Selected consolidated financial data
- ----------------------------------------------------------------------------------------------------------
1996 1995 1994 1993 1992 1991 1986
-------- -------- -------- -------- -------- -------- --------
(thousands except per-share data)
Revenues
Electric
Residential $ 66,295 $ 64,355 $ 62,687 $ 62,167 $ 59,038 $ 61,844 $ 64,123
Commercial and farms (1) 74,355 71,487 69,060 66,286 63,257 64,122 64,019
Industrial (1) 37,453 37,952 38,354 36,442 35,607 34,408 29,981
Sales for resale 10,238 19,110 19,066 18,107 11,126 11,330 6,330
Other electric 11,004 11,021 9,645 9,288 8,077 7,752 7,768
-------- -------- -------- -------- -------- -------- --------
Total electric $199,345 $203,925 $198,812 $192,290 $177,105 $179,456 $172,221
Health services 61,697 50,896 45,555 32,068 -- -- --
Manufacturing 56,868 38,690 13,083 8,473 -- -- --
Other business operations 43,829 32,818 29,276 32,396 32,433 20,389 --
-------- -------- -------- -------- -------- -------- --------
Total operating revenues $361,739 $326,329 $286,726 $265,227 $209,538 $199,845 $172,221
Net income $ 29,955 $ 28,945 $ 28,475 $ 27,369 $ 26,538 $ 26,096 $ 24,013
Cash flow from operations $ 67,145 $ 58,077 $ 51,832 $ 53,255 $ 44,866 $ 46,667 N/A
Total assets $662,287 $609,196 $578,972 $563,905 $530,456 $491,633 $480,621
Long-term debt $160,492 $168,261 $162,196 $166,563 $159,295 $146,326 $130,032
Redeemable preferred $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 18,000 $ 13,150 $ 18,145
Common shares outstanding
(2) (thousands) 11,215 11,180 11,180 11,180 11,180 11,185 11,961
Number of common
shareholders (3) 13,829 13,933 14,115 13,634 13,812 13,928 14,994
Earnings per common share (4) $2.47 $2.38 $2.34 $2.23 $2.17 $2.15 $1.78
Dividends per common share $1.80 $1.76 $1.72 $1.68 $1.64 $1.60 $1.42
- ----------------------------------------------------------------------------------------------------------
Notes:
(1) Customer classifications were redefined in 1996. Customers with demand less than
1000 kw previously classified as industrial are now classified as commercial.
(2) Number of shares outstanding at year-end.
(3) Holders of record at year-end.
(4) Based on average number of shares outstanding.
Management's discussion and analysis of
financial condition and results of operations
Management's major financial objective is to increase shareholder value by
continuing to earn a reasonable return on the Company's capital. This will
enable the Company to preserve and enhance its financial capability by
maintaining acceptable capitalization ratios, maintaining a strong interest
coverage position, providing a reasonable return to the common shareholder,
maintaining an above average level of internal cash generation, and
preserving strong credit ratings on outstanding securities to the benefit
of both the Company's customers and its shareholders.
Liquidity: Liquidity is the ability to generate adequate amounts of cash
to meet the Company's needs, both short-term and long-term. Historically,
the Company's liquidity has been a function of its capital project
expenditures and debt service requirements, its net internal funds
generation and its access to long-term securities markets and credit
facilities for external capital.
Over the years, the Company has achieved a high degree of long-term
liquidity by maintaining desired capitalization ratios and strong bond
ratings, implementing cost-containment programs, evaluating operations and
projects on a cost-benefit approach, investing in projects that enhance
shareholder value, and obtaining adequate depreciation rates.
Cash provided by operating activities of $67,145,000 along with net
proceeds from the issuance of short-term debt of $25,600,000 as shown on
the Consolidated Statement of Cash Flows for the year ended December 31,
1996, combined with funds on hand of $4,075,000 at December 31, 1995,
allowed the Company to finance its capital expenditures, pay dividends, and
provide for a majority of its investments in additional nonutility
businesses. Proceeds from the issuance of long-term debt net of payments
for the retirement of long-term debt of $5,700,000 for the year ended
December 31, 1996, were used to finance equipment purchases at the
Company's medical and manufacturing subsidiaries and to finance a portion
of the investments in additional nonutility businesses. The Company had
$1.2 million in cash, cash equivalents and temporary cash investments at
December 31, 1996, along with $21,725,000 available in unused lines of
credit which could be used to supplement cash needs.
The Company estimates that funds internally generated net of forecasted
dividend payments, 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 a majority of its estimated 1997-2001 consolidated
capital project expenditures.
Additional short-term or long-term financing will be required in the period
1997-2001 in connection with the following items:
- - A portion of the Company's estimated capital project expenditures.
- - Maturity of First Mortgage Bonds, $18,800,000 in 1997, and Long-Term
Lease Obligation, $2,200,000 in 1998.
- - In the event the Company decides to refund or retire early any of its
presently outstanding debt or cumulative preferred shares.
- - Other corporate purposes.
Capital Requirements: The Company has a construction and capital
investment program to provide facilities necessary to meet forecasted
customer demands and provide reliable service in the capital intensive
electric utility business. This includes improvements to existing power
plants, acquisition or construction of additional generating capacity, and
upgrading or replacing portions of the distribution and transmission
systems and other buildings and equipment. The construction program is
subject to continuing review and is revised annually in light of changes in
demands for energy, environmental laws, technology affecting the electric
utility industry, the costs of labor, materials and equipment, and the
Company's financial condition (including cash flow and earnings).
The subsidiaries capital requirements include periodic and timely
replacement of technically obsolete or worn out equipment, new equipment
purchases, and plant upgrades to accommodate anticipated growth.
Capital project expenditures for the years 1996, 1995, and 1994 were $64
million, $37 million, and $30 million, respectively. Actual 1996 cash
expenditures in excess of previously reported accrual-based estimates, and
1995 actual expenditures reflect: 1)reductions in capital related payables
at year-end 1996, compared to year-end 1995, at the electric utility,
2)$8 million in diagnostic medical equipment purchases by the health services
subsidiary acquired in April 1996, 3)accelerated replacement of equipment
at another of the Company's health services subsidiaries, 4)the purchase
and expansion of a building formerly being leased by a manufacturing
subsidiary and, 5)the purchase of a building by the Company's radio
broadcasting subsidiary.
The estimated capital expenditures for 1997 are $39 million, and the total
expenditures for the five-year period 1997-2001 are expected to be
approximately $169 million. The breakdown of 1996 actual and 1997-2001
estimated capital project expenditures by segment is as follows:
1996 1997 1997-2001
---- ---- ---------
(in millions)
Electric utility $38 $25 $127
Health services 16 6 18
Manufacturing 5 4 12
Other business operations 5 4 12
In addition to these capital requirements, funds totaling approximately
$84,808,000 will be needed during the five-year period 1997 through 2001 to
retire First Mortgage Bonds and other long-term obligations, including
subsidiary long-term obligations, at maturity and through sinking fund
payments.
Capital Resources: Financial flexibility is provided by unused lines of
credit, financial coverages in excess of the minimum levels required for
issuance of securities, and strong credit ratings.
On August 30, 1996, the Company filed a shelf registration statement with
the Securities and Exchange Commission for the issuance of up to
$50,000,000 of its debt securities, which may be sold from time to time in
one or more series, the proceeds of which will be used to repay short-term
and other indebtedness, to redeem one or more of the outstanding series of
the Company's First Mortgage Bonds and for general corporate purposes.
On August 30, 1996, the Company also filed a shelf registration statement
with the Securities and Exchange Commission for the issuance of up to
1,000,000 common shares pursuant to the Company's Automatic Dividend
Reinvestment and Share Purchase Plan (the Plan), which will permit shares
purchased by shareholders, employees, or customers who participate in the
Plan to be either new issue common shares or common shares purchased on the
open market. In December 1996 the Company began issuing newly issued
common shares to fulfill the requirements of the Plan, resulting in the
issuance of 34,516 common shares and proceeds to the Company of $1,130,000
in 1996. The Company estimates that it could raise approximately $6 million
per year in new capital if new issue common shares are used to fulfill all
requirements of the Plan in 1997 and beyond. Proceeds from newly issued
common shares will be used for general corporate purposes.
The Company also plans to fulfill part of the share purchase requirements
of its leveraged employee stock ownership plan (ESOP) in 1997, and possibly
in 1998, and 1999, with newly issued common shares, which could provide the
Company with up to $2.8 million of capital each year.
As of December 31, 1996, unused credit lines totaling $21.7 million were
available to meet interim financing of working capital and other capital
requirements, if needed. The Company had $25,600,000 in short-term
borrowings outstanding as of December 31, 1996. The subsidiary companies
had $7 million of credit lines in use at December 31, 1996, classified as
current maturities and long-term debt. (See note 9 to financial statements
for further information.)
During 1996 the Company's coverage ratios declined slightly from 1995
levels. The fixed charge coverage ratio after taxes was 3.0 for 1996, as
compared to 3.2 in 1995. The long-term debt interest coverage ratio before
taxes was 3.9 for 1996, as compared to 4.3 in 1995. The Company expects
these coverages to increase slightly in 1997.
The Company's credit ratings affect its access to the capital market. The
current credit ratings for the Company's First Mortgage Bonds are as
follows:
Moody's Investors Service Aa3
Duff and Phelps AA
Fitch Investors Service AA
Standard and Poor's AA-
The Company's disclosure of these security ratings is not a recommendation
to buy, sell, or hold the Company's securities.
As of December 31, 1996, the Company had the capacity under its Indenture
of Mortgage to issue an additional $138 million principal amount of First
Mortgage Bonds.
Results of operations:
Electric operations:
Otter Tail Power Company provides electrical service to nearly 125,000
customers in a service territory of over 50,000 square miles.
