Exhibit 13.0
FINANCIAL SUMMARY
In 1994, California Energy Company, Inc. produced record revenue, received
proceeds of $400 million from its issuance of Senior Discount Notes,
successfully closed financing and began construction of two geothermal
facilities in the Philippines, executed power purchase agreements for a 30 MW
geothermal pilot project to be constructed at Newberry, Oregon, secured three
additional power sales contracts in the Philippines and Indonesia, and
commenced the acquisition of Magma Power Company.
Revenues during 1994 increased to $185,854,000, a 25% increase from 1993
revenues of $149,253,000. The increase was due primarily to the contracted
annual energy price increase pursuant to the Coso Projects' power sales
contracts with Southern California Edison, and the commencement of commercial
operations of the 50 MW Yuma Cogeneration Project in late May 1994. During the
year, the plants comprising the Coso Project operated at an average 106.5%
capacity factor and received the maximum capacity and bonus payments available.
Income before the provision for taxes in 1994 was $55,836,000 as compared to
$61,258,000 in 1993. 1994 income reflects the effect of interest expense
resulting from the Company's issuance in March 1994 of 10 1/4% Senior Discount
Notes. Excluding the effects of the Notes issuance, income before provision for
taxes increased to $71,553,000 in 1994. Net income available to common
shareholders was $31,817,000 in 1994 compared to $42,544,000 in 1993. In March
1994, the Company recorded a one-time after tax charge to earnings of
$2,007,000 in connection with the defeasance of its 12% Senior Notes. In
January 1993, the Company adopted FAS 109, Accounting for Income Taxes, and
recorded a one-time noncash gain of $4,100,000. Excluding the effects of these
nonrecurring items, net income available to common shareholders was $33,824,000
in 1994 as compared to $38,444,000 in 1993.
In March 1994, the Company received proceeds of $400,000,000 from its issuance
of $529,640,000 aggregate principal amount Senior Discount Notes. The original
issue discount (the difference between $400,000,000 and $529,640,000) will be
amortized from issue date through January 15, 1997, during which time no cash
interest will be paid on the Senior Discount Notes. Commencing July 15, 1997,
cash interest on the Senior Discount Notes will be paid semiannually on January
15 and July 15 of each year. The Senior Discount Notes, which are redeemable
after January 15, 1999 at the option of the Company, mature on January 15, 2004
and bear an interest rate of 10 1/4%.
In April 1994, the Company closed financing and shortly thereafter commenced
construction of the 128 GMW Upper Mahiao geothermal power project in the
Philippines. In August 1994, the Company closed financing and immediately
commenced construction of the 180 GMW Mahanagdong geothermal project, also in
the Philippines. In addition, the Company during 1994 secured power sales
contracts aggregating up to 970 GMW of geothermal and hydroelectric power in
the Philippines, Indonesia and Oregon. These achievements underscore the
Company's ability to identify, target, and successfully develop power
generation projects internationally and in the U.S.
In September 1994, the Company initiated the purchase of 51% of outstanding
shares of Magma Power Company ("Magma") as the first step in the acquisition of
the entire equity interest in Magma. Purchase of majority control was completed
in January 1995, and the remaining 49% of the outstanding equity was acquired
in late February 1995. Concurrently with purchase of the remaining 49% of
Magma, the Company closed an offering of 16,670,000 shares of common stock at a
price of $17.00 per share providing net proceeds to the Company of
$275,653,300. In addition, the Company received proceeds of $24,735,000 on the
sale of 1,500,000 shares pursuant to the exercise by the underwriters of the
over-allotment option in connection with the public offering.
Upon completion of the Magma acquisition, the Company has become the largest
independent geothermal power producer in the world. The Company has an
aggregate net ownership of 347 MW of electric generating capacity in power
production facilities in the United States having an aggregate net capacity of
553 MW. The Company also has an aggregate net ownership of 409 MW of electric
generating capacity in three geothermal power projects in the Philippines
having an aggregate net capacity of 500 MW, which projects are financed and
under construction. Furthermore, the Company has a net ownership interest of
935 MW in eight additional development projects with executed or awarded power
sales contracts representing an aggregate net 1,589 MW of electric generating
capacity in the Philippines, Indonesia, and the United States.
The achievements of 1994 demonstrate our commitment to the goal of becoming the
most cost effective developer and operator of environmentally responsible power
generation facilities in the world.
SELECTED FINANCIAL DATA
amounts in thousands except per share data
YEAR ENDED DECEMBER 31,
1994 1993 1992 1991 1990
Sales of electricity $152,047 $129,861 $115,087 $104,155 $89,026
Sales of steam 2,515 2,198 2,255 2,029 -----
Other income 31,292 17,194 10,187 9,379 7,787
Expense 130,018 87,995 76,797 80,697 81,248
Income before provision for income taxes 55,836 61,258 50,732 34,866
Income before change in accounting principle
and extraordinary item 38,834 43.074 38,810 26,582 12,043
Cumulative effect of change in accounting
principle ----- 4,100 ----- ----- -----
Extraordinary item (2,007) ----- (4,991) -----
Net income 36,827 47,174 33,819 26,582 12,043
Preferred dividends 5,010 4,630 4,275 ----- -----
Income per share before change in accounting
principle and extraordinary item .95 1.00 .92 .75 .44
Cumulative effect of change in accounting
principle ----- ----- ----- ----- -----
Extraordinary item per share (.06) ----- (.13) ----- -----
Net income per share .89 1.11 .79 .75 .44
Total assets 1,131,145 715,984 580,550 517,994 331,134
Total liabilities 867,703 425,393 336,272 298,146 331,134
Deferred income 19,851 20,228 21,164 22,015 2,926
Redeemable preferred stock 3,600 58,800 54,350 54,705 4,705
Stockholders' equity 179,991 211,503 168,764 143,128 55,088
Common stock cash dividends ----- ----- ----- ----- -----
Management's Discussion and Analysis of
Financial Condition and Results of Operations
dollars and shares in thousands except per share data
The following is management's discussion and analysis of certain significant
factors which have affected the Company's financial condition and results of
operations during the periods included in the accompanying statements of
operations.
