Financial Summary
Over the last three years ended December 31, 1996, CalEnergy
Company, Inc. (the "Company") has experienced significant growth.
The market capitalization of the Company has risen at a compound
annual rate of 48% from approximately $656 million in 1993 to
approximately $2,140 million in 1996, the revenues of the Company
have risen at a compound annual rate of 57% from approximately
$149 million in 1993 to approximately $576 million in 1996 and
net income available to common stockholders has risen at a
compound annual rate of 29% from approximately $43 million in
1993 to approximately $92 million in 1996. This significant
growth has been achieved through: (i) acquisitions that
complement and diversify the Company's existing business, broaden
the geographic locations of its assets and enhance its
competitive capabilities; (ii) enhancement of the financial and
technical performance of existing and acquired projects; and
(iii) development and construction of new plants.
On December 24, 1996, CE Electric UK plc, which is 70% owned
indirectly by the Company and 30% owned indirectly by Peter
Kiewit Sons', Inc. ("PKS"), acquired majority ownership of the
outstanding ordinary share capital of Northern Electric plc
("Northern") pursuant to a tender offer. The total amount
expected to be paid for all of Northern's ordinary and preference
shares is approximately $1.3 billion.
In the last two years, the Company has consummated three other
significant acquisitions, in addition to the acquisition of
Northern. In January 1995, the Company acquired Magma Power
Company ("Magma"), a publicly-traded United States independent
power producer with 228 megawatts ("MW") of aggregate net
operating capacity and 154 MW of aggregate net ownership
capacity, for approximately $958 million. The Magma acquisition,
combined with the Company's previously existing assets, made the
Company the largest independent geothermal power producer in the
world today (based on the Company's estimate of aggregate MW of
electric generating capacity in operation and under
construction). In April 1996, the Company completed the buy-out
for approximately $70 million of its partner's interests
("Partnership Interest") in four electric generating plants in
Southern California, resulting in sole ownership of the Imperial
Valley Project. In August 1996, the Company acquired Falcon
Seaboard Resources, Inc. ("Falcon Seaboard") for approximately
$226 million, thereby acquiring significant ownership in 520 MW
of natural gas-fired electric production facilities located in
New York, Texas and Pennsylvania and a related gas transmission
pipeline.
Through its subsidiaries and joint ventures, the Company
presently operates 19 projects with an aggregate net capacity of
1,326 MW, in which it has a net ownership interest of 1,107 MW of
electric generating capacity. This includes an aggregate net
ownership interest of 916 MW in facilities located in the United
States (which facilities have an aggregate net capacity of 1,135
MW, of which 570 MW are fueled with natural gas and 565 MW are
geothermal-fired). The remaining 191 MW are supplied by two
geothermal power production facilities owned and operated by the
Company in the Philippines. These numbers do not reflect 47
small scale combined heat and power facilities and a diesel fired
power production facility in England that an indirect Northern
subsidiary operates. Finally, the Company owns, but does not
operate, 202 net MW from the 1,875 MW Teesside Project in
England.
With respect to power generation projects that are financed and
under construction, the Company has an aggregate net ownership
interest of 270 MW of electric generating capacity in two
geothermal power projects and one hydroelectric project in the
Philippines, which collectively have an aggregate net capacity of
459 MW. The Company is also currently constructing a 55 net MW
geothermal project in Indonesia, in which the Company has an
aggregate net ownership interest of 26 MW of electric generating
capacity, as the first phase of the Company's planned Indonesian
geothermal project development of approximately 1,000 MW under
contract. The Company has commenced construction of a 50 MW gas
fired power project in England in which the Company has net
ownership interest of 18 MW. The Company expects that it will
operate all of these projects.
The Company is also currently developing six additional projects
with executed or awarded power sales contracts in the
Philippines, Indonesia and the United States. The Company is
expected to have an approximate net ownership interest of 573 MW
in these development projects (which represent an aggregate net
capacity of 1,260 MW of additional potential electric generating
capacity). Substantial contingencies exist with respect to
development projects, including, without limitation, the need to
obtain financing, permits and licenses and the satisfactory
completion of construction. The Company expects that it will
operate all of these projects.
The Company's operations have historically been seasonal in
nature, with a disproportionate percentage of income earned in
the third quarter. As a result of the acquisition of Northern,
the Company's historical results could differ significantly from
the Company's actual results in the future.
SELECTED Financial Data
Dollars in Thousands Except Per Share Amounts
Year Ended December 31,
1996 1995 1994 1993 1992
Sales of electricity and steam $518,934 $335,630 $154,562 $132,059 $117,342
Total revenue 576,195 398,723 185,854 149,253 127,529
Expenses 440,482 301,672 130,018 87,995 76,797
Income before provision for income taxes 135,713 97,05 155,836 61,258 50,732
Income before change in accounting
principle and extraordinary item 93,892 66,420 38,834 43,074 38,810
Cumulative effect of change in
accounting principle --- --- --- 4,100 ---
Minority interest 1,431 3,005 --- --- ---
Extraordinary item --- --- (2,007) --- (4,991)
Net income before preferred dividends 92,461 63,415 36,827 47,174 33,819
Preferred dividends --- 1,080 5,010 4,630 4,275
Income per share before change in accounting
principle and extraordinary item 1.60 1.25 .95 1.00 .92
Cumulative effect of change in accounting
principle per share --- --- --- .11 ---
Extraordinary item per share --- --- (.06) --- (.13)
Net income per share - primary 1.60 1.25 .89 1.11 .79
Total assets 5,712,907 2,654,038 1,131,145 715,984 580,550
Total liabilities 4,263,803 2,084,474 867,703 425,393 336,272
Company-obligated mandatorily
redeemable convertible preferred
securities of subsidiary trust
holding solely convertible debentures 103,930 --- --- --- ---
Preferred securities of subsidiary 136,065 --- --- --- ---
Minority interest 299,252 --- --- --- ---
Redeemable preferred stock --- --- 63,600 58,800 54,350
Stockholders' equity 880,790 543,532 179,991 211,503 168,764
1 Reflects acquisitions of Northern, Falcon Seaboard and the
Partnership Interest owned for part of the year. See Note 3 to
the financial statements.
2 Reflects acquisition of Magma owned for part of the year. See
Note 3 to the financial statements.
MANAGEMENT'S Discussion and Analysis of Financial Condition
and Results of Operations
Dollars and Shares in Thousands Except Per Share Data
The following is management's discussion and analysis of certain
significant factors which have affected the Company's financial
condition and results of operations during the periods included
in the accompanying statements of operations. As a result of the
acquisition of Northern Electric plc ("Northern"), the Company's
historical results could differ significantly from the Company's
actual results in the future.
Acquisitions
On December 24, 1996, CE Electric UK plc ("CE Electric"), which
is 70% owned indirectly by the Company and 30% owned indirectly
by Peter Kiewit Sons', Inc. ("PKS"), acquired majority ownership
of the outstanding ordinary share capital of Northern pursuant to
a tender offer (the "Tender Offer"). Through January 31, 1997, CE
Electric had purchased more than 90% of Northern's ordinary
shares. Under United Kingdom statutory powers available to
compulsorily acquire shares not purchased in the Tender Offer, CE
Electric expects to acquire the remaining Northern shares by
April 30, 1997.
Northern's revenue and profit before tax were approximately
$1,412,200 and $236,100 respectively, for its fiscal year ended
March 31, 1996.
In April 1996, the Company completed the buy-out for
approximately $70,000 of its partner's interests ("Partnership
Interest") in four electric generating plants in Southern
California, resulting in sole ownership of the Imperial Valley
Project. In August 1996, the Company acquired Falcon Seaboard
Resources, Inc. ("Falcon Seaboard") for approximately $226,000,
thereby acquiring significant ownership in 520 MW of natural gas-
fired electric production facilities located in New York, Texas
and Pennsylvania and a related gas transmission pipeline.
Power Generation Projects
For purposes of consistency in financial presentation, plant
capacity factors for Navy I, Navy II, and BLM plants
(collectively the "Coso Project"), are based upon a capacity
amount of 80 net MW for each plant. Plant capacity factors for
Vulcan, Hoch (Del Ranch), Elmore, Leathers plants (collectively
the "Partnership Project"), are based on nominal capacity amounts
of 34, 38, 38, and 38 net MW respectively, and for Salton Sea I,
Salton Sea II, Salton Sea III and Salton Sea IV plants
(collectively the "Salton Sea Project"), are based on nominal
capacity amounts of 10, 20, 49.8 and 39.6 net MW, respectively
(the Partnership Project and the Salton Sea Project are
collectively referred to as the "Imperial Valley Project"). Plant
capacity factors for Saranac, Power Resources, NorCon and Yuma
plants (collectively the "Gas Plants") are based on capacity
amounts of 240, 200, 80 and 50 net MW, respectively. Each plant
possesses an operating margin which allows for production in
excess of the amount listed above. Utilization of this operating
margin is based upon a variety of factors and can be expected to
vary throughout the year under normal operating conditions.
See Note 4 to the financial statements for a discussion of the
Company's significant operating contracts.
Results of Operations Three Years Ended December 31, 1996, 1995
and 1994
Sales of electricity and steam increased to $518,934 in the year
ended December 31, 1996 from $335,630 in the year ended December
31, 1995, a 54.6% increase. This improvement was primarily due
to the acquisitions of the Partnership Interest, Falcon Seaboard
and Northern, the deemed completion of the Upper Mahiao Project
and Unit I of the Malitbog Project in the Philippines, the
completion of Salton Sea IV Project and an increase in the Coso
Project's electricity revenues.
The increase in sales of electricity and steam in 1995 to
$335,630 from $154,562 in 1994 was primarily due to the addition
of production from the Imperial Valley Project as a result of the
acquisition of Magma in the first quarter of 1995, an increase in
the Coso Project's electricity revenues and an increase in
revenue received from the Yuma Project which commenced operation
in May 1994.
The following operating data represents the aggregate capacity
and electricity production of the Coso Project:
1996 1995 1994
Overall capacity factor 110.2% 110.3% 106.5%
kWh produced (in thousands) 2,323,000 2,318,400 2,238,600
Capacity NMW (average) 240 240 240
The Coso Project capacity factor was 111.0% in the fourth quarter
of 1996 compared to 111.5%, 109.5% and 108.7% for the third,
second and first quarters of 1996, respectively. A steam transfer
agreement was signed and the interties were constructed in the
third quarter of 1995, providing for increased production,
primarily at the BLM Project.
The following operating data represents the aggregate capacity
and electricity production of the Partnership Project:
1996 1995 1994
Overall capacity factor 104.8% 105.9% 103.8%
kWh produced (in thousands) 1,361,800 1,373,310 1,346,000
Capacity NMW (average) 148 148 148
The Partnership Project capacity factor was 105.7% in the fourth
quarter of 1996 compared to 106.4%, 109.2%, and 97.6% for the
third, second, and first quarters of 1996, respectively. The
decreased production in 1996 is a result of scheduled overhauls
at Leathers and Elmore. The increased production in 1995 is a
result of minimizing unscheduled downtime at the plants.
The following operating data represents the aggregate capacity
and electricity production of the Salton Sea Project:
1996 1995 1994
Overall capacity factor 90.4% 86.5% 90.8%
kWh produced (in thousands) 817,400 604,300 634,890
Capacity NMW (average) 103.0 79.8 79.8
The overall Salton Sea Project capacity factor was 92.4% in the
fourth quarter of 1996 compared to 97.9%, 78.6% and 89.6% for the
third, second and first quarters of 1996, respectively. The
Salton Sea Project capacity factor has increased in 1996 from
1995 due to the commencement of operations at the Salton Sea IV
Project. The decrease in 1995 from 1994 is due to the scheduled
Salton Sea III Project overhaul in the second quarter of 1995 and
the conversion of that unit to the pH Mod technology in the
fourth quarter of 1995.
The following operating data represents the aggregate capacity
and electricity production of the Gas Plants:
1996 1995 1994
Overall capacity factor 84.2% 88.8% 80.6%
kWh produced (in thousands) 4,216,800 4,433,900 3,144,700
Installed capacity NMW 570 570 445.5
The capacity factor of the Gas Plants reflects the effect of
certain contractual curtailments. The capacity factors adjusted
for these contractual curtailments are 93.2%, 96.8% and 90.6% for
1996, 1995 and 1994, respectively.
Electric sale price per kWh for the Coso Project, Partnership
Project and Salton Sea Project varies seasonally in accordance
with the rate schedule included in the SO4 agreements and power
purchase agreements. The Coso Project's, Partnership Project's
and Salton Sea Project's average electricity prices per kWh in
1996, 1995 and 1994 were comprised of (in cents):
Coso Project Energy Capacity & Bonus Total
Average fiscal 1996 12.61 1.82 14.43
Average fiscal 1995 11.81 1.82 13.63
Average fiscal 1994 10.91 1.90 12.81
Partnership Project Energy Capacity & Bonus Total
Average fiscal 1996 10.02 2.12 12.14
Average fiscal 1995 11.14 2.10 13.24
Average fiscal 1994 10.29 2.16 12.45
Salton Sea Project Energy Capacity & Bonus Total
Average fiscal 1996 8.84 2.29 11.13
Average fiscal 1995 9.50 2.33 11.83
Average fiscal 1994 10.07 1.67 11.74
Income on equity investments reflects the Company's share of
equity income primarily from the Saranac Project and Northern.
Royalty income decreased in 1996 to $6,846 from $19,482 in 1995,
a 64.9% decrease. This decrease is a result of the Company no
longer recognizing royalty income received from the Partnership
Project as the Partnership Project is now owned 100% by the
Company due to the Partnership Interest acquisition. The Company
continues to receive royalty income from other projects not owned
by the Company. Royalty income in 1995 of $19,482 is a result of
the acquisition of Magma which received royalties from the
Partnership Project, and from other projects not owned by the
Company.
Interest and other income marginally increased in 1996 to $44,281
from $43,611 in 1995, a 1.5% increase. This increase is primarily
a result of operator fees received from the Saranac Project and
NorCon Project partially offset by the fact the Company is no
longer recognizing management services income received from the
Partnership Project as the Partnership Project is now owned 100%
by the Company due to the Partnership Interest acquisition.
Interest and other income increased in 1995 to $43,611 from
$31,292 in 1994. The increase primarily reflects management
services income received from the Partnership Project.
Overall, the Company's expenses increased in 1996 due to the
acquisitions of Northern, Falcon Seaboard and the Partnership
Interest, the commencement of operations of the Salton Sea IV
Project and the deemed completion of the Upper Mahiao Project
and Unit I of the Malitbog Project.
Plant operations increased to $108,962 in 1996 from $79,294 in
1995, an increase of 37.4%. The increase is a result of the
Falcon Seaboard and the Partnership Interest acquisitions, and
the commencement of operations of the Salton Sea IV Project.
Operating expense increased to $79,294 in 1995 from $33,015 in
1994, an increase of 140.2% as a result of the cost of plant
operations at the Imperial Valley Project and the full year of
operations at the Yuma Project.
The cost of sales of $31,840 are a result of the acquisition of
Northern and represent costs of electricity sales during the
period of the Company's controlling interest from December 24,
1996 through December 31, 1996.
General and administration costs decreased to $21,451 in 1996
from $23,376 in 1995, a decrease of 8.2%. This decrease is a
result of the Company's continued efforts to reduce costs and
reflects the elimination of redundant functions subsequent to the
acquisition of Magma. General and administration costs increased
to $23,376 in 1995 compared to $13,012 in 1994, a 79.6% increase
primarily attributable to the Magma acquisition.
Royalty costs marginally decreased to $23,693 in 1996 from
$24,308 in 1995, a 2.5% decrease. This decrease is primarily due
to decreased royalty costs at the Desert Peak Project due to
revenue reductions. Royalty cost increased to $24,308 in 1995
from $9,888 in 1994, a 145.8% increase. The 1995 increase was due
to the addition of the Imperial Valley Project, increased revenue
from the plants the Company owned in 1994 and scheduled royalty
increases associated with such plants.
Depreciation and amortization increased in 1996 to $118,586 from
$72,249 in 1995, a 64.1% increase. This increase is primarily due
to the depreciation and amortization of the allocated purchase
price and goodwill related to the Magma, Partnership Interest and
Falcon Seaboard acquisitions, the Philippine projects and the
commencement of operations at the Salton Sea IV Project.
Depreciation and amortization increased to $72,249 in 1995 from
$21,197 in 1994, a 240.8% increase. The increase was due to
depreciation and amortization of the allocated purchase price and
goodwill from the Magma acquisition.
Loss on equity investment in the Casecnan Project reflects the
Company's share of interest expense in excess of capitalized
interest and interest income at the Casecnan Project, which is
currently in construction.
Interest expense, less amounts capitalized, increased in 1996 to
$126,038 from $102,083 in 1995, a 23.5% increase, and increased
to $102,083 in 1995 from $52,906 in 1994, a 93.0% increase.
Higher interest expense is primarily due to a larger portfolio of
facilities and their associated debt partially offset by the
increase in capitalized interest on the Company's international
and domestic projects.
The provision for income taxes increased to $41,821 in 1996 from
$30,631 in 1995, and increased to $30,631 in 1995 from $17,002 in
1994. The effective tax rate was 30.8%, 31.6% and 30.5% in 1996,
1995, and 1994, respectively.
