Exhibit 13
Financial Summary
Over the last three years ended December 31, 1997, CalEnergy
Company, Inc. ("CalEnergy" or the "Company") has experienced
significant growth. Revenues have risen at a compound annual
rate of 130% from approximately $186 million in 1994 to
approximately $2,271 million in 1997 and net income available to
common stockholders excluding non-recurring and extraordinary
items has risen at a compound annual rate of 60% from
approximately $33.8 million in 1994 to approximately $138.8
million in 1997. 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 September 11, 1997, the Company signed a definitive agreement
with Kiewit Diversified Group ("KDG"), a wholly owned subsidiary
of Peter Kiewit Sons', Inc. ("PKS"), for the Company to purchase
KDG's ownership interest in various project partnerships and
CalEnergy common shares (the "KDG Acquisition"). Accordingly,
common stock and options subject to redemption have been
reclassified in the consolidated balance sheet.
KDG's ownership interest in CalEnergy comprised 20,231,065 shares
of common stock (assuming exercise by KDG of one million options
to purchase CalEnergy shares), the 30% interest in Northern
Electric plc ("Northern"), as well as the following minority
project interests: Mahanagdong (45%), Casecnan (35%), Dieng
(47%), Patuha (44%) and Bali (30%) and other interests in
international development stage projects.
CalEnergy paid approximately $1,159 million for the KDG
Acquisition and final closing of the transaction occurred in
January 1998. CalEnergy funded this acquisition with available
cash and the net proceeds of the equity and senior note offerings
completed in October 1997.
On December 24, 1996, CE Electric plc ("CE Electric"), which in
1997 was 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 a tender offer
(the "Northern Tender Offer") commenced in the United Kingdom on
November 5, 1996. As of March 18, 1997, CE Electric effectively
owned 100% of Northern's ordinary shares.
In the last three 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. 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.
The Company has substantially completed constructing the Dieng
Unit I, 55 net MW geothermal project in Indonesia, which is the
first unit of 400 MW under contract at Dieng. In 1997, the
Company financed and commenced construction of two other
projects; the Dieng Unit II 80 MW project as well as the Patuha
Unit I 80 MW project, which is the first unit of 400 MW under
contract at Patuha. Additionally, the Company has conducted
infrastructure construction and drilling activities for the 400
MW Bali project. Although the Company intends to enforce its
contractual rights, the ultimate outcome of the current uncertain
situation in Indonesia with respect to the possible abrogation by
the Indonesian government of the Dieng, Patuha and Bali contracts
adds significant risk to the completion of those projects and
resulted in the Company recording an asset impairment charge in
the fourth quarter of 1997. This $87 million charge includes all
reasonably estimated asset valuation impairments associated with
the Company's assets in Indonesia and gives effect to the
political risk insurance on such investment.
SELECTED Financial Data
Dollars in Thousands, Except Per Share Amounts
Year Ended December 31,
1997 1996(1) 1995(2) 1994 1993
Income Statement Data:
Operating revenue $2,166,338 $518,934 $335,630 $154,562 $132,059
Total revenue 2,270,911 576,195 398,723 185,854 149,253
Expenses 2,074,051 435,791 301,672 130,018 87,995
Income before provision
for income taxes 196,860(3) 140,404 97,051 55,836 61,258
Minority interest 45,993 6,122 3,005 --- ---
Income before change in accounting
principle and
extraordinary item 51,823(3) 92,461 63,415 38,834 43,074
Cumulative effect of change in
accounting principle --- --- --- --- 4,100
Extraordinary item (135,850) --- --- (2,007) ---
Net income (loss) (84,027)(3) 92,461 63,415 36,827 47,174
Preferred dividends --- --- 1,080 5,010 4,630
Net income (loss) available to
common stockholders (84,027)(3) 92,461 62,335 31,817 42,544
Income per share before change in accounting
principle and
extraordinary item 0.77(3) 1.69 1.32 1.02 1.08
Cumulative effect of change in accounting
principle per share --- --- --- --- 0.12
Extraordinary item per share (2.02) --- --- (0.06) ---
Net income (loss) per share (1.25)(3) 1.69 1.32 0.96 1.20
Balance Sheet Data:
Total assets 7,487,626 5,630,156 2,654,038 1,131,145 715,984
Total liabilities 5,282,162 4,181,052 2,084,474 867,703 425,393
Company-obligated mandatorily
redeemable convertible
preferred securities of
subsidiary trusts 553,930 103,930 --- --- ---
Preferred securities of
subsidiary 56,181 136,065 --- --- ---
Minority interest 134,454 299,252 --- --- ---
Redeemable preferred stock --- --- --- 63,600 58,800
Stockholders' equity 765,326 880,790 543,532 179,991 211,503
1 Reflects the acquisitions of Northern, Falcon Seaboard and the
Partnership Interest owned for a portion of the
year. See Note 4 to the financial statements.
2 Reflects the acquisition of Magma owned for a portion of the
year.
3 Includes the $87,000, $1.29 per share, non-recurring asset
impairment charge.
MANAGEMENT'S Discussion and Analysis of Financial Condition
and Results of Operations
Dollars, Pounds and Shares in Thousands, Except Per Share Amounts
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. The Company's
actual results in the future could differ significantly from the
Company's historical results.
Acquisitions
On December 24, 1996, CE Electric plc ("CE Electric"), which in
1997 was 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
"Northern Tender Offer") commenced in the United Kingdom on
November 5, 1996. As of March 18, 1997, CE Electric effectively
owned 100% of Northern's ordinary shares.
In the last three 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 $958,000. 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 nominal
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 5 to the financial statements for a discussion of the
Company's significant operating contracts.
Results of Operations Three Years Ended December 31, 1997, 1996
and 1995
Operating revenues increased to $2,166,338 in the year ended
December 31, 1997, from $518,934 in the year ended December 31,
1996, a 317.5% increase. This growth was primarily due to the
acquisitions of Northern, Falcon Seaboard, and the Partnership
Interest as well as the commencement of earnings at Salton Sea
IV, Upper Mahiao and Malitbog.
The increase in operating revenues in 1996 to $518,934 from
$335,630 in 1995 was primarily due to the acquisitions of the
Partnership Interest, Falcon Seaboard and Northern, the deemed
completion and commencement of receipt of revenue from Upper
Mahiao and Unit I of the Malitbog Project in the Philippines, the
completion and commencement of commercial operation of Salton Sea
IV and an increase in the Coso Project's electricity revenues.
The following data represents the supply and distribution
operations at Northern:
1997 1996 1995
Supply (GWh) 14,389 14,185 14,253
Distribution (GWh) 15,714 15,656 15,260
Gas Therms Supply (in thousands) 74.5 50.0 35.3
The increase in units supplied and distributed in 1997 from 1996
reflects increased activity in the local economy. The increase in
therms supplied in 1997 from 1996 reflects the increased volume
as the gas business in the U.K. begins to open up to competition
as a result of regulatory changes.
The following operating data represents the aggregate capacity
and electricity production of the domestic geothermal projects:
1997 1996 1995
Overall capacity factor 101.4% 104.4% 104.8%
kWh produced (in thousands) 4,507,500 4,502,200 4,296,010
Capacity NMW (average) 507.4 491.0* 467.8
* Weighted average for the commencement of operations at the
Salton Sea IV in 1996.
The capacity factor was 100.4% in the fourth quarter of 1997
compared to 102.6%, 99.6% and 103.1% for the third, second and
first quarters of 1997, respectively. The capacity factor
decreased in 1997 from 1996 due to marginally decreasing
production at the Coso Project and a scheduled turbine overhaul
at BLM in April 1997.
The following operating data represents the aggregate capacity
and electricity production of the Gas Plants:
1997 1996 1995
Overall capacity factor 84.3% 84.2% 88.8%
kWh produced (in thousands) 4,211,030 4,216,800 4,433,900
Installed capacity NMW 570 570 570
The capacity factor of the Gas Plants reflects the effect of
certain contractual curtailments. The capacity factors adjusted
for these contractual curtailments are 95.7%, 93.2% and 96.8% for
1997, 1996 and 1995, respectively.
Electric sale price per kWh for the Coso Project, Partnership
Project and Salton Sea Project varies seasonally in accordance
with the rate schedule referenced 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
received in 1997, 1996 and 1995 were comprised of (in cents):
Coso Project Energy Capacity & Bonus Total
Average fiscal 1997 12.56 1.91 14.47
Average fiscal 1996 12.61 1.82 14.43
Average fiscal 1995 11.81 1.82 13.63
Partnership Project Energy Capacity & Bonus Total
Average fiscal 1997 10.96 2.18 13.14
Average fiscal 1996 10.02 2.12 12.14
Average fiscal 1995 11.14 2.10 13.24
Salton Sea Project Energy Capacity & Bonus Total
Average fiscal 1997 8.66 1.97 10.63
Average fiscal 1996 8.84 2.29 11.13
Average fiscal 1995 9.50 2.33 11.83
Interest and other income increased in 1997 to $104,573 from
$57,261 in 1996, an 82.6% increase. This increase was due
primarily to interest earned by Northern, equity earnings from
Saranac and Mahanagdong, and increased interest income on the
proceeds of the equity and senior note offerings in October 1997.
Interest and other income decreased in 1996 to $57,261 from
$63,093 in 1995.
Overall, the Company's expenses increased in 1997 due to the full
year of operations of Northern, Falcon Seaboard, Partnership
Interest, Salton Sea IV Project, Upper Mahiao Project and Unit I
of the Malitbog Project and the deemed completion of Units II and
III of the Malitbog Project in July 1997.
Cost of sales increased to $1,055,195 in 1997 from $31,840 in
1996. This increase is a result of reflecting a full year of
Northern's operations. Cost of sales represents Northern's costs
of electricity and appliances during the period of the Company's
controlling interest since December 24, 1996.
Operating expense increased to $345,833 in 1997 from $132,655 in
1996, an increase of 160.7%. This increase is a result of the
acquisitions of Northern, Falcon Seaboard and the Partnership
Interest as well as the commencement of receipt of revenue at
Salton Sea IV, Upper Mahiao and Malitbog. Operating expense
increased to $132,655 in 1996 from $103,602 in 1995, an increase
of 28.0%. 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.
General and administration costs increased to $52,705 in 1997
from $21,451 in 1996, an increase of 145.7%. This increase is
primarily a result of the addition of Northern. 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.
Depreciation and amortization increased to $276,041 in 1997 from
$118,586 in 1996, an increase of 132.8%. This increase is a
result of the acquisitions of Northern, Falcon Seaboard and the
Partnership Interest as well as the commencement of the receipt
of revenue at Salton Sea IV, Upper Mahiao and Malitbog.
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 Magma, Partnership Interest and Falcon Seaboard
acquisitions, and the commencement of the receipt of revenue at
Salton Sea IV, Upper Mahiao and Malitbog.