GENERAL
For purposes of consistency in financial presentation, the Plants comprising
the Coso Project (including the Navy I, Navy II, and BLM Plants) capacity
factors are based upon a nameplate rating of 88 gross MW ("GMW")/80 net MW
("NMW") for each plant. The Navy I and Navy II Plants each consist of a set of
three turbines located at a plant site. The BLM Plant consists of two turbines
at one site ("BLM East") and one turbine at another site ("BLM West"). Each
Plant possesses an operating margin which periodically allows for production in
excess of the nameplate rating listed above which produces plant capacity
factors in excess of 100%. 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.
RESULTS OF OPERATIONS
THREE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
Sales of electricity and steam increased to $154,562 in the year ended December
31, 1994 from $132,059 in the year ended December 31, 1993, a 17.0% increase.
This improvement was primarily due to a 2.4% increase in the Coso Project's
electric kWh sales to 2,238.6 million kWh from 2,186.7 million kWh, an
increased price per kWh in accordance with the SO4 agreements, and revenue
received from the Yuma Project, which commenced commercial operation in late
May, 1994. The increase in Coso Project kWh sales was primarily due to the
completion of new production wells. The increase in sales of electricity and
steam in 1993 to $132,059 from $117,342 in 1992 was primarily due to increasing
the Coso Project's electric kWh sales by 9.1% to 2,186.7 million kWh from
2,004.0 million kWh largely as a result of the drilling of additional
production wells, and the aforementioned increase in price per kWh pursuant to
the SO4 agreements.
The following operating data includes the full capacity and electricity
production of the Coso Project only:
1994 1993 1992
Overall Capacity Factor 106.5% 104.0% 95.1%
kWh Produced 2,238,600,000 2,186,700,000 2,004,000,000
Installed Capacity NMW (Average) 240 240 240
The overall Coso Plant capacity factor was 109.3% in the fourth quarter of 1994
compared to 109.5%, 104.9% and 102.1% for the third, second and first quarters
of 1994, respectively. The Navy I Plant capacity factor was 114.0% in 1994,
compared to 111.2% and 99.8% in 1993 and 1992, respectively. The Navy II Plant
capacity factor was 105.9% in 1994 compared to 102.6% and 98.1% in 1993 and
1992, respectively. The BLM Plant capacity factor was 99.5% in 1994 compared to
98.1% and 87.2% in 1993 and 1992, respectively. The Navy II Plant, BLM Plant
and the Navy I Plant were overhauled in conjunction with scheduled maintenance
inspections in 1994, 1993 and 1992 respectively, resulting in a temporary
reduction of the plant capacity factor of approximately 3% in the specified
year. Electric sale price per kWh for the Coso Project varies seasonally in
accordance with the rate schedule included in the SO4 agreements. The price
consists of an energy payment based on the annualized contracted rate of 10.91
cents per kWh in 1994, 10.11 cents per kWh in 1993, and 9.23 cents per kWh in
1992, and constant annual capacity payments of which the Company's share was
approximately $5,600 to $5,900 per annum for each of the three power plants.
Capacity payments are significantly higher in the months of June through
September. Bonus payments are received monthly, of which the Company's share
was approximately $1,000 per annum for each of the three power plants.
The Coso Project's average electricity prices per kWh in 1994, 1993 and 1992
were comprised of (in cents):
CAPACITY
ENERGY & BONUS TOTAL
Average fiscal 1994 10.91 1.90 12.81
Average fiscal 1993 10.11 1.93 12.04
Average fiscal 1992 9.23 2.10 11.33
The Desert Peak and Roosevelt Hot Springs facilities ran at or near capacity
levels for each of the past three years. Steam sales from the Roosevelt Hot
Springs field were $2,185, $2,198, and $2,255 in 1994, 1993, and 1992,
respectively. Electric sales from Desert Peak were $5,281, $5,177 and $5,347
for the years 1994, 1993, and 1992, respectively. Electric and steam sales from
Yuma were $10,082 for approximately seven months in 1994.
Interest and other income increased in 1994 to $31,292 from $17,194 in 1993 and
from $10,187 in 1992. The increase reflects higher average cash balances
resulting from the issuance of the Senior Discount Notes, interest income on
notes receivable from the Coso Joint Ventures and interest income on the
Company's share of the cash reserves established in the refinancing of the Coso
Project debt in December, 1992.
The Company's cost per kWh* was as follows (in cents):
1994 1993 1992
Plant operations (net of
Company's operator fees
and Yuma fuel cost) 1.54 1.64 1.65
General and administration .82 1.03 1.04
Royalties .62 .65 .61
Depreciation and amortization 1.34 1.39 1.33
Interest, less amounts
capitalized 3.33 1.82 1.17
Total 7.65 6.53 5.80
*Cost per kWh includes electrical production from the Desert Peak and Yuma
facilities and the electrical production equivalent of the company's share of
geothermal steam produced at the Roosevelt Hot Springs Field.
The Company's expenses* as a percentage of sales of electricity and steam were
as follows:
1994 1993 1992
Plant operations (net of
Company's operator fees
and Yuma fuel cost) 15.8% 15.8% 17.7%
General and administration 8.4 10.0 11.1
Royalties 6.4 6.3 6.6
Depreciation and amortization 13.7 13.5 14.3
Interest, less amounts capitalized 34.2 17.7 12.7
Total 78.5% 63.3% 62.4%
*Expenses as a percentage of electricity sales and steam sales include
electricity sales from the Desert peak and Yuma facilities and steam sales from
the Roosevelt Hot Springs field.
The Company's expenses, excluding interest, increased as a general result of
the greater electricity production of the Coso Project and the inclusion of the
costs from the Yuma plant which operated for seven months in 1994. However, in
1994, excluding Yuma fuel cost of $4,107, plant operations and general and
administration costs per kWh decreased from 1993. In addition, in 1993, plant
operations and general and administration costs per kWh also decreased from
1992.
The cost of plant operations increased to $33,015 in 1994 from $25,362 in 1993,
an increase of 30.2%. The increase is a result of the cost of plant operations
at Yuma. The cost of plant operations increased to $25,362 in 1993 from $24,440
in 1992, an increase of 3.8%. General and administration costs decreased to
$13,012 in 1994 compared to $13,158 in 1993 a 1.1% decrease. General and
administration costs increased to $13,158 in 1993 from $13,033 in 1992, a 1.0%
increase. However, for 1994, 1993, and 1992, excluding Yuma fuel cost, both
plant operations and general and administration costs per kWh continued to
decrease due to a proportionally greater increase in electrical production than
plant operations and general administration costs. Plant cost per kWh decreased
to 1.54 cents in 1994 from 1.64 cents in 1993 and 1.65 cents in 1992. General
and administration cost per kWh decreased to .82 cents in 1994 from 1.03 cents
in 1993 and 1.04 cents in 1992.