Income before the provision for income taxes increased to
$135,713 in 1996 from $97,051 in 1995, a 39.8% increase. Minority
interest in 1996 reflects the Company's partial ownership in
Northern for the period from December 24, 1996 through December
31, 1996. Minority interest in 1995 reflects the Company's
partial ownership in Magma for the period from January 10, 1995
to February 24, 1995. Net income available to common
shareholders increased to $92,461 or $1.60 per common share in
1996 compared to $62,335 or $1.25 per common share in 1995 and
$31,817 or $.89 per common share in 1994. Net income for the year
ended December 31, 1994 was reduced by $2,007 or $.06 per share
due to an extraordinary item.
Liquidity and Capital Resources
Cash and short-term investments were $429,421 at December 31,
1996 as compared to $106,304 at December 31, 1995. In addition,
the Company's share of joint venture cash and investments
retained in project control accounts was $48,083 and $77,590 at
December 31, 1996 and 1995, respectively. Distributions out of
the project control accounts are made monthly to the Company for
operation and maintenance and capital costs and semiannually to
each Coso Project partner for profit sharing under a prescribed
calculation subject to mutual agreement by the partners. In
addition, the Company recorded separately restricted cash of
$107,143 and $149,227 at December 31, 1996 and 1995,
respectively. The restricted cash balances are comprised
primarily of amounts deposited in restricted accounts from which
the Company will provide its equity contribution requirements
relating to the Mahanagdong Project, fund certain capital
improvements at the Imperial Valley Project and the Company's
proportionate share of the Coso Project, the Power Resources
Project, the Upper Mahiao Project and the Malitbog Project cash
reserves for the debt service reserve funds.
Accounts receivable normally represents two months of revenues,
and fluctuates with both production and distribution and supply
of electricity.
The balance due from the joint ventures relates to operations,
maintenance, and management fees for managing the Coso Project as
well as advances and deferred revenue on the international
projects. This amount fluctuates based on the timing of billings
and incurrence of costs.
The Company repurchased 472 common shares during 1996 for the
aggregate amount of $12,008. The Company repurchased 102 shares
of common stock in 1995 at an aggregate amount of $1,590. As of
December 31, 1996 the Company holds 299 shares of treasury stock
at a cost of $8,787 to provide shares for issuance under the
Company's employee stock option and share purchase plan and other
outstanding convertible securities. The repurchase plan attempts
to minimize the dilutive effect of the additional shares issued
under these plans.
On February 26, 1997 CalEnergy Capital Trust II, a special
purpose Delaware business trust organized by the Company (the
"Trust II"), pursuant to the Amended and Restated Declaration of
Trust (the "Declaration") dated as of February 26, 1997,
completed a private placement (with certain shelf registration
rights) of 6 1/4%, $150,000 aggregate amount of Trust Convertible
Preferred Securities ("Trust Securities"). In addition, an
option to purchase an additional 600 Trust Securities, or $30,000
aggregate amount, was exercised by the initial purchasers to
cover over-allotments in connection with the placement. Each
Trust Security has a liquidation preference of fifty dollars and
is convertible at any time at the option of the holder into
1.1655 shares of Company Common Stock (equivalent to a conversion
price of $42.90 per common share) subject to adjustments in
certain circumstances.
On December 24, 1996 CE Electric, which is 70% owned indirectly
by the Company and 30% owned indirectly by PKS, acquired majority
ownership of the outstanding ordinary share capital of Northern
pursuant to the Tender Offer commenced in the United Kingdom by
CE Electric on November 5, 1996. Through January 31, 1997, CE
Electric had purchased more than 90% of Northern's ordinary
shares. Under United Kingdom statutory powers available to
compulsorily acquire shares not purchased in the tender offer, CE
Electric expects to acquire the remaining Northern shares by
April 30, 1997.
As of December 31, 1996, the Company had contributed to CE
Electric approximately $410,000 of the approximately $1,300,000
required to acquire all of Northern's ordinary and preference
shares in connection with the Tender Offer and PKS had
contributed approximately $176,000 to CE Electric for such
purpose. The Company obtained such funds from cash on hand,
short-term borrowings, and borrowings of approximately $100,000
under a $100,000 Credit Agreement entered into with Credit Suisse
on October 28, 1996 (the "CalEnergy Credit Facility"). As of
February 27, 1997, the Company had repaid the entire CalEnergy
Credit Facility through the use of proceeds of the $150,000 Trust
Securities offering. The remaining funds necessary to consummate
the Tender Offer will be provided from a 560,000 ($958,888) Term
Loan and Revolving Facility Agreement, dated as of October 28,
1996 (the "U.K. Credit Facility") with CE Electric. The Company
has not guaranteed, nor is it otherwise subject to recourse for,
amounts borrowed under the U.K. Credit Facility. As of January
31, 1997, CE Electric had borrowed approximately 321,000
($549,648) under the U.K. Credit Facility to pay for Northern
ordinary and preference shares purchased to date.
On October 4, 1996 the Company closed the $120,000 project
financing for the Dieng Unit I 55 net MW geothermal project
located in Indonesia. Dieng Unit I is already under construction
and is currently expected to begin commercial operation by late
1997.
On September 20, 1996 the Company completed a sale to
institutional investors of $225,000 aggregate principal amount of
its 9 1/2% Senior Notes due 2006.
Also on September 20, 1996 the Company converted the $64,850
convertible debt and associated accrued interest into 3,620
common shares at a conversion price of $18.375 per share. In
September and October, the Company converted substantially all of
the convertible subordinated debentures into 4,443 common shares
at a conversion price of $22.50 per share.
On July 8, 1996 the Company obtained a $100,000 three year
revolving credit facility of which the Company had drawn $95,000
as of December 31, 1996. Subsequent to year end, the Company had
repaid the entire outstanding balance. The facility is unsecured
and is available to fund general operating capital requirements
and finance future business opportunities.
On June 20, 1996 the Salton Sea Funding Corporation, a wholly
owned indirect subsidiary of the Company (the "Funding
Corporation"), completed a sale to institutional investors of
$135,000 aggregate amount of Senior Secured Notes and Bonds ("the
Notes and Bonds") which are nonrecourse to the Company. The
Funding Corporation Notes and Bonds which mature in May 2000 and
May 2011 respectively, bear an interest rate of 7.02% and 8.30%
respectively. The proceeds of the offering were used by Funding
Corporation to refinance $96,584 of existing project level
indebtedness at the Partnership Project, to fund a portion of the
Partnership Interest acquisition and for certain capital
improvements at the Imperial Valley Project.
On April 12, 1996 CalEnergy Capital Trust, a special purpose
Delaware business trust organized by the Company (the "Trust"),
completed a private placement (with certain shelf registration
rights) of $100,000 trust preferred convertible securities,
referred to as of Company-obligated mandatorily redeemable
convertible preferred securities of subsidiary trust holding
solely convertible debentures ("TIDES"). In addition, an option
to purchase an additional 78.6 TIDES, or $3,930, was exercised by
the initial purchasers to cover over-allotments in connection
with the placement.
In 1996, the Company signed an agreement with an international
mining company which provides for the extraction of minerals by
the mining company at the Imperial Valley Project and among other
things, for the Company, at its option, to deliver power for the
mineral extraction process. The initial phase of the project
would require at least 15 MW. A pilot plant has successfully
produced zinc at the Imperial Valley Project. Due to a failure
to reach agreement with the mining company on a satisfactory
partnership and development agreement for construction of a
larger extraction plant, the Company has determined to pursue the
mineral extraction project on its own or with other partners. If
successfully developed, the mineral extraction process will
provide an environmentally compatible and low cost minerals
recovery methodology.
In November 1995 the Company closed the financing and commenced
construction of the Casecnan Project, a combined irrigation and
150 net MW hydroelectric power generation project (the "Casecnan
Project") located in the central part of the island of Luzon in
the Republic of the Philippines.
CE Casecnan Water and Energy Company, Inc., a Philippine
corporation ("CE Casecnan") which is presently indirectly owned
as to approximately 35% of its equity by the Company and
approximately 35% by PKS, is developing the Casecnan Project
under the terms of the Project Agreement ("Project Agreement")
between CE Casecnan and the National Irrigation Administration
("NIA"). Under the Project Agreement, CE Casecnan will develop,
finance and construct the Casecnan Project over an estimated four-
year construction period, and thereafter own and operate the
Casecnan Project for 20 years (the "Casecnan Cooperation
Period"). During the Cooperation Period, NIA is obligated to
accept all deliveries of water and energy, and so long as the
Casecnan Project is physically capable of operating and
delivering in accordance with agreed levels set forth in the
Project Agreement, NIA will pay CE Casecnan a guaranteed fee for
the delivery of water and a guaranteed fee for the delivery of
electricity, regardless of the amount of water or electricity
actually delivered. In addition, NIA will pay a fee for all
electricity delivered in excess of a threshold amount up to a
specified amount. NIA will sell the electric energy it purchases
to the National Power Corporation of the Philippines ("NPC"),
although NIA's obligations to CE Casecnan under the Project
Agreement are not dependent on the purchase of the electricity
from NIA by NPC. All fees to be paid by NIA to CE Casecnan are
payable in U.S. dollars. The guaranteed fees for the delivery of
water and energy are expected to provide approximately 70% of CE
Casecnan's revenues.
The Project Agreement provides for additional compensation to CE
Casecnan upon the occurrence of certain events, including
increases in Philippine taxes and adverse changes in Philippine
law. Upon the occurrence and during the continuance of certain
force majeure events, including those associated with Philippines
political action, NIA may be obligated to buy the Casecnan
Project from CE Casecnan at a buy out price expected to be in
excess of the aggregate principal amount of the outstanding CE
Casecnan debt securities, together with accrued but unpaid
interest. At the end of the Casecnan Cooperation Period, the
Casecnan Project will be transferred to NIA and NPC for no
additional consideration on an "as is" basis.
The Republic of the Philippines has provided a Performance
Undertaking under which NIA's obligations under the Project
Agreement are guaranteed by the full faith and credit of the
Republic of the Philippines. The Project Agreement and the
Performance Undertaking provide for the resolution of disputes by
binding arbitration in Singapore under international arbitration
rules.
The Casecnan Project is being constructed on a joint and several
basis by Hanbo Corporation and Hanbo Engineering & Construction
Co. Ltd. (formerly known as You One Engineering & Construction
Co., Ltd., and herein referred to as "HECC"), both of which are
South Korean corporations, pursuant to a fixed-price, date-
certain, turnkey construction contract (the "Turnkey Construction
Contract"). Hanbo Corporation and HECC (sometimes collectively
referred to as the "Contractor") are under common ownership
control. Hanbo Corporation is an international construction
company. HECC, which recently emerged from a court-administered
receivership, is a contractor with over 25 years experience in
tunnel construction, using both the drill-and-blast and tunnel
boring machine ("TBM") methods.
The Contractor's obligations under the Turnkey Construction
Contract are guaranteed by Hanbo Iron & Steel Company, Ltd.
("Hanbo Steel"), a large South Korean steel company. In
addition, the Contractor's obligations under the Turnkey
Construction Contract are secured by an unconditional,
irrevocable standby letter of credit issued by Korea First Bank
("KFB") in the approximate amount of $118,000. The total cost of
the Casecnan Project, including development, construction,
testing and startup, is estimated to be approximately $495,000.
The current capital structure consists of term loans of $371,500
and $123,836 in equity contributions. The Company's portion of
the contributed equity is $61,918.
In late January 1997, the Company was advised that Hanbo
Corporation and Hanbo Steel had each filed to seek court
receivership protection in Korea. At the present time, all of
the construction work on the Casecnan Project is being performed
by the second contractor which is party to the Turnkey
Construction Contract, HECC. Although HECC, Hanbo Corporation
and Hanbo Steel are under common ownership control, HECC has not
filed for receivership protection and is believed to be solvent.
However, no assurances can be given that HECC will not file for
receivership due to the foregoing developments or that it will
remain solvent and able to perform fully its obligations under
the Turnkey Construction Contract.
The work on the Casecnan Project, which commenced in 1995, is
presently continuing on schedule and within the budget. CE
Casecnan is presently reviewing its rights, obligations and
potential remedies in respect of the recent developments
regarding the co-Contractor and the guarantor and is presently
unable to speculate as to the ultimate effect of such
developments on CE Casecnan. However, CE Casecnan has recently
received confirmation from HECC that it intends to fully perform
its obligations under the Turnkey Construction Contract and
complete the Casecnan Project on schedule and within the budget.
Additionally, it has been reported that the South Korean
government has informed the Philippine government that the South
Korean government will take appropriate actions to support HECC's
completion of the Casecnan Project.
KFB has recently reconfirmed to CE Casecnan that it will honor
its obligations under the Casecnan Project letter of credit and
also has stated its support for the successful completion of the
Casecnan Project. However, Moody's Investors Service has
recently issued a warning for a possible ratings downgrade for
KFB because of the possible impact of the Hanbo Steel
receivership on the substantial loans KFB previously made to
Hanbo Steel. In a related development, the South Korean
government has recently announced that it would provide some
funding to assist Hanbo Steel's creditor banks (including KFB)
and its subcontractors.
CE Casecnan financed a portion of the costs of the Casecnan
Project through the issuance of $125,000 of its 11.45% Senior
Secured Series A Notes due 2005 and $171,500 of its 11.95% Senior
Secured Series B Notes due 2010 pursuant to an indenture dated
November 27, 1995, as amended to date (the "Casecnan Indenture").
Although no default has occurred under the Casecnan Indenture as
a result of the announced receivership of Hanbo Corporation, CE
Casecnan will continue to closely monitor the Hanbo group and KFB
developments and project construction status and develop
appropriate contingency plans.
If HECC were to materially fail to perform its obligations under
the Turnkey Construction Contract and if KFB were to fail to
honor its obligations under the Casecnan letter of credit, such
actions could have a material adverse effect on the Casecnan
Project and CE Casecnan. However, based on the information
presently available to it, CE Casecnan does not presently expect
that either such event will occur.
In August 1994, the Company closed the financing for the 165 net
MW Mahanagdong Project located in the Philippines (the
"Mahanagdong Project"). The total project cost for the facility
is approximately $320,000. The capital structure consists of a
term loan of $240,000 and approximately $80,000 in equity
contributions. The Overseas Private Investment Corporation
("OPIC") and a consortium of international commercial lenders are
providing the construction debt financing facility. The debt
provided by the commercial lenders is insured against political
risk by the Export-Import Bank of the United States ("Ex-Im
Bank"). Ten year term debt financing (which will replace the
construction debt) will be provided by Ex-Im Bank and by OPIC. As
of December 31, 1996, the Company's proportionate share of draws
on the construction loan totaled $76,503 and equity investments
made by a subsidiary of the Company totaled $35,586. OPIC is
providing political risk insurance on the equity. The Mahanagdong
Project is targeted for service in July 1997. The Mahanagdong
Project is structured as a ten year build-own-operate-transfer
project ("BOOT"), in which the Company will be responsible for
implementing construction of the geothermal power plant and, as
owner, for providing operations and maintenance for the ten year
BOOT period. After a ten year cooperation period, and the
recovery by the Company of its capital investment plus
incremental return, the plant will be transferred to PNOC-Energy
Development Corporation ("PNOC-EDC") at no cost. The Mahanagdong
Project will be built, owned and operated by CE Luzon Geothermal
Power Company, Inc., a Philippine corporation, that is expected
to be owned post-completion as follows: 45% by the Company, 45%
by PKS, and up to 10% by another industrial company. The turnkey
contractor consortium consists of Kiewit Construction Group, Inc.
(with an 80% interest) and CE Holt Company, a wholly owned
subsidiary of the Company (with a 20% interest).
The electricity generated by the Mahanagdong Project will be sold
to PNOC-EDC, on a "take or pay" basis, which is also responsible
for supplying the facility with the geothermal steam. The terms
of the Mahanagdong Energy Conversion Agreement ("ECA") are
substantially similar to those of the Upper Mahiao ECA described
in Note 5 to the financial statements. All of PNOC-EDC's
obligations under the Mahangdong Energy Conversion Agreement
("ECA") are supported by the Government of the Philippines
through a performance undertaking. The capacity fees are expected
to be approximately 97% of total revenues at the design capacity
levels and the energy fees are expected to be approximately 3% of
such total revenues.
In 1994, the Company closed the financing and commenced
construction of the Malitbog Project, a 216 net MW geothermal
project, to be constructed in two phases, 72 net MW in 1996 and
144 net MW in 1997, located on the island of Leyte (the "Malitbog
Project"). The Malitbog Project is being built, and will be owned
and operated by Visayas Geothermal Power Company ("VGPC"), a
Philippine general partnership that is wholly owned, indirectly,
by the Company. Unit I of the Malitbog Project was "deemed
complete" by PNOC-EDC as of July 25, 1996, meaning that
construction of the first 72 net MW unit was completed on time
but the required transmission line was not completed and provided
to VGPC. During deemed completion, PNOC-EDC is required to pay,
and has in fact been paying (with respect to Unit I which has
been deemed completed), all capacity fees under the take or pay
provisions of the Malitbog ECA. VGPC is selling 100% of its
capacity to PNOC-EDC, which will in turn sell the power to the
NPC.
