EXHIBIT 13
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995 that are based on current
expectations, estimates and projections of SEMCO Energy, Inc. and its
subsidiaries ("the "Company"). Statements that are not historical facts,
including statements about the Company's outlook, beliefs, plans, goals, and
expectations, are forward-looking statements. These statements are subject to
potential risks and uncertainties and, therefore, actual results may differ
materially. The Company undertakes no obligation to update publicly any
forward-looking statements whether as a result of new information, future events
or otherwise. Factors that may impact forward-looking statements include, but
are not limited to, the following: (i) the effects of weather and other natural
phenomena; (ii) the economic climate and growth in the geographical areas where
the Company does business; (iii) the capital intensive nature of the Company's
business; (iv) increased competition within the energy industry as well as from
alternative forms of energy; (v) the timing and extent of changes in commodity
prices for natural gas and propane; (vi) the effects of changes in governmental
and regulatory policies, including income taxes, environmental compliance and
authorized rates; (vii) the Company's ability to bid on and win construction
contracts; (viii) the impact of energy prices on the amount of projects and
business available to the Company's engineering services business and
construction services business; (ix) the nature, availability and projected
profitability of potential investments available to the Company; (x) the
Company's ability to remain in compliance with its debt covenants and accomplish
its financing objectives in a timely and cost-effective manner in light of
changing conditions in the capital markets; (xi) the Company's ability to
operate and integrate acquired businesses in accordance with its plans and (xii)
the Company's ability to effectively execute its strategic plan.
16
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
REDIRECTION OF BUSINESS STRATEGY. During the fourth quarter of 2001, the
Company announced plans to redirect its business strategy. The plans include the
restructuring of corporate, business unit and operational structures. This will
include the integration of the Company's Alaska and Michigan gas distribution
divisions. The plans include the closure of the Company's Houston-based
engineering and construction headquarters and the related consolidation of
administrative functions in Michigan. The redirection also involves the
divestiture of the Company's engineering services business and certain regions
of the Company's construction services business that are not likely to
contribute to shareholder value in the foreseeable term. The Company, under its
new strategy, will concentrate more on profitable growth within each line of
business and less on acquisitions.
RESULTS FOR 2001 INCLUDE LOSSES FROM DISCONTINUED OPERATIONS AND OTHER UNUSUAL
ITEMS. The Company had a consolidated net loss for 2001 of $6.4 million, or
$0.35 per share. The net loss includes several unusual items, including losses
associated with discontinued operations, restructuring charges, and asset
impairments. Net income from continuing operations and before the unusual items,
was $4.8 million, or $0.27 per share. All references to earnings or loss per
share ("EPS") in Management's Discussion and Analysis are on a diluted basis.
For information related to the calculation of diluted EPS, refer to Note 11 of
the Notes to the Consolidated Financial Statements.
The net loss for 2001 includes losses of $6.1 million, or $0.34 per share,
associated with the Company's plans to discontinue its engineering business. As
discussed above, the Company's board of directors approved a plan to redirect
the Company's business strategy, which includes the divestiture of the
engineering services business. The planned divestiture is being accounted for as
a discontinued operation and, accordingly, the operating results of this
business and the estimated loss on its sale are segregated and reported as
discontinued operations in the Consolidated Statements of Income. The loss from
discontinued operations for 2001 includes a loss from operations of $1.1
million, net of income taxes, and an estimated loss from the sale, including a
provision for losses during the phase-out period, of $5.0 million, net of income
taxes. Prior year results have been restated to reflect the operating results
from the engineering services business in discontinued operations.
In addition to the losses from discontinued operations, the Company's
results for 2001 also include restructuring charges, asset impairments and
certain other unusual items that reduced net income by $5.1 million, or $0.28
per share. The restructuring charges and asset impairments account for $4.0
million of the charges, net of income taxes, and include severance expense,
costs associated with terminating leases, write-downs of certain construction
operations and other related expenses associated with the redirection of the
Company's business strategy. The other unusual items account for $1.1 million of
the charges, net of income taxes, and include the write-off of certain assets
and an increase in reserves for certain contingencies.
The restructuring charges and asset impairments ($6.1 million before income
taxes) are reflected in operating expenses in the Company's Consolidated
Statements of Income. The other unusual items are reflected in both operating
expenses ($.9 million before income taxes) and non-operating expenses ($.6
million before income taxes). For business segment reporting, the operating
income of the gas distribution business includes $1.1 million of the charges;
the operating loss of the construction services business includes $3.3 million
of the charges; and $2.6 million is reflected in the operating loss of the
corporate and other business segment.
As discussed previously, the Company incurred a net loss during 2001 of
$6.4 million (or $0.35 per share), which includes a number of unusual charges.
Net income for 2000 and 1999 was $16.7 million (or $0.90 per share) and $17.7
million (or $1.00 per share), respectively. Warmer than normal weather has
reduced net income during 2001, 2000 and 1999 by approximately $5.4 million (or
$0.29 per share), $4.0 million (or $0.21 per share) and $3.6 million (or $0.21
per share), respectively.
17
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following table shows the Company's consolidated operating results, as
well as the impact of warmer than normal weather and certain other unusual
items, for the past three years. Net income, excluding the impact of the unusual
items noted in the table below, would have been $10.2 million, $20.6 million and
$20.9 million for 2001, 2000 and 1999, respectively. The business segment
analyses and other discussions on the next several pages provide additional
information regarding the differences in operating results when comparing 2001,
2000 and 1999.
Years Ended December 31, 2001 2000 1999
- -------------------------------------------------------------- --------- --------- ---------
(in thousands, except per share amounts)
Operating revenues . . . . . . . . . . . . . . . . . . . . . . $445,823 $410,325 $369,922
Restructuring and impairment charges . . . . . . . . . . . . 6,103 - -
Other operating expenses . . . . . . . . . . . . . . . . . . 395,329 345,092 327,519
--------- --------- ---------
Operating income . . . . . . . . . . . . . . . . . . . . . . . $ 44,391 $ 65,233 $ 42,403
Other income and (deductions). . . . . . . . . . . . . . . . (29,449) (32,077) (16,750)
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . (6,578) (11,554) (7,631)
--------- --------- ---------
Income before dividends on trust preferred securities and
discontinued operations. . . . . . . . . . . . . . . . . . . $ 8,364 $ 21,602 $ 18,022
Dividends on trust preferred securities, net of income tax . . (8,603) (5,004) -
--------- --------- ---------
Net income (loss) from continuing operations . . . . . . . . . (239) 16,598 18,022
Income (loss) from discontinued operations, net of income tax. (6,122) 95 (363)
--------- --------- ---------
Net income (loss) available to common shareholders . . . . . . $ (6,361) $ 16,693 $ 17,659
========= ========= =========
Earnings per share ("EPS")
Basic. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (0.35) $ 0.93 $ 1.00
Diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . $ (0.35) $ 0.90 $ 1.00
Average common shares outstanding
Basic. . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,106 17,999 17,697
Diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . 18,106 18,619 17,720
--------- --------- ---------
Impact on net income of the following:
Warmer than normal weather . . . . . . . . . . . . . . . . . $ (5,350) $ (3,995) $ (3,640)
Income (Loss) from discontinued operations . . . . . . . . . (6,122) 95 (363)
Restructuring charges, impairments and other unusual items . (5,083) - -
Gain on divestiture of energy marketing business . . . . . . - - 729
Net income excluding the foregoing items . . . . . . . . . . . $ 10,194 $ 20,593 $ 20,933
EPS excluding the foregoing items
Basic. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.56 $ 1.14 $ 1.18
Diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.56 $ 1.11 $ 1.18
SUMMARY OF BUSINESS SEGMENTS
The Company operates four reportable business segments: (1) gas distribution;
(2) construction services; (3) information technology services; and (4) propane,
pipelines and storage. The latter three segments are sometimes referred to
together as the "diversified businesses." Refer to Note 10 of the Notes to the
Consolidated Financial Statements for further information regarding each
business segment and a summary of financial information by business segment.
18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Each business segment is discussed separately on the following pages. The
Company evaluates the performance of its business segments based on operating
income. Operating income does not include income taxes, interest expense,
discontinued operations, or other non-operating income and expense items. A
review of the non-operating items follows the business segment discussions.
GAS DISTRIBUTION
The Company's gas distribution business segment consists of operations in
Michigan and Alaska. ENSTAR, the Alaska-based operation, was acquired on
November 1, 1999. The acquisition of ENSTAR was accounted for as a purchase and,
therefore, the consolidated financial statements and the table below include the
results of ENSTAR's operations since November 1, 1999. The Michigan gas
distribution operation and ENSTAR are referred to together as the "Gas
Distribution Business".
Warm weather during the past three years has had a significant impact on
operating income. Weather was approximately 9%, 6% and 7% warmer than normal
during 2001, 2000 and 1999, respectively. Under normal weather conditions,
operating income during 2001, 2000 and 1999 would have been higher by
approximately $8.4 million, $6.5 million and $5.3 million, respectively. The
impact of weather on operating income during 2000 was greater than during 1999,
despite colder weather in 2000. This is due to the increase in the number of
customers as a result of the ENSTAR acquisition. A significant increase in the
number of customers causes any variation from normal weather to have a more
pronounced impact on operating results.
Years Ended December 31, 2001 2000 1999
- ------------------------------------ --------- --------- ---------
(in thousands)
Gas sales revenues . . . . . . . . . $ 295,397 $ 273,312 $ 191,169
Cost of gas sold . . . . . . . . . . 184,973 161,945 117,789
--------- --------- ---------
Gas sales margin . . . . . . . . . $ 110,424 $ 111,367 $ 73,380
Gas transportation revenue . . . . . 25,888 30,783 22,369
Other operating revenue. . . . . . . 3,080 3,756 3,293
--------- --------- ---------
Gross margin . . . . . . . . . . . $ 139,392 $ 145,906 $ 99,042
Restructuring charges. . . . . . . . 1,051 - -
Other operating expenses . . . . . . 88,004 83,030 58,908
--------- --------- ---------
Operating income . . . . . . . . . . $ 50,337 $ 62,876 $ 40,134
========= ========= =========
Weather-normalized operating income. $ 58,732 $ 69,366 $ 45,434
========= ========= =========
Volumes of gas sold (MMcf) . . . . . 63,127 61,054 39,245
Volumes of gas transported (MMcf). . 42,992 48,706 32,417
Number of customers at year end. . . 374,938 367,157 357,378
Average number of customers
Gas sales customers. . . . . . . . 364,442 353,168 258,406
Transportation and ATS customers . 5,453 8,253 9,183
--------- --------- ---------
369,895 361,421 267,589
Degree Days. . . . . . . . . . . . . 7,038 7,293 6,650
Percent colder (warmer) than normal. (8.6)% (5.9)% (6.7)%
<FN>
The amounts in the above table include intercompany transactions.
19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
GAS SALES MARGIN. During 2001, gas sales margin decreased by $.9 million (or
1%) when compared to 2000. The decrease is due primarily to the impact of warmer
weather and higher gas costs, offset partially by the addition of new customers
and customers switching from the Company's aggregated transportation service
program ("ATS") back to general gas sales service. Gas costs were higher in
Michigan during 2001 primarily as a result of purchasing gas with higher thermal
content than in 2000. The Company purchases its gas on a thermal basis, but must
sell it to most customers on a volumetric basis. When the thermal content
increases, the Company has to pay more for the gas but must still sell it based
on volume. The increase in thermal content also causes a decrease in gas sales
because gas with a higher thermal content burns more efficiently, which reduces
customer consumption. During the last half of 2001, the thermal content of
purchased gas returned to 2000 levels. Other factors contributing to the
increase in gas costs in 2001 are the release of excess pipeline capacity in
2000, which reduced the Company's 2000 gas costs, and an increase in
unaccounted-for gas.
The ATS program, which was effective April 1, 1998, provides all Michigan
commercial and industrial customers the opportunity to purchase their gas from a
third-party supplier, while allowing the Gas Distribution Business to continue
charging the existing distribution fees and customer fees. Distribution and
customer fees associated with customers who switch to third-party gas suppliers
are recorded in gas transportation revenue rather than gas sales revenue,
because the Company is acting only as a transporter for those customers. In 1998
and 1999, many customers participated in the ATS program. During 2000 and 2001,
many of the customers, who had previously switched to the ATS program in 1998
and 1999, switched back to the Company's general gas sales service. These
customers switched back primarily because the third-party marketers they were
utilizing stopped participating in the ATS program due to significant increases
and instability in the market price of natural gas.
During 2001, the Company's average number of gas sales customers increased
by 11,271. Approximately 2,800 of the increase was caused by customers switching
from the ATS program back to general gas sales service. The remaining increase
of approximately 8,500 represents the average number of new gas sales customers
added to the Company's distribution system in 2001.
In 2000, gas sales margin increased by $38.0 million (or 52%) when compared
to 1999. The increase included approximately $28.6 million of gas sales margin
from ENSTAR. As discussed previously, ENSTAR was acquired on November 1, 1999.
Therefore, 1999 results include only 2 months of operations from ENSTAR. The
remaining $9.4 million of the increase was attributable to the Michigan gas
distribution operation and was due in part to an increase in sales margins
earned on the sale of the gas commodity as a result of gas supply and storage
arrangements with TransCanada Gas Services, Inc. ("TransCanada") and an increase
in gas sales as a result of cooler weather compared to 1999. The increase was
also due to gas sales margins from new customers and customers switching from
the Company's ATS program back to general gas sales service.
The third-party gas supply and storage arrangements with TransCanada
pertain to the Michigan gas distribution operation. During 2001, TransCanada
sold its gas marketing business and assigned its supply and storage arrangements
to BP Gas and Power ("BP") with the Company's consent. Under the terms of the
agreements, TransCanada or BP provide a significant portion of the Company's
natural gas requirements and manage the Company's natural gas supply and the
supply aspects of transportation and storage operations in Michigan for the
three-year period that began April 1, 1999. Also, effective April 1, 1999, and
as authorized in a September 1998 Michigan Public Service Commission ("MPSC")
order, the Michigan operation reduced and froze in its base rate a gas charge of
$3.24 per thousand cubic feet ("Mcf") and suspended its gas cost recovery
("GCR") clause for a period of three years. TransCanada or BP supplies the gas
and related services to the Company at a cost below the $3.24 per Mcf that the
Company is authorized to charge its Michigan customers for gas. As a result of
suspending the GCR clause and contractually fixing the cost of gas below the
$3.24 charged to customers, the Michigan gas distribution operation retains the
sales margin on the sale of gas, subject to a customer profit sharing mechanism
also approved in the MPSC order. The sales margin is the amount by which the
$3.24 charged to customers exceeds the Company's cost of gas purchased from
TransCanada or BP. As discussed previously, the margin on the sale of gas during
2001 was lower because the gas purchased during 2001 had a higher thermal
content than in prior years. Prior to the suspension of the GCR clause on April
1, 1999, gas sales margin was generated primarily from distribution and customer
fees because the Michigan operation was not allowed to earn profits from the
sale of the gas commodity.
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Refer to the section titled "Outlook for Gas Distribution" for information
regarding new gas supply arrangements effective in 2002, the approval of thermal
rates and the extension of the fixed gas charge program for customers under the
jurisdiction of the City Commission of Battle Creek, and the return to the GCR
mechanism for customers under the jurisdiction of the MPSC.
During 2000, the Company's average number of gas sales customers increased
by 94,762. Approximately 83,200 of the increase was a result of having ENSTAR's
customers for the entire year while 1,770 of the increase was due to customers
switching from the ATS program back to general gas sales service. The remaining
increase of approximately 9,800 represented the average number of new gas sales
customers added to the Company's distribution system in 2000.
GAS TRANSPORTATION REVENUE. In 2001, gas transportation revenue decreased by
$4.9 million when compared to 2000. The decrease was primarily the result of
customers switching from the ATS program back to the Company's general gas sales
service and a decrease in standard transportation revenue. The decrease in
standard transportation revenue was due to reduced consumption as a result of
the softening economy and a few of the Company's industrial and large commercial
customers in Michigan switching to alternative fuels earlier in 2001 due to
high natural gas prices.
In 2000, gas transportation revenue increased by $8.4 million when compared
to 1999. A full year of ENSTAR's transportation revenues resulted in an increase
of $10.7 million. The increase generated by ENSTAR was partially offset by the
impact of ATS customers switching from the ATS program back to the Company's
general gas sales service. As discussed previously, the Company charges ATS
customers the same distribution and customer fees that are charged to general
gas sales service customers.
OTHER OPERATING REVENUE. During 2001, other operating revenue decreased by $.7
million. The decrease was due to a reduction in ATS balancing fees as a result
of ATS customers switching back to general gas sales service. Other operating
revenue increased in 2000 by $.5 million when compared to 1999. The primary
reason for the increase was a bonus received for completing on schedule the
installation of a large-diameter transmission pipeline for a power plant under
construction, offset partially by a reduction in ATS balancing fees for reasons
described previously. The bonus in 2000 was a one-time item, but the Company was
able to replace the bonus in 2001 with revenues from the power plant
transmission pipeline.
OPERATING EXPENSES. During 2001, operating expenses of the Gas Distribution
Business increased by $6.0 million (or 7%) when compared to 2000. A
restructuring charge, most of which was made up of employee severance expense
associated with workforce reductions, accounts for $1.1 million of the increase.
The increase also includes a $.9 million increase in depreciation and
amortization expense, a $1.2 million increase in general business tax expense
and a $2.8 million increase in operation and maintenance expenses. Depreciation
and amortization expense increased due primarily to additional property, plant
and equipment placed in service.
The increase in general business tax expense was due primarily to property
tax reductions recorded in 2000 and higher property taxes in 2001, because of
additional property in service. The property tax reductions of $2.1 million in
2000 were based on pending appeals of prior years' (1997 - 1999) personal
property tax assessments in Michigan ("prior year tax appeals") and new property
valuation tables approved by the State of Michigan in 1999 ("new property tax
tables"). The Company filed the appeals over the past several years, claiming
that its Michigan utility property was over-assessed. The new property tax
tables approved by the State of Michigan are consistent with the Company's claim
regarding its utility property assessments, and thus significantly increase the
likelihood of recovering the overpaid property taxes. See Note 13 of the Notes
to the Consolidated Financial Statements for further information regarding the
prior year tax appeals and recoverability of overpaid property taxes.
Operation and maintenance expenses increased in 2001, due primarily to
increased employee-related costs such as health care costs, retiree medical
costs and pension expense. There was also an increase in maintenance costs
associated with underground storage facilities.
21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
In 2000, operating expenses of the Gas Distribution Business increased by
$24.1 million (or 41%) when compared to 1999. A full year of operations from
ENSTAR increased operating expenses by $26.4 million. The offsetting $2.3
million decrease in operating expenses is attributable to the Michigan operation
and includes a number of offsetting increases and decreases in expenses.
The decreases in expenses at the Michigan operation include approximately
$1.5 million in reduced employee-related expenses, including reduced incentive
compensation and reduced pension and retiree medical expenses. Pension and
retiree medical expenses decreased due to better than expected historical
experience, changes in actuarial assumptions between years and a settlement
credit related to an early retirement program offered to employees in 2000. See
Note 8 of the Notes to the Consolidated Financial Statements for more
information related to pension and retiree medical costs. General business taxes
for 2000 also decreased by approximately $2.0 million when compared to 1999. The
decrease is due in part to a $2.1 million reduction in property taxes recorded
in 2000, based on the prior year tax appeals and new property tax tables
discussed previously. In addition, sales tax expense was lower due to refunds
received during 2000. These decreases in general business taxes are offset
partially by a $1.3 million reduction in property taxes recorded in 1999, based
on the prior year tax appeals.
The above decreases were offset by an increase of approximately $1.0
million in depreciation and amortization expense for 2000 when compared to 1999.
The increase was due primarily to additional property, plant and equipment
placed in service.
OUTLOOK FOR GAS DISTRIBUTION. The Company's strategy for the Gas Distribution
Business is to expand its distribution system through aggressive marketing to
on-main and near-main potential customers. The Company will also seek ways to
capitalize on other market opportunities, including new power generation
projects. In 2001, the number of customers in Michigan and at ENSTAR increased
by approximately 2.1%. By comparison, recent surveys by the American Gas
Association indicate that the customer growth rate for the U.S. gas distribution
industry has averaged approximately 1.8% annually during the last ten years.
However, average annual gas usage per customer has been decreasing slightly
because new homes and appliances are more energy efficient.
