EXHIBIT 99
Management's Discussion and
Analysis of Financial Condition
and Results of Operations
Effective December 31, 2000, Cleco Utility Group Inc. (Utility Group)
merged into Cleco Power LLC (Cleco Power). Immediately prior to the merger,
Cleco Power had only nominal assets or liabilities. Pursuant to the merger Cleco
Power acquired all of the assets and assumed all of the liabilities and
obligations of Utility Group.
Effective July 1, 1999, Utility Group reorganized into a holding company
structure. This reorganization resulted in the creation of a new holding
company, Cleco Corporation (the Company), which holds investments in several
subsidiaries, one of which, Cleco Power, contains the Louisiana Public Service
Commission (LPSC) jurisdictional generation, transmission and distribution
electric utility operations serving the Company's traditional retail and
wholesale customers. Another subsidiary, Cleco Midstream Resources LLC
(Midstream), operates competitive LPSC nonjurisdictional electric generation,
oil and natural gas production, energy marketing and natural gas pipeline
businesses. A third subsidiary, Utility Construction & Technology Solutions LLC
(UtiliTech, formerly Cleco Services LLC), provides utility engineering and line
construction services to municipal governments, rural electric cooperatives and
investor-owned electric companies. There was no impact on the Company's
Consolidated Financial Statements because the reorganization was accounted for
similarly to a pooling of interests. Under the terms of the reorganization, the
Company became the owner of all of Utility Group's outstanding common stock.
Holders of then existing common stock and two series of preferred stock
exchanged their stock in Utility Group for common stock in the Company. Shares
of preferred stock in three series that did not approve the reorganization were
redeemed for $5.7 million.
In December 2000 management decided to sell substantially all of
UtiliTech's assets and discontinue UtiliTech's operations after the sale. The
sale is expected to be finalized during the first quarter of 2001 with all
operations estimated to cease by March 31, 2001. Revenues and expenses
associated with UtiliTech are not shown in their respective line items of the
Company's Consolidated Statements of Income, but instead are netted and shown as
loss from operations from a discontinued operation.
Results of Operations
EARNINGS
The Company's consolidated 2000 earnings from continuing operations (net
income from continuing operations) totaled $69.3 million, or $3.00 per basic
average common share, an increase of $11.3 million, or $0.51 per share, compared
to 1999. Earnings from continuing operations increased primarily due to
increased earnings from Cleco Power and from tolling operations at a wholly
owned subsidiary of Midstream, Cleco Evangeline LLC (Evangeline). The $4.2
million increase in earnings at Cleco Power was attributable to increased
megawatt-hour (MWH) sales to regular customers. The increase in earnings at
Evangeline was due to the commencement of commercial operations of the
Evangeline generating plant during the summer of 2000. Offsetting the increases
from continuing operations was the operating loss from the discontinued
operation of UtiliTech of $5.4 million in 2000 compared to a $1.3 million loss
in 1999. A loss on the disposal of UtiliTech of $1.5 million in 2000 further
reduced earnings in 2000. Increasing earnings in 2000 was an extraordinary gain
of $2.5 million due to the repurchase of debt within Midstream. Total net income
applicable to common stock was $63.1 million, or $2.81 per basic average common
share, compared to $54.8 million, or $2.43 per basic average common share, in
1999.
The Company's consolidated 1999 earnings from continuing operations
(net income from continuing operations) totaled $58.1 million, or $2.49 per
basic average common share, an increase of $4.1 million, or $0.18 per share,
compared to 1998. Earnings increased primarily due to increased energy marketing
operations within Cleco Power and Midstream. Gross margins from energy marketing
operations (energy sales less energy purchases) increased $6.9 million.
Moderating the increase in gross margins were $0.9 million of costs for holding
company structure implementation, $2.0 million of costs for process redesign
consultants and $1.3 million
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of start-up costs for Evangeline. Offsetting the increase in continuing
operations is a loss of $1.3 million from the operations of UtiliTech compared
to a loss of $0.2 million in 1998. Total net income applicable to common stock
was $54.8 million, or $2.43 per basic average common share, in 1999 compared to
$51.7 million, or $2.30 per basic average common share, in 1998.
Earnings for past years are not necessarily indicative of future earnings
and results. Future earnings will be affected by, among other things, weather
conditions, the Company's business development programs, the overall economy of
Cleco Power's service area, operating performance of the facilities of Cleco
Power and Midstream, legislative and other regulatory changes, and increased
competition.
CONSOLIDATED REVENUES, EXCLUDING DISCONTINUED OPERATION
Consolidated operating revenues were $820.0 million in 2000, an increase of
$55.6 million over 1999. The majority of the increase in 2000 revenues compared
to 1999 revenues was due to an increase of $110.7 million in retail electric
operations within Cleco Power. Offsetting the increase in retail electric
operations was a decrease of $55.5 million in consolidated energy marketing and
tolling operations between 2000 and 1999. Consolidated operating revenues were
$764.4 million in 1999, an increase of $249.3 million over 1998 revenues. The
majority of the increase was due to increased sales in consolidated energy
marketing. Changes in consolidated revenues are further explained in the
discussion of revenues relating to each segment of the Company below.
REVENUES AND SALES - CLECO POWER
2000 1999 1998
- ------------------------------------------------------------------------------------------------
Revenues (Thousands) Change (Thousands) Change (Thousands) Change
-------------------------------------------------------------------
Base $322,716 5.4 % $306,225 3.1 % $296,893 6.6%
Fuel cost recovery 296,812 46.5 % 202,565 6.4 % 190,387 7.1%
Estimated customer credits (1,233) (55.6)% (2,776) (42.2)% (4,800) -
Energy marketing 18,078 (92.4)% 237,731 627.1 % 32,695 -
- ------------------------------------------------------------------------------------------------
Total revenues $636,373 (14.4)% $743,745 44.4 % $515,175 12.9%
- ------------------------------------------------------------------------------------------------
Retail rates for residential, commercial and industrial customers and
other retail sales (approximately 75% of the Company's consolidated revenues in
2000) are regulated by the LPSC. Rates for transmission and wholesale power
sales are regulated by the Federal Energy Regulatory Commission (FERC). Retail
rates consist of a base rate and a fuel rate. Base rates are designed to allow
recovery of the cost of providing service and a return on utility assets. Fuel
rates fluctuate, allowing recovery of, with no profit, the majority of costs of
purchased power and fuel used to generate electricity. Energy marketing revenues
are based on the electric and natural gas markets, which are affected by supply
and demand of those commodities, as well as Cleco Power's marketing strategies.
Cleco Power's base revenues were reduced $3.0 million annually
beginning November 1, 1996, and were reduced by an additional $2.0 million
annually beginning January 1, 1998, as part of an LPSC earnings review. Revenues
in 2000, 1999 and 1998 were reduced further by $1.2 million, $2.8 million and
$4.8 million, respectively, for one-time customer rate refunds based on the same
LPSC settlement. For more information on the LPSC settlement, see "Financial
Condition - Retail Rates of Cleco Power" below.
Most of the $16.5 million increase in base revenues in 2000 compared to
1999 was primarily due to a 4.9% increase in kilowatt-hour (kWh) sales to
regular customers caused by warmer than normal summer weather and the third
coldest December on record in Cleco Power's service territory. The remainder of
the increase was largely due to increased transmission and miscellaneous
revenues.
Fuel cost recovery revenues collected in 2000 increased $94.2 million
over 1999 mainly because of the increase in natural gas prices in 2000 compared
to 1999, which increased the cost to generate power from Cleco Power's own
generation stations and increased the cost of purchased power in the region.
Most of the cost of fuel and purchased power is currently passed on to customers
through fuel cost adjustment clauses. Generally, fluctuations in fuel and
purchased power cost do not materially affect net income. For information on
changes in the fuel adjustment clauses, see "Financial Condition - Retail Rates
of Cleco Power" below.
Energy marketing revenues decreased $219.7 million in 2000 compared to
1999 due to a reduced level of energy trading activities resulting from a
refinement of
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trading practices within Cleco Power and from the transfer of the Coughlin Power
Station (CPS) to Evangeline. Management expects energy trading revenues during
the next year to be in line with year 2000 levels.
Approximately half of the $9.3 million increase in base revenues in 1999
compared to 1998 was due to a 2.9% increase in sales to regular customers. The
increase in sales to regular customers in 1999 compared to 1998 resulted
primarily from increased sales to commercial and industrial customers primarily
driven by increased economic growth in the region. The remainder of the increase
was due largely to increased transmission and miscellaneous revenues.
Fuel cost recovery revenues collected in 1999 increased $12.2 million
over 1998 mainly because increased demand for power necessitated the purchase of
more power on the wholesale market at higher prices in 1999 than in 1998.
Energy marketing revenues increased $205.0 million in 1999 compared to
1998 due to several factors. Cleco Power's electric marketing operation was not
operational until late in the second quarter of 1998 and was still in start-up
mode in the third quarter of 1998. Additionally, in 1998 the operation traded
only in the Into Entergy market, whereas in 1999, it expanded into the Cinergy
market. In 1999 the operation also started marketing natural gas.
Weather influences the demand for electricity, especially among residential
customers. Much of this demand is measured in cooling degree days and heating
degree days. A cooling degree day is an indication of the likelihood of a
consumer utilizing air conditioning while a heating degree day is an indication
of the likelihood of a consumer utilizing heating. The following chart indicates
the percentage variance from normal and from the prior year for combined
cooling/heating degree days for 2000, 1999 and 1998.
Combined Cooling/Heating Degree Days
2000 1999 1998
- --------------------------------------------------------
Increase/(Decrease)
From Normal 5.1% (3.4)% 1.0 %
Increase/(Decrease)
From Prior Year 8.6% (4.3)% (3.0)%
Demand for electricity by commercial and industrial customers is primarily
dependent upon the strength of the economy in the service territory and the
nation and is less affected by weather. Sales to industrial customers also are
affected by the worldwide demand for wood products since Cleco Power's two
largest customers are producers of such products. The following chart compares
the kWh sales by customer class, for 2000, 1999 and 1998.
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------
Million kWh Change Million kWh Change Million kWh Change
-------------------------------------------------------------------------
Electric Sales
- ---------------------------------------------------------------------------------------------------------------
Residential 3,357 4.6 % 3,208 (0.7)% 3,230 13.8 %
Commercial 1,675 4.9 % 1,597 4.4 % 1,529 9.8 %
Industrial 2,926 7.6 % 2,720 8.0 % 2,518 2.1 %
Other retail 589 2.6 % 574 3.4 % 555 4.0 %
- ---------------------------------------------------------------------------------------------------------------
Total retail 8,547 5.5 % 8,099 3.4 % 7,832 8.3 %
Sales for resale 342 (8.3)% 373 (7.2)% 402 29.3 %
- ---------------------------------------------------------------------------------------------------------------
Total sales to regular customers 8,889 4.9 % 8,472 2.9 % 8,234 9.2 %
Short-term sales to other utilities 77 (38.9)% 126 65.8 % 76 (51.6)%
Sales from marketing activities 81 (98.6)% 5,815 467.3 % 1,025 -
- ---------------------------------------------------------------------------------------------------------------
Total electric sales 9,047 (37.2)% 14,413 54.4 % 9,335 21.2 %
- ---------------------------------------------------------------------------------------------------------------
The increase in sales to commercial and industrial customers during 2000
compared to 1999 resulted primarily from increased economic growth in the region
served by Cleco Power and in the United States generally.
The increase in sales to residential customers during 2000 compared to
1999 resulted primarily from warmer than normal spring and summer seasons in
2000 and colder than normal weather during the winter of 2000.
The increase in sales to commercial and industrial customers during 1999 as
compared to 1998 resulted primarily from increased economic growth in the region
served by Cleco Power and in the United States generally.
During the last five years, sales growth to retail electric customers
averaged 4.5% and, based on current information, is expected to range from 2% to
3% per year during the next five years. The levels of future sales will depend
upon factors such as weather conditions, customer conservation efforts, Cleco
Power's retail marketing and business development programs, and the overall
economy of the service area. Some of the issues
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facing the electric utility industry that could affect sales include
deregulation, retail wheeling, legislative and regulatory changes, retention of
large industrial customers, franchises, changes in electric rates compared to
customers' ability to pay and access to transmission systems.
Sales from energy marketing activities are primarily affected by
transmission constraints, demand versus supply, Cleco Power's marketing strategy
and market prices. The decrease in sales from marketing activities in 2000 over
1999 was due to a reduced level of energy trading activities resulting from a
refinement of trading practices within Cleco Power and from the transfer of CPS
to Evangeline. The increase in sales of electricity from marketing activities in
1999 over 1998 was due to a full year of marketing of electricity in 1999. The
Company is exploring the possibility of transferring additional generation
facilities from Cleco Power to Midstream. Management is unable to predict
whether it will be able to transfer any additional generation from Cleco Power
to Midstream or what impact any such transfer would have on the Company's
financial condition or results of operations.
REVENUES AND SALES - MIDSTREAM
Midstream's revenue in 2000 was $183.6 million, an increase of $162.7
million compared to 1999, which primarily resulted from energy marketing and
tolling activities which accounted for 99.7% of total Midstream 2000 revenues.
The three main subsidiaries of Midstream are Evangeline, Cleco Marketing &
Trading LLC (CMT) and Cleco Energy LLC (Energy).
Evangeline's tolling revenue in 2000 was $41.3 million and was derived
from the Evangeline Capacity Sale and Tolling Agreement (Evangeline Tolling
Agreement) and the Interim Tolling Agreement with Williams Energy Marketing and
Trading Company (Williams). In July 2000 Unit No. 7 of the Evangeline power
plant commenced commercial operation. The other unit at the plant, Unit No. 6,
commenced commercial operation during June 2000. In 2001 revenues and operating
expenses relating to both units are reflected on the Company's Consolidated
Statements of Income after they commenced commercial operation. Revenues
expected to be recognized from the Evangeline Tolling Agreement in 2001 are as
follows: 15% in the first quarter, 15% in the second quarter, 50% in the third
quarter and 20% in the fourth quarter. Tolling revenues are primarily affected
by the availability of the Evangeline power plant to operate and other
characteristics of the plant. See Notes to the Consolidated Financial
Statements, Note B - "Summary of Significant Accounting Policies - Revenues and
Fuel Costs - Tolling Revenues" for more information.
CMT's and Energy's revenues in 2000 were $141.8 million, an increase of
$123.1 million compared to 1999. The primary reason for the increase was CMT
began operations in July 1999, whereas CMT had an entire year of operations in
2000. The main business of CMT is marketing wholesale natural gas and
electricity in Louisiana and Texas. Sales from energy marketing activities are
primarily affected by transportation constraints, demand versus supply, ability
to meet margin calls and market prices.
Midstream's revenue in 1999 was $20.9 million and was derived mainly
from one of its subsidiaries, CMT, which began operations in July 1999 and
represented approximately 89% of Midstream's revenues during 1999. Midstream had
minimal revenues in 1998 due to its organization in the fourth quarter of 1998.
Fuel, Purchased Power and Purchases for Energy Marketing - Cleco Power
Changes in fuel and purchased power expenses reflect fluctuations in
generation mix, fuel costs, availability of economy power and deferral of
expenses for recovery from customers through fuel adjustment clauses in
subsequent months. The following table shows the amount and changes in fuel and
purchased power expenses for 2000, 1999 and 1998.
2000 1999 1998
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(Thousands) Change (Thousands) Change (Thousands) Change
--------------------------------------------------------------------------
Fuel used for electric
generation $182,023 25.3 % $145,229 1.7% $142,737 4.9%
Power purchased 121,963 86.8 % 65,303 23.2% 53,011 18.9%
- -----------------------------------------------------------------------------------------------------------
Total fuel expenses $303,986 44.4 % $210,532 7.6% $195,748 8.4%
- -----------------------------------------------------------------------------------------------------------
Gas purchased for marketing $ 11,136 (54.9)% $ 24,687 - - -
Power purchased for marketing $ 2,447 (98.8)% $205,397 651.8% $ 27,322 -
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Total fuel expense increased $93.5 million in 2000 compared to 1999
primarily due to increased prices in natural gas and increased demand from
native load customers. Of the 1,359 megawatts (MW) of Cleco Power's generating
capacity, 437 MW uses natural gas as the source of fuel, 440 MW can use either
natural gas or fuel oil, 157 MW can use either natural gas or coal, and 325 MW
uses lignite.
Purchased power increased $56.7 million in 2000 compared to 1999 largely
due to the amount of generation in the region that uses natural gas as a fuel,
the overall increase in demand in the region and the reduction of generation
capacity resulting from the transfer of CPS.
Power and gas purchased for marketing primarily in 2000 decreased $216.5
million compared to 1999 mainly due to a reduced level of energy trading
activities resulting from a refinement of trading practices within Cleco Power
and from the transfer of CPS to Evangeline.
Total fuel expense increased $14.8 million in 1999 compared to 1998
primarily due to increased demand from native load customers, which necessitated
the purchase of more power on the wholesale market at higher prices than in
1998. Power purchased for marketing in 1999 compared to 1998 increased largely
due to a full year of activity in the energy marketing operations in 1999.
Natural gas marketing did not begin until 1999.
Coal and lignite are obtained under long-term contracts. Natural gas is
purchased for Cleco Power's use under short-term contracts. Cleco Power has
several power contracts with two power marketing companies for 605 MW of
capacity in 2000, increasing to 760 MW of capacity in 2004. Power is purchased
from other utilities to supplement Cleco Power's generation resources at times
of relatively high demand, as well as when the purchase price is less than Cleco
Power's cost of generation and when transmission capacity is available to
transport the energy to Cleco Power's system. During 2000, 34% of Cleco Power's
energy requirements were met with purchased power, up from 27% in 1999 and 24%
in 1998.
In future years Cleco Power's generating facilities may not supply
enough electric power to meet its growing native load demand. Because of its
location on the transmission grid, Cleco Power relies on one main supplier of
electric transmission and is sometimes constrained as to the amount of purchased
power it can bring into its system. The power contracts described above are not
expected to be affected by such transmission constraints. The Company is
exploring the possibility of transferring generation facilities from Cleco Power
to Midstream. Management is unable to predict whether it will be able to
transfer any additional generation from Cleco Power to Midstream or what impact
any such transfer would have on the Company's financial condition or results of
operations.
Cleco Power and the joint owner of one of its electric generating units
jointly filed suit in 1997 against a joint venture and its partners who mine
lignite for the generating unit. The joint venture has filed counterclaims. The
counterclaims caused Cleco Power and the joint owner to file another suit
against the joint venture's parent company. Management believes the
counterclaims, if successful, would not have a material adverse effect on Cleco
Power's financial condition or results of operations. Normal day-to-day
operations continue at the mining facility and the jointly owned electric
generating unit. See Note Q - "Legal Proceeding: Fuel Supply - Lignite" for more
information.
Energy owns and operates natural gas pipelines at two of Cleco Power's
generating plants where natural gas is used as a primary fuel. These pipelines
increase access to natural gas markets and lower the cost of gas supplies.
PURCHASES FOR ENERGY MARKETING - MIDSTREAM
Purchases for energy marketing in Midstream were $134.1 million in
2000, an increase of $119.8 million compared to 1999. Energy marketing expenses
are incurred by CMT, Energy and Evangeline. The primary reasons for the increase
are a full year of trading during 2000 at CMT and the start-up of Evangeline in
2000.
Purchases for energy marketing operations in CMT and Energy were $127.7
million, an increase of $113.6 million compared to 1999. The primary reason for
the increase was CMT began operations in July 1999, whereas CMT had an entire
year of operations in 2000.