The Malitbog Project has a total project cost of approximately
$280,000, including interest during construction and project
contingency costs. A consortium of international banks and OPIC
have provided a total of $210,000 of construction and term loan
facilities, the $135,000 international bank portion of which is
supported by political risk insurance from OPIC. As of December
31, 1996, draws on the construction loan totaled $137,881 and
equity investments made by subsidiaries of the Company totaled
$70,000. The Company's equity participation is covered by
political risk insurance from OPIC. The Malitbog Project is
structured as a BOOT, in which the Company will be responsible
for implementing construction of the geothermal power plant and,
as owner, for providing operations and maintenance for the ten
year BOOT period.
Units II and III of the Malitbog Project are being constructed by
Sumitomo Corporation pursuant to a fixed-price, date-certain,
turnkey supply and construction contract. Commercial operation
of Units II and III are scheduled to commence prior to July 25,
1997.
The Malitbog Project is located on land provided by PNOC-EDC at
no cost. The electrical energy produced by the facility will be
sold to PNOC-EDC on a take-or-pay basis. Specifically, PNOC-EDC
is obligated to make payments (the "Capacity Payments") to VGPC
based upon the available capacity of the Malitbog Project. The
Capacity Payments equal approximately 100% of total revenues.
The Capacity Payments will be payable so long as the Malitbog
Project is available to produce electricity, even if the Malitbog
Project is not operating due to scheduled maintenance, because
PNOC-EDC fails to supply steam to the Malitbog Project as
required or because NPC is unable (or unwilling) to accept
delivery of electricity from the Malitbog Project. In addition,
PNOC-EDC must continue to make the Capacity Payments if there is
a force majeure event (e.g., war, nationalization, etc.) that
affects the operation of the Malitbog Project and that is within
the reasonable control of PNOC-EDC or the Government of the
Philippines or any agency or authority thereof. The Capacity
Payments are designed to cover, under expected operating
conditions, the Malitbog Project's operating and maintenance
expenses and VGPC's debt service and to provide a return on
investment to the partners in VGPC. A substantial majority of
the Capacity Payments are required to be made by PNOC-EDC in U.S.
dollars. The portion of Capacity Payments payable by PNOC-EDC in
pesos is expected to vary over the term of the Malitbog ECA from
10% of VGPC's revenues in the early years of the 10 year
cooperation period to 23% of VGPC's revenues at the end of the
cooperation period. Payments made in pesos will generally be made
to a peso-denominated account and will be used to pay peso-
denominated operation and maintenance expenses with respect to
the Malitbog Project and Philippine withholding taxes, if any, on
the Malitbog Project's debt service. The Government of the
Philippines has entered into a performance undertaking, which
provides that all of PNOC-EDC's obligations pursuant to the
Malitbog ECA carry the full faith and credit of, and are affirmed
and guaranteed by, the Government of the Philippines.
The Malitbog ECA cooperation period will expire ten years after
the date of commencement of commercial operation of Unit III. At
the end of the cooperation period, the facility will be
transferred to PNOC-EDC at no cost, on an "as is" basis.
On October 4, 1996 the Company closed the $120,000 project
financing for the Dieng Unit I 55 net MW geothermal project
located in Indonesia (the "Dieng Unit I Project"). The loan
carries a variable interest rate (weighted average of 7.19% at
December 31, 1996) and has scheduled project term repayments
through 2002. Dieng Unit I is under construction and is
currently expected to begin commercial operation by late 1997.
The Dieng Unit I Project has drawn $12,442 as of December 31,
1996.
Magma sought new long-term final SO4 power purchase agreements in
the Salton Sea area through the bidding process adopted by the
CPUC under its 1992 Biennial Resource Plan Update ("BRPU"). In
its BRPU, the California Public Utilities Commission ("CPUC")
cited the need for an additional 9,600 MW of power production
through 1999 among California's three investor-owned utilities,
Southern California Edison Company ("Edison"), San Diego Gas and
Electric ("SDG&E") and Pacific Gas and Electric Company. Of this
amount, 275 MW was set aside for bidding by independent power
producers (such as Magma) utilizing renewable resources. Pursuant
to an order of the CPUC dated June 22, 1994 (confirmed on
December 21, 1994), Magma was awarded 163 net MW for sale to
Edison and SDG&E, with in-service dates in 1997 and 1998. On
February 23, 1995 the Federal Energy Regulatory Commission
("FERC") issued an order finding that the CPUC's BRPU program
violated the Public Utilities Regulatory Policies Act ("PURPA")
and FERC's implementing regulations and recommended negotiated
settlements. In response, the CPUC issued an Assigned
Commissioners Ruling encouraging settlements between the final
winning bidders and the utilities. The utilities are expected to
continue to challenge the BRPU and, in light of the regulatory
uncertainty, there can be no assurance that power sales contracts
will be executed or that any such projects will be completed. In
light of these developments, the Company agreed to execute an
agreement with Edison on March 16, 1995 providing that in certain
circumstances it would withdraw its Edison BRPU bid in
consideration for the payment of certain sums. In December,
1996, the Company entered into a confidential cash buyout
agreement with SDG&E. These agreements are subject to CPUC
approval.
The Company is actively seeking to develop, construct, own and
operate new power projects utilizing geothermal and other
technologies, both domestically and internationally, the
completion of any of which is subject to substantial risk. The
Company has in development or under construction, projects
representing an aggregate generating capacity in excess of the
generating capacity of those currently in operation. Development
can require the Company to expend significant sums for
preliminary engineering, permitting, fuel supply, resource
exploration, legal and other expenses in preparation for
competitive bids which the Company may not win or before it can
be determined whether a project is feasible, economically
attractive or capable of being financed. Successful development
and construction is contingent upon, among other things,
negotiation on terms satisfactory to the Company of engineering,
construction, fuel supply and power sales contracts with other
project participants, receipt of required governmental permits
and consents and timely implementation of construction. Further,
there can be no assurance that the Company, which is
substantially leveraged, will obtain access to the substantial
debt and equity capital required to continue to develop and
construct electric power projects or to refinance projects. The
Company's future growth is dependent, in large part, upon the
demand for significant amounts of additional electrical
generating capacity and its ability to obtain contracts to supply
portions of this capacity. There can be no assurance that
development efforts on any particular project, or the Company's
efforts generally, will be successful.
The Company believes that the international independent power
market holds the majority of new opportunities for financially
attractive private power development in the next several years.
The financing, construction and development of projects outside
the United States entail significant political and financial
risks (including, without limitation, uncertainties associated
with first time privatization efforts in the countries involved,
currency exchange rate fluctuations, currency repatriation
restrictions, political instability, civil unrest and
expropriation) and other structuring issues that have the
potential to cause substantial delays or material impairment of
value to the project being developed, which the Company may not
be fully capable of insuring against. The uncertainty of the
legal environment in certain foreign countries in which the
Company may develop or acquire projects could make it more
difficult for the Company to enforce its rights under agreements
relating to such projects. In addition, the laws and regulations
of certain countries may limit the ability of the Company to hold
a majority interest in some of the projects that it may develop
or acquire. The Company's international projects may, in certain
cases, be terminated by a government. Projects in operation,
construction and development are subject to a number of
uncertainities, more specifically described in the Company's Form
8-K dated February 25, 1997, filed with the Securities and
Exchange Commission.
Inflation has not had a substantial impact on the Company's
operating revenues and costs; energy payments for electricity for
the Coso Project, Partnership Project, Salton Sea II Project and
Salton Sea III Project will continue to be based upon scheduled
rates and are not adjusted for inflation through the initial ten
year period of each power purchase agreement.
CONSOLIDATED BALANCE SHEETS
As of December 31, 1996 and 1995
Dollars and Shares in Thousands Except Per Share Amounts
ASSETS 1996 1995
Cash and cash equivalents $ 424,500 $ 72,114
Joint venture cash and investments 48,083 77,590
Restricted cash 107,143 149,227
Short-term investments 4,921 34,190
Accounts receivable 342,307 57,909
Due from joint ventures 17,556 27,273
Properties, plants, contracts and
equipment, net 3,348,583 1,781,255
Excess of cost over fair value of
net assets acquired, net 790,920 302,288
Equity investments 196,535 60,815
Deferred charges and other assets 432,359 91,377
Total assets $5,712,907 $2,654,038
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable $218,182 $ 6,638
Other accrued liabilities 674,842 87,892
Parent company debt 1,146,685 842,205
Subsidiary and project debt 1,754,895 921,219
Deferred income taxes 469,199 226,520
Total liabilities 4,263,803 2,084,474
Deferred income 29,067 26,032
Commitments and contingencies (Notes 3, 17, 18, 19 and 20)
Company - obligated mandatorily redeemable
convertible preferred securities of
subsidiary trust holding solely
convertible debentures 103,930 ---
Preferred securities of subsidiary 136,065 ---
Minority interest 299,252 ---
Stockholders' equity:
Preferred stock - authorized 2,000
shares, no par value --- ---
Common stock - par value $.0675 per share,
authorized 80,000 shares, issued 63,747
and 50,680 shares, outstanding 63,448
and 50,593 shares, respectively 4,303 3,421
Additional paid in capital 563,567 343,406
Retained earnings 297,520 205,059
Cumulative effect of foreign currency
translation adjustment 29,658 ---
Treasury stock - 299 and 87 common
shares at cost (8,787) (1,348)
Unearned compensation - restricted stock (5,471) (7,006)
Total stockholders' equity 880,790 543,532
Total liabilities and stockholders'
equity $5,712,907 $2,654,038
The accompanying notes are an integral part of these financial
statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Years Ended December 31, 1996
Dollars and Shares in Thousands Except Per Share Amounts
1996 1995 1994
Revenue:
Sales of electricity and steam $518,934 $335,630 $154,562
Income on equity investments 6,134 --- ---
Royalty income 6,846 19,482 ---
Interest and other income 44,281 43,611 31,292
Total revenues 576,195 398,723 185,854
Cost and expenses:
Operating expense 108,962 79,294 33,015
Cost of sales 31,840 --- ---
General and administration 21,451 23,376 13,012
Royalty expense 23,693 24,308 9,888
Depreciation and amortization 118,586 72,249 21,197
Loss on equity investment in Casecnan 5,221 362 ---
Interest expense 165,900 134,637 62,837
Less interest capitalized (39,862) (32,554) (9,931)
Dividends on convertible preferred
securities of subsidiary trust 4,691 --- ---
Total expenses 440,482 301,672 130,018
Income before provision for
income taxes 135,713 97,051 55,836
Provision for income taxes 41,821 30,631 17,002
Income before extraordinary item 93,892 66,420 38,834
Extraordinary item --- --- (2,007)
Income before minority interest
and preferred dividends 93,892 66,420 36,827
Minority interest 1,431 3,005 ---
Net income 92,461 63,415 36,827
Preferred dividends --- 1,080 5,010
Net income available to common
stockholders $92,461 $62,335 $31,817
Income per share before
extraordinary item $ 1.60 $ 1.25 $ .95
Extraordinary item --- --- (.06)
Net income per share - primary $1.60 $1.25 $ .89
Net income per share - fully diluted $1.50 $1.18 $ .88
Average number of shares
outstanding - primary 57,870 49,971 35,721
Fully diluted shares 67,164 57,742 40,166
The accompanying notes are an integral part of these financial
statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended December 31, 1996
Dollars and Shares in Thousands
Outstanding Additional
Foreign
Common Common Paid-In
Retained Currency Treasury Unearned
Shares Stock Capital
Earnings Adjust. Stock Compensation Total
Balance December 31, 1993 35,446 $2,404 $100,965 $111,031
$ --- $(2,897) $ --- $211,503
Exercise of stock options 46 3 379 ---
- - - - --- --- --- 382
Purchase of treasury stock (3,765) --- --- ---
- - - - --- (65,119) --- (65,119)
Exercise of stock options
from treasury stock 96 --- (1,473) ---
- - - - --- 1,772 --- 299
Employee stock purchase plan
issues from treasury stock 26 --- (122) ---
- - - - --- 470 --- 348
Preferred stock dividends,
Series C, including cash
distribution of $121 --- --- --- (4,921)
- - - - --- --- --- (4,921)
Tax benefit from stock plan --- --- 672 ---
- - - - --- --- --- 672
Net income before preferred
dividends --- --- --- 36,827
- - - - --- --- --- 36,827
Balance December 31, 1994 31,849 2,407 100,421 142,937
- - - - --- (65,774) --- 179,991
Equity offering 18,170 1,004 240,825 ---
- - - - --- 56,801 --- 298,630
Exercise of stock options 102 7 303 ---
- - - - --- --- --- 310
Restricted stock 500 --- 848 ---
- - - - --- 8,652 (9,500) ---
Amortization of unearned
compensation --- --- --- ---
- - - - --- --- 2,494 2,494
Employee stock purchase
plan issues 41 3 559 ---
- - - - --- --- --- 562
Exercise of stock options
from treasury stock 33 --- (416) ---
- - - - --- 563 --- 147
Purchase of treasury stock (102) --- --- ---
- - - - --- (1,590) --- (1,590)
Preferred stock dividends,
Series C, including cash
distribution of $43 --- --- --- (1,293)
- - - - --- --- --- (1,293)
Tax benefit from stock plan --- --- 866 ---
- - - - --- --- --- 866
Net income before preferred
dividends --- --- --- 63,415
- - - - --- --- --- 63,415
Balance December 31, 1995 50,593 3,421 343,406 205,059
- - - - --- (1,348) (7,006) 543,532
Exercise of stock options and
other equity transactions 4,971 335 57,190 ---
- - - - --- 1 --- 57,526
Amortization of unearned
compensation --- --- --- ---
- - - - --- --- 1,535 1,535
Employee stock purchase plan
issues 60 2 547 ---
- - - - --- 588 --- 1,137
Exercise of stock options
from treasury stock 232 --- (4,707) ---
- - - - --- 3,980 --- (727)
Purchase of treasury stock (472) --- --- ---
- - - - --- (12,008) --- (12,008)
Conversion of debt 8,064 545 164,912 ---
- - - - --- --- --- 165,457
Tax benefit from stock plan --- --- 2,219 ---
- - - - --- --- --- 2,219
Foreign currency translation
adjustment --- --- --- ---
29,658 --- --- 29,658
Net income --- --- --- 92,461
- - - - --- --- --- 92,461
Balance December 31, 1996 63,448 $4,303 $563,567 $297,520
$29,658 $(8,787) $(5,471) $880,790
The accompanying notes are an integral part of these financial
statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Years Ended December 31, 1996
Dollars in Thousands
1996
1995 1994
Cash flows from operating activities:
Net income $92,461 $
63,415 $ 36,827
Adjustments to reconcile net cash flow from operating activities:
Depreciation and amortization 109,447
65,244 21,197
Amortization of excess of cost over fair
value of net assets acquired 9,139
7,005 ---
Amortization of original issue discount 50,194
45,409 31,946
Amortization of deferred financing costs 9,677
8,979 1,885
Amortization of unearned compensation 1,535
2,494 ---
Provision for deferred income taxes 12,252
13,983 8,258
Loss (income) on equity investments (910)
362 ---
Income applicable to minority interest 1,431
3,005 ---
Changes in other items:
Accounts receivable (13,936)
213 (6,614)
Accounts payable and other accrued liabilities (942)
5,922 19,364
Deferred income 3,035
6,181 (437)
Net cash flows from operating activities 273,383
222,212 112,426
Cash flows from investing activities:
Purchase of Northern, Falcon Seaboard, Partnership
Interest and Magma, net of cash acquired (474,443)
(907,614) (3,043)
Distributions from equity investments 8,222
- - - - --- ---
Capital expenditures relating to operating
projects (24,821)
(27,120) (38,078)
Philippine construction (167,160)
(289,655) (69,997)
Indonesian and other development (81,068)
(8,973) (2,445)
Salton Sea IV construction (63,772)
(62,430) ---
Pacific Northwest, Nevada, and Utah
exploration costs (4,885)
(10,445) (8,493)
Decrease (increase) in short-term investments 33,998
80,565 (50,000)
Decrease (increase) in restricted cash 63,175
(17,452) (83,670)
Other (2,591)
11,514 1,847
Investment in Casecnan ---
(61,177) ---
Net cash flows from investing activities
(713,345)(1,292,787)(253,879)
Cash flows from financing activities:
Proceeds from sale of common and treasury stock
and exercise of stock options 54,935
299,649 1,580
Proceeds from convertible preferred securities
of subsidiary trust 103,930
- - - - --- ---
Proceeds from issuance of parent company debt 324,136
200,000 400,000
Net proceeds from revolver 95,000
- - - - --- ---
Proceeds from subsidiary and project debt 428,134
654,695 31,503
Repayments of subsidiary and project debt (210,892)
(176,664) (13,800)
Deferred charges relating to debt financing (36,010)
(34,733) (11,905)
Decrease (increase) in amounts due from
joint ventures 10,756
(29,169) 316
Purchase of treasury stock (12,008)
(1,590) (65,119)
Proceeds from merger facility ---
500,000 ---
Recapitalization of merger facility ---
(500,000) ---
Defeasance of 12% senior notes ---
- - - - --- (35,730)
Net cash flows from financing activities 757,981
912,188 306,845
Effect of exchange rate changes 4,860
- - - - --- ---
Net increase (decrease) in cash and investments 322,879
(158,387) 165,392
Cash and cash equivalents at beginning of period 149,704
308,091 142,699
Cash and cash equivalents at end of period $472,583
$149,704 $308,091
Supplemental Disclosures:
Interest paid (net of amounts capitalized) $ 92,829 $
50,840 $ 12,624
Income taxes paid $ 23,211 $
14,812 $ 4,926
See note 6 regarding conversion of debt to equity.
