monthly Energy, in MWh, shall be
calculated as follows:
(A x 16) x 50 MW
where A is the number of Monday to Friday
days in the month.
Monthly Capacity Factor - expressed as a percentage,
shall mean with respect to a particular month:
(a) the energy delivered during the respective month,
divided by;
(b) the product of:
(i) the amount of capacity required to be made
available to a receiving Party in such
month, and
(ii) the number of hours in such month.
Point of Interconnection - as defined in the Manitoba -
United States Winnipeg - Grand Forks 230 kV
Interconnection Coordinating Agreement, dated
January 16, 1969, as amended.
Summer Season - shall mean the period from May 1 through
to the following October 31.
Supplementary Agreement - shall mean an instrument in
writing duly authorized and executed by the Parties
which alters, varies, modifies or waives any provision
of this Agreement.
System Participation Power - shall mean power and energy
sold from a Party's system on a continuously available
basis except when the Party's facilities are temporarily
out of service for scheduled or forced maintenance,
during which time the delivery of energy from other
sources shall be at the seller's option.
Week - shall mean a period of seven consecutive days
commencing on Monday at 12:01 a.m. Central Time.
Winter Season - shall mean the period from November 1
through to the following April 30.
Section 1.02 When required by the context of this Agreement,
the singular shall include the plural, and the plural shall
include the singular.
ARTICLE 2
SERVICE TO BE PROVIDED
Section 2.01 During the period May 1, 2000 through
April 30, 2010, MH shall make available to OTP, at the Point of
Interconnection, 50 MW of System Participation power from MH's
HVDC facilities terminating at the Dorsey Converter Station in
accordance with Section 2.05.
Section 2.02 OTP may schedule delivery of energy associated
with the capacity specified in section 2.01 which will result in
a maximum capacity factor during any twenty-eight day (28) day
period of up to 47.62%.
Section 2.03 Energy associated with the capacity specified
in Section 2.01 may be available in addition to the energy
specified in Section 2.02. The availability of such additional
energy is at the sole discretion of MH.
Section 2.04 At the request of MH, OTP must schedule for
delivery to MH, in any month, an amount of energy up to the
amount of energy OTP scheduled for delivery from MH in that same
month pursuant with Section 2.02. The delivery point for this
energy will be specified by Manitoba Hydro at the time of
scheduling.
Section 2.05 In the event of unavailability of any portion
of MH's HVDC system terminating at the Dorsey Converter Station,
including the DC transmission facilities, and/or Manitoba Hydro's
generating facilities, MH may curtail the System Participation
power specified in Section 2.01 to OTP.
Section 2.06 Notwithstanding Section 2.05, if conditions
arise which affect MH's ability to make available or deliver the
System Participation power as specified in this Agreement, MH may
curtail availability and deliveries by the amount necessary to
enable MH to meet:
a. Firm Commitments within the province of Manitoba,
including obligations now existing or hereafter
created to retail customers (including retail
customers presently served by MH which are outside
the Province of Manitoba but are located adjacent
to a Province of Manitoba border and any future
customers similarly located, in each case with less
than 10 megawatts peak demand), and obligations now
existing or hereafter created to other electric
suppliers to serve retail customers within the
Province of Manitoba.
b. The 500 megawatt sale to Northern States Power
Company as set out in the original June 14, 1984,
Power Agreement between Northern States Power
Company, The Manitoba Hydro-Electric Board and
The Manitoba Energy Authority.
c. The Island Falls Power and Energy Transfer
Agreement between The Manitoba Hydro-Electric
Board and Saskatchewan Power Corporation dated
January 15, 1985.
d. The August 28, 1987, Electricity Sale Agreement
between The Manitoba Hydro-Electric Board, The
Manitoba Energy Authority and Ontario Hydro.
e. The November 16, 1987, Diversity Exchange
Agreement between Northern States Power Company
and The Manitoba Hydro-Electric Board.
f. The Diversity Exchange Agreement between Northern
States Power Company and The Manitoba Hydro-
Electric Board, effective February 1, 1991.
g. The Diversity Exchange Agreement between United
Power Association and The Manitoba Hydro-Electric
Board, effective February 1, 1991.
h. The Firm Power Agreement between Minnkota Power
Cooperative, Inc. and The Manitoba Hydro-Electric
Board, effective June 3, 1993.
i. The Power Services Agreement between Otter Tail
Power Company and The Manitoba Hydro-Electric
Board, effective September 26, 1993.
j. All Firm Commitments outside the province of
Manitoba entered into after the date first above
written.