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 1997 to
$251,305 from $126,038 in 1996, a 99.4% increase, and increased
to $126,038 in 1996 from $102,083 in 1995, a 23.5% 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 non-recurring charge of $87,000 represents an asset valuation
impairment under Financial Accounting Standard No. 121,
"Accounting for the Impairment of Long-Lived Assets", relating to
CalEnergy's assets in Indonesia. The charge includes all
reasonably estimated cash flows associated with the Company's
assets in Indonesia and gives effect to the political risk
insurance on such investments. The estimate assumes there will
be no tax benefits associated with the asset valuation
impairment.
The provision for income taxes increased to $99,044 in 1997 from
$41,821 in 1996 and $30,631 in 1995. After adjusting for the non-
recurring charge for asset valuation impairment and the dividends
on convertible preferred securities, the effective tax rate was
38.0%, 30.8%, and 31.6% in 1997, 1996, and 1995, respectively.
The increase from 1996 to 1997 is due primarily to larger energy
tax credits and depletion deductions in 1996.
Minority interest increased to $45,993 in 1997 from $6,122 in
1996, an increase of 651.3%. Minority interest consists of
dividends on convertible preferred securities of subsidiary
trusts and the Company's partial ownership in Northern. This
increase is a result of issuance of the $180,000 of Trust II
Securities in February 1997 and $270,000 of Trust III Securities
in August 1997 and a full year of operations from Northern.
Minority interest in 1995 reflects the Company's partial
ownership in Magma for the period from January 10, 1995 to
February 24, 1995.
Income before extraordinary item was $51,823 or $0.77 per common
share in 1997 compared to $92,461 or $1.69 per common share in
1996 and $62,335 or $1.32 per common share in 1995. Excluding
the $87,000, $1.29 per share, non-recurring charge, income before
extraordinary item would have been $138,823 in 1997.
On July 31, 1997, the Finance Act in the United Kingdom was
passed by Parliament and included the introduction of a one time
so-called "windfall tax" equal to 23% of the difference between
the price paid for Northern upon privatization and the Labour
government's assessed "value" of Northern as calculated by
reference to a formula set forth in the July budget. This
amounted to $135,850, net of minority interest, which was
recorded as an extraordinary item. The first installment was
paid on December 1, 1997 and the second installment is payable on
December 1, 1998.
Liquidity and Capital Resources
Cash and short-term investments were $1,446,620 at December 31,
1997 as compared to $429,421 at December 31, 1996. In addition,
the Company's share of joint venture cash and investments
retained in project control accounts was $6,072 and $47,764 at
December 31, 1997 and 1996, 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
$223,636 and $106,968 at December 31, 1997 and 1996,
respectively. The restricted cash balances are comprised
primarily of amounts deposited in restricted accounts from which
the Company will fund construction of Dieng Unit II and Patuha
Unit I; the Power Resources Project, the Upper Mahiao Project and
the Malitbog Project cash reserves for the debt service reserve
funds; and the Coso Project royalty payment.
The Company repurchased 1,622 common shares during 1997 for the
aggregate amount of $55,505. The Company repurchased 472 shares
of common stock in 1996 at an aggregate amount of $12,008. As of
December 31, 1997 the Company held 1,658 shares of treasury stock
at a cost of $56,525 to provide shares for issuance under the
Company's employee stock option and share purchase plan and other
outstanding convertible securities. The repurchase plan minimizes
the dilutive effect of the additional shares issued under these
plans.
On September 11, 1997, the Company signed a definitive agreement
with Kiewit Diversified Group ("KDG"), a wholly owned subsidiary
of PKS, for the Company to purchase KDG's ownership interest in
various project partnerships and CalEnergy common shares (the
"KDG Acquisition").
KDG's ownership interest in CalEnergy comprised approximately
20,231 shares of common stock (assuming exercise by KDG of one
million options to purchase CalEnergy shares), the 30% interest
in Northern Electric, as well as the following minority project
interests: Mahanagdong (45%), Casecnan (35%), Dieng (47%),
Patuha (44%) and Bali (30%) and other interests in international
development projects.
CalEnergy paid $1,159,215 for the KDG Acquisition and final
closing of the transaction occurred in January 1998. CalEnergy
funded this acquisition with available cash and the proceeds of
the equity and senior note offerings completed in October 1997.
On December 15, 1997, CE Electric UK Funding Company, an indirect
subsidiary of the Company (the "Funding Company"), issued
$125,000 of 6.853% senior notes due 2004, and $237,000 of 6.995%
senior notes due 2007 (collectively, the "CE Electric UK Funding
Company Senior Notes"), and pound 200,000 of 7.25% Sterling Bonds due
2022.
On November 26, 1997, the Company amended and increased its
$100,000 revolving credit facility to $400,000. The facility is
unsecured and is available to fund working capital requirements
and finance future business expansion opportunities.
On October 17, 1997, the Company completed the public offering of
17.1 million shares of its common stock ("Common Stock") at $37
7/8 per share (the "Public Offering"). In addition, 2 million
shares of Common Stock were purchased from CalEnergy in a direct
sale by a trust affiliated with Walter Scott, Jr., the Chairman
and Chief Executive Officer of PKS (the "Direct Sale"),
contemporaneously with the closing of the Public Offering.
On October 28, 1997, the Company completed the sale of $350,000
aggregate principal amount of its 7.63% Senior Notes due 2007
(the "Senior Note Offering").
On August 12, 1997, a subsidiary of the Company completed a
private placement (with certain shelf registration rights) of
$225,000 aggregate amount of 6 1/2% Trust Convertible Preferred
Securities (the "6 1/2% Trust Securities"). In addition, an
option to purchase an additional 900 of the 6 1/2% Trust
Securities, or $45,000 aggregate amount, was exercised by the
initial purchasers to cover overallotments in connection with the
placement. Each 6 1/2% Trust Security has a liquidation
preference of fifty dollars and is convertible at any time at the
option of the holder into 1.047 shares of Company Common Stock
(equivalent to a conversion price of $47.75 per common share)
subject to adjustments in certain circumstances.
On August 5, 1997, the Company and certain affiliated capital
funding trusts filed with the Securities and Exchange Commission
a shelf registration statement covering up to $1,500,000 of
common stock, preferred stock and debt securities which may be
sold from time to time for various purposes. The Company
completed the Public Offering and the Senior Note Offering under
the shelf registration statement.
On February 26, 1997, a subsidiary of the Company completed a
private placement (with certain shelf registration rights) of
$150,000 aggregate amount of 6 1/4% 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.
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 approximately 70% indirectly
owned by the Company (after the KDG Acquisition), is developing
the Casecnan Project. 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 Bonds due 2010 and $75,000 of its
Secured Floating Rate Notes due 2002, pursuant to an indenture
dated as of November 27, 1995, as amended to date.
The Casecnan Project was being constructed pursuant to a fixed-
price, date-certain, turnkey construction contract (the "Hanbo
Contract") on a joint and several basis by Hanbo Corporation
("Hanbo") and Hanbo Engineering and Construction Co., Ltd.
("HECC"), both of which are South Korean corporations. As of May
7, 1997, CE Casecnan terminated the Hanbo Contract due to
defaults by Hanbo and HECC including the insolvency of each such
company. On May 7, 1997, CE Casecnan entered into a new turnkey
engineering, procurement and construction contract to complete
the construction of the Casecnan Project (the "Replacement
Contract"). The work under the Replacement Contract is being
conducted by a consortium consisting of Cooperativa Muratori
Cementisti CMC di Ravenna and Impressa Pizzarottie & C. Spa,
working together with Siemens A.G., Sulzer Hydro Ltd., Black &
Veatch and Colenco Power Engineering Ltd. (collectively, the
"Replacement Contractor").
In connection with the Hanbo Contract termination, CE Casecnan
tendered a certificate of drawing to Korea First Bank ("KFB") on
May 7, 1997, under the irrevocable standby letter of credit
issued by KFB as security under the Hanbo Contract to pay for
certain transition costs and other presently ascertainable
damages under the Hanbo Contract. As a result of KFB's wrongful
dishonor of the draw request, CE Casecnan filed an action in New
York State Court. That Court granted CE Casecnan's request for a
temporary restraining order requiring KFB to deposit $79,329, the
amount of the requested draw, in an interest bearing account with
an independent financial institution in the United States. KFB
appealed this order, but the appellate court denied KFB's appeal
and on May 19, 1997, KFB transferred funds in the amount of
$79,329 to a segregated New York bank account pursuant to the
Court order.
On August 6, 1997, CE Casecnan announced that it had issued a
notice to proceed to the Replacement Contractor. The Replacement
Contractor has fully mobilized and commenced engineering,
procurement and construction work on the Casecnan Project.
On August 27, 1997, CE Casecnan announced that it had received a
favorable summary judgment ruling in New York State Court against
KFB. The judgment, which has been appealed by the bank, requires
KFB to honor the $79,329 drawing by CE Casecnan on a $117,850
irrevocable standby letter of credit.
On September 29, 1997, CE Casecnan tendered a second certificate
of drawing for $10,828 to KFB and on December 30, 1997 CE
Casecnan tendered a third certificate of drawing for $2,920 to
KFB. KFB also wrongfully dishonored these draws, but pursuant to
a stipulation agreed to deposit the draw amounts in an interest
bearing account with the same independent financial institution
in the United States pending resolution of the appeal regarding
the first draw and agreed to expedite the appeal.
The receipt of the letter of credit funds from KFB remains
essential and CE Casecnan will continue to press KFB to honor its
clear obligations under the letter of credit and to pursue Hanbo
and KFB for any additional damages arising out of their actions
to date. If KFB were to fail to honor its obligations under the
Casecnan letter of credit, such action could have a material
adverse effect on the Casecnan Project and CE Casecnan.
On September 2, 1997, Hanbo and HECC filed a Request for
Arbitration before the International Chamber of Commerce ("ICC").
The Request for Arbitration asserts various claims by Hanbo and
HECC against CE Casecnan relating to the terminated Hanbo
Contract and seeking damages. On October 10, 1997, CE Casecnan
served its answer and defenses in response to the Request for
Arbitration as well as counterclaims against Hanbo and HECC for
breaches of the Hanbo Contract. The arbitration proceedings
before the ICC are ongoing and CE Casecnan intends to pursue
vigorously its claims against Hanbo, HECC and KFB in the
proceedings described above.
In June 1997, the Company's indirect special-purpose subsidiary,
CE Indonesia Funding Corp., entered into a $400,000 revolving
credit facility (which is nonrecourse to the Company) to finance
the development and construction of the Company's geothermal
power facilities in Indonesia.
On September 20, 1997, a Presidential Decree (the "Decree") was
issued in Indonesia, providing for government action to the
effect that, in order to address certain recent fluctuations in
the value of the Indonesian currency, the start-up dates for a
number of private power projects would be: (i) continued
according to their initial schedule (because construction was
underway); (ii) postponed as to their start-up dates (because
they are not yet in construction) until economic conditions have
recovered; or (iii) reviewed with a view to being continued,
postponed or rescheduled, depending on the status of those
projects. In the Decree, Dieng Units 1, 2 and 3 are approved to
continue according to their initial schedule; Patuha Unit 1 and
Bali Units 1 and 2 are to receive further review to determine
whether or not they should be continued in accordance with their
initial schedule; and Bali Units 3 and 4, Patuha Units 2, 3 and 4
and Dieng Unit 4 are to be postponed for an unspecified period.