The accompanying notes are an integral part of these financial
statements.
NOTES Consolidated Financial Statements
For the Three Years Ended December 31, 1996
Dollars and Shares in Thousands, Except Per Share Amounts
1. Business
CalEnergy Company, Inc. (the "Company") is a United States-
based
global power company which generates, distributes and
supplies
electricity to utilities, government entities, retail customers
and
other customers located throughout the world. The Company was
founded
in 1971 and through its subsidiaries is primarily engaged in
the
development, ownership and operation of environmentally
responsible
independent power production facilities worldwide utilizing
geothermal
resources, natural gas and hydroelectric or other energy sources,
such
as oil and coal. In addition, through its recently
acquired
subsidiary, Northern, the Company is engaged in the distribution
and
supply of electricity to approximately 1.5 million customers
primarily
in northeast England as well as the generation and
supply of
electricity (together with other related business
activities)
throughout England and Wales.
The Company has organized several partnerships and joint
ventures
(herein referred to as the "Coso Joint Ventures") in order to
develop
geothermal energy at the China Lake Naval Air Weapons Station,
Coso
Hot Springs, China Lake, California. Collectively, the
projects
undertaken by these Coso Joint Ventures are referred to as the
Coso
Project. In 1992, the Company entered into the natural gas-
fired
electrical generation market through the purchase of a
development
opportunity in Yuma, Arizona which commenced commercial
operation in
May 1994. In 1993, the Company started developing a
number of
international power project opportunities where private
power
generating programs have been initiated, including the
Philippines and
Indonesia. In 1995, the Company acquired Magma Power
Company
("Magma"). Magma's operating assets included four projects
referred to
as the Partnership Project in which Magma had a 50% interest,
and
three projects referred to as the Salton Sea Project of which
Magma
owned 100%. A fourth project included in the Salton Sea Project
was
constructed after the acquisition of Magma and commenced
operations in
June 1996. In addition, in April 1996, the Company acquired
the
remaining 50% interest in the Partnership Project. In August
1996,
the Company acquired Falcon Seaboard Resources, Inc.
("Falcon
Seaboard") which includes significant interests in three
operating gas-
fired cogeneration facilities and a related natural gas pipeline.
On
December 24, 1996, CE Electric UK plc ("CE Electric"), which is
70%
owned indirectly by the Company and 30% owned indirectly by
Peter
Kiewit Sons', Inc. ("PKS"), acquired majority ownership of
the
outstanding ordinary share capital of Northern pursuant to a
tender
offer ("Tender Offer"). The total amount expected to be paid for
all
of Northern's ordinary and preference shares is approximately
$1.3
billion.
Northern is one of the twelve regional electric companies
("RECs")
which came into existence as a result of the restructuring
and
subsequent privatization of the electricity industry in the
United
Kingdom in 1990. Northern is primarily engaged in the
distribution
and supply of electricity. Northern was granted a Public
Electricity
Supply ("PES") license under the Electricity Act to distribute
and
supply electricity in Northern's Authorized Area ("Authorized
Area").
Northern's Authorized Area covers approximately 14,400
square
kilometers with a population of approximately 3.2 million people
and
includes the counties of Northumberland, Tyne and Wear,
Durham,
Cleveland and North Yorkshire. Northern distributes and
supplies
electricity outside its Authorized Area pursuant to second tier
PES
licenses. Northern also is involved in non-regulated
activities,
including the generation of electricity, electrical
appliance
retailing and gas exploration and production.
2. Summary of Significant Accounting Policies
The consolidated financial statements include the accounts of
the
Company, its wholly-owned subsidiaries, and its proportionate
share of
the partnerships and joint ventures in which it has an
undivided
interest in the assets and is proportionally liable for its
share of
liabilities. Other investments and corporate joint ventures
where the
Company has the ability to exercise significant influence
are
accounted for under the equity method of accounting.
Investments,
where the Company's ability to influence is limited, are
accounted for
under the cost method of accounting. All significant inter-
enterprise
transactions and accounts have been eliminated. The
results of
operations of the Company include the Company's proportionate
share of
results of operations of entities acquired as of the date of
each
acquisition.
Investments and Restricted Cash
Investments other than restricted cash are primarily commercial
paper
and money market securities. The restricted cash balance includes
such
securities and mortgage backed securities, and is mainly
composed of
amounts deposited in restricted accounts from which the Company
will
source its equity contributions and debt service reserve
requirements
relating to the projects. These funds are restricted by
their
respective project debt agreements to be used only for the
related
project.
At December 31, 1996, all of the Company's investments are
classified
as held-to-maturity and are accounted for at their amortized
cost
basis. The carrying amount of the investments approximates the
fair
value based on quoted market prices as provided by the
financial
institution which holds the investments.
Well, Resource Development and Exploration Costs
The Company follows the full cost method of accounting for
costs
incurred in connection with the exploration and
development of
geothermal resources. All such costs, which include dry hole
costs and
the cost of drilling and equipping production wells and
directly
attributable administrative and interest costs, are capitalized
and
amortized over their estimated useful lives when production
commences.
The estimated useful lives of production wells are ten to twenty
years
depending on the characteristics of the underlying
resource;
exploration costs and development costs, other than production
wells,
are generally amortized over the weighted average remaining
term of
the Company's power and steam purchase contracts.
Deferred Well and Rework Costs
Well rework costs are deferred and amortized over the estimated
period
between reworks. These deferred costs, net of
accumulated
amortization, are $8,371 and $7,086 at December 31, 1996 and
1995,
respectively, and are included in other assets.
Properties, Plants, Contracts, Equipment and Depreciation
The cost of major additions and betterments are capitalized,
while
replacements, maintenance, and repairs that do not improve or
extend
the lives of the respective assets are expensed.
Depreciation of the operating power plant costs, net of salvage
value,
is computed on the straight-line method over the estimated
useful
lives, between 10 and 30 years. Depreciation of furniture,
fixtures
and equipment which are recorded at cost, is computed on the
straight
line method over the estimated useful lives of the related
assets,
which range from three to ten years.
The Northern, Falcon Seaboard, Partnership Interest and
Magma
acquisitions by the Company have been accounted for as
purchase
business combinations. All identifiable assets acquired
and
liabilities assumed were assigned a portion of the cost of
acquiring
the respective companies equal to their fair values at the date
of the
acquisition and include the following:
Property and equipment of Northern is depreciated using a
systematic
method, which approximates the straight line method over the
estimated
useful lives of the related assets which range from 1-40 years.
Northern's investment in Teesside Power Limited is being
amortized
over the remaining contract life of 11 years using a straight
line
method.
Power sales agreements are amortized separately over (1) the
remaining
portion of the scheduled price periods of the power sales
agreements
and (2) for the Partnership Interest and Magma acquisitions
the 20
year avoided cost periods of the power sales agreements using
the
straight line method.
Mineral reserves are amortized on the units of production method.
Excess of Cost over Fair Value
Total acquisition costs in excess of the fair values assigned to
the
net assets acquired are amortized over a 40 year period for
the
Northern and Magma acquisitions and a 25 year period for the
Falcon
Seaboard acquisition, both using the straight line method.
Capitalization of Interest and Deferred Financing Costs
Prior to the commencement of operations, interest is
capitalized on
the costs of the plants and geothermal resource development to
the
extent incurred. Capitalized interest and other deferred charges
are
amortized over the lives of the related assets.
Deferred financing costs are amortized over the term of the
related
financing using the implicit interest method.
Revenue Recognition
Revenues are recorded based upon service rendered and electricity
and
steam delivered to the end of the month. Royalties earned
from
providing geothermal resources to power plants operated by
other
geothermal power producers are recorded on an accrual basis.
Deferred Income Taxes
The Company recognizes deferred tax assets and liabilities
based on
the difference between the financial statement and tax bases of
assets
and liabilities using estimated tax rates in effect for the
year in
which the differences are expected to reverse. The Company
intends to
repatriate earnings of foreign subsidiaries in the foreseeable
future.
As a result, deferred income taxes are provided for retained
earnings
of international subsidiaries and corporate joint ventures which
are
intended to be remitted.
Fair Values of Financial Instruments
The following methods and assumptions were used by the
Company in
estimating fair values of financial instruments as discussed
herein.
Fair values have been estimated based on quoted market prices for
debt
issues listed on exchanges. Fair values of financial instruments
that
are not actively traded are based on market prices of
similar
instruments and/or valuation techniques using market assumptions.
The Company assumes that the carrying amount of short-term
financial
instruments approximates their fair value. For these purposes,
short-
term is defined as any item that matures, reprices, or
represents a
cash transaction between willing parties within six months or
less of
the measurement date.
Net Income per Common Share
Primary and fully diluted earnings per common share are based on
the
weighted average number of common and dilutive common
equivalent
shares outstanding during the period computed using the treasury
stock
method. Fully diluted earnings per common share also assumes
the
conversion at the beginning of the year of the convertible debt
into
3,529 common shares at a conversion price of $18.375 per share,
the
conversion at the beginning of the year of the
convertible
subordinated debentures into 4,444 common shares at a conversion
price
of $22.50 per share, the convertible preferred securities
of
subsidiary into 3,477 common shares at a conversion price of
$29.89
per share and the exercise of all dilutive stock options
outstanding
at their option prices, with the option exercise proceeds
used to
repurchase shares of common stock at the ending market price for
fully
diluted earnings per share. For primary earnings per share,
shares of
common stock are assumed to be repurchased at the average price
for
the period.
Cash Equivalents
The Company considers all investment instruments purchased
with an
original maturity of three months or less to be cash
equivalents.
Restricted cash is not considered a cash equivalent.
Impairment of Long-Lived Assets
On January 1, 1996, the Company adopted Statement of
Financial
Accounting Standards No. 121 ("SFAS 121"), "Accounting for
the
Impairment of Long-Lived Assets and for Long-Lived Assets
to be
Disposed Of" which requires that long-lived assets and
certain
identifiable intangibles be reviewed for impairment whenever
events or
changes in circumstances indicate that the carrying amount of an
asset
may not be recoverable. The adoption of SFAS 121 did not
have a
material effect on the Company's financial statements.
Reclassification
Certain amounts in the fiscal 1995 and 1994 financial statements
and
supporting footnote disclosures have been reclassified to
conform to
the fiscal 1996 presentation. Such reclassification did not
impact
previously reported net income or retained earnings.
Use of Estimates
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.
3. Acquisitions
Northern
On December 24, 1996, CE Electric, which is 70% owned
indirectly by
the Company and 30% owned indirectly by PKS, acquired
majority
ownership of the outstanding ordinary share capital of
Northern
pursuant to the Tender Offer. Through January 31, 1997, CE
Electric
had purchased more than 90% of Northern's ordinary shares.
Under
United Kingdom statutory procedures available to compulsorily
acquire
shares not purchased in the Tender Offer, CE Electric
expects to
acquire the remaining Northern ordinary shares by April 30, 1997.
As of December 31, 1996, the Company and PKS had contributed
to CE
Electric approximately $410,000 and $176,000 respectively, of
the
approximately $1,300,000 required to acquire all of
Northern's
ordinary and preference shares in connection with the Tender
Offer.
The Company obtained such funds from cash on hand, short-
term
borrowings, and borrowings of approximately $100,000 under a
Credit
Agreement entered into with Credit Suisse on October 28, 1996
(the
"CalEnergy Credit Facility"). The remaining funds
necessary to
consummate the Tender Offer will be provided from a 560,000
($958,888)
Term Loan and Revolving Facility Agreement, dated October 28,
1996
(the "U.K. Credit Facility").
The Northern acquisition has been accounted for as a purchase
business
combination. All identifiable assets acquired and liabilities
assumed
were assigned a portion of the cost of acquiring Northern,
equal to
their fair values at the date of the acquisition. Minority
interest
is recorded at historical cost. The total cost of the
acquisition
through December 31, 1996 was allocated as follows:
Cash $ 200,399
Properties, plants and equipment 1,101,860
Other assets 541,554
Northern project debt (447,119)
Accounts payable (213,710)
Accrued liabilities (606,525)
Minority interest (297,821)
Preferred securities (136,065)
Excess of cost over fair value of
net assets acquired, net of
deferred taxes of $129,493 267,648
$ 410,221
In 1993, Northern entered into a contract relating to the
purchase of
400 MW of capacity from a 15.4% owned related party, Teesside
Power
Limited ("Teesside"), for a period of 15 years beginning
April 1,
1993. The contract sets escalating purchase prices at
predetermined
levels. Currently the escalating contract prices exceed those
paid by
the Company to the electricity pool (the "Pool") which is
operated by
the National Grid Group. However, under current price cap
regulation
expected to expire March 31, 1998 the Company is able to recover
these
costs. For the period after March 31, 1998, the Company
has
established a liability for the estimated loss as a result of
this
contract.
Northern utilizes contracts for differences ("CFDs") to mitigate
its
exposure to volatility in the prices of electricity purchased
through
the Pool. Such contracts allow the Company to effectively
convert the
majority of its anticipated Pool purchases from market to
fixed
prices. As of December 31, 1996, CFDs were in place to
hedge a
portion of electricity purchases of approximately 55,000 GWh
through
the year 2008.
The Labour Party has asserted that if they are elected at the
next
General Election, which must be held no later than May 22, 1997,
they
will seek to introduce a "windfall" assessment to be levied on
the
privatized utilities including Northern. The Company has
established
a liability for such an assessment as part of its purchase
accounting
reserves.
The preferred securities reflect the fair value of the
outstanding
preferred stock of Northern.
Falcon Seaboard
On August 7, 1996 the Company completed the acquisition of
Falcon
Seaboard for a cash price of $229,500 including acquisition
costs.
Through the acquisition, the Company indirectly acquired
significant
ownership interests in three operating gas-fired
cogeneration
facilities and a related natural-gas pipeline. The plants
are
located in Texas, Pennsylvania and New York and total 520
MW in
capacity.
The Falcon Seaboard acquisition has been accounted for as a
purchase
business combination. All identifiable assets acquired
and
liabilities assumed were assigned a portion of the cost of
acquiring
Falcon Seaboard, equal to their fair values at the date of
the
acquisition. The total cost of the acquisition was
allocated as
follows:
Cash $ 22,923
Operating facilities 141,176
Power sales agreements 23,282
Equity investments 144,656
Other assets 27,229
Project loans (119,478)
Other liabilities (15,527)
Excess of cost over fair value of
net assets acquired, net of
deferred taxes of $93,279 5,239
$ 229,500
Edison Mission Energy's Partnership Interest
On April 17, 1996 the Company completed the acquisition of
Edison
Mission Energy's Partnership Interests in four geothermal
operating
facilities in California for a cash purchase price of
$71,000
including acquisition costs. The four projects, Vulcan, Hoch
(Del
Ranch), Leathers and Elmore, are located in the Imperial
Valley of
California. Prior to this transaction, the Company was a 50%
owner of
these facilities.
The Partnership Interest acquisition has been accounted for
as a
purchase business combination. All identifiable assets acquired
and
liabilities assumed were assigned a portion of the cost of
acquiring
the Partnership Interest, equal to their fair values at the
date of
the acquisition. The total cost of the acquisition was
allocated as
follows:
Cash $ 12,956
Restricted cash 13,226
Power sales agreements 78,036
Other assets 20,254
Project loans (48,161)
Liabilities (5,311)
$ 71,000
Magma Power Company
On January 10, 1995, the Company acquired approximately 51% of
the
outstanding shares of common stock of Magma (the "Magma Common
Stock")
through a cash tender offer (the "Magma Tender Offer") and
completed
the Magma acquisition on February 24, 1995 by acquiring
the
approximately 49% of the outstanding shares of Magma Common Stock
not
owned by the Company through a merger.
The Magma acquisition has been accounted for as a purchase
business
combination. All identifiable assets acquired and liabilities
assumed
were assigned a portion of the cost of acquiring Magma, equal to
their
fair values at the date of the acquisition. The total cost of
the
acquisition was allocated as follows:
Cash $ 62,116
Operating facilities and project cash 291,365
Power sales agreements 173,730
Mineral reserves 160,768
Construction in progress 93,174
Process license and other 39,304
Excess of cost over fair value of net assets
acquired, net of deferred taxes of $168,914 137,455
$957,912
Unaudited pro forma combined revenue, net income and primary
earnings
per share of the Company, Northern, Falcon Seaboard, the
Partnership
Interest and Magma for the twelve months ended December 31, 1996
and
1995, as if the acquisitions had occurred at the beginning of
1995
after giving effect to certain pro forma adjustments related to
the
acquisition were $2,162,381, $64,811 and $1.12, compared
to
$2,006,496, $53,887 and $1.02, respectively.
4.Properties, Plants, Contracts and Equipment
Properties, plants, contracts and equipment comprise the
following at
December 31:
1996 1995
Operating project costs:
Power plants and distribution system $2,361,089
$623,778
Wells and resource development 391,929
329,414
Power sales agreements 232,228
188,415
Licenses, equipment, wells and resource
development in progress 66,207
58,517
Total operating facilities 3,051,453
1,200,124
Less accumulated depreciation and amortization (271,216)
(164,184)
Net operating facilities 2,780,237
1,035,940
Mineral reserves 207,424
212,929
Construction in progress:
Malitbog 152,411
146,735
Mahanagdong 123,567
76,560
Other international development 84,944
11,418
Upper Mahiao ---
188,904
Salton Sea IV ---
108,769
Total $3,348,583
$1,781,255
Coso Project Operating Facilities
The Coso Project operating facilities comprise the
Company's
proportionate share of the assets of three of its Coso Joint
Ventures:
Coso Finance Partners ("Navy I Joint Venture"), Coso Energy
Developers
("BLM Joint Venture"), and Coso Power Developers ("Navy II
Joint
Venture"). The Navy I power plant is located on land owned by
and
leased from the U.S. Navy to December 2009, with a 10 year
extension
at the option of the Navy. Under terms of the Navy I Joint
Venture,
profits and losses were allocated approximately 49% before
payout of
Units 2 and 3 and approximately 46.4% thereafter to the Company.