Royalty costs increased to $9,888 in 1994 from $8,274 in 1993, an increase of
19.5% due to higher electrical sales and effective royalty rate. Royalty costs
increased to $8,274 in 1993 from $7,710 in 1992, an increase of 7.3%. This
increase was due to higher electrical sales and effective royalty rate.
Overall, the royalty cost per kWh was 0.62 cents in 1994 compared to 0.65 cents
in 1993 and 0.61 cents in 1992. The 1994 royalty cost per kWh decreased as a
result of the production at Yuma which is not burdened by royalty payments.
Excluding Yuma electricity production, the Company's royalty cost per kWh was
0.73 cents in 1994.
Depreciation and amortization expense increased to $21,197 in 1994 from $17,812
and $16,754 in 1993 and 1992, respectively, a 19.0% increase from 1994 to 1993,
and a 6.3% increase from 1993 to 1992. Depreciation and amortization expense
for 1994 was 1.34 cents per kWh compared to 1.39 cents per kWh in 1993 and 1.33
cents per kWh in 1992. The dollar increase in 1994 was due to the completion of
H2S abatement systems, vacuum pumps at the Coso plants, increased number of
wells, and the commencement of Yuma operations. The increase in 1993 was due to
additional capitalized costs associated with the settlement of litigation as
well as additional wells and gathering systems.
Interest expense, less amounts capitalized, increased to $52,906 in 1994 from
$23,389 in 1993, an increase of 126.2%, or 3.33 cents per kWh in 1994, compared
to 1.82 cents per kWh in 1993. Net interest expense increased to $23,389 in
1993 from $14,860, or 1.17 cents per kWh in 1992. Net interest expense in 1994
increased due primarily to the Company's issuance of Senior Discount Notes in
March 1994. The increase in 1993 was due to a higher weighted average interest
rate, higher levels of indebtedness associated with the Coso Project, and the
issuance of Convertible Subordinated Debentures in June 1993. The short-term
variable rate debt on the Coso Project was refinanced in 1992 with longer-term
fixed rate debt. The weighted average interest rate on the Coso Project debt
was 8.1%, 7.9%, and 5.4% in 1994, 1993, and 1992 respectively.
The provision for income taxes decreased to $17,002 in 1994 from $18,184 in
1993, and increased to $18,184 in 1993 from $11,922 in 1992. The effective tax
rate was 30.5%, 29.7% and 23.5% in 1994, 1993, and 1992. The increase in the
1993 effective tax rate was a result of adopting Financial Accounting Standard
109 ("FAS 109").
Income before the provision for income taxes decreased 8.9% to $55,836 in 1994
from $61,258 in 1993. Net income after an extraordinary item was $36,827 and
net income available to common shareholders was $31,817 or $.89 per common
share for the year ended December 31, 1994. This compares to net income of
$47,174 after the cumulative effect of a change in accounting principle and net
income available to common shareholders of $42,544 or $1.11 per common share
for the year ended December 31, 1993. Net income before an extraordinary item
for the year ended December 31, 1994 was $38,834 or $.95 per common share
versus net income before the cumulative effect of a change in accounting
principle of $43,074 or $1.00 per common share in 1993. This compares to net
income of $33,819 after an extraordinary item and net income available to
common shareholders of $29,544 or $.79 per common share for 1992.
Earnings per share in 1994, 1993, and 1992 were favorably impacted by the
Company's stock repurchase plan.
LIQUIDITY AND CAPITAL RESOURCES
Cash and short-term investments were $304,004 at December 31, 1994 as compared
to $127,756 at December 31, 1993. In addition, the Coso Project retained cash
and investments in project control accounts of which the Company's share was
$54,087 and $14,943 at December 31, 1994 and 1993, 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 Joint
Venture partner for profit sharing under a prescribed calculation subject to
mutual agreement by the partners. In addition to these liquid instruments, the
Company recorded separately restricted cash of $131,775 and $48,105 at December
31, 1994 and 1993, respectively. The restricted cash balance in 1994 was
comprised primarily of amounts deposited in restricted accounts from which the
Company will provide all of its equity contribution requirements relating to
the Upper Mahiao and Mahanagdong projects and also comprise and the Company's
proportionate share of Coso Project cash reserves for the fully-funded debt
reserve funds.
Accounts receivable normally represents two months of revenues, and fluctuates
with both production and price per kWh.
The balance due from/to the Joint Ventures relates to operations, maintenance,
and management fees for managing the Coso Project as well as advances on the
international projects. This amount fluctuates based on the timing of billings
and incurrence of costs.
In March 1994, the Company issued $400,000 of 10 1/4% Senior Discount Notes
which accrete to an aggregate principal amount of $529,640 at maturity in 2004.
The original issue discount (the difference between $400,000 and $529,640) will
be amortized from issue date through January 15, 1997, during which time no
cash interest will be paid on the Senior Discount Notes. Commencing July 15,
1997, cash interest on the Senior Discount Notes will be payable semiannually
on January 15 and July 15 of each year. The Senior Discount Notes are
redeemable at any time on or after January 15, 1999. The redemption prices
commencing in the twelve month period beginning January 15, 1999 (expressed in
percentages of the principal amount) are 105.125%, 103.417%, 101.708%, and 100%
for 1999, 2000, 2001, and 2002, respectively, plus accrued interest through the
redemption date in each case. The Senior Discount Notes are unsecured senior
obligations of the Company.
Simultaneous with the closing of the Senior Discount Notes (see Note 7 of the
Notes to the Consolidated Financial Statements), the Company used approximately
$39,000 to defease and provide for the repayment of the entire aggregate
principal amount of Senior Notes outstanding. The Senior Notes, in the
aggregate principal amount of $35,730, mature in March 1995 and bear interest
at the rate of 12% per annum, plus contingent interest, calculated by reference
to the Company's share of the cash flow from the Coso Project through December
31, 1994.