In this regard, the Company notes that its contracts and
government undertakings for the Dieng, Patuha and Bali projects
do not by their terms permit such categorization or delays by the
government and that the Company has obtained political risk
insurance coverage for its Dieng and Patuha projects. Moreover,
the Company intends to continue to take actions to attempt to
require the Government of Indonesia to honor its contractual
obligations; however, subsequent actions by the Government of
Indonesia and continued economic problems in Indonesia have
created further uncertainty as to whether the contracts for such
projects will be abrogated by the Indonesian government and
accordingly have created significant risks to the completion of
these projects. As a result, the Company recorded a SFAS 121
asset valuation impairment charge of $87,000 in the fourth
quarter of 1997. This charge includes all reasonably estimated
asset valuation impairments associated with the Company's assets
in Indonesia and gives effect to the political risk insurance on
such investments.
On December 2, 1994, a subsidiary of the Company, Himpurna
California Energy Ltd. ("HCE") executed a joint operation
contract (the "Dieng JOC") for the development of the geothermal
steam field and geothermal power facilities at the Dieng
geothermal field, located in Central Java (the "Dieng Project")
with Perusahaan Pertambangan Minyak Dan Gas Bumi Negara
("Pertamina"), the Indonesian national oil company, and executed
a "take-or-pay" energy sales contract (the "Dieng ESC") with both
Pertamina and P.T. PLN (Persero) ("PLN"), the Indonesian national
electric utility. HCE was formed pursuant to a joint development
agreement with P.T. Himpurna Enersindo Abadi ("P.T. HEA"), its
Indonesian partner, which is a subsidiary of Himpurna, whereby
the Company and P.T. HEA have agreed to work together on an
exclusive basis to develop the Dieng Project (the "Dieng Joint
Venture"). Subsequent to the January 1998 KDG acquisition, the
Dieng Joint Venture is structured with subsidiaries of the
Company holding an approximate 94% interest (including certain
assignments of dividend rights representing an economic interest
of 4%), and P.T. HEA holding a 6% interest in the Dieng Project.
Financial closing and first disbursement of construction loan
funds occurred on October 3, 1996. Construction of Dieng Unit I
is expected to be completed in March 1998.
Pursuant to the Dieng JOC and ESC, Pertamina has granted to HCE
the geothermal field and the wells and other facilities presently
located thereon and HCE may build, own and operate power
production units with an aggregate capacity of up to 400 MW. HCE
will accept the field operation responsibility for developing and
supplying the geothermal steam and fluids required to operate the
plant. The Dieng JOC is structured as a build own operate
transfer agreement and will expire (subject to extension by
mutual agreement) on the date which is the later of (i) 42 years
following effectiveness of the Dieng JOC and (ii) 30 years
following the date of commencement of commercial generation of
the final unit. Upon the expiration of the proposed Dieng JOC,
all facilities will be transferred to Pertamina at no cost.
HCE began well testing in the fourth quarter of 1995 and issued a
notice to proceed for the construction and supply of an initial
55 net MW unit ("Dieng Unit I") in the first quarter of 1996. PT
Kiewit/Holt Indonesia, a consortium including Kiewit Construction
Group, Inc., a subsidiary of PKS ("KCG"), is constructing Dieng
Unit I pursuant to a fixed price, date certain, turnkey
construction contract ("Construction Contract"). Affiliates of
KCG are providing the engineered supply with respect to Dieng
Unit I pursuant to a fixed price, date certain, turnkey supply
contract ("Supply Contract"). The Construction Contract and
Supply Contract are sometimes referred to herein as the "Dieng
EPC" and KCG and their affiliates party to the Construction
Contract and Supply Contract are sometimes referred to herein,
collectively, as the "Construction Consortium." The obligations
of the Construction Consortium under the Construction and Supply
Contracts are supported by a guaranty of KCG. KCG is the lead
member of the Construction Consortium, with a 60% interest. HCE
will be responsible for operating and managing the Dieng Project.
In the fourth quarter of 1997, HCE issued a notice to proceed and
closed the project financing for the construction and supply of
the Dieng Unit II 80 net MW project. The same construction
consortium as described above for Dieng Unit I has contracted to
construct Dieng Unit II under similar terms. The Company has
contributed the necessary equity for the completion of Dieng Unit
II and the construction loan of $109,000 was arranged under the
June 1997 CE Indonesia Funding Corp. facility. However, pending
resolution of the current uncertainties associated with
Indonesia, construction activities on this project have been
significantly reduced.
Patuha Power, Ltd. ("Patuha Power") is developing a geothermal
power plant in the Patuha geothermal field in Java, Indonesia
(the "Patuha Project"). On December 2, 1994, Patuha Power
executed both a joint operation contract and an energy sales
contract, each of which contains terms substantially similar to
those described above for the Dieng Project. Patuha Power began
well testing and exploration in the fourth quarter of 1995 and in
the third quarter of 1997, issued a notice to proceed for the
construction and supply of the Patuha Unit I 80 net MW project.
The same construction consortium as described above for Dieng
Unit I has contracted to construct Patuha Unit I under similar
terms. The Company has contributed the necessary equity for the
completion of Patuha Unit I and the construction loan of $150,000
was arranged under the June 1997 CE Indonesia Funding Corp.
facility. However, pending resolution of the current
uncertainties associated with Indonesia, construction activities
on this project have been significantly reduced.
The Company and PT Panutan Group, an Indonesian consortium of
energy, oil, gas and mining companies, have formed a joint
venture to pursue the development of geothermal resources in Bali
(the "Bali Project"). The PT Panutan Group is entitled to
contribute up to 40% of the total equity and obtain up to 40% of
the net profit of the Bali Project. The project company
developing the Bali Project, Bali Energy Ltd. ("Bali Energy"),
has executed both a joint operation contract and an energy sales
contract with terms similar to those at Dieng and Patuha.
However, pending resolution of the current uncertainties
associated with Indonesia, infrastructure construction and
drilling activities on this project have been significantly
reduced.
The Company developed and owns the rights to a proprietary
process for the extraction of minerals from elements in solution
in the geothermal brine and fluids utilized at its Imperial
Valley plants (the "Salton Sea Extraction Project") as well as
the production of power to be used in the extraction process.
The initial phase of the project would require delivery of 49 net
MW of power. A pilot plant has successfully produced commercial
quality zinc at the Company's Imperial Valley Project. Zinc is
primarily used in galvanizing steel for use in the automobile
industry. The Company intends to sequentially develop manganese,
silver, gold, lead, boron, lithium and other products as it
further develops the extraction technology. The Company is also
investigating producing silica from the solids precipitated out
of the geothermal power process. Silica is used as a filler for
such products as paint, plastics and high temperature cement. If
successfully developed, the mineral extraction process will
provide an environmentally responsible and low cost minerals
recovery methodology.
Subsidiaries of Magma, a subsidiary of the Company, sought new
long-term final SO4 power purchase agreements in the Salton Sea
area through the bidding process adopted by the California Public
Utilities Commission ("CPUC") under its 1992 Biennial Resource
Plan Update ("BRPU"). In its BRPU, the 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.
Within the United Kingdom there was continued investment to
extend and improve the electricity distribution network.
Expenditures in the year were approximately $102,000 although
customers directly contributed approximately $33,000 to the
additional costs incurred in expanding the system to meet their
specific requirements.
The Company is actively seeking to develop, construct, own and
operate new energy projects, both domestically and
internationally, the completion of any of which is subject to
substantial risk. 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.
There can be no assurance that development efforts on any
particular project, or the Company's development 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 generation 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
uncertainties, more specifically described in the Company's Form
8-K dated March 6, 1998, filed with the Securities and Exchange
Commission and incorporated herein by reference.
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 after the dates of firm operation under each power
purchase agreement.
The Company has commenced, for all of its information systems, a
year 2000 date conversion project to address all necessary code
changes, testing and implementation. The "Year 2000 Computer
Problem" creates risk for the Company from unforeseen problems in
its own computer systems and from third parties with whom the
Company deals on financial transactions worldwide. Such failures
of the Company's and/or third parties' computer systems could
have a material impact on the Company's ability to conduct its
business, and especially to process and account for the transfer
of funds electronically. Management believes that the year 2000
implementation costs and related potential effect should not have
a material financial impact on the Company.