As of
December 31, 1994, payout had been reached on Units 2 and 3 of
the
Navy I Joint Venture. The BLM power plant is situated on lands
leased
from the U.S. Bureau of Land Management under a geothermal
lease
agreement that extends until October 31, 2035. The lease
may be
extended to 2075 at the option of the BLM. Under the terms of the
BLM
Joint Venture agreement, the Company's share of profits and
losses
before and after payout is approximately 45% and 48%,
respectively.
The BLM Joint Venture reached payout in June 1994. Under terms
of the
Navy II Joint Venture, all profits, losses and capital
contributions
for Navy II are divided equally by the two partners.
Imperial Valley Project Operating Facilities
The Company currently operates eight geothermal power plants in
the
Imperial Valley in California. Four of these plants were
developed by
Magma. The Partnership Project consists of the Vulcan, Hoch
(Del
Ranch), Elmore, and Leathers Partnerships. The remaining four
plants
which comprise the Salton Sea Project are indirect wholly
owned
subsidiaries of the Company, three of which were purchased by
Magma on
March 31, 1993 from Union Oil Company of California and the
fourth
which was completed by the Company in June 1996. These
geothermal
power plants consist of the Salton Sea I, Salton Sea II, Salton
Sea
III and the Salton Sea IV. The Partnership Project and the
Salton Sea
Project are collectively referred to as the Imperial Valley
Project.
The Imperial Valley Project commencement dates and nominal
capacities
are as follows:
Imperial Valley Commencement
Nominal
Plants Date
Capacity
Vulcan February 10, 1986 34
MW
Hoch (Del Ranch) January 2, 1989 38
MW
Elmore January 1, 1989 38
MW
Leathers January 1, 1990 38
MW
Salton Sea I July 1, 1987 10
MW
Salton Sea II April 5, 1990 20
MW
Salton Sea III February 13, 1989
49.8 MW
Salton Sea IV May 24, 1996
39.6 MW
Significant Customers and Contracts
All of the Company's sales of electricity from the Coso Project
and
Imperial Valley Project, which comprise approximately 77% of
1996
electricity and steam revenues, are to Edison and are under long-
term
power purchase contracts.
The Coso Project and the Partnership Project sell all
electricity
generated by the respective plants pursuant to seven long-term
SO4
Agreements between the projects and Edison. These SO4
Agreements
provide for capacity payments, capacity bonus payments and
energy
payments. Edison makes fixed annual capacity payments to the
projects
and, to the extent that capacity factors exceed certain
benchmarks, is
required to make capacity bonus payments. The price for capacity
and
capacity bonus payments is fixed for the life of the SO4
Agreements.
Energy is sold at increasing scheduled rates for the first ten
years
after firm operation and thereafter at Edison's Avoided
Cost of
Energy.
The scheduled energy price periods of the Coso Project SO4
Agreements
extend until at least August 1997, March 1999 and January 2000
for
each of the units operated by the Navy I, BLM and Navy
II
Partnerships, respectively. The Company's share of the annual
capacity
payments is approximately $5,600 to $5,900 per annum for each
plant.
The Company's share of bonus payments is approximately $1,000
per
annum for each plant.
The scheduled energy price periods of the Partnership Project
SO4
Agreements extended until February 1996 for the Vulcan
Partnership and
extend until December 1998, December 1998, and December 1999 for
each
of the Hoch (Del Ranch), Elmore and Leathers
Partnerships,
respectively. The annual capacity payments are approximately
$24,500
and the bonus payments are approximately $4,400 in aggregate for
the
four plants.
Excluding Vulcan, which is receiving Edison's Avoided Cost of
Energy,
the Company's SO4 Agreements provide for energy rates ranging
from
12.6> per kWh in 1996 to 15.6> per kWh in 1999. The weighted
average
energy rate for all of the Company's SO4 Agreements was 11.7> per
kWh
in 1996.
Salton Sea I sells electricity to Edison pursuant to a 30-
year
negotiated power purchase agreement, as amended (the "Salton
Sea I
PPA"), which provides for capacity and energy payments. The
energy
payment is calculated using a Base Price which is subject to
quarterly
adjustments based on a basket of indices. The time period
weighted
average energy payment for Salton Sea I was 5.1> per kWh during
1996.
As the Salton Sea I PPA is not an SO4 Agreement, the energy
payments
do not revert to Edison's Avoided Cost of Energy. The
capacity
payment is approximately $1,100 per annum.
Salton Sea II and Salton Sea III sell electricity to Edison
pursuant
to 30-year modified SO4 Agreements that provide for capacity
payments,
capacity bonus payments and energy payments. The price for
contract
capacity and contract capacity bonus payments is fixed for the
life of
the modified SO4 Agreements. The energy payments for the first
ten
year period, which period expires in April 2000 and February 1999
are
levelized at a time period weighted average of 10.6> per kWh and
9.8>
per kWh for Salton Sea II and Salton Sea III,
respectively.
Thereafter, the monthly energy payments will be Edison's Avoided
Cost
of Energy. For Salton Sea II only, Edison is entitled to
receive, at
no cost, 5% of all energy delivered in excess of 80% of
contract
capacity through September 30, 2004. The annual capacity and
bonus
payments for Salton Sea II and Salton Sea III are approximately
$3,300
and $9,700, respectively.
The Salton Sea IV Project sells electricity to Edison pursuant
to a
modified SO4 agreement which provides for contract capacity
payments
on 34 MW of capacity at two different rates based on the
respective
contract capacities deemed attributable to the original Salton
Sea PPA
option (20 MW) and to the original Fish Lake PPA (14 MW). The
capacity
payment price for the 20 MW portion adjusts quarterly based
upon
specified indices and the capacity payment price for the 14 MW
portion
is a fixed levelized rate. The energy payment (for deliveries up
to a
rate of 39.6 MW) is at a fixed price for 55.6% of the total
energy
delivered by Salton Sea IV and is based on an energy payment
schedule
for 44.4% of the total energy delivered by Salton Sea IV.
The
contract has a 30-year term but Edison is not required to
purchase the
20 MW of capacity and energy originally attributable to the
Salton Sea
I PPA option after September 30, 2017, the original termination
date
of the Salton Sea I PPA.
For the year ended December 31, 1996, Edison's average Avoided
Cost of
Energy was 2.5 cents per kWh which is substantially below the
contract
energy prices earned for the year ended December 31, 1996.
Estimates
of Edison's future Avoided Cost of Energy vary substantially from
year
to year. The Company cannot predict the likely level of Avoided
Cost
of Energy prices under the SO4 Agreements and the modified
SO4
Agreements at the expiration of the scheduled payment periods.
The
revenues generated by each of the projects operating under
SO4
Agreements could decline significantly after the expiration of
the
respective scheduled payment periods.
The Upper Mahiao Project was deemed complete in June 1996 and
began
receiving capacity payments pursuant to the Upper Mahiao
Energy
Conversion Agreement ("ECA"), in July of 1996. The
project is
structured as a ten year BOOT, in which the Company's
subsidiary CE
Cebu Geothermal Power Company, Inc. ("CE Cebu"), the project
company,
is responsible for providing operations and maintenance during
the ten
year BOOT period. The electricity generated by the Upper
Mahiao
geothermal power plant is sold to PNOC-Energy Development
Corporation
("PNOC-EDC"), which is also responsible for supplying the
facility
with the geothermal steam. After the ten year cooperation
period, and
the recovery by the Company of its capital investment plus
incremental
return, the plant will be transferred to PNOC-EDC at no cost.
PNOC-EDC is obligated to pay for electric capacity that is
nominated
each year by CE Cebu, irrespective of whether PNOC-EDC is
willing or
able to accept delivery of such capacity. PNOC-EDC pays to CE
Cebu a
fee (the "Capacity Fee") based on the plant capacity nominated to
PNOC-
EDC in any year (which, at the plant's design capacity,
is
approximately 95% of total contract revenues) and a fee (the
"Energy
Fee") based on the electricity actually delivered to
PNOC-EDC
(approximately 5% of total contract revenues). The Capacity
Fee
serves to recover the capital costs of the project, to recover
fixed
operating costs and to cover return on investment. The Energy
Fee is
designed to cover all variable operating and maintenance costs of
the
power plant. Payments under the Upper Mahiao ECA are
denominated in
U.S. Dollars, or computed in U.S. dollars and paid in Philippine
pesos
at the then-current exchange rate, except for the Energy Fee,
which
will be used to pay Philippine peso-denominated expenses.
Significant
portions of the Capacity Fee and Energy Fee are indexed to U.S.
and
Philippine inflation rates, respectively. PNOC-EDC's
payment
requirements, and its other obligations under the Upper Mahiao
ECA are
supported by the Government of the Philippines through a
performance
undertaking.
Unit I of the Malitbog Project was deemed complete in July 1996.
The
Malitbog Project is being built, owned and operated by
VGPC, a
Philippine general partnership that is wholly owned,
indirectly, by
the Company. VGPC is selling 100% of its capacity on
substantially
the same basis as described above for the Upper Mahiao Project to
PNOC-
EDC, which will in turn sell the power to the NPC. As with the
Upper
Mahiao project, the Malitbog project is structured as a ten year
BOOT,
in which the Company will be responsible for implementing
construction
of the geothermal power plant and, as owner, for providing
operations
and maintenance for the ten year BOOT period. After a ten
year
cooperation period, and the recovery by the Company of its
capital
investment plus incremental return, the plant will be
transferred to
PNOC-EDC at no cost.
The Saranac Project sells electricity to New York State Electric
& Gas
pursuant to a 15 year negotiated power purchase agreement
(the
"Saranac PPA"), which provides for capacity and energy
payments.
Capacity payments, which in 1996 total 2.1> per kWh, are received
for
electricity produced during "peak hours" as defined in the
Saranac PPA
and escalate at approximately 4.1% annually for the remaining
term of
the contract. Energy payments, which average 6.3> per kWh in
1996,
escalate at approximately 4.4% annually for the remaining term of
the
Saranac PPA. The Saranac PPA expires in June of 2009.
The Power Resources Project sells electricity to Texas
Utilities
Electric Company ("TUEC") pursuant to a 15 year negotiated
power
purchase agreement (the "Power Resources PPA"), which provides
for
capacity and energy payments. Capacity payments and energy
payments,
which in 1996 are $2,930 per month and 2.86> per kWh,
respectively,
escalate at 3.5% annually for the remaining term of the
Power
Resources PPA. The Power Resources PPA expires in September
2003.
The NorCon Project sells electricity to Niagara Mohawk
Power
Corporation ("Niagara") pursuant to a 25 year negotiated
power
purchase agreement (the "NorCon PPA") which provides for
energy
payments calculated pursuant to an adjusting formula based
on
Niagara's ongoing Tariff Avoided Cost and the contractual
Long-Run
Avoided Cost. The NorCon PPA term extends through December 2017.
The
Company and Niagara are currently engaged in discussions
regarding a
potential restructuring or buyout and termination of the NorCon
PPA.
The Yuma Project sells electricity to SDG&E under an existing 30-
year
power purchase contract. The energy is sold at SDG&E's Avoided
Cost
of Energy and the capacity is sold to SDG&E at a fixed price for
the
life of the power purchase contract. The contract term
extends
through May 2024.
Royalty Expense
Royalty expense comprises the following for the years ended:
1996 1995 1994
Navy I, Unit 1 $ 1,620 $ 1,622 $1,641
Navy I, Units 2 and 3 3,512 3,394 3,174
BLM 2,538 3,036 2,842
Navy II 5,742 5,571 1,963
Partnership Project 6,702 6,820 ---
Salton Sea Project 3,526 3,578 ---
Desert Peak 53 287 268
Total $23,693 $24,308 $9,888
The amount of royalties paid by Navy I to the U.S. Navy to
develop
geothermal energy for Navy I, Unit 1 on the lands owned by the
Navy
comprises (i) a fee payable during the term of the contract
based on
the difference between the amounts paid by the Navy to Edison
for
specified quantities of electricity and the price as determined
under
the contract (which currently approximates 73% of that paid by
the
Navy to Edison), and (ii) $25,000 payable in December 2009, of
which
the Company's share is $11,600. The $25,000 payment is
secured by
funds placed on deposit monthly, which funds, plus accrued
interest,
will aggregate $25,000. The monthly deposit is currently $50.
As of
December 31, 1996, the balance of funds deposited approximated
$5,311,
which amount is included in restricted cash.
Units 2 and 3 of Navy I and the Navy II power plants are on
Navy
lands, for which the Navy receives a royalty based on electric
sales
revenue at the initial rate of 4% escalating to 22% by the end of
the
contract in December 2019. The BLM is paid a royalty of 10% of
the
value of steam produced by the geothermal resource supplying the
BLM
Plant.
The Partnership Project pays royalties based on both energy
revenues
and total electricity revenues. Hoch (Del Ranch) and Leathers
pay
royalties of approximately 5% of energy revenues and 1% of
total
electricity revenue. Elmore pays royalties of approximately
5% of
energy revenues. Vulcan pays royalties of 4.167% of energy
revenues.
The Salton Sea Project's weighted average royalty expense in
1996 was
approximately 5.2%. The royalties are paid to numerous
recipients
based on varying percentages of electrical revenue or steam
production
multiplied by published indices.
Nevada and Utah Properties
Roosevelt Hot Springs. The Company operates and owns an
approximately
70% interest in a geothermal steam field which supplies
geothermal
steam to a 23 net MW power plant owned by Utah Power & Light
Company
("UP&L") located on the Roosevelt Hot Springs property under a 30-
year
steam sales contract.
The Company obtained approximately $20,317 cash under a pre-
sale
agreement with UP&L whereby UP&L paid in advance for the
steam
produced by the steam field. The Company must make certain
penalty
payments to UP&L if the steam produced does not meet certain
quantity
and quality requirements.
Desert Peak. The Company is the owner and operator of a
geothermal
plant at Desert Peak, Nevada that is currently selling
electricity to
Sierra Pacific Power Company ("Sierra") at Sierra's Avoided Cost.
Glass Mountain
Under a Bonneville Power Administration ("BPA") geothermal
pilot
program, the Company has been developing a 30 net MW
geothermal
project which was originally located in the Newberry Known
Geothermal
Resource Area in Deschutes County, Oregon. Pursuant to two
power
sales contracts executed in September 1994, an affiliate of
the
Company agreed to sell 20 MW to BPA and 10 MW to Eugene Water
and
Electric Board ("EWEB") from the Project. In addition, BPA and
EWEB
together have an option to purchase up to an additional 100
MW of
production from the project under certain circumstances. These
power
sales contracts provide that under certain circumstances the
contracts
may be utilized at an alternative location.
Pursuant to its resource exploration program, the Company
has
determined that the geothermal resource at Newberry is not
sufficient
to support the contracts and accordingly has determined to
utilize the
contracts at its leasehold position in Glass Mountain (the
"Glass
Mountain Project") in Northern California, where it has two
successful
production wells. The Company and BPA have agreed to relocate
the
project to Glass Mountain. Under the relocation agreement BPA
will
purchase 30 MW from the project. The movement of the project to
this
alternative location and BPA's purchase obligation are
subject to
obtaining a final environmental impact statement relating to the
new
site location. Discussions with EWEB are continuing.
The Glass Mountain Project is currently expected to
commence
commercial operation in 2000. Completion of this project is
subject
to a number of significant uncertainties and cannot be assured.
5. Equity Investments
The Company has a present indirect ownership of approximately
35% in
the Casecnan Project, a combined irrigation and 150 net
MW
hydroelectric power generation project located on the island of
Luzon
in the Philippines.
The Company acquired an approximate 47% economic interest in
Saranac
Power Partners, L.P. and a 20% economic interest in NorCon
Power
Partners, L.P. as part of the Falcon Seaboard acquisition.
Summary financial information for these equity investments
follows:
Casecnan Saranac NorCon
As of and for the year ended December 31, 1996:
Assets $ 492,166 $ 325,174 $
125,956
Liabilities 380,737 213,326
121,223
Net income (loss) (11,207) 40,005
(53)
As of December 31, 1995:
Assets 501,160 N/A N/A
Liabilities 378,524 N/A N/A
6. Parent Company Debt
Parent company debt comprises the following at December 31:
1996 1995
Senior discount notes $ 527,535 $ 477,355
Senior notes 224,150 ---
Limited recourse senior secured notes* 200,000 200,000
CalEnergy credit facility 100,000 ---
Revolving credit facility 95,000 ---
Convertible subordinated debentures --- 100,000
Convertible debt --- 64,850
$ 1,146,685 $ 842,205
*The amount of recourse obligation to the parent was $0 at
December 31, 1996.