In June of 1993, the Company issued $100,000 principal amount of 5% convertible
subordinated debentures (the "Convertible Subordinated Debentures") due July
31, 2000. The Convertible Subordinated Debentures are convertible into shares
of the Company's common stock at any time prior to redemption or maturity at a
conversion price of $22.50 per share, subject to adjustment in certain
circumstances. Interest on the Convertible Subordinated Debentures is payable
semi-annually in arrears on July 31 and January 31 each year, commencing on
July 31, 1993. The Convertible Subordinated Debentures are redeemable for cash
at any time on or after July 31, 1996 at a redemption price of (expressed in
percentages of the principal amount) 102%, 101%, 100% and 100% in 1996, 1997,
1998 and 1999, respectively. The Convertible Subordinated Debentures are an
unsecured general obligation of the Company and subordinated to all existing
and future senior indebtedness of the Company.
In December 1992, the Company refinanced the existing bank debt of the Coso
Project utilizing a single purpose corporation, Coso Funding Corp., to issue
the notes (see Note 5 of the Notes to the Consolidated Financial Statements).
As of December 31, 1994 and 1993 the Company's proportionate share of the Coso
Project loan was $233,080 and $246,880, respectively. The Coso Funding Corp.
notes have remaining terms of up to seven years and different fixed interest
rates for each tranche. The underlying project loans have identical terms as
the Coso Project loans and are also non-recourse to the Company.
On June 9, 1993, MPE and the Mission Power Group, subsidiaries of SCECorp., and
the Coso Joint Ventures reached a final settlement of all of their outstanding
disputes and claims relating to the construction of the Coso Project. As a
result of the various payments and releases involved in such settlement, the
Coso Joint Ventures agreed to make a net payment of $20,000 to MPE from the
cash reserves of the Coso Project contingency fund and MPE agreed to release
its mechanics' liens on the Coso Projects. After making the $20,000 payment,
the remaining balance of the Coso Project contingency fund (approximately
$49,300) was used to increase the Coso Project debt reserve fund from
approximately $43,000 to its maximum fully-funded requirement of $67,900. The
remaining $24,400 balance of the contingency fund was retained within the Coso
Project for future capital expenditures and for Coso Project debt service
payments. Since the Coso Project debt service reserve is fully funded in
advance, Coso Project cash flows otherwise intended to fund the Coso Project
debt service reserve funds, subject to satisfaction of certain covenants and
conditions contained in the Coso Joint Ventures' refinancing documents, are
available for distribution to the Company in its proportionate share.
The Company repurchased 3,765 common shares during 1994 for the aggregate
amount of $65,119. The Company repurchased 157 shares of common stock in 1993
at an aggregate amount of $2,897. As of December 31, 1994 the Company holds
3,800 shares of treasury stock at a cost of $65,774 to provide shares for
issuance under the Company's employee stock option and share purchase plans and
other outstanding convertible securities. The repurchase plan attempts to
minimize the dilutive effect of the additional shares issued under these plans.
Subsequent to year end these shares were issued in a public offering associated
with the Magma transaction.
The Company is actively engaged in the acquisition of, and is seeking to
develop, construct, own and operate power projects utilizing geothermal and
other technologies, both domestically and internationally, the completion of
any of which is subject to substantial risk. The Company is currently pursuing
a number of international power project opportunities in countries where
private power generation programs have been initiated, including the
Philippines and Indonesia. Development can require the Company to expend
significant sums for preliminary engineering, permitting, 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 financeable. Successful development is contingent upon, among
other things, negotiation of construction, fuel supply and power sales
contracts with other project participants on terms satisfactory to the Company,
and receipt of required governmental permits and consents. Further, there can
be no assurance that the Company will obtain access to the substantial debt and
equity capital required for the acquisition or development and construction of
electric power projects. To the extent the Company engages in international
development efforts, the financing and development of projects 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 that
the Company may not be fully capable of insuring against. There can be no
assurance that development efforts on any particular project, or the Company's
acquisition or development efforts generally, will be successful.
In particular, the Company is developing a number of international projects,
for which it may have significant capital requirements. In 1995, the Company
intends to incur approximately $41,000 for international development efforts.
In addition to its international projects, the Company intends to incur its
share of domestic geothermal capital expenditures in the approximate aggregate
amount of $31,000. The Company's planned capital spending includes, among other
things, its share of recurring Coso Project capital expenditures, as well as
development of the Newberry Project in the Pacific Northwest.
In April 1994, the Company closed the financing for the 128 GMW Upper Mahiao
geothermal power project located in the Philippines. The total project cost for
the facility is approximately $218,000. The Company will supply approximately
$56,000 of equity and project debt financing will constitute the balance of
approximately $162,000. A syndicate of international commercial banks is
providing the construction financing. The Export-Import Bank of the U.S.
("Ex-Im Bank") is providing political risk insurance to the commercial banks on
the construction loan and will provide the preponderance of project term
financing upon satisfaction of conditions associated with commercial operation.
As of December 31, 1994, draws on the construction loan totalled $24,508,
equity investments made by a subsidiary of the Company totalled $14,048, and
the Company has invested $9,998. The Overseas Private Investment Corporation
("OPIC") is providing political risk insurance on the equity investment by the
Company in this project. The Upper Mahiao project has begun construction, and
is expected to be in service by July of 1996. The project is structured as a
ten year Build-Own-Operate-Transfer ("BOOT"), in which the Company's subsidiary
CE Cebu Geothermal Power Company, Inc. ("CE Cebu"), the project company, will
be responsible for implementing construction of the geothermal power plant and,
as owner, for providing operations and maintenance during 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. Ormat Inc. of Sparks, Nevada is the turnkey contractor
for the project.
The electricity generated by the Upper Mahiao geothermal power plant will be
sold to the Philippine National Oil Company - Energy Development Corporation
("PNOC-EDC"), on a "take or pay" basis, which is also responsible for supplying
the facility with the geothermal steam. PNOC-EDC will be obligated to pay for
the 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 will pay to CE Cebu a fee (the "Capacity Fee") based on the plant
capacity nominated to PNOC-EDC in any year (which, at the plant's design
capacity, is approximately 95% of total contract revenues) and a fee (the
"Energy Fee") based on the electricity actually delivered to PNOC-EDC
(approximately 5% of total contract revenues). The Capacity Fee serves to
recover the capital costs of the project, to recover fixed operating costs and
to cover return on investment. The Energy Fee is designed to cover all variable
operating and maintenance costs of the power plant. Payments under the Upper
Mahiao Energy Conversion Agreement ("ECA") will be denominated in U.S. dollars,
or computed in U.S. dollars and paid in Philippine pesos at the then-current
exchange rate, except for the Energy Fee, which will be used to pay Philippine
peso-denominated expenses. The convertibility of Philippine peso receipts into
U.S. dollars is insured by OPIC. Significant portions of the Capacity Fee and
Energy Fee will be 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.