ARTICLE 3
SCHEDULING
Section 3.01 Notwithstanding Section 3.02 and Section 3.03,
the following procedures shall apply for scheduling deliveries of
power associated with Section 2.02, Section 2.03 and Section 2.04
of this Agreement:
(a) Monthly Procedure:
For energy associated with Section 2.02 and Section
2.04, the following monthly procedure shall apply
unless mutually agreed to by the Parties:
For energy associated with Section 2.02, OTP shall
provide MH with an estimate of OTP's anticipated energy
usage for the forthcoming month on or before the first
of each month.
For energy associated with Section 2.04, MH shall
provide OTP with an estimate of MH's requirement to
have the energy returned for the forthcoming month on
or before the first of each month.
(b) Weekly Procedure:
For energy associated with Section 2.02, Section 2.03
and Section 2.04, the following weekly procedure shall
apply, unless otherwise mutually agreed to by the
Parties:
For energy associated with Section 2.02, OTP shall
provide MH with a proposed schedule of deliveries for
each clock hour of the following Week on or before 1500
hours Central Time on Thursday of each Week.
For energy associated with Section 2.03, energy will be
scheduled by mutual agreement.
For energy associated with Section 2.04, MH shall
provide OTP with MH's requirement to have the energy
returned on or before 1500 hours Central Time on
Thursday of each Week. The scheduling for this energy
shall be by mutual agreement of the Parties.
(c) Daily Procedure:
The following daily procedure shall apply, unless
otherwise mutually agreed to by the Parties:
For energy associated with Section 2.02, OTP may modify
its hourly schedule, provided in (b) above, by
providing MH with a modified schedule of deliveries for
each clock hour of the following day on or before 1000
hours Central Time of each day.
For energy associated with Section 2.03 and Section
2.04, modification to the hourly schedule, as provided
in accordance with (b) above, will be only by mutual
agreement of the Parties.
Section 3.02 The Parties may schedule energy in accordance
with Section 3.01 subject to the availability of transmission
capability.
Section 3.03 Schedules may be curtailed for the following
reasons:
(i) due to a loss of or capability in the
transmission path between MH and OTP;
(ii) scheduling reductions imposed upon either
Party by the MAPP Security Center;
(iii) by an amount equal to scheduling reductions
necessary on the Manitoba-U.S. interface for
MH to deliver its share of MAPP generation
reserves; or
(iv) in the event of the unavailability of any
portion of MH's HVDC system terminating at
the Dorsey Converter Station, including the
DC transmission facilities, and/or Manitoba
Hydro's generating facilities.
Section 3.04 Each Party will provide as much notice as
possible to the other Party if schedules are curtailed for
reasons provided for in Section 3.03.
ARTICLE 4
PRICING
Section 4.01 The monthly rate for capacity reserved for OTP,
as specified in Section 2.01, is as follows:
Period Monthly Capacity Rate
May 1, 2000 - April 30, 2001 $*/MW-month
May 1, 2001 - April 30, 2002 $*/MW-month
May 1, 2002 - April 30, 2003 $*/MW-month
May 1, 2003 - April 30, 2004 $*/MW-month
May 1, 2004 - April 30, 2005 $*/MW-month
May 1, 2005 - April 30, 2006 $*/MW-month
May 1, 2006 - April 30, 2007 $*/MW-month
May 1, 2007 - April 30, 2008 $*/MW-month
May 1, 2008 - April 30, 2009 $*/MW-month
May 1, 2009 - April 30, 2010 $*/MW-month
Section 4.02 The rate for energy scheduled to OTP in
accordance with Section 2.02 is as follows:
Energy Rate = $*/MW.h x E/F
where:
"E" is *
"F" is *
For example, the energy rate for the period May 1, 2001
through April 30, 2002 would be: $*/MWh. x */*.
Section 4.03 The rate for energy scheduled in accordance
with Section 2.03 shall be determined by mutual agreement between
the Parties.
Section 4.04 The rate for energy scheduled in accordance
with Section 2.04 will be OTP's cost including losses and any
associated transmission charges, plus *%. OTP's cost will
include opportunity cost.
Section 4.05 The amount payable by OTP to MH in each month
shall be the sum of:
(a) the capacity rate in dollars per MW-month in
accordance with Section 4.01 multiplied by the
capacity reserved in accordance with Section 2.01;
plus
(b) the energy rate in dollars per MW.h determined in
accordance with Section 4.02 multiplied by the
greater of:
i) the energy scheduled for delivery in accordance
with Section 2.02; and
ii) the Minimum Monthly Energy for the billing month
less any energy quantity which could not have
been delivered during HE 07:00 through to
HE 22:00 Monday through Friday in accordance
with Section 3.02 and Section 3.03;
plus
(c) the energy rate in dollars per MW.h determined in
accordance with Section 4.03 multiplied by the energy
scheduled for delivery in accordance with Section 2.03;
minus
(d) the energy rate in dollars per MW.h determined in
accordance with Section 4.04 multiplied by the energy
scheduled for delivery in accordance with Section 2.04.