Operating revenues
- ------------------
The change in revenues may be summarized as follows:
Revenue increase(decrease)
from prior year
1996 1995 1994
------ ------ ------
(in thousands)
Volume variance (1) $ (499) $ 5,419 $ 6,979
Price variance (2) (3,985) (1,517) (492)
Other (96) 1,211 35
------- ------- -------
Total Electric $(4,580) $ 5,113 $ 6,522
(1) Derived for each customer class by multiplying year-to-year change in
units sold by the average revenue per kwh for the prior year.
(2) Derived for each customer class by multiplying the year-to-year change
in average revenue per kwh by the units sold during the year.
The 1996 volume variance was mainly due to a decrease in noncontractual
power pool kwh sales partially offset by a 4% increase in retail kwh sales.
A number of factors contributed to the decrease in noncontractual power
pool sales. Midcontinent Area Power Pool (MAPP) transmission service
charges have made it less economical to ship energy over long distances.
The summer of 1996 was milder than the summer of 1995 and high water levels
in the summer of 1996 furnished MAPP's hydro generators with an excess of
low-priced electricity to market. In addition to external factors, lower
plant availability in 1996 due to scheduled outages at both Hoot Lake Unit
3 and Big Stone Plant also contributed to the decrease in noncontractual
power pool sales.
The 1995 volume variance was due to a 3.4% increase in retail kwh sales.
The increase in retail kwh sales was due to increased sales in each
customer class: residential, commercial, and industrial. Total power pool
sales decreased by 1% from the previous year. Noncontractual power pool
sales increased due to a combination of warmer weather and greater plant
availability in 1995 which resulted in more opportunity sales. This
increase was offset by a 53.7% decrease in contractual power pool sales.
The 1994 volume variance was due to a 3.6% increase in retail kwh sales.
The increase in retail kwh sales was principally due to increased sales to
commercial and industrial customers. Power pool sales remained at the same
level as in the previous year. Noncontractual power pool sales declined in
1994 because of the exceptionally high level of sales in 1993. However,
contractual power pool sales were up significantly in 1994 because of a
large sale to another utility.
Heating degree days, which generally correlate to increases or decreases in
usage by residential customers, were 10,349 for 1996, 9,326 for 1995, and
9,204 for 1994. The average revenue per retail kilowatt-hour was 5.35 cents in
1996, 5.45 cents in 1995, and 5.50 cents in 1994.
The 1996 price variance relates to lower fuel costs at Big Stone Plant
being passed on to customers through the cost of energy adjustment clause
and lower rates charged to one of the Company's largest industrial
customers under the Company's recently developed Large General Service
Time-of-Use Rider.
The 1995 price variance was primarily attributed to residential and
commercial sales, sales to a large industrial customer, and the cost of
energy adjustment clause. The negative variance in these categories was
partially offset by a positive price variance in contractual power pool
sales. The increase in contractual power pool sales revenue per kwh sold
resulted from spreading a fixed demand charge over a decrease in kwh sales.
The 1994 price variance was essentially due to increased sales to
industrial customers and increased contractual power pool sales. The
decrease in contractual power pool sales revenue per kwh sold resulted from
spreading a fixed demand charge over an increase in kwh sales.
The change in electric revenue attributed to factors other than price and
volume variances in 1996 reflects an increase in conservation program
revenues recognized in 1996, offset by a decrease of $614,000 in North
Dakota unbilled revenues as a result of the three year phase-in period for
the initial recognition of these revenues ending in 1995. (See note 1 to
financial statements for further information.) The increase in electric
revenue related to other factors in 1995 reflects an increase in unbilled
revenue of $388,000 over 1994 and the initial recognition of conservation
program revenues and wheeling service fees in 1995.
Expenses
- --------
The percentage changes in operating expenses may be summarized as follows:
Percentage increase (decrease)
from prior year
1996 1995 1994
---- ---- ----
Production fuel (12) (2) 3
Purchased power (7) 7 5
Electric operation expenses 3 13 2
Electric maintenance 8 (11) 6
Depreciation and amortization 2 3 4
Property taxes 8 (6) 6
Production fuel and purchased power expense
- -------------------------------------------
The 12% decrease in production fuel expense in 1996 was the result of
declines in fuel expenses at all three of the Company's major power plants
due to decreases in fuel costs per kwh at Big Stone and Hoot Lake and
decreases in net generation at Big Stone and Coyote. Two factors
contributing to the decrease in system wide generation in 1996 were lower
demand as a result of fewer noncontractual power pool sales and scheduled
maintenance shutdowns at Hoot Lake and Big Stone Plants. In 1995 the cost
of steam production fuel per kwh generated decreased by 4.1% while the
total kwhs generated increased by 1.6%, which, in combination, contributed
to the 2% decrease in 1995 production fuel expense compared to 1994. The
decrease in fuel cost per unit of generation in 1996 and 1995 resulted
mainly from switching fuels at Big Stone Plant from lignite to higher-Btu
subbituminous coal in August 1995. The 3% increase in production fuel in
1994 resulted chiefly from a 3.2% increase in generation.
The 7% decrease in purchased power in 1996 reflects a 45% decrease in kwh
purchases for resale partially offset by a 21% increase in purchases for
system use. The decrease in purchases for resale correlates to the
decrease in noncontractual power pool sales. The purchase of replacement
generation for planned plant outages was the major factor contributing to
the increase in purchases for system use. The 7% increase in purchased
power in 1995 was due to increased kwh purchases for system use, which
correlates to the increase in retail sales. Purchased power increased 5%
in 1994 essentially because of an increase in cost per kwh purchased. The
bulk of the increase in cost per kwh purchased resulted from an increase in
replacement generation cost for plant outages.
The increase or decrease in fuel and purchased power costs arising from
changing prices results in adjustments to the Company's rate schedules
through the cost of energy adjustment clause. Over the last five years
this has resulted in savings of nearly $39 million to the Company's
customers.
Electric operation and maintenance expenses
- -------------------------------------------
The 3% increase in electric operation expenses for 1996 was mainly due to
increased benefit costs resulting from revised actuarial assumptions for
the Company's Executive Survivor and Supplemental Retirement Plan (see note
8 to financial statements for further information) and increased payments
for contracted services offset by a decrease in economic development
expenditures that were lower than the increased levels recorded in 1995.
The increase in electric operating expense of 13% in 1995 was primarily due
to a settlement with the Minnesota Public Utilities Commission requiring
recovery of Conservation Improvement Program costs in current rates
starting in 1995 and an increase in postretirement health-care benefit
costs resulting from a plan amendment which reduces the health insurance
contribution requirements for surviving spouses of retired employees. (See
notes 3 and 8 to financial statements for further information.) Storm-
related expenses in the summer and fall of 1995 along with 1995 economic
development expenditures and wage and salary increases also contributed to
the increase in electric operating expense.
The 1994 increase of 2% in electric operating expense resulted principally
from increases in customer account expenses and payroll expenses.
The majority of the increase in electric maintenance expense of 8% in 1996
was due to increased production plant maintenance expenses. Hoot Lake Unit
3 was down for scheduled maintenance in February and March of 1996 and had
a turbine rebuild and steam chest replacement in July 1996. Big Stone
Plant underwent a scheduled ten-week major overhaul in September, October
and November of 1996.
The 11% decrease in electric maintenance expense in 1995 was mainly due to
significant reductions in power plant maintenance expenses. Coyote Plant,
which had a major overhaul in the spring of 1994 but no major overhauls in
1995, was the primary contributor to the reduction in maintenance expenses.
Lower maintenance expenses on Hoot Lake Plant Unit 2, which underwent major
repairs in the summer of 1994, also contributed to the decrease.
The increase in electric maintenance expense of 6% in 1994 was due to
increases in production and distribution maintenance. Production
maintenance increased because of boiler repairs at Coyote Plant.
Distribution maintenance increased due to more tree-trimming expenses.
Depreciation and amortization
- -----------------------------
The increases in depreciation and amortization expense of 2% in 1996, 3% in
1995 and 4% in 1994 were attributable to additions to plant in service from
capital expenditures.
Property taxes
- --------------
The 8% increase in property taxes in 1996 was due to a 10% increase in the
assessed value of the Company's South Dakota utility property compounded by
a 14% increase in the mill rates applied to that property. The 6% decrease
in property taxes in 1995 was mainly due to decreased property tax rates in
Minnesota and valuation decreases in South Dakota. The increase in
property taxes of 6% for 1994 was due to property additions and increased
mill rates.
Health services operations:
Health services operations include businesses which are involved in the
sale, service, rental, refurbishing, and operation of medical imaging
equipment and the sale of related supplies and accessories to various
medical institutions, primarily in the Midwest. Initial acquisitions of
businesses in this segment were made in 1993. Two companies were acquired
in 1996: one in February, and a second more significant acquisition in
April. (See note 2 to financial statements for more information.)
1996 1995 1994
------ ------ ------
(in thousands)
Operating revenues $61,697 $50,896 $45,555
Cost of goods sold 40,224 31,576 28,690
Operating expenses 16,336 15,739 14,379
------- ------- -------
Operating income $ 5,137 $ 3,581 $ 2,486
The increases in health services revenue of 21% and cost of goods sold of
27% in 1996, as compared to 1995, were due to acquisitions of two health
services companies. The 12% increase in health services operating revenues
in 1995 was due to increased sales of medical equipment in 1995 compared to
1994. The acquisition of three additional diagnostic imaging companies in
January 1995 also contributed to the increase in operating revenues. The
increase in cost of goods sold in 1995 compared to 1994 was directly
related to the 1995 increase in equipment sales.
Manufacturing operations:
Manufacturing operations is made up of businesses involved in the
production of agricultural equipment, plastic pipe extrusion, and metal
parts stamping and fabrication. Initial acquisitions of businesses in this
segment were made in 1990. No additional companies were acquired in 1996.