In August 1994, the Company closed the financing for the 180 GMW Mahanagdong
project located in the Philippines. The total project cost for the facility is
approximately $320 million. The capital structure consists of a term loan of
$240 million and approximately $80 million in equity contributions. OPIC and a
consortium of commercial lenders led by Bank of America NT&SA is providing the
construction debt financing facility. The debt provided by the commercial
lenders is insured against political risk by the Ex-Im Bank. Ten-year term debt
financing (which will replace the construction debt) will be provided by Ex-Im
Bank and by OPIC. The Mahanagdong project has commenced construction and as of
December 31, 1994, the Company's proportionate share of draws on the
construction loan totalled $6,995, equity investments made by a subsidiary of
the Company totaled $3,899, and the Company has invested $10,549. OPIC is
providing political risk insurance on the equity. The Mahanagdong project has
begun construction and is targeted for service in July, 1997. As with the Upper
Mahiao project, the Mahanagdong project is structured as a ten-year
Build-Own-Operate-Transfer ("BOOT"), in which the Company will be responsible
for implementing construction of the geothermal power plant and, as owner, for
providing operations and maintenance for the ten- year BOOT period. After a ten
year cooperation period, and the recovery by the Company of its capital
investment plus incremental return, the plant will be transferred to PNOC-EDC
at no cost. The Mahanagdong project will be built, owned and operated by CE
Luzon Geothermal Power Company, a Philippine corporation, that is expected to
be owned post-completion as follows: 45% by the Company, 45% by Kiewit, and up
to 10% by another industrial company. The turnkey contractor consortium
consists of Kiewit Construction Group, Inc. (with an 80% interest) and The Ben
Holt Co., a wholly owned subsidiary of the Company (with a 20% interest).
The electricity generated by the Mahanagdong project will be sold to PNOC-EDC,
on a "take or pay" basis, which is also responsible for supplying the facility
with the geothermal steam. The terms of the Mahanagdong 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.
The Yuma Cogeneration Associates ("YCA") 50 MW cogeneration power plant
commenced commercial operation pursuant to its power purchase agreement with
San Diego Gas & Electric ("SDG&E") at the end of May, 1994. YCA, a wholly owned
subsidiary of the Company, received all outstanding amounts due from SDG&E.
The Company has acquired all of the outstanding equity interest in Magma Power
Company ("Magma") in a two-step transaction according to the terms of a merger
agreement whereby on January 10, 1995, the Company acquired approximately 51%
of the outstanding shares of Magma common stock (the "Magma Common Stock")
through a cash tender offer (the "Magma Tender Offer") and on February 24, 1995
the Company acquired the remaining 49% of Magma Common Stock not owned by the
Company through a merger (the "Merger"). Each outstanding share of Magma Common
Stock (other than shares of Magma Common Stock held by the Company, CE
Acquisition Company, Inc., a wholly owned subsidiary of the Company, or any
other direct or indirect subsidiary of the Company and shares of Magma Common
Stock held in the treasury of Magma) was converted into the right to receive an
average of approximately $38.75 per share of Magma Common Stock. The Company
paid the Merger consideration solely in cash, funded with the net proceeds of a
public common stock offering of 15,170 shares (the "Offering"), and the
proceeds of a direct sale of 1,500 shares to Peter Kiewit Sons', Inc. (the
"Direct Sale") at $17.00 per share which together netted $275,653, borrowings
of $500,000 under bank credit facilities, and general corporate funds of the
Company. In addition, the Company received over-allotment proceeds of $24,735
on the sale of 1,500 shares. Magma is engaged in independent geothermal power
operations and development activities similar to those of the Company.
The Magma Tender Offer was financed with a $245,600 facility from Credit Suisse
(the "Tender Facility"). Loans under the Tender Facility were made to the
Company on a non-recourse basis, secured by the magma Stock acquired, and the
Company lent the proceeds of such loans to Magma in exchange for a secured term
note of Magma (the "Tender Note"). The loans under the Tender Facility were
repaid from funds received from the Merger Facilities.
A total of approximately $957,000 was required to refinance the Tender Facility
and to complete the Magma acquisition (the "Magma Acquisition"). Up to $500,000
in secured bank financing was provided by Credit Suisse (the "Merger
Facilities") on specified terms and subject to customary conditions. Such funds,
together with the net proceeds of the Offering and over-allotment, the proceeds
of the Direct Sale and general corporate funds of the Company, were used to
complete the Magma Acquisition.
The Merger Facilities are comprised of (i) a six-year term loan ("Term Loan A")
in a principal amount of up to the difference between $500,000 and the
principal amount of Term Loan B (as defined below), to be amortized in
semi-annual payments, and (ii) an eight-year term loan ("Term Loan B") in a
principal amount of $150,000, to be amortized in semi-annual payments in the
seventh and eighth years of such Term Loan. Loans under the Merger Facilities
were made to the Company on a non-recourse basis, and the Company lent the
proceeds of such loans to Magma in exchange for a secured term note of Magma
(the "Magma Note"). The loans under the Merger Facilities will be amortized
from payments received by the Company from Magma on the Magma Note which is
expected to be amortized from internally generated funds of Magma. Loans under
the Merger Facilities are secured by an assignment and pledge by the Company of
the Magma Note and 100% of the capital stock of Magma. The Magma Note is
secured by an assignment of certain unencumbered assets of Magma.
Interest on loans under the Merger Facilities are payable at spreads of 2.50%
above LIBOR (adjusted for reserves) or 1.50% above the Base Rate for Term Loan
A, and 3.00% above LIBOR (adjusted for reserves) or 2.00% above the Base Rate
for Term Loan B. The LIBOR spreads are subject to upward adjustment in certain
instances. The Company may elect to have loans bear interest based on either
LIBOR or the Base Rate (as defined in the Merger Facilities).