The Company has offered early retirement programs during the past few years
to help reduce costs. The increased use of technology has also created operating
efficiencies. In addition, the Gas Distribution Business eliminated its
unprofitable Heating, Ventilation and Air Conditioning ("HVAC") department in
2001 and also eliminated other employee positions as part of the Company's
restructuring plan. The Gas Distribution Business will continue its efforts to
control or reduce operating expenses.
With the approval of profit incentive and sharing mechanisms by the MPSC in
1998, the Michigan operation is allowed to retain a portion of its earnings in
excess of its authorized return, if any, and credit the remainder to customers.
The profit incentive and sharing mechanism is effective for the calendar years
1999, 2000 and 2001. See Note 2 of the Notes to the Consolidated Financial
Statements for details regarding the profit incentive and sharing mechanism.
Based on results for 2000, the Company reduced its earnings by approximately
$50,000 to reflect amounts to be credited to customers. The Company was not
required to credit any amounts to its customers for 1999. Based on results for
2001, the Company does not expect that it will be required to credit any amounts
to its customers.
In 1998, the MPSC also authorized the Company to, among other things,
suspend its GCR clause and freeze for three years in its base rate a gas charge
of $3.24 per Mcf. The GCR suspension and the fixed rate took effect in April
1999, and extend through March 2002. The Gas Distribution Business was able to
offer this GCR suspension and rate freeze partly as a result of agreements
reached with TransCanada. Under the agreements, TransCanada provides the
Company's natural gas requirements and manages the Company's natural gas supply
and the supply aspects of transportation and storage operations in Michigan for
the same three-year period at a cost below the $3.24 charged to customers. As a
result of the MPSC order and the TransCanada agreements, the Michigan gas
distribution operation retains any sales margins achieved on the sale of gas
during the period from April 1999 through March 2002, subject to the customer
profit sharing mechanism discussed previously. The sales margin is the amount by
which the $3.24 charged to customers exceeds the Company's cost of gas and
related services purchased from TransCanada. As discussed previously,
TransCanada sold its gas marketing business and assigned its supply and storage
contracts to BP during 2001 with the Company's consent.
22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
During 2001, the Company applied for and received approval from the City
Commission of Battle Creek ("CCBC") to extend the GCR suspension period and the
fixed gas charge program until March 31, 2005 for customers located in the City
of Battle Creek, Michigan and surrounding communities. The fixed gas charge
program protects these customers from increases in the market price of natural
gas. During the three-year extension period, the Company will charge customers
in the geographic areas subject to the regulatory jurisdiction of the CCBC
("CCBC customers") a fixed gas charge of $4.85 per dekatherm ("Dth"). The
Company has also entered into new agreements with BP to provide the Company's
natural gas requirements and manage the Company's natural gas supply and the
supply aspects of transportation and storage operations for its CCBC customers.
BP provides the natural gas and services to the Company at a cost below the
$4.85 charged to CCBC customers. As a result of the new fixed gas charge and BP
agreements, the Company will retain any sales margin achieved on the sale of
natural gas to CCBC customers through March 2005. The margin is the amount by
which the $4.85 charged to customers exceeds the Company's cost of gas purchased
from BP.
The Company also received approval from the CCBC to start charging CCBC
customers on a thermal basis rather than a volumetric basis. The Company buys
all its natural gas by the dekatherm and now also sells it to these customers by
the dekatherm. This will help reduce the Company's risk, which was discussed
previously, to sudden increases in the thermal content of purchased natural gas
and will protect CCBC customers when the thermal content of natural gas drops.
The profit incentive and sharing mechanism discussed previously will remain in
effect through March 2005 for CCBC customers.
The Company also filed an application with the MPSC in September 2001 to
extend its fixed charge program until March 31, 2005 and increase the current
fixed charge for customers in the geographic areas subject to the regulatory
jurisdiction of the MPSC ("MPSC customers"). However, the Company was unable to
reach an agreement with the MPSC and other interested parties on a fixed
customer charge for natural gas for the three years of the proposed extended
period. As a result, the Company withdrew its application. The Company will
instead reinstate its GCR pricing mechanism when the current fixed gas charge
program expires on March 31, 2002. Under the GCR mechanism, the Company's MPSC
customers will be charged an amount that allows the Company to recoup its cost
of purchased natural gas. The MPSC has the authority to adjust the GCR factor
based on the variability in natural gas prices. The MPSC suspended the Company's
GCR clause in April 1999, when the current fixed gas charge program went into
effect. When the GCR mechanism goes back into effect in April 2002 for MPSC
customers, the Company will no longer be allowed to retain any sales margin on
the sale of natural gas to these customers. The Company anticipates that this
loss of sales margin will reduce 2002 net income by $.9 million when compared to
2001.
The Company also entered into new agreements with BP to supply natural gas
for the Company's MPSC customers through March 31, 2005. Refer to Note 2 of the
Notes to the Consolidated Financial Statements for more information regarding
the GCR mechanism and the BP gas supply arrangements.
Beginning in 2002, the profit incentive and sharing mechanism discussed
previously will no longer be in effect for MPSC customers. Instead, the profit
incentive and sharing mechanism in effect for the calendar year 1998 will be
reinstated for 2002. Refer to Note 2 of the Notes to the Consolidated Financial
Statements for further information. The Company is evaluating its revenue
requirments to determine if there is a need to file a general rate case with the
MPSC in 2002.
Hearings and a proceeding before the Regulatory Commission of Alaska
("RCA") were held in December 2001 to review and determine if ENSTAR's rates are
just and reasonable. The Company expects to receive a final order for ENSTAR
during the first quarter of 2002. The Company believes that ENSTAR's rates are
just and reasonable, but cannot predict the outcome of the proceeding. See Note
2 of the Notes to the Consolidated Financial Statements for additional
information regarding various RCA orders and rate matters.
The Michigan gas distribution operation competes with suppliers of
alternative energy sources such as coal and #6 and #2 fuel oil to meet the
energy requirements of its industrial customers. Natural gas has typically been
less expensive than these alternative energy sources. However, during a short
period of time in late 2000 and early 2001, natural gas prices increased
significantly, making some of these alternative energy sources more economical
than natural gas. During this period, a few of the Company's large Michigan
industrial customers switched to alternative energy sources. This competition
did not have a material impact on the financial results of the Company in 2001.
Prior to 2000, the market price of natural gas had been fairly stable.
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
However, the Company cannot predict the future stability of natural gas prices.
To lessen the possibility of fuel switching by industrial customers, the Company
offers flexible contract terms and additional services, such as gas storage and
balancing, in addition to a more environmentally friendly fuel. ENSTAR supplies
natural gas in its service territory at prices that currently preclude
substitution of alternative energy sources. At present, the residential energy
cost of natural gas in Alaska is less than half the cost of fuel oil, the next
most economical energy choice.
General economic conditions also have an impact on the volume of gas sold
or transported to the Company's commercial and industrial customers. During
economic downturns, these customers may see a decrease in demand for their
product, which in turn may lead to a decrease in the amount of natural gas they
require for production. However, under normal weather conditions, the Gas
Distribution Business generates approximately 68 percent of its gas sales
revenues from residential customers who use natural gas for heating purposes,
which is generally not impacted materially by downturns in the economy.
Temperatures, however, do have an impact on the amount of gas sold for heating
purposes.
Consistent with other gas distribution utilities, there is a potential risk
that industrial and electric generating plants on the Company's gas distribution
system, and also located in close proximity to interstate natural gas pipelines,
will bypass the Company and connect directly to such pipelines. However,
management is currently unaware of any significant bypass efforts by the
Company's customers. The Company has addressed and would continue to address any
such efforts by offering special services and rate arrangements designed to
retain these customers on the Company's system.
For information on environmental matters, regulatory matters and the
application of SFAS 71, "Accounting for the Effects of Certain Types of
Regulation," refer to Notes 2 and 13 of the Notes to the Consolidated Financial
Statements.
CONSTRUCTION SERVICES
The Company's construction services segment ("Construction Services") does
business in the midwestern, southern and southeastern areas of the United
States. The businesses that make up Construction Services have all been acquired
since mid-1997 and each acquisition has been accounted for using the purchase
method of accounting. As a result, Construction Services' operating results for
2001, 2000 and 1999 include the results of each of the acquired businesses for
the periods subsequent to their acquisition dates.
Company Acquisition Date
- ---------------------------------------------- ----------------
Sub-Surface Construction Co. ("Sub-Surface") . August 1997
K&B Construction, Inc. ("K&B") . . . . . . . . February 1999
Iowa Pipeline Associates, Inc. ("Iowa"). . . . April 1999
Flint Construction Co. ("Flint") . . . . . . . September 1999
Long's Underground Technologies, Inc. ("Long") September 1999
KLP Construction Co. ("KLP") . . . . . . . . . May 2000
Refer to Note 3 of the Notes to the Consolidated Financial Statements for
information regarding the amount paid for acquisitions during the last three
years.
24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Construction Services generates the majority of its sales revenue from the
installation of underground natural gas mains and service lines. The Company
also provides underground construction services to other industries such as
telecommunications and water supply. Underground construction businesses are
seasonal in nature. As a result, Construction Services generally incurs
operating losses during the winter and spring months when underground
construction is inhibited, and generates the majority of its operating revenue
and operating income during the summer and fall months.
Years Ended December 31, 2001 2000 1999
- ------------------------------------- --------- -------- -------
(in thousands)
Operating revenues. . . . . . . . . . $126,205 $105,231 $58,272
Restructuring and impairment charges. 3,098 - -
Other operating expenses. . . . . . . 124,481 101,555 55,661
--------- -------- -------
Operating income (loss) . . . . . . . $ (1,374) $ 3,676 $ 2,611
========= ======== =======
Feet of pipe installed. . . . . . . . 7,320 7,969 6,208
========= ======== =======
<FN>
The amounts in the above table include intercompany transactions.
OPERATING REVENUES. Construction Services' operating revenues increased to
$126.2 million during 2001, a $21.0 million (or 20%) increase over 2000. The
increase during 2001 was due primarily to a large multi-year construction
project in the southeastern region of the United States as well as increased
construction revenue in other regions of the country. Construction Services'
operating revenues increased to $105.2 million during 2000, a $47.0 million (or
81%) increase over 1999. The increase during 2000 was due primarily to a full
year of revenues from Iowa, Flint and Long and an increase in construction
projects.
OPERATING INCOME. Construction Services had an operating loss of $1.4 million
for 2001. Excluding restructuring charges, asset impairments and other unusual
charges of $3.3 million, operating income was $1.9 million in 2001, compared to
$3.7 million in 2000 and $2.6 million in 1999. The restructuring and impairment
charges and other unusual items include the write-down of goodwill and fixed
assets of certain construction operations, severance expense and other related
charges. In addition to the unusual charges, the items contributing to the
decrease in operating results in 2001, a large portion of which occurred in the
fourth quarter, include the mix of available work and the softening economy. The
softening economy has reduced new housing starts which has caused a decrease in
the number of new gas service lines installed by the Company's construction
services business. The Company also believes that the softening economy has
caused many customers to delay certain construction projects until 2002, which
has changed the mix of work available to Construction Services. The mix of work
has included more lower margin work at certain business units. The factors
causing the decrease in 2001 operating income were offset partially by profits
on the large, multi-year construction project in the southeastern region of the
United States.
The $1.1 million increase in operating income in 2000, when compared to
1999, was due primarily to a full year of operating results from Iowa, Flint and
Long, offset partially by additional operating costs incurred on various
construction projects as a result of some project delays, increased fuel costs
and other factors.
OUTLOOK FOR CONSTRUCTION SERVICES. Management believes there are opportunities
for growth in the pipeline construction industry. Management views the industry
as large but highly fragmented and believes that customer preference is shifting
from smaller construction companies to larger contractors. Management also
believes there is a trend in the utility industry towards outsourcing services
such as those provided by Construction Services, and management's goal is to
position Construction Services to take advantage of this trend.
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Construction Services competes with small- and medium-size regional underground
facilities contractors who provide similar services and utilize comparable
equipment and installation techniques. There is also competition from in-house
construction operations of existing or prospective customers. New federal
regulations in the United States require a minimum level of operator
qualifications for individuals performing certain tasks on pipelines. The
Company believes that the costs and training required for compliance with these
new regulations may force some of Construction Services' smaller competitors to
abandon certain pipeline work.
General economic conditions also have an impact on the amount or type of
work available for Construction Services. During economic downturns, new
housing starts often decline, which leads to a decrease in new gas service line
installations. Customers may also reduce amounts typically spent for
non-essential construction projects, which also leads to a decrease in work
available to Construction Services.
As discussed previously, the Company is redirecting its business strategy.
Under this redirected strategy, the Company's goal for Construction Services is
to expand its market share by focusing on profitable growth of its existing
construction businesses, with less emphasis on acquisitions. This change in
focus is intended to redirect resources to help maximize the profitability of
existing product offerings. As part of its strategic redirection, the Company
plans to divest itself of certain regional construction operations that are not
profitable. The Company also intends to consolidate certain regions of its
construction services operations. For additional information on the Company's
redirected business strategy, refer to Note 14 of the Notes to Consolidated
Financial Statements.
INFORMATION TECHNOLOGY SERVICES
This is the first year that the Company is reporting its information technology
("IT") services business as a separate business segment. This business, under
the Aretech Information Services name ("Aretech"), began operations in April of
2000 and provides IT infrastructure outsourcing services, and other IT services
with a focus on mid-range computers, particularly the IBM
AS-400 platform.
OPERATING REVENUES. Operating revenues were $10.3 million in 2001, compared to
$5.2 million in 2000. Of these amounts $9.3 million and $5.0 million for 2001
and 2000, respectively, represent sales to affiliates. The increase in revenues
in 2001, when compared to 2000, was due primarily to providing IT services for
all affiliates of the Company and the addition of non-affiliate customers.
During the first several months of its operation in 2000, the IT services
business was primarily providing services to the Michigan gas distribution
operation and the Company's corporate office. Non-affiliate operating revenues
were $1.0 million in 2001 and $.2 million in 2000.
Years Ended December 31, 2001 2000 1999
- ------------------------- ------- ------ -----
(in thousands)
Operating revenues. . . . $10,275 $5,184 $ -
Restructuring charges . . 20 - -
Other operating expenses. 9,824 4,703 -
------- ------ -----
Operating income. . . . . $ 431 $ 481 $ -
======= ====== =====
<FN>
This business began operations in April of 2000
The amounts in the above table include intercompany transactions.
26
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
OPERATING INCOME. Operating income for the IT business was $.4 million and $.5
million for 2001 and 2000, respectively. During 2000, the IT business performed
more special project services, which typically is higher margin work.
OUTLOOK FOR IT SERVICES. The Company believes there is a growing trend by small
to mid-sized companies to outsource certain information technology functions.
The Company believes the trend towards outsourcing large mainframe computing
services is now moving to include mid-range computers. The Company's goal is to
capitalize on its internal expertise in this area and position this business to
take advantage of these trends. Aretech's business strategy is focused on IT
infrastructure outsourcing services and business-to-consumer and
business-to-business Internet commerce.
Aretech competes with businesses that range from small local firms to large
international companies, as well as the in-house IT departments of potential
customers. Aretech is an early provider in the mid-range computer outsourcing
market and, as the market expands, it is likely that new competition will arise
from other firms that possess the necessary technical skills.
PROPANE, PIPELINES AND STORAGE
The Company's natural gas pipeline and storage operations consist of several
transmission pipelines and an ownership interest in a gas storage facility, all
of which are located in Michigan. The Company also owns a propane distribution
business ("Hotflame"), which sells more than 4 million gallons of propane to
retail customers in Michigan's upper peninsula and northeast Wisconsin.
OPERATING REVENUES. Operating revenues were $7.4 million in 2001, compared to
$6.9 million in 2000 and $6.3 million in 1999. The increase in revenues in 2001,
when compared to 2000, was due primarily to higher propane distribution revenues
resulting from an increase in the market price of propane. The increase in
revenues in 2000, compared to 1999, was due primarily to higher propane
distribution revenues, offset partially by slightly lower pipeline revenues.
Pipeline revenues decreased in 2000 due to the absence of revenues from a
pipeline that was sold in mid-1999.
Years Ended December 31, 2001 2000 1999
- ------------------------- ------ ------ ------
(in thousands)
Operating revenues. . . . $7,443 $6,949 $6,284
Operating expenses. . . . 5,572 5,419 3,943
------ ------ ------
Operating income. . . . . $1,871 $1,530 $2,341
====== ====== ======
OPERATING INCOME. The Company's Propane, Pipelines and Storage segment had
operating income during 2001, 2000 and 1999 of $1.9 million, $1.5 million and
$2.3 million, respectively. The increase during 2001, when compared to 2000 was
due primarily to lower operating expenses and higher propane margins, offset
partially by the impact of warmer weather. The decrease during 2000, when
compared to 1999, was caused primarily by higher propane costs, which reduced
propane margins, and the absence of operating income from the pipeline that was
sold in mid-1999. In addition, Hotflame's profit margins were slightly lower in
2000 as a result of customer price reductions caused by increased competition in
the propane industry.
Weather in Hotflame's market area was warmer than normal in 2001, 2000 and
1999. Operating income on a weather-normalized basis would have been higher by
approximately $.1 million during 2001 and 2000, respectively, and $.3 million
during 1999. The impact of weather on the operating income of the propane,
pipelines and storage segment relates entirely to the propane business.
27
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
OUTLOOK FOR PROPANE, PIPELINE AND STORAGE. Management believes that the gas
pipeline and storage operations could experience opportunities for growth with
the increased deregulation of gas markets. As gas markets expand or are
deregulated, management believes that the quantity of gas moving through the
Great Lakes Region will increase, which could create additional pipeline and
storage opportunities.
The Company's propane business competes with other regional propane
providers and with other energy sources such as natural gas, fuel oil and
electricity. The propane business has become increasingly competitive and less
profitable. The Company will continue to assess the strategic fit of this
business over the coming years.
OTHER INCOME AND DEDUCTIONS
Years Ended December 31, 2001 2000 1999
- ----------------------------------------- --------- --------- ---------
(in thousands)
Interest expense. . . . . . . . . . . . . $(31,784) $(34,905) $(20,490)
Divestiture of energy marketing business. - - 1,122
Other income. . . . . . . . . . . . . . . 2,335 2,828 2,618
--------- --------- ---------
Total other income (deductions) . . . . $(29,449) $(32,077) $(16,750)
========= ========= =========
INTEREST EXPENSE. Interest expense decreased by $3.1 million (or 8.9%) in 2001
when compared to 2000. The decrease is due primarily to lower debt levels as a
result of refinancing the $290 million short-term bridge loan, which was
utilized to finance the November 1, 1999 acquisition of ENSTAR, with various
securities offerings during the second and third quarters of 2000. Therefore,
the bridge loan was outstanding during the first half of 2000, while during the
last half of 2000 and all of 2001, the Company had long-term debt and trust
preferred securities outstanding. As a result, interest expense was less in 2001
primarily because the dividends on the trust preferred securities are reported
separately from interest expense. Lower short-term interest rates during 2001
also contributed to the overall decrease in interest expense. However, these
factors were partially offset by $2.1 million of non-recurring income from
terminated interest rate swaps, reflected in 2000 interest expense, and interest
on additional debt incurred in 2001 to finance the Company's capital expenditure
programs.
The Company's 2000 interest expense increased $14.4 million (or 70%) when
compared to 1999. The increase was due primarily to increases in debt levels to
finance the Company's capital expenditure and business acquisition programs and
for general corporate purposes. The increases during 2000 were offset partially
by $2.1 million of income recognized on interest rate swaps terminated in 2000.
The most significant increase in debt levels occurred on November 1, 1999, when
the Company incurred the bridge loan discussed above. The bridge loan was repaid
during 2000 with the proceeds of several securities offerings and borrowings
from the Company's bank lines of credit, which are discussed in Note 5 of the
Notes to the Consolidated Financial statements.
DIVESTITURE OF ENERGY MARKETING BUSINESS. The Company sold the subsidiary
comprising its energy marketing business effective March 31, 1999. The
divestiture resulted in a gain of $1.1 million ($.7 million after-tax).
OTHER INCOME. In 2001, other income decreased by $.5 million when compared to
2000. The decrease was due primarily to the write-off of certain assets in 2001
and gains on property sales in 2000. These factors were partially offset by an
increase in allowance for funds used during construction ("AFUDC") and an
increase in interest income. The increase in interest income was the result of
interest received on a supplier refund in 2001.