CONSOLIDATED BALANCE SHEETS
As of December 31, 1997 and 1996
Dollars and Shares in Thousands, Except Per Share Amounts
ASSETS 1997 1996
Cash and cash equivalents (Note 3) $ 1,445,338 $ 424,500
Joint venture cash and investments 6,072 47,764
Restricted cash 223,636 106,968
Short-term investments 1,282 4,921
Accounts receivable 376,745 342,307
Properties, plants, contracts and
equipment, net 3,528,910 3,225,496
Excess of cost over fair value of net
assets acquired, net 1,312,788 790,920
Equity investments 238,025 238,856
Deferred charges and other assets 354,830 448,424
Total assets $ 7,487,626 $ 5,630,156
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable $ 173,610 $ 218,164
Other accrued liabilities 1,106,641 668,612
Parent company debt 1,303,845 1,146,685
Subsidiary and project debt 2,189,007 1,678,392
Deferred income taxes 509,059 469,199
Total liabilities 5,282,162 4,181,052
Deferred income 40,837 29,067
Commitments and contingencies (Notes 3, 18, 19 and 20)
Company - obligated mandatorily redeemable
convertible preferred securities
of subsidiary trusts 553,930 103,930
Preferred securities of subsidiary 56,181 136,065
Minority interest 134,454 299,252
Common stock and options subject to redemption 654,736 ---
Stockholders' equity:
Preferred stock - authorized 2,000 shares,
no par value --- ---
Common stock - par value $.0675 per share,
authorized 180,000 shares, issued 82,980
and 63,747 shares, outstanding 81,322 and
63,448 shares, respectively 5,602 4,303
Additional paid in capital 1,261,081 563,567
Retained earnings 213,493 297,520
Cumulative effect of foreign currency
translation adjustment (3,589) 29,658
Common stock and options subject to redemption (654,736) ---
Treasury stock - 1,658 and 299 common
shares at cost (56,525) (8,787)
Unearned compensation - restricted stock --- (5,471)
Total stockholders' equity 765,326 880,790
Total liabilities and stockholders' equity $ 7,487,626 $ 5,630,156
The accompanying notes are an integral part of these financial
statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Years Ended December 31, 1997
Dollars and Shares in Thousands, Except Per Share Amounts
1997 1996 1995
Revenue:
Operating revenue $2,166,338 $ 518,934 $ 335,630
Interest and other income 104,573 57,261 63,093
Total revenues 2,270,911 576,195 398,723
Costs and expenses:
Cost of sales 1,055,195 31,840 ---
Operating expense 345,833 132,655 103,602
General and administration 52,705 21,451 23,376
Depreciation and amortization 276,041 118,586 72,249
Loss on equity investment in Casecnan 5,972 5,221 362
Interest expense 296,364 165,900 134,637
Less interest capitalized (45,059) (39,862) (32,554)
Non-recurring charge - asset valuation
impairment 87,000 --- ---
Total costs and expenses 2,074,051 435,791 301,672
Income before provision for income taxes 196,860 140,404 97,051
Provision for income taxes 99,044 41,821 30,631
Income before minority interest 97,816 98,583 66,420
Minority interest 45,993 6,122 3,005
Income before extraordinary item 51,823 92,461 63,415
Extraordinary item, net of
minority interest of $58,222 (135,850) --- ---
Net income (loss) (84,027) 92,461 63,415
Preferred dividends --- --- 1,080
Net income (loss) available to
common stockholders $ (84,027) $ 92,461 $ 62,335
Income per share before extraordinary
item $ 0.77 $ 1.69 $ 1.32
Extraordinary item $ (2.02) $ --- $ ---
Net income (loss) per share $ (1.25) $ 1.69 $ 1.32
Income per share before extraordinary
item - diluted $ 0.75 $ 1.54 $ 1.22
Extraordinary item - diluted $ (1.97) $ --- $ ---
Net income (loss) per share - diluted $ (1.22) $ 1.54 $ 1.22
The accompanying notes are an integral part of these financial
statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended December 31, 1997
Dollars and Shares in Thousands
Common Stock
Outstanding Additional Foreign & Options
Common Common Paid-In Retained Currency Subject to Treasury Unearned
Shares Stock Capital Earnings Adjust. Redemption Stock Compensation Total
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
Restricted stock 500 --- 848 --- --- --- 8,652 (9,500) ---
Exercise of stock options
and other equity
transactions 176 10 446 --- --- --- 563 2,494 3,513
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 5,263 337 53,030 --- --- --- 4,569 1,535 59,471
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
Equity offering 19,100 1,289 697,315 --- --- --- --- --- 698,604
Exercise of stock options
and other equity
transactions 396 10 (2,757) --- --- --- 7,767 5,471 10,491
Purchase of treasury
stock (1,622) --- --- --- --- --- (55,505) --- (55,505)
Common stock and options
subject to
redemption --- --- --- --- --- (654,736) --- --- (654,736)
Tax benefit from
stock plan --- --- 2,956 --- --- --- --- --- 2,956
Foreign currency
translation
adjustment --- --- --- --- (33,247) --- --- --- (33,247)
Net loss --- --- --- (84,027) --- --- --- --- (84,027)
Balance December 31,
1997 81,322 $5,602 $1,261,081 $213,493$(3,589)$(654,736) $(56,525)$ ---$ 765,326
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Years Ended December 31, 1997
Dollars in Thousands
1997 1996 1995
Cash flows from operating activities:
Net income (loss) $ (84,027) $ 92,461 $ 63,415
Adjustments to reconcile net cash flow from operating activities:
Non-recurring charge-asset valuation
impairment 87,000 --- ---
Depreciation and amortization 239,234 109,447 65,244
Amortization of excess of cost over
fair value of net assets acquired 36,807 9,139 7,005
Amortization of original issue discount 2,160 50,194 45,409
Amortization of deferred financing costs 26,161 9,677 8,979
Amortization of unearned compensation 5,471 1,535 2,494
Provision for deferred income taxes 55,584 12,252 13,983
Loss (income) on equity investments (16,068) (910) 362
Income (loss) applicable to minority
interest (35,387) 1,431 3,005
Changes in other items:
Accounts receivable (34,146) (13,936) 213
Accounts payable, accrued liabilities
and deferred income 29,799 2,093 12,103
Net cash flows from operating activities 312,588 273,383 222,212
Cash flows from investing activities:
Purchase of Northern, Falcon Seaboard, Partnership Interest
and Magma, net of cash acquired (632,014) (474,443) (907,614)
Distributions from equity investments 23,960 8,222 ---
Capital expenditures relating to operating
projects (194,224) (24,821) (27,120)
Philippine construction (27,334) (167,160) (289,655)
Indonesian and other development (155,963) (81,068) (8,973)
Salton Sea IV construction --- (63,772) (62,430)
Pacific Northwest, Nevada, and Utah
exploration costs (3,128) (4,885) (10,445)
Decrease in short-term investments 2,880 33,998 80,565
Decrease (increase) in restricted cash (116,668) 63,175 (17,452)
Other 60,390 (2,910) 11,514
Investment in Casecnan --- --- (61,177)
Net cash flows from investing activities (1,042,101) (713,664) (1,292,787)
Cash flows from financing activities:
Proceeds from sale of common and treasury stock
and exercise of stock options 703,624 54,935 299,649
Proceeds from convertible preferred securities
of subsidiary trusts 450,000 103,930 ---
Proceeds from issuance of parent company debt 350,000 324,136 200,000
Repayment of parent company debt (100,000) --- ---
Net proceeds from revolver (95,000) 95,000 ---
Proceeds from subsidiary and project debt 795,658 428,134 654,695
Repayments of subsidiary and project debt (271,618) (210,892) (176,664)
Deferred charges relating to debt financing (48,395) (36,010) (34,733)
Purchase of treasury stock (55,505) (12,008) (1,590)
Other 13,142 10,756 (29,169)
Net cash flows from financing activities 1,741,906 757,981 912,188
Effect of exchange rate changes (33,247) 4,860 ---
Net increase (decrease) in cash and
investments 979,146 322,560 (158,387)
Cash and cash equivalents at beginning
of year 472,264 149,704 308,091
Cash and cash equivalents at end of year $ 1,451,410 $ 472,264 $ 149,704
Supplemental Disclosures:
Interest paid (net of amounts capitalized)$ 316,060 $ 92,829 $ 50,840
Income taxes paid $ 44,483 $ 23,211 $ 14,812
The accompanying notes are an integral part of these
financial statements.
NOTES Consolidated Financial Statements
For the Three Years Ended December 31, 1997
Dollars, Pounds 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, natural gas, hydroelectric and other energy sources. In
addition, 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 is also active in supplying gas and has
applications for over 400,000 customers in those areas of England,
Wales and Scotland where retail gas competition has been introduced.
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 in 1997
was 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 ("Tender Offer"). As of March
18, 1997, CE Electric effectively owned 100% of Northern ordinary
shares.
Northern is one of the twelve regional electricity 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 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 supplies electricity outside its Authorized Area
pursuant to second tier licenses. Northern also is involved in non-
regulated activities, including the supply of gas within England,
Wales and Scotland, 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.
Cash Equivalents, Investments and Restricted Cash
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.
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, 1997, 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.
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 3-40 years.
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.
Capitalized costs for gas reserves, other than costs of unevaluated
exploration projects and projects awaiting development consent, are
depleted using the unit of production method. Depletion is calculated
based on hydrocarbon reserves of properties in the evaluated pool
estimated to be commercially recoverable and include anticipated
future development costs in respect of those reserves.
Expenditures on major information technology systems are capitalized
and depreciated on a straight line basis over the useful life of the
developed systems which range from 3-10 years.
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 and natural gas 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.
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.
Impairment of Long-Lived Assets
The Company reviews long-lived assets and certain identifiable
intangibles for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable.
An impairment loss would be recognized whenever evidence exists that
the carrying value is not recoverable.
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 $5,421 and $8,371 at December 31, 1997 and 1996,
respectively, and are included in other assets.
Revenue Recognition
Revenues are recorded based upon service rendered and electricity and
steam delivered, distributed or supplied to the end of the month.
Where there is an overrecovery of supply or distribution business
revenues against the maximum regulated amount, revenues are deferred
equivalent to the overrecovered amount. The deferred amount is
deducted from revenue and included in other liabilities. Where there
is an underrecovery, no anticipation of any potential future recovery
is made.
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 effective interest method.
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.
Pensions
Northern contributes to the Electricity Supply Pension Scheme and
contributions to the scheme are charged to the income statement. The
capital cost of ex gratia and supplementary pensions are normally
charged to the income statement in the period in which they are
granted. Variations in pension cost, which are identified as a result
of actuarial valuations/reviews, are amortized over the average
expected remaining working lives of employees in proportion to their
expected payroll costs. Differences between the amounts funded and
the amounts charged to the profit and loss account are treated as
either provisions or prepayments in the balance sheet.
Net Income per Common Share
In February 1997, the Financial Accounting Standards Board ("FASB")
adopted Statement of Financial Accounting Standards ("SFAS") No. 128,
"Earnings per Share." SFAS 128 replaced primary and fully diluted
earnings per share with basic and diluted earnings per share,
respectively.
Basic and diluted earnings per common share are based on the weighted
average number of common shares outstanding during the period.
Diluted earnings per common share also assumes the conversion of the
convertible preferred securities of subsidiary trusts, when dilutive,
and the exercise of all dilutive stock options outstanding at their
option prices, with the option exercise proceeds and tax benefits used
to repurchase shares of common stock at the average market price using
the treasury stock method.
A reconciliation of basic earnings per share before extraordinary item
to diluted earnings per share before extraordinary item follows:
1997 1996 1995
Per-Share Per-Share Per-Share
Income Shares Amount Income Shares Amount Income Shares Amount
Basic earnings
per share before
extraordinary
item $ 51,823 67,268 $0.77 $ 92,461 54,739 $1.69 $62,335 47,249 $1.32
Effect of dilutive securities
Stock options --- 1,418 --- 1,881 --- 1,688
Convertible preferred securities
of subsidiary
trusts(1) --- --- 2,840 2,517 --- ---
Convertible debt --- --- 4,968 5,935 6,038 7,258
Diluted earnings per share
before extraordinary
item $ 51,823 68,686 $0.75 $100,269 65,072 $1.54 $68,373 56,195 $1.22
(1) The convertible preferred securities of subsidiary trusts were
antidilutive in 1997.
Reclassification
Certain amounts in the fiscal 1996 and 1995 financial statements and
supporting footnote disclosures have been reclassified to conform to
the fiscal 1997 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.
New Accounting Pronouncements
In June 1997, the FASB adopted SFAS No. 130, "Reporting Comprehensive
Income", and No. 131, "Disclosures about Segments of an Enterprise and
Related Information". SFAS 130 establishes standards for reporting
and display of comprehensive income and its components in a full set
of general purpose financial statements. SFAS 131 redefines how
operating segments are determined and requires disclosure of certain
financial and descriptive information about a company's operating
segments. Both statements will be effective for the Company beginning
January 1, 1998. The Company has not yet determined the impact of
these statements on current disclosures.
3. KDG Acquisition
On September 11, 1997, the Company signed a definitive agreement with
Kiewit Diversified Group ("KDG"), a wholly owned subsidiary of PKS,
for the Company to purchase KDG's ownership interest in various
project partnerships and CalEnergy common shares (the "KDG
Acquisition"). Accordingly, common stock and options subject to
redemption have been reclassified in the consolidated balance sheet.