Purchases for energy marketing expenses in Evangeline were $6.9 million
in 2000, which relates to purchases for replacement power provided to Williams
under the Evangeline Tolling Agreement. When Evangeline's plant is unable to
operate, Evangeline has the option to purchase replacement power to provide to
Williams. By providing replacement power, Evangeline
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can maintain certain capacity requirements under the Evangeline Tolling
Agreement and be reimbursed by Williams for replacement power based upon the
heat rate of the plant, the price of natural gas and the amount of MWH of
replacement power provided to Williams.
NONFUEL OPERATING EXPENSES AND INCOME
TAXES - ALL SEGMENTS, EXCLUDING
DISCONTINUED OPERATION
Changes in consolidated nonfuel operating expenses for all segments for
2000, 1999 and 1998 were as follows:
2000 1999 1998
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(Thousands) Change (Thousands) Change (Thousands) Change
--------------------------------------------------------------------------
Other operations $ 90,766 14.5% $ 79,240 11.5 % $ 71,066 10.0%
Maintenance 35,271 18.2% 29,852 (1.4)% 30,285 30.0%
Depreciation 55,840 11.8% 49,966 3.3 % 48,382 5.4%
Other taxes 37,429 3.8% 36,045 1.8 % 35,420 6.0%
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Total $219,306 12.4% $195,103 5.4 % $185,153 10.7%
- -----------------------------------------------------------------------------------------------------------
Other operations expense increased $11.5 million in 2000 compared to 1999.
Approximately $5.2 million of the increase was in Cleco Power. Energy capacity
payments increased $10.2 million in 2000 compared to 1999 primarily due to
increased purchased power for native load, offset by decreased expenses in
transmission, distribution and customer accounting operations. The majority of
the remaining $6.3 million of the increase is within Midstream and is primarily
due to the operations of Evangeline and asset development efforts.
Maintenance expense increased $5.4 million in 2000 compared to 1999.
Evangeline's maintenance increased $1.5 million due to the commencement of
operations during 2000. Maintenance within Cleco Power increased $1.5 million in
2000 compared to 1999 mainly due to overhead distribution maintenance.
Depreciation expense increased $5.9 million in 2000 compared to 1999
primarily attributable to a $4.2 million increase in Evangeline's depreciation
due to the commencement of commercial operations during 2000.
The 1999 increase in other operations expense was mainly due to start-up
expenses in the Midstream subsidiaries and increased charges of wheeling
purchased power into Cleco Power's system.
A number of parishes (counties) have attempted in recent years to impose
franchise fees on retail revenues earned within the unincorporated areas which
Cleco Power serves. If the parishes are ultimately successful, Cleco Power's
taxes other than income taxes could increase substantially in future years.
INTEREST INCOME, OTHER INCOME, AND
INTEREST EXPENSE - ALL SEGMENTS,
EXCLUDING DISCONTINUED OPERATION
Interest income in 2000 was $6.6 million, a $4.9 million increase compared
to 1999. Evangeline's interest income was $2.9 million in 2000, an increase of
$2.8 million compared to 1999. The increase was primarily due to the interest
earned from investing the proceeds of the Evangeline senior secured bonds and
the equity infusion in Evangeline from the Company. The Company earned $2.5
million from investing proceeds of the $100 million bond issuance.
Interest income in 1999 increased $1.3 million compared to 1998 mainly
due to interest related to federal tax refunds and Cleco Power carrying more
investments than in previous years, as a result of pre-funding the refinancing
of medium-term notes.
Interest expense for 2000 was $48.7 million, an increase of $20.3 million
compared to 1999. Interest expense at Evangeline for 2000 was $11.2 million
compared to $0.2 million in 1999. The increase at Evangeline was mainly caused
by the Evangeline senior secured bonds issued in December 1999. Interest expense
increased $6.2 million in 2000 compared to 1999 largely due to the issuance by
the Company of $100 million in notes in May 2000 and the increased balance in
commercial paper issued.
Interest expense for 1999 increased $1.4 million compared to 1998. The
increase is primarily due to several factors: higher interest rates on variable
rate short-term debt during 1999; higher interest expense on Cleco Power's
pollution control bonds due to the refinancing of the bonds at a fixed rate; and
the replacement of short-term debt at Cleco Power with medium-term notes in
order to pre-fund the refinancing of medium-term notes at Cleco Power.
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ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION (AFUDC)
AFUDC represents Cleco Power's estimated cost of financing LPSC and FERC
rate-regulated construction and is not a current source of cash. A return on and
recovery of AFUDC is permitted by regulatory bodies in setting rates charged for
utility services. AFUDC accounted for 1.0% of net income applicable to common
stock in 2000, compared to 0.9% in 1999 and 2.2% in 1998.
INCOME TAX EXPENSE
Income tax expense for 2000 increased by $7.2 million compared to 1999
primarily due to higher earnings. The $1.0 million increase in income tax
expense in 1999 compared to 1998 also was a result of slightly higher earnings.
See Note K - "Income Tax Expense" for additional information.
DISCONTINUED OPERATION
In December 2000 management decided to sell substantially all of
UtiliTech's assets and discontinue UtiliTech's operations after the sale. The
sale is expected to be finalized during the first quarter of 2001 with all
operations estimated to cease by March 31, 2001. Additional information about
UtiliTech is as follows:
For the year ended December 31,
2000 1999 1998
- ----------------------------------------------------------------
(Thousands)
Revenues $18,125 $ 6,866 $ 214
Pretax loss from
operations of UtiliTech $ 8,801 $ 1,966 $ 275
Income tax benefit
associated with loss
from operations $ 3,390 $ 662 $ 106
Pretax loss from
disposal of UtiliTech $ 2,358 $ - $ -
Income tax benefit
associated with loss
on disposal $ 908 $ - $ -
EXTRAORDINARY GAIN
In March 2000 Four Square Gas, a wholly owned subsidiary of Energy, which
is wholly owned by Midstream, paid a third party $2.1 million for a note with a
face value of approximately $6.0 million issued by Four Square Production,
another wholly owned subsidiary of Energy. The note relates to the production
assets held by Four Square Production which were classified as assets available
for sale, described in Note H - "Assets Held for Sale," below. As part of the
transaction, the third-party debt holder sold the note, associated mortgage,
deed of trust and pledge agreement and assigned a 5% overriding royalty interest
in the production assets to Four Square Gas. Four Square Gas paid, in addition
to the $2.1 million, a total of 4.5% in overriding royalty interest in the
production assets. Four Square Gas borrowed the $2.1 million from the Company.
The gain of approximately $3.9 million was offset against the $1.4 million of
income tax related to the gain to arrive at the extraordinary gain, net of
income tax, of approximately $2.5 million. For the year ended December 31, 2000,
the extraordinary gain, net of income tax, had a basic earnings per share impact
of $0.11 and a diluted earnings per share impact of $0.10.
Financial Condition
LIQUIDITY AND CAPITAL RESOURCES
Financing for construction requirements and operational needs is dependent
upon the cost and availability of external funds through capital markets and
from financial institutions at both a company level and a project level. Access
to funds is dependent upon factors such as general economic conditions,
regulatory authorizations and policies, the Company's credit rating, the credit
rating of its subsidiaries, the operations of projects funded and the pro-forma
economics of projects to be funded.
At December 31, 2000 and 1999, there were $96.0 million and $26.0 million,
respectively, of short-term debt outstanding in the form of commercial paper and
bank loans. The following table shows short-term debt by subsidiary.
At December 31,
2000 1999
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Cleco Corporation (Thousands)
(Holding company level)
Commercial paper $ 54,220 -
Bank loans - $ 20,000
Cleco Power
Commercial paper 41,397 5,989
Midstream
Bank loans 340 -
- -----------------------------------------------------
Total $ 95,957 $ 25,989
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CLECO CORPORATION
(HOLDING COMPANY LEVEL)
Commercial paper increased at the Company level by $54.2 million at
December 31, 2000, compared to the same date in 1999, as a result of (i) the
extinguishment of $20 million of bank loans by the Company and (ii) project
funding at Midstream. Two credit facilities for the Company totaling $200
million are structured so that $120 million is scheduled to terminate on June
14, 2001,
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and $80 million is scheduled to terminate on August 25, 2002. The facilities
provide for working capital and other needs of the Company and its subsidiaries.
Guaranties issued by the Company to third parties for certain types of
transactions between those parties and the Company's subsidiaries, other than
Cleco Power, will reduce the amount of the facilities available to the Company
by an amount equal to the stated or determinable amount of the primary
obligation. In addition, certain indebtedness incurred by the Company outside of
these facilities will reduce the amount of the facilities available to the
Company. The amount of such guaranties and other indebtedness at December 31,
2000 and 1999, totaled $60.9 million and $18.2 million, respectively.
Uncommitted lines of credit with banks totaling $5 million are also available to
support working capital needs.
CLECO POWER
Commercial paper increased at Cleco Power by $35.4 million at December
31, 2000, compared to the same date in 1999, due to the maturity of $25 million
in medium-term notes and the need to fund increased fuel costs until cash is
received from customers. An existing $100 million Cleco Power revolving credit
facility is scheduled to terminate on June 14, 2001. This facility provides
support for the issuance of commercial paper and working capital needs.
OTHER
At December 31, 2000, CLE Resources, Inc. (Resources), a wholly owned
subsidiary of the Company, held $18.8 million of cash and marketable securities
compared to $13.1 million at December 31, 1999. This cash and marketable
securities are committed to supporting activities of affiliates.
Restricted cash represents cash to be used for specific purposes.
Approximately $15.8 million in restricted cash at December 31, 2000, represents
deposits into an escrow account for credit support as required by a provision of
the Evangeline Tolling Agreement. The credit support is to be maintained as
security for the performance of certain obligations by Evangeline under to the
Agreement. Upon the fulfillment of certain conditions specified in the
agreement, the credit support can be reduced to $13 million. The remaining $39.5
million of restricted cash at December 31, 2000, consists of the remaining
proceeds from the sale of Evangeline senior secured bonds, a capital
contribution from Midstream, cash received from Williams pursuant to the
Evangeline Tolling Agreement, less cash distributed to Midstream. The
construction of the project is complete and the plant has begun commercial
operation. However, the $55.3 million of restricted cash at December 31, 2000,
remains restricted under the bond indenture until certain of its provisions are
met. As the provisions are met, cash is transferred out of the escrow account
and is available for general corporate purposes.
CASH GENERATION AND CASH REQUIREMENTS
Cash Flows
During 2000 cash flows from operating activities generated $81.7 million,
as shown in the Consolidated Statements of Cash Flows. Net cash provided by
operating activities resulted from net income, adjusted for noncash charges to
income and changes in working capital. The net cash used in investing activities
of $209.7 million related primarily to additions to property, plant and
equipment and changes in utility and nonutility investments. Net cash provided
by financing activities of $132.2 million resulted principally from the issuance
of $100 million in senior unsecured notes by the Company in May 2000, cash
transferred from the restricted escrow account and issuance of short-term debt.
Net cash provided by financing activities was reduced by payment of dividends to
shareholders and the maturity of medium-term notes at Cleco Power.
On May 25, 2000, the Company issued $100 million aggregate principal amount
of its five-year senior unsecured notes. The new notes bear interest at 8.75%
per year and mature on June 1, 2005. Approximately $50 million of the proceeds
from the notes offered were used to pay down commercial paper financing. The
remainder was used to invest in joint ventures at Midstream.
Shelf Registrations
At December 31, 2000, the Company had a shelf registration statement
providing for the issuance of $100 million aggregate principal amount of its
debt securities. In February 2001, the Company filed a shelf registration
statement providing for the issuance of up to $150 million of common stock,
preferred stock and trust preferred securities, or any combination thereof. In
addition, at December 31, 2000, Cleco Power had a shelf registration providing
for the issuance of $200 million aggregate principal amount of medium-term notes
for which LPSC approval has been obtained.
F-8
Construction and Investment
in Subsidiaries Overview
The Company has divided its construction and investments along its
major first-tier subsidiaries - Cleco Power and Midstream. Cleco Power
construction consists of assets that may be added to Cleco Power's rate base,
and the cost of which, if considered prudent by the LPSC, may be passed on to
jurisdictional customers. Those assets earn a rate of return restricted by the
LPSC and are subject to the rate agreement described under "Retail Rates of
Cleco Power." Construction consists of additions to Cleco Power's distribution
system, improvements to its transmission system and improvements at its
generation stations. Midstream construction and investment consist of assets
whose rate of return is largely determined by the market, not the LPSC. Examples
include the repowering of the Evangeline facility, additions to gas pipeline
transmission systems and investments in joint ventures engaged in constructing
and owning power plants.
The Company is exploring the possibility of transferring generation
facilities from Cleco Power to Midstream. Management is unable to predict
whether it will be able to transfer any additional generation from Cleco Power
to Midstream or what impact any such transfer would have on the Company's
financial condition or results of operations.
Other subsidiaries had construction expenditures of $5 million during
2000 and $0.2 million during 1999. The expenditures primarily relate to the
installation of new financial software by Cleco Support Group LLC (Support
Group) in order to meet the growing needs of the Company and its subsidiaries.
Other construction expenditures for 2001 are estimated to total $9 million and
for the five-year period ending 2005 are expected to total $14.6 million. The
majority of the planned other construction in the five-year period will go
toward the installation of new financial software by Support Group.
Cleco Power Construction
In recent years Cleco Power's construction program has consisted primarily
of additions to its distribution system, improvements to its transmission system
and improvements at its generation stations. Cleco Power's construction
expenditures, excluding AFUDC, totaled $47.9 million in 2000 and $51.7 million
in 1999.
Cleco Power's construction expenditures, excluding AFUDC, for 2001 are
estimated to be $57 million and for the five-year period ending 2005 are
expected to total $249 million. About one-half of the planned construction in
the five-year period will support line extensions and substation upgrades to
accommodate new business and load growth. Some investment will be made to
rehabilitate older transmission, distribution and generation assets. Cleco Power
will also continue to invest in technology to allow it to operate more
efficiently.
In 2000 and 1999, 100% of Cleco Power's construction requirements were
funded internally, as compared to 99.8% in 1998. In 2001, 100% of construction
requirements are expected to be funded internally. For the five-year period
ending 2005, 96% of the construction requirements are expected to be funded
internally.
Midstream Construction
and Investment in Subsidiaries
Before 1998 construction within Midstream companies had consisted of a
series of natural gas interconnections between several gas transmission
pipelines and Cleco Power's generation stations that use natural gas. In 1998
Midstream started the repowering project at Evangeline Power Station. Additions
to property, plant and equipment totaled $60.3 million in 2000 and $127.3
million in 1999. Cash investments in subsidiaries, discussed below, totaled
$97.7 million in 2000 and zero in 1999. Total construction and investment in
subsidiaries totaled $158 million in 2000 and $127.3 million in 1999. At
December 31, 2000, Evangeline had total capitalized costs of $218.6 million and
construction work in progress of $7.1 million.
During 2000 Midstream announced the formation of two joint ventures, both
of which are 50% owned by Midstream.
Acadia Power Partners LLC (APP) is a joint venture with Calpine Corporation
which is in the process of constructing a 1,000 MW combined-cycle, natural gas-
fired power plant near Eunice, Louisiana. Total construction costs of the plant
to be incurred by APP are estimated at $564 million with an estimated completion
date of mid-2002. As of December 31, 2000, Midstream had contributed $97.2
million to APP. Midstream expects to contribute another $33 million to APP by
the end of the first quarter of 2001. In the second quarter of 2001, the Company
expects APP to receive interim non-recourse project financing and to reimburse
the Company for a large portion of the contributions to APP. Permanent non-
recourse financing at APP is expected to be received by the end of 2001.
Midstream's total equity
F-9
contribution to APP, net of reimbursement from permanent and interim project
financing, is expected to be approximately $80 million. See Note S -
"Commitments and Contingencies" for information concerning an action relating to
APP's water and air permits.
Perryville Energy Partners LLC (PEP) is a joint venture with Mirant
Corporation (formerly Southern Energy Inc.) that is in the process of
constructing a 700 MW combined-cycle, natural gas-fired power plant in
Perryville, Louisiana. Total construction costs of the plant to be incurred by
PEP are estimated at $340 million. A 150 MW combustion turbine operating in
simple cycle is expected to be operational by the summer of 2001. Full
commercial operation in combined cycle is expected for the summer of 2002. As of
December 31, 2000, Midstream had advanced PEP $11.2 million which it expects to
be reimbursed in the first quarter of 2001 by interim non-recourse project
financing obtained by PEP. Permanent non-recourse financing at PEP is expected
to be received in the second quarter of 2001. Total equity contribution in PEP,
net of reimbursement from permanent and interim project financing, is expected
to be approximately $34 million. See Note S - "Commitments and Contingencies"
for information concerning an action relating to PEP's air permit.
Expenditures for 2001 for Midstream's construction and net investment
in subsidiaries are estimated to total $47.9 million and for the five-year
period ending 2005 are expected to total $497 million. Most of the planned
construction and investment in the five-year period will consist of investment
in APP and PEP, additional generation facilities (including the potential
transfer of Cleco Power generation facilities to Midstream) and the potential
acquisition of natural gas assets.
In 2000, 15.3% of Midstream's construction and investment in subsidiaries
requirements were funded internally, compared to 1.6% in 1999 and 14.3% in 1998.
In 2001, 49% of Midstream's construction and investment in subsidiaries
requirements are expected to be funded internally. For the five-year period
ending 2005, 61% of Midstream's construction and investment in subsidiaries
requirements are expected to be funded internally.
Other Cash Requirements
Scheduled maturities of debt and preferred stock will total about $30.7
million for 2001 and approximately $297.5 million for the five-year period
ending 2005. In 1991 the Company began a common stock repurchase program in
which up to $23 million of common stock may be repurchased. The Company's
purchases of common stock under its repurchase program depend on a number of
factors including market conditions. The purchases may or may not be announced
in advance and may be made in the open market or in privately negotiated
transactions. During 2000 and 1998, the Company did not repurchase common stock
under the repurchase plan. In 1999 the Company repurchased common stock at a
cost of $3.8 million.
Inflation
Annual inflation rates, as measured by the U.S. Consumer Price Index,
have averaged approximately 2.6% during the three years ended December 31, 2000.
Management believes that inflation, at this level, does not materially affect
the Company's results of operations or financial position. However, under
existing regulatory practices, only the historical cost of plant is recoverable
from customers. As a result, Cleco Power's cash flows designed to provide
recovery of historical plant costs may not be adequate to replace plant in
future years.
INDUSTRY DEVELOPMENTS / CUSTOMER
CHOICE
Forces driving increased competition in the electric utility industry
involve complex economic, technological, legislative and regulatory factors.
These factors have resulted in the introduction of federal and state legislation
and other regulatory initiatives that could potentially produce even greater
competition at both the wholesale and retail levels in the future. Cleco Power
and a number of parties, including other Louisiana electric utilities, certain
power marketing companies and various associations representing industry and
consumers, have been participating in electric industry restructuring activities
before the LPSC since 1997. In 2000 the LPSC staff developed a transition to
competition plan that was presented to the LPSC. The staff's plan would allow
large industrial customers to have the opportunity to choose a power provider
starting in January 2003. The plan does not suggest a date for residential or
commercial customers. The LPSC is currently receiving comments and is reviewing
the plan. Several neighboring states have passed legislation providing for
retail choice by 2002. At the Federal level, several bills, some with
conflicting provisions, have been introduced and actively debated this past year
to promote a
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competitive environment in the electric utility industry, although none were
passed. Conversely, the troubled electric supply situation experienced in
California this past year has led many in the industry to reexamine the
restructuring process. While a competitive environment continues to be espoused
in many areas, several states have reduced or eliminated their restructuring
efforts or have asked for delays in implementing already passed rules or
legislation. Management expects the debate relating to customer choice and other
related issues to continue in legislative and regulatory bodies in 2001. At this
time, Cleco Power cannot predict whether any legislation or regulation affecting
it will be enacted or adopted during 2001 and, if enacted, what form such
legislation or regulation would take.