During 2000, other income increased by $.2 million, when compared to 1999.
The increase was due primarily to an increase in AFUDC associated with two
construction projects, an increase in equity income from an investment in a gas
storage partnership and gains on property sales. These increases were offset
partially by the absence in 2000 of life insurance proceeds received in 1999
upon the death of a retired Company executive.
28
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
INCOME TAXES
Income taxes for 2001, 2000 and 1999 were $6.6 million, $11.6 million and $7.6
million, respectively. The change in income taxes, when comparing one year to
another, is due primarily to changes in income before income taxes and dividends
on trust preferred securities, and any adjustments necessary for compliance with
tax laws and regulations.
DIVIDENDS ON TRUST PREFERRED SECURITIES
The Company issued trust preferred securities and FELINE PRIDES during the
second quarter of 2000. These securities are described in Note 5 of the Notes to
the Consolidated Financial Statements. Dividends on these securities, net of
income tax, were $8.6 million during 2001 and $5.0 million in 2000. The $3.6
million increase in dividends in 2001, when compared to 2000, was the result of
a full year of dividends during 2001, in comparison to a half year of dividends
during 2000.
DISCONTINUED OPERATIONS
In December 2001, the Company's Board of Directors approved a plan to redirect
the Company's business strategy, which, as discussed previously, includes the
divestiture of its engineering services business. The planned divestiture is
being accounted for as a discontinued operation and, accordingly, the operating
results and the estimated loss on the disposal of this business are segregated
and reported as discontinued operations in the Consolidated Statements of
Income, with prior years restated. For additional information, including a
component breakdown of operating results reflected in discontinued operations,
refer to Note 14 of the Notes to Consolidated Financial Statements.
LIQUITY AND CAPITAL RESOURCES
CASH FLOWS FROM INVESTING. The Company's single largest use of cash is capital
investments. The following table identifies investments for the past three
years:
Years Ended December 31, 2001 2000 1999
- -------------------------------------------------------- ------- ------- --------
(in thousands)
Capital investments
Property additions - gas distribution. . . . . . . . . $34,074 $47,466 $ 22,761
Property additions - diversified businesses and other. 21,370 19,170 12,258
Business acquisitions (a). . . . . . . . . . . . . . . - 1,784 305,142
------- ------- --------
$55,444 $68,420 $340,161
======= ======= ========
<FN>
(a) Includes the net amounts paid for business acquisitions, including non-cash
amounts such as deferred payments and value, at the time of issuance, of Company
stock issued as part of the acquisitions.
Property additions for the Gas Distribution Business represent primarily
gas service lines for new customers and, to a lesser extent, gas main and
service line replacements. However, during 2001 and 2000 the Michigan gas
distribution operation incurred approximately $1.1 million and $7.9 million,
respectively, to construct a large diameter transmission pipeline to supply a
power generation plant. In addition, the Company invested approximately $5.9
million, $11.9 million and $2.4 million in technology in 2001, 2000 and 1999,
respectively. This technology consists of automated meter reading, measurement
systems and other computer system and infrastructure improvements that have
increased customer service and administrative and operational efficiency.
29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Business acquisitions were approximately $1.8 million and $305.1 million in 2000
and 1999, respectively. Business acquisitions for 1999 include the acquisition
of ENSTAR for approximately $290 million. There were no acquisitions in 2001.
In 2002, the Company plans to spend approximately $40 million on property
additions. This is significantly less than the $55 million the Company spent in
2001 for property additions. The anticipated decrease for 2002 is largely the
result of reducing capital expenditures for construction equipment and the
completion in 2001 of a number of large technology projects.
CASH FLOWS FROM OPERATIONS. The Company's net cash provided from operating
activities totaled $36.7 million in 2001, $49.0 million in 2000 and $41.2
million in 1999. The change in operating cash flows is influenced significantly
by changes in the level and cost of gas in underground storage, changes in
accounts receivable and accrued revenue and other working capital changes. The
changes in these accounts are largely the result of how the Company manages the
timing of cash receipts and payments.
The Company uses significant amounts of short-term borrowings to finance
natural gas purchases for storage during the non-heating season. The Company
owns and leases natural gas storage facilities in Michigan, with available
capacity approximating 35% of the Company's average annual Michigan gas sales.
Generally, gas is stored during the months of April through October and
withdrawn for sale from November through March.
CASH FLOWS FROM FINANCING. The Company received net cash from financing
activities of $19.3 million, $13.6 million and $287.4 million in 2001, 2000 and
1999, respectively.
Years Ended December 31, 2001 2000 1999
- ------------------------------------------------- --------- ---------- ---------
(in thousands)
Cash provided by financing activities
Issuance of common stock, net of repurchases. . $ 2,436 $ 865 $ 3,726
Issuance of trust preferred securities. . . . . - 134,885 -
Issuance of long-term debt, net of redemptions. 58,286 136,569 -
Net cash change in notes payable. . . . . . . . (26,185) (243,708) 302,347
Redemption of preferred stock . . . . . . . . . - - (3,281)
Payment of dividends. . . . . . . . . . . . . . (15,193) (15,033) (15,442)
--------- ---------- ---------
$ 19,344 $ 13,578 $287,350
========= ========== =========
The Company's net funds borrowed (paid) on notes payable were ($26.2
million), ($243.7 million) and $302.3 million in 2001, 2000 and 1999,
respectively. On November 1, 1999, the Company financed the acquisition of
ENSTAR with a $290 million unsecured bridge loan. In 2000, the Company utilized
the proceeds of several securities offerings and its short-term bank lines of
credit to repay the bridge loan. During 2001, the Company issued $60 million of
long-term debt and used the proceeds to repay a portion of its short-term lines
of credit with banks. The net change in notes payable for 2000 includes the
combined cash borrowed or paid on the Company's short-term lines of credit with
banks and the ENSTAR bridge loan.
The Company redeemed certain of its securities and issued various debt and
equity securities during the past three years. Refer to Note 5 of the Notes to
the Consolidated Financial Statements for information regarding these
redemptions and issues.
Cash dividends paid per share for common shareholders were $.839, $.835 and
$.863 in 2001, 2000 and 1999, respectively. The 1999 dividends include a
one-time special cash dividend of $.05 per share.
NON-CASH FINANCING ACTIVITIES. The Company issued .1 million shares and .2
million shares of its common stock to the shareholders of businesses acquired
during 2000 and 1999, respectively. As part of a business acquisition in 1999,
the Company and sellers agreed to defer a portion of the purchase price. Under
the acquisition agreement, this additional payment, in the amount of $1.0
million due in April 2002, is subject to set-off for certain liabilities. The
Company expects to seek recovery from the sellers for liabilities and damages in
excess of $1.0 million, and to deposit the $1.0 million in an interest bearing
account, pursuant to the acquisition agreement, pending resolution of the
Company's claims.
30
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
OFF-BALANCE SHEET ARRANGEMENTS. The Company does not have any off-balance sheet
financing arrangements.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS. Summarized below are the
contractual obligations and other commercial commitments of the Company.
As of December 31, 2001
- ----------------------------------------------------------------------------------------------------
(in millions) Payments Due by Period
-------------------------------------------------
2006
Contractual Obligations Total 2002 2003 2004 2005 and beyond
- ------------------------------------------------- ------ ------ ----- ----- ------ -----------
Long-term debt (a). . . . . . . . . . . . . . . $365.0 $ 30.0 $ - $55.0 $ 15.0 $ 265.0
Trust preferred securities of subsidiaries (a) 141.0 - - - 101.0 40.0
Unconditional gas purchase
and gas transportation obligations. . . . . . 182.8 53.2 42.4 23.2 23.2 40.8
Operating leases. . . . . . . . . . . . . . . . 8.7 1.5 1.4 1.4 1.0 3.4
Miscellaneous notes payable . . . . . . . . . . 2.5 1.5 0.6 0.2 - 0.2
- ------------------------------------------------- ------ ------ ----- ----- ------ -----------
Total contractual cash obligations. . . . . . . . $700.0 $ 86.2 $44.4 $79.8 $140.2 $ 349.4
As of December 31, 2001
- ----------------------------------------------------------------------------------------------------
(in millions) Amount of Commitment Expiration Per Period
-------------------------------------------------
2006
Commercial commitments. . . . . . . . . . . . . . Total 2002 2003 2004 2005 and beyond
- ------------------------------------------------- ------ ------ ----- ----- ------ -----------
Lines of credit . . . . . . . . . . . . . . . . $145.0 $145.0 $ - $ - $ - $ -
<FN>
(a) Certain of these obligations could become due before their maturity under specific
circumstances. Refer to Note 5 of the Notes to the Consolidated Financial Statements for further
information.
FUTURE FINANCING. In general, the Company funds its capital expenditure program
and dividend payments with operating cash flows and the utilization of
short-term lines of credit. When appropriate, the Company will refinance its
short-term lines with long-term debt, common stock or other long-term financing
instruments. The Company has short-term lines of credit with banks of $145
million, all of which are committed facilities. At December 31, 2001, the unused
portion of the Company's lines of credit was $39.5 million. The Company's lines
of credit expire during June and July 2002 and the Company expects to put in
place lines of credit with comparable terms.
In March 2000, a registration statement on Form S-3 ("registration
statement") filed by the Company and SEMCO Capital Trust I, SEMCO Capital Trust
II and SEMCO Capital Trust III ("Capital Trusts") with the Securities and
Exchange Commission became effective. The Company and Capital Trusts registered
up to $500 million of securities under the registration statement, of which $276
million and $60 million were utilized to issue securities during 2000 and 2001,
respectively. The remaining balance of $164 million under the registration
statement is available for any future issues of common stock, preferred stock,
trust preferred securities and long-term debt, as needed. Refer to Note 5 of the
Notes to the Consolidated Financial Statements for additional information
regarding the registration statement and securities issued. The Company's $30
million of 6.83% notes are due in October 2002. The Company plans to refinance
these notes by issuing new long-term debt under the registration statement.
The Company intends to reduce future financing requirements through its
strategic redirection. This includes a reduction in future operating expenses as
a result of restructuring activities, a reduction in the amount of capital
expenditures when compared to previous years and the Company's expectation that
it will not make any additional acquisitions in 2002. In February 2002, the
Company also announced that its Board of Directors changed the dividend rate on
the common stock of the Company. Future dividends, when declared, will be at an
annual rate of $0.50 per share. Previously, the annual dividend rate was $0.84
per share.
The Company's long-term and short-term debt agreements contain restrictive
financial covenants including, among others, maintaining a Fixed Charges
Coverage Ratio (as defined in the agreements) of at least 1.50 and placing
limits on the payment of dividends beyond certain levels. Non-compliance with
31
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
these covenants could result in an acceleration of the due dates for the debt
obligations under the agreements. As of December 31, 2001, the Fixed Charges
Coverage Ratio was 1.55 and the Company was in compliance with all of the
covenants in these agreements. The Company has currently projected its financial
covenants for each of the four quarters during 2002, based on the Company's
forecasted operating results for the year, and these forecasted results show
that the Company would be able to remain in compliance with all of its covenants
during 2002. However, these forecasted results are dependent on several
internal assumptions and external factors. If these assumptions or factors
differ from management's current expectations, they could have an adverse impact
on the Company's ability to remain in compliance with its covenants during 2002.
The most significant assumptions and factors that could impact the ongoing
compliance with these covenants include the effects of weather on the Company's
operating results; the outcome of the ENSTAR rate case compared to management's
expectations; the ability of the Company to improve its operating results with
the implementation of the Company's new strategic direction; and the completion
of an asset impairment test under Statement of Financial Accounting Standards
("SFAS") 142 (to be adopted by the Company during 2002). Refer to the section
titled "New Accounting Standards" for more information.
In the event the Company is not able to remain in compliance with these
covenants, management plans to request a modification of the covenants or a
waiver of certain covenant provisions.
The Company's ratio of earnings to fixed charges, as defined under Item 502
of SEC regulations S-K, was 1.04, 1.60 and 2.18 for 2001, 2000 and 1999,
respectively. If common stock of the Company had been issued in place of the
FELINE PRIDES, the ratio of earnings to fixed charges for 2001 would have been
1.30. This ratio is more strictly defined than the Fixed Charges Coverage Ratio
used to determine compliance with the Company's previously discussed debt
covenants.
MARKET RISK INFORMATION
The Company's primary market risk arises from fluctuations in commodity prices
and interest rates. The Company's exposure to commodity price risk arises from
changes in natural gas and propane prices throughout the United States and in
eastern Canada, where the Company conducts sales and purchase transactions. The
Company does not currently use financial derivative instruments (such as swaps,
collars or futures) to manage its exposure to commodity price risk. A
significant portion of the natural gas requirements of the Company's Michigan
gas distribution operations are covered under the TransCanada/BP supply
arrangement. ENSTAR's natural gas requirements are primarily covered by a number
of long-term supply arrangements and an RCA-approved mechanism that passes
commodity costs through to its customers. In the first quarter of 2002, the
Company entered into new agreements with BP for the provision of its natural gas
supply requirements in Michigan. The agreements cover a three-year period
beginning April 1, 2002 through March 31, 2005. For further information on how
these agreements reduce the Company's exposure to commodity price risk, see Note
2 of the Notes to the Consolidated Financial Statements.
The Company is also subject to interest rate risk in connection with the
issuance of variable- and fixed-rate debt. In order to manage interest costs,
the Company may use interest rate swap agreements and exchange fixed- and
variable-rate interest payment obligations over the life of the agreements,
without exchange of the underlying principal amounts. See Note 1 of the Notes to
the Consolidated Financial Statements for additional information on the fair
value of interest rate swap agreements at December 31, 2001, and how the Company
accounts for its risk management activities.
IMPACT OF INFLATION
The cost of gas sold by ENSTAR is recovered from natural gas distribution
customers on a current basis through its gas cost adjustment ("GCA") clause.
Prior to April 1, 1999, the cost of gas sold by the Michigan gas distribution
operation was recovered from natural gas distribution customers on a current
basis through its GCR clause. The GCA and GCR mechanisms allow for the
adjustment of rates charged to customers in response to increases and decreases
in the cost of gas purchased. The MPSC authorized the Company to suspend its GCR
clause and freeze for three years in its base rate a gas charge of $3.24 per
Mcf. The GCR suspension and fixed gas charge took effect in April, 1999,
32
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
and will expire on March 31, 2002, after which the Company will reinstate its
GCR pricing mechanism for Michigan customers in the geographic areas subject to
the jurisdiction of the MPSC. The Company applied for and received approval from
the CCBC to extend the fixed gas charge program until March 31, 2005 for
customers located in the City of Battle Creek, Michigan and surrounding
communities. During the three-year extension period, the Company will charge
these customers a fixed gas charge of $4.85 per Dth. See Note 2 of the Notes to
the Consolidated Financial Statements for more information.
Increases in other utility operating costs are recovered through the
regulatory process of a rate case and, therefore, may adversely affect the
results of operations in inflationary periods due to the time lag involved in
this process. The Company attempts to minimize the impact of inflation by
controlling costs, increasing productivity and filing rate cases on a timely
basis.
NEW ACCOUNTING STANDARDS
In 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 141,
"Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets."
SFAS 141 addresses financial accounting and reporting for all business
combinations and requires that all business combinations entered into subsequent
to June 2001 be recorded under the purchase method. This statement also
addresses financial accounting and reporting for goodwill and other intangible
assets acquired in a business combination at acquisition. SFAS 142 addresses
financial accounting and reporting for intangible assets acquired individually
or with a group of other assets at acquisition. This statement also addresses
financial accounting and reporting for goodwill and other intangible assets
subsequent to their acquisition.
These statements will be adopted by the Company on January 1, 2002.
Goodwill amortization will cease as of December 31, 2001, which will reduce
annual amortization expense by approximately $3.0 million after income taxes (or
$0.16 per share based on the current level of outstanding common stock). The
Company will be required to complete an impairment test in the year of adoption,
and perform subsequent impairment tests on the remaining goodwill balance at
least annually. If an impairment test of goodwill shows that the carrying amount
of the goodwill is in excess of the fair value, a corresponding impairment loss
would be recorded in the consolidated statements of income. The Company has not
yet determined the financial impact of adopting these standards.
In August 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations," effective January 1, 2003. The standard requires entities to
record the fair value of a liability for an asset retirement obligation in the
period in which it is incurred.
When the liability is initially recorded, the entity capitalizes a cost by
increasing the carrying amount of the related long-lived asset. Over time, the
liability is accreted to its present value each period, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The Company is currently studying the new
standard but has yet to quantify the effects of adoption on its financial
statements.
In October 2001, the FASB issued SFAS 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets," which replaces SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and
Accounting Principles Board ("APB") Opinion 30, "Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business."
SFAS 144 requires long-lived assets to be measured at the lower of either
the carrying amount or of the fair value less the cost to sell, whether reported
in continuing operations or in discontinued operations. Therefore, discontinued
operations will no longer be measured at net realizable value or include amounts
for operating losses that have not yet occurred.
SFAS 144 also broadens the reporting of discontinued operations to include
all components of an entity with operations that can be distinguished from the
rest of the entity and that will be eliminated from the ongoing operations of
the entity in a disposal transaction. The adoption of SFAS 144, effective
January 1, 2002, will result in the Company accounting for any future impairment
or disposal of long-lived assets under the provisions of SFAS 144, but will not
change the accounting used for previous asset impairments or disposals.
33
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To SEMCO Energy, Inc.
We have audited the accompanying consolidated statements of financial
position and capitalization of SEMCO Energy, Inc. (a Michigan corporation) and
subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, changes in common shareholders' equity and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on the financial statements based on our
audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of SEMCO
Energy, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Detroit, Michigan
February 7, 2002
34
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2001 2000 1999
- -------------------------------------------------------------------- --------- --------- ---------
(000's, except per share amounts)
OPERATING REVENUES
Gas sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $295,397 $273,312 $191,169
Gas transportation . . . . . . . . . . . . . . . . . . . . . . . . 25,888 30,783 22,369
Construction services. . . . . . . . . . . . . . . . . . . . . . . 117,160 95,537 49,965
Gas Marketing. . . . . . . . . . . . . . . . . . . . . . . . . . . - - 96,855
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,378 10,693 9,564
--------- --------- ---------
445,823 410,325 369,922
--------- --------- ---------
OPERATING EXPENSES
Cost of gas sold . . . . . . . . . . . . . . . . . . . . . . . . . 184,973 161,945 117,789
Cost of gas marketed . . . . . . . . . . . . . . . . . . . . . . . - - 95,632
Operation and Maintenance. . . . . . . . . . . . . . . . . . . . . 162,289 140,236 85,696
Depreciation and amortization. . . . . . . . . . . . . . . . . . . 36,505 33,051 19,742
Property and other taxes . . . . . . . . . . . . . . . . . . . . . 11,562 9,860 8,660
Restructuring and impairment charges . . . . . . . . . . . . . . . 6,103 - -
--------- --------- ---------
401,432 345,092 327,519
--------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . 44,391 65,233 42,403
--------- --------- ---------
Other income (deductions)
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . (31,784) (34,905) (20,490)
Divestiture of energy marketing business . . . . . . . . . . . . . - - 1,122
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,335 2,828 2,618
--------- --------- ---------
(29,449) (32,077) (16,750)
--------- --------- ---------
INCOME BEFORE INCOME TAXES AND DIVIDENDS ON
TRUST PREFERRED SECURITIES. . . . . . . . . . . . . . . . . . . . 14,942 33,156 25,653
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,578 11,554 7,631
--------- --------- ---------
NET INCOME BEFORE DIVIDENDS ON TRUST PREFERRED SECURITIES. . . . . . 8,364 21,602 18,022
Dividends on trust preferred securities, net of
income taxes, of $4,632 and $2,695. . . . . . . . . . . . . . . . 8,603 5,004 -
--------- --------- ---------
NET INCOME FROM CONTINUING OPERATIONS. . . . . . . . . . . . . . . . (239) 16,598 18,022
DISCONTINUED OPERATIONS:
Income (loss) from engineering services operations, net of
income tax benefits (provisions) of $694, ($52) and $226 . . . . (1,142) 95 (363)
Estimated loss on divestiture of engineering services operations,
including provision for losses during phase-out period, net of
income tax benefits of $2,429. . . . . . . . . . . . . . . . . . (4,980) - -
--------- --------- ---------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS . . . . . . . . . $ (6,361) $ 16,693 $ 17,659
========= ========= =========
EARNINGS PER SHARE - BASIC
Net income (loss) from continuing operations . . . . . . . . . . . $ (0.01) $ 0.92 $ 1.02
Net income (loss) available to common shareholders . . . . . . . . $ (0.35) $ 0.93 $ 1.00
EARNINGS PER SHARE - DILUTED
Net income (loss) from continuing operations . . . . . . . . . . . $ (0.01) $ 0.89 $ 1.02
Net income (loss) available to common shareholders . . . . . . . . $ (0.35) $ 0.90 $ 1.00
CASH DIVIDENDS PAID PER SHARE. . . . . . . . . . . . . . . . . . . . $ 0.839 $ 0.835 $ 0.863
AVERAGE COMMON SHARES OUTSTANDING. . . . . . . . . . . . . . . . . . 18,106 17,999 17,697
========= ========= =========
<FN>
The accompanying notes to the consolidated financial statements are an integral part of these
statements.