1996 1995 1994
------ ------ ------
(in thousands)
Operating revenues $56,868 $38,690 $13,083
Cost of goods sold 43,745 29,884 9,167
Operating expenses 7,700 5,536 1,475
------- ------- -------
Operating income $ 5,423 $ 3,270 $ 2,441
The 47% increase in manufacturing operating revenues in 1996 reflects
revenues from Northern Pipe Products, acquired in October of 1995, and
increased sales at BTD Manufacturing. The 46% increase in manufacturing
cost of goods sold and 39% increase in operating expenses in 1996 were
directly related to the increase in manufacturing revenue. The increases
in 1995 operating revenues and 1995 cost of goods sold and operating
expenses resulted principally from the acquisitions of Northern Pipe
Products and BTD Manufacturing in 1995 and sales in expanded product lines
of companies acquired prior to 1995.
Other business operations:
The Company's other business operations include a telephone utility and
businesses involved in electrical and telephone construction contracting,
radio broadcasting, and waste incinerating. In 1996 the Company's
subsidiary, Mid-States Development, Inc., acquired four radio stations, and
the Company's telecommunications subsidiary, North Central Utilities, Inc.
(NCU), acquired two small cable TV systems. On January 2, 1997, NCU
acquired The Peoples Telephone Co. of Bigfork (Peoples) in a pooling-of-
interests transaction. Peoples, with 1,903 access lines serving five
communities in Northern Minnesota, had 1996 revenues of $1.6 million. (See
note 2 to financial statements for more information.)
1996 1995 1994
------ ------ ------
(in thousands)
Operating revenues $43,829 $32,818 $29,276
Cost of goods sold 28,297 18,954 16,903
Operating expenses 13,145 10,333 9,247
------- ------- -------
Operating income $ 2,387 $ 3,531 $ 3,126
The 34% increase in operating revenue in 1996, as compared to 1995,
reflects material cost pass through billings by the Company's construction
subsidiaries on material intensive jobs. The increase in material costs
billed is also reflected in the 49% increase in cost of goods sold from
other business operations. The increase of 27% in 1996 operating expenses
as compared to 1995 was due to increased construction activity and non-
recurring expenses associated with the acquisition of four radio stations
in 1996. (See note 2 to financial statements for more information.)
Operating revenues increased 12% in 1995, of which half was attributable to
increased construction revenues related to material cost billings on large
projects with a commensurate increase in cost of goods sold. The remaining
increases in revenues and operating income were due to modest contributions
from all other businesses in 1995.
Consolidated other income and deductions--net:
The increase in other income and deductions--net in 1996, as compared to
1995, reflects a reduction in miscellaneous expenses at the health services
subsidiaries in 1996 and losses on marketable securities recognized in 1995
related to the Company's preferred stock investment program which ended in
October of 1995.
Consolidated interest charges:
Interest charges increased 10% in 1996 as a result of increased debt at the
Company's subsidiaries due to acquisitions and growth and to an increase in
the use of short-term debt at the parent-company level. Interest charges
increased 11% in 1995 due to new business acquisitions.
Consolidated income taxes:
The 13% decrease in income taxes in 1996, compared to 1995, was the result
of net capital losses realized in 1995 on the sale of marketable securities
not generating tax savings, the initial recording of affordable housing
tax credits in 1996, and reversal of taxes previously deferred at rates
higher than current tax rates. (See note 11 and "Investments" under note 1
to financial statements for more information.)
Impact of inflation:
For an electric utility, the regulatory process limits the amount of
depreciation expense included in the Company's revenue allowance and limits
electric utility plant in the rate base to original cost. Such amounts
produce cash flows that are inadequate to replace such property in the
future or preserve the purchasing power of common equity capital previously
invested. Under continuation of the current regulatory process, the
Company expects that it will be able to establish rates that will cover the
increased costs of new plant when such costs are incurred. The Company
operates under regulatory provisions that allow price increases in the cost
of fuel and purchased power to be passed to customers through automatic
adjustments to its rate schedules under the cost of energy adjustment
clause. For the past eight years this has resulted in lower retail
electric rates. Other increases in the cost of electric service must be
recovered through timely filings for rate relief with the appropriate
regulatory agency.
The Company's health services, manufacturing and other business operations
consist almost entirely of unregulated businesses. Increased operating
costs are reflected in product or services pricing with any limitations on
price increases determined by the marketplace.
Factors affecting future earnings:
Growth of electric revenue
- --------------------------
The results of operations discussed above are not necessarily indicative of
future earnings. Anticipated higher operating costs and carrying charges
on increased investment in plant, if not offset by proportionate increases
in operating revenues and other income (either by appropriate rate
increases, increases in unit sales, or increases in nonelectric
operations), will affect future earnings.
Growth in electric sales will be subject to a number of factors, including
the volume of power pool sales to other utilities, the effectiveness of
demand-side management programs, weather, competition, and the rate of
economic growth or decline in the Company's service area. The Company's
electric business is primarily dependent upon the use of electricity by
customers in our service area. Percentage changes in the Company's
electric kwh sales to retail customers over the prior year for the last
three years were increases of 4.0% in 1996, 3.4% in 1995, and 3.6% in 1994.
Market factors beyond the Company's control such as mergers and
acquisitions, geographical location, transmission costs and uncertainty
about the impact of deregulation may contribute to a continued decline in
noncontractual power pool sales. However, the relative effect of the
decrease in noncontractual power pool sales on earnings is less than its
proportionate effect on the decrease in electric revenues due to the
relatively low margin of profits on these sales.
Rates of return earned on utility operations are subject to review by the
various state commissions that have jurisdiction over the electric rates
charged by the Company. These reviews may result in future revenue
reductions when actual rates of return are deemed by regulators to be in
excess of allowed rates of return.
Demand-side management
- ----------------------
Demand-side management (DSM) efforts will continue in all jurisdictions
served by the Company. The goal of DSM is to encourage the wise and
efficient use of electricity by customers. Currently, Minnesota is the
only jurisdiction that mandates investments in DSM.
In 1994 the Company filed a petition with the Minnesota Public Utilities
Commission (MPUC) for approval of an annual recovery mechanism for DSM-
related costs under Minnesota's Conservation Improvement Programs (CIP).
An intervenor on behalf of the Large General Service Group filed comments
against the petition and requested the MPUC to order a general rate case to
review the Company's earnings levels. In the interest of rate stability
the Company reached an agreement, which was approved by the MPUC, resulting
in costs to the Company of approximately $2.2 million each year for three
years being absorbed in current rates starting in 1995.
In 1996 the MPUC approved the Company's 1995 financial incentive filing
along with a 1.25% surcharge on all Minnesota customers' bills starting on
July 1, 1996, for the recovery of conservation-related costs over and above
those being recovered in current rates. The approved surcharge in effect
from July 1, 1995, through June 30, 1996, was .5030%. The surcharge
approvals resulted in earnings of approximately $655,000 in 1996 and
$620,000 in 1995 due to recognition of revenue related to CIP impacts on
1996, 1995, and 1994 energy consumption. The current surcharge rate will
be in place until June 30, 1997, when it will be revised for subsequent
years' program results.
Energy adjustment clause
- ------------------------
The Company began purchasing subbituminous coal for Big Stone Plant in
August 1995 under a new coal contract that runs through December 1999.
Price reductions, in addition to plant efficiency gains due to switching
from lignite to higher-Btu subbituminous coal, have resulted in cost
reductions. The majority of these reductions have been, and continue to
be, passed on to retail electric customers through the cost of energy
adjustment clause, which enhances the Company's competitive position.
In November 1995 the Company and two other Coyote Plant partners initiated
a lawsuit against Knife River Coal Mining Company and its parent, MDU
Resources Group, in an attempt to resolve disputes over the pricing
mechanism included in the Coyote coal agreement. The case has been
remanded to arbitration to determine if the items under dispute are
arbitrable. Any fuel cost savings that may result from resolution of this
dispute will be passed on to customers through the cost of energy
adjustment clause.
Environmental regulation
- ------------------------
Under current regulations the Federal Clean Air Act (the Act) is not
expected to have a significant impact on future capital requirements or
operating costs. However, proposed or future regulations under the Act,
changes in the future coal supply market, and/or other laws and regulations
could impact such requirements or costs. It is anticipated that, under
current regulatory principles, any such costs could be recovered through
rates.
The Company's plants are not subject to the Act's phase one requirements.
Phase two standards of the Act must be met by the year 2000. The Company
intends that Big Stone Plant will maintain current levels of operation and
meet phase two requirements for sulfur dioxide emissions by burning
subbituminous coal, which is much lower in sulfur emissions than lignite.
As stated previously, Big Stone Plant's new coal contract expires at the
end of 1999. The cost of subbituminous coal in 2000 and beyond will
probably be higher than the current market price but will likely not
adversely affect the Company's power plant operations. Under recently
proposed regulations, modifications would be required at Big Stone Plant by
2000 to satisfy proposed nitrogen oxide emission standards. The Company is
a member of the Utility Air Regulatory Group (UARG), which has filed a
petition in Federal Court for reconsideration of the standards based on
inconsistencies in current laws. Compliance costs will depend on the
regulations that are ultimately adopted and the cost of available
technologies.
The Company's Coyote Plant is equipped with sulfur dioxide removal
equipment. Compliance with the phase two requirements is not expected to
significantly impact operations at that plant. Hoot Lake Plant already
uses low-sulfur subbituminous coal. Minor modifications may be required at
Hoot Lake Plant to meet the phase two nitrogen oxide emission requirements
by 2000.
Competition
- -----------
In 1995 the Federal Energy Regulatory Commission (FERC) issued a Notice of
Proposed Rulemaking (NOPR) to promote competition and deregulation in
wholesale electric markets by requiring owners of transmission facilities
to offer nondiscriminatory open-access transmission and ancillary services
to wholesale sellers and purchasers of electric energy in interstate
commerce. On April 24, 1996, the FERC issued two final rules, Order Nos.
888 and 889, which may have a potentially significant impact on wholesale
markets.
Order No. 888, effective July 9, 1996, requires electric utilities and
other transmission users to abide by comparable terms, conditions and
pricing in transmitting power. The Company filed its initial transmission
tariff on July 9, 1996, as required by Order No. 888. A revised rate
schedule will become effective in the first quarter of 1997.