The Merger Facilities contain affirmative and negative covenants customary for
similar non-recourse credit facilities. Such covenants include a negative
pledge of all stock and unencumbered assets of Magma; a limitation on
guaranties by Magma; a limitation on mergers and sales of assets by Magma; a
limitation on investments in other persons by Magma; a prohibition on dividends
and other payments by Magma to the Company unless the proceeds are used to pay
down the Merger Facilities; a prohibition on the sale of ownership interests in
Magma; a limitation on the incurrence of additional debt by Magma; a
requirement that the Company deliver each fiscal quarter a certificate as to
the absence of material adverse changes in the Company or Magma which could
reasonably be expected to materially affect the ability of the Company to repay
the Merger Facilities or the ability of the lenders to realize on the
collateral for the Merger Facilities; and a restriction on a change in the
nature of the business of the Company and Magma.
The Merger Facilities also contain financial covenants and customary events of
default, including events of default based on breaches of certain
representations, warranties and covenants; cross defaults with respect to
certain debt of the Company and Magma; bankruptcy and similar events; the
failure to pay certain final judgments; the failure to make a payment with
respect to the Merger Facilities when due; and the failure of the pledge
agreement with respect to the capital stock of Magma and the Magma Note to be
in full force and effect.
Inflation has not had a substantial impact on the Company's operating revenues
and costs. The Coso Project's energy payments for electricity will continue to
be based upon scheduled rate increases through the initial ten-year period of
each SO4 Agreement. Prior to the Coso Project refinancing, the Project Loans
relating to the Coso Project were generally for periods up to twelve months at
LIBOR plus a specified margin. Accordingly, the interest rates on the loans
varied and over the operating period resulted in fluctuating interest payments.
The refinanced Coso Project debt has fixed interest rates.
ADOPTION OF FINANCIAL ACCOUNTING STANDARD NO. 109
On January 1, 1993, the Company adopted FAS 109. The adoption of FAS 109
changed the Company's method of accounting for income taxes from the deferred
method as required by Accounting Principles Board No. 11 to an asset and
liability approach. Under FAS 109, the net excess deferred tax liability as of
January 1, 1993 was determined to be $4,100. This amount was reflected in 1993
income as the cumulative effect of a change in accounting principle. It
primarily represents the recognition of the Company's tax credit carryforwards
as a deferred tax asset. There was no cash impact to the Company upon the
required adoption of FAS 109. Under FAS 109, the effective tax rate increased
at the time of adoption as a result of the tax credit carryforwards being
recognized as an asset and unavailable to reduce the current period's effective
tax rate for computing the Company's provision for income taxes. The effective
tax rate continues to be less than the statutory rate primarily due to the
depletion deduction and the generation of energy credits in 1994. The
significant components of the deferred tax liability are the temporary
differences between the financial reporting bases and income tax bases of the
power plant and the well and resource development costs, and in addition, the
offsetting benefits of operating loss carryforwards and investment and
geothermal energy tax credits and alternative minimum tax carryforwards.
CONSOLIDATED BALANCE SHEETS
As of December 31, 1994 and December 31, 1993
dollars and shares in thousands, except per share amounts
ASSETS 1994 1993
Cash and investments $254,004 $127,756
Joint venture cash and investments (Note 5) 54,087 14,943
Restricted cash (Notes 4, 5 and 6) 131,775 48,105
Short-term investments 50,000 ---
Accounts receivable 28,272 21,658
Due from Joint Ventures --- 1,394
Properties and plants, net (Notes 4, 5, and 6) 556,992 458,974
Equipment, net of accumulated depreciation of
$5,023 and $4,773 4,651 4,540
Notes receivable - Joint Ventures (Note 15) 12,627 11,280
Deferred charges and other assets 38,737 27,334
Total assets $1,131,145 $ 715,984
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable $ 1,679 $ 607
Other accrued liabilities 42,658 19,866
Income taxes payable (Note 10) --- 4,000
Project finance loans (Note 5) 233,080 246,880
Construction loans (Note 6) 31,503 ---
Due to Joint Ventures 269 ---
Senior notes (Note 8) --- 35,730
Senior discount notes (Note 7) 431,946 ---
Convertible subordinated debentures (Note 9) 100,000 100,000
Deferred income taxes (Note 10) 26,568 18,310
Total liabilities 867,703 425,393
Deferred income (Note 4) 19,851 20,288
Commitments and contingencies (Notes 3, 14 and 17)
Redeemable preferred stock (Note 11) 63,600 58,800
Stockholders' equity (Notes 12, 13, and 17):
Preferred stock - authorized 2,000 shares,
no par value (Note 11) --- ---
Common stock - authorized 60,000 shares,
par value $0.0675 per share
issued and outstanding 31,849 and 35,446 shares 2,407 2,404
Additional paid in capital 100,421 100,965
Retained earnings 142,937 111,031
Treasury stock - 3,800 and 157 common shares at cost (65,774) (2,897)
Total stockholders' equity 179,991 211,503
Total liabilities and
stockholders' equity $1,131,145 $ 715,984
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
for the three years ended December 31, 1994
dollars and shares in thousands, except per share amounts
1994 1993 1992
Revenue:
Sales of electricity and steam $154,562 $132,059 $117,342
Interest and other income 31,292 17,194 10,187
Total revenues 185,854 149,253 127,529
Cost and expenses:
Plant operations 33,015 25,362 24,440
General and administration 13,012 13,158 13,033
Royalties 9,888 8,274 7,710
Depreciation and amortization 21,197 17,812 16,754
Interest 62,837 30,205 20,459
Less interest capitalized (9,931) (6,816) (5,599)
Total expenses 130,018 87,995 76,797
Income before provision for income taxes 55,836 61,258 50,732
Provision for income taxes (Note 10) 17,002 18,184 11,922
Income before change in accounting principle