35
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
DECEMBER 31, 2001 2000
- -------------------------------------------------------------------- -------- --------
(000's)
CURRENT ASSETS
Cash and temporary cash investments, at cost . . . . . . . . . . . $ 1,728 $ 1,221
Receivables, less allowances of $1,849 and $1,436. . . . . . . . . 64,219 73,139
Accrued revenue. . . . . . . . . . . . . . . . . . . . . . . . . . 33,153 32,212
Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . 22,276 14,309
Gas in underground storage . . . . . . . . . . . . . . . . . . . . 12,731 8,739
Materials and supplies, at average cost. . . . . . . . . . . . . . 5,258 5,065
Gas charges recoverable from customers . . . . . . . . . . . . . . 1,994 2,698
Accumulated deferred income taxes. . . . . . . . . . . . . . . . . - 6,994
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,608 946
-------- --------
144,967 145,323
-------- --------
PROPERTY PLANT AND EQUIPMENT
Gas distribution . . . . . . . . . . . . . . . . . . . . . . . . . 613,467 585,628
Diversified businesses and other . . . . . . . . . . . . . . . . . 94,514 79,167
-------- --------
707,981 664,795
Less - accumulated depreciation and impairments. . . . . . . . . . 183,436 154,769
-------- --------
524,545 510,026
-------- --------
DEFERRED CHARGES AND OTHER ASSETS
Goodwill, less amortization and impairments of $17,764 and $9,117. 161,084 169,692
Deferred retiree medical benefits. . . . . . . . . . . . . . . . . 9,891 10,790
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . 7,831 6,966
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,230 8,426
-------- --------
194,036 195,874
-------- --------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . $863,548 $851,223
======== ========
CURRENT LIABILITIES
Notes payable and current maturities of long-term debt . . . . . . $137,957 $134,142
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . 30,410 32,300
Customer advance payments. . . . . . . . . . . . . . . . . . . . . 13,530 13,068
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . 7,665 8,020
Amounts payable to customers . . . . . . . . . . . . . . . . . . . 1,463 3,097
Accumulated deferred income taxes. . . . . . . . . . . . . . . . . 912 -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,076 10,774
-------- --------
209,013 201,401
-------- --------
DEFERRED CREDITS AND OTHER LIABILITIES
Accumulated deferred income taxes. . . . . . . . . . . . . . . . . 33,149 36,385
Customer advances for construction . . . . . . . . . . . . . . . . 15,548 14,444
Unamortized investment tax credit. . . . . . . . . . . . . . . . . 1,445 1,713
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,223 14,504
-------- --------
62,365 67,046
-------- --------
CAPITALIZATION
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . 338,966 307,930
Company-obligated mandatorily redeemable trust preferred
securities of subsidiaries holding solely debt securities
of SEMCO Energy, Inc.. . . . . . . . . . . . . . . . . . . . . . 139,394 139,374
Common shareholders' equity. . . . . . . . . . . . . . . . . . . . 113,810 135,472
-------- --------
592,170 582,776
-------- --------
TOTAL LIABILITIES AND CAPITALIZATION . . . . . . . . . . . . . . . . $863,548 $851,223
======== ========
<FN>
The accompanying notes to the consolidated financial statements are an integral part of
these statements
36
CONSOLIDATED STATEMENTS OF CASH FLOW
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ----------------------------------------------------------------- --------- ---------- ----------
(000,s)
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . $ (6,361) $ 16,693 $ 17,659
Adjustments to reconcile net income to net
cash from operating activities:
Depreciation and amortization . . . . . . . . . . . . . . 36,505 33,051 19,742
Depreciation and amortization in discontinued operations. 454 421 264
Non-cash impairment charges . . . . . . . . . . . . . . . 7,679 - -
Divestiture of energy marketing business. . . . . . . . . - - (1,122)
Changes in assets and liabilities, net of effects of
acquisitions, divestitures and other changes as
shown below: . . . . . . . . . . . . . . . . . . . . . (1,621) (1,203) 4,661
--------- ---------- ----------
NET CASH FROM OPERATING ACTIVITIES. . . . . . . . . . . . . . . . 36,656 48,962 41,204
--------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Property additions - gas distribution . . . . . . . . . . . . . (34,074) (47,466) (22,761)
Property additions - diversified businesses and other . . . . . (21,370) (19,170) (12,258)
Proceeds from property sales, net of retirement costs . . . . . (49) 15 1,657
Proceeds from business divestiture. . . . . . . . . . . . . . . - - 6,579
Acquisitions of businesses, net of cash acquired. . . . . . . . - (784) (300,638)
--------- ---------- ----------
NET CASH FROM INVESTING ACTIVITIES. . . . . . . . . . . . . . . . (55,493) (67,405) (327,421)
--------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock, net of expenses . . . . . . . . . . . 2,436 865 6,110
Repurchase of common stock and related expenses . . . . . . . . - - (2,384)
Issuance of trust preferred securities, net of expenses . . . . - 134,885 -
Net cash change in notes payable. . . . . . . . . . . . . . . . (26,185) (243,708) 302,347
Issuance of long-term debt, net of expenses . . . . . . . . . . 58,296 136,619 -
Repayment of long-term debt and related expenses. . . . . . . . (10) (50) -
Redemption of preferred stock . . . . . . . . . . . . . . . . . - - (3,281)
Payment of dividends. . . . . . . . . . . . . . . . . . . . . . (15,193) (15,033) (15,442)
--------- ---------- ----------
NET CASH FROM FINANCING ACTIVITIES. . . . . . . . . . . . . . . . 19,344 13,578 287,350
--------- ---------- ----------
CASH AND TEMPORARY CASH INVESTMENTS
Net increase (decrease) . . . . . . . . . . . . . . . . . . . . 507 (4,865) 1,133
Beginning of period . . . . . . . . . . . . . . . . . . . . . . 1,221 6,086 4,953
--------- ---------- ----------
END OF PERIOD . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,728 $ 1,221 $ 6,086
========= ========== ==========
CHANGES IN ASSETS AND LIABILITIES, NET OF EFFECTS OF
ACQUISITIONS, DIVESTITURES AND OTHER CHANGES:
Receivables, net. . . . . . . . . . . . . . . . . . . . . . $ 8,920 $ 7,161 $ (39,488)
Accrued revenue . . . . . . . . . . . . . . . . . . . . . . (941) (6,832) 13,497
Prepaid expenses. . . . . . . . . . . . . . . . . . . . . . (7,967) 12 (2,538)
Materials, supplies and gas in
underground storage . . . . . . . . . . . . . . . . . . . (4,185) 4,065 23,349
Gas charges recoverable from customers. . . . . . . . . . . 704 311 8,547
Accounts payable. . . . . . . . . . . . . . . . . . . . . . (1,890) (3,780) (2,143)
Customer advances and amounts payable
to customers . . . . . . . . . . . . . . . . . . . . . . (68) (4,036) 4,189
Accumulated deferred taxes and investment tax credit. . . . 4,402 6,877 1,651
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . (596) (4,981) (2,403)
--------- ---------- ----------
$ (1,621) $ (1,203) $ 4,661
========= ========== ==========
<FN>
The accompanying notes to the consolidated financial statements are an integral part of these
statements
37
CONSOLIDATED STATEMENTS OF CAPITALIZATION
YEARS ENDED DECEMBER 31, 2001 2000
- ---------------------------------------------------------------- --------- --------
(000,s)
CURRENT MATURITIES OF LONG-TERM DEBT
6.83% notes due 2002. . . . . . . . . . . . . . . . . . . . . $ 30,000 $ -
--------- --------
CAPITALIZATION
LONG-TERM DEBT
6.83% notes due 2002. . . . . . . . . . . . . . . . . . . . . $ - $ 30,000
8.00% notes due 2004. . . . . . . . . . . . . . . . . . . . . 56,900 55,000
7.20% notes due 2007. . . . . . . . . . . . . . . . . . . . . 30,000 30,000
8.95% notes due 2008, remarketable 2003 . . . . . . . . . . . 106,179 106,919
8.00% notes due 2010. . . . . . . . . . . . . . . . . . . . . 30,887 31,011
8.00% notes due 2016. . . . . . . . . . . . . . . . . . . . . 60,000 -
8.32% notes due 2024. . . . . . . . . . . . . . . . . . . . . 25,000 25,000
6.50% medium-term notes due 2005. . . . . . . . . . . . . . . 15,000 15,000
6.40% medium-term notes due 2008. . . . . . . . . . . . . . . 5,000 5,000
7.03% medium-term notes due 2013. . . . . . . . . . . . . . . 10,000 10,000
--------- --------
$338,966 $307,930
--------- --------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED
SECURITIES OF SUBSIDIARIES HOLDING SOLELY DEBT SECURITIES OF
SEMCO ENERGY, INC.
10.25% cumulative trust preferred securities - 1,600,000
shares issued and outstanding . . . . . . . . . . . . $ 38,394 $ 38,374
FELINE PRIDES -10,100,000 shares issued and outstanding . 101,000 101,000
--------- --------
$139,394 $139,374
--------- --------
COMMON SHAREHOLDERS' EQUITY
Common stock, par value $1 per share - 40,000,000 shares
authorized; 18,240,143 and 18,055,639 shares outstanding. $ 18,240 $ 18,056
Capital surplus . . . . . . . . . . . . . . . . . . . . . . . 117,091 115,186
Accumulated other comprehensive income (loss) . . . . . . . . (2,196) -
Retained earnings (deficit) . . . . . . . . . . . . . . . . . (19,325) 2,230
--------- --------
$113,810 $135,472
--------- --------
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . $592,170 $582,776
========= ========
<FN>
The accompanying notes to the consolidated financial statements are an integral part
of these statements.
38
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ----------------------------------------------------------- --------- --------- ---------
(000,s)
COMMON STOCK
Beginning of year. . . . . . . . . . . . . . . . . . . . $ 18,056 $ 17,909 $ 17,382
Issuance of common stock for acquisitions,
the DRIP and other. . . . . . . . . . . . . . . . 184 147 686
Repurchase of common stock . . . . . . . . . . . . . - - (159)
--------- --------- ---------
End of year. . . . . . . . . . . . . . . . . . . . . . . $ 18,240 $ 18,056 $ 17,909
========= ========= =========
COMMON STOCK CAPITAL SURPLUS
Beginning of year. . . . . . . . . . . . . . . . . . . . $115,186 $123,861 $116,663
Issuance of common stock for acquisitions,
the DRIP and other. . . . . . . . . . . . . . . . 2,256 1,718 9,423
Repurchase of common stock . . . . . . . . . . . . . - - (2,225)
Costs related to FELINES PRIDES (see Note 5) . . . . (351) (10,393) -
--------- --------- ---------
End of year. . . . . . . . . . . . . . . . . . . . . . . $117,091 $115,186 $123,861
========= ========= =========
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Beginning of year. . . . . . . . . . . . . . . . . . . . $ - $ - $ -
Minimum pension liability adjustment, net of income
tax benefits of $781 (See Note 8). . . . . . . . . (1,452) - -
Unrealized derivative loss on interest rate
hedge from an investment in an affiliate . . . . . (744) - -
--------- --------- ---------
End of year. . . . . . . . . . . . . . . . . . . . . . . $ (2,196) $ - $ -
========= ========= =========
RETAINED EARNINGS (DEFICIT)
Beginning of year. . . . . . . . . . . . . . . . . . . . $ 2,230 $ 570 $ (1,817)
Net income (loss). . . . . . . . . . . . . . . . . . (6,361) 16,693 17,659
Cash dividends on common stock . . . . . . . . . . . (15,194) (15,033) (15,272)
--------- --------- ---------
End of year. . . . . . . . . . . . . . . . . . . . . . . $(19,325) $ 2,230 $ 570
========= ========= =========
DISCLOSURE OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ----------------------------------------------------------- --------- --------- ---------
(000,s)
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS. . . . . $ (6,361) $ 16,693 $ 17,659
Minimum pension liability adjustment, net of
income tax benefits of $781 (See Note 8) . . . . . . . (1,452) - -
Unrealized derivative loss on interest rate
hedge from an investment in an affiliate . . . . . . . (744) - -
--------- --------- ---------
TOTAL COMPREHENSIVE INCOME (LOSS) . . . . . . . . . . . . . $ (8,557) $ 16,693 $ 17,659
========= ========= =========
<FN>
The accompanying notes to the consolidated financial statements are an integral part of
these statements.
39
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
COMPANY DESCRIPTION. SEMCO Energy, Inc., is an investor-owned company. SEMCO
Energy, Inc. and its subsidiaries (the "Company") operate four reportable
business segments: (1) gas distribution; (2) construction services; (3)
information technology services; and (4) propane, pipelines and storage. The
latter three segments are sometimes referred to together as the "Diversified
Businesses." The Company's gas distribution business segment distributes and
transports natural gas to approximately 267,000 customers in the state of
Michigan and approximately 108,000 customers in the state of Alaska. The
Alaska-based operation and the Michigan-based operation are known together as
the "Gas Distribution Business" and operate as divisions of SEMCO Energy, Inc.
SEMCO Energy Gas Company, which had conducted the Michigan gas distribution
operation, was merged into SEMCO Energy, Inc. on December 31, 1999.
The construction services segment ("Construction Services") currently
conducts most of its business in the midwestern, southern and southeastern areas
of the United States. Its primary service is the installation of underground
natural gas mains and service lines. Construction Services also provides
underground construction services to other industries such as telecommunications
and water supply.
Effective January 1, 2001, the Company started reporting its information
technology services business as a reportable business segment. The information
technology services segment ("IT Services") is headquartered in Michigan and
provides IT infrastructure outsourcing services and other IT services with a
focus on mid-range computers, particularly the IBM AS-400 platform. The
Company's other business segments currently account for a large portion of IT
Services revenues.
The propane, pipelines and storage segment sells more than 4 million
gallons of propane annually to retail customers in Michigan's upper peninsula
and northeast Wisconsin and operates natural gas transmission and storage
facilities in Michigan.
The Company began accounting for its engineering services segment as a
discontinued operation, effective with the fourth quarter of 2001. For
additional information, refer to the "Discontinued Operations" disclosure within
this Note.
BASIS OF PRESENTATION. The financial statements of the Company were prepared in
conformity with accounting principles generally accepted in the United States.
In connection with the preparation of the financial statements, management was
required to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include the
accounts of SEMCO Energy, Inc. and its wholly-owned subsidiaries. Investments in
unconsolidated companies where the Company has significant influence, but does
not control the entity, are reported using the equity method of accounting.
Certain of the Company's diversified businesses, primarily Construction
Services, IT Services, and the discontinued engineering business supply services
at a profit to the Company's regulated gas distribution business. In these
situations, intercompany profits remaining in the assets of the regulated
business at a particular date are not eliminated since it is probable that,
through the ratemaking process, the cost will be recovered through future
revenue. As a result, $.6 million, $.9 million and $.4 million of profit on
revenues earned from the Company's regulated business by the Company's
diversified businesses was not eliminated during consolidation in 2001, 2000,
and 1999 respectively. All other significant intercompany transactions have been
eliminated.
RECLASSIFICATIONS. Certain reclassifications have been made to prior years'
financial statements to conform to the 2001 presentation.
RATE REGULATION. The rates of gas distribution customers located in the City of
Battle Creek, Michigan, and surrounding communities are subject to the
jurisdiction of the City Commission of Battle Creek("CCBC"). The Michigan Public
Service Commission ("MPSC") authorizes the rates charged to all of the remaining
Michigan customers. The gas distribution operation in Alaska is subject to
regulation by the Regulatory Commission of Alaska ("RCA") which has jurisdiction
over, among other things, rates, accounting procedures, and standards of
service.
40
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
PROPERTY, PLANT, EQUIPMENT AND DEPRECIATION. The Company's property, plant and
equipment ("property") is recorded at cost. The Company provides for
depreciation on a straight-line basis over the estimated useful lives of the
related property. The ratio of depreciation to the average balance of property
approximated 4.7% for the years 2001 and 2000, and 4% for the year 1999.
GAS IN UNDERGROUND STORAGE. The gas inventory held by the Battle Creek division
of the Gas Distribution Business is stated at last-in, first-out ("LIFO") cost.
At December 31, 2001, and 2000, the replacement cost of the Battle Creek
division's gas inventory exceeded the LIFO cost by $0.2 million and $0.1
million, respectively. The remainder of gas inventory is reported at average
cost.
In general, commodity costs and variable transportation costs are
capitalized as gas in underground storage. Fixed costs, primarily pipeline
demand charges and storage charges, are expensed as incurred through cost of
gas.
GOODWILL. Goodwill represents the excess of purchase price and related costs
over the value assigned to the net tangible assets of businesses acquired.
Goodwill is amortized on a straight-line basis over periods of up to 40 years.
Periodically, the Company reviews the recoverability of goodwill. The
measurement of possible impairment is based primarily on the ability to recover
the balance of the goodwill from expected future operating cash flows on an
undiscounted basis. During 2001, the Company recorded a charge of $4.0 million
for the impairment of goodwill associated with the Company's construction
services segment and its discontinued engineering services business. In
management's opinion, no other impairment existed at December 31, 2001.
Amortization expense was approximately $4.6 in 2001, $4.0 million in 2000 and
$1.6 million in 1999. Effective January 1, 2002, Goodwill amortization will
cease in compliance with the adoption of Statement of Financial Accounting
Standards ("SFAS") 142, "Goodwill and Other Intangible Assets."
LONG-TERM NOTE RECEIVABLE. The Company sold its entire interest in NOARK to
ENOGEX Arkansas Pipeline Corporation ("ENOGEX") in 1998. Pursuant to the terms
included in the sales agreement, the Company will receive annual payments of
$0.8 million from ENOGEX for 17 years beginning in the year 2004. At December
31, 2001, the Company has a long-term discounted note receivable of $7.1 million
for this note.
REVENUE RECOGNITION. The Gas Distribution Business bills monthly on a cycle
basis and follows the industry practice of recognizing accrued revenue for gas
services rendered to its customers but not billed at month end. Engineering
Services and Construction Services recognize revenues as services are rendered
and recognize accrued revenue for services rendered but not billed at month end.
The propane business recognizes propane sales in the same period that the
propane is delivered to customers.
COST OF GAS. Prior to April 1, 1999, the Company's Michigan-based gas
distribution operation had a regulator-approved gas cost recovery ("GCR")
mechanism for the geographic areas subject to the regulatory jurisdiction of the
MPSC and CCBC, which allowed for the adjustment of rates charged to customers in
response to increases and decreases in the cost of gas purchased. Effective
April 1, 1999, the MPSC and CCBC authorized the Company to suspend the GCR
clause and freeze for three years in base rates a fixed gas charge of $3.24 per
Mcf. The suspension period for the GCR mechanism expires on March 31, 2002,
after which the Company will reinstate its GCR pricing mechanism for customers
subject to the jurisdiction of the MPSC. The Company received approval from the
CCBC to extend the fixed gas charge program and GCR suspension period until
March 31, 2005. See Note 2 for further information.
The Alaska-based gas distribution operation also has a regulator-approved
gas cost adjustment ("GCA") mechanism, which allows for the adjustment of rates
charged to customers for increases and decreases in the cost of gas purchased.
All gas sales rates are adjusted annually to reflect changes in the operation's
cost of purchased gas based on estimated costs for the upcoming 12-month period.
The GCA may be adjusted quarterly if it is determined that there are significant
variances from the estimates used in the annual determination. Any difference
between actual cost of gas purchased and the RCA's approved rate adjustment is
deferred and included with applicable carrying charges in the next GCA.