Order No. 889, which became effective January 3, 1997, requires public
utilities to implement Standards of Conduct and an Open Access Same-Time
Information System (OASIS). These rules require transmission personnel to
provide information about their transmission systems to all customers,
including their associates within their respective companies, through the
OASIS.
The state utility commissions in Minnesota and North Dakota are currently
investigating the impact of electric utility industry restructuring and the
prospects for reregulation and retail competition in their respective
jurisdictions. To date, the MPUC and the NDPSC have issued no new policies
or rulemakings regarding this issue. The South Dakota PUC has not taken
any action with regards to industry restructuring or retail competition.
The Company is taking a number of steps to position itself for success in a
competitive marketplace. It has initiated the process of functionally
unbundling its generation, transmission, distribution and energy services
operations by setting up distinct separate business units in each of these
areas. The Company is developing the necessary accounting systems to
capture costs and determine the profitability of each of these units and to
identify areas for improvement and opportunities for increased
profitability. The Company is establishing an energy services business
unit to promote the energy related products and services that have always
been offered to its customers and to develop new products and services to
be offered to current and potential customers in order to distinguish
itself from the competition.
As the electric industry evolves and becomes more competitive, the Company
believes it is well positioned to maintain its customer base and may have
opportunities to increase its market share. The Company's generation
capacity appears poised for competition due to unit heat rate improvements
and reductions in fuel and freight costs. A comparison of the Company's
electric retail rates with the rates of other investor-owned utilities,
cooperatives, and municipals in the states the Company serves indicates
that its rates are competitive. In addition, the Company would attempt
more flexible pricing strategies under an open, competitive environment.
The year 2000 (millennium) bug
- ------------------------------
The Company does not expect to incur significant costs over the next three
years to modify software programs to accommodate the year 2000 because
coding standards used when the programs were written have enabled the
Company to programmatically identify and locate the code that needs to be
changed on all programs written in-house. The Company anticipates that it
will be able to cover any conversion costs within current operating budget
levels. Additionally, the Company has replaced or is in the process of
updating or replacing a number of its financial application and other
operating programs within the normal course of business. The new software
will accommodate the millennium change.
Diversification
- ---------------
The Company continues to investigate acquisitions of additional businesses
(both utility and nonutility) and expects continued growth in this area.
The success of these businesses and any future business purchases will
affect future earnings.
Quadrant Co., the Company's waste incineration subsidiary, continues to
provide primary service to one of its two steam customers under an
agreement which can be terminated by either party upon one year's prior
written notice. Quadrant is currently providing backup service to its
other steam customer under an agreement that commenced on June 1, 1996 and
terminates on May 31, 1998, subject to earlier termination by either party
upon 90 days' written notice. Quadrant also continues to burn municipal
solid waste for three Minnesota counties under a contract extension which
expires April 1, 1997. Two Minnesota counties, representing about 40% of
Quadrant's processing capacity, did not renew or extend their contracts for
waste incineration which expired in September 1996.
Quadrant is in the process of negotiating new waste incineration agreements
with the remaining counties and is pursuing additional incineration
contracts. New pollution rules for Minnesota municipal waste incinerators
have recently been issued. The costs to be in compliance with the new
rules by the year 2000, combined with a decline in future revenues from
decreased steam sales and the loss of the two counties' waste streams
threaten the economic viability of the plant. Quadrant is currently
generating positive cash flows from the operation of its plant, which had a
net undepreciated book value of approximately $3.2 million on December 31,
1996. However, the outcome of current incineration contract negotiations
could result in an impairment issue under SFAS 121. Prospects for new
incineration contracts are positive but the range of prices being
considered results in a wide variance in estimates of future cash flows,
making it impossible to accurately calculate an impairment value at this
time.
The majority of the subsidiary companies' long-term debt is variable
interest rate debt. Any increase in prime lending rates would result in
increased interest expense and have a negative impact on future earnings.
Accounting pronouncements
- -------------------------
In March 1995 the Financial Accounting Standards Board issued SFAS 121 -
Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of, which became effective for the Company's
financial statements in 1996. The nature of utility regulation generally
provides for the recovery of amounts invested in utility assets used to
serve customers, over a specified period of time, through approved service
rates and allowed rates of return on rate base. Currently, most of the
Company's utility revenues are subject to regulation. The Company has
determined that the carrying amounts of all its long-lived assets and
identifiable intangibles at December 31, 1996, for both its utility and
subsidiary operations are recoverable through expected future cash flows
from the use of those assets.
In October 1995 the Financial Accounting Standards Board issued SFAS 123 -
Accounting for Stock-Based Compensation, which became effective for the
Company's financial statements in 1996. The statement establishes
financial accounting and reporting standards for stock-based employee
compensation. As of December 31, 1996, the Company had no stock-based
employee compensation programs that are subject to SFAS 123 reporting
requirements.
Cautionary Statements for Purposes of the Safe Harbor
Provisions of the Private Securities Litigation Reform Act of 1995
- ------------------------------------------------------------------
The information in this annual report includes forward-looking statements.
Important risks and uncertainties that could cause actual results to differ
materially from those discussed in such forward-looking statements are set
forth above under "Factors affecting future earnings." Other risks and
uncertainties may be detailed from time to time in the Company's future
Securities and Exchange Commission filings.
Independent Auditors' Report
To the Shareholders of Otter Tail Power Company:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Otter Tail Power Company and its subsidiaries (the
Company) as of December 31, 1996, and 1995, and the related consolidated
statements of income, retained earnings, and cash flows for each of the
three years in the period ended December 31, 1996. These consolidated
financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the consolidated financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
consolidated financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December
31, 1996, and 1995, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
January 29, 1997
Minneapolis, Minnesota
Otter Tail Power Company
Consolidated Balance Sheets, December 31 1996 1995
- ----------------------------------------------------------------------------------------
(in thousands)
Assets
Plant:
Electric plant in service $742,065 $715,305
Subsidiary companies 93,975 54,266
-------- --------
Total 836,040 769,571
Less accumulated depreciation and amortization 327,672 308,174
-------- --------
508,368 461,397
Construction work in progress 11,470 16,285
-------- --------
Net plant 519,838 477,682
-------- --------
Investments 19,880 12,716
-------- --------
Intangibles--net 21,954 18,902
-------- --------
Other assets 6,553 7,732
-------- --------
Current assets:
Cash and cash equivalents 1,229 1,867
Temporary cash investments -- 2,208
Accounts receivable:
Trade (less accumulated provision for uncollectible accounts:
1996, $690,000; 1995, $398,000) 32,590 31,184
Other 5,018 8,276
Materials and supplies:
Fuel 3,220 3,322
Inventory, materials and operating supplies 23,778 19,408
Deferred income taxes 4,550 3,754
Accrued utility revenues 5,349 4,328
Other 4,537 4,427
-------- --------
Total current assets 80,271 78,774
-------- --------
Deferred debits:
Unamortized debt expense and reacquisition premiums 4,270 4,687
Regulatory assets 5,866 5,727
Other 3,655 2,976
-------- --------
Total deferred debits 13,791 13,390
-------- --------
Total $662,287 $609,196
======== ========
See accompanying notes to consolidated financial statements.
Otter Tail Power Company
Consolidated Balance Sheets, December 31 1996 1995
- ----------------------------------------------------------------------------------------
(in thousands)
Liabilities
Capitalization (page 38):
Common shares, par value $5 per share -- authorized, 25,000,000
shares; outstanding, 1996 11,214,652; 1995 11,180,136 shares $ 56,073 $ 55,901
Premium on common shares 31,271 30,335
Retained earnings 105,882 98,006
-------- --------
Total 193,226 184,242
Cumulative preferred shares:
Subject to mandatory redemption 18,000 18,000
Other 20,831 20,831
Long-term debt 160,492 168,261
-------- --------
Total capitalization 392,549 391,334
-------- --------
Current liabilities:
Short-term debt 25,600 --
Sinking fund requirements and current maturities 42,136 13,733
Accounts payable 26,587 27,828
Accrued salaries and wages 3,847 3,703
Federal and state income taxes accrued 2,031 393
Other taxes accrued 12,043 11,356
Interest accrued 3,622 3,509
Other 2,822 6,752
-------- --------
Total current liabilities 118,688 67,274
-------- --------
Noncurrent liabilities 16,688 13,498
-------- --------
Commitments (note 6) -- --
-------- --------
Deferred credits:
Accumulated deferred income taxes 98,498 99,398
Accumulated deferred investment tax credit 19,818 20,994
Regulatory liabilities 13,283 14,500
Other 2,763 2,198
-------- --------
Total deferred credits 134,362 137,090
-------- --------
Total $662,287 $609,196
======== ========
See accompanying notes to consolidated financial statements.
Otter Tail Power Company
Consolidated Statements of Income
For the Years Ended December 31 1996 1995 1994
- ----------------------------------------------------------------------------------------
(in thousands, except per share amounts)
Operating revenues:
Electric $199,345 $203,925 $198,812
Health services 61,697 50,896 45,555
Manufacturing 56,868 38,690 13,083
Other business operations 43,829 32,818 29,276
-------- -------- --------
Total operating revenues 361,739 326,329 286,726
Operating expenses:
Production fuel 27,913 31,559 32,311
Purchased power 28,378 30,591 28,717
Electric operation and maintenance expenses 66,401 63,777 59,409
Cost of goods sold 112,266 80,414 54,760
Other nonelectric expenses 34,126 29,111 22,842
Depreciation and amortization 22,904 21,909 21,190
Property taxes 11,525 10,670 11,318
-------- -------- --------
Total operating expenses 303,513 268,031 230,547
Operating income:
Electric 45,279 47,916 48,126
Health services 5,137 3,581 2,486
Manufacturing 5,423 3,270 2,441
Other business operations 2,387 3,531 3,126
-------- -------- --------
Total operating income 58,226 58,298 56,179
Other income and deductions -- net 2,370 1,881 1,864
Interest charges 16,601 15,075 13,687
-------- -------- --------
Income before income taxes 43,995 45,104 44,356
Income taxes 14,040 16,159 15,881
-------- -------- --------
Net income 29,955 28,945 28,475
Preferred dividend requirements 2,358 2,358 2,358
-------- -------- --------
Earnings available for common shares $ 27,597 $ 26,587 $ 26,117
======== ======== ========
Average number of common shares outstanding 11,182 11,180 11,180
Earnings per average common share $2.47 $2.38 $2.34
Dividends per common share $1.80 $1.76 $1.72
See accompanying notes to consolidated financial statements.