and extraordinary item 38,834 43,074 38,810
Cumulative effect of change in accounting
principle (Note 10) --- 4,100 ---
Extraordinary item (Note 16) (2,007) --- (4,991)
Net income 36,827 47,174 33,819
Preferred dividends 5,010 4,630 4,275
Net income available to common stockholders $31,817 $42,544 $29,544
Income per share before change in accounting
principle and extraordinary item $.95 $ 1.00 $ .92
Cumulative effect of change in accounting
principle (Note 10) --- .11 ---
Extraordinary item (Note 16) (.06) --- (.13)
Net income per share assuming no dilution $ .89 $ 1.11 $ .79
Average number of shares outstanding 35,721 38,485 37,495
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
for the three years ended
December 31, 1994 dollars and shares in thousands
Outstanding Additional
Common Common Paid-In Retained Treasury
Shares Stock Capital Earnings Stock
Total
Balance January 1, 1992 32,712 $2,208 $100,170 $40,750 --- $143,128
Exercise of stock options 1,544 67 2,764 --- --- 2,831
Exercise of warrants 612 41 1,206 --- --- 1,247
Issue costs on stock --- --- (96) --- --- (96)
Purchases/issuances of treasury stock
for exercise of options and warrants,
net of proceeds of $797 (565) --- (4,090) --- --- (4,090)
Preferred stock dividends, Series B & C,
including cash distributions of $134 --- --- --- (6,162) --- (6,162)
Retirement of warrants --- --- (11,716) --- --- (11,716)
Tax benefit from stock plan --- --- 3,420 --- --- 3,420
Net income before preferred dividends --- --- --- 33,819 --- 33,819
Conversion of preferred stock
to common stock 955 64 6,319 --- --- 6,383
Balance December 31, 1992 35,258 2,380 97,977 68,407 --- 168,764
Exercise of stock options 258 18 937 --- --- 955
Issuance of stock for purchase of
The Ben Holt Co. 87 6 1,551 --- --- 1,557
Purchase of treasury stock (157) --- --- --- (2,897) (2,897)
Preferred stock dividends, Series C,
including cash distributions of $100 --- --- --- (4,550) --- (4,550)
Tax benefit from stock plan --- --- 500 --- --- 500
Net income before preferred dividends --- --- --- 47,174 --- 47,174
Balance December 31, 1993 35,446 2,404 100,965 111,031 (2,897) 211,503
Exercise of stock options 46 3 379 --- --- 382
Purchase of treasury stock (3,765) --- --- --- (65,119) (65,119)
Exercise of stock options from treasury
stock 96 --- (1,473) --- 1,772 299
Employee stock purchase plan issues
from treasury stock 26 --- (122) --- 470 348
Preferred stock dividends, Series C,
including cash distribution of $121 --- --- --- (4,921) --- (4,921)
Tax benefit from stock plan --- --- 672 --- --- 672
Net income before preferred dividends --- --- --- 36,827 --- 36,827
Balance December 31, 1994 31,849 $ 2,407 $100,421 $142,937 $(65,774) $179,991
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the three years ended December 31,
1994 dollars in thousands
1994 1993 1992
Cash flows from operating activities:
Net income $ 36,827 $ 47,174 $33,819
Adjustments to reconcile net cash flow from operating activities:
Depreciation and amortization 21,197 17,812 16,754
Amortization of original issue discount 31,946 --- ---
Amortization of deferred financing costs 1,687 1,013 967
Expense of previously deferred financing costs 198 --- 3,895
Provision for deferred income taxes 8,258 3,098 3,645
Changes in other items:
Accounts receivable (6,614) (5,486) 1,279
Accounts payable and other accrued liabilities 23,864 (784) (7,082)
Deferred income (437) (876) (851)
Income tax payable (4,500) 4,000 (1,202)
Other assets --- (177) 814
Net cash flows from operating activities 112,426 65,774 52,038
Cash flows from investing activities:
Capital expenditures relating to power plants (26,347) (10,295) (6,711)
Well and resource development expenditures for existing projects (11,370) (16,565) (19,203)
Acquisition of equipment (361) (1,104) (1,093)
Magma acquisition costs (3,043) --- ---
Upper Mahiao - construction in progress (48,554) --- ---
Mahanagdong - construction in progress (21,443) --- ---
Other international development (2,445) --- ---
Pacific Northwest, Nevada, and Utah exploration costs (8,493) (19,060) (4,145)
Yuma - construction in progress --- (40,167) (1,294)
Transmission line deposit --- 7,684 (118)
Increase in short-term investment (50,000) --- ---
Decrease (increase) in restricted cash (83,670) 14,409 9,882
Decrease (increase) in other investments 1,847 941 (14,503)
Net cash flows from investing activities (253,879) (64,157) (37,185)
Cash flows from financing activities:
Proceeds from sale of common, treasury and preferred
stocks and exercise of warrants and options 1,580 2,912 8,065
Repayment of project finance loans --- --- (17,098)
Repayment of project loans (13,800) (16,724) (6,277)
Retirement of project finance loans --- --- (204,210)
Defeasance of senior notes (35,730) --- ---
Proceeds from issue of Senior Discount Notes 400,000 --- ---
Proceeds from refinancing --- --- 269,881
Proceeds from issue of convertible subordinated debentures --- 100,000 ---
Increase in restricted cash related to the refinancing --- --- (65,670)
Deferred charges relating to senior discount note (11,477) --- ---
Construction loans 31,503 --- ---
Deferred charges relating to debt financing (428) (2,582) (2,937)
Decrease (increase) in amounts due from Joint Ventures 316 (3,146) 6,198
Purchase of warrants --- --- (11,716)
Purchase of treasury stock (65,119) (2,897) (4,887)
Net cash flows from financing activities 306,845 77,563 (28,651)
Net increase (decrease) in cash and investments 165,392 79,180 (13,798)
Cash and investments at beginning of period 142,699 63,519 77,317
Cash and investments at end of period $308,091 $142,699 $63,519
Interest paid (net of amounts capitalized) $ 12,624 $20,136 $19,237
Income taxes paid $ 4,926 $6,819 $4,129
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
for the three years ended December 31, 1994
dollars and shares in thousands, except per share amounts
1. BUSINESS
California Energy Company, Inc. (the "Company") was formed in 1971. It
is primarily engaged in the exploration for and development of
geothermal resources and conversion of such resources into electrical
power and steam for sale to electric utilities, and the development of
other environmentally responsible forms of power generation.