In accordance with the GCR mechanism, the Company had $2.0 million recorded
in current assets at December 31, 2001 for gas charges recoverable from
customers. Also at December 31, 2001, the Company had $1.5 million recorded in
current liabilities for amounts payable to customers in accordance with the GCA
mechanism.
41
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
RISK MANAGEMENT ACTIVITIES AND DERIVITIVE TRANSACTIONS. The Company's business
activities expose it to a variety of risks, including commodity price risk and
interest rate risk. The Company's management identifies risks associated with
the Company's business and determines which risks it wants to manage and which
type of instruments it should use to manage those risks.
On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," and SFAS 137 and SFAS 138, which
were amendments to SFAS 133 (hereinafter collectively referred to as "SFAS
133"). SFAS 133 was effective for fiscal years beginning after June 15, 2000,
and establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the statement of financial position as either an
asset or liability measured at its fair value. SFAS 133 requires that changes in
the derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting.
Certain gas purchase contracts of the Company qualify under the provisions
of SFAS 133 as fair value hedges and require the recognition of the derivatives
at their fair value in the Consolidated Statements of Financial Position as an
asset or liability. Upon adoption of SFAS 133 on January 1, 2001, the Company
recorded an asset and liability of $1.4 million. In accordance with SFAS 133, at
December 31, 2001, the Company had an asset and liability of $0.8 million
recorded in its Consolidated Statements of Financial Position for these gas
purchase contracts.
An affiliate, in which the Company has a 50% investment, uses an interest
rate swap agreement to hedge the variable interest rate payments on its
long-term debt. This agreement qualifies under the provisions of SFAS 133 as a
cash flow hedge. As a result of this interest rate swap agreement, the Company's
Consolidated Statements of Financial Position, at December 31, 2001, reflected a
$.7 million reduction in the Company's equity investment in the affiliate and in
accumulated other comprehensive income.
In August 2001 the Company entered into an interest rate swap agreement in
order to hedge its $55 million 8% Notes due June 1, 2004. This agreement also
qualifies under the provisions of SFAS 133 as a fair value hedge. In accordance
with SFAS 133, the Company's Consolidated Statements of Financial Position, at
December 31, 2001, included an asset of $1.9 million and an increase in
long-term debt of $1.9 million for this interest rate swap. For further
information concerning the interest rate swap agreement, refer to Note 5.
INCOME TAXES. Investment tax credits ("ITC") utilized in prior years for income
tax purposes are deferred for financial accounting purposes and are amortized
through credits to the income tax provision over the lives of the related
property. The Company files a consolidated federal income tax return and income
taxes are allocated among the subsidiaries within each business segment based on
their separate taxable income.
DISCONTINUED OPERATIONS. In December 2001, the Company's board of directors
approved a plan to redirect the Company's business strategy, which includes the
divestiture, by sale, of its engineering services business. The planned
divestiture is being accounted for as a discontinued operation and, accordingly,
its operating results and estimated loss on disposal are segregated and reported
as discontinued operations in the Consolidated Statements of Income, with prior
years restated. For additional information, refer to Note 14 of the Notes to
Consolidated Financial Statements.
42
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
STATEMENTS OF CASH FLOW. For purposes of the Consolidated Statements of Cash
Flow, the Company considers all highly liquid investments purchased with
original maturities of three months or less to be cash and temporary cash
investments. Supplemental cash flow information for the years ended December 31,
2001, 2000 and 1999, is summarized in the following table.
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ---------------------------------------------- ------- -------- ---------
(000's)
CASH PAID DURING THE YEAR FOR:
Interest. . . . . . . . . . . . . . . . . . $31,301 $29,153 $ 16,686
Income taxes, net of refunds. . . . . . . . $ 4,258 $ 4,160 $ 7,479
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Capital stock issued for acquisitions . . . $ - $ 1,000 $ 3,699
Deferred payments for acquisitions. . . . . $ - $ - $ 805
DETAILS OF ACQUISITIONS:
Fair value of assets acquired . . . . . . . $ - $ 3,364 $346,103
Fair value of liabilities assumed . . . . . - (1,576) (37,250)
Deferred payments . . . . . . . . . . . . . - - (805)
Company stock issued. . . . . . . . . . . . - (1,000) (3,699)
------- -------- ---------
Cash paid. . . . . . . . . . . . . . . . . . . $ - $ 788 $304,349
Less cash acquired . . . . . . . . . . . . . . - 4 3,711
------- -------- ---------
Net cash paid for (acquired via) acquisitions. $ - $ 784 $300,638
======= ======== =========
NOTE 2. REGULATORY MATTERS
RCA. In July 1999, the Company entered into a definitive purchase and sale
agreement to acquire the assets and certain liabilities of ENSTAR Natural Gas
Company and the outstanding stock of Alaska Pipeline Company (together known as
"ENSTAR") from Ocean Energy, Inc ("Ocean Energy"). In October 1999, the Company
received an order from the RCA approving a joint application for the transfer of
the Certificate of Public Convenience and Necessity held by ENSTAR Natural Gas
Company and for a transfer of controlling interest in Alaska Pipeline Company.
The RCA's order contained certain conditions, including the obligation to file
by July 1, 2000 certain revenue requirement and cost of service information and
the prohibition from encumbering ENSTAR's assets for financing of non-utility
business activities. In compliance with the October 1999 order, the Company
filed the requested revenue requirement and cost of service information in the
first half of 2000.
In November 2000, the Company received an order requesting additional
information in order to ensure that ENSTAR's rates are just and reasonable. The
order also appointed a hearing examiner and established certain procedures. The
order indicated that if changes in ENSTAR's existing rates were required, such
changes would be applied on a prospective basis. In March 2001, the RCA issued
an additional order granting ENSTAR's motion to use a 2000 test year, accepting
a proposed procedural schedule, and finding that, because the proceeding was
taking longer than expected, ENSTAR should show cause why its current rates
should not be made interim and refundable effective April 6, 2001. The hearing
on this issue of the interim and refundable rates was held in April 2001. The
RCA issued an order in May 2001, concluding that ENSTAR's rates should not be
made interim and refundable pending the RCA's final determination in the rate
case.
43
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
In June 2001, the Company filed updated revenue requirement information
using 2000 as the test year. The updated information indicated that ENSTAR's
return on equity ("ROE") was 12.64% based on its existing rates versus the
15.65% allowed ROE. In August 2001, the Company filed a cost of service study
using 2000 as the test year. The Public Advocacy Section of the RCA filed its
testimony in October 2001. The hearing and proceeding were held in December
2001. The Company expects to receive a final order for ENSTAR during the first
quarter of 2002. The Company believes that ENSTAR's rates are just and
reasonable but cannot predict the outcome of the proceeding.
MPSC AND CCBC. In September 1998, the division of the Gas Distribution
Business, subject to the jurisdiction of the MPSC, received authority from the
MPSC, to: (1) implement an experimental residential gas customer choice program;
(2) suspend its GCR clause; (3) roll into its base rate and freeze for three
years a gas charge of $3.24 per thousand cubic feet ("Mcf"); (4) freeze
distribution rate adjustments for the same three-year period, with exceptions;
(5) suspend an income sharing mechanism adopted in October 1997 and adopt a new
income sharing mechanism for use during the 1999, 2000 and 2001 calendar years;
and (6) establish gas service performance criteria. The new rates took effect in
April 1999 and generally extend through March 2002.
The MPSC order is applicable only in the geographic areas subject to the
regulatory jurisdiction of the MPSC, and, therefore, does not govern rates
regulated by the CCBC. However, the Gas Distribution Business voluntarily
requested, and the CCBC approved, a similar decrease in the gas charge from
$3.60 per Mcf to $3.24 for customers subject to the jurisdiction of the CCBC.
The CCBC also approved a customer choice program, a suspension of the GCR
clause, a distribution rate freeze and an income sharing mechanism similar to
the MPSC approved program. The changes are effective for the same time period as
the changes approved by the MPSC.
Under the experimental residential gas customer choice program and a
similar program in Battle Creek, up to approximately 8,300 residential customers
per year are allowed to choose their own gas supplier during the three-year
period that began April 1, 1999. As a result, up to 25,000 residential customers
would be allowed to choose their own gas supplier by the third year of the
programs. This alternative gas supply is delivered to customers under a tariff
similar to an existing transportation service tariff used to provide such
service to commercial and industrial customers. The program has not, and is not
expected to, significantly affect the income of the Gas Distribution Business
because the approved rates for transportation service are designed to recover
all costs other than the cost of gas and provide a return in approximately the
same amounts as from Michigan residential customers, for whom the Company is the
natural gas supplier.
Several of the changes in the MPSC order are interrelated. The $3.24 gas
charge represents a reduction of approximately $.33 per Mcf from the rates prior
to April 1999. The suspension of the GCR clause means that customers pay $3.24
per Mcf regardless of the Company's actual cost of gas. The Gas Distribution
Business was able to offer this Michigan GCR suspension and rate freeze mainly
as a result of agreements reached with TransCanada Gas Services, Inc.
("TransCanada"). During 2001, TransCanada sold its gas marketing business and
assigned the agreements to BP Gas and Power ("BP") with the Company's consent.
Under the agreements, TransCanada or BP provide a significant portion of the
Company's natural gas requirements, and manage the Company's natural gas supply
and the supply aspects of transportation and storage operations in Michigan for
the three-year period that began April 1, 1999, at a cost below the $3.24 price
charged to customers. As a result, during the three-year period from April 1,
1999 through March 31, 2002, the Michigan gas distribution operation retains any
margin achieved between the sale of natural gas at $3.24 and the cost, subject
to a customer profit sharing mechanism described below.
Included in receivables at December 31, 2001, is approximately $16.5
million, representing amounts ultimately due the Company under the terms of the
TransCanada and BP agreements. Under the agreements, the Company does not have
title to gas in its leased storage facilities and it must remit payments to
TransCanada or BP in accordance with a contractual delivery schedule that is
designed to include the gas delivered to the leased storage facilities.
Differences between these scheduled deliveries and actual deliveries to the
Company-owned storage facilities result in an amount due the Company at December
31, 2001. This amount will be trued-up between TransCanada or BP and the Company
by the end of the heating season (April 1).
The profit incentive and sharing mechanism is effective for the calendar
years 1999, 2000 and 2001. Under the mechanism, if the Company's return on
equity for its Michigan-based natural gas distribution business exceeds 12.75%,
certain portions of the excess return would be credited to customers, i.e.,
would be reflected prospectively in reduced rates. For purposes of the profit
incentive and sharing mechanism, 50% of any gas costs savings generated as a
result of the TransCanada or BP arrangements are excluded from the calculation
of return on equity. As a result, the Company's actual reported earnings can
generate a return on equity in excess of 12.75% before triggering profit sharing
with customers. Four safety and reliability performance measures need to be met
in order not to reduce the return on equity threshold used in the income sharing
mechanism.
44
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The Company applied for and received approval from the CCBC to extend the
GCR suspension period and the fixed gas charge program until March 31, 2005 for
customers located in the City of Battle Creek, Michigan and surrounding
communities ("CCBC customers"). During the three-year extension period, the
Company will charge CCBC customers a fixed gas charge of $4.85 per dekatherm
("Dth"). The profit incentive and sharing mechanism discussed previously will
remain in effect through March 2005 for CCBC customers.
The Company also received approval during 2001 from the CCBC to start
charging CCBC customers on a thermal basis rather than a volumetric basis. The
Company buys all its natural gas by the dekatherm and now also sells it to these
customers by the dekatherm. This will help reduce the Company's risk to
increases in the thermal content of purchased natural gas.
The Company filed an application with the MPSC in September 2001 to extend
its fixed charge program until March 31, 2005 and increase the current fixed
charge for all remaining Michigan customers. However, the Company was unable to
reach an agreement with the MPSC and other interested parties on a fixed
customer charge for natural gas for the three years of the proposed extended
period. As a result, the Company withdrew its application. The Company will
instead reinstate its GCR pricing mechanism when the current fixed gas charge
program expires on March 31, 2002. Under the GCR mechanism, the Company's
customers in the geographic areas subject to the regulatory jurisdiction of the
MPSC ("MPSC customers") will be charged an amount that allows the Company to
recoup its cost of purchased natural gas. The MPSC has the authority to adjust
the GCR factor based on the variability in natural gas prices. The MPSC
suspended the Company's GCR clause in April 1999 when the current fixed gas
charge program went into effect.
Beginning in 2002, the profit incentive and sharing mechanism discussed
previously will no longer be in effect for MPSC customers. Instead, the profit
incentive and sharing mechanism in effect for the calendar year 1998 will be
reinstated for 2002. Under this mechanism, referred to as a reverse taper
incentive, if the return on equity for the division of Company's Michigan-based
natural gas distribution business that serves its MPSC customers exceeds 10.75%,
certain portions of the excess return between 10.75% and 16.0% would be credited
to customers. For purposes of this mechanism, if the return on equity exceeds
16.0%, the Company is required to file a general rate case with the MPSC.
The Company has entered into new agreements with BP for the provision of
its natural gas supply requirements and the management of its natural gas supply
and the supply aspects of its transportation and storage operations in Michigan.
The agreements cover a three-year period from April 1, 2002 through March 31,
2005. There are now separate natural gas requirement agreements for MPSC
customers and CCBC customers.
Under the new BP agreement covering MPSC customers, the Company will no
longer purchase gas at a fixed cost over the three-year period. In keeping with
the Company's switch back to the GCR mechanism for MPSC customers, a significant
portion of the Company's gas supply will be purchased from BP at the prevailing
spot market price at the date of purchase. 50% of the Company's gas supply will
be secured through one-year fixed rate contracts. The remainder of its gas
supply will be purchased on the open market based on the prevailing market rate.
The difference between the costs incurred under this agreement and the costs
reflected in the Company's cost of service will be passed on to the customers.
Consequently, effective April 1, 2002, the Company will not retain the gas
margin on sales to MPSC customers.
The new BP agreement covering CCBC customers will continue to have a fixed
cost covering the three-year period which will be below the $4.85 price per Dth
charged to CCBC customers. As a result, the Company will continue to retain any
margin achieved between the sale of natural gas at $4.85 and the cost of gas
purchased from BP.
REGULATORY ASSETS AND LIABILITIES. The Gas Distribution Business is subject to
the provisions of SFAS 71, "Accounting for the Effects of Certain Types of
Regulation." As a result, the actions of regulators affect when revenues and
expenses are recognized. Regulatory assets represent incurred costs to be
recovered from customers through the ratemaking process. Regulatory liabilities
represent benefits to be refunded to customers.
In the event the Company determines that the Gas Distribution Business no
longer meets the criteria for following SFAS 71, the accounting impact would be
an extraordinary, non-cash charge to operations of an amount that could be
material. Criteria that give rise to the discontinuance of SFAS 71 include (1)
increasing competition that restricts the ability of the Gas Distribution
Business to establish prices to recover specific costs, and (2) a significant
change in the manner in which rates are set by regulators from cost-based
regulation to another form of regulation. The Company's periodic review of these
criteria currently supports the continuing application of SFAS 71.
45
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the regulatory assets and liabilities
recorded in the Consolidated Statements of Financial Position.
DECEMBER 31, 2001 2000
- ------------------------------------------------------------ ------- -------
(000's)
REGULATORY ASSETS
Deferred retiree medical benefits. . . . . . . . . . $ 9,891 $10,790
Gas charges recoverable from customers . . . . . . . 1,994 2,698
Unamortized loss on retirement of debt . . . . . . . 2,126 2,371
Other. . . . . . . . . . . . . . . . . . . . . . . . 2,126 2,188
------- -------
$16,137 $18,047
======= =======
REGULATORY LIABILITIES
Unamortized investment tax credit. . . . . . . . . . $ 1,593 $ 1,958
Tax benefits amortizable to customers. . . . . . . . 3,448 3,811
Amounts payable to customers (gas cost overrecovery) 1,464 3,097
------- -------
$ 6,505 $ 8,866
======= =======
NOTE 3. MERGERS AND ACQUISITIONS
BUSINESS ACQUISITIONS. The Company has expanded in recent years with several
acquisitions which are summarized in the table below.
COMPANY BUSINESS SEGMENT ACQUISITION DATE
Sub-Surface Construction Co. ("Sub-Surface") . Construction Services August 1997
Maverick Pipeline Services, Inc. ("Maverick"). Engineering Services December 1997
Hotflame Gas, Inc. ("Hotflame"). . . . . . . . Propane, Pipelines & Storage March 1998
Oilfield Materials Consultants, Inc. ("OMC") . Engineering Services November 1998
K&B Construction, Inc. ("K&B") . . . . . . . . Construction Services February 1999
Iowa Pipeline Associates, Inc. ("Iowa"). . . . Construction Services April 1999
Flint Construction Co. ("Flint") . . . . . . . Construction Services September 1999
Long's Underground Technologies, Inc. ("Long") Construction Services September 1999
Drafting Services, Inc. ("DSI"). . . . . . . . Engineering Services September 1999
Pinpoint Locators, Inc. ("Pinpoint") . . . . . Engineering Services October 1999
ENSTAR Natural Gas Company and
Alaska Pipeline Company ("ENSTAR") . . . . . Gas Distribution November 1999
KLP Construction Co. ("KLP") . . . . . . . . . Construction Services May 2000
46
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The acquisition of OMC was accounted for under the pooling of interests
accounting method. The remainder of the business acquisitions have been
accounted for using the purchase method of accounting. As a result, the
Company's operating results for 2000 and 1999 include the results of these
businesses for the period subsequent to their acquisition dates. There were no
adjustments necessary to the accounting practices of these companies to conform
with the practices of the Company. Any goodwill associated with these
acquisitions is being amortized on a straight line method over a period of up to
40 years. However, effective January 1, 2002, goodwill amortization will cease
in compliance with the adoption of SFAS 142, "Goodwill and Other Intangible
Assets."
In addition to the consideration shown below, the acquisition of
Sub-Surface included non-compete agreements requiring payments of $235,000 per
year during the two years following the acquisition and $160,000 per year during
the third through fifth year following the acquisition. The Hotflame acquisition
also included non-compete agreements requiring payments of approximately $67,000
per year during the three years following the acquisition. In addition to the
consideration shown below, the acquisitions of K&B and Pinpoint provide for
additional amounts to be paid if certain post-acquisition operating results are
achieved, subject to set-off of certain liabilities. See Note 13 for further
information. Consideration issued to the prior owners of the businesses acquired
during the years ended December 31, 2001, 2000 and 1999 are summarized in the
table below.
COMMON SHARES DEFERRED
COMPANY CASH OF THE COMPANY PAYMENTS
- ----------------------- -------------- --------------- ---------
(000's)
K&B . . . . . . . . . . $ 1,000 $ - $ 805
Iowa. . . . . . . . . . - 138 -
Flint . . . . . . . . . 6,500 - -
Long. . . . . . . . . . 1,889 108 -
DSI . . . . . . . . . . 1,000 - -
Pinpoint. . . . . . . . 1,154 - -
KLP . . . . . . . . . . 788 83 -
ENSTAR. . . . . . . . . 292,805 - -
In December 2001, the Company's board of directors approved a plan to
redirect the Company's business strategy. This redirection will include the
divestiture of its engineering services businesses and certain of its
construction operations shown in the table above. For further information refer
to Note 14 of the Notes to Consolidated Financial statements.
NOTE 4. INCOME TAXES
SFAS NO. 109. The Company accounts for income taxes in accordance with SFAS
109, "Accounting For Income Taxes." SFAS 109 requires an annual measurement of
deferred tax assets and deferred tax liabilities based upon the estimated future
tax effects of temporary differences and carry forwards.
47
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
PROVISION FOR INCOME TAXES. The table below summarizes the components of the
Company's provision for income taxes.
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ------------------------------------------------- -------- -------- -------
(000's)
FEDERAL INCOME TAXES:
Currently payable (refundable). . . . . . $(7,056) $ 3,065 $5,749
Deferred to future periods. . . . . . . . 4,717 5,935 1,529
Investment tax credits ("ITC"). . . . . . (267) (267) (267)
STATE INCOME TAXES:
Currently payable (refundable). . . . . . 695 (473) 466
Deferred to future periods. . . . . . . . 734 651 (72)
-------- -------- -------
TOTAL INCOME TAX PROVISION (BENEFIT). . . . . . . $(1,177) $ 8,911 $7,405
LESS AMOUNTS INCLUDED IN:
Dividends on trust preferred securities . (4,632) (2,695) -
Discontinued operations . . . . . . . . . (3,123) 52 (226)
-------- -------- -------
INCOME TAXES, EXCLUDING AMOUNTS SHOWN SEPARATELY. $ 6,578 $11,554 $7,631
======== ======== =======
RECONCILIATION OF STATUTORY RATE TO EFFECTIVE RATE. The table below provides a
reconciliation of the difference between the Company's provision for income
taxes and income taxes computed at the statutory rate.