Senior Discount Notes
In March 1994, the Company issued $400,000 of 10 1/4% Senior
Discount
Notes which accrete to an aggregate principal amount of
$529,640 at
maturity in 2004. The original issue discount (the difference
between
$400,000 and $529,640) will be amortized from issue date
through
January 15, 1997, during which time no cash interest will be
paid on
the Senior Discount Notes. Commencing July 15, 1997, cash
interest on
the Senior Discount Notes will be payable semiannually on
January 15
and July 15 of each year. The Senior Discount Notes are
redeemable at
any time on or after January 15, 1999 initially at a redemption
price
of 105.125% declining to 100% on January 15, 2002 plus
accrued
interest to the date of redemption. The Senior Discount Notes
are
unsecured senior obligations of the Company.
The Senior Discount Notes prohibit payment of cash dividends
unless
certain financial ratios are met and unless the dividends do
not
exceed 50% of the Company's accumulated adjusted consolidated
net
income as defined, subsequent to April 1, 1994, plus the
proceeds of
any stock issuance.
Senior Notes
On September 20, 1996 the Company completed a private
sale to
institutional investors of $225,000 aggregate principal amount
of 9
1/2% Senior Notes due 2006. Interest on the Senior Notes
will be
payable semiannually on March 15 and September 15 of each year.
The
Senior Notes are redeemable at any time on or after September 15,
2001
initially at a redemption price of 104.75% declining to
100% on
September 15, 2004 plus accrued interest to the date of
redemption.
The Senior Notes are unsecured senior obligations of the Company.
Limited Recourse Senior Secured Notes
On July 21, 1995 the Company issued $200,000 of 9 7/8%
Limited
Recourse Senior Secured Notes Due 2003 (the "Notes"). Interest on
the
Notes is payable on June 30 and December 30 of each year,
commencing
December 1995. The Notes are secured by an assignment and
pledge of
100% of the outstanding capital stock of Magma and are recourse
only
to such Magma capital stock, the Company's interest in a secured
Magma
note and general assets of the Company equal to the Restricted
Payment
Recourse Amount, as defined in the Note Indenture ("Note
Indenture"),
which was $0 at December 31, 1996.
At any time or from time to time on or prior to June 30, 1998,
the
Company may, at its option, use all or a portion of the net
cash
proceeds of a Company equity offering (as defined in the
Note
Indenture) and shall at any time use all of the net cash
proceeds of
any Magma equity offering (as defined in the Note Indenture) to
redeem
up to an aggregate of 35% of the principal amount of the
Notes
originally issued at a redemption price equal to 109.875% of
the
principal amount thereof plus accrued interest to the redemption
date.
On or after June 30, 2000, the Notes are redeemable at the
option of
the Company, in whole or in part, initially at a redemption
price of
104.9375% declining to 100% on June 30, 2002 and thereafter,
plus
accrued interest to the date of redemption.
CalEnergy Credit Facility
On October 28, 1996 the Company obtained a $100,000 credit
facility
(the "CalEnergy Credit Facility") of which the Company has
drawn
$100,000 as of December 31,1996. Borrowings under the
CalEnergy
Credit Facility are unsecured and mature on October 28, 1997,
subject
to prepayment by the Company at any time. Subsequent to year
end, the
Company repaid the entire balance of the CalEnergy Credit
Facility.
Revolving Credit Facility
On July 8, 1996 the Company obtained a $100,000 three year
revolving
credit facility. The facility is unsecured and is available to
fund
general operating capital requirements and finance future
business
opportunities. The Company had drawn $95,000 as of December 31,
1996.
Subsequent to year end, the Company repaid the entire balance.
Convertible Subordinated Debentures
In June of 1993, the Company issued $100,000 principal amount
of 5%
convertible subordinated debentures ("debentures") due July 31,
2000.
Substantially all of the debentures were converted into 4,443
common
shares in September and October 1996 at a conversion price of
$22.50
per share.
Convertible Debt
On November 19, 1991, the Company sold one thousand
shares of
convertible preferred stock, Series C, at $50,000 per share to
Kiewit
Energy Company Inc. ("Kiewit"), a subsidiary of PKS, in a
private
placement. Each share of the Series C preferred stock was
convertible
at any time at $18.375 per common share into 2,721 shares of
common
stock subject to customary adjustments. The Series C preferred
stock
had a dividend rate of 8.125%, commencing March 15, 1992
through
conversion date or December 15, 2003. The dividends, which
were
cumulative, were payable quarterly in convertible preferred
stock,
Series C, through March 15, 1995 and in cash on subsequent
dividend
dates.
Pursuant to the terms of the Securities Purchase Agreement,
the
Company exercised its rights to exchange the preferred stock,
Series
C, on March 15, 1995 for $64,850 principal amount 9.5%
convertible
subordinated debenture of the Company due 2003, with the
same
conversion features of the preferred stock, Series C. On
September
20, 1996, the Company converted the $64,850 convertible debt
and
associated accrued interest into 3,620 common shares at a
conversion
price of $18.375 per share.
The annual repayments of the parent company debt for the
years
beginning January 1, 1997 are as follows:
Senior Limited
Discount Senior Recourse
Notes Notes Notes *
1997 - 2001 $ --- $ --- $ ---
Thereafter 529,640 225,000 200,000
$529,640 $225,000 $200,000
*The amount of recourse obligation to the parent was $0 at
December 31, 1996.
7. Subsidiary and Project Debt:
Project loans held by subsidiaries and projects of the
Company
comprise the following at December 31:
1996 1995
Salton Sea Notes and Bonds $ 538,982$ 452,088
Northern eurobonds 439,192 ---
Coso Funding Corp. project loans 148,346 203,226
U.K. Credit Facility 128,423 ---
Power Resources project debt 114,571 ---
Construction loans 377,454 211,198
Other 7,927 54,707
$ 1,754,895 $ 921,219
Pursuant to separate project financing agreements, substantially
all
the assets of the Company are pledged or encumbered to support or
otherwise provide the security for the project or subsidiary
debt.
Salton Sea Notes and Bonds
On June 20, 1996 and July 25, 1995, the Company through its
wholly
owned subsidiary, Salton Sea Funding Corporation
("Funding
Corporation"), completed sales to institutional investors of
$135,000
and $475,000, respectively, of Salton Sea Notes and Bonds (the
"Notes
and Bonds"). The Salton Sea Notes and Bonds are nonrecourse to
the
Company. The Funding Corporation debt securities were
offered as
follows:
Senior Secured Series Due Rate
Amount
July 25, 1995 A Notes May 30, 2000 6.69%
$232,750
July 25, 1995 B Bonds May 30, 2005 7.37%
133,000
July 25, 1995 C Bonds May 30, 2010 7.84%
109,250
June 20, 1996 D Notes May 30, 2000 7.02%
70,000
June 20, 1996 E Bonds May 30, 2011 8.30%
65,000
The Salton Sea Notes and Bonds are secured by the Company's
four
existing Salton Sea plants as well as an assignment of the
right to
receive various royalties payable to Magma in connection with
its
Imperial Valley properties and distributions from the
Partnership
Project.
Each of the Company's direct or indirect subsidiaries is
organized as
a legal entity separate and apart from the Company and its
other
subsidiaries. It should not be assumed that any asset of any
such
subsidiary will be available to satisfy the obligations of the
Company
or any of its other such subsidiaries; provided, however,
that
unrestricted cash or other assets which are available for
distribution
may, subject to applicable law and the terms of financing
arrangements
of such parties, be advanced, loaned, paid as dividends or
otherwise
distributed or contributed to the Company or affiliates
thereof.
Substantially all of the assets of each subsidiary listed
below
(except Vulcan/BN Geothermal Power Company and certain
other
subsidiaries involved in project financing activities) have
been
encumbered to secure obligations owed to the creditors of
such
subsidiary:
Fish Lake Power Company
Salton Sea Brine Processing L.P.
Salton Sea Power Generation L.P.
Vulcan Power Company
CalEnergy Operating Company
Salton Sea Funding Corporation
Salton Sea Power Company
Salton Sea Royalty Company
Vulcan/BN Geothermal Power Company
Del Ranch, L.P.
Elmore, L.P.
Leathers, L.P.
Pursuant to the Depository Agreement, Funding Corporation
established
a debt service reserve fund in the form of a letter of credit in
the
amount of $70,430 from which scheduled interest and principal
payments
can be made.
Northern Eurobonds
The Northern debt includes a 55,000 ($94,177) debenture due in
1999,
which bears a fixed interest rate of 12.661%. The debt also
includes
bearer bonds repayable in 100,000 ($171,230) amounts in 2005 and
2020,
bearing fixed interest rates of 8.625% and 8.875%, respectively.
The balance at December 31, 1996 consists of the following:
Debenture due 1999 $ 99,924
Bearer bonds due 2005 171,130
Bearer bonds due 2020 168,138
$ 439,192
Coso Funding Corp. Project Loans
The Coso Funding Corp. project loans are from Coso Funding
Corp., a
single-purpose corporation formed to issue notes for its own
account
and act as an agent on behalf of the Coso Project. On December
16,
1992, pursuant to separate credit agreements executed between
Coso
Funding Corp. and each Coso Joint Venture, the proceeds from
Coso
Funding Corp.'s note offering were loaned to the Coso Project.
The
proceeds of $560,245 were used by the Coso Project to (i)
purchase and
retire project finance debt comprised of the term loans
and
construction loans in the amount of $424,500, (ii) fund
contingency
funds in the amount of $68,400, (iii) fund debt service reserve
funds
in the amount of $40,000, and (iv) finance $27,345 of
capital
expenditures and transaction costs. The contingency fund and
debt
service reserve fund were required by the project loan
agreements.
The contingency fund represented the approximate maximum
amount, if
any, which could theoretically have been payable by the Coso
Project
to third parties to discharge all liens of record and other
contract
claims encumbering the Coso Project's plants at the time of
the
project loans. The contingency fund was established in
order to
obtain investment-grade ratings to facilitate the offer and
sale of
the notes by Coso Funding Corp., and such establishment did
not
reflect the Coso Project's view as to the merits or likely
disposition
of such litigation or other contingencies. On June 9, 1993, MPE
and
the Mission Power Group, subsidiaries of Edison Corp., and the
Coso
Project reached a final settlement of all of their
outstanding
disputes and claims relating to the construction of the Coso
Project.
As a result of the various payments and releases involved in
such
settlement, the Coso Project agreed to make a net payment of
$20,000
to MPE from the cash reserves of the Coso Project contingency
fund and
MPE agreed to release its mechanics' liens on the Coso Project.
After
making the $20,000 payment, the remaining balance of the Coso
Project
contingency fund (approximately $49,300) was used to increase the
Coso
Project debt reserve fund from approximately $43,000 to its
maximum
fully-funded requirement of $67,900. The remaining $24,400
balance of
contingency fund was retained within the Coso Project for
future
capital expenditures and for Coso Project debt service
payments.
Since the Coso Project debt service reserve is fully
funded in
advance, Coso Project cash flows otherwise intended to fund the
Coso
Project debt service reserve fund, subject to satisfaction of
certain
covenants and conditions contained in the Coso Joint
Ventures'
refinancing documents, may be available for distribution to
the
Company in its proportionate share.
The Coso Funding Corp. project loans are collateralized by,
among
other things, the power plants, geothermal resource, debt
service
reserve funds, contingency funds, pledge of contracts, and
an
assignment of all such Coso Project's revenues which will be
applied
against the payment of obligations of each Coso Joint
Venture,
including the project loans. Each Coso Joint Venture's assets
will
secure only its own project loan, and will not be cross-
collateralized
with assets pledged under other Coso Joint Venture's
credit
agreements. The project loans are nonrecourse to any partner in
the
Coso Joint Ventures and the Coso Funding Corp. shall solely
look to
such Coso Joint Venture's pledged assets for satisfaction of
such
project loans. However, the loans are cross-collateralized by
the
available cash flow of each Coso Joint Venture. Each Coso
Joint
Venture after satisfying a series of its own obligations has
agreed to
advance support loans (to the extent of available cash flow and,
under
certain conditions, its debt service reserve funds) in the
event
revenues from the supporting Coso Joint Ventures are
insufficient to
meet scheduled principal and interest on their separate project
loans.
The Coso Funding Corp. project loans carry a fixed interest rate
with
weighted average interest rates of 8.46% and 8.29% at December
31,
1996 and 1995, respectively. The loans have scheduled
repayments
through December 2001.
U.K. Credit Facility
On October 28, 1996 CE Holdings obtained a 560,000 ($958,888)
five
year term loan and revolving credit facility (the "U.K.
Credit
Facility"). The Company has not guaranteed, nor is it
otherwise
subject to recourse for, amounts borrowed under the U.K.
Credit
Facility. The agreement places restrictions on distributions
from CE
Electric to any of its shareholders based on certain financial
ratios.
As of December 31, 1996, CE Holdings had drawn 75,000 ($128,423)
under
the agreement.
Power Resources Project Financing Debt
Power Resources, an indirect wholly-owned subsidiary, has
project
financing debt consisting of a term loan payable to a
consortium of
banks with interest and principal due quarterly through October
2003.
The debt carries fixed interest rates of 10.385% and 10.625%.
The
loan is collateralized by all of the assets of Power Resources.
The annual repayments of the subsidiary and project debt,
excluding
construction loans, for the years beginning January 1, 1997
and
thereafter are as follows:
Salton Sea Coso
Notes and Funding UK Credit Power
Bonds Northern Corp. Facility
Resources Other
1997 $ 90,228 $ --- $ 41,729 $ --- $
11,228 $ 873
1998 106,938 --- 38,912 ---
12,805 1,678
1999 57,836 99,924 31,717 ---
14,268 1,421
2000 25,072 --- 4,080 ---
16,087 1,181
2001 22,376 --- 31,908 128,423
18,119 959
Thereafter 236,532 339,268 --- ---
42,064 1,815
$538,982 $439,192 $148,346 $128,423
$114,571 $7,927
Construction Loans
The Company's share of project construction loans comprise the
following at December 31:
1996 1995
Upper Mahiao $150,628 $134,619
Malitbog 137,881 36,863
Mahanagdong 76,503 39,716
Dieng Unit I 12,442 ---
$377,454 $211,198
The construction loans are scheduled to be replaced by term
project
financing upon completion of construction and commencement
of
commercial operations.
Upper Mahiao Construction Loan
Draws on the construction loan for the Upper Mahiao geothermal
power
project at December 31, 1996 totaled $150,628. A
consortium of
international banks provided the construction financing with
interest
rates at LIBOR or "Prime" with interest payments due every
quarter and
at LIBOR maturity. The weighted average interest rate at
December 31,
1996 and 1995 is approximately 8.01% and 8.31%, respectively.
The
Export-Import Bank of the U.S. ("Ex-Im Bank") is providing
political
risk insurance to commercial banks on the construction loan.
The
construction loan is expected to be converted to a term loan
promptly
after NPC completes the full capacity transmission line,
which is
currently expected in early 1997. The largest portion of the
term
loan for the project will also be provided by Ex-Im Bank. The
term
financing for the Ex-Im Bank loan will be for a ten year term
at a
fixed interest rate of 5.95%.
Malitbog Construction Loan
Draws on the construction loan for the Malitbog geothermal
power
project at December 31, 1996 totaled $137,881. Credit Suisse and
OPIC
have provided the construction and term loan facilities. The
eight
year project term loan facilities will be at variable interest
rates
(weighted average of 8.15% and 8.42% at December 31, 1996 and
1995,
respectively). The international bank portion of the debt
will be
insured by the Overseas Private Investment Corporation
("OPIC")
against political risks and the Company's equity
contribution to
Visayas Geothermal Power Company ("VGPC") is covered by political
risk
insurance from the Multilateral Investment Guarantee Agency and
OPIC.
Mahanagdong Construction Loan
The Company's share of draws on the construction loan for
the
Mahanagdong geothermal power project at December 31, 1996
totaled
$76,503. The construction debt financing is provided by OPIC
and a
consortium of international banks. The construction loan
interest
rates are at LIBOR or "Prime" with interest payments due
quarterly and
at LIBOR maturity. The weighted average interest rate at
December 31,
1996 and 1995 is approximately 8.05% and 8.02% respectively.
Political
risk insurance from Ex-Im Bank has been obtained for the
commercial
lenders. Ten year project term debt financing of
approximately
$120,000 will be provided by Ex-Im Bank (which will replace the
bank
construction debt) and by OPIC. The majority of the term
financing is
expected to be provided by the Ex-Im Bank at a fixed interest
rate of
6.92%.
Dieng Construction Loan
On October 4, 1996 the Company closed the $120,000 project
financing
for the Dieng Unit I 55 net MW geothermal project
located in
Indonesia. The loan carries a variable interest rate
(weighted
average of 7.19% at December 31, 1996) and has scheduled project
term
repayments through 2002. Dieng Unit I is under construction
and is
currently expected to begin commercial operation by late 1997.
The
Company has drawn $12,442 as of December 31, 1996.