KDG's ownership interest in CalEnergy comprised approximately 20,231
shares of common stock (assuming exercise by KDG of one million
options to purchase CalEnergy shares), the 30% interest in Northern
Electric, as well as the following minority project interests:
Mahanagdong (45%), Casecnan (35%), Dieng (47%), Patuha (44%) and Bali
(30%) and other interests in international development stage projects.
CalEnergy paid $1,159,215 for the KDG Acquisition and final closing of
the transaction occurred in January 1998. CalEnergy funded this
acquisition with available cash and the net proceeds of the equity
offering and the debt offering completed in October 1997.
4. Acquisitions
Northern
On December 24, 1996, CE Electric UK plc ("CE Electric"), which in
1997 was 70% owned indirectly by the Company and 30% owned indirectly
by PKS, acquired majority ownership of the outstanding ordinary share
capital of Northern Electric plc ("Northern") pursuant to a tender
offer (the "Northern Tender Offer") commenced in the United Kingdom on
November 5, 1996. As of March 18, 1997, CE Electric effectively
acquired the remaining ordinary shares and owned 100% of Northern's
ordinary shares.
The Company and PKS contributed to CE Electric approximately $410,000
and $176,000 respectively, of the approximately $1,200,000 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 Company has repaid
the entire CalEnergy Credit Facility through the use of proceeds of
the Trust Securities offering. The remaining funds necessary to
consummate the Tender Offer were provided from a pound 560,000 Term Loan
and Revolving Facility Agreement, dated October 28, 1996 (the "U.K.
Credit Facility"). CE Electric has repaid the entire U.K. Credit
Facility through the use of proceeds of the senior note and sterling
bond offerings of CE Electric UK Funding Company.
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
was recorded at historical cost.
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 in 1998 the Company is able to recover these costs.
For the period after the price cap regulation ends, 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, 1997, CFDs were in place to hedge a
portion of electricity purchases of approximately 55,000 GWh through
the year 2008.
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.
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.
Unaudited pro forma combined revenue, income and basic earnings per
share before extraordinary item of the Company, Northern, Falcon
Seaboard, and the Partnership Interest for the twelve months ended
December 31, 1997 and 1996, as if the acquisitions had occurred at the
beginning of 1996 after giving effect to certain pro forma adjustments
related to the acquisitions were $2,270,911, $52,430, and $0.78
compared to $2,162,381, $64,811 and $1.18, respectively. Excluding
the $87,000, $1.29 per share, non-recurring charge, pro forma income
before extraordinary item would have been $139,430 in 1997.
5.Properties, Plants, Contracts and Equipment
Properties, plants, contracts and equipment comprise the following at
December 31:
1997 1996
Operating project costs:
Distribution system $1,237,743 $928,575
Power plants 1,464,885 1,277,663
Wells and resource development 395,314 377,731
Power sales agreements 227,535 227,535
Other assets 254,973 176,483
Total operating assets 3,580,450 2,987,987
Less accumulated depreciation and
amortization (497,832) (271,216)
Net operating assets 3,082,618 2,716,771
Mineral and gas reserves, net 297,048 270,851
Construction in progress:
Malitbog --- 152,411
Indonesia 140,172 81,875
Other development 9,072 3,588
Total $ 3,528,910 $ 3,225,496
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,
current profits and losses are allocated 46.4% to the Company. 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 is 48%. Under terms of the Navy
II Joint Venture, all profits, losses and capital contributions for
Navy II are divided equally by the two partners.
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, 1997, the balance of funds deposited approximated $6,337,
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 Coso Joint Ventures had royalty expense included in operating
expenses of $13,458, $13,412 and $13,623 in the years ended December
31, 1997, 1996 and 1995, respectively.
Imperial Valley Project Operating Facilities
The Company currently operates eight geothermal power plants in the
Imperial Valley in California. 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. These geothermal
power plants consist of Salton Sea I, Salton Sea II, Salton Sea III
and 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
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 1997 was
approximately 6.1%. The royalties are paid to numerous recipients
based on varying percentages of electrical revenue or steam production
multiplied by published indices.
The Imperial Valley Projects had royalty expense included in operating
expenses of $14,343, $10,228 and $10,398 in the years ended December
31, 1997, 1996 and 1995, respectively.
Significant Customers and Contracts
All of the Company's sales of electricity from the Coso Project and
Imperial Valley Project, which comprise approximately 20% of 1997
operating revenue, are to Southern California Edison Company
("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 and capacity bonus
payments to the projects to the extent that capacity factors exceed
certain benchmarks. 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
extended until at least August 1997 for each of the units operated by
the Navy I Partnership and extend until at least March 1999 and
January 2000 for each of the units operated by the BLM and Navy II
Partnerships, respectively. The Company's share of aggregate annual
capacity payments is approximately $17,000 and its share of aggregate
bonus payments is approximately $3,000.
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 Navy I and Vulcan, which are receiving Edison's Avoided Cost
of Energy, the Company's SO4 Agreements provide for energy rates
ranging from 12.8 cents per kWh in 1997 to 15.6 cents per kWh in 1999. The
weighted average energy rate for all of the Company's SO4 Agreements
was 12.0 cents per kWh in 1997.
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 5.3 cents per kWh during 1997.
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 cents per kWh and 9.8
cents 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, 1997, and 1996 Edison's average
Avoided Cost of Energy was 3.3 cents and 2.5 cents, respectively, per kWh which
is substantially below the contract energy prices earned for the year
ended December 31, 1997. 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.
Philippine Projects
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 build-own-operate-transfer project ("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). 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. 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 (the "Malitbog Project") was deemed
complete in July 1996 and Units II and III in July 1997 at which times
such units commenced receiving capacity payments under the Malitbog
ECA. The Malitbog Project is owned and operated by Visayas Geothermal
Power Company ("VGPC"), a Philippine general partnership that is
wholly owned, indirectly, by the Company. Under its contract, VGPC is
to sell 100% of its output 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 National Power Corporation of the
Philippines ("NPC"). However, VGPC receives 100% of its revenues from
such sales in the form of capacity payments. As with the Upper Mahiao
Project, the Malitbog Project is structured as a ten year BOOT, in
which the Company is responsible 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 Mahanagdong Project (the "Mahanagdong Project") was deemed
complete in July 1997 and accordingly, the Mahanagdong Project began
receiving capacity payments pursuant to the Mahanagdong ECA in August
of 1997. The Mahanagdong Project is owned and operated by CE Luzon
Geothermal Power Company, Inc., a Philippine corporation, that is
expected to be indirectly owned by the Company (after the KDG
Acquisition) subject to a minority partner participation. 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
ECA are substantially similar to those of the Upper Mahiao ECA. All
of PNOC-EDC's obligations under the Mahanagdong 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.
Gas Projects
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 1997 total 2.2 cents 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 6.6 cents per kWh in 1997,
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 1997 are $3,032 per month and 2.96 cents 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.
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.
Subsequent to year end, an indirect subsidiary of the Company entered
into a lease agreement whereby they will lease the facility to another
power producer and receive rental payments.
Salton Sea Minerals Extraction
The Company developed and owns the rights to a proprietary process for
the extraction of minerals from elements in solution in the geothermal
brine and fluids utilized at its Imperial Valley plants (the "Salton
Sea Extraction Project") as well as the production of power to be used
in the extraction process. A pilot plant has successfully produced
commercial quality zinc at the Company's Imperial Valley Project. The
Company is also investigating producing silica from the solids
precipitated out of the geothermal power process.
Telephone Flat
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 (the "Telephone Flat
Project"). Pursuant to an amended power sales contract the project
has been relocated to Telephone Flat and BPA has agreed to purchase 30
MW from the project with an option to purchase up to an additional 100
MW. 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.
Completion of this project is subject to a number of significant
uncertainties and cannot be assured.
6. Equity Investments
At December 31, 1997, the Company had an 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 is expected to
indirectly own approximately 70% of the Casecnan Project after the KDG
Acquisition.
The Company had an indirect ownership of 50% in the Mahanagdong
Project, subject to a minority partner participation. The Company will
indirectly own 100% of the Mahanagdong Project after the KDG
Acquisition.
The Company has an approximate 45% 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 Mahanagdong
As of and for the year ended
December 31, 1997:
Assets $ 482,527 $ 315,671 $ 118,415 $ 294,250
Liabilities 384,369 211,299 115,487 197,575
Net income (loss) (11,267) 43,097 4,072 14,996
As of and for the year ended December 31, 1996:
Assets 492,166 325,174 125,956 240,222
Liabilities 380,737 213,326 121,223 168,512
Net income (loss) (11,207) 40,005 (53) N/A
7. Parent Company Debt
Parent company debt comprises the following at December 31:
1997 1996
Senior discount notes $ 529,640 $ 527,535
9.5% senior notes 224,205 224,150
7.63% senior notes 350,000 ---
Limited recourse senior secured notes* 200,000 200,000
CalEnergy credit facility --- 100,000
Revolving credit facility --- 95,000
$ 1,303,845 $ 1,146,685
* The amount of recourse obligation to the parent was $0 at December
31, 1997.
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 was amortized from the
issue date through January 15, 1997, during which time no cash
interest was paid on the Senior Discount Notes. Cash interest on the
Senior Discount Notes is payable semiannually on January 15 and July
15 of each year, commencing July 15, 1997. 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.
9.5% Senior Notes
On September 20, 1996, the Company issued $225,000 of 9.5% Senior
Notes (the "9.5% Senior Notes") due 2006. Interest on the 9.5% Senior
Notes is payable semiannually on March 15 and September 15 of each
year, commencing March 15, 1997. The 9.5% 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 9.5% Senior Notes are
unsecured senior obligations of the Company.
7.63% Senior Notes
On October 28, 1997, the Company issued $350,000 of 7.63% Senior Notes
(the "7.63% Senior Notes") due 2007. Interest on the 7.63% Senior
Notes will be payable semiannually on April 15 and October 15 of each
year, commencing April 15, 1998. The 7.63% 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, 1997.
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 had drawn
$100,000 as of December 31, 1996. The Company has 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. On November 26, 1997, the credit facility was
amended and increased to $400,000 and extended to November 2000. The
facility is unsecured and is available to fund working capital
requirements and finance future business expansion opportunities.
Annual Repayments of Parent Company Debt
There are no annual repayments of the parent company debt due for the
next five years.
8. Subsidiary and Project Debt:
Project loans held by subsidiaries and projects which are non recourse
to the Company comprise the following at December 31:
1997 1996
Salton Sea Notes and Bonds $ 448,754$ 538,982
Northern eurobonds 427,732 439,192
U.K. credit facility --- 128,423
CE Electric UK Funding Company Senior Notes 357,331 ---
CE Electric UK Funding Company Sterling Bonds 322,534 ---
Power Resources project debt 103,334 114,571
Coso Funding Corp. project loans 106,616 148,346
Construction loans 416,744 300,951
Other 5,962 7,927
$2,189,007 $1,678,392
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. Pursuant to separate project financing agreements, the
assets of each subsidiary are pledged or encumbered to support or
otherwise provide the security for their own project or subsidiary
debt. 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.