Years ended December 31, 2001 2000 1999
- --------------------------------------- -------- -------- --------
(000's)
NET INCOME (LOSS) . . . . . . . . . . . $(6,361) $16,693 $17,659
ADD BACK:
Preferred dividends . . . . . . - - 325
Income taxes. . . . . . . . . . (1,177) 8,911 7,405
-------- -------- --------
PRE-TAX INCOME (LOSS) . . . . . . . . . $(7,538) $25,604 $25,389
======== ======== ========
COMPUTED FEDERAL INCOME TAXES . . . . . $(2,638) $ 8,961 $ 8,886
AMORTIZATION OF DEFERRED ITC. . . . . . (267) (267) (267)
AMORTIZATION OF NON-DEDUCTIBLE AMOUNTS
RESULTING FROM ACQUISITIONS . . 237 237 221
STATE INCOME TAX EXPENSE, NET OF
FEDERAL TAX BENEFIT . . . . . . 928 79 256
OTHER . . . . . . . . . . . . . . . . . 563 (99) (1,691)
-------- -------- --------
TOTAL INCOME TAXES. . . . . . . . . . . $(1,177) $ 8,911 $ 7,405
======== ======== ========
48
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DEFERRED INCOME TAXES. Deferred income taxes arise from temporary differences
between the tax basis of assets and liabilities and their reported amounts in
the financial statements. At December 31, 2001 and 2000 there was no valuation
allowance recorded against deferred tax assets. The table below shows the
principal components of the Company's deferred tax assets (liabilities).
DECEMBER 31, 2001 2000
- -------------------------------------------------------------- --------- ---------
(000's)
Property . . . . . . . . . . . . . . . . . . . . . . . . . . . $(35,235) $(25,183)
Retiree medical benefit obligation . . . . . . . . . . . . . . 1,249 1,803
Retiree medical benefit regulatory assets. . . . . . . . . . . (3,462) (3,776)
Gas in underground storage . . . . . . . . . . . . . . . . . . 68 4,994
ITC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 820 955
Unamortized debt expense . . . . . . . . . . . . . . . . . . . (1,025) (1,167)
Gas cost overrecovery. . . . . . . . . . . . . . . . . . . . . 114 487
Property taxes . . . . . . . . . . . . . . . . . . . . . . . . (2,329) (2,055)
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,430) (4,625)
Other comprehensive income . . . . . . . . . . . . . . . . . . 781 -
Reserves associated with discontinued operations . . . . . . . 2,315 -
Reserves associated with restructuring and impairment charges. 1,793 -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,280 (824)
--------- ---------
TOTAL DEFERRED TAXES . . . . . . . . . . . . . . . . . . . . . $(34,061) $(29,391)
========= =========
Gross deferred tax liabilities . . . . . . . . . . . . . . . . $(71,695) $(63,379)
Gross deferred tax assets. . . . . . . . . . . . . . . . . . . 37,634 33,988
--------- ---------
TOTAL DEFERRED TAXES . . . . . . . . . . . . . . . . . . . . . $(34,061) $(29,391)
========= =========
NOTE 5. CAPITALIZATION
REGISTRATION STATEMENT. In March 2000, a registration statement on Form S-3
("registration statement") filed by the Company and SEMCO Capital Trust I, SEMCO
Capital Trust II and SEMCO Capital Trust III ("Capital Trusts") with the
Securities and Exchange Commission became effective. The registration statement
was for the registration of senior and subordinated debt securities, preferred
stock, common stock, stock purchase contracts and stock purchase units of the
Company and trust preferred securities of the Capital Trusts and related
guarantees in any combination up to $500 million. The Company has utilized $336
million of the $500 million to issue securities in 2000 and 2001.
COMMON STOCK EQUITY. During the last half of 2001, the Company issued
approximately 166,000 shares of its common stock to the Company's Direct Stock
Purchase and Dividend Reinvestment Plan ("DRIP") to meet the dividend
reinvestment and stock purchase requirements of its participants. During 2000
and the first half of 2001, the DRIP purchased Company common stock on the open
market to meet these requirements. The Company issued 374,000 shares of its
common stock in 1999 to meet the dividend reinvestment and stock purchase
requirements of the DRIP. Also in 1999, the Company purchased 159,000 shares of
its common stock on the open market to offset the number of shares sold through
the DRIP during the same period.
The Company issued 83,000 shares, and 246,000 shares of its common stock to
the shareholders of businesses acquired during 2000 and 1999 respectively.
49
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The Company issued approximately 19,000, 52,000 and 44,000 shares of
Company common stock to certain of the Company's employee benefit plans in 2001,
2000 and 1999, respectively. Also in 2001, the Company purchased approximately
48,000 shares of its common stock on the open market to contribute to certain of
its employee benefit plans.
COMPANY-OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF
SUBSIDIARIES. The Company's Capital Trusts were established for the sole
purpose of issuing trust preferred securities and lending the gross proceeds to
the Company. The sole assets of the Capital Trusts are debt securities of the
Company with terms similar to the terms of the related trust preferred
securities. The Capital Trusts are subsidiaries of the Company.
In April 2000, SEMCO Capital Trust I issued 1.6 million shares of 10.25%
cumulative trust preferred securities ("10.25% TPS") in a public offering at a
price of $25 per security. SEMCO Capital Trust I used the $40 million in
proceeds from the issuance of the 10.25% TPS to invest in subordinated
debentures of the Company bearing an interest rate of 10.25%. The 10.25% TPS are
subject to mandatory redemption upon repayment of the subordinated debentures at
maturity or their earlier redemption. The subordinated debentures mature in
2040, but may be redeemed at any time after April 19, 2005, or at any time
within 90 days following the occurrence of certain special events. The Company
used the entire net proceeds from the sale of the subordinated debentures to
repay a portion of the bridge loan utilized in the ENSTAR acquisition.
Also during 2000, the Company issued 10.1 million FELINE PRIDES in a public
offering at a price of $10 per security. Each FELINE PRIDES consists of a stock
purchase contract of the Company and a 9% trust preferred security of SEMCO
Capital Trust II due 2005 with a stated face value per security of $10 ("9%
TPS"). SEMCO Capital Trust II used the $101 million in proceeds to invest in 9%
senior deferrable notes of the Company due 2005. The Company used the net
proceeds from the sale of the senior deferrable notes to repay a portion of the
bridge loan utilized for the acquisition of ENSTAR and to repay a portion of its
short-term lines of credit.
Under the terms of each stock purchase contract (which is a component of a
FELINE PRIDES unit), the FELINE PRIDES holder is obligated to purchase, and the
Company is obligated to sell, between .7794 and .8651 shares of Company common
stock in August 2003. The actual number of shares of common stock to be sold
will depend on the average market value of a share of common stock in August
2003. In addition to payments on the 9% TPS, the Company is also obligated to
pay the FELINE PRIDES holders a quarterly contract adjustment payment on each
stock purchase contract at an annual rate of 2% of $10. The present value of the
contract adjustment payments, or $5.6 million, was recorded as a liability and
as a reduction to common stock capital surplus when the FELINE PRIDES were
issued. As the Company pays the contract adjustment payments, common stock
capital surplus is also reduced by the interest component of the payments. In
addition, common stock capital surplus was reduced by $4.6 million for the
issuance costs of the FELINE PRIDES.
The FELINE PRIDES holders can settle their obligation to purchase Company
common stock by paying cash or by having their 9% TPS remarketed in August 2003.
If they decide to have their 9% TPS remarketed, $10 of the proceeds from
remarketing each 9% TPS will automatically be applied to satisfy in full the
obligation to purchase Company common stock under the related stock purchase
contract.
The distribution rate on the 9% TPS will also be reset in August 2003. The
reset rate will be equal to the sum of the reset spread and the rate on the
two-year benchmark treasury and will be determined by the reset agent as the
rate the TPS should bear in order to have an approximate market value of 100.5%
of $10. However, the Company may limit the reset rate to be no higher than the
rate on the two-year benchmark treasury plus 200 basis points (or 2%).
LONG-TERM DEBT. In June 2001, the Company issued $60 million of 8% Senior Notes
due 2016. Interest on the Senior Notes is payable quarterly. On or after June
30, 2006, the Company may redeem some or all of the Senior Notes at a redemption
price of 100% of the principal amount plus any accrued and unpaid interest. The
proceeds from the sale of the Senior Notes were used to repay short-term debt
and for general corporate purposes.
In August 2001, the Company entered into an interest rate swap agreement
with a financial institution in order to hedge its $55 million 8% Notes due June
1, 2004. The swap agreement, which covers the Notes through maturity,
effectively converts the fixed rate on the Notes to a floating rate of interest.
On a semi-annual basis, the Company pays the counterparty a floating rate of
interest based on LIBOR plus a spread of 297 basis points and receives payments
based on a fixed rate of 8%.
50
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
In April 2000, the Company sold $30 million of 8% Senior Notes due 2010
("Senior Notes") in a public offering. Interest on the Senior Notes is paid
semi-annually. The Senior Notes contain provisions that give the estates or
heirs of deceased Senior Note holders the right to request that the Company
redeem their Senior Notes. During 2001 and 2000, the Company redeemed $10,000
and $50,000, respectively, of Senior Notes in accordance with these provisions.
The Company also sold $105 million of 8.95% Remarketable or Redeemable
Securities ("ROARS") in a public offering in June 2000. The ROARS were issued at
a discount of approximately $.3 million. Interest on the ROARS is payable
semi-annually. The ROARS mature in July 2008; however, the Company may purchase,
or be required to purchase, all of the ROARS in July 2003 if they are not
remarketed as discussed below. In conjunction with the sale of the ROARS, the
Company entered into a remarketing agreement with Banc of America Securities LLC
("BAS") under which BAS has the option to purchase all the ROARS in July 2003 or
any subsequent remarketing date. The Company received an option premium of
approximately $2.5 million for the remarketing option, which is included with
the ROARS in long-term debt in the Company's Consolidated Statements of
Financial Position. The option premium is being amortized to income over the
life of the ROARS.
If BAS purchases the ROARS in July 2003, they will remarket the ROARS at a
new interest rate in accordance with the terms of the ROARS. If BAS does not
exercise its option to purchase the ROARS in July 2003 then the Company is
required to redeem all of the ROARS at that time.
The Company used the entire net proceeds from the sale of the Senior Notes
and ROARS to repay a portion of the bridge loan utilized for the acquisition of
ENSTAR.
The Company's long-term and short-term debt agreements contain restrictive
financial covenants including, among others, maintaining a Fixed Charges
Coverage Ratio (as defined in the agreements) of at least 1.50 and placing
limits on the payment of dividends beyond certain levels. Non-compliance with
these convenants could result in an acceleration of the due dates for the debt
obligations under the agreements. As of December 31, 2001, the fixed charges
coverage ratio was 1.55 and the Company was in compliance with all of the
covenants in these agreements. The Company has currently projected its financial
covenants for each of the four quarters during 2002, based on the Company's
forecasted operating results for the year, and these forecasted results show
that the Company would be able to remain in compliance with all of its covenants
during 2002. However, these forecasted results are dependent on several
internal assumptions and external factors. If these assumptions or factors
differ from management's current expectations, they could have an adverse impact
on the Company's ability to remain in compliance with its covenants during 2002.
The most significant assumptions and factors that could impact the ongoing
compliance with these covenants include the effects of weather on the Company's
operating results; the outcome of the ENSTAR rate case compared to management's
expectations; the ability of the Company to improve its operating results with
the implementation of the Company's new strategic direction; and the completion
of an asset impairment test under SFAS 142 (to be adopted by the Company during
2002).
In the event the Company is not able to remain in compliance with these
covenants, management plans to request a modification of the covenants or a
waiver of certain covenant provisions.
There are no annual sinking fund requirements for the Company's existing
debt over the next five years. Debt maturing over the next five years includes
the maturity of $30 million of 6.83% notes in 2002, $55 million of 8.0% notes in
2004 and $15 million of 6.5% medium-term notes in 2005. In addition, the Company
may purchase, or be required to purchase, the $105 million of ROARS in July 2003
if they are not remarketed as discussed previously. At December 31, 2001, the
$30 million of 6.83% notes due in 2002 are reflected as current maturities of
long-term debt in the Consolidated Statements of Financial Position.
51
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6. SHORT-TERM BORROWINGS
The Company currently maintains unsecured lines of credit with banks totaling
$145 million, all of which is committed facilities. The outstanding balances
owed by the Company on these lines of credit at December 31, 2001, 2000 and 1999
were $105.5 million, $133.4 million, and $84.6 million, respectively. Interest
on all such lines are at variable rates, which do not exceed the banks' prime
lending rates. These arrangements expire during June and July 2002 and the
Company expects to put in place lines of credit with comparable terms. In
addition, the Company had a $290 million short-term unsecured bridge loan, which
was used to acquire ENSTAR on November 1, 1999. The bridge loan was repaid
during 2000.
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ------------------------------------ --------- --------- ---------
(000's)
Notes payable balance at year end. . $107,957 $134,142 $376,629
Unused lines of credit at year end . $ 39,500 $ 26,650 $ 25,400
Average interest rate at year end. . 2.60% 7.30% 7.1%
Maximum borrowings at any month-end. $122,033 $371,621 $377,585
Average borrowings . . . . . . . . . $101,362 $214,813 $ 91,279
Weighted average cost of borrowings. 4.80% 7.20% 6.5%
NOTE 7. FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each significant class of financial instruments:
CASH, TEMPORARY CASH INVESTMENTS, ACCOUNTS RECEIVABLES, PAYABLES AND NOTES
PAYABLE. The carrying amount approximates fair value because of the short
maturity of those instruments.
LONG-TERM DEBT. The fair values of the Company's long-term debt are estimated
based on quoted market prices for the same or similar issues or, where no market
quotes are available, based on discounted future cash flows using current
interest rates at which similar loans would be made to borrowers with similar
credit ratings and remaining maturities. Although the current fair value of the
long-term debt may differ from the current carrying amount, settlement of the
reported debt is generally not expected until maturity.
The table below shows the estimated fair values of the Company's long-term
debt as of December 31, 2001 and 2000.
DECEMBER 31, 2001 2000
- --------------------------------------------- -------- --------
(000's)
Long-term debt, including current maturities
Carrying amount. . . . . . . . . . . . . . $368,966 $307,930
Fair value . . . . . . . . . . . . . . . . 385,416 319,214
52
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS
PENSIONS. The Company has defined benefit pension plans that cover the
employees of certain companies in the consolidated group. Pension plan benefits
are generally based upon years of service or a combination of years of service
and compensation during the final years of employment. The Company's funding
policy is to contribute amounts annually to the plans based upon actuarial and
economic assumptions designed to achieve adequate funding of projected benefit
obligations. The Company also has a supplemental executive retirement plan
("SERP"), which is an unfunded defined benefit pension plan.
During 2000, certain pension plans covering employees at the Company's gas
distribution operations and corporate offices in Michigan and Alaska were
amended. The amendments to certain of the plans included a special frozen
benefit for certain eligible employees. In conjunction with the amendments, the
Company offered early retirement programs to certain eligible employees. The
programs gave the employees the options of receiving either a lump-sum pension
benefit payment or an immediate annuity. Sixty-three employees elected to take
the early retirement offer. As a result of the 2000 early retirement program,
the Company incurred a one-time gain which reduced 2000 net periodic pension
costs by approximately $.4 million.
Because of unfavorable returns on pension plan assets in 2000 and 2001,
certain pension plans were underfunded at December 31, 2001. As a result, a
minimum pension liability of $3.0 million was recorded during 2001.
OTHER POSTRETIREMENT BENEFITS. The Company has postretirement benefit plans
that provide certain medical and prescription drug benefits to qualified retired
employees, their spouses and covered dependents. Determination of benefits is
based on a combination of the retiree's age and years of service at retirement.
The Company accounts for retiree medical benefits in accordance with SFAS 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions." This
standard requires the full accrual of such costs during the years that the
employee renders service to the Company until the date of full eligibility.
In 2001, 2000 and 1999, the Company expensed retiree medical costs of $1.9
million, $1.5 million and $1.4 million, respectively. The retiree medical
expense for each of those years includes $0.9 million of amortization of
previously deferred retiree medical costs. Prior to getting regulatory approval
for the recovery of retiree medical benefits in rates, the Michigan gas
distribution operation deferred, as a regulatory asset, any portion of retiree
medical expense that was not yet provided for in customer rates. After receiving
rate approval for recovery of such costs, the Company began amortizing, as
retiree medical expense, the amounts previously deferred.
The Company has certain Voluntary Employee Benefit Association ("VEBA")
trusts to fund its retiree medical benefits and contributed $0.5 million, $3.0
million and $2.5 million to the trusts in 2001, 2000 and 1999, respectively. The
Company can also partially fund retiree medical benefits on a discretionary
basis through an Internal Revenue Code Section 401(h) account. No cash
contributions were made to the 401 (h) account in 2001, 2000 and 1999.
The following two tables provide reconciliations of the plan benefit
obligations, plan assets, funded status of the plans and components of net
periodic benefit costs.
PENSION BENEFITS OTHER POSTRETIREMENT BENEFITS
---------------------------- -----------------------------
YEARS ENDED DECEMBER 31, 2001 2000 1999 2001 2000 1999
- ----------------------------------------- -------- -------- -------- -------- -------- --------
(000's)
COMPONENTS OF NET BENEFIT COST
Service cost . . . . . . . . . . . . . $ 2,097 $ 1,988 $ 1,514 $ 348 $ 364 $ 358
Interest cost. . . . . . . . . . . . . 4,054 4,076 3,157 2,527 2,235 2,137
Expected return on plan assets . . . . (5,897) (6,600) (4,547) (2,150) (1,967) (1,514)
Amortization of transition obligation. 53 53 161 921 920 1,228
Amortization of prior service costs. . 150 106 73 - - -
Amortization of net (gain) or loss . . (301) (502) (727) (601) (950) (1,712)
Amortization of regulatory asset . . . - - - 899 899 899
Net gain due to special,
termination benefits . . . . . . . - (354) - - - -
-------- -------- -------- -------- -------- --------
Net benefit cost (credit). . . . . . . $ 156 $(1,233) $ (369) $ 1,944 $ 1,501 $ 1,396
======== ======== ======== ======== ======== ========
53
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
PENSION BENEFITS OTHER POSTRETIREMENT BENEFITS
---------------------------- -----------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
(000's)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at January 1 . . . . . . . . . $ 57,184 $ 57,218 $ 34,323 $ 33,350
Service cost. . . . . . . . . . . . . . . . . . . 2,097 1,988 348 364
Interest cost . . . . . . . . . . . . . . . . . . 4,054 4,076 2,527 2,235
Actuarial (gain) loss . . . . . . . . . . . . . . 3,461 (713) (1,671) 184
Benefits paid from plan assets. . . . . . . . . . (5,615) (2,952) - -
Benefits paid from corporate assets,
net of participant contributions . . . . . - - (1,563) (1,316)
Plan amendments . . . . . . . . . . . . . . . . . (6) 940 - (3,992)
Loss from reduction in workforce. . . . . . . . . - 440 - 3,498
Lump sums paid for reduction in workforce . . . . - (8,501) - -
Special termination benefits. . . . . . . . . . . - 4,688 - -
----------- ----------- ----------- -----------
Benefit obligation at December 31 . . . . . . . . $ 61,175 $ 57,184 $ 33,964 $ 34,323
=========== =========== =========== ===========
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1. . . . . . $ 62,579 $ 76,036 $ 22,851 $ 20,991
Actual return on plan assets. . . . . . . . . . . (3,034) (2,004) (1,387) (1,140)
Company contributions . . . . . . . . . . . . . . - - 500 3,000
Benefits paid from plan assets. . . . . . . . . . (5,615) (2,952) - -
Lump sums paid for reduction in workforce . . . . - (8,501) - -
----------- ----------- ----------- -----------
Fair value of plan assets at December 31. . . . . $ 53,930 $ 62,579 $ 21,964 $ 22,851
=========== =========== =========== ===========
RECONCILIATION OF FUNDED STATUS OF THE PLANS
Funded (unfunded) status. . . . . . . . . . . . . $ (7,245) $ 5,395 $ (12,000) $ (11,472)
Unrecognized net (gain) loss. . . . . . . . . . . 8,968 (3,725) (6,104) (8,571)
Unrecognized prior service cost . . . . . . . . . 824 980 - -
Unrecognized net transition obligation. . . . . . 65 118 10,137 11,058
Additional minimum pension liability. . . . . . . (2,983) - - -
----------- ----------- ----------- -----------
Prepaid (accrued) benefit cost . . . . . . . . . . $ (371) $ 2,768 $ (7,967) $ (8,985)
=========== =========== =========== ===========
WEIGHTED AVERAGE ASSUMPTIONS AS OF DECEMBER 31
Discount rate . . . . . . . . . . . . . . . . . . 7.25% 7.50% 7.25% 7.50%
Expected long-term rate of return on plan assets. 9.75% 9.75% 9.75% 9.75%
Rate of compensation increase . . . . . . . . . . 4.00-5.00% 4.00-5.00% 4.00-5.00% 4.00-5.00%
54
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The 2001 postretirement medical costs were developed based on the health
care plan in effect at January 1, 2001. As of December 31, 2001, the actuary
assumed that retiree medical cost increases in 2002 would be 6.6% and
prescription drug cost increases in 2002 would be 8.0%. The actuary also assumed
that the rate of increase in retiree medical costs and prescription drug costs
would decrease uniformly to 5.5% in 2005 and thereafter. The health care cost
trend rate assumption significantly affects the amounts reported. For example, a
one percentage point increase in each year would increase the accumulated
retiree medical obligation as of December 31, 2001 by $4.8 million and the
aggregate of the service and interest cost components of net periodic retiree
medical costs for 2001 by $.5 million.