8. Income Taxes
Provision for income taxes is comprised of the following at
December
31:
1996 1995
1994
Currently payable:
State $ 7,520 $ 5,510
$1,970
Federal 19,873 11,138
5,829
Foreign 2,176 ---
- - - - ---
29,569 16,648
7,799
Deferred:
State 1,619 921
1,017
Federal 9,209 13,062
7,241
Foreign 1,424 ---
- - - - ---
12,252 13,983
8,258
Total after benefit of
extraordinary item 41,821 30,631
16,057
Tax benefit attributable to
extraordinary item --- ---
945
Total before benefit of
extraordinary item $41,821 $30,631
$17,002
A reconciliation of the federal statutory tax rate to the
effective
tax rate applicable to income before provision for income
taxes
follows:
1996 1995 1994
Federal statutory rate 35.00% 35.00% 35.00%
Percentage depletion in excess
of cost depletion (6.12) (7.38) (6.85)
Investment and energy tax credits (8.34) (1.80) (3.04)
State taxes, net of federal
tax effect 4.38 4.09 4.48
Goodwill amortization 2.51 2.53 ---
Non-deductible expense .84 1.10 ---
Lease investment --- (2.18) ---
Tax effect of foreign income 2.54 --- ---
Other .01 .20 .86
30.82% 31.56% 30.45%
Deferred tax liabilities (assets) are comprised of the following
at
December 31:
1996 1995
Depreciation and amortization, net $725,366 $349,079
Pensions 22,883 ---
Other 6,119 4,043
754,368 353,122
Deferred contract costs (128,745) ---
Deferred income (9,298)
(7,709)
Loss carryforwards ---
(3,050)
Energy and investment tax credits (55,931)
(52,857)
Advance corporation tax (20,205) ---
Alternative minimum tax credits (50,819)
(52,480)
Jr. SO4 royalty receivable (5,865)
(5,865)
Accruals not currently deductible
for tax purposes (13,372) ---
Other (934)
(4,641)
(285,169)
(126,602)
Net deferred taxes $469,199 $226,520
The Company has unused investment and geothermal energy tax
credit
carryforwards of approximately $55,931 expiring between 2002 and
2011.
The Company also has approximately $50,819 of alternative
minimum tax
credit and 11,800 ($20,205) of surplus advance corporation
tax
carryforwards which have no expiration date.
9. Company-Obligated Mandatorily Redeemable Convertible
Preferred
Securities of Subsidiary Trust Holding Solely Convertible
Debentures
On April 12, 1996 CalEnergy Capital Trust, a special purpose
Delaware
business trust organized by the Company (the "Trust"),
pursuant to
the Amended and Restated Declaration of Trust (the
"Declaration")
dated as of April 4, 1996, completed a private placement (with
certain
shelf registration rights) of $100,000 of convertible
preferred
securities ("TIDES"). In addition, an option to purchase an
additional
78.6 TIDES, or $3,930, was exercised by the initial
purchasers to
cover over-allotments.
The Trust has issued 2,078.6 of 6 1/4% TIDES with a
liquidation
preference of fifty dollars each. The Company owns all of the
common
securities of the Trust. The TIDES and the common
securities
represent undivided beneficial ownership interests in the Trust.
The
assets of the Trust consist solely of the Company's 6 1/4%
Convertible
Junior Subordinated Debentures due 2016 in an outstanding
aggregate
principal amount of $103,930 ("Junior Debentures") issued
pursuant to
an indenture dated as of April 1, 1996. The indenture
includes an
agreement by the Company to pay expenses and obligations
incurred by
the Trust. Each TIDES will be convertible at the option of the
holder
thereof at any time into 1.6728 shares of CalEnergy Common
Stock
(equivalent to a conversion price of $29.89 per share of the
Company's
Common Stock), subject to customary anti-dilution adjustments.
Until converted into the Company's Common Stock, the TIDES will
have
no voting rights with respect to the Company and, except under
certain
limited circumstances, will have no voting rights with respect to
the
Trust. Distributions on the TIDES (and Junior Debentures)
are
cumulative, accrue from the date of initial issuance and are
payable
quarterly in arrears, commencing June 15, 1996. The Junior
Debentures
are subordinated in right of payment to all senior indebtedness
of the
Company and the Junior Debentures are subject to certain
covenants,
events of default and optional and mandatory redemption
provisions,
all as described in the Junior Debenture Indenture.
Pursuant to a Preferred Securities Guarantee Agreement, dated
as of
April 10, 1996 (the "Guarantee"), between the Company and a
preferred
guarantee trustee, the Company has agreed irrevocably to pay to
the
holders of the TIDES, to the extent that the Trustee has
funds
available to make such payments, quarterly distributions,
redemption
payments and liquidation payments on the TIDES. Considered
together,
the undertakings contained in the Declaration, Junior
Debentures,
Indenture and Guarantee constitute a full and unconditional
guarantee
by the Company of the Trust's obligations under the TIDES.
10.Preferred Stock
On December 1, 1988 the Company distributed a dividend of
one
preferred share purchase right ("right") for each outstanding
share of
common stock. The rights are not exercisable until ten days
after a
person or group acquires or has the right to acquire,
beneficial
ownership of 20% or more of the Company's common stock or
announces a
tender or exchange offer for 30% or more of the Company's
common
stock. Each right entitles the holder to purchase one one-
hundredth of
a share of Series A junior preferred stock for $52. The rights
may be
redeemed by the Board of Directors up to ten days after an
event
triggering the distribution of certificates for the rights. The
rights
plan was amended in February 1991 so that the agreement with
Kiewit
would not trigger the exercise of the rights. The rights will
expire,
unless previously redeemed or exercised, on November 30, 1998.
The
rights are automatically attached to, and trade with, each
share of
common stock.
11.Stock Options and Restricted Stock
The Company has issued various stock options. As of December 31,
1996,
a total of 5,088 shares are reserved for stock options, of which
4,777
shares have been granted and remain outstanding at prices of
$3.00 to
$30.38 per share.
The Company has stock option plans under which shares were
reserved
for grant as incentive or non-qualified stock options, as
determined
by the Board of Directors. The plans allow options to be
granted at
85% of their fair market value at the date of grant.
Generally,
options are issued at 100% of fair market value at the date of
grant.
Options granted under the 1996 Plan become exercisable over a
period
of three to five years and expire if not exercised within ten
years
from the date of grant or, in some instances a lesser term.
Prior to
the 1996 Plan, the Company granted 256 options at fair market
value at
date of grant which had terms of ten years and were
exercisable at
date of grant. In addition, the Company had issued approximately
138
options to consultants on terms similar to those issued under the
1996
Plan. The non-1996 plan options are primarily options
granted to
Kiewit (see Note 12).
The Company granted 500 shares of restricted common stock
with an
aggregate market value of $9,500 in exchange for the
relinquishment of
500 stock options which were canceled by the Company. The shares
have
all rights of a shareholder, subject to certain
restrictions on
transferability and risk of forfeiture. Unearned
compensation
equivalent to the market value of the shares at the date of
issuance
was charged to Stockholders' equity. Such unearned
compensation is
being amortized over the vesting period of which 125 shares
were
immediately vested and the remaining 375 shares vest straight
line
over approximately five years. Accordingly, $1,535 and
$2,494 of
unearned compensation was charged to general and
administrative
expense in 1996 and 1995, respectively.
Transactions in Stock Options
Options Outstanding
Shares Available
for Grant Under Option
Price Weighted Avg
1996 Option Plan Shares Per
Shares Option Price Total
Balance December 31, 1993 439 8,514 $3.00 -
$19.00 $12.32 $104,931
Options granted (954) 1,243 12.00 -
17.25 15.49 19,260
Options terminated 15 (15) 3.00 -
15.94 13.67 (205)
Options exercised --- (141) 3.00 -
15.94 5.03 (709)
Additional shares reserved
under 1996 Option Plan 586 --- ---
- - - - --- ---
Balance December 31, 1994 86 9,601 3.00 -
19.00 12.84 123,277
Options granted (396) 396 15.81 -
19.00 18.15 7,188
Options terminated 571 (571) 14.88 -
19.00 18.69 (10,673)
Options exercised --- (135) 3.00 -
15.94 3.41 (460)
Balance December 31, 1995 261 9,291 3.00 -
19.00 12.84 119,332
Options granted (1,157) 1,1572 5.06 -
30.38 28.17 32,590
Options terminated 468 (468) 3.00 -
19.00 17.96 (8,406)
Options exercised --- (5,203) 3.00 -
21.68 11.13 (57,931)
Additional shares reserved
under 1996 Option Plan 739 --- ---
- - - - --- ---
Balance December 31, 1996 311 4,777 $3.00 -
$30.38 $17.92 $85,585
Options exercisable at:
December 31, 1994 7,897 $3.00 -
$19.00 $11.87 $93,705
December 31, 1995 8,229 $3.00 -
$19.00 $12.26 $100,886
December 31, 1996 3,071 $3.00 -
$30.38 $14.25 $43,770
The following table summarizes information about stock options
outstanding
and exercisable as of December 31, 1996:
Options Outstanding
Options Exercisable
Weighted
Weighted Average Weighted
Range of Number Average
Remaining Number Average
Exercise Prices Outstanding Exercise Price
Contractual Life Exercisable Exercise Price
$3.00 $11.99 1,251 $ 10.70 4
years 1,251 $ 10.70
12.00 20.99 2,369 16.72 7
years 1,786 16.50
21.00 30.38 1,157 28.16 9
years 34 29.25
4,777 $ 17.92 7
years 3,071 $ 14.25
In October 1995 the Financial Accounting Standards Board issued
Statement
of Financial Accounting Standards No. 123 ("SFAS
123"), "Accounting for Stock-Based Compensation." SFAS 123
defines a fair
value based method of accounting for stock-based employee
compensation
plans and encourages all entities to adopt that method of
accounting.
However, it also allows an entity to continue to measure
compensation cost
for those plans using the intrinsic value based method of
accounting.
The Company has decided to continue to apply the intrinsic value
based
method of accounting for its stock-based employee compensation
plans.
If the fair value based method had been applied for 1996 and
1995, non-
cash compensation expense and the effect on net income
available to
common stockholders and earnings per share would have been
immaterial.
The fair value for stock options was estimated using the Black-
Scholes
option pricing model with assumptions for the risk-free interest
rate
of 6.00%, expected volatility of 22%, expected life of
approximately
4.5 years, and no expected dividends. The weighted average fair
value
of options granted during 1996 and 1995 was $8.62 per option and
$5.72
per option, respectively.
12.Common Stock Sales & Related Options
Simultaneous with the acquisition of the remaining equity
interest of
Magma on February 24, 1995, the Company completed a public
offering
(the "Offering") of 18,170 shares of common stock, which
amount
included a direct sale by the Company to Kiewit of 1,500 shares
and
the exercise of underwriter over-allotment options for 1,500
shares,
at a price of $17.00 per share. The Company received
proceeds of
$300,388 from the Offering.
The Company and Kiewit signed a Stock Purchase Agreement and
related
agreements, dated as of February 18, 1991. Under the terms of
the
agreements, Kiewit purchased 4,000 shares of common stock at
$7.25 per
share and received options to buy 3,000 shares at a price of $9
per
share exercisable over three years and an additional 3,000 shares
at a
price of $12 per share exercisable over five years
(subject to
customary adjustments).
In May 1994, pursuant to a special antidilution provision of the
1991
Stock Purchase Agreement between the Company and Kiewit, the
Company
increased Kiewit's existing option (granted in 1991) to purchase
3,000
shares at $12 per share by an additional 289 shares as a
final
adjustment under such provisions.
In connection with this initial stock purchase, the Company and
Kiewit
also entered into certain other agreements pursuant to which
Kiewit
and its affiliates agreed not to acquire more than 34% of
the
outstanding common stock (the "Standstill Percentage") for a five-
year
period ending in February 1996 and Kiewit became entitled to
nominate
at least three of the Company's directors.
On June 19, 1991, the board approved a number of amendments to
the
Stock Purchase Agreement and the related agreements. As part of
those
amendments, the Company extended the term of the $9 and $12
options to
seven years; modified certain of the other terms of these
options;
granted to Kiewit an option to acquire an additional 1,000
shares of
the common stock at $11.625 per share for a ten year term;
and
increased the Standstill Percentage from 34% to 49%.
On November 19, 1991, the Board approved the issuance by the
Company
to Kiewit of one thousand shares of Series C preferred stock
for
$50,000. In connection with the sale of the Series C preferred
stock
to Kiewit, the Standstill Agreement was amended so that the
49%
Standstill Percentage restriction would apply to voting stock
rather
than just common stock.
13. Related Party Transactions
The Company charged and recognized a management fee and
interest on
advances to its Coso Joint Ventures, which aggregated
approximately
$5,731, $6,075 and $5,569 in the years ended December 31, 1996,
1995
and 1994, respectively. The Company has a note receivable from
the
Coso Joint Ventures included in deferred charges and other
assets
which bears a fixed interest rate of 12.5% and is payable on or
before
March 19, 2002. The balance of the note is $11,578 and $14,254
as of
December 31, 1996 and 1995, respectively. This note is
subordinated
to the senior project loan on the project.
The Mahanagdong Project is being constructed by a consortium (the
"EPC
Consortium") of Kiewit Construction Group, Inc. ("KCG") and
the CE
Holt Company, a wholly owned subsidiary of the Company,
pursuant to
fixed-price, date-certain, turnkey supply and construction
contracts
(collectively, the "Mahanagdong EPC"). The obligations of the
EPC
Consortium under the Mahanagdong EPC are supported by a
guaranty of
KCG at an aggregate amount equal to approximately 50% of
the
Mahanagdong EPC price. The Mahanagdong EPC provides for
maximum
liability for liquidated damages of up to $100,500 and total
liability
of up to $201,000. KCG, a wholly owned subsidiary of PKS, is the
lead
member of the EPC Consortium, with an 80% interest. KCG
performs
construction services for a wide range of public and private
customers
in the U.S. and internationally. CE Holt Company provides design
and
engineering services for the EPC Consortium, and holds a 20%
interest.
The Company has provided a guaranty of CE Holt Company's
obligations
under the Mahanagdong EPC Contract.
The Company has in an international joint venture agreement with
PKS,
a stockholder of the Company, which the Company believes
enhances its
capabilities in foreign power markets. The joint venture
agreement is
limited to international power project development activities
and
provides that, if both the Company and PKS agree to participate
in a
project, they will share all development costs equally. The
Company
and PKS each will provide 50% of the equity required for
financing a
project developed by the joint venture and the Company will
receive
from the project a development fee (generally 1% of project
capital)
and will operate and manage such project for a fee. The
agreement
creates a joint development structure under which, on a
project by
project basis, the Company will be the development manager,
managing
partner and/or project operator, and equal equity participant
with PKS
and a preferred participant in the construction consortium and
PKS
will be an equal equity participant and the preferred
turnkey
construction contractor. The joint venture agreement may be
terminated
by either party on 15 days written notice, provided that
such
termination cannot affect the pre-existing contractual
obligations of
either party.
14. Extraordinary Item
In conjunction with the Company's Senior Discount Notes
offering in
1994, the 12% Senior Notes were defeased. This resulted
in an
extraordinary item in the amount of $2,007, after the income
tax
effect of $945. The extraordinary item represents the amount
necessary
to defease the interest payments and the unamortized portion of
the
deferred financing costs on the 12% Senior Notes.
15.Fair Value of Financial Instruments
The fair value of a financial instrument is the amount at which
the
instrument could be exchanged in a current transaction between
willing
parties, other than in a forced sale or liquidation.
Although
management uses its best judgment in estimating the fair
value of
these financial instruments, there are inherent limitations in
any
estimation techniques. Therefore, the fair value estimates
presented
herein are not necessarily indicative of the amounts which the
Company
could realize in a current transaction.
The methods and assumptions used to estimate fair value
are as
follows:
Debt instruments - The fair value of all debt issues
listed on
exchanges has been estimated based on the quoted market prices.
Interest rate swap agreements - The fair value of interest rate
swap
agreements is estimated based on quotes from the counter
party to
these instruments and represents the estimated amounts that
the
Company would expect to receive or pay to terminate the
agreements. It
is the Company's intention to hold the swap agreements to
their
intended maturity.
Other financial instruments - All other financial instruments
of a
material nature fall into the definition of short-term and fair
value
is estimated as the carrying amount.
The carrying amounts in the table below are included under
the
indicated captions in Notes 6 and 7 except for the interest rate
swaps
which are discussed in Note 16.
1996
1995
Estimated
Estimated
Carrying Fair Carrying
Fair
Value Value Value
Value
Financial assets:
Interest rate swap receivable $ 100 $ 222 $ 61
$ 561
Financial liabilities:
Senior discount notes 527,535 556,971 477,355
503,158
Senior notes 224,150 229,866 ---
- - - - ---
Limited recourse senior secured
notes 200,000 212,560 200,000
210,500
CalEnergy credit facility 100,000 100,000 ---
- - - - ---
Revolving line of credit 95,000 95,000 ---
- - - - ---
Convertible subordinated debentures --- --- 100,000
100,500
Salton Sea notes and bonds 538,982 531,807 452,088
459,629
Northern Electric eurobonds 439,192 445,830 ---
- - - - ---
Construction loans 377,454 377,454 211,198
211,198
Coso Funding Corp. project loans 148,346 153,650 203,226
214,917
Power Resources Inc. project
financing debt 114,571 114,571 ---
- - - - ---
U.K. credit facility 128,423 128,423 ---
- - - - ---
Other 7,927 7,927 54,707
54,707
Interest rate swap payable --- --- 226
672
16. Interest Rate Swap Agreements
In January 1993, the Coso Joint Ventures entered into five
year
deposit interest rate swap agreements. The subject deposits
represent
debt service reserves established in conjunction with refinancing
the
Coso Joint Ventures loans through Coso Funding Corp. The
deposit
interest rate swaps effectively convert interest earned on the
debt
service reserve deposits from a variable rate to a fixed
rate, in
order to match the nature of the interest rate on the borrowings
used
to fund the debt service reserve deposits. The Company's
proportion of
the deposit amount of $27,239 included in restricted cash
and
investments accretes annually to a maximum amount of
approximately
$29,300 in 1997. Under the agreements, which mature on January
11,
1998, the Coso Joint Ventures make semi-annual payments to the
counter
party at variable rates based on LIBOR, reset and compounded
every
three months, and in return receive payments based on a fixed
rate of
6.34%. The effective LIBOR rate ranged from 5.5313% to 5.9375%
during
1996 and was 5.5313% at December 31, 1996. The counter party to
these
agreements is a large multi-national financial institution.