Consolidated Statements of Retained Earnings
For the Years Ended December 31 1996 1995 1994
- ----------------------------------------------------------------------------------------
(in thousands)
Retained earnings at beginning of year $ 98,006 $ 90,412 $ 84,209
Net income 29,955 28,945 28,475
Other 403 684 (684)
-------- -------- --------
Total 128,364 120,041 112,000
-------- -------- --------
Dividends paid:
Cumulative preferred shares at required annual rates 2,358 2,358 2,358
Common shares 20,124 19,677 19,230
-------- -------- --------
Total 22,482 22,035 21,588
-------- -------- --------
Retained earnings at end of year $105,882 $ 98,006 $ 90,412
======== ======== ========
See accompanying notes to consolidated financial statements.
Otter Tail Power Company
Consolidated Statements of Cash Flows
For the Years Ended December 31 1996 1995 1994
- ---------------------------------------------------------------------------------------------------
(in thousands)
Cash flows from operating activities:
Net income $ 29,955 $ 28,945 $ 28,475
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 34,788 28,602 25,899
Deferred investment tax credit--net (1,177) (1,177) (1,347)
Deferred income taxes (5,276) 751 1,386
Change in deferred debits and other assets 3,679 (1,792) (1,016)
Change in noncurrent liabilities and deferred credits 3,389 4,560 1,016
Allowance for equity (other) funds used during construction (325) (229) (146)
(Gain)/loss on investments in and disposal of noncurrent assets 308 946 (201)
Cash provided by (used for) current assets and current liabilities:
Change in receivables, materials, and supplies 660 (1,035) (10,712)
Change in other current assets (957) (1,349) (339)
Change in payables and other current liabilities 548 1,436 6,720
Change in interest and income taxes payable 1,553 (1,581) 2,097
-------- -------- --------
Net cash provided by operating activities 67,145 58,077 51,832
-------- -------- --------
Cash flows from investing activities:
Gross capital expenditures (63,951) (37,134) (30,411)
Proceeds from disposal of noncurrent assets 4,649 2,417 2,574
Purchase of subsidiaries, net of cash acquired (10,006) (5,808) (286)
Change in temporary cash investments 2,208 (1,817) 60
Change in marketable securities and other investments (10,609) 13,151 (1,630)
-------- -------- --------
Net cash used in investing activities (77,709) (29,191) (29,693)
-------- -------- --------
Cash flows from financing activities:
Change in short-term debt---net issuances 25,600 (2,900) 2,900
Proceeds from issuance of long-term debt 117,083 54,482 6,433
Proceeds from issuance of common stock 1,130 -- --
Payments for debt and common stock issuance expense (22) -- (56)
Payments for retirement of long-term debt (111,383) (58,418) (11,784)
Dividends paid (22,482) (22,035) (21,588)
-------- -------- --------
Net cash used In financing activities 9,926 (28,871) (24,095)
-------- -------- --------
Net change in cash and cash equivalents (638) 15 (1,956)
Cash and cash equivalents at beginning of year 1,867 1,852 3,808
-------- -------- --------
Cash and cash equivalents at end of year $ 1,229 $ 1,867 $ 1,852
======== ======== ========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized) $ 16,375 $ 14,160 $ 13,160
Income taxes $ 18,759 $ 18,286 $ 14,058
See accompanying notes to consolidated financial statements.
Otter Tail Power Company
Consolidated Statements of Capitalization, December 31 1996 1995
- ----------------------------------------------------------------------------------------
(in thousands)
Total common shareholders' equity $193,226 $184,242
Cumulative preferred shares -- without par value (stated and
liquidating value $100 a share) -- authorized 1,500,000 shares;
outstanding:
Series subject to mandatory redemption
$6.35, 180,000 shares; 9,000 shares due 2002-06;
135,000 shares due 2007 18,000 18,000
-------- --------
Total 18,000 18,000
-------- --------
Other series:
$3.60, 60,000 shares 6,000 6,000
$4.40, 25,000 shares 2,500 2,500
$4.65, 30,000 shares 3,000 3,000
$6.75, 40,000 shares 4,000 4,000
$9.00, 53,311 shares 5,331 5,331
-------- --------
Total other preferred 20,831 20,831
-------- --------
Cumulative preference shares -- without par value, authorized
1,000,000 shares; outstanding: none
Long-term debt:
First mortgage bond series:
8.75%, due December 15, 1997 18,800 19,000
7.25%, due August 1, 2002 19,200 19,400
7.625%, due February 1, 2003 9,240 9,360
8.75%, due September 15, 2021 19,000 19,200
8.25%, due August 1, 2022 28,800 29,100
Pollution control series:
6.10-6.80%, due February 1, 2006, Big Stone project 5,427 5,487
8.125%, due August 1, 2009, Coyote project, series B 830 840
6.10-6.90%, due February 1, 2019, Coyote project 21,734 21,969
-------- --------
Total 123,031 124,356
Subsidiary and other long-term debt:
Long-term lease obligation (5.625% pollution control revenue
bonds due July 1, 1998) 2,200 2,200
Industrial development refunding revenue bonds
5.00% due December 1, 2002 3,010 3,010
Pollution control refunding revenue bonds
variable 4.20% at December 31, 1996, due December 1, 2012 10,400 10,400
Industrial development revenue bond (Quadrant Co. project) -- 200
Obligations of Mid-States Development, Inc.
rates 2.90% to 11.38% at December 31, 1996 56,606 33,496
Obligations of North Central Utilities, Inc.
variable 6.90% to 7.05% at December 31, 1996 8,026 9,013
Other 1 8
-------- --------
Total 203,274 182,683
Less:
Current maturity 41,011 12,408
Sinking fund requirement 1,125 1,325
Unamortized debt discount and premium -- net 646 689
-------- --------
Total long-term debt 160,492 168,261
-------- --------
Total capitalization $392,549 $391,334
======== ========
See accompanying notes to consolidated financial statements.
Otter Tail Power Company
Notes to consolidated financial statements
For the three years ended December 31, 1996
1. Summary of accounting policies
System of accounts -- The accounting records of the Company conform to the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission (FERC), the Public Service Commission of North Dakota, and
the Public Utilities Commissions of Minnesota and South Dakota.
Principles of consolidation -- The consolidated financial statements
include the accounts of the Company and all wholly owned subsidiaries.
All significant intercompany transactions have been eliminated.
Plant, retirements, and depreciation -- Utility plant is stated at
original cost. The cost of additions includes contracted work, direct
labor and materials, allocable overheads, and allowance for funds used
during construction. The cost of depreciable units of property retired
plus removal costs less salvage is charged to the accumulated provision
for depreciation. Maintenance, repairs, and replacement of minor items
of property are charged to operating expenses. Repairs to property made
necessary by storm damage are charged to the reserve therefor. The
provisions for utility depreciation for financial reporting purposes are
made on the straight-line method based on the estimated service lives of
the properties. Such provisions as a percent of the average balance of
depreciable property were 3.00% in 1996, 2.97% in 1995, and 2.98% in
1994.
Property and equipment of nonutility and subsidiary operations are
carried at historical cost, or at the current appraised value if
acquired in a business combination, and are depreciated on a
straight-line basis over the useful lives (3 to 40 years) of the related
assets. Upon sale or retirement of property and equipment, the cost and
related accumulated depreciation are eliminated from the respective
accounts and the resulting gain or loss is included in the consolidated
financial statements.
Jointly owned plants -- The consolidated financial statements include the
Company's 53.9% and 35% ownership interests in the assets, liabilities
and expenses of Big Stone and Coyote Plants, respectively. Amounts at
December 31, 1996 and 1995, included in Plant in Service for Big Stone
were $109,251,000 and $108,577,000, respectively, and the accumulated
provision for depreciation and amortization was $59,078,000 and
$62,486,000, respectively. Amounts at December 31, 1996 and 1995,
included in Plant in Service for Coyote were $145,542,000 and
$143,748,000, respectively, and the accumulated provision for
depreciation and amortization was $58,436,000 and $54,441,000,
respectively. The Company's share of direct expenses of the jointly
owned plants in service is included in the corresponding operating
expenses in the statement of income.
Allowance for funds used during construction (AFC) -- AFC, a noncash item,
is included in construction work in progress based on a composite rate
that assumes that funds used for construction were provided by borrowed
funds and equity funds. The AFC so included in construction work in
progress will ultimately be included in the rate base used in
establishing rates for utility services. The composite rate for AFC was
8.50% for 1996, 9.50% for 1995, and 10.25% for 1994.
Income taxes -- Comprehensive interperiod income tax allocation is used
for substantially all book and tax temporary differences. Deferred
income taxes arise for all temporary differences between the book and
tax basis of assets and liabilities. Deferred taxes are recorded using
the tax rates scheduled by tax law to be in effect when the temporary
differences reverse. The Company amortizes the investment tax credit
over the estimated lives of the related property.
Operating revenues -- Electric customers' meters are read and bills are
rendered on a cycle basis. Prior to 1993 the Company in all of its
jurisdictions recorded electric revenues based on billing dates.
Effective January 1, 1993, due to a North Dakota Public Service
Commission (NDPSC) order, the Company changed its method of revenue
recognition in North Dakota from billing dates to energy delivery dates.
(See note 3 for further information on the order.) The North Dakota
unbilled revenue amount as of January 1, 1993, ($4.4 million) was
amortized to electric revenues over 36 months as required by the order.