The Company is exploring the possibility of transferring generation
facilities from Cleco Power to Midstream. Management believes any potential
transfer of LPSC jurisdictional generation facilities from Cleco Power to
Midstream would be accompanied by consumer safeguards for Cleco Power's retail
customers. Management is unable to predict whether it will be able to transfer
any additional generation from Cleco Power to Midstream or what impact any such
transfer would have on the Company's financial condition or results of
operations.
A potentially competitive environment presents the opportunity to supply
electricity to new customers, as well as the risk of losing existing customers.
Management believes that Cleco Power is a reliable, low-cost provider of
electricity, and as such is currently positioned to compete effectively in a
restructured electric marketplace.
RETAIL RATES OF CLECO POWER
Retail rates regulated by the LPSC account for approximately 75% of the
Company's consolidated 2000 revenues. Fuel costs and monthly fuel adjustment
billing factors are subject to audit by the LPSC. In the past, Cleco Power has
sought increases in base rates to reflect the cost of service related to plant
facility additions and increases in operating costs. If Cleco Power requests an
increase in rates and adequate rate relief is not granted on a timely basis, the
ability to attract capital at reasonable costs to finance operations and capital
improvements might be impaired.
The LPSC elected in 1993 to review the earnings of all electric, gas,
water and telecommunications utilities it regulated to determine whether the
returns on equity of these companies may be higher than returns that might be
awarded in the then-current economic environment. In 1996 the LPSC approved a
settlement of Cleco Power's earnings review, providing customers with lower
electricity rates. A base rate decrease of $3 million annually became effective
November 1, 1996, with a second decrease of an additional $2 million annually
effective January 1, 1998. The terms of this settlement were to be effective for
a five-year period. In February 1999 the period was extended three years until
2004 under an agreement with the LPSC to transfer the existing assets of CPS
from Cleco Power's LPSC regulated rate base into Evangeline, which then
repowered the generating plant.
During the eight-year period ending September 30, 2004, an LPSC-approved
rate stabilization plan is in place. This plan allows Cleco Power to retain all
earnings equating to a regulatory return on equity up to and including 12.25% on
its regulated utility operations. Any earnings that result in a return on equity
over 12.25% and up to and including 13% will be shared equally between Cleco
Power and its customers. Any earnings above 13% will be fully refunded to
customers. This effectively allows Cleco Power the opportunity to realize a
regulatory rate of return of up to 12.625%. As part of the rate stabilization
plan, the LPSC will annually review revenues and return on equity. If Cleco
Power is found to be achieving a regulatory return on equity above the minimum
12.25%, a refund will be made in the form of billing credits during the month of
September following the evaluation period. Customers received a refund of $1.1
million in September 2000. Of that amount, approximately $0.6 million was
reflective of the earnings level achieved in the previous earnings period while
the remainder originated from a settlement agreement with the LPSC pertaining to
the 1998 earnings period. The determination of any refund relative to the 2000
earnings monitoring period is under review by LPSC staff. See Note M- "Accrual
of Estimated Customer Credits" for information concerning amounts accrued by
Cleco Power based on the settlement agreement and Note P -"Proceedings before
the LPSC" for information regarding a settlement with the LPSC.
In November 1997 the LPSC issued an order in a generic docket which
promulgated new standards for the monthly Fuel Adjustment Clause (FAC) rate
filings of electric companies under its jurisdiction. The order
F-11
adopted new rules and procedures for the monthly FAC computation and required
changes in reporting of fuel and purchased power cost. Although the order
narrowed the types of costs that can be included in the FAC, it offset this
reduction with an increase in the base rates. New rate schedules that
incorporate the shifting of costs from FAC to base rates were calculated,
subsequently approved by the LPSC and implemented on January 1, 2000. The
changes resulted in an immaterial effect upon the Company's financial condition
and results of operations.
FRANCHISES
Cleco Power operates under nonexclusive franchise rights granted by
governmental units, such as municipalities and parishes (counties), and enforced
by state regulation. These franchises are for fixed terms, which vary from 10 to
50 years. In the past, Cleco Power has been substantially successful in the
timely renewal of franchises as each reaches the end of its term. In February
2001 Cleco Power successfully negotiated a franchise with the City of Jeanerette
for a 20-year franchise covering its approximately 3,000 customers. The City of
Jeanerette franchise had expired in 1997, and Cleco Power continued to serve the
city while negotiating for a new franchise. Cleco Power's franchise with the
City of Opelousas, which has 10,873 customers, was scheduled to expire August
2001. In November 2000 Cleco Power successfully negotiated a renewal of that
franchise for a term of 10 years beginning August 2001. Cleco Power's franchises
with the cities of Washington and Franklinton, and their 1,891 and 2,484
customers, respectively, will be up for renewal in 2003. Cleco Power was
successful in an October 7, 2000, referendum to renew its franchise agreement
with the City of New Iberia for a term of 25 years. Cleco Power currently serves
18,744 customers in New Iberia.
ENVIRONMENTAL MATTERS
The Company is subject to federal, state and local laws and regulations
governing the protection of the environment. Violations of these laws and
regulations may result in substantial fines and penalties. The Company has
obtained all material environmental permits necessary for its operations and
believes it is in substantial compliance with these permits, as well as all
applicable environmental laws and regulations. The Company anticipates that
existing environmental rules will not affect operations significantly, but some
capital improvements may be required in response to new environmental programs
expected in the next few years.
Implementation of Phase I of the Clean Air Act did not require the
Company to reduce sulfur emissions at Cleco Power's solid-fuel generating units,
which either burn low-sulfur coal or utilize pollution control equipment.
Installation of continuous emission monitoring equipment on Cleco Power's
generating units was completed in 1996 at a cost of approximately $3 million.
Although Phase II of the legislation, which became effective in 2000, involves
more stringent limits on emissions, these requirements have not and in the
future should not significantly affect the operation of the Company's generating
units. The following table lists capital expenditures for environmental matters
by subsidiary.
Capital expenditures Projected capital
for 2000 expenditures for 2001
- ---------------------------------------------------------------
Subsidiary (Thousands)
Cleco Power $ 573 $651
Evangeline 3,732 -
- ---------------------------------------------------------------
Total $4,305 $651
- ---------------------------------------------------------------
See Note S - "Commitments and Contingencies."
REGULATORY MATTERS
The Energy Policy Act, enacted by Congress in 1992, significantly changed
U.S. energy policy, including regulations governing the electric utility
industry. The Energy Policy Act allows the FERC, on a case-by-case basis and
with certain restrictions, to order wholesale transmission access and to order
electric utilities to enlarge their transmission systems. The Act prohibits
FERC-ordered retail wheeling such as opening up electric utility transmission
systems to allow customer choice of energy suppliers at the retail level,
including "sham" wholesale transactions. Further, under the Energy Policy Act, a
FERC transmission order requiring a transmitting utility to provide wholesale
transmission services must include provisions generally permitting the utility
to recover from the FERC applicant all of the costs incurred in connection with
the transmission services, including any enlargement of the transmission system
and any associated services.
In addition, the Energy Policy Act revised the 1935 Federal Power Act
(1935 FPA) to permit utilities, including registered holding companies, and
non-utilities to form "exempt wholesale generators" without the principal
restrictions of the 1935 FPA. Under prior law, independent power producers
generally were required to adopt inefficient and complex ownership structures to
avoid pervasive regulation under the 1935 FPA.
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In 1996 the FERC issued Orders No. 888 and 889 requiring open access to
utilities' transmission systems. The open access provisions require
FERC-regulated electric utilities to offer third parties access to transmission
under terms and conditions comparable to the utilities' use of their own
systems. In addition, Order No. 888, as amended, provides for the full recovery
of wholesale stranded costs, to the extent such costs were prudently incurred to
serve wholesale customers and would go unrecovered if those customers used open
access transmission service and moved to another electricity supplier, from a
utility's departing customers. Order No. 888, as amended, also allows customers
under existing wholesale sales contracts to seek FERC approval to modify their
contracts on a case-by-case basis. Because of the "grandfather" provisions of
Orders No. 888 and 889, most of Cleco Power's existing transmission contracts
are not affected. To date, the orders have not had a material effect on the
Company's financial condition or results of operation.
In 1999 the FERC issued Order No. 2000, which further defines the operation
of utilities' transmission systems. This order establishes a general framework
for all transmission-owning entities in the nation to voluntarily place their
transmission facilities under the control of an appropriate Regional
Transmission Organization (RTO). Although participation is voluntary, the FERC
has made it clear that any jurisdictional entity not participating in an RTO
will be subject to further regulatory directives. Current objectives state that
all electric utilities which own, operate or control interstate transmission
facilities should participate in an RTO that will be operational no later than
December 15, 2001. On October 16, 2000, Cleco Power submitted a filing with the
FERC stating that it will join the RTO of the Southwest Power Pool (SPP), either
as a member of the SPP Independent System Operator or as part of Entergy's
transmission company, by December 15, 2001. The decision will be made once the
details of the transmission companies are finalized. The transfer of control of
Cleco Power's transmission facilities to an RTO has the potential to materially
affect the Company's financial condition and results of operations.
Wholesale energy markets, including the market for wholesale electric
power, are becoming even more competitive than in the past as the number of
participants in these markets increases with the ongoing enactment of the Energy
Policy Act and the regulatory activities of the FERC.
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," establishes accounting standards for determining if long-lived assets are
impaired and when and how losses, if any, should be recognized. The Company
believes that the net cash flows that will result from the operation of the
Company's assets are currently sufficient to cover the carrying value of the
assets.
The Emerging Issues Task Force (EITF) assists the Financial Accounting
Standards Board (FASB) in identifying emerging issues affecting financial
reporting. In 1997 the EITF reached a consensus in Issue No. 97-4, "Deregulation
of the Pricing of Electricity - Issues Related to the Application of SFAS No. 71
and No. 101." EITF 97-4 specified that SFAS No. 71, "Accounting for the Effects
of Certain Types of Regulation," should be discontinued at a date no later than
when the details of a transition plan toward the deregulation of electric rates
for all or a portion of the entity subject to such plan are known. However,
other factors could cause the discontinuation of SFAS No. 71 before that date.
Additionally, EITF 97-4 establishes that regulatory assets to be recovered
through cash flows derived from another portion of the entity which continues to
apply SFAS No. 71 should not be written off, but rather should continue to be
considered regulatory assets of the separable portion which will continue to
apply SFAS No. 71. As of December 31, 2000, none of the requirements of EITF
97-4 were met, therefore Cleco Power did not discontinue applying SFAS No. 71.
FINANCIAL RISK MANAGEMENT
The market risk inherent in the Company's market risk-sensitive instruments
and positions is the potential change arising from increases or decreases in the
short-, medium- and long-term interest rates, the commodity price of electricity
traded on the Into Entergy and Cinergy markets and the commodity price of
natural gas traded. Generally, Cleco Power's market risk-sensitive instruments
and positions are characterized as "other than trading;" however, Cleco Power
does have positions that are considered "trading" as defined by EITF 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." All of CMT's positions are characterized as "trading" under EITF
98-10. The Company's exposure to market risk, as discussed below, represents an
estimate of possible
F-13
changes in the fair value or future earnings that would occur, assuming possible
future movements in interest rates and the commodity price of electricity and
natural gas. Management's views on market risk are not necessarily indicative of
actual results, nor do they represent the maximum possible gains or losses. The
views do represent, within the parameters disclosed, what management estimates
may happen.
Interest
The Company has entered into various fixed- and variable-rate debt
obligations. See the Notes to the Consolidated Financial Statements, Note E -
"Debt" for details. The calculations of the changes in fair market value and
interest expense of the debt securities are made over a one-year period.
As of December 31, 2000, the carrying value of the Company's long-term,
fixed-rate debt was approximately $680.7 million, with a fair market value of
approximately $708.9 million. Fair value was determined using quoted market
prices. Each 1% change in the average interest rates applicable to such debt
would result in a change of approximately $41.9 million in the fair values of
these instruments. If these instruments are held to maturity, no change in fair
value will be realized.
As of December 31, 2000, the carrying value of the Company's long-term,
variable-rate debt was approximately $9.7 million, which approximates the fair
market value. Each 1% change in the average interest rates applicable to such
debt would result in a change of approximately $97,000 in the Company's pretax
earnings.
As of December 31, 2000, the carrying value of the Company's long-term
debt to be paid in Company common stock was approximately $0.5 million, with an
approximate market value of $0.9 million. Fair value was determined using the
quoted market price for Company common stock at December 31, 2000. Each $6
change in price of Company common stock would result in a change of
approximately $96,000 in the fair value of this debt.
As of December 31, 2000, the carrying value of the Company's short-term,
variable-rate debt was approximately $95.9 million, which approximates the fair
market value. Each 1% change in the average interest rates applicable to such
debt would result in a change of approximately $1 million in the Company's
pretax earnings.
The Company monitors its mix of fixed- and variable-rate debt obligations
in light of changing market conditions and from time to time may alter that mix
by, for example, refinancing balances outstanding under its variable-rate
commercial paper program with fixed-rate debt.
As of December 31, 2000, Resources held $18.8 million in cash equivalents
in a money market account. Each 1% change in average interest rates applicable
to such investments could result in a change of approximately $188,000 in the
Company's pretax earnings.
Market Risk
Management believes the Company has in place controls to help minimize
the risks involved in marketing and trading. Controls over marketing and trading
consist of a back office (accounting) and mid-office (risk management)
independent of the marketing and trading operations, oversight by a risk
management committee comprised of Company officers and a daily risk report which
shows value-at-risk (VAR) and current market conditions. The Company's Board of
Directors appoint the members of the Risk Management Committee. VAR limits are
set and monitored by the Risk Management Committee.
CMT engages in marketing and trading of power and natural gas. All of
CMT's trades are considered "trading" under EITF 98-10 and are marked-to-market.
Due to market price volatility, mark-to-market reporting may introduce
volatility to carrying values and hence to the Company's financial statements.
The mark-to-market of trading positions at December 31, 2000, was a loss of
$421,373.
Most of Cleco Power's positions are considered "other than trading"
under EITF 98-10. However, Cleco Power does have financial positions that are
defined as "trading" under EITF 98-10. At December 31, 2000, the mark-to-market
for those positions was a gain of $55,148.
Both CMT and Cleco Power utilize a VAR model to assess the market risk
of their trading portfolios including the derivative financial instruments. VAR
represents the potential loss for an instrument from adverse changes in market
factors for a specified period of time and confidence level. The VAR is
estimated using historical simulation calculated daily assuming a holding period
of one day with a 95% confidence level for natural gas positions and a 99.7%
confidence level for electricity positions. Total volatility is based on
historical cash volatility, implied market volatility, current cash volatility
and option pricing. Based on these assumptions, the high, low and average VAR
during the year ended
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December 31, 2000, as well as the VAR at December 31, 2000, is summarized below:
At
High Low Average 12/31/2000
- ----------------------------------------------------
(Thousands)
CMT $5,873.2 $35.2 $1,122.2 $1,570.6
Cleco Power $2,168.1 $ 5.2 $ 275.2 $ 322.4
Consolidated $6,113.4 $69.4 $1,390.8 $1,892.9
In 1999 the Company reported VAR using a 99.7% confidence level for both
natural gas and electricity. The change in reporting VAR using a confidence
level of 95% for natural gas is due to the greater maturity, greater liquidity
and depth of products in the natural gas market as compared to the immaturity
and volatility of the electricity markets. Reporting VAR using a confidence
level of 95% is also the industry standard for natural gas. The table below
summarizes the VAR at December 31, 1999, if VAR had been reported using a 95%
confidence level:
At December 31, 1999
- ----------------------------------------
(Thousands)
CMT $46.3
Cleco Power $51.2
Consolidated $97.4
New Accounting Standards
In 1998 the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 established accounting and
reporting standards requiring that every derivative instrument (including
certain derivatives embedded in other contracts) be recorded on the balance
sheet as either an asset or liability measured at its fair value. This statement
requires that changes in the derivative's fair value be recognized in current
earnings, unless effective accounting criteria tests are met, where changes in
the fair value of the derivative would be recorded in other comprehensive income
in the equity section of the balance sheet.
In June 1999 the FASB issued SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133," which deferred the effective date of SFAS No. 133 to fiscal
years beginning after June 15, 2000. In June 2000 the FASB issued SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities,"
which amended certain normal purchase and sales guidance within SFAS No. 133.
In early 2000 the Company organized a cross-functional project team for
implementing SFAS No. 133, as amended. The team completed an inventory of the
Company's financial and commodity contracts and other commitments, and assessed
the Company's derivative-related transactions identified in this inventory. This
assessment revealed that Cleco Power and subsidiaries of Midstream were impacted
by this standard.
Cleco Power
As of January 1, 2001, Cleco Power had the following contractual
obligations that met the definition of a derivative-related transaction:
. Long-term power purchase agreements with two suppliers
. Natural gas futures contracts
. Natural gas option contracts.
The long-term power purchase agreements give Cleco Power the right to
purchase up to a given amount of energy. Under one contract, Cleco Power can
purchase up to 200 MW in years one through five and 100 MW in year six, while
another contract allows Cleco Power to purchase up to 155 MW in year one,
increasing to 225 MW in year two, 255 MW in year three, and 310 MW for the
remainder of the four-and-a-half-year contract. The agreements set the purchase
price for power on market index prices agreed to by both parties. Because the
fair value of the power is based on these same market index prices, there is no
SFAS No. 133 impact when the contracts are valued at market.
Cleco Power has recorded in current income the changes in the fair value
(marked-to-market) of open natural gas futures and options positions, prior to
the implementation of SFAS No. 133. Cleco Power will not change this accounting
and will continue to record the changes in fair value of these derivative
instruments by marking them to market and recording any change in value in
income. At January 1, 2001, the mark-to-market of these open positions was a
loss of $407,000.
Midstream
As of January 1, 2001, Midstream had the following contractual obligations
that met the definition of a derivative-related transaction:
. Natural gas futures contracts
. Natural gas option contracts
. Natural gas swap contracts.
Energy engages in the wholesale marketing of natural gas and the
production, gathering and transmission of natural gas. Prior to the
implementation of SFAS No. 133, Energy employed hedge accounting
F-15
and did not reflect the fair value of its open contracts in its financial
statements. All physical and financial transactions were recorded in the
financial statements as the terms of each contract were fulfilled.
Financial contracts between Energy and outside parties hedge the price
volatility of other Energy contracts for forward purchases and sales of natural
gas. These financial contracts (futures, options and swaps) are derivatives
according to SFAS No. 133 guidelines, with prices based on selected market
indexes. The derivative transactions qualify as cash-flow hedges and, beginning
January 1, 2001, the fair value of these open positions will be reflected in the
financial statements in other comprehensive income, a component of equity. At
January 1, 2001, implementation of SFAS No. 133 by recording the fair value of
open cash-flow hedges at Energy would reduce equity by $4.5 million.
This charge to equity at Energy is due to the abnormal price volatility of
natural gas commodity prices at December 31, 2000. As the current open hedge
positions close, this equity charge will reverse by the beginning of the fourth
quarter of 2001.
Based on the above, implementation of SFAS No. 133, as amended, at Energy
shows a significant impact on Energy's balance sheet, but will not result in
increased volatility in earnings.
CMT engages in activities that are considered "trading" as defined by EITF
98-10. All of CMT's open positions are currently being marked-to-market under
the rules of EITF 98-10. As such, implementation of SFAS No. 133 will not have
an impact on the current accounting procedures or results of CMT.