"Subsidiaries" means all of CalEnergy's direct or indirect
subsidiaries (1) owning interests in the Coso, Imperial Valley,
Saranac, NorCon, Power Resources, Mahanagdong, Malitbog, Upper Mahiao,
Casecnan, Dieng and Patuha projects or (2) owning interests in the
subsidiaries that own interests in the foregoing projects.
Salton Sea Notes and Bonds
The Salton Sea Funding Corporation, a wholly owned subsidiary of the
Company, (the "Funding Corporation") debt securities are as follows:
Final
Maturity December 31, December 31,
Senior Secured Series Date Rate 1997 1996
July 21, 1995 A Notes May 30, 2000 6.69% $ 97,354 $161,732
July 21, 1995 B Bonds May 30, 2005 7.37% 133,000 133,000
July 21, 1995 C Bonds May 30, 2010 7.84% 109,250 109,250
June 20, 1996 D Notes May 30, 2000 7.02% 44,150 70,000
June 20, 1996 E Bonds May 30, 2011 8.30% 65,000 65,000
$448,754 $538,982
Principal and interest payments are made in semi-annual installments.
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. The Salton Sea Notes and Bonds are nonrecourse to the
Company.
Pursuant to a 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 debenture due in 1999, which bears a
fixed interest rate of 12.661%. The debt also includes bearer bonds
repayable in 2005 and 2020, bearing fixed interest rates of 8.625% and
8.875%, respectively.
The balance at December 31, 1997 and 1996 consists of the following:
1997 1996
Debenture due 1999 $ 97,530 $ 99,924
Bearer bonds due 2005 165,236 171,130
Bearer bonds due 2020 164,966 168,138
$ 427,732 $ 439,192
U.K. Credit Facility
On October 28, 1996, CE Holdings, an indirect subsidiary of the
Company, obtained a pound 560,000 five year term loan and revolving credit
facility (the "U.K. Credit Facility"). The Company did not guarantee,
nor was it otherwise subject to recourse for, amounts borrowed under
the U.K. Credit Facility. The agreement placed restrictions on
distributions from CE Electric to any of its shareholders based on
certain financial ratios. CE Electric has repaid the entire U.K.
Credit Facility through the use of proceeds from the senior note and
sterling bond offerings of CE Electric UK Funding Company described
below.
CE Electric UK Funding Company Senior Notes and Sterling Bonds
On December 15, 1997, CE Electric UK Funding Company, an indirect
subsidiary of the Company (the "Funding Company"), issued $125,000 of
6.853% senior notes due 2004, and $237,000 of 6.995% senior notes due
2007 (collectively, the "CE Electric UK Funding Company Senior
Notes"), and pound 200,000 of 7.25% Sterling Bonds due 2022. The CE
Electric UK Funding Company Senior Notes and Sterling Bonds prohibit
distributions to any of its shareholders unless certain financial
ratios are met by the Funding Company.
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%.
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. The Coso Funding
Corp. project loans carry a fixed interest rate with weighted average
interest rates of 8.65% and 8.46% at December 31, 1997 and 1996,
respectively. The loans have scheduled repayments through December
2001. The Coso Project has established irrevocable letters of credit
of $67,850 as a debt service reserve fund.
Annual Repayments of Subsidiary and Project Debt
The annual repayments of the subsidiary and project debt, excluding
construction loans, for the years beginning January 1, 1998 and
thereafter are as follows:
CE Electric UK
Salton Sea Funding Company Coso
Notes and Northern Senior Notes and Power Funding
Bonds Eurobonds Sterling Bonds Resources Corp. Other Total
1998 $ 106,938 $ --- $ --- $ 12,805 $ 38,912 $1,544 $160,199
1999 57,836 97,530 --- 14,268 31,717 1,297 202,648
2000 25,072 --- --- 16,087 4,080 1,051 46,290
2001 22,376 --- --- 18,119 31,907 838 73,240
2002 24,298 --- --- 20,312 --- 1,232 45,842
There-
after 212,234 330,202 679,865 21,743 --- --- 1,244,044
$448,754 $427,732 $679,865 $103,334 $106,616 $5,962$1,772,263
Construction Loans
The Company's allocable share of non-recourse project construction
loans comprise the following at December 31:
1997 1996
Upper Mahiao $ 150,628 $150,628
Malitbog 176,657 137,881
CE Indonesia Funding Corp. 89,459 12,442
$ 416,744 $ 300,951
The Upper Mahiao and Malitbog construction loans are scheduled to be
replaced by non-recourse 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, 1997 totaled $150,628. A consortium of
international banks provided the construction financing with variable
interest rates based on LIBOR or "Prime" with interest payments due
every quarter and at LIBOR maturity. The weighted average interest
rate at December 31, 1997 and 1996 is approximately 8.43% and 8.01%,
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 1998. 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 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, 1997 totaled $176,657. International banks and
the Overseas Private Investment Corporation ("OPIC") have provided the
construction and term loan facilities at variable interest rates
(weighted average of 8.48% and 8.15% at December 31, 1997 and 1996,
respectively). The international bank portion of the debt will be
insured by 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. 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 1998.
CE Indonesia Funding Corp.
In June 1997, the Company's indirect special-purpose subsidiary, CE
Indonesia Funding Corp., entered into a $400,000 revolving credit
facility (which is nonrecourse to the Company) to finance the
development and construction of the Company's geothermal power
facilities in Indonesia. This credit facility was used in part to
replace the original project financing for Himpurna California
Energy's Dieng Unit I. At December 31, 1997, the Company's share of
the credit facility relating to Dieng Unit I was $50,481 and carried a
variable interest rate (weighted average of 7.44% at December 31,
1997).
On November 18, 1997, Himpurna California Energy announced the funding
of the Dieng Unit II project pursuant to the CE Indonesia Funding
Corp. facility arranged in June 1997. At December 31, 1997, the
Company's share of the credit facility relating to Dieng Unit II was
$11,211 and carried a variable interest rate (weighted average of
7.48% at December 31, 1997).
On September 2, 1997, Patuha Power announced the funding of the Patuha
Unit I project pursuant to the CE Indonesia Funding Corp. facility
arranged in June 1997. At December 31, 1997, the Company's share of
the credit facility relating to Patuha was $27,767 and carried a
variable interest rate (weighted average of 7.44% at December 31,
1997).
9. Income Taxes
Provision for income taxes is comprised of the following at December
31:
1997 1996 1995
Currently payable:
State $ 5,084$ 7,520 $5,510
Federal 33,114 19,873 11,138
Foreign 5,262 2,176 ---
43,460 29,569 16,648
Deferred:
State (264) 1,619 921
Federal 14,579 9,209 13,062
Foreign 41,269 1,424 ---
55,584 12,252 13,983
Total $ 99,044 $41,821 $30,631
A reconciliation of the federal statutory tax rate to the effective
tax rate applicable to income before provision for income taxes
follows:
1997 1996 1995
Federal statutory rate 35.00% 35.00% 35.00%
Percentage depletion in excess of cost depletion (3.77) (6.12) (7.38)
Investment and energy tax credits (.64) (8.34) (1.80)
State taxes, net of federal tax effect 1.59 4.38 4.09
Goodwill amortization 2.06 2.51 2.53
Non-deductible expense 1.33 .84 1.10
Lease investment --- --- (2.18)
Dividends on convertible preferred securities
of subsidiary trusts* (4.12) (1.17) ---
Tax effect of foreign income 2.64 2.54 ---
Asset valuation impairment 15.47 --- ---
Other .75 .15 .20
Effective tax rate 50.31% 29.79% 31.56%
* Dividends on convertible preferred securities of subsidiary trusts
are included in minority interest.
Deferred tax liabilities (assets) are comprised of the following at
December 31:
1997 1996
Depreciation and amortization, net $ 802,215 $ 725,366
Pensions 19,441 22,883
Unremitted foreign earnings 10,781 2,857
Other 3,324 3,262
835,761 754,368
Deferred contract costs (193,996) (128,745)
Deferred income (12,690) (9,298)
Energy and investment tax credits (42,049) (55,931)
Advance corporation tax --- (20,205)
Alternative minimum tax credits (39,402) (50,819)
Accruals not currently deductible for tax purposes (31,561) (13,372)
Other (7,004) (6,799)
(326,702) (285,169)
Net deferred taxes $509,059 $469,199
The Company has unused investment and geothermal energy tax credit
carryforwards of approximately $42,049 expiring between 2004 and 2012.
The Company also has approximately $39,402 of alternative minimum tax
credit carryforwards which have no expiration date.
10. Company-Obligated Mandatorily Redeemable Convertible Preferred
Securities of Subsidiary Trusts
The Company has organized special purpose Delaware business trusts
("Trust I", "Trust II" and "Trust III" or collectively, the "Trusts")
pursuant to their respective amended and restated declarations of
trusts (collectively, the "Declarations"). On April 12, 1996,
February 26, 1997 and August 12, 1997, the Company, through these
Trusts, issued Company-obligated mandatorily redeemable convertible
preferred securities (collectively, the "Trust Securities") as
follows:
Issuer Issue Date Rate Amount Conversion Rate
CalEnergy Capital Trust I April 12,1996 6.25% $103,930 1.6728
CalEnergy Capital Trust II February 26,1997 6.25% $180,000 1.1655
CalEnergy Capital Trust III August 12, 1997 6.50% $270,000 1.047
The Company owns all of the common securities of the Trusts. The Trust
Securities have a liquidation preference of fifty dollars each and
represent undivided beneficial ownership interests in each of the
Trusts. The assets of the Trusts consist solely of the Company's
Convertible Subordinated Debentures due March 10, 2016, February 25,
2012 and September 1, 2027, respectively, in outstanding aggregate
principal amounts of $103,930, $180,000 and $270,000, respectively
(collectively, the "Junior Debentures") issued pursuant to their
respective indentures. The indentures include agreements by the
Company to pay expenses and obligations incurred by the Trusts. Each
Trust Security with a par value of $50 is convertible at the option of
the holder at any time into shares of CalEnergy Common Stock based on
the conversion rate and 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 Trusts. Distributions on the Trust Securities (and
Junior Debentures) are cumulative, accrue from the date of initial
issuance and are payable quarterly in arrears. 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 indentures.
Pursuant to Preferred Securities Guarantee Agreements (collectively,
the "Guarantees"), 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 Trustee has funds
available to make such payments, quarterly distributions, redemption
payments and liquidation payments on the Trust Securities. Considered
together, the undertakings contained in the Declarations, Junior
Debentures, Indentures and Guarantees constitute full and
unconditional guarantees by the Company of the Trusts' obligations
under the Trust Securities.
11.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 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.
12.Stock Options and Restricted Stock
The Company has issued various stock options. As of December 31, 1997,
a total of 6,949 shares are reserved for stock options, of which 6,780
shares have been granted and remain outstanding at prices of $3.74 to
$40.81 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 two 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.
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 was
amortized over the vesting period of which 125 shares were immediately
vested and the remaining 375 shares vested through January 1, 1998.