The change in method of revenue recognition resulted in additional net
income of $984,000 in 1995 and $751,000 in 1994. The impact on
earnings per share was $.09 in 1995 and $.07 in 1994.
The Company's rate schedules applicable to substantially all customers
include a cost of energy adjustment clause under which the rates are
adjusted to reflect changes in average cost of fuels and purchased
power. Since July 1, 1995, rate schedules applicable to Minnesota
customers also include a surcharge for recovery of conservation-related
expenses: 1.25% as of July 1, 1996 and .5030% from July 1, 1995, through
June 30, 1996. (See further discussion under note 3.)
Health services' operating revenues on major equipment and installation
contracts are recorded using the percentage-of-completion method.
Amounts received in advance under customer service contracts are
deferred and recognized on a straight-line basis over the contract
period.
Manufacturing operating revenues are recorded when products are shipped,
when services are rendered, and on a percentage-of-completion basis for
large items that are assembled over several months.
Other business operations' operating revenues are recorded when services
are rendered or products are shipped. In the case of construction
contracts, the percentage-of-completion method is used.
Storm damage reserve -- The Company is required under its Indenture of
Mortgage to make annual provisions for storm damage of not less than .5%
of gross electric operating revenues. Provisions for loss have been
used in determining rates approved by the applicable regulatory
commissions. Provisions for 1996, 1995, and 1994 were $1,247,000,
$1,800,000, and $995,000, respectively; repairs charged to these
reserves were $1,304,000, $1,597,000, and $1,269,000, respectively.
Accrued liabilities included $1,003,000 and $1,060,000 for storm damage
at December 31, 1996 and 1995, respectively.
Employee incentive plan -- The Company has a gain sharing plan for the
benefit of all electric utility company employees. The totals received
by all electric utility company employees for 1996, 1995, and 1994 were
$778,000, $870,000, and $1,314,000, respectively.
Use of estimates -- In recording transactions and balances resulting from
business operations, the Company uses estimates based on the best
information available. Estimates are used for such items as plant
depreciable lives, tax provisions, uncollectible accounts, environmental
loss contingencies, unbilled revenues and actuarially determined benefit
costs. As better information becomes available (or actual amounts are
determinable) the recorded estimates are revised. Consequently,
operating results can be affected by revisions to prior accounting
estimates. Recent changes in anticipated retirement ages have resulted
in changes to actuarial assumptions used in the cost calculations for
postretirement benefits related to the Company's Executive Survivor and
Supplemental Retirement Plan. Also, the depreciable lives of certain
plant assets are reviewed and, if appropriate, revised each year, as
discussed previously. (See note 8 for more information on the effects
of these changes in estimates.)
Reclassifications -- Certain prior year amounts have been reclassified to
conform to the 1996 presentation format. Such reclassification had no
impact on net income and shareholders' equity.
Cash equivalents -- The Company considers all highly liquid debt
instruments purchased with a maturity of 90 days or less to be cash
equivalents.
Consolidated Statements of Cash Flows -- Excluded from the Consolidated
Statements of Cash Flows, are the following noncash transactions. In
September 1995 the Company recorded a $3.5 million passive investment in
the form of a delayed equity contribution to a limited liability
company. As of December 31, 1996 and 1995, $13,000 and $3,033,000,
respectively, remained to be paid on the obligation. In 1995 the
Company recorded an investment of $2 million in the form of a delayed
equity contribution in a limited partnership that invests in tax-credit
qualifying affordable housing. The $780,000 balance of the obligation
remaining to be paid at December 31, 1995, was paid in the second
quarter of 1996.
Debt reacquisition premiums -- In accordance with regulatory treatment,
the Company defers debt redemption premiums and amortizes such costs
over the original life of the reacquired bonds.
Investments -- At December 31, 1996 and 1995, the Company had noncurrent
investments of $6,163,000 and $4,491,000, respectively, in limited
partnerships that invest in tax-credit qualifying affordable housing
projects. These investments, accounted for under the equity method,
provided the Company with tax credits of $593,000 and $92,000, in 1996
and 1995, respectively. At December 31, 1996, the Company had $820,000
invested in marketable equity securities classified as available-for-
sale and recorded at market value. The balance of investments at
December 31, 1996, consists of $8,722,000 in additional investments
accounted for under the equity method, and $3,916,000 in financial
instruments, primarily related to participation in economic development
loan pools. The Company's temporary cash investments consist of money
market funds recorded at cost, which approximates market. (See further
discussion under note 10.)
Inventories -- The electric operation inventories are reported at average
cost. The health service, manufacturing and other business operation
inventories are stated at the lower of cost (first-in, first-out) or
market.
Short-term debt -- The composite interest rate on short-term debt
outstanding as of December 31, 1996, was 5.77%. The average interest
rate paid on short-term debt during 1996 was 5.65%.
Intangible assets -- The majority of the Company's intangible assets
consist of goodwill associated with the acquisition of subsidiaries.
Intangible assets are amortized on a straight-line basis over periods of
40 years for the telephone company and 15 years or less for all other
intangibles. The Company periodically evaluates the recovery of
intangible assets based on an analysis of undiscounted future cash
flows. Total intangibles as of December 31 are as follows:
1996 1995
-------- --------
(in thousands)
Goodwill on telephone company $ 7,749 $ 7,749
Other intangible assets 19,870 15,797
------- -------
Total 27,619 23,546
Less accumulated amortization 5,665 4,644
------- -------
Intangibles-net $21,954 $18,902
2. Segment information
The Company's wholly owned subsidiary Mid-States Development, Inc. (Mid-
States) purchased a Montana-based supplier of X-ray supplies and
accessories in February of 1996, a mobile medical diagnostic services
company located in Bemidji, MN in April of 1996, and four radio stations
located in the Fargo, North Dakota/Moorhead, Minnesota, market area, two
in June, one in October, and one in December 1996. Mid-States purchased
two additional manufacturing companies and three small diagnostic imaging
companies in 1995, and one additional business in 1994. Of the companies
purchased in 1995, one manufacturing company and all three diagnostic
imaging companies were purchased in January, and the other manufacturing
company was purchased in October. The Company's telecommunications
subsidiary North Central Utilities, Inc. (NCU) acquired two cable TV
systems in 1996 that serve the communities of Milbank, South Dakota, and
Carlos, Minnesota.
In all acquisitions, the purchase method of accounting was used and the
acquisitions would have had no significant pro forma effect on the
Company's operating revenues, net income, or earnings per share for
1996, 1995, and 1994. The total price for all businesses acquired was
$11,060,000 in 1996, $10,820,000 in 1995, and $575,000 in 1994.
On January 2, 1997, NCU completed the acquisition of The Peoples
Telephone Co. of Bigfork (Peoples). The acquisition will be accounted
for under the pooling-of-interests method. This acquisition will have
no significant pro forma effect on the Company's operating revenues, net
income, or earnings per share for 1996, 1995, and 1994.
The Company's business operations, which are based mainly in Minnesota,
North Dakota, and South Dakota, principally in the region known as the
"Red River Valley of the North," are broken down into four segments.
Electric operations includes the electric utility only. 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
primarily in the Midwestern United States. Manufacturing operations
includes production of agricultural equipment, plastic pipe, and
fabricated metal parts. Other business operations consists of businesses
diversified in such areas as electrical and telephone construction
contracting, radio broadcasting, waste incinerating, and
telecommunications. Information for the business segments for 1996,
1995 and 1994 is presented in the table below:
1996 1995 1994
-------- -------- --------
(in thousands)
Operating revenue
Electric $199,345 $203,925 $198,812
Health services 61,697 50,896 45,555
Manufacturing 56,868 38,690 13,083
Other business operations 43,829 32,818 29,276
-------- -------- --------
Total $361,739 $326,329 $286,726
Operating income
Electric $ 45,279 $ 47,916 $ 48,126
Health services 5,137 3,581 2,486
Manufacturing 5,423 3,270 2,441
Other business operations 2,387 3,531 3,126
-------- -------- --------
Total $ 58,226 $ 58,298 $ 56,179
Depreciation and amortization
Electric $ 19,880 $ 19,448 $ 18,970
Health services 585 517 455
Manufacturing 551 344 227
Other business operations 1,888 1,600 1,538
-------- -------- --------
Total $ 22,904 $ 21,909 $ 21,190
Capital expenditures
Electric $ 38,224 $ 27,443 $ 25,693
Health services 16,230 4,020 2,544
Manufacturing 4,575 3,879 357
Other business operations 4,922 1,792 1,817
-------- -------- --------
Total $ 63,951 $ 37,134 $ 30,411
Identifiable assets
Electric $523,509 $509,588 $505,291
Health services 65,140 41,623 26,415
Manufacturing 32,474 27,270 7,215
Other business operations 41,164 30,715 40,051
-------- -------- --------
Total $662,287 $609,196 $578,972
3. Rate matters
On July 1, 1995, the Company began charging all Minnesota customers a
.5030% surcharge on their electric service statements for recovery of
conservation-related costs exceeding the amount already included in base
rates. On July 1, 1996 the rate was increased to 1.25%. The
conservation-related costs being recovered through the surcharge and in
base rates include Conservation Improvement Program (CIP) expenditures,
carrying charges on costs incurred in excess of costs currently being
recovered, lost margins on avoided kilowatt-hour sales, and bonus
incentives related to energy savings. The MPUC approved recovery of
1995 and 1994 lost margins and bonus incentives in 1996 and 1995,
respectively. The Company recorded revenues related to 1996, 1995, and
1994 lost margins and bonus incentives of $800,000, $766,000, and
$537,000, respectively. As these costs are recovered through the monthly
billing process, the amounts billed are offset by the amortization of
deferred CIP charges.
In 1994 the Company filed a petition with the MPUC for approval of an
annual recovery mechanism for DSM-related costs, under Minnesota's CIP.