401(K) PLANS AND PROFIT SHARING PLANS. The Company has defined contribution
plans, commonly referred to as 401(k) plans, covering the employees of certain
of its businesses or divisions. Certain of the 401(k) plans contain provisions
for Company matching contributions. The amount expensed for the Company match
provisions was $1.1 million for 2001 and 2000 and $.7 million for 1999.
The Company has profit sharing plans, covering the employees of certain of
its businesses or divisions. Annual contributions are generally discretionary or
determined by a formula which contains minimum contribution requirements. Profit
sharing expense was $.3 million for 2001 and 2000 and $.5 million for 1999.
NOTE 9. STOCK-BASED COMPENSATION
At the Company's 1997 annual meeting, the shareholders approved a long-term
incentive plan providing for the issuance of up to 500,000 shares of
non-qualified common stock options over the next ten years adjusted for any
subsequent stock dividends and stock splits. During 2000, the Company's Board of
Directors approved a second such plan that provides for the issuance of
non-qualified stock options up to an amount not to exceed five percent of the
total outstanding shares of the Company. The options are reserved for the
executives and directors of the Company and are awarded based upon both the
Company's and individual's performance. The options vest at the rate of 33 1/3%
per year beginning one year after the date of grant and expire ten years after
the grant date.
The exercise price of all the options granted is equal to the average of
the high and low market price on the options' grant date. Both the number of
options granted and the exercise price are adjusted accordingly for any stock
dividends and stock splits occurring during the options' life. Fair value of the
options was estimated at the date of grant using a Black-Scholes option pricing
model and the weighted average assumptions shown in the table below.
2001 2000 1999
------- ------- -------
Risk-free interest rate. . . . 4.92% 6.55% 5.28%
Dividend yield . . . . . . . . 5.86% 6.98% 5.29%
Volatility . . . . . . . . . . 29.42% 24.96% 20.84%
Average expected term (years). 5 5 5
Fair value of options granted. $ 2.57 $ 1.80 $ 2.20
55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Employee stock options available for grant were 529,000 and 1,011,000 at
December 31, 2001 and 2000, respectively. The following table shows the stock
option activity during the past three years and the number of stock options
exercisable under the Company's plans at the end of each such year.
Number Average Price
of Shares Per Share ($)
---------- --------------
OUTSTANDING AT DECEMBER 31, 1998 . . . . . . 217,630 16.40
Granted . . . . . . . . . . . . . . . 111,501 15.54
Exercised . . . . . . . . . . . . . . - -
Canceled. . . . . . . . . . . . . . . (11,345) 16.11
OUTSTANDING AT DECEMBER 31, 1999 . . . . . . 317,786 16.16
Granted . . . . . . . . . . . . . . . 192,701 12.07
Exercised . . . . . . . . . . . . . . - -
Canceled. . . . . . . . . . . . . . . (44,707) 14.18
OUTSTANDING AT DECEMBER 31, 2000 . . . . . . 465,780 14.65
Granted . . . . . . . . . . . . . . . 555,040 14.33
Exercised . . . . . . . . . . . . . . (667) 11.94
Canceled. . . . . . . . . . . . . . . (71,404) 14.25
OUTSTANDING AT DECEMBER 31, 2001 . . . . . . 948,749 14.49
OPTIONS EXERCISABLE AT DECEMBER 31, 1999 . . 95,088 16.39
OPTIONS EXERCISABLE AT DECEMBER 31, 2000 . . 200,924 16.38
OPTIONS EXERCISABLE AT DECEMBER 31, 2001 . . 298,403 15.48
The Company accounts for all stock options under the provisions and related
interpretations of Accounting Principles Board ("APB") Opinion 25, "Accounting
for Stock Issued to Employees." In accordance with SFAS 123, "Accounting for
Stock-Based Compensation," the Company has chosen to continue accounting for
these transactions under APB 25 for purposes of determining net income and to
present the pro forma disclosures required by SFAS 123. If compensation expense
had been determined in a manner consistent with the provisions of SFAS 123, the
Company's net income and earnings per share would have been reduced to the pro
forma amounts indicated in the table below.
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ----------------------------- -------- ------- -------
(000's)
NET INCOME (LOSS)
As reported. . . . . . $(6,361) $16,693 $17,659
Pro forma. . . . . . . $(6,664) $16,517 $17,501
EARNINGS PER SHARE - BASIC
As reported. . . . . . $ (0.35) $ 0.93 $ 1.00
Pro forma. . . . . . . $ (0.37) $ 0.92 $ 0.99
EARNINGS PER SHARE - DILUTED
As reported. . . . . . $ (0.35) $ 0.90 $ 1.00
Pro forma. . . . . . . $ (0.37) $ 0.89 $ 0.99
56
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 10. BUSINESS SEGMENTS
The Company follows SFAS 131, "Disclosure about Segments of an Enterprise and
Related Information," which specifies standards for reporting information about
operating segments ("business segments") in annual financial statements and
requires selected information in interim financial statements. Business segments
are defined as components of an enterprise about which separate financial
information is available that is evaluated regularly by the chief operating
decision maker, or decision making group, to make decisions on how to allocate
resources and to assess performance. The Company's chief operating decision
making group is the Chief Executive Officer ("CEO") and certain other executive
officers who report directly to the CEO. The operating segments are organized
and managed separately because each segment offers different products or
services. The Company evaluates the performance of its business segments based
on the operating income generated. Operating income does not include income
taxes, interest expense, discontinued operations, and non-operating income and
expense items.
Under SFAS 131, an operating segment that does not exceed certain
quantitative levels is not considered a reportable segment. Instead, the results
of all segments that do not exceed the quantitative thresholds can be combined
and reported as one segment and referred to as "all other." The Company's
propane, pipelines and storage business segment and information technology
service segment did not meet these quantitative thresholds and could have been
grouped into the "all other" category. However, the Company has decided to
voluntarily disclose information on these business segments.
The Company currently operates four reportable business segments. They are
gas distribution, construction services, information technology service, and
propane, pipelines and storage. Refer to Note 1 for a brief description of each
business segment.
In December 2001, the Company's board of directors approved a plan to
redirect the Company's business strategy, which includes the divestiture of its
engineering services business and certain regions of its construction operation.
The operating results of the engineering services business are segregated and
reported as discontinued operations in the Consolidated Statements of Income.
For further information refer to Note 14. The Company sold the subsidiary
comprising its energy marketing business effective March 31, 1999.
The accounting policies of the Company's four operating segments are the
same as those described in Note 1 except that intercompany transactions have not
been eliminated in determining individual segment results. The following table
provides business segment information as well as a reconciliation ("Corporate
and other") of the segment information to the applicable line in the
consolidated financial statements. Corporate and other includes corporate
related expenses not allocated to segments, intercompany eliminations and
results of other smaller operations.
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ------------------------------------------------------- --------- --------- ---------
(000's)
OPERATING REVENUES (a)
Gas distribution. . . . . . . . . . . . . . . . $324,365 $307,851 $216,831
Construction services . . . . . . . . . . . . . 126,205 105,231 58,272
Information technology services (b) . . . . . . 10,275 5,184 -
Propane, pipelines and storage. . . . . . . . . 7,443 6,949 6,284
Energy marketing. . . . . . . . . . . . . . . . - - 96,904
Corporate and other(c). . . . . . . . . . . . . (22,465) (14,890) (8,369)
--------- --------- ---------
Total consolidated revenues . . . . . . $445,823 $410,325 $369,922
========= ========= =========
DEPRECIATION AND AMORTIZATION (a)
Gas distribution. . . . . . . . . . . . . . . . $ 27,180 $ 26,272 $ 14,955
Construction services . . . . . . . . . . . . . 7,504 5,360 3,233
Information technology services (b) . . . . . . 397 60 -
Propane, pipelines and storage. . . . . . . . . 1,008 999 1,092
Energy marketing. . . . . . . . . . . . . . . . - - 36
Corporate and other . . . . . . . . . . . . . . 416 360 426
--------- --------- ---------
Total consolidated depreciation . . . . $ 36,505 $ 33,051 $ 19,742
========= ========= =========
OPERATING INCOME (LOSS) (a)
Gas distribution. . . . . . . . . . . . . . . . $ 50,337 $ 62,876 $ 40,134
Construction services . . . . . . . . . . . . . (1,374) 3,676 2,611
Information technology services (b) . . . . . . 431 481 -
Propane, pipelines and storage. . . . . . . . . 1,871 1,530 2,341
Energy marketing. . . . . . . . . . . . . . . . - - (341)
Corporate and other . . . . . . . . . . . . . . (6,874) (3,330) (2,342)
--------- --------- ---------
Total consolidated operating income . . $ 44,391 $ 65,233 $ 42,403
========= ========= =========
ASSETS
Gas distribution. . . . . . . . . . . . . . . . $734,115 $741,593 $713,900
Construction services . . . . . . . . . . . . . 74,453 69,276 52,620
Engineering services(a) . . . . . . . . . . . . 4,302 8,837 9,477
Information technology services (b) . . . . . . 4,384 1,808 -
Propane, pipelines and storage. . . . . . . . . 23,125 24,827 28,399
Corporate and other . . . . . . . . . . . . . . 23,169 4,882 10,787
--------- --------- ---------
Total consolidated assets . . . . . . . $863,548 $851,223 $815,183
========= ========= =========
CAPITAL INVESTMENTS (d)
Gas distribution. . . . . . . . . . . . . . . . $ 34,074 $ 47,466 $312,653
Construction services . . . . . . . . . . . . . 14,855 15,318 21,720
Engineering services (a). . . . . . . . . . . . 275 209 2,499
Information technology services (b) . . . . . . 1,960 2,143 -
Propane, pipelines and storage. . . . . . . . . 335 251 1,318
Corporate and other . . . . . . . . . . . . . . 3,945 3,033 1,971
--------- --------- ---------
Total consolidated capital investments. $ 55,444 $ 68,420 $340,161
========= ========= =========
<FN>
(a) Effective December 2001, the Company began accounting for the engineering services
segment as a discontinued operation. Accordingly, its operating results are segregated
and reported as discontinued operations in the Consolidated Statements of Income, with
prior years restated.
(b) Operations began for the information technology services segment in April 2000.
(c) Includes the elimination of intercompany construction service revenue of
$12,986,000, $9,694,000 and $8,307,000 for 2001, 2000 and 1999, respectively. Includes
the elimination of intercompany information technology revenue of $9,349,000 and
$5,032,000 for 2001 and 2000, respectively. Includes the elimination of intercompany
energy marketing revenue of $49,000 for 1999.
(d) Capital investments include purchase of property, plant and equipment and net
amounts paid for business acquisitions, including non-cash amounts such as deferred
payments and the value, at the time of issuance, of Company stock issued as part of the
acquisitions.
58
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. EARNINGS PER SHARE
The Company computes earnings per share ("EPS") in accordance with SFAS 128,
"Earnings per Share." SFAS 128 requires the computation and presentation of two
EPS amounts, basic and diluted. Basic EPS is computed by dividing income
available to common shareholders by the weighted average number of common shares
outstanding during the period. The computation of diluted EPS is similar to that
of basic EPS except that the weighted average number of common shares
outstanding is increased to include any shares that would be available if
outstanding stock options, stock purchase contracts, or convertible securities
("dilutive securities") were exercised. Accordingly, income available to common
shareholders is also adjusted for any changes to income that would result from
the assumed conversion of the dilutive securities. The diluted EPS calculation
excludes the affect of stock options when their exercise prices exceed the
average market price of the Company's common stock during the period and
excludes the affect of stock purchase contracts when their reference price
exceeds the average market price of common stock during the period.
The following table provides the computations of basic and diluted earnings
per share for the years ended December 31, 2001, 2000 and 1999.
YEARS ENDED DECEMBER 31, 2001 2000 1999
- -------------------------------------------------------------- -------- ------- --------
(000's, except per share amounts)
BASIC EARNINGS PER SHARE COMPUTATION
Net income (loss) from continuing operations . . . . . $ (239) $16,598 $18,022
Discontinued operations (a). . . . . . . . . . . . . . (6,122) 95 (363)
-------- ------- --------
Net income (loss) available to common shareholders . . $(6,361) $16,693 $17,659
======== ======= ========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . 18,106 17,999 17,697
======== ======= ========
EARNINGS PER SHARE - BASIC
Net income (loss) from continuing operations . . . . . $ (0.01) $ 0.92 $ 1.02
Discontinued operations (a). . . . . . . . . . . . . . (0.34) 0.01 (0.02)
-------- ------- --------
Net income (loss) available to common shareholders . . $ (0.35) $ 0.93 $ 1.00
======== ======= ========
DILUTED EARNINGS PER SHARE COMPUTATION
Net income (loss) from continuing operations . . . . . $ (239) $16,598 $18,022
Adjustment for effect of assumed conversions:
Preferred convertible stock dividends . . . . . . . - - 13
-------- ------- --------
Adjusted net income (loss) from continuing operations. (239) 16,598 18,035
Discontinued operations (a). . . . . . . . . . . . . . (6,122) 95 (363)
-------- ------- --------
Net income (loss) available to common shareholders . . $(6,361) $16,693 $17,672
======== ======= ========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . 18,106 17,999 17,697
Incremental shares from assumed conversions of:
FELINE PRIDES - stock purchase contracts (b). . . . - 599 -
Preferred convertible stock . . . . . . . . . . . . - - 22
Stock options (b) . . . . . . . . . . . . . . . . . - 21 1
-------- ------- --------
DILUTED WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (b) . . . . 18,106 18,619 17,720
======== ======= ========
EARNINGS PER SHARE - DILUTED
Net income (loss) from continuing operations . . . . . $ (0.01) $ 0.89 $ 1.02
Discontinued operations (a). . . . . . . . . . . . . . (0.34) 0.01 (0.02)
-------- ------- --------
Net income (loss) available to common shareholders . . $ (0.35) $ 0.90 $ 1.00
======== ======= ========
<FN>
(a) Effective December 2001, the Company began accounting for the engineering services
business as a discontinued operation. Accordingly, its operating results are segregated
and reported as discontinued operations in the Consolidated Statement of Income, with prior
years restated.
(b) The FELINE PRIDES and stock options were not included in the computation of diluted
earnings per share for 2001 because their effect was antidilutive.
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. INVESTMENTS IN AFFILIATES
The equity method of accounting is used for interests where the Company has
significant influence, but does not control the entity. At December 31, 2001,
the Company's only investment in affiliates was a 50% ownership interest in the
Eaton Rapids Gas Storage System. During 2000, the Company sold its 50% interest
in the Michigan Intrastate Lateral System and its 50% interest in the Michigan
Intrastate Pipeline System. Investments in unconsolidated affiliates are
reported in deferred charges and other assets in the Consolidated Statements of
Financial Position. The table below summarizes the combined financial
information for investments in affiliates.
2001 2000 1999
------- ------- -------
(000's)
Net sales. . . . . . . . . . . . . $ 5,714 $ 5,806 $ 6,071
Operating income . . . . . . . . . $ 3,489 $ 3,579 $ 3,486
Net income . . . . . . . . . . . . $ 2,379 $ 2,372 $ 1,956
The Company's share of net income. $ 1,190 $ 1,186 $ 978
Current assets . . . . . . . . . . $ 3,598 $ 1,435 $ 1,637
Non-current assets . . . . . . . . 20,552 22,767 26,903
------- ------- -------
Total assets . . . . . . . . . . . $24,150 $24,202 $28,540
======= ======= =======
Current liabilities. . . . . . . . $ 3,332 $ 2,024 $ 4,266
Non-current liabilities. . . . . . 12,567 13,023 15,274
Equity . . . . . . . . . . . . . . 8,251 9,155 9,000
------- ------- -------
Total liabilities and equity . . . $24,150 $24,202 $28,540
======= ======= =======
The Company's equity investment. . $ 4,126 $ 4,165 $ 4,207
NOTE 13. COMMITMENTS AND CONTINGENCIES
CAPITAL INVESTMENTS. The Company's plans for expansion and improvement of its
business properties are continually reviewed. Aggregate capital expenditures for
property in 2002 are projected at approximately $40 million. The Company has no
plans to incur additional expenditures for business acquisitions in 2002.
LEASE COMMITMENTS. The Company leases buildings, vehicles and equipment. The
resulting leases are classified as operating leases in accordance with SFAS 13,
"Accounting for Leases." Vehicle leases comprise a significant portion of total
lease expense. Leases on the majority of the Company's new vehicles are for a
minimum of twelve months. The Company has the right to extend each vehicle lease
annually and to cancel the extended lease at any time.
The Company's future minimum lease payments that have initial or remaining
noncancelable lease terms in excess of one year at December 31, 2001 totaled
$8.7 million consisting of (in millions): 2002 - $1.5; 2003 - $1.4; 2004 - $1.4;
2005 - $1.0; 2006 - $.8 and thereafter - $2.6. Total lease expense approximated
$2.5 million, $2.3 million and $2.3 million in 2001, 2000 and 1999,
respectively. The annual future minimum lease payments are substantially less
than the lease expense incurred in 1999 through 2001 because most of the vehicle
leases at December 31, 2001 were on a month-to-month basis and were subject to
cancellation at any time. However, management expects to renew or replace
substantially all leases.
60
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
ENVIRONMENTAL ISSUES. Prior to the construction of major natural gas pipelines,
gas for heating and other uses was manufactured from processes involving coal,
coke or oil. The Company owns seven Michigan sites which formerly housed such
manufacturing facilities and expects that it will ultimately incur investigation
and remedial action costs at some of these sites, and a number of other sites.
The Company has closed one site with the approval of the appropriate
environmental regulatory authority in the State of Michigan, and has developed
plans to conduct field investigations at two other sites. The extent of the
Company's liabilities and potential costs in connection with these sites cannot
be reasonably estimated at this time. In accordance with an MPSC accounting
order, any environmental investigation and remedial action costs will be
deferred and amortized over ten years. Rate recognition of the related
amortization expense will not begin until after a prudence review in a general
rate case.
PERSONAL PROPERTY TAXES. In 1998, the Company began filing its personal
property tax information with local taxing jurisdictions, using a revised
calculation of the value of personal property subject to taxation. The revised
calculation excludes intangible costs from the value of personal property. A
number of local taxing jurisdictions have accepted the revised calculation, and
the Company recorded lower property tax expense in the years 1998 through 2001
associated with the accepting taxing jurisdiction. The Company has also filed
appeals to recover excess payments made in 1996 and 1997 based on the revised
calculation and recorded lower property tax expense as a result of the filings.