Accordingly, $5,471, $1,535 and $2,494 of unearned compensation was
charged to general and administrative expense in 1997, 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, 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) 1,157 25.06 - 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 17.928 5,585
Options granted (2,307) 2,513 29.06 - 40.81 34.80 87,457
Options terminated 165 (165) 3.00 - 29.06 20.04 (3,307)
Options exercised --- (345) 3.74 - 29.06 13.28 (4,583)
Additional shares
reserved under 1996
Option Plan 2,000 --- --- --- ---
Balance
December 31, 1997 169 6,780 $3.74 -$40.81 $24.36 $165,152
Options exercisable at:
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
December 31, 1997 3,665 $3.74 -$40.19 $18.12 $ 66,425
The following table summarizes information about stock options outstanding
and exercisable as of December 31, 1997:
Options Outstanding Options Exercisable
Weighted Weighted Weighted
Range of Number Average Average Remaining Number Average
Exercise Outstanding Exercise Contractual Life Exercisable Exercise
Prices Price Price
$3.74 $11.99 1,161 $ 11.22 3 years 1,161 $ 11.22
12.00 21.99 2,020 16.90 6 years 1,739 16.82
22.00 31.99 1,092 28.10 8 years 311 28.25
32.00 40.81 2,507 34.83 9 years 454 34.12
6,780 $ 24.36 7 years 3,665 $ 18.12
The Company applies the intrinsic value based method of accounting for
its stock-based employee compensation plans. If the fair value based
method had been applied for 1997, non-cash compensation expense and
the effect on net income available to common stockholders and earnings
per share would have been approximately $3,600, or $0.05 per share.
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 5.50% in 1997 and 6.00% in 1996 and 1995, expected volatility of
25% in 1997 and 22% in 1996 and 1995, expected life of approximately
3.7 years in 1997 and 4.5 years in 1996 and 1995, and no expected
dividends. The weighted average fair value of options granted during
1997, 1996 and 1995 was $9.55, $8.62 and $5.72 per option,
respectively.
13.Common Stock Sales & Related Options
On October 17, 1997, the Company completed the public offering of
17,100 shares of its common stock ("Common Stock") at $37 7/8 per
share (the "Public Offering"). In addition, 2,000 shares of Common
Stock were purchased from CalEnergy in a direct sale by a trust
affiliated with Walter Scott, Jr., the Chairman and Chief Executive
Officer of PKS (the "Direct Sale"), contemporaneously with the closing
of the Public Offering. Proceeds from the Public Offering and the
Direct Sale were approximately $699,920.
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.
14.Asset Valuation Impairment Charge
The non-recurring charge of $87,000 represents an asset valuation
impairment charge under Financial Accounting Standard No. 121,
"Accounting for the Impairment of Long-Lived Assets," relating to
CalEnergy's assets in Indonesia. Moreover, the Company intends to
continue to take actions to attempt to require the Government of
Indonesia to honor its contractual obligations; however, the ultimate
outcome of the current uncertain situation in Indonesia with respect
to the possible abrogation by the Indonesian government of the Dieng,
Patuha and Bali contracts adds significant risk to the completion of
those projects. Consequently, the charge of $87,000 represents the
amount by which the carrying amount of such assets exceed the fair
value of the assets determined by discounting the expected future net
cash flows of the Indonesia projects, assuming proceeds from political
risk insurance and no tax benefits.
15. Extraordinary Item
On July 31, 1997, the Finance Act in the United Kingdom was passed by
Parliament and included the introduction of a one time so-called
"windfall tax" equal to 23% of the difference between the price paid
for Northern upon privatization and the Labour government's assessed
"value" of Northern as calculated by reference to a formula set forth
in the July budget. This amounted to $135,850, net of minority
interest of $58,222, which was recorded as an extraordinary item. The
first installment was paid December 1, 1997 and the second installment
is payable on December 1, 1998.
16.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 technique. 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.
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 7, 8 and 10.
1997 1996
Estimated Estimated
Carrying Fair Carrying Fair
Value Value Value Value
Senior discount notes $529,640 $569,148 $527,535 $556,971
9.5% Senior notes 224,205 243,615 224,150 229,866
7.63% Senior notes 350,000 352,857 --- ---
Limited recourse senior secured notes 200,000 217,829 200,000 212,560
CalEnergy credit facility --- --- 100,000 100,000
Revolving line of credit --- --- 95,000 95,000
Salton Sea notes and bonds 448,754 463,720 538,982 531,807
Northern eurobonds 427,732 482,064 439,192 445,830
Construction loans 416,744 416,744 300,951 300,951
Coso Funding Corp. project loans 106,616 112,932 148,346 153,650
CE Electric UK Funding Company Senior Notes 357,331 357,331 --- ---
CE Electric UK Funding Company Sterling Bonds322,534 333,257 --- ---
Power Resources project debt 103,334 103,334 114,571 114,571
U.K. credit facility --- --- 128,423 128,423
Other 5,962 5,962 7,927 7,927
Convertible preferred securities of
subsidiary trusts 553,930 514,373 103,930 128,354
17. Interest Rate Swap Agreements
On December 15, 1997, CE Electric UK Funding Company entered into
certain interest rate swap agreements for the CE Electric UK Funding
Company Senior Notes with two large multi-national financial
institutions. The swap agreements effectively convert the U.S. dollar
fixed interest rate to a fixed rate in Sterling. For the $125,000 of
6.853% senior notes, the agreements extend until December 30, 2004 and
convert the U.S. dollar interest rate to a fixed Sterling rate of
7.744%. For the $237,000 of 6.995% senior notes, the agreements
extend until December 30, 2007 and convert the U.S. dollar interest
rate to a fixed Sterling rate of 7.737%. The estimated fair value of
these swap agreements is approximately $4,929 based on quotes from the
counter party to these instruments and represents the estimated amount
that the Company would expect to pay to terminate these agreements.
It is the Company's intention to hold the swap agreements to their
intended maturity.
18. Regulatory Matters
Northern is subject to price cap regulation. Price control formulas
for the supply and distribution businesses are enforced by the Office
of Electricity Regulation ("OFFER").
In the distribution business the current price control is expected to
last until 2000. The formula was reviewed with effect from April 1,
1995 and April 1, 1996 which resulted in one-time reductions in
allowed income per unit distributed of about 17% and 13% respectively,
with continuing real reductions in each of the subsequent three years
1997/98 to 1999/2000. The current formula requires that each year
regulated distribution income per unit is increased or decreased by
RPI-Xd where RPI reflects the average of the twelve month inflation
rates recorded for the previous July to December period and Xd is set
at 3%. The formula also takes account of the changes in system
electrical losses, the number of customers connected and the voltage
at which customers receive the units of electricity distributed.
In the supply business the current formula applies only to customers
with demands below 100kW. Under the current formula the purchase cost
of electricity and the cost of transmission, distribution and the
fossil fuel levy are passed through to customers in full. That part
of the formula governing Northern's own supply business costs requires
that this element of the permitted income falls by 2% per annum in
real terms. The current formula is due to be replaced from April 1,
1998 with a new formula which will require Northern to reduce prices
to those customers protected by the new price control from the level
prevailing at August 1, 1997 by about 4.2% (minus inflation) with
effect from April 1, 1998 and a further 3% (minus inflation) with
effect from April 1, 1999.
The market for electricity supplied to customers with demands over 1MW
was opened to competition in 1990. In 1994 this limit was reduced to
0.1MW. In 1998, liberalization of the entire market is due to
commence in stages with complete liberalization achieved by June 1999.
19. 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 for December 31, 1997 and 1996 assumed
interest rates of 6.75% and 7.75%, respectively, an expected return on
plan assets of 7.25% and 8.25%, respectively, and annual compensation
increases of 4.75% and 5.75%, respectively, 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.
Northern's funding policy for the plan is to contribute annually at a
rate that is intended to remain a level percentage of compensation for
the covered employees.
The following table details the funded status and the amount
recognized in the balance sheet of the Company as of December 31,
1997 and 1996.
Actuarial present value of benefit obligations: 1997 1996
Vested benefits $ 847,694 $ 797,932
Nonvested benefits --- ---
Accumulated benefit obligation 847,694 797,932
Effect of future increase in compensation 40,898 58,218
Projected benefit obligation 888,592 856,150
Fair value of plan assets 1,012,601 919,163
Assets in excess of projected benefit obligation 124,009 63,013
Unrecognized net gain 61,265 ---
Prepaid pension asset $ 62,744 $ 63,013
Net periodic pension cost for 1997 included the following components
(the components for the period from the acquisition date of Northern
to December 31, 1996 are not meaningful):
Service cost - benefits earned during the period$ 12,600
Interest cost on projected benefit obligation 62,300
Actual return on plan assets (71,300)
Net periodic pension cost $ 3,600
20. Commitments and Contingencies
Casecnan
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 expected to be approximately 70% indirectly
owned by the Company (after the KDG Acquisition), is developing the
Casecnan Project. 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 Bonds due 2010 and $75,000 of its Secured Floating
Rate Notes due 2002, pursuant to an indenture dated as of November 27,
1995, as amended to date.
The Casecnan Project was being constructed pursuant to a fixed-price,
date-certain, turnkey construction contract (the "Hanbo Contract") on
a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo
Engineering and Construction Co., Ltd. ("HECC"), both of which are
South Korean corporations. As of May 7, 1997, CE Casecnan terminated
the Hanbo Contract due to defaults by Hanbo and HECC including the
insolvency of each such company. On May 7, 1997 CE Casecnan entered
into a new turnkey engineering, procurement and construction contract
to complete the construction of the Casecnan Project (the "Replacement
Contract"). The work under the Replacement Contract is being
conducted by a consortium consisting of Cooperativa Muratori
Cementisti CMC di Ravenna and Impressa Pizzarottie & C. Spa working
together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and
Colenco Power Engineering Ltd. (collectively, the "Replacement
Contractor").
In connection with the Hanbo Contract termination, CE Casecnan
tendered a certificate of drawing to Korea First Bank ("KFB") on May
7, 1997 under the irrevocable standby letter of credit issued by KFB
as security under the Hanbo Contract to pay for certain transition
costs and other presently ascertainable damages under the Hanbo
Contract. As a result of KFB's wrongful dishonor of the draw request,
CE Casecnan filed an action in New York State Court. That Court
granted CE Casecnan's request for a temporary restraining order
requiring KFB to deposit $79,329, the amount of the requested draw, in
an interest bearing account with an independent financial institution
in the United States. KFB appealed this order, but the appellate
court denied KFB's appeal and on May 19, 1997, KFB transferred funds
in the amount of $79,329 to a segregated New York bank account
pursuant to the Court order. If KFB were to fail to honor its
obligations under the Casecnan letter of credit, such action could
have a material adverse effect on the Casecnan Project and CE
Casecnan.
On August 6, 1997, CE Casecnan announced that it had issued a notice
to proceed to the Replacement Contractor. The Replacement Contractor
was already on site and has fully mobilized and commenced engineering,
procurement and construction work on the Casecnan Project.
On August 27, 1997, CE Casecnan announced that it had received a
favorable summary judgment ruling in New York State Court against KFB.