An intervenor, on behalf of the large general service group, filed
comments against the petition and requested the MPUC to order a general
rate case to review the Company's earnings levels. In the interest of
rate stability the Company reached an agreement, which was approved by
the MPUC, resulting in costs of approximately $2.2 million each year for
three years being absorbed in current rates beginning in 1995.
4. Common shares
New issuances -- On August 30, 1996, the Company filed a shelf
registration statement with the Securities and Exchange Commission for
the issuance of up to 1,000,000 common shares pursuant to the Company's
Automatic Dividend Reinvestment and Share Purchase Plan (the Plan),
which will permit shares purchased by shareholders, employees, or
customers who participate in the Plan to be either new issue common
shares or common shares purchased on the open market. In December 1996
the Company began issuing newly issued common shares under the Plan,
which resulted in the issuance of 34,516 common shares in 1996. On
January 2, 1997, the Company issued 163,758 unregistered common shares
to effect the acquisition of Peoples. On February 7, 1997, the Company
issued 30,561 common shares to its leveraged employee stock ownership
plan.
Shareholder Rights Plan -- On January 27, 1997, the Company's Board of
Directors declared a dividend of one preferred share purchase right
(Right) for each outstanding common share held of record as of February
10, 1997. One Right was also issued with respect to each common share
issued after February 10, 1997. Each Right entitles the holder to
purchase from the Company one one-hundredth of a share of newly created
Series A Junior Participating Preferred Stock at a price of $70, subject
to certain adjustment. The Rights are exercisable when, and are not
transferable apart from the Company's common shares until, a person or
group has acquired 15% or more, or commenced a tender or exchange offer
for 15% or more, of the Company's common shares. If the specified
percentage of the Company's common shares is acquired, each right will
entitle the holder (other than the acquiring person or group) to
receive, upon exercise, common shares of either the Company or the
acquiring company having value equal to two times the exercise price of
the Right. The Rights are redeemable by the Company's Board of
Directors in certain circumstances and expire on January 27, 2007.
5. Retained earnings restriction
The Company's Indenture of Mortgage and Articles of Incorporation, as
amended, contain provisions that limit the amount of dividends that may
be paid to common shareholders. Under the most restrictive of these
provisions, retained earnings at December 31, 1996, were restricted by
$10,089,000.
6. Commitments
At December 31, 1996, the Company had commitments under contracts in
connection with construction programs aggregating approximately
$4,600,000. For capacity requirements the Company has agreements
extending through April 2005, at annual costs of approximately
$5,100,000 in 1997, $4,700,000 in 1998, $4,800,000 in 1999, $2,300,000
in each year of 2000 through 2004 and $760,000 in 2005.
The Company also has several long-term coal contracts in which it is
responsible for making payment only upon the delivery of the coal. The
risk of loss from nonperformance of the contracts is considered nominal
because of the availability of other suppliers and the expected
continued reliability of the current fuel suppliers. Furthermore, the
cost of energy adjustment provision in the rate-making process lessens
the risk of loss (in the form of increased costs) from market price
changes because it assures recovery of almost all fuel costs.
The Big Stone Plant joint owners entered into operating leases for 250
new aluminum coal cars for transporting coal to Big Stone Plant. The
terms of the leases are 15 years and the Company's share of lease
payments is approximately $539,000 per year. The new cars began
transporting coal in October 1996. The Company has no other significant
operating leases.
7. Long-term obligations
Preferred shares--The $6.35 cumulative preferred shares are redeemable
in whole or in part at the option of the Company after December 1, 1997,
at $103.175, declining linearly to $100.00 at December 31, 2002.
The $9.00 exchangeable cumulative preferred shares are redeemable in
whole or in part at the option of the Company after August 9, 1999, for
$100.00 per share payable in cash or, at the holder's election, common
shares. Subject to certain conditions, such shares are exchangeable at
the option of the holder after August 9, 1999, for $100.00 per share in
cash or common shares.
Long-term debt--All utility property, with certain minor exceptions, is
subject to the lien of the Indenture of Mortgage of the Company securing
its First Mortgage Bonds. The Company is required by the Indenture to
make annual payments (exclusive of redemption premiums) for sinking fund
purposes, except that the requirement with respect to certain series may
be satisfied by the delivery of bonds of such series of equal principal
amount. The Company issued First Mortgage Bonds of its pollution
control and industrial development series to secure payment of a like
principal amount of revenue bonds that were issued by local governmental
units to finance facilities leased or purchased and that the Company has
capitalized. The aggregate amounts of maturities and sinking fund
requirements on bonds outstanding and other long-term obligations at
December 31, 1996, for each of the next five years are $42,136,000 for
1997, $17,197,000 for 1998, $10,628,000 for 1999, $10,457,000 for 2000,
and $4,390,000 for 2001.
8. Pension plan and other postretirement benefits
The Company's noncontributory funded pension plan covers substantially
all electric utility employees. The plan provides 100% vesting after 5
vesting years of service and for retirement compensation at age 65, with
reduced compensation in cases of retirement prior to age 62. The
Company reserves the right to discontinue the plan, but no change or
discontinuance may affect the pensions theretofore vested. The
Company's policy is to fund pension costs accrued. All past service
costs have been provided for. The total pension cost was $1,292,000 for
1996, $1,009,000 for 1995, and $1,356,000 for 1994. A portion of the
pension cost is capitalized as a part of utility plant construction.
The pension plan has a trustee who is responsible for pension payments
to retirees. Five investment managers are responsible for managing the
plan's assets. In addition, an independent actuary performs the
necessary actuarial valuations for the plan.
Net periodic pension cost for 1996, 1995, and 1994 includes the
following components:
1996 1995 1994
-------- -------- --------
(in thousands)
Service cost--benefit earned during the period $ 2,273 $ 1,908 $ 2,076
Interest cost on projected benefit obligation 6,754 6,511 6,209
-------- -------- --------
$ 9,027 $ 8,419 $ 8,285
(Gain)/loss on return on assets (15,738) (26,509) 3,234
Plus/(less): net deferral and amortization 8,003 19,099 (10,163)
-------- -------- --------
Net periodic pension cost $ 1,292 $ 1,009 $ 1,356
======== ======== ========
The plan assets consist of common stock and bonds of public companies,
U.S. Government Securities, cash and cash equivalents.
The funded status of the plan and amounts recognized on the balance
sheet at December 31, 1996 and 1995, are as follows:
1996 1995
-------- --------
(in thousands)
Actuarial present value of benefit obligation:
Vested benefits $ 72,243 $ 69,340
Nonvested benefits 9,688 8,594
-------- --------
Accumulated benefit obligation $ 81,931 $ 77,934
======== ========
Projected benefit obligation $100,664 $ 95,359
Plan assets at fair value 121,506 110,728
-------- --------
Funded status $ 20,842 $ 15,369
Unrecognized transition asset (1,251) (1,486)
Unrecognized prior service cost 9,916 9,200
Unrecognized net actuarial (gain) or loss (25,773) (18,057)
-------- --------
Net pension asset $ 3,734 $ 5,026
======== ========
The assumptions used for actuarial valuations were:
1996 1995
-------- --------
Discount rate 7.25% 7.25%
Rate of increase in future compensation level 4.25% 4.25%
Long-term rate of return on assets 8.50% 8.50%
In addition to providing pension benefits to all electric utility
employees, the Company has an unfunded, nonqualified benefit plan for
executive officers and certain key management employees. This plan
provides defined benefit payments to these employees upon their
retirements or to their beneficiaries upon their deaths for a 15-year
period. Life insurance carried on the plan participants is payable to
the Company upon the employee's death. The net periodic pension cost of
this program in 1996, 1995 and 1994 was $485,000, $412,000, and
$271,000, respectively. In the second quarter of 1996 actuary reports
for the Company's Executive Survivor and Supplemental Retirement Program
amended July 1, 1994, were revised to reflect assumption changes
regarding expected retirement age and projected benefits under the July
1, 1994 plan amendment, which expanded the plan to include nonofficer
upper level management employees. The restatement resulted in an
expense adjustment of an additional $2,590,000, and a reduction in
earnings per share of $0.14 in 1996, along with a $711,000 reduction in
the $1,426,000 additional minimum liability reflected on the Company's
December 31, 1995, balance sheet.
The funded status of the plan and amounts recognized on the balance
sheet at December 31, 1996 and 1995, are as follows:
1996 1995
-------- --------
(in thousands)
Actuarial present value of benefit obligation:
Vested benefits $ 4,322 $ 3,067
Nonvested benefits 686 583
------- -------
Accumulated benefit obligation $ 5,008 $ 3,650
======= =======
Projected benefit obligation $ 6,636 $ 3,650
Plan assets at fair value -- --
------- -------
Funded Status $(6,636) $(3,650)
Unrecognized transition obligation 82 102
Unrecognized prior service cost 1,774 1,177
Unrecognized net actuarial (gain) or loss 487 1,018
Additional liability (715) (1,426)
------- -------
Accrued benefit liability $(5,008) $(2,779)
======= =======
The assumptions used for actuarial valuations for 1996 and 1995 were a
discount rate of 7.25%, and a salary scale rate increase of 5%.
In addition to providing pension benefits, the Company provides a
portion of health insurance benefits for retired employees.
Substantially all of the Company's electric utility employees may become
eligible for health insurance benefits if they reach age 55 and have 10
years of service. Upon adoption of Statement of Financial Accounting
Standards No. 106 - Employers' Accounting for Postretirement Benefits
Other Than Pensions - in January 1993, the Company elected to recognize
its transition obligation related to postretirement benefits earned of
approximately $14,964,000 over a period of twenty years.
During the second quarter of 1996 actuary valuations for postretirement
benefits other than pensions were computed to reflect a change in
assumptions related to group life insurance. The change in actuarial
assumptions resulted in a reduction in 1996 expenses related to a
reduction in expected postretirement benefit obligations. The plan was
amended during the fourth quarter of 1995 to reduce the contribution
required of an employee's surviving spouse for health insurance. This
amendment increased benefit costs by $2,155,000 in 1995 because most of
the prior service cost was related to retired employees' spouses for
which the Company has no current economic benefit. The Company
estimates this amendment will have a service cost of approximately
$200,000 per year in future years.