17. Regulatory Matters
Northern is subject to price cap regulation. The Office
of
Electricity Regulation ("OFFER") controls the revenues
generated by
Northern in its distribution and supply businesses by applying a
price
control formula, P + RPI - X (where X is currently 3% for
distribution
and 2% for supply), where P is the price level at the
beginning of
each new regulatory period, RPI is the change in the Retail
Price
Index and X is an adjustment factor determined by OFFER.
In the distribution business, the Distribution Price Control
Formula
("DPCF") is usually set for a five-year period, subject to
more
frequent adjustments as determined necessary by the Director
General
of Electricity Supply (the "Regulator"). At each review,
the
Regulator can require a one-time price reduction. An initial
review
by the Regulator of allowable income in the distribution
business led
to a reduction of the price level by 17% for Northern starting
April
1, 1995, followed by efficiency factors of X=2% for each year
until
March 2000. On July 6, 1995, the Regulator announced the result
of a
further distribution price review which was precipitated by
certain
market events in the UK electric utility industry. For Northern,
such
announcement meant a further real reduction of 11% in
allowable
distribution income for the twelve months from April 1, 1996,
followed
by an efficiency factor X=3% for each year until March 31,
2000,
before an allowed increase for inflation.
In the supply business, which is progressively being
opened to
competition, price regulation still applies to the market
for
customers with demand of not more than 100kW. The calculation of
the
maximum supply charge is based on a Supply Price Control
Formula,
similar to the DPCF and is set for a four-year period. In 1993,
OFFER
announced the supply franchise market (i.e., with demand of not
more
than 100kW) income entitlement for the four-year period ending
March
1998. A relatively small efficiency factor of X=2% was
applied to
Northern and is being offset by an allowance for both unit
and
customer growth. The nonfranchise markets (above 1 MW) were
opened to
full competition during privatization in 1990; the
nonfranchise
markets above 100kW were opened to full competition starting in
April
1994.
18. Pension Commitments
Northern participates in the Electricity Supply Pension Scheme,
which
provides pension and other related defined benefits, based on
final
pensionable pay, to substantially all employees throughout
the
Electricity Supply Industry in the United Kingdom.
The actuarial computation assumed an interest rate of
7.75% an
expected return on plan assets of 8.25% and annual
compensation
increases of 5.75% over the remaining service lives of
employees
covered under the plan. Amounts funded to the pension are
primarily
invested in equity and fixed income securities.
The following table details the funded status and the
amount
recognized in the balance sheet of the Company as of December
31,
1996.
Actuarial present value of benefit obligations:
Vested benefits $ 797,932
Nonvested benefits ---
Accumulated benefit obligation 797,932
Effect of future increase in compensation 58,218
Projected benefit obligation 856,150
Fair value of plan assets 919,163
Prepaid pension asset $ 63,013
19. Commitments and Contingencies
There were no material outstanding lawsuits as of December 31,
1996.
Casecnan
In November 1995, CE Casecnan Water and Energy Company,
Inc., a
Philippine corporation ("CE Casecnan"), closed the financing
and
commenced construction of the Casecnan Project, a combined
irrigation
and 150 net MW hydroelectric power generation project (the
"Casecnan
Project") located in the central part of the island of Luzon in
the
Republic of the Philippines. The Casecnan Project will
consist
generally of diversion structures in the Casecnan and Denip
Rivers
that will divert water into a tunnel of approximately 23
kilometers.
The tunnel will transfer the water from the Casecnan and Denip
Rivers
in the Pantabangan Reservoir for irrigation and hydroelectric
use in
the Central Luzon area. An underground powerhouse located at
the end
of the water tunnel and before the Pantabangan Reservoir will
house a
power plant consisting of approximately 150 MW of newly
installed
rated electrical capacity. A tailrace tunnel of approximately
three
kilometers will deliver water from the water tunnel and the
new
powerhouse to the Pantabangan Reservoir, providing additional
water
for irrigation and increasing the potential electrical
generation at
two downstream existing hydroelectric facilities of the National
Power
Corporation of the Philippines ("NPC").
CE Casecnan, which is presently indirectly owned as to
approximately
35% of its equity by the Company and approximately 35% by
PKS, is
developing the Casecnan Project under the terms of the
Project
Agreement between CE Casecnan and the National
Irrigation
Administration ("NIA"). Under the Project Agreement, CE Casecnan
will
develop, finance and construct the Casecnan Project over an
estimated
four-year construction period, and thereafter own and operate
the
Casecnan Project for 20 years (the "Cooperation Period"). During
the
Cooperation Period, NIA is obligated to accept all deliveries of
water
and energy, and so long as the Casecnan Project is physically
capable
of operating and delivering in accordance with agreed levels set
forth
in the Project Agreement, NIA will pay CE Casecnan a guaranteed
fee
for the delivery of water and a guaranteed fee for the
delivery of
electricity, regardless of the amount of water or electricity
actually
delivered. In addition, NIA will pay a fee for all
electricity
delivered in excess of a threshold amount up to a specified
amount.
NIA will sell the electric energy it purchases to NPC, although
NIA's
obligations to CE Casecnan under the Project Agreement are
not
dependent on NPC's purchase of the electricity from NIA. All
fees to
be paid by NIA to CE Casecnan are payable in U.S. dollars.
The
guaranteed fees for the delivery of water and energy are
expected to
provide approximately 70% of CE Casecnan's revenues.
The Project Agreement provides for additional compensation
to CE
Casecnan upon the occurrence of certain events, including
increases in
Philippine taxes and adverse changes in Philippine law. Upon
the
occurrence and during the continuance of certain force majeure
events,
including those associated with Philippines political action, NIA
may
be obligated to buy the Casecnan Project from CE Casecnan at a
buy out
price expected to be in excess of the aggregate principal
amount of
the outstanding CE Casecnan debt securities, together with
accrued but
unpaid interest. At the end of the Cooperation Period, the
Casecnan
Project will be transferred to NIA and NPC for no
additional
consideration on an "as is" basis.
The Republic of the Philippines has provided a Performance
Undertaking
under which NIA's obligations under the Project Agreement
are
guaranteed by the full faith and credit of the Republic of
the
Philippines. The Project Agreement and the Performance
Undertaking
provide for the resolution of disputes by binding
arbitration in
Singapore under international arbitration rules.
The Casecnan Project is being constructed on a joint and several
basis
by Hanbo Corporation and Hanbo Engineering & Construction Co.
Ltd.
(formerly known as You One Engineering & Construction Co., Ltd.,
and
herein referred to as "HECC"), both of which are South
Korean
corporations, pursuant to a fixed-price, date-certain,
turnkey
construction contract (the "Turnkey Construction Contract").
Hanbo
Corporation and HECC (sometimes collectively referred to as
the
"Contractor") are under common ownership control. Hanbo
Corporation
is an international construction company. HECC, which
recently
emerged from a court-administered receivership, is a contractor
with
over 25 years experience in tunnel construction, using both the
drill-
and-blast and tunnel boring machine ("TBM") methods.
The Contractor's obligations under the Turnkey Construction
Contract
are guaranteed by Hanbo Iron & Steel Company, Ltd. ("Hanbo
Steel"), a
large South Korean steel company. In addition, the
Contractor's
obligations under the Turnkey Construction Contract are secured
by an
unconditional, irrevocable standby letter of credit issued by
Korea
First Bank ("KFB") in the approximate amount of $118,000. The
total
cost of the Casecnan Project, including development,
construction,
testing and startup, is estimated to be approximately $495,000.
In late January 1997, the Company was advised that Hanbo
Corporation
and Hanbo Steel had each filed to seek court receivership
protection
in Korea. At the present time, all of the construction work on
the
Casecnan Project is being performed by the second contractor
which is
party to the Turnkey Construction Contract, HECC. Although
HECC,
Hanbo Corporation and Hanbo Steel are under common ownership
control,
HECC has not filed for receivership protection and is believed
to be
solvent. However, no assurances can be given that HECC will not
file
for receivership due to the foregoing developments or that it
will
remain solvent and able to perform fully its obligations under
the
Turnkey Construction Contract.
The work on the Casecnan Project, which commenced in
1995, is
presently continuing on schedule and within the budget. CE
Casecnan
is presently reviewing its rights, obligations and potential
remedies
in respect of the recent developments regarding the co-
Contractor and
the guarantor and is presently unable to speculate as to the
ultimate
effect of such developments on CE Casecnan. However, CE Casecnan
has
recently received confirmation from HECC that it intends to
fully
perform its obligations under the Turnkey Construction Contract
and
complete the Casecnan Project on schedule and within the
budget.
Additionally, it has been reported that the South Korean
government
has informed the Philippine government that the South
Korean
government will take appropriate actions to support HECC's
completion
of the Casecnan Project.
KFB has recently reconfirmed to CE Casecnan that it will honor
its
obligations under the Casecnan Project letter of credit and also
has
stated its support for the successful completion of the
Casecnan
Project. However, Moody's Investors Service has recently
issued a
warning for a possible ratings downgrade for KFB because of
the
possible impact of the Hanbo Steel receivership on the
substantial
loans KFB previously made to Hanbo Steel. In a related
development,
the South Korean government has recently announced that it
would
provide some funding to assist Hanbo Steel's creditor banks
(including
KFB) and its subcontractors.
CE Casecnan financed a portion of the costs of the Casecnan
Project
through the issuance of $125,000 of its 11.45% Senior Secured
Series A
Notes due 2005 and $171,500 of its 11.95% Senior Secured
Series B
Notes due 2010 pursuant to an indenture dated November 27,
1995, as
amended to date (the "Casecnan Indenture"). Although no default
has
occurred under the Casecnan Indenture as a result of the
announced
receivership of Hanbo Corporation, CE Casecnan will
continue to
closely monitor the Hanbo group and KFB developments and
project
construction status and develop appropriate contingency plans.
If HECC were to materially fail to perform its obligations under
the
Turnkey Construction Contract and if KFB were to fail to honor
its
obligations under the Casecnan letter of credit, such actions
could
have a material adverse effect on the Casecnan Project
and CE
Casecnan. However, based on the information presently
available to
it, CE Casecnan does not presently expect that either such event
will
occur.
Leases
Certain retail facilities, buildings and equipment are leased.
The
leases expire in periods ranging from one to 75 years and some
provide
for renewal options.
At December 31, 1996, the Company's future minimum rental
payments
with respect to non-cancellable operating leases were as follows:
1997 $ 9,137
1998 8,897
1999 5,337
2000 5,279
2001 5,098
Thereafter 61,204
$94,952
20. Subsequent Event
On February 26, 1997, CalEnergy Capital Trust II, a special
purpose
Delaware business trust organized by the Company (the "Trust
II"),
pursuant to the Amended and Restated Declaration of Trust
(the
"Declaration") dated as of February 26, 1997, completed a
private
placement (with certain shelf registration rights) of
$150,000 of
trust preferred convertible securities, referred to as Company-
obligated mandatorily redeemable convertible preferred
securities of
subsidiary trust holding solely convertible debentures
("Trust
Securities"). In addition, an option to purchase an additional
600
Trust Securities, or $30,000, was exercised by the initial
purchasers
to cover over-allotments.
The Trust has issued 3,600 of 6 1/4% Trust Securities
with a
liquidation preference of fifty dollars each. The Company owns
all of
the common securities of the Trust. The Trust Securities and
the
common securities represent undivided beneficial ownership
interests
in the Trust. The assets of the Trust consist solely of the
Company's
6 1/4% Convertible Junior Subordinated Debentures due 2012
in an
outstanding aggregate principal amount of $180,000
("Junior
Debentures") issued pursuant to an indenture dated as of February
20,
1997. The indenture includes an agreement by the Company to
pay
expenses and obligations incurred by the Trust. Each Trust
Security
will be convertible at the option of the holder thereof at any
time
into 1.1655 shares of CalEnergy Common Stock (equivalent
to a
conversion price of $42.90 per share of the Company's Common
Stock),
subject to customary anti-dilution adjustments.
Until converted into the Company's Common Stock, the Trust
Securities
will have no voting rights with respect to the Company and,
except
under certain limited circumstances, will have no voting rights
with
respect to the Trust. Distributions on the Trust Securities
(and
Junior Debentures) are cumulative, accrue from the date of
initial
issuance and are payable quarterly in arrears, commencing
June 1,
1997. The Junior Debentures are subordinated in right of
payment to
all senior indebtedness of the Company and the Junior Debentures
are
subject to certain covenants, events of default and optional
and
mandatory redemption provisions, all as described in the
Junior
Debenture Indenture.
Pursuant to a Preferred Securities Guarantee Agreement
(the
"Guarantee"), between the Company and a preferred guarantee
trustee,
the Company has agreed irrevocably to pay to the holders of the
Trust
Securities, to the extent that the Trust has funds available to
make
such payments, quarterly distributions, redemption payments
and
liquidation payments on the Trust Securities. Considered
together,
the undertaking contained in the Declaration, Junior
Debentures,
Indenture and Guarantee constitute a full and unconditional
guarantee
by the Company of the Trust's obligations under the Trust
Securities.
A portion of the net proceeds of the Trust Securities offering
were
used to repay the CalEnergy Credit Facility.
21. Geographic Information
The Company operates in one principal industry segment: the
generation, distribution and supply of electricity to customers
located throughout the world. The Company's operations by
geographic
area are as follows:
1996 1995 1994
Revenue
Americas 457,032 355,112 154,562
Asia 35,691 --- ---
Europe 39,191 --- ---
531,914 355,112 154,562
Operating income (loss)
Americas 203,305 155,885 77,450
Asia 17,914 --- ---
Europe 6,163 --- ---
227,382 155,885 77,450
1996 1995
Identifiable assets
Americas $2,613,830 $2,194,873
Asia 713,570 459,165
Europe 2,385,507 ---
$5,712,907 $2,654,038
22. QUARTERLY FINANCIAL DATA (UNAUDITED)
Following is a summary of the Company's quarterly results of
operations for the years ended December 31, 1996 and December 31,
1995.
Three Months Ended *
1996: (1) March 31 June 30 September 30
December 31
Sales of electricity $75,944 $104,735 $165,487
$172,768
and steam
Total revenue 90,356 115,794 179,048
190,997
Total costs and 69,398 87,482 123,169
160,433
expenses
Income before provision
for income 20,958 28,312 55,879
30,564
taxes and minority 6,497 9,040 18,325
7,959
interest
Provision for income
taxes
Net income before 14,461 19,272 37,554
22,605
minority interest --- --- ---
1,431
Minority interest
Net income attributable $14,461 $ 19,272 $ 37,544 $
21,174
to common shares
Net income per share -
primary $ .27 $ .35 $ .67 $
33
Net income per share -
fully diluted $ .26 $ .33 $ .59 $
.32
Three Months Ended *
1995: (2) March 31 June 30 September 30
December 31
Sales of electricity
and steam $72,978 $ 81,756 $102,423 $
78,473
Total revenue 86,685 97,096 119,717
95,225
Total costs and
expenses 68,527 76,957 79,898
76,290
Income before provision
for income taxes and
minority interest 18,158 20,139 39,819
18,935
Provision for income
taxes 5,540 6,248 12,457
6,386
Net income before
minority interest 12,618 13,891 27,362
12,549
Minority interest 3,005 --- --- --
- - - - -
Net income 9,613 13,891 27,362
12,549
Preferred dividends 1,080 --- --- --
- - - - -
Net income attributable
to common shares $ 8,533 $13,891 $27,362 $
12,549
Net income per share -
primary $ .21 $ .27 $ .52 $
.24
Net income per share -
fully diluted $ .21 $ .27 $ .48 $
.18
* The Company's operations are seasonal in nature with a
disproportionate percentage of income historically earned in the
second and third quarters.
(1) Reflects acquisitions of Northern, Falcon Seaboard and the
Partnership Interest.
(2) Reflects acquisition of Magma.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Shareholders
CalEnergy Company, Inc.
Omaha, Nebraska
We have audited the accompanying consolidated balance sheets
of
CalEnergy Company, Inc. and subsidiaries as of December 31,
1996
and 1995, and the related consolidated statements of
operations,
stockholders' equity and cash flows for each of the three years
in
the period ended December 31, 1996. 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 in accordance with generally
accepted
auditing standards. Those standards 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. An audit
also
includes assessing the accounting principles used and
significant
estimates made by management, as well as evaluating the
overall
financial statement presentation. We believe that our
audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements
present
fairly, in all material respects, the financial position
of
CalEnergy Company, Inc. and subsidiaries at December 31, 1996
and
1995 and the results of their operations and their cash flows
for
each of the three years in the period ended December 31, 1996,
in
conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Omaha, Nebraska
January 31, 1997
(February 27, 1997 as to Notes 6 and 20)
_______________________________