- --------------------------------------------------------------------------------
Disclosure Regarding Forward-Looking Statements
This current report includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. All statements
other than statements of historical fact included in this report, including,
without limitation, certain statements under "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Results of
Operations - Earnings," "- Revenues and Sales - Cleco Power,""- Revenues and
Sales - Midstream," "- Fuel, Purchased Power and Purchases for Energy Marketing-
Cleco Power," "- Discontinued Operation," "- Financial Condition - Cash
Generation and Cash Requirements - Construction and Investment in Subsidiaries
Overview," "- Cleco Power Construction," "- Midstream Construction and
Investment in Subsidiaries," "- Industry Developments/Customer Choice," "-
Environmental Matters," and Notes D, O, Q, R and S of the Notes to the
Consolidated Financial Statements contain forward-looking statements. Located
elsewhere in this report are forward-looking statements regarding future
earnings, sales growth, revenue recognition from the Evangeline Tolling
Agreement, the effects of the outcome of litigation and other legal proceedings,
efforts to transfer generation facilities from Cleco Power to Midstream, the
timing of the sale of UtiliTech, capital expenditures, sources of funds for
capital expenditures, the timing of completion of the APP project and the PEP
project, the ultimate equity investment in APP and PEP, future legislative and
regulatory changes, the effect of certain recent FERC regulations, environmental
compliance costs, development of electric generating facilities, future minimum
operating lease rental payments and other matters. Although the Company believes
the expectations reflected in such forward-looking statements are reasonable,
such forward-looking statements are based on numerous assumptions (some of which
may prove to be incorrect) and are subject to risks and uncertainties, including
the weather and other natural phenomena, state and federal legislative and
regulatory initiatives, the timing and extent of changes in commodity prices and
interest rates, the operating performance of Cleco Power's and Midstream's
facilities, and the other risks and uncertainties more fully described in the
Company's latest Annual Report on Form 10-K and Quarterly Reports on Form 10-Q.
Actual results may differ materially from those indicated in such forward-
looking statements. Forward-looking statements are based on management's beliefs
as well as assumptions made by and information currently available to
management. When used in this current report, the words "anticipate,"
"estimate," "expect," "objective," "projection," "forecast," "goal" and similar
expressions are intended to identify forward-looking statements.
The Company undertakes no obligation to update or revise any forward-
looking statements, whether as a result of changes in actual results, changes in
assumptions or other factors affecting such statements.
F-16
Cleco Corporation
Consolidated Statements of Income
For the Year Ended December 31,
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
(Thousands, except share and per share amounts)
Operating revenue
Retail electric operations $ 619,528 $ 508,790 $ 487,280
Energy marketing and tolling operations 201,244 256,780 32,695
Other operations 476 1,641 -
- ---------------------------------------------------------------------------------------------------------------------
Gross operating revenue 821,248 767,211 519,975
Less retail electric customer credits 1,233 2,776 4,800
- ---------------------------------------------------------------------------------------------------------------------
Total operating revenue 820,015 764,435 515,175
Operating expenses
Fuel used for electric generation 183,309 145,229 142,737
Power purchased for utility customers 121,963 65,303 53,011
Purchases for energy marketing operations 148,242 244,384 27,322
Other operations 90,766 79,240 71,066
Maintenance 35,271 29,852 30,285
Depreciation 55,840 49,966 48,382
Taxes other than income taxes 37,429 36,045 35,420
- ---------------------------------------------------------------------------------------------------------------------
Total operating expenses 672,820 650,019 408,223
- ---------------------------------------------------------------------------------------------------------------------
Operating income 147,195 114,416 106,952
Interest income 6,628 1,697 372
Allowance for other funds used during construction - 654 812
Other income (expense), net (222) (1,328) (35)
- ---------------------------------------------------------------------------------------------------------------------
Income before interest charges 153,601 115,439 108,101
- ---------------------------------------------------------------------------------------------------------------------
Interest charges
Interest on debt and other, net of amount capitalized 48,721 28,412 27,016
Allowance for borrowed funds used during construction (580) (91) (904)
Amortization of debt discount, premium and expense, net 1,164 1,282 1,248
- ---------------------------------------------------------------------------------------------------------------------
Total interest charges 49,305 29,603 27,360
- ---------------------------------------------------------------------------------------------------------------------
Net income from continuing operations before income taxes
and preferred dividends 104,296 85,836 80,741
Federal and state income taxes 34,961 27,766 26,771
- ---------------------------------------------------------------------------------------------------------------------
Net income from continuing operations 69,335 58,070 53,970
- ---------------------------------------------------------------------------------------------------------------------
Discontinued operations
Loss from operations, net of income taxes (5,411) (1,304) (169)
Loss on disposal of segment, net of income taxes (1,450) - -
- ---------------------------------------------------------------------------------------------------------------------
Total discontinued operations (6,861) (1,304) (169)
- ---------------------------------------------------------------------------------------------------------------------
Net income before extraordinary item 62,474 56,766 53,801
Extraordinary item, net of income taxes 2,508 - -
- ---------------------------------------------------------------------------------------------------------------------
Net income before preferred dividends 64,982 56,766 53,801
Preferred dividend requirements, net 1,870 2,010 2,137
- ---------------------------------------------------------------------------------------------------------------------
Net income applicable to common stock $ 63,112 $ 54,756 $ 51,664
=====================================================================================================================
Average shares of common stock outstanding
Basic 22,473,859 22,501,324 22,480,163
Diluted 23,827,477 23,848,515 23,867,458
Basic earnings per share
From continuing operations $ 3.00 $ 2.49 $ 2.31
From discontinued operations $ (0.30) $ (0.06) $ (0.01)
Extraordinary item $ 0.11 - -
Net income applicable to common stock $ 2.81 $ 2.43 $ 2.30
Diluted earnings per share
From continuing operations $ 2.91 $ 2.42 $ 2.24
From discontinued operations $ (0.29) $ (0.05) -
Extraordinary item $ 0.10 - -
Net income applicable to common stock $ 2.72 $ 2.37 $ 2.24
Cash dividends paid per share of common stock $ 1.69 $ 1.65 $ 1.61
The accompanying notes are an integral part of the consolidated financial
statements.
F-17
Cleco Corporation
Consolidated Balance Sheets
At December 31,
2000 1999
- --------------------------------------------------------------------------------------
(Thousands)
Assets
Current assets
Cash and cash equivalents $ 29,407 $ 25,161
Accounts receivable (less allowance for doubtful
accounts of $1,883 in 2000 and $838 in 1999) 74,620 32,968
Other accounts receivable 24,200 14,245
Unbilled revenues 37,547 20,816
Fuel inventory, at average cost 7,275 10,461
Material and supplies inventory, at average cost 15,956 14,768
Margin deposits 21,657 498
Risk management assets 19,070 351
Accumulated deferred fuel 3,617 -
Other current assets 4,857 6,443
- --------------------------------------------------------------------------------------
Total current assets 238,206 125,711
Property, plant and equipment
Property, plant and equipment 1,799,161 1,579,304
Accumulated depreciation (604,145) (555,675)
- --------------------------------------------------------------------------------------
Net property, plant and equipment 1,195,016 1,023,629
Construction work-in-progress 37,742 187,988
- --------------------------------------------------------------------------------------
Total property, plant and equipment, net 1,232,758 1,211,617
Equity investment in investee 98,204 -
Other assets 2,642 4,225
Prepayments 16,766 6,427
Restricted cash 55,343 77,251
Regulatory assets - deferred taxes 100,267 115,918
Other deferred charges 45,010 37,862
Accumulated deferred federal and state income taxes 56,508 125,639
- --------------------------------------------------------------------------------------
Total Assets $1,845,704 $1,704,650
======================================================================================
The accompanying notes are an integral part of the consolidated
financial statements.
(Continued on next page)
F-18
Cleco Corporation
Consolidated Balance Sheets - Continued
At December 31,
2000 1999
- ------------------------------------------------------------------------------------------------------
(Thousands)
Liabilities and shareholders' equity
Current liabilities
Short-term debt $ 95,957 $ 25,989
Long-term debt due within one year 30,665 27,374
Accounts payable 102,838 74,700
Retainage 8,770 7,733
Customer deposits 20,436 20,326
Taxes accrued 17,286 4,786
Interest accrued 15,177 9,634
Accumulated deferred fuel - 2,638
Risk management liabilities 21,118 451
Other current liabilities 13,008 5,263
- ------------------------------------------------------------------------------------------------------
Total current liabilities 325,255 178,894
Deferred credits
Accumulated deferred federal and state income taxes 270,118 321,197
Accumulated deferred investment tax credits 24,252 25,994
Regulatory liabilities - deferred taxes 38,840 97,154
Other deferred credits 48,089 49,271
- ------------------------------------------------------------------------------------------------------
Total deferred credits 381,299 493,616
Long-term debt, net 659,135 579,595
- ------------------------------------------------------------------------------------------------------
Total Liabilities 1,365,689 1,252,105
Stockholders' equity
Preferred stock
Not subject to mandatory redemption 28,090 28,880
Deferred compensation related to preferred stock held by ESOP (12,994) (14,991)
- ------------------------------------------------------------------------------------------------------
Total preferred stock not subject to mandatory redemption 15,096 13,889
- ------------------------------------------------------------------------------------------------------
Common shareholders' equity
Common stock, $2 par value, authorized 50,000,000 shares,
issued 22,531,870 shares at December 31, 2000 and 1999 45,064 45,064
Premium on capital stock 112,502 112,733
Long-term debt payable in Company's common stock 519 1,036
Retained earnings 308,047 282,825
Treasury stock, at cost, 36,536 and 90,094 shares
at December 31, 2000 and 1999, respectively (1,213) (3,002)
- ------------------------------------------------------------------------------------------------------
Total common shareholders' equity 464,919 438,656
Total shareholders' equity 480,015 452,545
- ------------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity $1,845,704 $1,704,650
======================================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
F-19
Cleco Corporation
Consolidated Statements of Cash Flows
For the Year Ended December 31,
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------
(Thousands, except share and per share amounts)
Operating activities
Net income $ 64,982 $ 56,766 $ 53,801
Adjustments to reconcile net income to net cash provided
by operating activities
Loss from discontinued operations, net of tax 5,411 1,304 169
Loss on disposal of segment, net of tax 1,450 - -
Depreciation and amortization 56,958 51,153 50,650
Allowance for funds used during construction (580) (745) (1,716)
Amortization of investment tax credits (1,742) (1,790) (1,790)
Deferred income taxes 4,960 8,457 8,703
Deferred fuel costs (6,255) (1,975) 1,648
Extraordinary gain, net of tax (2,508) - -
Gain on sale of property, plant and equipment, net - (711) -
Changes in assets and liabilities, net of disposals
Accounts receivable, net (52,774) 1,908 (2,516)
Unbilled revenues (18,503) (12,078) 1,378
Fuel, material and supplies inventories 1,912 (2,830) 662
Accounts payable 28,490 21,118 4,423
Customer deposits 110 206 (52)
Taxes accrued 14,523 (7,948) (269)
Interest accrued 5,543 2,295 (341)
Margin deposits (21,159) (498) -
Risk management assets and liabilities, net 1,948 - -
Other, net (1,043) 114 (1,366)
- -----------------------------------------------------------------------------------------------------------------
Net cash from operating activities of continuing operations 81,723 114,746 113,384
- -----------------------------------------------------------------------------------------------------------------
Investing activities
Additions to property, plant and equipment (113,343) (179,226) (94,030)
Allowance for funds used during construction 580 745 1,716
Proceeds from sales of property, plant and equipment 291 1,194 408
Equity investment in investee (97,234) - -
Purchase of investments - (580) (480)
- -----------------------------------------------------------------------------------------------------------------
Net cash used in investing activities of continuing operations (209,706) (177,867) (92,386)
- -----------------------------------------------------------------------------------------------------------------
Financing activities
Issuance of common stock - 243 100
Repurchase of common stock - (3,833) -
Redemption of preferred stock - (6,518) (522)
Transfer of cash (into) from restricted accounts 21,908 (77,251) -
Issuance of long-term debt 110,332 269,352 -
Retirement of long-term debt (29,774) (30,639) (30,000)
Increase (decrease) in short-term debt, net 69,623 (43,383) 49,197
Dividends paid on common and preferred stock, net (39,860) (39,146) (38,331)
- -----------------------------------------------------------------------------------------------------------------
Net cash from (used in) financing activities of continuing operations 132,229 68,825 (19,556)
- -----------------------------------------------------------------------------------------------------------------
Net increase in cash and cash equivalents 4,246 5,704 1,442
Cash and cash equivalents at beginning of year 25,161 19,457 18,015
- -----------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 29,407 $ 25,161 $ 19,457
=================================================================================================================
Supplementary cash flow information
Interest paid (net of amount capitalized) $ 46,527 $ 30,819 $ 28,118
- -----------------------------------------------------------------------------------------------------------------
Income taxes paid $ 23,060 $ 24,614 $ 20,140
=================================================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
F-20
Cleco Corporation
Consolidated Statements of Changes
In Common Shareholders' Equity
Long-term
Debt
Payable in
Premium Company
Common Stock on Capital Common Retained Treasury Stock
------------ --------------
Shares Amount Stock Stock Earnings Shares Cost
- ---------------------------------------------------------------------------------------------------------------
(Thousands, except share and per share amounts)
BALANCE, JANUARY 1, 1998 22,762,754 $45,525 $113,763 $255,549 299,842 $ 6,086
Redemptions of preferred stock 10
Incentive stock options exercised 5,000 10 74
Issuance of treasury stock 24 (19,755) (401)
Incentive shares forfeited 1,987 54
Directors restricted stock award (144) (5)
Dividend requirements, preferred
stock, net (2,137)
Cash dividends paid, common stock,
$1.61 per share (36,194)
Net income 53,801
- ---------------------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 1998 22,767,754 45,535 113,871 271,019 281,930 5,734
- ---------------------------------------------------------------------------------------------------------------
Redemption of preferred stock 18
Repurchase of preferred stock (62)
Incentive stock options exercised 10,800 22 217
Issuance of treasury stock 5 (62,823) (1,545)
Treasury shares canceled (246,684) (493) (1,316) (3,256) (246,684) (5,020)
Treasury shares purchased 117,671 3,833
Dividend requirements, preferred
stock, net (2,010)
Adjustment for step-by-step
acquisition of subsidiary $1,036 (2,558)
Cash dividends paid, common stock,
$1.65 per share (37,136)
Net Income 56,766
- ---------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 22,531,870 45,064 112,733 1,036 282,825 90,094 3,002
- ---------------------------------------------------------------------------------------------------------------
Redemption of preferred stock (471)
Issuance of treasury stock 22 (39,949) (1,343)
Incentive shares forfeited 2,371 71
Incentive shares purchased 218
Dividend requirements, preferred
stock, net (1,870)
Payment in common stock (517) (15,980) (517)
Cash dividends paid, common stock,
$1.69 per share (37,890)
Net income 64,982
- ---------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000 22,531,870 $45,064 $112,502 $ 519 $308,047 36,536 $ 1,213
===============================================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
F-21
Cleco Corporation
Notes to Consolidated
Financial Statements
Note A - Reorganizations
Effective July 1, 1999, Cleco Utility Group Inc. (Utility Group)
reorganized into a holding company structure. This reorganization resulted in
the creation of a new holding company, Cleco Corporation (the Company), which
holds investments in several subsidiaries. There was no impact to the Company's
Consolidated Financial Statements because the reorganization was accounted for
similarly to a pooling of interests. Under the terms of the reorganization, the
Company became the owner of all of Utility Group's outstanding common stock, and
holders of then-existing common stock and two series of preferred stock
exchanged their stock in Utility Group for common stock in the Company. Shares
of preferred stock in three series that did not approve the reorganization were
redeemed for $5.7 million.
Effective December 31, 2000, Utility Group merged into Cleco Power LLC
(Cleco Power), a Louisiana limited liability company and wholly owned subsidiary
of the Company, which became the successor issuer to Utility Group. Immediately
prior to the merger, Cleco Power had only nominal assets or liabilities.
Pursuant to the merger, Cleco Power acquired all of the assets and assumed all
of the liabilities and obligations of Utility Group.
- --------------------------------------------------------------------------------
Note B - Summary of Significant Accounting Policies
GENERAL
The Company is an exempt holding company under the Public Utility Holding
Company Act of 1935. Its major, first-tier subsidiaries consist of Cleco Power,
Cleco Midstream Resources LLC (Midstream) and Utility Construction & Technology
Solutions LLC (UtiliTech).
Cleco Power provides electric generation, transmission, distribution and
customer care services to a diversified base of residential, commercial and
industrial customers in 23 parishes (counties) of Louisiana under the
jurisdiction of the Louisiana Public Service Commission (LPSC). Cleco Power also
operates energy marketing operations, which trade in the Cinergy and Into
Entergy power markets, and markets natural gas.
Midstream's operations consist of:
. developing wholesale generation projects,
. owning and operating Cleco Evangeline LLC (Evangeline), a 775 MW
wholesale electric generation station not regulated by the LPSC,
. providing personnel to operate power plants,
. operating an energy marketing and trading business, and
. owning and operating natural gas pipelines in Louisiana and Texas.
UtiliTech specializes in engineering and line construction contracting
services operating mainly in Louisiana, Texas, Mississippi and Arkansas. In
December 2000 management decided to dispose of substantially all of UtiliTech's
assets by sale in 2001. Interest was allocated to UtiliTech based upon the
amount of debt attributable to UtiliTech based upon working capital needs. The
amount of interest allocated to UtiliTech was $0.3 million in 2000, $0.1 million
in 1999 and zero in 1998. See Note R - "Discontinued Operations" for further
discussion.
The consolidated financial statements include the accounts of the
Company and all subsidiaries that the Company owns directly or indirectly
through a majority interest. Intercompany transactions and balances are
eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management 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.
RECLASSIFICATIONS
Certain reclassifications have been made to the 1998 and 1999 consolidated
financial statements to conform to the presentation used in the 2000
consolidated financial statements. These reclassifications had no effect on net
income applicable to common stock or total common shareholders' equity.
F-22
REGULATION
Cleco Power maintains its accounts in accordance with the Uniform System of
Accounts prescribed for electric utilities by the Federal Energy Regulatory
Commission (FERC), as adopted by the LPSC. Cleco Power's retail rates for
residential, commercial and industrial customers and other retail sales are
regulated by the LPSC, and its rates for transmission services and wholesale
power sales are regulated by the FERC. Cleco Power follows Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." This Statement allows utilities to capitalize or
defer certain costs based on regulatory approval and management's ongoing
assessment that it is probable these items will be recovered through the
ratemaking process. During 2000 the LPSC staff developed a transition to
competition plan that was presented to the LPSC. The staff's plan would allow
large industrial customers to have the opportunity to choose a power provider
starting in January 2003. The plan does not suggest a date for residential or
commercial customers. The LPSC is currently receiving comments and is reviewing
the plan. Any plan adopted by the LPSC may affect the regulatory assets and
liabilities recorded in Cleco Power under SFAS No. 71 if the criteria for the
application of SFAS No. 71 cannot continue to be met.
Pursuant to SFAS No. 71, Cleco Power has recorded regulatory assets and
liabilities, primarily for the effects of income taxes, as a result of past rate
actions of regulators. The effects of potential deregulation of the industry or
possible future changes in the method of rate regulation of Cleco Power could
require Cleco Power to discontinue the application of SFAS No. 71 in the future,
pursuant to SFAS No. 101, "Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71." At December 31, 2000,
Cleco Power had recorded $61.5 million of regulatory assets, net of regulatory
liabilities, because of the regulatory requirement to flow through the tax
benefits of accelerated deductions to current customers and an implied
regulatory compact that future customers would fund these amounts when Cleco
Power pays the additional taxes. These differences occur over the lives of
relatively long-lived assets, up to 30 years or more. Under the current
regulatory and competitive environment, Cleco Power believes these regulatory
assets will be fully recoverable. However, if in the future, as a result of
regulatory changes or increased competition, Cleco Power's ability to recover
these regulatory assets would not be probable, then to the extent that such
regulatory assets were determined not to be recoverable, Cleco Power would be
required to write-off or write-down such assets.