The net postretirement benefit cost for 1996, 1995, and 1994 includes
the following components:
1996 1995 1994
-------- -------- --------
(in thousands)
Service cost - benefit earned during the period $ 484 $ 411 $ 596
Interest cost on accumulated postretirement
benefit obligation 1,132 1,187 1,412
Amortization of transition obligation 748 881 881
Amortization of experience (gain)/loss (210) (311) --
Plan amendment prior service cost -- 2,155 --
Life insurance curtailment gain (749) -- --
------ ------ ------
Net postretirement benefit cost $1,405 $4,323 $2,889
====== ====== ======
The funded status of the plan and the amounts recognized on the balance
sheet at December 31, 1996 and 1995, are as follows:
1996 1995
-------- --------
(in thousands)
Actuarial present value of benefit obligation:
Retirees $ 9,096 $ 10,276
Fully eligible plan participants 4,582 5,000
Other active plan participants 2,645 2,607
-------- --------
Accumulated postretirement benefit obligation $ 16,323 $ 17,883
Plan assets at fair value -- --
-------- --------
Funded status $(16,323) $(17,883)
Unrecognized (gain)/loss (4,038) (4,662)
Unrecognized transitional obligation 11,971 14,976
-------- --------
Postretirement benefit liability $ (8,390) $ (7,569)
======== ========
The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation as of December 31, 1996,
was 7.0% for 1997, decreasing linearly each successive year until it
reaches 5% in 2001, after which it remains constant. The assumed health
care cost trend rate used in measuring the accumulated postretirement
benefit obligation as of December 31, 1995, was 9.5% for 1996,
decreasing linearly each successive year until it reaches 5% in 2001,
after which it remains constant. The assumed discount rate used in
determining the accumulated postretirement benefit obligation as of
December 31, 1996 and 1995, was 7.25%. A one-percentage-point increase
in the assumed health care cost trend rate for each year would increase
the accumulated postretirement obligation as of December 31, 1996, by
approximately 11% and the service and interest cost components of the
net postretirement health care cost in 1996 by approximately 17%.
The Company has a leveraged employee stock ownership plan (ESOP) for the
benefit of all its employees. Contributions made by the Company were
$1,010,000 for 1996, $993,000 for 1995, and $970,000 for 1994.
9. Compensating balances and short-term borrowings
The Company maintains formal bank lines of credit for its electric
utility operations separate from lines and letters of credit maintained
by the subsidiary companies. They make available to the Company bank
loans for short-term financing and provide backup financing for
commercial paper notes. At December 31, 1996, the Company maintained no
compensating balances to support formal bank lines of credit. The
Company's bank lines of credit for electric utility operations totaled
$30,000,000 of which $25,600,000 was used at December 31, 1996. The
subsidiary companies' bank lines and letters of credit, which require no
compensating balances, totaled $24,357,000 of which $7,032,000 was used
at December 31, 1996. Based on the terms and nature of use of the
subsidiaries' lines, outstanding amounts are reflected in long-term debt
and current maturities on the Company's consolidated balance sheets.
10. Fair value of financial instruments
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is practicable
to estimate that value:
Cash and short-term investments -- The carrying amount approximates fair
value because of the short-term maturity of those instruments.
Marketable securities -- The fair value of investments are estimated based
on quoted market prices.
Other investments -- The carrying amount approximates fair value. A
portion of other investments is in financial instruments that have
variable interest rates that reflect fair value. The remainder of other
investments is accounted for by the equity method which, in the case of
operating losses, results in a reduction of the carrying amount.
Redeemable preferred stock -- The fair value is estimated based on the
current rates available to the Company for the issuance of redeemable
preferred stock.
Long-term debt--The fair value of the Company's long-term debt is
estimated based on the current rates available to the Company for the
issuance of debt. About $42 million of the Company's long term debt,
which is subject to variable interest rates, approximates fair value.
1996 1995
-------------------- --------------------
(in thousands)
Carrying Fair Carrying Fair
amount value amount value
--------- --------- --------- ---------
Cash and short-term investments $ 1,229 $ 1,229 $ 4,075 $ 4,075
Marketable securities 820 820 -- --
Other investments 19,060 19,060 12,716 12,716
Redeemable preferred stock (18,000) (18,000) (18,000) (18,650)
Long-term debt (160,492) (167,799) (168,261) (183,099)
The Company's marketable securities are included in investments on the
balance sheet and are classified as available for sale. These
securities are recorded at fair value with any unrealized gain or loss
included as a separate component in the retained earnings on the balance
sheet. Realized gains and losses are computed on each specific
investment sold. The amounts recognized on the balance sheet as of
December 31, 1996 and 1995, and amounts sold for each year are as
follows:
1996 1995
-------- --------
(in thousands)
Available for sale - securities
Cost $ 133 $ --
Gross unrealized gain 687 --
Gross unrealized loss -- --
------- -------
Fair value $ 820 $ --
======= =======
Proceeds from sale $ -- $90,774
Gross realized gains -- 1,591
Gross realized losses -- (2,816)
11. Income tax expense
The total income tax expense differs from the amount computed by
applying the federal income tax rate (35% in 1996, 1995 and 1994) to net
income before total income tax expense for the following reasons:
1996 1995 1994
-------- -------- --------
(in thousands)
Tax computed at federal statutory rate $15,398 $15,786 $15,525
Increases (decreases) in tax from:
State income taxes net of federal income tax
benefit 1,835 2,097 2,088
Investment tax credit amortization (1,177) (1,177) (1,347)
Depreciation differences--flow-through
method reversal (137) 222 617
Differences reversing in excess of federal rates (1,030) (754) (707)
Dividend received/paid deduction (604) (872) (889)
Permanent and other differences
and affordable housing tax credits (245) 857 594
------- ------- -------
Total Income tax expense $14,040 $16,159 $15,881
======= ======= =======
Overall effective federal and state income tax rate 31.9% 35.8% 35.8%
Income tax expense includes the following:
Charged (credited) to operations:
Current federal income taxes $18,034 $13,840 $12,892
Current state income taxes 3,608 3,201 2,935
Deferred federal income taxes (4,656) 603 1,185
Deferred state income taxes (480) 117 266
Investment tax credit amortization (1,177) (1,177) (1,347)
------- ------- -------
Total $15,329 $16,584 $15,931
Charged (credited) to other income and deductions:
Current federal income taxes (1,023) (269) 115
Current state income taxes (103) (21) 50
Deferred federal and state income taxes (163) (135) (215)
------- ------- -------
Total Income tax expense $14,040 $16,159 $15,881
======= ======= =======
The Company's deferred tax assets and liabilities were composed of the
following on December 31, 1996 and 1995:
1996 1995
-------- --------
(in thousands)
Deferred tax assets
Amortization of tax credits $ 13,021 $ 13,782
Vacation accrual 1,039 953
Unbilled/unearned revenue 4,452 3,886
Reserves 6,872 5,137
Nondeductible land - plant abandonment 1,134 1,134
Transfer to regulatory asset (617) (689)
Other 1,646 1,364
--------- ---------
Total deferred tax assets $ 27,547 $ 25,567
Deferred tax liabilities
Differences related to property (113,450) (114,081)
Excess tax over book - pensions (1,481) (1,994)
Transfer to regulatory asset (4,012) (2,563)
Transfer to regulatory liability 204 649
Other (2,756) (3,222)
--------- ---------
Total deferred tax liabilities $(121,495) $(121,211)
--------- ---------
Deferred income taxes $ (93,948) $ (95,644)
========= =========
12. Property, plant and equipment
1996 1995
-------- --------
(December 31, in thousands)
Electric Plant:
Production $305,472 $302,601
Transmission 137,539 132,031
Distribution 217,825 207,248
General 81,229 73,425
-------- --------
742,065 715,305
Less accumulated depreciation and amortization 301,380 291,740
-------- --------
440,685 423,565
Construction work in progress 11,470 16,285
-------- --------
Net electric plant $452,155 $439,850
-------- --------
Subsidiary companies plant $ 93,975 $ 54,266
Less accumulated depreciation and amortization 26,292 16,434
-------- --------
Net subsidiary companies plant $ 67,683 $ 37,832
-------- --------
Net plant $519,838 $477,682
======== ========
13. Quarterly information (unaudited)
The quarterly data shown below reflects seasonal and timing variations that are common in the
utility industry.
Three Months Ended
March 31 June 30 September 30 December 31
-------------- -------------- -------------- --------------
1996 1995 1996 1995 1996 1995 1996 1995
------ ------ ------ ------ ------ ------ ------ ------
(in thousands except per share data)
Operating revenues $88,390 $83,250 $89,588 $73,433 $92,866 $80,585 $90,895 $89,061
Operating income $18,831 $17,648 $12,293 $11,814 $12,273 $14,910 $14,829 $13,926
Net income $10,032 $ 8,707 $ 5,980 $ 5,337 $ 6,207 $ 7,147 $ 7,736 $ 7,754
Earnings available for common shares $ 9,442 $ 8,118 $ 5,391 $ 4,747 $ 5,617 $ 6,557 $ 7,147 $ 7,165
Earnings per common share $ .84 $ .73 $ .48 $ .42 $ .50 $ .59 $ .64 $ .64
Dividends paid per common share $ .45 $ .44 $ .45 $ .44 $ .45 $ .44 $ .45 $ .44
Price range:
High $38 5/8 $35 $38 5/8 $35 $34 1/2 $35 1/4 $34 1/4 $37 3/4
Low $35 1/4 $31 3/4 $32 $30 3/4 $31 3/4 $32 1/4 $32 $34 1/8
Average number of common shares
outstanding 11,180 11,180 11,180 11,180 11,180 11,180 11,187 11,180
Exhibit 13-A
Stock listing
Otter Tail common stock is traded on The Nasdaq Stock Market's National
Market. (Nasdaq: National Association of Securities Dealers Automated
Quotation.)