The judgment, which has been appealed by the bank, requires KFB to
honor the $79,329 drawing by CE Casecnan on the $117,850 irrevocable
standby letter of credit.
On September 29, 1997, CE Casecnan tendered a second certificate of
drawing for $10,828 to KFB and on December 30, 1997, CE Casecnan
tendered a third certificate of drawing for $2,920 to KFB. KFB also
wrongfully dishonored these draws, but pursuant to a stipulation
agreed to deposit the draw amounts in an interest bearing account with
the same independent financial institution in the United States
pending resolution of the appeal regarding the first draw and agreed
to expedite the appeal.
The receipt of the letter of credit funds from KFB remains essential
and CE Casecnan will continue to press KFB to honor its clear
obligations under the letter of credit and to pursue Hanbo and KFB for
any additional damages arising out of their actions to date. If KFB
were to fail to honor its obligations under the Casecnan letter of
credit, such action could have a material adverse effect on the
Casecnan Project and CE Casecnan.
On September 2, 1997, Hanbo and HECC filed a Request for Arbitration
before the International Chamber of Commerce ("ICC"). The Request for
Arbitration asserts various claims by Hanbo and HECC against CE
Casecnan relating to the terminated Hanbo Contract and seeking
damages. On October 10, 1997, CE Casecnan served its answer and
defenses in response to the Request for Arbitration as well as
counterclaims against Hanbo and HECC for breaches of the Hanbo
Contract. The arbitration proceedings before the ICC are ongoing and
CE Casecnan intends to pursue vigorously its claims against Hanbo,
HECC and KFB in the proceedings described above.
Indonesia
On September 20, 1997, a Presidential Decree (the "Decree") was issued
in Indonesia, providing for government action to the effect that, in
order to address certain recent fluctuations in the value of the
Indonesian currency, the start-up dates for a number of private power
projects would be: (i) continued according to their initial schedule
(because construction was underway); (ii) postponed as to their start-
up dates (because they are not yet in construction) until economic
conditions have recovered; or (iii) reviewed with a view to being
continued, postponed or rescheduled, depending on the status of those
projects. In the Decree, Dieng Units 1, 2 and 3 are approved to
continue according to their initial schedule; Patuha Unit 1 and Bali
Units 1 and 2 are to receive further review to determine whether or
not they should be continued in accordance with their initial
schedule; and Bali Units 3 and 4, Patuha Units 2, 3 and 4 and Dieng
Unit 4 are to be postponed for an unspecified period. In this regard,
the Company notes that its contracts and government undertakings for
the Dieng, Patuha and Bali projects do not by their terms permit such
categorization or delays by the government and that the Company has
obtained political risk insurance coverage for its Dieng and Patuha
projects. Moreover, the Company intends to continue to take actions to
attempt to require the Government of Indonesia to honor its
contractual obligations; however, subsequent actions by the Government
of Indonesia and continued economic problems in Indonesia have created
further uncertainty as to whether the contracts for such projects will
be abrogated by the Indonesian government and accordingly have created
significant risks to the completion of these projects. As a result,
the Company recorded a SFAS 121 asset valuation impairment charge of
$87,000 in the fourth quarter of 1997. This charge includes all
reasonably estimated asset valuation impairments associated with the
Company's assets in Indonesia and gives effect to the political risk
insurance on such investments.
Edison
On June 9, 1997, Edison filed a complaint alleging breach of the power
purchase agreements ("SO4 Agreements") between Edison and the Coso
Joint Ventures as a result of alleged improper venting of certain
noncondensible gases at the Coso geothermal energy project. In the
complaint Edison seeks unspecified damages, including the refund of
certain amounts previously paid under the SO4 Agreements, and
termination of the SO4 Agreements. In September 1997, the Coso Joint
Ventures and the Company filed a cross-complaint against Edison and
its affiliates, The Mission Group and Mission Power Engineering
Company alleging, among other things, that Edison's lawsuit violates
the 1993 settlement agreement which settled certain litigation arising
from the construction of certain units at the Coso geothermal project
by Edison affiliates. In addition, the Coso Joint Ventures filed a
separate complaint against Edison alleging breach of the SO4
Agreements, unfair business practices, slander and various other tort
and contract claims. The actions were effectively consolidated in
December 1997. As a result of certain procedural actions by the
parties and a November court order, Edison filed an amended complaint
on December 16, 1997 and the Coso Joint Ventures amended their cross-
complaint. The litigation is in its early procedural stages and the
pleadings have not been settled. The Coso Joint Ventures believe that
their claims and defenses are meritorious and that they will prevail
if the matter is ultimately heard on its merits. The Coso Joint
Ventures intend to vigorously defend this action and prosecute all
available counterclaims against Edison.
NYSEG
On February 14, 1995, NYSEG filed with the FERC a Petition for a
Declaratory Order, Complaint, and Request for Modification of Rates in
Power Purchase Agreements Imposed Pursuant to the Public Utility
Regulatory Policies Act of 1978 ("Petition") seeking FERC (i) to
declare that the rates NYSEG pays under the Saranac PPA, which was
approved by the New York Public Service Commission (the "PSC") were in
excess of the level permitted under PURPA and (ii) to authorize the
PSC to reform the Saranac PPA. On March 14, 1995, the Saranac
Partnership intervened in opposition to the Petition asserting, inter
alia, that the Saranac PPA fully complied with PURPA, that NYSEG's
action was untimely and that the FERC lacked authority to modify the
Saranac PPA. On March 15, 1995, the Company intervened also in
opposition to the Petition and asserted similar arguments. On April
12, 1995, the FERC by a unanimous (5-0) decision issued an order
denying the various forms of relief requested by NYSEG and finding
that the rates required under the Saranac PPA were consistent with
PURPA and the FERC's regulations. On May 11, 1995, NYSEG requested
rehearing of the order and, by order issued July 19, 1995, the FERC
unanimously (5-0) denied NYSEG's request. On June 14, 1995, NYSEG
petitioned the United States Court of Appeals for the District of
Columbia Circuit (the "Court of Appeals") for review of FERC's April
12, 1995 order. FERC moved to dismiss NYSEG's petition for review on
July 28, 1995. On October 30, 1996, all parties filed final briefs
and the Court of Appeals heard oral arguments on December 2, 1996. On
July 11, 1997, the Court of Appeals dismissed NYSEG's appeal from
FERC's denial of the petition on jurisdictional grounds.
On August 7, 1997, NYSEG filed a complaint in the U.S. District Court
for the Northern District of New York against the FERC, the PSC (and
the Chairman, Deputy Chairman and the Commissioners of the PSC as
individuals in their official capacity), the Saranac Partnership and
Lockport Energy Associates, L.P. ("Lockport") concerning the power
purchase agreements that NYSEG entered into with Saranac Partners and
Lockport.
NYSEG's suit asserts that the PSC and the FERC improperly implemented
PURPA in authorizing the pricing terms that NYSEG, the Saranac
Partnership and Lockport agreed to in those contracts. The action
raises similar legal arguments to those rejected by the FERC in its
April and July 1995 orders. NYSEG in addition asks for retroactive
reformation of the contracts as of the date of commercial operation
and seeks a refund of $281 million from the Saranac Partnership.
Saranac and other parties have filed motions to dismiss and oral
arguments on those motions were heard on March 2, 1998. Saranac
believes that NYSEG's claims are without merit for the same reasons
described in the FERC's orders.
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, 1997, the Company's future minimum rental payments
with respect to non-cancelable operating leases were as follows:
1998 $ 5,321
1999 4,970
2000 4,914
2001 4,742
2002 4,643
Thereafter 53,905
$ 78,495
21. Geographic Information
The Company operates in one principal industry segment: the
generation, distribution and supply of electricity to customers
located throughout the world. Europe consists primarily of Northern.
The Company's operations by geographic area are as follows:
1997 1996 1995
Revenue
Americas $ 570,587$ 486,189 $ 386,833
Asia 102,960 33,282 ---
Europe 1,566,442 39,191 ---
Corporate/Other 30,922 17,533 11,890
$2,270,911 $ 576,195 $ 398,723
Operating income *
Americas $ 301,589 $ 259,665 $ 209,872
Asia 61,131 16,766 ---
Europe 191,299 6,163 ---
Corporate/Other (12,882) (10,931) (10,376)
$ 541,137 $ 271,663 $ 199,496
* Operating income excludes the loss on equity investment in Casecnan,
net interest expense and the non-recurring charge.
1997 1996
Identifiable assets
Americas $ 2,268,629 $ 2,364,448
Asia 835,616 649,053
Europe 2,937,686 2,384,789
Corporate/Other 1,445,695 231,866
$ 7,487,626 $ 5,630,156
22. QUARTERLY FINANCIAL DATA (UNAUDITED)
Following is a summary of the Company's quarterly results of
operations for the years ended December 31, 1997 and 1996.
Three
Months
Ended *
1997: (1) March 31 June 30 September 30 December 31
Operating revenue $542,589 $505,922 $527,896 $589,931
Total revenue 565,976 524,994 551,893 628,048
Total costs and 506,104 460,184 467,900 639,863
expenses
Income (loss) before 59,872 64,810 83,993 (11,815)
income taxes 22,249 24,342 27,929 24,524
Provision for income
taxes
Income (loss) before 37,623 40,468 56,064 (36,339)
minority interest 10,175 9,579 9,656 16,583
Minority interest
Income (loss) before 27,448 30,889 46,408 (52,922)
extraordinary item --- --- (135,850) ---
Extraordinary item
Net income (loss)
attributable to 27,448 30,889 (89,442) (52,922)
common stockholders
Income (loss) per
share before extraordinary
item $ .43 $ .49 $ .73 $ (.67)
Extraordinary item --- --- (2.14) ---
Net income (loss) per
share $ .43 $ .49 $ (1.41) $ (.67)
Income (loss) per
share before
extraordinary item - $ .42 $ .46 $ .67 $ (.67)
diluted --- --- (1.80) ---
Extraordinary item -
diluted
Net income (loss) per
share - diluted $ .42 $ .46 $ (1.13) $ (.67)
Three Months Ended
*
1996: (112) March 31 June 30 September 30 December 31
Operating revenue $ 75,944 $104,735 $165,487 $172,768
Total revenue 90,356 115,794 179,048 190,997
Total costs and 69,398 86,039 121,545 158,809
expenses
Income before income 20,958 29,755 57,503 32,188
taxes 6,497 9,040 18,325 7,959
Provision for income
taxes
Income before minority 14,461 20,715 39,178 24,229
interest --- 1,443 1,624 3,055
Minority interest
Net income attributable
to common stockholders $14,461 $19,272 $37,554 $ 21,174
Net income per share $ .28 $ .37 $ .71 $ .34
Net income per share -
diluted $ .27 $ .34 $ .61 $ .33
* The Company's operations are seasonal in nature.
(1) Reflects acquisitions of Northern, Falcon Seaboard and the
Partnership Interest.
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, 1997
and 1996, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in
the period ended December 31, 1997. 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, 1997 and
1996 and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Omaha, Nebraska
February 12, 1998