PROPERTY, PLANT AND EQUIPMENT
Electric utility plant consists of LPSC regulated generation assets
utilized for retail operations and electric transmission and distribution
properties. Electric utility plant is stated at the original cost of
construction, which includes certain materials, labor, payroll taxes and
benefits, administrative and general costs, and the estimated cost of funds used
during construction. The cost of repairs and minor replacements is charged as
incurred to the appropriate operating expense and clearing accounts. The cost of
improvements is capitalized. Upon retirement or disposition, the recorded cost
of depreciable plant and the cost of removal, net of salvage value, are charged
to accumulated depreciation.
The table below discloses the amounts of plant acquisition adjustments
reported in Cleco Power's property, plant and equipment and the associated
accumulated amortization reported in accumulated depreciation. The plant
acquisition adjustment primarily relates to the 1997 acquisition of Teche
Electric Cooperative, Inc.
At December 31,
2000 1999
- ---------------------------------------------------------
Cleco Power (Thousands)
Plant acquisition adjustment $5,379 $5,379
Less accumulated
amortization 951 698
- ---------------------------------------------------------
Total plant acquisition
adjustment $4,428 $4,681
=========================================================
The provision for depreciation is computed using the straight-line method
at rates that will amortize the unrecovered cost of depreciable property over
its estimated useful life. Annual depreciation provisions expressed as a
percentage of average depreciable property were 3.27% for 2000, 3.28% for 1999
and 3.32% for 1998.
Other property, plant and equipment primarily consists of the Evangeline
generation station, natural gas pipelines and work-in-progress on LPSC non-
jurisdictional projects. Other property, plant and equipment is stated the same
as utility plant, except that estimated cost of funds used during construction
is not included; instead, interest is capitalized during the construction
period.
F-23
Depreciation on other property, plant and equipment is calculated primarily
on a straight-line basis over the useful lives of the assets.
CASH EQUIVALENTS
The Company considers highly liquid, marketable securities and other
similar instruments with original maturity dates of three months or less at the
time of purchase to be cash equivalents.
RESTRICTED CASH
Restricted cash represents cash to be used for specific purposes. At
December 31, 2000, approximately $15.8 million in restricted cash represents
deposits into an escrow account for credit support as required by a provision of
the Evangeline Capacity Sale and Tolling Agreement (Evangeline Tolling
Agreement) between Evangeline and Williams Energy Marketing and Trading Company
(Williams). The credit support is to be maintained as security for the
performance of certain obligations by Evangeline in regard to the Evangeline
Tolling Agreement. Upon the fulfillment of certain conditions specified in the
agreement, the credit support can be reduced to $13 million. The remaining $39.5
million of restricted cash at December 31, 2000, consists of the remaining
proceeds from the sale of Evangeline senior secured bonds, an equity infusion
from Midstream, cash received from Williams pursuant to the Evangeline Tolling
Agreement, less cash distributed to Midstream. The construction of the project
is complete and the plant has begun commercial operation. However, the $55.3
million of restricted cash at December 31, 2000, remains restricted under the
bond indenture until certain of its provisions are met. As the provisions are
met, cash is transferred out of the escrow account and is available for general
corporate purposes.
INCOME TAXES
Deferred income taxes are provided at the current enacted income tax rate
on all temporary differences between tax and book bases of assets and
liabilities. The Company recognizes regulatory assets and liabilities incurred
within Cleco Power for the tax effect of temporary differences, which, to the
extent past ratemaking practices are continued by regulators, will be realized
over the accounting lives of the related properties. The Company files a federal
consolidated income tax return for all wholly owned subsidiaries.
INVESTMENT TAX CREDITS
Investment tax credits, which were deferred for financial statement
purposes, are amortized to income over the estimated service life of the
properties that gave rise to the credits.
DEBT EXPENSE, PREMIUM AND DISCOUNT
Expense, premium and discount applicable to debt securities are amortized
to income ratably over the lives of the related issues. Expense and call premium
related to refinanced Cleco Power debt are deferred and amortized over the
remaining life of the original issue.
REVENUES AND FUEL COSTS
Utility Revenues. Revenues from sales of electricity are recognized based
upon the amount of energy delivered. The cost of fuel and purchased power used
for retail customers is currently recovered from customers through fuel
adjustment clauses, based upon fuel costs incurred in prior months. These
adjustments are subject to audit and final determination by regulators.
Energy Marketing and Other Revenues. Revenues are recognized at the time
products or services are provided to and accepted by customers.
Tolling Revenues. The Company considers the Evangeline Tolling Agreement to
be an operating lease as defined by SFAS No. 13, "Accounting for Leases" and
SFAS No. 29, "Determining Contingent Rentals" because of William's ability to
control the use of the plant for the next 20 years. The Evangeline Tolling
Agreement contains a monthly shaping factor which provides for a greater portion
of annual revenue to be received by the Company during the summer months, which
is designed to coincide with the physical usage of the plant. SFAS No. 13
generally requires lessors to recognize revenue using a straight-line approach
unless another rational allocation of the revenue is more representative of the
pattern in which the leased property is employed. The Company believes that the
recognition of revenue pursuant to the monthly shaping factor for several
provisions contained within the Evangeline Tolling Agreement is a rational
allocation method, which better reflects the expected usage of the plant. Other
provisions are recognized as revenue using a straight-line approach. Certain
provisions of the Evangeline Tolling Agreement, such as bonuses and penalties,
are considered contingent as defined by SFAS No. 29. Contingent rents are
recorded as revenue or a reduction in revenue in the period in which the
contingency is met. See Note O - "Operating Lease" for more information.
F-24
ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION (AFUDC)
The capitalization of AFUDC by Cleco Power is a utility accounting practice
prescribed by the FERC and the LPSC. AFUDC represents the estimated cost of
financing construction and is not a current source of cash. Under regulatory
practices, a return on and recovery of AFUDC is permitted in setting rates
charged for utility services. The composite AFUDC rate, including borrowed and
other funds on a combined basis, for 2000 was 13.62% on a pretax basis (8.38%
net of tax), for 1999 was 13.75% on a pretax basis (8.46% net of tax), and for
1998 was 13.49% on a pretax basis (8.30% net of tax).
CAPITALIZED INTEREST
The Company and its subsidiaries, except Cleco Power, capitalize interest
costs for construction in accordance with SFAS No. 34, "Capitalization of
Interest Cost." SFAS No. 34 states interest should be capitalized on assets,
other than inventory, that require a period of time to construct and when
interest costs are incurred by the enterprise constructing the asset. During the
year ending December 31, 2000, the Company capitalized approximately $7.8
million in interest costs compared to approximately $5.3 million during the year
ending December 31, 1999.
The Company and its subsidiaries capitalize interest costs for investments
accounted for by the equity method, while the investee has activities in
progress necessary to commence its planned operations, in accordance with SFAS
No. 58, "Capitalization of Interest Cost in Financial Statements That Include
Investments Accounted for by the Equity Method." See Note N - "Equity Investment
in Investee" for more information.
RISK MANAGEMENT
The market risk inherent in the Company's market risk-sensitive instruments
and positions is the potential change arising from increases or decreases in the
short-, medium- and long-term interest rates, the commodity price of electricity
traded on the Into Entergy and the Cinergy markets and the commodity price of
natural gas traded. Generally, Cleco Power's market risk-sensitive instruments
and positions are characterized as "other than trading;" however, Cleco Power
does have positions that are considered "trading" as defined by Emerging Issues
Task Force (EITF) Consensus No. 98-10 (EITF 98-10). All of the positions held by
Cleco Marketing & Trading LLC (CMT), a subsidiary of Midstream, are
characterized as "trading" under EITF 98-10. Positions that are considered
"trading" under EITF 98-10 are marked-to-market at the end of reporting periods.
The mark-to-market gains or losses are reflected in the income statement in the
energy marketing and tolling revenue line item. The off-setting unrealized gain
or loss is recorded on the balance sheet in risk management assets and
liabilities. Positions that are considered "other than trading" under EITF 98-10
are accounted for under SFAS No. 80, "Accounting for Futures Contracts." Under
SFAS No. 80, income or loss in such positions is deferred until the underlying
transactions have been realized.
RECENT ACCOUNTING STANDARDS
In 1998 the Financial Accounting Standards Board (FASB) issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No.
133 established accounting and reporting standards requiring that every
derivative instrument (including certain derivatives embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. This statement requires that changes in the
derivative's fair value be recognized in current earnings, unless effective
accounting criteria tests are met, where changes in the fair value of the
derivative would be recorded in other comprehensive income in the equity section
of the balance sheet.
In June 1999 the FASB issued SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133," which deferred the effective date of SFAS No. 133 to fiscal
years beginning after June 15, 2000. In June 2000 the FASB issued SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities,"
which amended certain normal purchase and sales guidance within SFAS No. 133.
In early 2000 the Company organized a cross-functional project team for
implementing SFAS No. 133, as amended. The team completed an inventory of the
Company's financial and commodity contracts and other commitments, and assessed
the Company's derivative-related transactions identified in this inventory. This
assessment determined that Cleco Power and subsidiaries of Midstream were
impacted by this standard.
F-25
Cleco Power has recorded in current income the changes in the fair value
(marked-to-market) of open natural gas futures and options positions, prior to
the implementation of SFAS No. 133. Cleco Power will not change this accounting
and will continue to record the changes in fair value of these derivative
instruments by marking them to market and recording any change in value in
income. At January 1, 2001, the mark-to-market of these open positions was a
loss of $407,000.
Financial contracts between Cleco Energy LLC (Energy) and outside parties
hedge the price volatility of other Energy contracts for forward purchases and
sales of natural gas. These financial contracts (futures, options and swaps) are
derivatives according to SFAS No. 133 guidelines, with prices based on selected
market indices. The derivative transactions qualify as cash-flow hedges and,
beginning January 1, 2001, the fair value of these open positions will be
reflected in the financial statements in other comprehensive income, a component
of equity. At January 1, 2001, implementation of SFAS No. 133 by recording the
fair value of open cash-flow hedges at Energy would reduce equity by $4.5
million.
CMT engages in activities that are considered "trading" as defined by EITF
98-10. All of CMT's open positions are currently being marked-to-market under
the rules of EITF 98-10. As such, implementation of SFAS No. 133 will not have
an impact on the current accounting procedures or results of CMT.
EARNINGS PER AVERAGE COMMON SHARE
Earnings per average common share (EPS) is computed using the weighted
average number of shares of common stock outstanding during the year. EPS is
reported for the years 2000, 1999 and 1998 to reflect the Company's adoption of
SFAS No. 128, "Earnings per Share." The following table is a reconciliation of
the components in the calculation of basic and diluted earnings per share.
For the years ended December 31, 2000 and 1998, the incentive stock
options outstanding were dilutive and included in the calculation of diluted
EPS.
For the year ended December 31,
2000 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------------
Income Shares Per Share Income Shares Per Share Income Shares Per Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
------------------------------------------------------------------------------------------------------------------
(Thousands, except per share amounts)
Net income
from continuing
operations $ 69,335 $ 58,070 $ 53,970
Less: preferred
dividend
requirements, net 1,870 2,010 2,137
- ------------------------------------------------------------------------------------------------------------------------------------
Basic EPS
Income from
continuing
operations
available for
common
shareholders $ 67,465 22,474 $3.00 $ 56,060 22,501 $2.49 $ 51,833 22,480 $2.31
- ------------------------------------------------------------------------------------------------------------------------------------
Effect of Dilutive
Securities
Stock option grants 40 7
Convertible ESOP
preferred stock 1,830 1,313 1,723 1,347 1,707 1,380
- ------------------------------------------------------------------------------------------------------------------------------------
Diluted EPS
Income from
continuing
operations
available to
common
shareholders plus
assumed
conversions $ 69,295 23,827 $2.91 $ 57,783 23,848 $2.42 $ 53,540 23,867 $2.24
====================================================================================================================================
F-26
Note C - Jointly Owned Generating Units
Two electric generating units operated by Cleco Power are jointly owned
with other utilities. The Company's proportionate share of operation and
maintenance expenses associated with these two units is reflected in the
financial statements.
At December 31, 2000
Rodemacher Dolet Hills
Unit #2 Unit #1
- ---------------------------------------------------------------------------------
(Dollar amounts in thousands)
Ownership 30% 50%
Utility plant in service $85,536 $275,388
Accumulated depreciation $47,200 $119,456
Unit capability (megawatts) 523.0 650.0
Share of capability (megawatts) 156.9 325.0
=================================================================================
Note D - Fair Value of Financial Instruments
The amounts reflected in the Consolidated Balance Sheets at December 31,
2000 and 1999, for cash and cash equivalents, accounts receivable, accounts
payable and short-term debt approximate fair value because of their short-term
nature. The fair value of the Company's long-term debt and nonconvertible
preferred stock is estimated based upon the quoted market price for the same or
similar issues or by a discounted present value analysis of future cash flows
using current rates obtainable by the Company for debt and preferred stock with
similar maturities. The fair value of convertible preferred stock is estimated
assuming its conversion into common stock at the market price per common share
at December 31, 2000 and 1999, with proceeds from the sale of the common stock
used to repay the principal balance of the Company's loan to the Employee Stock
Ownership Plan (ESOP). The estimated fair value of energy market positions is
based upon observed market prices when available, and when such market prices
are not available, management estimates market value at a discrete point in time
based on market conditions and observed volatility. These estimates are
subjective in nature and involve uncertainties. Therefore, actual results may
differ from these estimates.
At December 31,
2000 1999
- ----------------------------------------------------------------------------------------------------
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
--------------------------------------------------
(Thousands)
Financial instruments not marked-to-market
Long-term debt $690,622 $718,610 $615,007 $608,838
Preferred stock
Not subject to mandatory redemption $ 15,096 $ 56,867 $ 13,889 $ 26,036
Original Estimated Original Estimated
Value Fair Value Value Fair Value
--------------------------------------------------
Financial instruments not marked-to-market
Energy Market Positions
Assets $ 39,205 $ 39,901 $ 10,097 $ 8,832
Liabilities $ 77,523 $ 78,668 $ 7,470 $ 6,760
The financial instruments not marked-to-market are reported on the
Company's consolidated balance sheets at carrying value. The financial
instruments marked-to-market represent off-balance-sheet risk because, to the
extent the Company has an open position, it is exposed to the risk that
fluctuating market prices may adversely impact its financial condition or
results of operations upon settlement. Original value represents the fair value
of the positions at the time originated.
F-27
Note E - Debt
The Company and its subsidiaries have four separate revolving credit
facilities totaling $310 million. Compensating balances are not required for any
of the facilities.
The Company has two credit facilities totaling $200 million. The first
facility is a $120 million facility which provides for borrowings at interest
rates based on either competitive bid, prime rate, or the London Interbank
Offered Rate and will expire on June 14, 2001. The commitment fees for this
facility are based upon the Company's lowest secured debt ratings and are
currently 0.125%. The second facility is an $80 million, three-year facility
that provides for borrowings at interest rates established by competitive bid
and will expire on August 25, 2002. The commitment fees for this facility are
based upon the Company's lowest secured debt ratings and are currently 0.15%.
Both facilities provide support for the issuance of commercial paper. At
December 31, 2000, and December 31, 1999, there was approximately $54.2 million
and zero, respectively, in commercial paper outstanding under the facilities.
Guaranties issued by the Company to third parties for certain types of
transactions between those parties and the Company's subsidiaries, other than
Cleco Power, will reduce the amount of the facilities available to the Company
by an amount equal to the stated or determinable amount of the primary
obligation. In addition, certain indebtedness incurred by the Company outside of
the facilities will reduce the amount of the facilities available to the
Company. The amount of guaranties provided by the Company and other indebtedness
reducing the amount of the facilities available to be utilized was $60.9 million
at December 31, 2000, and $18.2 million at December 31, 1999.
Cleco Power has one credit facility for $100 million. This facility
provides for uncollateralized borrowings at prevailing interest rates and is
scheduled to expire on June 14, 2001. The facility provides support for the
issuance of commercial paper. At December 31, 2000, and December 31, 1999, there
was approximately $41.4 million and $6.0 million, respectively, in commercial
paper outstanding under the facility. Interest rates are established by
competitive bid. Commitment fees are based upon Cleco Power's lowest secured
debt rating and are currently 0.10%.
Energy has one credit facility for $10 million. This facility provides
for borrowings at prevailing interest rates and will expire on June 30, 2005. At
December 31, 2000, there was approximately $9.7 million outstanding under the
facility. This facility did not exist at December 31, 1999. Commitment fees for
the facility are based on a percentage of the unused line of credit. The
facility is collateralized by the assets of Energy, and is supported by a $10
million guarantee from the Company.
Total indebtedness as of December 31, 2000 and 1999 was as follows:
F-28
At December 31,
2000 1999
- ----------------------------------------------------------------------------------------------------------
(Thousands)
Commercial paper, net $ 95,617 $ 5,989
Short-term bank loans 340 20,000
- ----------------------------------------------------------------------------------------------------------
Total short-term debt $ 95,957 $ 25,989
==========================================================================================================
First mortgage bonds
Series X, 91 1/42%, due 2005 $ 60,000 $ 60,000
Pollution control revenue bonds, fixed rate of 5.875%,
due 2029, callable after September 1, 2009 61,260 61,260
Long-term bank loans 9,741 9,106
Medium-term notes
7.85%, due 2000 - 25,000
7.55%, due 2004, callable at 100%, 2002 15,000 15,000
7.50%, due 2004, callable at 100%, 2002 10,000 10,000
7.00%, due 2003 10,000 10,000
6.55%, due 2003 15,000 15,000
6.33%, due 2002 25,000 25,000
6.78%, due 2001 10,000 10,000
6.20%, due 2006 15,000 15,000
6.42%, due 2001 15,000 15,000
6.95%, due 2006 10,000 10,000
6.53%, due 2007 10,000 10,000
6.32%, due 2006 15,000 15,000
7.50%, due 2007 15,000 15,000
7.00%, due 2007 25,000 25,000
6.52%, due 2009 50,000 50,000
- ----------------------------------------------------------------------------------------------------------
Total medium-term notes 240,000 265,000
Senior secured bonds, 8.82%, due 2019 218,600 218,600
Senior notes, 8.75%, due 2005 100,000 -
Other long-term debt 1,061 -
- ----------------------------------------------------------------------------------------------------------
Gross amount of long-term debt 690,662 613,966
Less:
Amount due within one year (30,665) (27,374)
Amount classified as assets available for sale - (6,076)
Unamortized premium and discount, net (862) (921)
- ----------------------------------------------------------------------------------------------------------
Total long-term debt, net $659,135 $579,595
==========================================================================================================
2001 2002 2003 2004 2005 Thereafter
- -------------------------------------------------------------------------------------------------------------
(Thousands)
Amounts payable under long-term debt agreements $30,665 $32,510 $32,875 $31,585 $169,920 $393,107
=============================================================================================================
The weighted average interest rate on short-term debt at December 31, 2000,
was 7.7% compared to 6.8% at December 31, 1999.
The first mortgage bonds are collateralized by the LPSC jurisdictional
property, plant and equipment within Cleco Power. In the various parishes that
contain such property, a lien is filed with the clerk of court. Before Cleco
Power can sell any of this property, it must get a release signed by the
trustee.
The senior secured bonds are collateralized with the Evangeline generating
station assets held by Evangeline.
Medium-term notes and the pollution control revenue bonds are not
collateralized.