Section 4.06 All rates stated and all rates calculated shall
be in lawful money of the United States of America.
ARTICLE 5
CONDITIONS OF SALE AND PURCHASE
Section 5.01 OTP is responsible for all and any applicable
costs incurred in the U.S. including but not limited to
transmission service charges, with the exception of:
any MAPP assessed Schedule F transmission charges
associated with energy scheduled from OTP to MH in
accordance with Section 2.04; and
any transmission losses associated with energy
identified in Section 2.02 and Section 2.03, to
the extent that these losses are not greater than
those losses incurred by transporting the energy
from MH directly to OTP.
OTP is not responsible for transmission service costs in the
Province of Manitoba.
Section 5.02 MH is responsible for all costs incurred in
Canada as a result of this Agreement, and any MAPP assessed
Schedule F transmission charges associated with energy scheduled
from OTP to MH in accordance with Section 2.04. MH is
responsible for any transmission losses associated with this
Agreement to the extent that these losses are not greater than
those losses incurred by transporting the energy from MH directly
to OTP. OTP is responsible for any transmission losses over and
above this quantity.
Section 5.03 In the event OTP fails to schedule the
Minimum Monthly Energy during any month, and any such failure was
not allowed in accordance with Sections 3.02 or 3.03 or MH's
failure to perform in accordance with the terms of this
Agreement, then OTP will pay MH an amount for each MWh of such
deficiency as if the energy were delivered.
Section 5.04 Except as provided within the terms of this
agreement, energy transactions may not be curtailed by either
Party for economic reasons.
ARTICLE 6
GENERAL
Section 6.01 This Agreement shall be conditional upon
receiving:
the approvals of applicable regulatory authorities,
including but not limited to, National Energy Board
of Canada approval and the U.S. Federal Energy
Regulatory Commission approval;
MAPP accreditation; and
transmission service between MH's and OTP's system.
Section 6.02 Except as otherwise provided herein, the
provisions of the Manitoba - United States Winnipeg - Grand Forks
230 kV Interconnection Coordinating Agreement, dated January 16,
1969, as amended, shall apply to this Agreement and are hereby
incorporated by reference.
Section 6.03 This Agreement represents the entire agreement
between the Parties with respect to the subject matter hereof and
terminates and supersedes all prior oral and written proposals
and communications pertaining hereto. There are no representations,
conditions, warranties or agreements, express or implied,
statutory or otherwise, with respect to or collateral to this
Agreement other than those contained herein or expressly
incorporated herein. Unless otherwise specifically provided
herein, this Agreement may be altered, modified or varied, in
whole or in part, only by Supplementary Agreement.
ARTICLE 7
CONTRACT TERM
Section 7.01 Subject to Section 6.01 of this Agreement, this
MH-OTP POWER SALES AGREEMENT shall become effective on July 1,
1999, and shall continue until the later of April 30, 2010, and
the date upon which all obligations under this Agreement are
discharged.
THE MANITOBA HYDRO-ELECTRIC BOARD
DATE: July 7, 1999
/s/ R.G. Kirby
R.G. Kirby
Manager, Export Power Marketing
OTTER TAIL POWER
DATE: July 9, 1999
/s/ W. Uggerud
W. Uggerud
Vice-President Operations
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet as of September 30, 1999 and the Consolidated
Statement of Income for the nine months ended September 30, 1999, and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 447,846
<OTHER-PROPERTY-AND-INVEST> 114,845
<TOTAL-CURRENT-ASSETS> 102,082
<TOTAL-DEFERRED-CHARGES> 7,989
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 672,762
<COMMON> 59,626
<CAPITAL-SURPLUS-PAID-IN> 41,410
<RETAINED-EARNINGS> 132,789
<TOTAL-COMMON-STOCKHOLDERS-EQ> 233,825
18,000
15,500
<LONG-TERM-DEBT-NET> 189,895
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 6,940
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 208,602
<TOT-CAPITALIZATION-AND-LIAB> 672,762
<GROSS-OPERATING-REVENUE> 347,841
<INCOME-TAX-EXPENSE> 14,632
<OTHER-OPERATING-EXPENSES> 296,348
<TOTAL-OPERATING-EXPENSES> 310,980
<OPERATING-INCOME-LOSS> 36,861
<OTHER-INCOME-NET> 983
<INCOME-BEFORE-INTEREST-EXPEN> 37,844
<TOTAL-INTEREST-EXPENSE> 11,069
<NET-INCOME> 26,775
1,758
<EARNINGS-AVAILABLE-FOR-COMM> 25,017
<COMMON-STOCK-DIVIDENDS> 17,651
<TOTAL-INTEREST-ON-BONDS> 10,745
<CASH-FLOW-OPERATIONS> 64,645
<EPS-BASIC> 2.10
<EPS-DILUTED> 2.10
</TABLE>