Additionally, the Company and other Michigan utilities have asserted that
Michigan's valuation tables result in the substantial overvaluation of utility
personal property. Valuation tables established by the Michigan State Tax
Commission ("STC") are used to estimate the reduction in value of personal
property based on the property's age. In November 1999, the STC approved new
valuation tables that more accurately recognize the value of a utility's
personal property. The new tables became effective in 2000 and are being used
for current year assessments in most jurisdictions. However, several local
taxing jurisdictions have taken legal action attempting to prevent the STC from
implementing the new valuation tables and have continued to prepare assessments
based on the superceded tables.
The Company will seek to apply the new tables retroactively and to
ultimately settle the pending tax appeals related to prior periods. This is a
solution supported by the STC in the past. The legal action, along with possible
additional appeals by local taxing jurisdictions or negotiated settlements, may
delay the time period for recovery and ultimately impact the amount of recovery.
As of December 31, 2001, the Company had a receivable of approximately $4.0
million recorded for the Company's estimated recovery of these prior year excess
property tax payments.
CONTINGENCIES. The terms of certain of the Company's acquisition agreements in
1999 provided for additional consideration to be paid if certain results were
achieved. The former owners of PinPoint and K&B were given the opportunity to
receive additional consideration if future results of operations exceed certain
targeted levels. During 2000 and 2001, the Company made payments of $0.1 million
and $0.5 million, respectively, to the former owners of Pinpoint in full
settlement of its agreement. As a result, the Company has no further obligation
to pay additional consideration in connection with the acquisition of Pinpoint.
The amounts potentially payable to the former owners of K&B are subject to
set-off for certain liabilities. There has been no additional consideration paid
in connection with the K&B acquisition.
In the normal course of business, the Company may be a party to certain
lawsuits and administrative proceedings before various courts and government
agencies. These lawsuits and proceedings may involve personal injury, property
damage, contractual issues and other matters. Management cannot predict the
ultimate outcome of any pending or threatening litigation or of actual or
possible claims; however, management believes resulting liabilities, if any,
will not have a material adverse impact upon the Company's financial position or
results of operations.
NOTE 14. RESTRUCTURING AND DISCONTINUATION OF OPERATIONS
During the fourth quarter of 2001, the Company announced a redirection of its
business strategy. The Company is restructuring corporate, business unit and
operational structures. This will involve the integration of the Company's
Michigan and Alaska gas distribution divisions and the closure of the Company's
Houston-based engineering and construction headquarters and related
consolidation of administrative functions in Michigan. The redirection will also
involve the divestiture of the Company's engineering services business and
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
certain regions of the construction operation that are not likely to contribute
to shareholder value in the near term. The new strategy will concentrate more on
profitable growth within each line of business and less on acquisitions. In
December 2001 a plan was approved by the Board of Directors to accomplish the
strategic redirection and reorganization, and it is anticipated that the
restructuring and divestitures, under this plan, will be completed by November
30, 2002.
The Company recorded $6.1 million of restructuring and impairment charges
in the fourth quarter of 2001 for the planned restructuring activities and the
divestiture of certain regions of its construction business. The charges are
included in operating expenses in the Consolidated Statements of Income and
include severance expense, costs associated with terminating leases, writedowns
of certain construction operations and other related expenses.
The planned divestiture of the Company's engineering services business has
been accounted for as a discontinued operation and, accordingly, the operating
results and the estimated loss on the disposal of this business segment are
segregated and reported as discontinued operations in the Consolidated
Statements of Income, with prior years restated. Operating results, net of
income taxes, from discontinued operations were $(1.1) million, $0.1 million and
$(0.4) million for 2001, 2000 and 1999, respectively. In the fourth quarter of
2001, the Company recorded a loss of $5.0 million, net of income taxes, for the
estimated loss the Company expects to incur on the disposal of its engineering
business segment, including estimated losses from operations during the
phase-out period. Components of amounts reflected in the Consolidated Statements
of Income and Consolidated Statements of Financial Position for the engineering
services business are presented in the following table.
2001 2000 1999
-------- -------- --------
(000's)
CONSOLIDATED STATEMENTS OF INCOME DATA
Revenues. . . . . . . . . . . . . . . . . . . . . $12,247 $20,655 $17,485
Operating expenses. . . . . . . . . . . . . . . . 14,340 20,630 17,998
Operating income (loss) . . . . . . . . . . . . . (2,093) 25 (513)
Other income (deductions) . . . . . . . . . . . . 257 122 (76)
Income taxes. . . . . . . . . . . . . . . . . . . (694) 52 (226)
-------- -------- --------
Income (loss) from discontinued operations. . . . $(1,142) $ 95 $ (363)
-------- -------- --------
Estimated loss on divestiture of discontinued
operations, including provisions for losses
during phase-out period, net of income
tax benefits of $2,429. . . . . . . . . . . . . (4,980) - -
-------- -------- --------
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION DATA
Current assets. . . . . . . . . . . . . . . . . . $ 4,050 $ 5,136 $ 6,648
Property, plant and equipment, net. . . . . . . . 250 1,233 1,451
Deferred charges and other assets, net. . . . . . 2 2,468 1,378
Current liabilities . . . . . . . . . . . . . . . (4,880) (3,401) (3,861)
Deferred credits and other liabilities. . . . . . - (911) (883)
-------- -------- --------
Net assets of discontinued operations
held for sale. . . . . . . . . . . . . . . . . $ (578) $ 4,525 $ 4,733
======== ======== ========
62
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 15. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
In the opinion of the Company, the following quarterly information includes all
adjustments necessary for a fair statement of the results of operations for such
periods. Earnings and dividends per share for each quarter are calculated based
upon the weighted average number of shares outstanding during each quarter. As a
result, adding the earnings or dividends per share for each quarter of a year
may not equal annual earnings or dividends per share due to changes in shares
outstanding throughout the year. Due to the seasonal nature of the Company's gas
distribution business, the results of operations reported on a quarterly basis
show substantial variations.
Quarters First Second Third Fourth
- ----------------------------------------------------- ---------- -------- -------- ---------
(000's, except per share amounts)
2001 (a)
Operating revenues. . . . . . . . . . . . . . $ 149,978 $86,512 $76,804 $132,529
Operating income. . . . . . . . . . . . . . . 25,666 5,344 939 12,442
Net income (loss) from continuing operations. 9,478 (3,345) (6,503) 131
Net income (loss) available to common
shareholders. . . . . . . . . . . . . . . . 9,056 (3,339) (6,645) (5,433)
Earnings per share from net income (loss)
from continuing operations:
- basic. . . . . . . . . . . . . . . . . . 0.52 (0.19) (0.36) 0.01
- diluted. . . . . . . . . . . . . . . . . 0.50 (0.19) (0.36) 0.01
Earnings per share from net income (loss)
available to common shareholders:
- basic. . . . . . . . . . . . . . . . . . 0.50 (0.18) (0.37) (0.30)
- diluted. . . . . . . . . . . . . . . . . 0.48 (0.18) (0.37) (0.30)
Cash dividends per share. . . . . . . . . . . 0.210 0.210 0.210 0.210
========== ======== ======== =========
2000 (a)
Operating revenues. . . . . . . . . . . . . . $ 126,637 $72,754 $68,167 $142,767
Operating income. . . . . . . . . . . . . . . 26,199 4,531 4,206 30,297
Net income (loss) from continuing operations. 11,966 (3,165) (4,611) 12,408
Net income (loss) available to common
shareholders. . . . . . . . . . . . . . . . 11,994 (3,074) (4,749) 12,522
Earnings per share from net income (loss)
from continuing operations:
- basic. . . . . . . . . . . . . . . . . . 0.67 (0.18) (0.26) 0.69
- diluted. . . . . . . . . . . . . . . . . 0.67 (0.18) (0.26) 0.64
Earnings per share from net income (loss)
available to common shareholders:
- basic. . . . . . . . . . . . . . . . . . 0.67 (0.17) (0.26) 0.69
- diluted. . . . . . . . . . . . . . . . . 0.67 (0.17) (0.26) 0.65
Cash dividends per share. . . . . . . . . . . 0.205 0.210 0.210 0.210
========== ======== ======== =========
<FN>
(a) 2001 and 2000 results have been restated to reflect the reclassification of the results of
operations for the Company's engineering services business from the continuing operations
section of the Consolidated Statements of Income to the discontinued operations section.
63
SELECTED FINANCIAL DATA
YEARS ENDED DECEMBER 31, 2001 2000 1999 1998 1997 1996
- ------------------------------------- ------------ ------------ ------------ ---------------- --------------- ---------------
INCOME STATEMENT DATA (000'S)
Operating revenue . . . . . . . . . $445,823 $410,325 $369,922 $596,548 $770,272 $544,949
--------- --------- --------- --------- --------- ---------
Operating expenses
Cost of gas sold. . . . . . . . . $184,973 $161,945 $117,789 $109,388 $150,967 $151,135
Cost of gas marketed. . . . . . . - - 95,632 386,691 518,157 308,619
Operations and maintenance. . . . 162,289 $140,236 85,696 55,064 50,562 40,669
Depreciation. . . . . . . . . . . 36,505 $ 33,051 19,742 15,167 12,863 11,317
Property and other taxes. . . . . 11,562 9,860 8,660 8,981 9,334 8,648
Restructuring and
impairment charges. . . . . . . 6,103 - - - - -
--------- --------- --------- --------- --------- ---------
$401,432 $345,092 $327,519 $575,291 $741,883 $520,388
--------- --------- --------- --------- --------- ---------
Operating Income. . . . . . . . . . $ 44,391 $ 65,233 $ 42,403 $ 21,257 $ 28,389 $ 24,561
Other income (deductions) . . . . . (29,449) (32,077) (16,750) (8,986)(i) (5,240)(j) (44,672)(l)
--------- --------- --------- --------- --------- ---------
Income (loss) before income
taxes and dividends on trust
preferred securities. . . . . . . $ 14,942 $ 33,156 $ 25,653 $ 12,271 $ 23,149 $(20,111)
Income taxes. . . . . . . . . . . . 6,578 11,554 7,631 5,188 8,228 (7,308)
Dividends on trust preferred
securities, net of income tax . . 8,603 5,004 - - - -
--------- --------- --------- --------- --------- ---------
Net income (loss) from
continuing operations . . . . . . $ (239) $ 16,598 $ 18,022 $ 7,083 $ 14,921 $(12,803)
Discontinued operations,
extraordinary charges
and changes in
accounting methods. . . . . . . . (6,122)(f) 95 (f) (363)(f) 2,957 (f)-(h) 504 (f) 41(f)
--------- --------- --------- --------- --------- ---------
Net income (loss) available to
common shareholders . . . . . . . $ (6,361)(f) $ 16,693 (f) $ 17,659 (f) $ 10,040 (f)-(i) $ 15,425 (f)(j) $(12,762)(f)(l)
Common dividends. . . . . . . . . . 15,193 15,033 15,272 11,836 10,225 9,814
--------- --------- --------- --------- --------- ---------
Earnings (deficit) reinvested
in the business . . . . . . . . . $(21,554) $ 1,660 $ 2,387 $ (1,796) $ 5,200 $(22,576)
========= ========= ========= ========= ========= =========
COMMON STOCK DATA
Average shares
outstanding (000's) (a)
Basic. . . . . . . . . . . . . 18,106 17,999 17,697 15,906 14,608 14,573
Diluted (b). . . . . . . . . . 18,106 18,619 17,720 (b) (b) (b) (b)
Earnings per share on net
income (loss) available to
common shareholders (a)
Basic. . . . . . . . . . . . . $ (0.35)(f) $ 0.93 (f) $ 1.00 (f) $ 0.63 (f)-(i) $ 1.06 (f)(j) $ (0.88)(f)(l)
Diluted (b). . . . . . . . . . $ (0.35)(f) $ 0.90 (f) $ 1.00 (f) $ 0.63 $ 1.06 $ (0.88)
Dividends paid per share (a). . . . $ 0.839 $ 0.835 $ 0.863 (n) $ 0.744 $ 0.700 $ 0.673
Dividends payout ratio. . . . . . . N/A 90.1% 86.5% 117.9% 66.0% N/A
Book value per share (a) (c). . . . $ 6.24 $ 7.50 $ 7.95 $ 7.61 $ 6.44 $ 5.95
Market value per share (a) (c) (d). $ 10.75 $ 15.56 $ 11.81 $ 16.31 $ 17.26 $ 16.78
Number of registered common
shareholders (c). . . . . . . . . 9,327 9,517 9,217 9,336 8,755 8,509
BALANCE SHEET DATA (000'S) (c)
Total assets. . . . . . . . . . . . $863,548 $851,223 $815,183 $489,662 $507,160 $479,037
========= ========= ========= ========= ========= =========
Capitalization
Long-term debt (e). . . . . . . . . $368,966 $307,930 $170,000 $170,000 $163,548 $108,112
Company-obligated mandatorily
redeemable trust preferred
securities of subsidiaries. . . . 139,394 139,374 - - - -
Preferred stock . . . . . . . . . . -- -- -- 3,255 3,269 3,269
Common equity . . . . . . . . . . . 113,810 135,472 142,340 132,228 95,131 86,678
--------- --------- --------- --------- --------- ---------
$622,170 $582,776 $312,340 $305,483 $261,948 $198,059
========= ========= ========= ========= ========= =========
FINANCIAL RATIOS
Capitalization
Long-term debt (e). . . . . . . . . 59.3% 52.8% 54.4% 55.6% 62.4% 54.6%
Company-obligated mandatorily
redeemable trust preferred
securities of subsidiaries. . . . 22.4% 23.9% - - - -
Preferred stock . . . . . . . . . . - - -- 1.1% 1.3% 1.6%
Common equity . . . . . . . . . . . 18.3% 23.3% 45.6% 43.3% 36.3% 43.8%
--------- --------- --------- --------- --------- ---------
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
--------- --------- --------- --------- --------- ---------
Return on average common equity . . (5.1%) 12.0% 12.9% 8.8% 17.0%(k) (13.0%)(m)
========= ========= ========= ========= ========= =========
YEARS ENDED DECEMBER 31, 1995 1994 1993 1992 1991
- ------------------------------------- --------- ------------ ------------ ------------ ---------
INCOME STATEMENT DATA (000'S)
Operating revenue . . . . . . . . . $335,538 $372,430 $288,963 $251,526 $231,522
--------- --------- --------- --------- ---------
Operating expenses
Cost of gas sold. . . . . . . . . $120,619 $135,669 $139,051 $121,643 $111,005
Cost of gas marketed. . . . . . . 130,087 153,973 67,474 52,347 46,237
Operations and maintenance. . . . 36,217 35,558 34,496 33,590 33,425
Depreciation. . . . . . . . . . . 12,035 11,549 12,468 12,344 12,138
Property and other taxes. . . . . 7,966 8,186 8,446 7,729 7,193
Restructuring and
impairment charges. . . . . . . - - - - -
--------- --------- --------- --------- ---------
$306,924 $344,935 $261,935 $227,653 $209,998
--------- --------- --------- --------- ---------
Operating Income. . . . . . . . . . $ 28,614 $ 27,495 $ 27,028 $ 23,873 $ 21,524
Other income (deductions) . . . . . (11,132) (11,658) (11,612) (11,022) (10,791)
--------- --------- --------- --------- ---------
Income (loss) before income
taxes and dividends on trust
preferred securities. . . . . . . $ 17,482 $ 15,837 $ 15,416 $ 12,851 $ 10,733
Income taxes. . . . . . . . . . . . 6,151 4,559 5,676 3,640 3,432
Dividends on trust preferred
securities, net of income tax . . - - - - -
--------- --------- --------- --------- ---------
Net income (loss) from
continuing operations . . . . . . $ 11,331 $ 11,278 $ 9,740 $ 9,211 $ 7,301
Discontinued operations,
extraordinary charges
and changes in
accounting methods. . . . . . . . - (1,286)(g) (177)(g) (901)(g) -
--------- --------- --------- --------- ---------
Net income (loss) available to
common shareholders . . . . . . . $ 11,331 $ 9,992 (g) $ 9,563 (g) $ 8,310 (g) $ 7,301
Common dividends. . . . . . . . . . 9,230 8,656 7,419 6,875 6,385
--------- --------- --------- --------- ---------
Earnings (deficit) reinvested
in the business . . . . . . . . . $ 2,101 $ 1,336 $ 2,144 $ 1,435 $ 916
========= ========= ========= ========= =========
COMMON STOCK DATA
Average shares
outstanding (000's) (a)
Basic. . . . . . . . . . . . . 13,696 13,440 12,155 11,835 11,533
Diluted (b). . . . . . . . . . (b) (b) (b) (b) (b)
Earnings per share on net
income (loss) available to
common shareholders (a)
Basic. . . . . . . . . . . . . $ 0.83 $ 0.74 (g) $ 0.79 (g) $ 0.70 (g) $ 0.63
Diluted (b). . . . . . . . . . $ 0.83 $ 0.74 $ 0.79 $ 0.70 $ 0.63
Dividends paid per share (a). . . . $ 0.674 $ 0.644 $ 0.610 $ 0.581 $ 0.554
Dividends payout ratio. . . . . . . 81.5% 86.6% 77.6% 82.7% 87.5%
Book value per share (a) (c). . . . $ 7.99 $ 7.86 $ 6.94 $ 6.45 $ 6.07
Market value per share (a) (c) (d). $ 15.54 $ 14.80 $ 17.24 $ 14.19 $ 10.84
Number of registered common
shareholders (c). . . . . . . . . 8,334 8,149 7,261 6,892 6,594
BALANCE SHEET DATA (000'S) (c)
Total assets. . . . . . . . . . . . $378,523 $368,498 $348,813 $319,548 $294,933
========= ========= ========= ========= =========
Capitalization
Long-term debt (e). . . . . . . . . $107,325 $104,910 $117,022 $102,728 $ 95,656
Company-obligated mandatorily
redeemable trust preferred
securities of subsidiaries. . . . - - - - -
Preferred stock . . . . . . . . . . 3,272 3,288 3,290 3,320 3,332
Common equity . . . . . . . . . . . 109,511 107,379 85,657 77,353 70,758
--------- --------- --------- --------- ---------
$220,108 $215,577 $205,969 $183,401 $169,746
========= ========= ========= ========= =========
FINANCIAL RATIOS
Capitalization
Long-term debt (e). . . . . . . . . 48.8% 48.7% 56.8% 56.0% 56.4%
Company-obligated mandatorily
redeemable trust preferred
securities of subsidiaries. . . . - - - - -
Preferred stock . . . . . . . . . . 1.5% 1.5% 1.6% 1.8% 2.0%
Common equity . . . . . . . . . . . 49.7% 49.8% 41.6% 42.2% 41.6%
--------- --------- --------- --------- ---------
100.0% 100.0% 100.0% 100.0% 100.0%
--------- --------- --------- --------- ---------
Return on average common equity . . 10.4% 9.5% 11.6% 11.1% 10.6%
========= ========= ========= ========= =========
<FN>
(a) Adjusted to give effect to 5 percent stock dividends in May each year, 1991 through 1998.
(b) Prior to 1999, diluted average common shares outstanding were not materially different than
basic average common shares outstanding. Therefore, there was no dilutive impact on earnings
per share.
(c) At year end.
(d) Amounts prior to 1997 based on closing bid price. Amounts for 1997 and subsequent years,
based on closing stock price.
(e) Includes current maturities of long-term debt.
(f) Includes, net of tax, ($6,122) or ($.34) per share, $95 or $.01 per share, ($363) or ($.02)
per share, $1,672 or $.11 per share, $504 or $.03 per share and $41 or $.00 per share in 2001,
2000, 1999, 1998, 1997 and 1996, respectively, attributable to the reclassification of the
operating results of the engineering services business to discontinued operations.
(g) Includes $499 (net of tax) or $.03 per share, $1,286 (net of tax) or $.10 per share, $177
(net of tax) or $.01 per share, and $901 (net of tax) or $.08 per share in 1998, 1994, 1993 and
1992, respectively, attributable to extraordinary losses on the early extinguishment of debt.
(h) Includes income of $1,784 (net of tax) or $.11 per share attributable to a change in
accounting method.
(i) Includes a gain of $1,708 (net of tax) or $.11 per share from the sale of the NOARK
Investment.
(j) Includes income due to an adjustment to the reserve for the NOARK investment - $5,025 (net
of tax) or $.34 per share.
(k) Excluding the adjustment to the reserve for the NOARK investment, return on average common
equity was 11.8%.
(l) Includes the write-down of the NOARK investment - $21,000 (net of tax) or $1.44 per share.
(m) Excluding the write-down of the NOARK investment, return on average common equity was
7.6%.
(n) Includes a special one-time dividend of $0.05 per share.
64 & 65