On May 25, 2000, the Company sold $100 million aggregate principal amount
of its five-year senior notes. These notes bear interest at 8.75% per year,
mature on June 1, 2005, and are uncollateralized. Approximately $50 million of
the proceeds from the sale of the notes was used to pay down commercial paper
financing, and the remainder was used to invest in joint ventures.
F-29
Note F - Common Stock
Under the terms of the incentive compensation plans in effect during the
three-year period ended December 31, 2000, certain officers and key employees of
the Company and its subsidiaries were awarded shares of restricted Company
common stock. The cost of the restricted stock awards, as measured by the market
value of the common stock at the time of the grant, is recorded as compensation
expense during the periods in which the restrictions lapse. As of December 31,
2000, the number of shares of restricted stock previously granted for which
restrictions had not lapsed totaled 138,118 shares.
The Company makes no charge to expense with respect to the granting of
options at fair market value or above to employees or directors. Options may be
granted to certain officers, key employees or directors of the Company or its
subsidiaries. During 2000, the Company granted two types of non-qualified stock
options under the incentive compensation plan - basic and premium options. Basic
options have an exercise price approximately equal to the fair market value of
the stock at grant date. Premium options have three exercise prices that are
above the fair market value of the stock at grant date. Both types of options
granted in 2000 vest one-third each year beginning on the third anniversary of
the grant date. Both types of options granted in 2000 expire after ten years. In
accordance with Accounting Principles Board (APB) Opinion No. 25, "Accounting
for Stock Issued to Employees," the Company has not recognized any compensation
expense for stock options granted.
Changes in incentive shares for the three-year period ended December 31,
2000, were as follows:
Incentive Share
- -------------------------------------------------------------------------------------------------
Option Price Unexercised Available for
per Share Option Shares Future Grants
- -------------------------------------------------------------------------------------------------
Balance, January 1, 1998 15,800 708,039
Options exercised $ 16.780 (5,000)
Options granted (directors) $ 31.875 12,503 (12,503)
Restricted stock granted (21,362)
Restricted stock forfeited 2,543
- -------------------------------------------------------------------------------------------------
Balance, December 31, 1998 23,303 676,717
Options exercised $ 16.780 (10,800)
Options granted (directors) $ 31.875 7,778 (7,778)
Options granted - basic (employees) $ 32.250 166,300 (166,300)
Options granted - premium (employees) $ 38.41 to 371,400 (371,400)
$ 43.16
Restricted stock granted (50,074)
Restricted stock forfeited 552
- -------------------------------------------------------------------------------------------------
Balance, December 31, 1999 557,981 81,717
Approval of 2000 LTIP 800,000
Options forfeited $ 32.25 (4,800) 4,800
Options forfeited $ 38.41 to (15,000) 15,000
$ 43.16
Options granted (directors) $ 34.63 10,000 (10,000)
Options granted - basic (employees) $ 34.63 4,000 (4,000)
Options granted - premium (employees) $ 41.24 to 27,000 (27,000)
$ 46.34
Options granted - basic (employees) $ 36.88 18,900 (18,900)
Options granted - premium (employees) $ 43.92 to 27,000 (27,000)
$ 49.35
Restricted stock granted (71,426)
Restricted stock forfeited 1,669
- -------------------------------------------------------------------------------------------------
Balance, December 31, 2000 625,081 744,860
=================================================================================================
F-30
Had the compensation cost for the Company's stock-based compensation plans
been determined consistent with SFAS No. 123, "Accounting for Stock-Based
Compensation," the Company's net income and net income per common share would
approximate the pro forma amounts below:
For the year ended December 31,
2000 1999 1998
- ------------------------------------------------------------------------------------------
As Pro As Pro As Pro
Reported Forma Reported Forma Reported Forma
----------------------------------------------------------
(Thousands except per share amounts)
SFAS No. 123 expense $ - $ 311 $ - $ 1,036 $ - $ 525
Estimated reduction in income
tax for SFAS No. 123 expense - (103) - (342) - (173)
- ------------------------------------------------------------------------------------------
Net income applicable to
common stock $63,112 $62,904 $54,756 $54,062 $51,664 $51,312
==========================================================================================
Net income per basic
common share $ 2.81 $ 2.80 $ 2.43 $ 2.40 $ 2.30 $ 2.28
==========================================================================================
The assumptions used to calculate the additional compensation expense are
as follows:
For the year ended December 31,
2000 1999 1998
- ----------------------------------------------------------------
Expected term (in years) 5.26 6.31 5.00
Volatility 14.22% 12.94% 12.29%
Expected dividend yield 4.75% 5.11% 5.05%
Risk-free interest rate 6.32% 5.94% 5.79%
Weighted average fair value
(Black Scholes value) $ 3.01 $ 2.15 $ 3.13
The effects of applying SFAS No. 123 in this pro forma disclosure are not
necessarily indicative of future amounts. SFAS No. 123 does not apply to awards
prior to 1995, and the Company anticipates making awards in the future under its
stock-based compensation plans.
The following table summarizes information about employee and director
stock options outstanding at December 31, 2000:
Options Outstanding
Number Weighted Average Weighted Average
Range of Number Exercisable at Exercise Remaining
Exercise Price Outstanding 12/31/2000 Price Contractual Life
- ------------------------------------------------------------------------------------
$31.875 20,281 20,281 $31.875 7.68
$32.25 161,500 - $32.25 8.50
$38.41 to $43.16 356,400 - $40.76 8.50
$34.63 14,000 - $34.63 9.29
$41.24 to $46.34 27,000 - $43.77 9.29
$36.88 18,900 - $36.88 9.54
$43.92 to $49.35 27,000 - $46.61 9.54
Various of the Company's debt agreements contain covenants that restrict
the amount of retained earnings that may be distributed as dividends to common
shareholders. The most restrictive covenant requires that common shareholders'
equity be not less than 30% of total capitalization, including short-term debt.
At December 31, 2000, approximately $85.1 million of retained earnings was not
restricted.
On July 28, 2000, the Company's board of directors adopted the Shareholder
Rights Plan (Rights Plan). Under the Rights Plan, the holders of common stock as
of August 14, 2000, received a dividend of one right for each share of common
stock held on that date. In the event an acquiring party accumulates 15% or more
of the Company's common stock, the rights would, in essence, allow the holder to
purchase the company's common stock at half the current fair market value. The
Company generally would be entitled to redeem the rights at $0.01 per right at
any time until the tenth day following the time the rights become exercisable.
The rights expire on July 30, 2010.
On January 28, 2000, the Company's board of directors adopted a Cleco
Corporation Employee Stock Purchase Plan (ESPP), subject to shareholder
approval, which was granted on April 28, 2000. The ESPP provides the opportunity
for employees to purchase shares of the Company's common stock at a discounted
price. The Company implemented the ESPP effective October 1, 2000.
Regular, full-time and part-time employees of the Company and its
participating affiliates, except officers
F-31
and general managers and employees who own 5% or more of the Company's stock,
may participate in the ESPP. An eligible employee enters into an option
agreement to become a participant in the ESPP. Under the agreement, the employee
authorizes payroll deductions in an amount not less than $10 but not more than
$350 each pay period. Payroll deductions are accumulated during a calendar
quarter and applied to the purchase of common stock at the end of each quarter,
which is referred to as an "offering period." Pending the purchase of common
stock, payroll deductions remain as general assets of the Company. No trust or
other fiduciary account will be established in connection with the ESPP. At the
end of each offering period, payroll deductions are automatically applied to the
purchase of shares of common stock. The number of shares of common stock
purchased is determined by dividing each participant's payroll deductions during
the offering period by the option price of a share of common stock. The "option
price" is equal to the lesser of:
. 85% of the closing sales price of common stock on the first day of
the offering period (or if no sales occurred on that day, the
immediately preceding day on which common stock was traded); or
. 85% of the closing sales price of common stock on the last day of the
period (or if no sales occurred on that day, the immediately
preceding day on which common stock was traded).
A maximum number of 322,000 shares of common stock may be purchased
under the ESPP, subject to adjustment for changes in the capitalization of the
Company. The Compensation Committee of the Company's board of directors
administers the ESPP. The Compensation Committee and the board of directors each
possess the authority to amend the ESPP, but shareholder approval is required
for any amendment that increases the number of shares subject to the ESPP.
- --------------------------------------------------------------------------------
Note G - Extraordinary Gain
In March 2000 Four Square Gas, a wholly owned subsidiary of Energy, which
is wholly owned by Midstream, paid a third party $2.1 million for a note with a
face value of approximately $6 million issued by Four Square Production, another
wholly owned subsidiary of Energy. The note relates to the production assets
held by Four Square Production which were previously classified as assets
available for sale, described in Note H - "Assets Held for Sale," below. As part
of the transaction, the third-party debtholder sold the note, associated
mortgage, deed of trust and pledge agreement and assigned a 5% overriding
royalty interest in the production assets to Four Square Gas. Four Square Gas
paid, in addition to the $2.1 million, a total of 4.5% in overriding royalty
interest in the production assets. Four Square Gas borrowed the $2.1 million
from the Company. The gain of approximately $3.9 million was offset against the
$1.4 million of income tax related to the gain to arrive at the extraordinary
gain, net of income tax, of approximately $2.5 million.
- --------------------------------------------------------------------------------
Note H - Assets Held for Sale
Oil and gas properties held by Energy, were identified as "Assets Held for
Sale" and were accounted for in accordance with the provisions of EITF Consensus
No. 87-11, "Allocation of Purchase Price to Assets to Be Sold." Oil and gas
properties held for sale are reflected net of working capital and debt
specifically identified with the purchase of the oil and gas properties. These
properties are periodically reviewed to determine if they have been impaired. In
accordance with EITF No. 87-11, a net loss relative to the operations of these
assets of approximately $0.3 million has been excluded from the Consolidated
Statements of Income and capitalized as a component of assets held for sale for
the seven-month period ended July 31, 1999. The components of the assets
available for sale consist of assets with a book value of approximately $8.9
million offset by capitalized losses of $0.3 million and long-term debt of
approximately $6.1 million, for a net of $2.5 million, which is reported in
other current assets. A net loss of approximately $0.2 million has been included
in the Consolidated Statements of Income for the five-month period ended
December 31, 1999. As of September 30, 2000, the Company has discontinued
actively searching for a buyer for these assets, resulting in the
reclassification of the book value of the assets to property, plant and
equipment. Long-term debt of approximately $6.0 million relating to the
acquisition of the oil and gas properties was purchased by an affiliate as
described in Note G - "Extraordinary Gain," above.
F-32
Note I - Preferred Stock
In connection with the establishment of the ESOP, Utility Group, the
predecessor of Cleco Power, sold 300,000 shares of 8.125% convertible preferred
stock to the ESOP. As part of the holding company reorganization, each share of
Utility Group 8.125% convertible preferred stock was exchanged for one share of
Company 8.125% convertible preferred stock. Each share of Company 8.125%
preferred stock is convertible into 4.8 shares of Company common stock. The
amount of total capitalization reflected in the consolidated financial
statements has been reduced by an amount of deferred compensation expense
related to the shares of convertible preferred stock which have not yet been
allocated to ESOP participants. The amount shown in the consolidated financial
statements for preferred dividend requirements in 2000, 1999 and 1998 has been
reduced by $391,000, $435,000 and $521,000, respectively, to reflect the benefit
of the income tax deduction for dividend requirements on unallocated shares held
by the ESOP.
Upon involuntary liquidation, preferred shareholders are entitled to
receive par value for shares held before any distribution is made to common
shareholders. Upon voluntary liquidation, preferred shareholders are entitled to
receive the redemption price per share applicable at the time such liquidation
occurs, plus any accrued dividends.
Information about the components of preferred stock capitalization is as
follows:
Balance Balance Balance Balance
Jan. 1, Dec. 31, Dec. 31, Dec. 31,
1998 Change 1998 Change 1999 Change 2000
- -----------------------------------------------------------------------------------------------------------------
(Thousands, except share amounts)
CUMULATIVE PREFERRED STOCK,
$100 par value
NOT SUBJECT TO MANDATORY
REDEMPTION
4.50% $ 1,029 $ 1,029 $ 1,029 $ 1,029
Convertible, Series of 1991,
8.125%, ESOP 29,073 $ (384) 28,689 $ (838) 27,851 $ (790) 27,061
- -----------------------------------------------------------------------------------------------------------------
$ 30,102 $ (384) $ 29,718 $ (838) $ 28,880 $ (790) $ 28,090
=================================================================================================================
SUBJECT TO MANDATORY
REDEMPTION
4.50%, Series of 1955 $ 320 $ (40) $ 280 $ (280) - - -
4.65%, Series of 1964 2,940 (140) 2,800 (2,800) - - -
4.75%, Series of 1965 2,860 (260) 2,600 (2,600) - - -
- -----------------------------------------------------------------------------------------------------------------
$ 6,120 $ (440) $ 5,680 $(5,680)
=================================================================================================================
Deferred compensation related to
convertible preferred stock held
by the ESOP $ (18,766) $1,843 $(16,923) $ 1,932 $(14,991) $1,997 $(12,994)
=================================================================================================================
CUMULATIVE PREFERRED STOCK,
$100 par value
Number of shares
Authorized 1,410,000 (4,000) 1,406,000 (54,000) 1,352,000 1,352,000
Issued and outstanding 362,218 (8,240) 353,978 (65,174) 288,804 (7,904) 280,900
=================================================================================================================
CUMULATIVE PREFERRED STOCK,
$25 par value
Number of shares authorized
(None outstanding) 3,000,000 3,000,000 3,000,000 3,000,000
=================================================================================================================
Preferred stock, other than the convertible preferred stock held by the
ESOP, is redeemable at the Company's option, subject to 30 days' prior written
notice to holders. The convertible preferred stock is redeemable at any time at
the Company's option. If the Company were to elect to redeem the convertible
preferred stock, shareholders may elect to receive the optional redemption price
or convert the preferred stock into common stock. The redemption provisions for
the various series of preferred stock are shown in the following table.
Optional Redemption
- ----------------------------------------------------
Price per Share
--------------------
Series
4.50% $101
Convertible, Series of 1991 $100.8125 to $100
F-33
Note J - Pension Plan and Employee Benefits
Substantially all employees are covered by a noncontributory, defined
benefit pension plan. Benefits under the plan reflect an employee's years of
service, age at retirement and highest total average compensation for any
consecutive five calendar years during the last ten years of employment with the
Company. The Company's policy is to fund contributions to the employee pension
plan based upon actuarial computations utilizing the projected unit credit
method, subject to the Internal Revenue Service's full funding limitation. No
contributions to the pension plan were required during the three-year period
ended December 31, 2000. Cleco Power is considered the plan sponsor and Cleco
Support Group LLC is considered the plan administrator.
The Company's retirees and their dependents are eligible to receive health,
dental and life insurance benefits (Other Benefits). The Company recognizes the
expected cost of these benefits during the periods in which the benefits are
earned.
The employee pension plan and other benefits obligation plan assets and
funded status as determined by the actuary at December 31, 2000 and 1999, are
presented in the following table.
Pension Benefits Other Benefits
2000 1999 2000 1999
- ------------------------------------------------------------------------------------------------------------
(Thousands)
Change in benefit obligation
Benefit obligation at beginning of year $129,970 $132,721 $ 16,194 $ 16,602
Service cost 3,825 4,353 848 661
Interest cost 9,706 9,198 1,321 1,099
Plan participants' contributions - - 454 338
Actuarial (gain)/loss (6,076) (8,728) 362 (1,624)
Expenses paid (1,212) (1,254) - -
Benefits paid (6,602) (6,320) (966) (882)
- ------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year 129,611 129,970 18,213 16,194
- ------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year 184,613 181,698 - -
Actual return on plan assets 18,035 10,489 - -
Expenses paid (6,602) (1,254) - -
Benefits paid (1,212) (6,320) - -
- ------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 194,834 184,613 - -
- ------------------------------------------------------------------------------------------------------------
Funded status 65,223 54,643 (18,213) (16,194)
Unrecognized net actuarial (gain) (60,375) (53,369) (2,646) (3,058)
Unrecognized transition obligation/(asset) (3,990) (5,308) 6,160 6,673
Prior service cost 11,806 12,775 - -
- ------------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 12,664 $ 8,741 $(14,699) $(12,579)
============================================================================================================
F-34
Employee pension plan assets are invested in the Company's common stock,
other publicly traded domestic common stocks, U.S. government, federal agency
and corporate obligations, an international equity fund, commercial real estate
funds and pooled temporary investments.
The components of net periodic pension and other benefits cost (income) for
2000, 1999 and 1998 are as follows, along with assumptions used:
Pension Benefits Other Benefits
2000 1999 1998 2000 1999 1998
- ---------------------------------------------------------------------------------------------------
(Thousands)
Components of periodic benefit costs
Service cost $ 3,825 $ 4,353 $ 3,734 $ 848 $ 661 $ 671
Interest cost 9,706 9,198 8,326 1,321 1,099 1,062
Expected return on plan assets (15,912) (14,267) (12,797) - - -
Amortization of transition
obligation (asset) (1,318) (1,317) (1,318) 513 513 513
Prior period service cost
amortization 969 969 969 - - -
Net (gain) loss (1,194) - (142) 5 - (66)
- ---------------------------------------------------------------------------------------------------
Net periodic benefit cost/(income) $ (3,924) $ (1,064) $ (1,228) $2,687 $2,273 $2,180
- ---------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
2000 1999 1998 2000 1999 1998
- ---------------------------------------------------------------------------------------------------
Weighted-average assumptions as of
December 31:
Discount rate 8.00% 7.50% 6.75% 8.00% 7.50% 6.75%
Expected return on plan assets 9.50% 9.50% 9.50% N/A N/A N/A
Rate of compensation increase 5.00% 5.00% 5.00% N/A N/A N/A
The assumed health care cost trend rate used to measure the expected cost
of other benefits was 8.0% in 2000, 8.5% in 1999 and 9.5% in 1998, declining to
5.5% by 2009 and remaining at 5.5% thereafter. The initial health care cost
trend rate was reduced from 10% in 1996 to 9.5% in 1998 to 8.5% in 1999 and to
8.0% in 2000, which resulted in an unrecognized gain. Assumed health care cost
trend rates have a significant effect on the amount reported for the health care
plans. A one-percentage point change in assumed health care cost trend rates
would have the following effects on other benefits:
1-percentage point
Increase Decrease
- ---------------------------------------------------------
(Thousands)
Effect on total of service and
interest cost components $147 $(149)
Effect on post-retirement
benefit obligation $953 $(988)
Substantially all employees are eligible to participate in a savings and
investment plan (401(k) Plan). The Company makes matching contributions to
401(k) Plan participants by allocating shares of convertible preferred stock
held by the ESOP. Compensation expense related to the 401(k) Plan is based upon
the value of shares of preferred stock allocated to ESOP participants and the
amount of interest incurred by the ESOP, less dividends on unallocated shares
held by the ESOP. At December 31, 2000 and 1999, the ESOP had allocated to
employees 152,189 and 139,086 shares, respectively.
The table below contains information about the 401(k) Plan and the ESOP:
For the year ended December 31,
2000 1999 1998
- ----------------------------------------------------------------
(Thousands)
401(k) Plan expense $1,061 $1,108 $1,107
Dividend requirements to
ESOP on convertible
preferred stock $2,231 $2,283 $2,341
Interest incurred by ESOP
on its indebtedness $1,109 $1,296 $1,683
Company contributions
to ESOP $1,391 $1,513 $1,075
F-35
Note K - Income Tax Expense
Federal income tax expense is less than the amount computed by applying the
statutory federal rate to book income before tax as follows:
For the year ended December 31,
2000 1999 1998
- -------------------------------------------------------------------------------------------------
(Thousands, except for %)
Amount % Amount % Amount %
------------------------------------------------
Net income from continuing operations
before tax $104,296 100.0 $85,836 100.0 $80,741 100.0
Tax at statutory rate 36,504 35.0 30,043 35.0 28,259 35.0
Increase (decrease):
Tax effect of AFUDC (381) (0.3) (261) (0.3) (601) (0.7)
Amortization of investment tax credits (1,742) (1.7) (1,790) (2.1) (1,790) (2.2)
Tax effect of prior-year tax
benefits not deferred 988 0.9 1,119 1.3 2,175 2.7
AFUDC gross up - SFAS No. 109 (1,731) (1.6) (1,548) (1.8) (1,009) (1.2)
Other, net (2,263) (2.2) (2,929) (3.4) (2,449) (3.1)
- -------------------------------------------------------------------------------------------------
Total federal income tax expense
from continuing operations 31,375 30.1 24,634 28.7 24,585 30.5
- -------------------------------------------------------------------------------------------------
Current state income tax expense
from continuing operations 3,586 3.4 3,132 3.6 2,186 2.7
- -------------------------------------------------------------------------------------------------
Total federal and state income tax expense
from continuing operations $ 34,961 33.5 $27,766 32.3 $26,771 33.2
=================================================================================================
Information about current and deferred income tax expense is as follows:
2000 1999 1998
- --------------------------------------------------------------------------------------------------------
(In thousands)
Current federal income tax expense $28,157 $17,967 $17,672
Deferred federal income tax expense 4,960 8,457 8,703
Amortization of accumulated deferred investment tax credits (1,742) (1,790) (1,790)
- --------------------------------------------------------------------------------------------------------
Total federal income tax expense 31,375 24,634 24,585
Current state income tax expense 3,586 3,132 2,186
- --------------------------------------------------------------------------------------------------------
Total federal and state income tax expense from continuing operations 34,961 27,766 26,771
- --------------------------------------------------------------------------------------------------------
Discontinued operation
Income tax expense from loss from operations
Federal current (2,344) (565) (91)
Federal deferred (575) 1 -
State current and deferred (471) (98) (15)
- --------------------------------------------------------------------------------------------------------
Total tax expense from loss from discontinued operation (3,390) (662) (106)
- --------------------------------------------------------------------------------------------------------
Income tax expense from loss on disposal of segment
Federal deferred (825) - -
State deferred (83) - -
- --------------------------------------------------------------------------------------------------------
Total tax expense from loss on disposal of segment (908) - -
- --------------------------------------------------------------------------------------------------------
Income tax expense from gain on extraordinary item
Federal current 1,408 - -
- --------------------------------------------------------------------------------------------------------
Total federal and state income tax expense $32,071 $27,104 $26,665
========================================================================================================
Deferred federal income tax expense attributable to:
Depreciation $ 6,038 $ 8,524 $11,748
Storm damages (199) 912 492
Asset basis differences (2,078) (2,797) (571)
Employee benefits 1,390 197 (419)
Fuel costs 2,062 660 (612)
Reacquired debt (210) (269) (249)
Other (2,043) 1,230 (1,686)
- --------------------------------------------------------------------------------------------------------
Total deferred federal income tax expense $ 4,960 $ 8,457 $ 8,703
========================================================================================================
F-36
The balance of accumulated deferred federal and state income tax assets and
liabilities at December 31, 2000 and 1999, was comprised of the tax effect of
the following:
2000 1999
- ------------------------------------------------------------------------------------------------------
Asset Liability Asset Liability
-----------------------------------------------
(Thousands)
Depreciation and property basis differences $ 5,528 $157,986 $ 6,894 $153,090
Allowance for funds used during construction - 28,756 - 42,974
Investment tax credits 16,259 - 15,979 -
SFAS No. 109 adjustments 22,535 65,286 92,416 110,315
Postretirement benefits other than pension 4,333 - 4,731 -
Other 7,853 18,090 5,619 14,818
Accumulated deferred federal and state income taxes $56,508 $270,118 $125,639 $321,197
Regulatory assets recorded for deferred taxes at December 31, 2000 and
1999, were $100.3 million and $115.9 million, respectively. Regulatory
liabilities recorded for deferred taxes at December 31, 2000 and 1999, were
$38.8 million and $97.1 million, respectively. Regulatory assets and liabilities
will be realized over the accounting lives of the related properties to the
extent past ratemaking practices are continued by regulators.
The Company does not have a valuation account for deferred tax assets since
the Company considers deferred tax assets realizable.
- --------------------------------------------------------------------------------
Note L - Disclosures about Segments
Unallocated Items,
Cleco Reclassifications
2000 Power Midstream UtiliTech Others & Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------
(Thousands)
Revenues
Retail electric operations $ 619,528 $ 619,528
Energy marketing operations 18,078 $183,166 201,244
Other operations - 403 $18,125 $ 73 $ (18,125) 476
Customer credits (1,233) - - - - (1,233)
- ---------------------------------------------------------------------------------------------------------------
Total operating revenue $ 636,373 $183,569 $18,125 $ 73 $ (18,125) $ 820,015
Intersegment revenues $ 9,256 $ 37,667 $ 1,071 $103,366 $(151,360)
Depreciation expense $ 49,787 $ 5,952 $ 118 $ 101 $ (118) $ 55,840
Interest charges $ 28,722 $ 13,469 $ 258 $ 7,114 $ (258) $ 49,305
Segment profit (loss) (1) $ 90,855 $ 15,220 - $ (1,779) $ (36,831) $ 67,465
Loss on disposal of
discontinued segment, net - - $(1,450) - - $ (1,450)
Loss from discontinued
operations, net - - $(5,411) - - $ (5,411)
Extraordinary item - $ 2,508 - - - $ 2,508
Segment assets $1,302,175 $485,085 $ 8,892 $429,259 $(379,707) $1,845,704
(1) Reconciliation of segment profit to consolidated profit: Unallocated items
Income taxes $34,961
Preferred dividends 1,870
--------
$36,831
========
1999
- ---------------------------------------------------------------------------------------------------------------
Revenues
Retail electric operations $ 508,790 $ 508,790
Energy marketing operations 238,082 $ 18,698 256,780
Other operations - 2,227 $ 6,866 $ 636 $ (8,088) 1,641
Customer credits (2,776) - - - - (2,776)
- ---------------------------------------------------------------------------------------------------------------
Total operating revenues $ 744,096 $ 20,925 $ 6,866 $ 636 $ (8,088) $ 764,435
Intersegment revenues $ 7,816 $ 8,081 $ 792 $ 1,151 $ (17,840)
Depreciation expense $ 49,298 $ 1,101 $ 199 - $ (632) $ 49,966
Interest charges $ 28,414 $ 1,284 $ 12 $ 666 $ (773) $ 29,603
Segment profit (loss) (1) $ 83,955 $ 1,306 - $ 968 $ (30,169) $ 56,060
Loss from discontinued operations (1,304) - (1,304)
Segment assets $1,414,579 $247,021 $ 2,848 $263,889 $(223,687) $1,704,650
(1) Reconciliation of segment profit to consolidated profit: Unallocated items
Income taxes $27,766
Preferred dividends 2,010
Other 92
--------
$30,169
========
F-37
1998
- ---------------------------------------------------------------------------------------------------------------
Revenues
Retail electric operations $ 487,280 $ 487,280
Energy marketing operations 32,695 $ 10,118 $ (10,118) 32,695
Other operations - - $ 214 $ 865 (1,079) -
Customer credits (4,800) - - - - (4,800)
- ---------------------------------------------------------------------------------------------------------------
Total Operating revenues $ 515,175 $ 10,118 $ 214 $ 865 $ (11,197) $ 515,175
Intersegment revenues $ 3,242 $ 297 $ 1,443 $ (4,982)
Depreciation expense $ 48,382 $ 831 $ 79 - $ (910) $ 48,382
Interest charges $ 27,360 $ 792 - - $ (792) $ 27,360
Segment profit/(loss) (1) $ 79,383 $ (719) - $ 1,505 $ (28,336) $ 51,833
Loss from discontinued operations $ (169) $ (169)
Segment assets $1,383,648 $ 67,322 $ 3,483 $27,443 $ (52,896) $1,429,000
/(1)/ Reconciliation of segment profit to consolidated profit: Unallocated items
Income taxes $26,771
Preferred dividends 2,137
Other (572)
--------
$28,336
========
The Company has determined that its reportable segments are based on the
Company's method of internal reporting, which disaggregates its business units
by major first-tier subsidiary. The Company's reportable segments are Cleco
Power, Midstream and UtiliTech. Reportable segments were determined by applying
SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information." Each reportable segment engages in business activities from which
it earns revenues and incurs expenses. Segment managers report at least monthly
to the Company's Chief Executive Officer (the chief decision maker) with
discrete financial information, present quarterly discrete financial information
to the Company's Board of Directors and meet quantitative thresholds as defined
by SFAS No. 131. Budgets were prepared by each reportable segment for 2000,
which were presented to, and approved by, the Company's Board of Directors.
In December 2000 management decided to dispose of UtiliTech. See Note R-
"Discontinued Operations" for more information.
The "Others" segment consists of costs within the parent company, costs
within a shared services subsidiary, start-up costs associated with a retail
services subsidiary, and revenue and expenses associated with an investment
subsidiary. These subsidiaries operate within Louisiana and Delaware.
The financial results of the Company's segments are presented on an accrual
basis. Significant differences among the accounting policies of the segments as
compared to the Company's consolidated financial statements principally involve
the classification of revenue and expense between operating and other.
Management evaluates the performance of its segments and allocates resources to
them based on segment profit (loss) before income taxes and preferred stock
dividends. In the year 1998 and the first six months of 1999, Midstream and
UtiliTech reported profit (loss) as other income (expense) within Cleco Power.
For purposes of this footnote, gross amounts of revenue and expenses are
reported on the appropriate line. The "Unallocated Items, Reclassifications &
Eliminations" column reclassifies the items of revenue and expense recorded
under the equity method to other income (expense). Material intersegment
transactions occur on a regular basis.
F-38
Note M - Accrual of Estimated Customer Credits
The Company's reported earnings in the year ended December 31, 2000,
reflect a $1.2 million accrual within Cleco Power for estimated customer credits
that may be required under terms of an earnings review settlement reached with
the LPSC in 1996. The 1996 LPSC settlement, and a subsequent amendment, set
Cleco Power's rates until the year 2004 and also provided for annual base rate
tariff reductions of $3 million in 1997 and $2 million in 1998. As part of the
settlement, Cleco Power is allowed to retain all regulated earnings up to a
12.25% return on equity, and to share equally with customers as credits on their
bills all regulated earnings between 12.25% and 13% return on equity. All
regulated earnings above a 13% return on equity are credited to customers. The
amount of credits due customers, if any, is determined by the LPSC annually
based on 12-month-ending results as of September 30th of each year. The
settlement provides for such credits to be made on customers' bills the
following summer.
Of the $1.2 million, $0.7 million relates to the 12-months-ended September
30, 2000, cycle, and the remaining $0.5 million relates to the estimated refund
for the 12-months-ended September 30, 1999, cycle. The $1.2 million was recorded
as a reduction in revenue due to the nature of the customer credits. The $0.5
million relating to the September 30, 1999, cycle is due to a settlement with
the LPSC. The amount of the credit for the cycle ending September 30, 2000, if
any, has not yet been determined by the LPSC.
- --------------------------------------------------------------------------------
Note N - Equity Investment in Investee
Equity investment in investee represents Midstream's approximately $97.2
million investment in Acadia Power Partners LLC (APP) and Energy's approximately
$0.9 million investment in Hudson SVD LLC.
APP is a joint venture 50% owned by Midstream and 50% owned by Calpine
Corporation. APP was formed in order to construct, own and operate a 1,000 MW,
natural gas-fired electric plant to be located near Eunice, Louisiana. The
Company reports its investment in APP on the equity method of accounting as
defined in APB Opinion No. 18, "The Equity Method of Accounting for Investments
in Common Stock." Midstream's equity as reported in the unaudited interim
balance sheet of APP at December 31, 2000, was $94.8 million and zero at
December 31, 1999. The majority of the difference of $2.4 million between the
equity investment in investee and the member's equity was the interest
capitalized on funds used to contribute to APP as required by SFAS No. 58,
"Capitalization of Interest Cost in Financial Statements That Include
Investments Accounted for by the Equity Method. See Note B - "Summary of
Significant Accounting Policies, Capitalized Interest."
Energy owns 50% of Hudson SVD LLC, which owns interest in several other
entities that own and operate natural gas pipelines in Texas and Louisiana. The
Company reports its investment in Hudson SVD LLC on the equity method of
accounting as defined in APB Opinion No. 18. The most recent unaudited financial
statements available for Hudson SVD are as of October 31, 2000. The member's
equity as reported in the unaudited interim balance sheet at October 31, 2000,
was approximately $0.9 million, which equals the investment at Energy.
F-39
Note O - Operating Lease
In July 1998 the Board of Directors of the predecessor of Cleco Power
approved the construction of a 775-megawatt repowering project (Project) by its
then wholly owned subsidiary, Evangeline, at the Coughlin Power Station (CPS).
The Project used three new natural gas-fueled combustion turbine generators and
related heat recovery system generators to repower two existing steam turbines
at CPS.
Evangeline, now a wholly owned subsidiary of Midstream, owns the Project.
Evangeline has an agreement with an affiliate, Cleco Generation Services LLC, to
operate the Project. As of December 31, 2000, the Company had capitalized
approximately $218.6 million in plant in operation and $7.1 million in
construction work in progress on the Project.
In July 2000 Unit No. 7 of the Evangeline power plant was declared in
commercial operation. The other unit at the plant, Unit No. 6, was declared in
commercial operation during June 2000. Revenues and operating expenses
associated with Unit No. 7 prior to the July commercial operation date are
reflected in construction work in progress on the Company's Consolidated Balance
Sheets. Revenues and operating expenses relating to both units are reflected on
the Company's Consolidated Statements of Income after they were declared in
commercial operation.
Under the terms of the Evangeline Tolling Agreement, for 20 years
Williams has the right to own and market the electricity produced by the
Evangeline facility and will supply the required natural gas to the facility.
Evangeline will collect a fee from Williams for operating and maintaining the
Evangeline facility. The Evangeline Tolling Agreement is accounted for as an
operating lease and its revenues are recognized as described in Note B -
"Summary of Significant Accounting Policies, Revenues and Fuel Costs."
The following table contains an analysis of the Company's property being
utilized under an operating lease:
At December 31,
2000
- -------------------------------------------------------
(Thousands)
Evangeline Power Station $218,564
Construction work in
progress 7,141
Less: accumulated
depreciation 4,277
- -------------------------------------------------------
$221,428
=======================================================
The following is a schedule by years of future minimum rental payments
(assumes no change to the tested capacity or heat rate of the plant) required
under the Evangeline Tolling Agreement, which is in effect until mid-2020.
Year ending December 31: (Thousands)
2001 $ 50,327
2002 50,845
2003 51,371
2004 51,905
2005 52,442
Thereafter 824,499
- ------------------------------------------------------
Total future minimum rental payments $1,081,389
======================================================
Future minimum rental (assumes no changes to the tested capacity or heat
rate of the plant) payments have not been adjusted for contingent items such as
bonuses or penalties which will vary the actual amounts received from Williams
under the Evangeline Tolling Agreement. For the year ending December 31, 2000,
tolling rental revenues of $41.5 million were recognized, including contingent
rents of approximately $1 million.
- --------------------------------------------------------------------------------
Note P - Proceedings before the LPSC
Several Louisiana-based contractors providing utility line construction
services instituted a proceeding via petition with the LPSC on April 9, 1999,
alleging subsidization by Cleco Power to a nonregulated affiliate, Cleco
Services LLC, now operating as UtiliTech. The LPSC assigned Docket No. U-24064
to the complaint. On September 6, 2000, Cleco Power and the complainants signed
an agreement to settle the dispute. The terms of the settlement did not result
in a material effect upon the Company's results of operations and financial
condition.
In connection with this proceeding, LPSC staff engaged the services of
an outside consultant. The outside consultant filed testimony on behalf of the
LPSC staff identifying several possible ratemaking adjustments to Cleco Power's
previous and future Rate Stabilization Plan filings that could affect Cleco
Power's customer credits. On October 3, 2000, Cleco Power and the staff of the
LPSC signed an agreement resolving all outstanding issues, which the LPSC
approved on November 2, 2000. The settlement resulted in an increase to Cleco
Power's customer credits of approximately $500,000, which will be paid to Cleco
Power's customers in September 2001.
F-40
Note Q - Legal Proceeding: Fuel Supply - Lignite
Cleco Power and Southwestern Electric Power Company (SWEPCO), each a 50%
owner of Dolet Hills Unit 1, jointly own lignite reserves in the Dolet Hills
area of northwestern Louisiana. In 1982 Cleco Power and SWEPCO entered into the
Lignite Mining Agreement (LMA) with the Dolet Hills Mining Venture (DHMV), a
partnership for the mining and delivery of lignite from a portion of these
reserves (Dolet Hills Mine). The LMA expires in 2011. The price of lignite
delivered pursuant to the LMA is a base price per ton, subject to escalation
based on certain inflation indices, plus specified "pass-through" costs.
Currently, Cleco Power is receiving annually a minimum delivery of
1,750,000 tons under the LMA. Since the late 1980s, additional spot lignite
deliveries have been obtained through competitive bidding from DHMV and another
lignite supplier. In 2000 Cleco Power and SWEPCO received deliveries which
approximated 21% of the annual lignite consumption at the Dolet Hills Unit 1
from the other lignite supplier.
On April 15, 1997, Cleco Power and SWEPCO filed a lawsuit in the United
States District Court for the Western District of Louisiana (Federal Court Suit)
against DHMV and its partners seeking to enforce various obligations of DHMV to
Cleco Power and SWEPCO under the LMA, including provisions relating to the
quality of the delivered lignite, pricing, and mine reclamation practices. On
June 15, 1997, DHMV filed an answer denying the allegations in Cleco Power's
lawsuit and filed a counterclaim asserting various contract-related claims
against Cleco Power and SWEPCO. Cleco Power and SWEPCO have denied the
allegations in the counterclaims.
As a result of the counterclaims filed by DHMV in the Federal Court Suit,
on August 13, 1997, Cleco Power and SWEPCO filed a lawsuit in the First Judicial
District Court for Caddo Parish, Louisiana (State Court Suit) against the parent
companies of DHMV, namely Jones Capital Corporation and Philipp Holzmann USA,
Inc. The State Court Suit seeks to enforce a separate 1995 agreement by Jones
Capital Corporation and Philipp Holzmann USA, Inc. related to the LMA. Jones
Capital Corporation and Philipp Holzmann USA, Inc. have asked the state court to
stay that proceeding until the Federal Court Suit isresolved.
On March 1, 2000, the court in the Federal Court Suit ruled that DHMV was
not in breach of certain financial covenants under the LMA and denied Cleco
Power's and SWEPCO's claim to terminate the LMA on that basis. The ruling has no
material adverse effect on the operations of Cleco Power and does not affect the
other claims scheduled for trial. Cleco Power and SWEPCO have appealed the
federal court's ruling to the U.S. Court of Appeals for the Fifth Circuit.
The civil, nonjury trial in the Federal Court Suit was to have commenced on
May 22, 2000. However, on April 20, 2000, all parties jointly requested that the
court postpone the trial date and grant a 120-day stay of all matters before the
trial court to give the parties an opportunity to attempt to reach an amicable
resolution of the litigation. A preliminary memorandum of understanding to
settle the litigation has been executed among Cleco Power, SWEPCO, and DHMV. The
memorandum of understanding, however, is subject to several conditions precedent
that are not yet fulfilled, including prior authorization by the LPSC of
favorable rate recovery of the settlement by Cleco Power and SWEPCO. The federal
court granted the motion, stayed the action at the trial court and postponed the
trial commencement date to October 23, 2000. At a status conference held on July
12, 2000, the court extended the stay of the proceedings and again postponed the
trial date to January 16, 2001. Due to the need for additional time to attempt
to refine the settlement, the parties requested, and on September 26, 2000, the
court ordered that the stay be extended and the trial date be postponed
indefinitely. The Fifth Circuit appeal of the federal court's March 1, 2000,
ruling has also been stayed pending settlement. Settlement negotiations are on-
going during the pendency of the stay.
Should settlement discussions be unsuccessful, Cleco Power and SWEPCO will
continue aggressively to prosecute the claims against DHMV and defend against
the counterclaims that DHMV has asserted. Cleco Power and SWEPCO continue to pay
DHMV for lignite delivered pursuant to the LMA. Normal day-to-day operations
continue at the Dolet Hills Mine and Dolet Hills Unit 1. Although the ultimate
outcome of this litigation or the settlement negotiations cannot be predicted at
this time, based on information currently available to the Company, management
does not believe the outcome of the Federal Court Suit or any settlement in the
Federal Court Suit will have a material adverse effect on the Company's
financial condition or results of operations.
F-41
Note R - Discontinued Operations
In December 2000 management decided to sell substantially all of
UtiliTech's assets and discontinue UtiliTech's operations after the sale. The
sale is expected to be finalized during the first quarter of 2001 with all
operations estimated to cease by March 31, 2001. The assets of UtiliTech at
December 31, 2000, consist of accounts receivable of approximately $3.9 million,
unbilled revenues of approximately $3.4 million and goodwill, net of
amortization of $0.5 million. Liabilities of UtiliTech at December 31, 2000,
consist of an intercompany note payable to the Company of approximately $6.1
million and payables to vendors and employees of $1.3 million. Additional
information about UtiliTech is as follows:
For the year ended December 31,
2000 1999 1998
- ------------------------------------------------------------------
(Thousands)
Revenues $18,125 $ 6,866 $ 214
Loss from operations,
net $(5,411) $(1,304) $(169)
Income tax benefit
associated with loss
from operations $ 3,390 $ 662 $ 106
Loss on disposal of
segment, net $(1,450) - -
Income tax benefit
associated with loss
on disposal $ 908 - -
- --------------------------------------------------------------------------------
Note S - Commitments and Contingencies
Construction and investment in joint ventures expenditures for 2001 are
estimated to be $105 million, excluding AFUDC, and for the five-year period
ending 2005 are expected to total $746 million, excluding AFUDC. Scheduled
maturities of debt and preferred stock will total approximately $30.7 million
for 2001 and approximately $297.5 million for the five-year period ending 2005.
Air and water permits issued on or about July 13, 2000, by the Louisiana
Department of Environmental Quality (LDEQ) to APP were judicially appealed by
various citizens and environmental action groups (APP-related petitioners) in
early August 2000. APP is engaged in the developmental stages of the
construction, ownership and operation of a new electric generating plant near
Eunice, Louisiana. APP-related petitioners filed their appeals to the air and
water permits in the 19th Judicial District Court in Baton Rouge, Louisiana.
APP-related petitioners asked the court to reverse the air and water permits
issued by the LDEQ and allege that LDEQ's decision to issue the permits was
arbitrary, capricious and procedurally inadequate. APP-related petitioners have
also asked the court to stay APP's power plant construction activities pending
resolution of the litigation. APP has denied APP-related petitioners'
allegations and is vigorously defending the validity of the permits issued to it
by the LDEQ. The permits could be upheld, reversed, or remanded in whole or in
part. If the permits were to be reversed in material part by the court, APP may
be required to cease its construction of the generating plant temporarily or
permanently, depending on the nature and details of the reversal. If the court
were to remand the permits, without reversing them, to the LDEQ for further
proceedings, APP's continuation of construction of the generating plant may be
jeopardized, depending upon the nature and details of the remand. Oral arguments
on the appeal of these permits were held on February 5, 2001. The parties are
awaiting the court's ruling. Although the ultimate outcome of this action cannot
be predicted at this time, based on information currently available to the
Company, management does not believe the outcome of this action will have a
material adverse effect on the Company's financial condition or results of
operations.
An air permit issued by the LDEQ on August 25, 2000, to Perryville Energy
Partners LLC (PEP), a joint venture in which Midstream has a 50 percent interest
with Mirant Corporation, was judicially appealed by various citizens and
community action groups (PEP-related petitioners). PEP is engaged in the
developmental stages of the construction, ownership and operation of a new
electric generating plant near Perryville, Louisiana. PEP-related petitioners
filed their appeal of the air permit in the 19th Judicial District Court in
Baton Rouge, Louisiana, alleging that the issuance of the air permit violates
the Louisiana Constitution, the public trustee doctrine and state and federal
environmental laws. PEP-related petitioners have asked that the district court
reverse the permit decision or remand the permit decision to require that the
LDEQ
F-42
address certain alleged deficiencies in its issuance of the permit and have also
requested that the court stay the air permit. PEP denies PEP-related
petitioners' allegations and is vigorously defending the validity of the permit
issued to it by the LDEQ. The permit could be upheld, reversed or remanded, in
whole or in part. In the event of a reversal or remand by the court, PEP's
construction of the generating plant may be delayed, depending upon the nature
and details of the reversal or remand. A hearing date on PEP-related
petitioners' challenge to the permit has not yet been scheduled with the court.
Although the ultimate outcome of this action cannot be predicted at this time,
based on information currently available to the Company, management does not
believe the outcome of this action will have a material adverse effect on the
Company's financial condition or results of operations.
For the upcoming session of the Louisiana Legislature, a proposed bill,
Senate Bill 1, has been filed for consideration. The bill institutes a process
by which all new industrial and agricultural users of groundwater must apply for
and obtain permits to pump groundwater if their wells have a maximum potential
flow rate of one million gallons per day or more. If the bill becomes law, it
will be effective prior to the date APP's generating plant is completed and
operating. In its current form, the draft bill may require APP to apply for and
obtain a permit for the wells the plant will use. If APP were required to apply
for a permit under the bill, thereis no guarantee that APP would be successful
in obtaining the permit. Although it cannot be predicted if the bill will be
adopted, or what final form the bill may take, Management believes that if the
bill becomes law it will not have a material adverse effect on the Company's
financial condition or results of operations.
Cleco Power has accrued for liabilities to third parties, employee medical
benefits, storm damages and deductibles under insurance policies that it
maintains on major properties, primarily generating stations and transmission
substations. Consistent with regulatory treatment, annual charges to operating
expense to provide a reserve for future storm damages are based upon the average
amount of noncapital, uninsured storm damages experienced by Cleco Power during
the previous five years.
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," establishes accounting standards for
determining if long-lived assets are impaired and when and how losses, if any,
should be recognized. The Company believes that the net cash flows that will
result from the operation of its assets are sufficient to cover the carrying
value of the assets.
F-43
Note T - Miscellaneous Financial Information (Unaudited)
Quarterly information for the Company for 2000 and 1999 is shown in the
following table.
2000
- ------------------------------------------------------------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
-----------------------------------------------------------------
(Thousands, except per share amounts)
Operating revenues as reported in 10-Q $ 141,026 $ 189,003 $ 273,668 $ 233,605
Adjustments:
Operating revenue from UtiliTech (3,609) (3,541) (4,543) (6,431)
Reclassification to/from other income (expense) (322) 1,159 - -
Operating revenues $ 137,095 $ 186,621 $ 269,125 $ 227,174
- ------------------------------------------------------------------------------------------------------------------------
Operating income as reported in 10-Q $ 23,103 $ 31,748 $ 59,805 $ 21,466
Adjustments:
Operating loss from UtiliTech 660 2,407 1,794 3,289
Reclassification to/from other income (expense) 430 2,477 16
Operating income 24,193 36,632 61,615 24,755
- ------------------------------------------------------------------------------------------------------------------------
Loss from discontinued operations, net of tax $ (438) $ (1,599) $ (1,192) $ (2,182)
Loss on disposal of segment, net of tax - - - $ (1,450)
Extraordinary gain, net of tax $ 2,508 - - -
Net income applicable to common stock $ 12,258 $ 16,454 $ 29,677 $ 4,725
Net income applicable to common before
extraordinary tax $ 9,750 $ 16,454 $ 29,677 $ 4,725
Basic net income applicable to common before
extraordinary item per average common share $ 0.43 $ 0.73 $ 1.32 $ 0.21
Basic net income per average common share $ 0.54 $ 0.73 $ 1.32 $ 0.21
Diluted net income applicable to common before
extraordinary item per average common share $ 0.43 $ 0.71 $ 1.26 $ 0.21
Diluted net income per average common share $ 0.53 $ 0.71 $ 1.26 $ 0.21
Dividends paid per common share $ 0.415 $ 0.425 $ 0.425 $ 0.425
Closing market price per share
High $ 33.94 $ 36.25 $ 46.75 $ 55.38
Low $ 30.44 $ 32.88 $ 34.13 $ 44.63
- ------------------------------------------------------------------------------------------------------------------------
1999
- ------------------------------------------------------------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
-----------------------------------------------------------------
(Thousands, except per share amounts)
Operating revenues as reported in 10-Q $ 121,719 $ 222,474 $ 285,032 $ 138,975
Adjustments:
Operating revenue from UtiliTech - - (1,465) (2,651)
Reclassification to/from other income (expense) - (3) (403) 757
Operating revenues $ 121,719 $ 222,471 $ 283,164 $ 137,081
- ------------------------------------------------------------------------------------------------------------------------
Operating income as reported in 10-Q $ 19,481 $ 29,519 $ 47,291 $ 16,250
- ------------------------------------------------------------------------------------------------------------------------
Adjustments:
Operating loss from UtiliTech - - 321 1,216
Reclassification to/from other income (expense) (3) (6) (406) 753
Operating income $ 19,478 $ 29,513 $ 47,206 $ 18,219
- ------------------------------------------------------------------------------------------------------------------------
Loss from discontinued operations, net of tax $ (188) $ (170) $ (198) $ (748)
Net income applicable to common stock $ 8,017 $ 13,716 $ 25,152 $ 7,871
Basic net income per average common share $ 0.36 $ 0.61 $ 1.12 $ 0.35
Diluted net income per average common share $ 0.35 $ 0.59 $ 1.07 $ 0.35
Dividends paid per common share $ 0.405 $ 0.415 $ 0.415 $ 0.415
Closing market price per share
High $ 35.50 $ 33.56 $ 33.63 $ 35.19
Low $ 28.25 $ 28.44 $ 30.06 $ 31.13
The Company's common stock is listed for trading on the New York and
Pacific stock exchanges under the ticker symbol "CNL." The Company's preferred
stock is not listed on any stock exchange. On December 31, 2000, the Company had
9,386 common and 118 preferred shareholders, as determined from the records of
the transfer agent.
On January 26, 2001, the Company's Board of Directors declared a quarterly
dividend of 42.5 cents per share payable February 15, 2001, to common
shareholders of record on February 5, 2001. Preferred dividends were also
declared payable March 1, 2001, to preferred shareholders of record on February
15, 2001.
F-44
[LETTERHEAD OF PRICEWATERHOUSECOOPERS]
Report of Independent Accountants
To the Shareholders and
Board of Directors of Cleco Corporation:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of changes in common shareholders' equity and
of cash flows present fairly, in all material respects, the financial position
of Cleco Corporation and its subsidiaries at December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
January 30, 2001
F-45
Cleco Corporation
Selected Financial Data (Unaudited)
2000 1999 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts and percentages)
Selected Consolidated Income Statement Items
Revenue from retail electric operations, net $ 618,295 $ 506,014 $ 482,480 $ 456,245 $ 437,121
Fuel and purchased power for retail electric operations 303,987 210,532 195,748 180,599 171,251
- --------------------------------------------------------------------------------------------------------------------------
Gross profit from retail electric operations 314,308 295,482 286,732 275,646 265,870
- --------------------------------------------------------------------------------------------------------------------------
Revenue from energy marketing operations 159,696 256,780 32,695 - -
- --------------------------------------------------------------------------------------------------------------------------
Purchases from energy marketing operations 141,352 244,384 27,322 - -
- --------------------------------------------------------------------------------------------------------------------------
Gross profit from energy marketing operations 18,344 12,396 5,373 - -
- --------------------------------------------------------------------------------------------------------------------------
Tolling revenue 41,548 - - - -
Other operating revenues 476 1,641 - - -
Other operating expenses 227,481 195,103 185,153 169,107 161,295
- --------------------------------------------------------------------------------------------------------------------------
Operating income 147,195 114,416 106,952 106,539 104,575
Total other income, net 6,406 1,023 1,149 2,319 1,723
Interest and AFUDC, net 49,305 29,603 27,360 28,586 28,009
- --------------------------------------------------------------------------------------------------------------------------
Net income before income taxes, discontinued
operations, extraordinary item, and preferred
dividends 104,296 85,836 80,741 80,272 78,289
Income taxes 34,961 27,766 26,771 27,729 26,154
Discontinued operations
Loss from operations, net of income taxes 5,411 1,304 169 24 -
Loss on disposal of segment, net of income
taxes 1,450 - - - -
Gain on extraordinary item, net of income taxes 2,508 - - - -
Preferred dividend requirements, net 1,870 2,010 2,137 2,117 2,074
- --------------------------------------------------------------------------------------------------------------------------
Net income applicable to common stock $ 63,112 $ 54,756 $ 51,664 $ 50,402 $ 50,061
- --------------------------------------------------------------------------------------------------------------------------
Basic EPS from continuing operations $ 3.00 $ 2.49 $ 2.31 $ 2.24 $ 2.23
Basic EPS applicable to common stock $ 2.81 $ 2.43 $ 2.30 $ 2.24 $ 2.23
Diluted EPS from continuing operations $ 2.91 $ 2.42 $ 2.24 $ 2.18 $ 2.16
Diluted EPS applicable to common stock $ 2.72 $ 2.37 $ 2.24 $ 2.18 $ 2.16
EBITDA $ 202,813 $ 163,054 $ 155,299 $ 153,677 $ 148,349
- --------------------------------------------------------------------------------------------------------------------------
Selected Consolidated Balance Sheet and Cash Flow Items
Capital expenditures $ 210,577 $ 179,226 $ 94,030 $ 77,525 $ 64,425
Internal cash generation (% of capital expenditures) 36% 30% 63% 100% 96%
Property, plant, and equipment, net $ 1,232,758 $ 1,211,617 $ 1,089,798 $ 1,025,562 $ 994,136
Total assets $ 1,845,704 $ 1,704,650 $ 1,429,000 $ 1,361,044 $ 1,321,771
Total nonutility assets $ 543,529 $ 307,468 $ 85,268 $ 28,591 $ 25,415
Total capitalization $ 1,139,150 $ 1,032,140 $ 786,208 $ 792,104 $ 750,154
Consolidated capitalization ratios
Common shareholders' equity 40.81% 42.50% 54.02% 51.60% 52.44%
Preferred stock 1.33% 1.35% 2.35% 2.20% 2.12%
Long-term debt 57.86% 56.15% 43.63% 46.20% 45.44%
- --------------------------------------------------------------------------------------------------------------------------
Shareholder Value Information
Average shares outstanding for year, basic 22,473,859 22,501,324 22,480,163 22,459,770 22,442,683
Average shares outstanding for year, diluted 23,827,477 23,848,515 23,867,458 23,864,031 23,857,967
Market capitalization at year-end $ 1,228,720 $ 719,551 $ 771,556 $ 727,237 $ 620,252
Book value per common share at year-end $ 20.68 $ 19.49 $ 18.89 $ 18.20 $ 17.52
Dividends paid per common share $ 1.69 $ 1.65 $ 1.61 $ 1.57 $ 1.53
Dividend-payout ratio 60.2% 67.8% 70.1% 70.0% 68.6%
Dividend yield at year-end 3.1% 5.1% 4.7% 4.8% 5.5%
Return on average common equity 14.0% 12.7% 12.4% 12.6% 13.0%
Total return to shareholders 76.0% (2.5%) 11.0% 22.9% 8.5%
Price-earnings ratio at year-end 19.5x 13.2x 14.9x 14.5x 12.4x
Market value to EBITDA at year-end 6.06x 4.42x 4.97x 4.67x 4.18x
Market-to-book ratio at year-end 2.65x 1.64x 1.82x 1.78x 1.58x
Market value to capitalization at year-end 108% 70% 98% 92% 83%
Effective tax rate 33.5% 32.3% 33.2% 34.5% 33.4%
F-46
Cleco Corporation
Selected Operating Data (Unaudited)
2000 1999 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------
Sales of Electricity - Cleco Power
Electric energy sales (millions of kilowatt-hours)
Residential 3,357 3,208 3,230 2,838 2,723
Commercial 1,675 1,597 1,529 1,393 1,345
Industrial 2,926 2,720 2,518 2,467 2,362
Other retail 589 574 555 533 526
- ------------------------------------------------------------------------------------------------------------------------
Total retail 8,547 8,099 7,832 7,231 6,956
Sales for resale 500 6,314 1,503 468 621
- ------------------------------------------------------------------------------------------------------------------------
Total electric sales 9,047 14,413 9,335 7,699 7,577
========================================================================================================================
Energy Supply and Production Data - Cleco Power
Energy supply (millions of kilowatt-hours)
Net generation - system plants 6,254 6,378 6,764 6,227 5,348
Purchased power 3,109 8,730 3,031 1,985 2,803
- ------------------------------------------------------------------------------------------------------------------------
Total energy supply 9,363 15,108 9,795 8,212 8,151
========================================================================================================================
Generating capability (megawatts) 2,767 1,713 1,713 1,713 1,713
Peak demand (megawatts) 1,839 1,767 1,627 1,560 1,500
Cost of fuel per KWH $ 0.0328 $ 0.0236 $ 0.0228 $ 0.0235 $ 0.0225
Fuel Mix:
Coal & lignite 35.4% 33.3% 37.3% 43.0% 41.5%
Natural gas & oil 30.4% 39.7% 39.0% 33.7% 25.1%
Purchased power 34.2% 27.0% 23.7% 23.3% 33.4%
System annual load factor 55.4% 54.3% 56.2% 56.1% 56.1%
Electric Utility Customer Data
Total customers 249,175 246,508 242,457 238,061 224,703
Telephone access:
Percent calls answered within 20 seconds 83% 67% 50% - -
Average speed of answer (seconds) 15 39 47 46 -
Average revenue per KWH sold
Residential $ 0.0779 $ 0.0682 $ 0.0677 $ 0.0686 $ 0.0684
Commercial $ 0.0718 $ 0.0624 $ 0.0612 $ 0.0630 $ 0.0625
Industrial $ 0.0500 $ 0.0421 $ 0.0415 $ 0.0425 $ 0.0418
Other $ 0.0978 $ 0.0612 $ 0.0605 $ 0.0483 $ 0.0414
Composite for regular customers $ 0.0685 $ 0.0578 $ 0.0575 $ 0.0566 $ 0.0550
Net utility plant (in thousands)
Production $231,108 $246,810 $264,891 $277,779 $297,024
Transmission $240,256 $231,953 $226,493 $219,239 $218,191
Distribution $419,737 $411,520 $406,063 $386,990 $348,295
Other $ 90,162 $ 92,756 $ 92,832 $ 95,341 $ 89,388
System Average Interruption Duration Index (SAIDI) 1.82 1.78 1.75 1.43 1.43
(Average amount of hours a customer's service is interrupted)
System Average Interruption Frequency Index (SAIFI) 1.41 1.39 1.25 1.47 1.34
(Average number of times a customer's service is interrupted)
Customer Satisfaction Percentage 94% 97% 95% 95% 92%
========================================================================================================================
F-47