The Company has organized several partnerships and Joint Ventures
(herein referred to as 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. The Company is the operator and holds interests between 46.4%
and 50% in the Coso Joint Ventures after payout. Payout is achieved
when a Coso Joint Venture has returned the initial capital to the Coso
Joint Venturers. In addition, the Company is exploring geothermal
resources in Northern California, Washington and Oregon (collectively
the Pacific Northwest). In January 1991, the Company acquired a power
plant and an interest in steam fields in Nevada and Utah (See Note 4
Nevada and Utah Properties). In 1992, the Company entered into the
natural gas-fired electrical generation market through the purchase of
a development opportunity in Yuma, Arizona. Commercial operation of
the Yuma project commenced in late 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 addition, in
January 1995, the Company acquired approximately 51% of Magma Power
Company ("Magma") and completed the acquisition in February 1995 by
acquiring the remaining percentage of approximately 49% of Magma
Common Stock. (See Note 17).
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 Coso Joint Ventures in which it has invested. All significant
inter-enterprise transactions and accounts have been eliminated.
INVESTMENTS AND RESTRICTED CASH
Investments other than restricted cash are primarily commercial paper
and money market securities. The restricted cash balance includes such
securities and mortgage backed securities, and is mainly composed of
amounts deposited in restricted accounts from which the Company will
source its equity contribution requirements relating to the Upper
Mahiao and Mahanagdong projects and of the Coso Joint Ventures' debt
service reserve funds. The debt service reserve funds are legally
restricted to their use and require the maintenance of specific
minimum balances.
Effective January 1, 1994, the Company adopted the provisions of
Statement of Financial Accounting Standards No. 115 ("FAS 115")
"Accounting for Certain Investments in Debt and Equity Securities".
Adoption of FAS 115 had no material effect on the Company's individual
or combined financial position or results or operations. FAS 115
requires the classification of the Company's investments and the
accounting for changes in fair value, as follows:
Debt securities that the Company has the positive intent and ability to
hold to maturity are classified as held-to-maturity securities and reported at
amortized cost.
Debt and equity securities that are bought and held principally for the
purpose of selling them in the near term are classified as trading securities
and reported at fair value, with unrealized gains and losses included in
earnings.
Debt and equity securities not classified as either held-to-maturity
securities or trading securities are classified as available-for-sale
securities and reported at fair value, with unrealized gains and losses
excluded from earnings and reported as a separate component of stockholders'
equity.
At December 31, 1994, 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
institutions which hold the investments.
WELL, RESOURCE DEVELOPMENT AND EXPLORATION COSTS
The Company follows the full cost method of accounting for costs
incurred in connection with the exploration and development of
geothermal resources. All such costs, which include dry hole costs and
the cost of drilling and equipping production wells, as well as
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 years each; 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. For purposes of current period visibility and disclosure,
all such costs are identified in the Consolidated Statements of Cash
Flows as they are incurred.
DEFERRED WELL AND REWORK COSTS
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs of $733 and $1,305 at December
31, 1994 and 1993, respectively, are included in other assets.
Currently, both production and injection well reworks are amortized
over twelve months.
FIXED ASSETS 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 plants is computed on the
straight-line method over the estimated useful lives resulting in a
composite rate of depreciation of approximately 2.67% per annum.
Depreciation of equipment, which is 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.
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. Loan fees are amortized using the implicit interest method;
other deferred financing costs are amortized using the straight-line
method. Accumulated amortization at December 31, 1994 and 1993 was
approximately $3,848 and $1,954, respectively.
REVENUE RECOGNITION
Revenues are recorded based upon service rendered and electricity and
steam delivered to the end of the month.
MANAGEMENT FEE AND INTEREST REVENUE RECOGNITION
The Company charges the Coso Joint Ventures management fees, operator
fees and interest on outstanding advances. Recognition of fees and
interest relating to power plants and resource development of the Coso
Joint Ventures in which the Company has invested was deferred until
each Coso Joint Venture commenced operations. Revenue previously
deferred is amortized over the lives of the related assets of the Coso
Joint Ventures.
DEFERRED INCOME TAXES
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standard No. 109 ("FAS 109"), "Accounting for Income
Taxes". The adoption of FAS 109 changes the Company's method of
accounting for income taxes from the deferred method as required by
Accounting Principles Board Opinion No. 11 to an asset and liability
approach.
NET INCOME PER COMMON SHARE
Earnings per common share are based on the weighted average number of
common and dilutive common equivalent shares outstanding during the
period computed using the treasury stock method.
CASH FLOWS
The statement of cash flows classifies changes in cash according to
operating, investing, or financing activities. Investing activities
include capital expenditures incurred in connection with the power
plants, wells, resource development, and exploration costs. The
Company considers all investment instruments purchased with a maturity
of three months or less to be cash equivalents. Restricted cash is not
considered a cash equivalent.
RECLASSIFICATION
Certain amounts in the fiscal 1993 and 1992 financial statements and
supporting footnote disclosures have been reclassified to conform to
the fiscal 1994 presentation. Such reclassification did not impact
previously reported net income or retained earnings.
3. INTEREST RATE SWAP AGREEMENTS
In January 1993, the Coso Joint Ventures entered into five year
deposit interest rate swap agreements. The subject deposits represent
debt service reserves established in conjunction with refinancing the
Coso Joint Ventures loans through Coso Funding Corp. The deposit
interest rate swaps effectively convert interest earned on the debt
service reserve deposits from a variable rate to a fixed rate, in
order to match the nature of the interest rate on the borrowings used
to fund the debt service reserve deposits. The Company's proportion of
the deposit amount of $23,723 included in restricted cash and
investments accretes annually to a maximum amount of approximately
$29,300 in 1996. Under the agreements, which mature on January 11,
1998, the Coso Joint Ventures make semi-annual payments to the counter
party at variable rates based on LIBOR, reset and compounded every
three months, and in return receive payments based on a fixed rate of
6.34%. The effective LIBOR rate ranged from 3.375% to 4.4375% during
1994 and was 4.4375% at December 31, 1994. The counter party to these
agreements is a large multi-national financial institution. The
Company's proportionate share of the carrying amount, representing
accrued interest receivable, and the fair value of the swap
agreements, which, hypothetically assumes the Company closes out the
swap agreements prior to the stated maturity, are $110 and a negative
amount of $1,279, respectively. The fair value at December 31, 1993
was $1,281. The fair value is based on quoted market prices provided
by the counter party to the swap. It is the Company's intention to
hold the swap agreements to their stated maturity.
In September 1993, the Company entered into a three year deposit
interest rate swap agreement, which effectively converts a notional
deposit balance of $75,000 from a variable rate to a fixed rate. The
Company makes semi-annual payments to the counter party at effectively
the LIBOR rate, reset every six months, and in return receives
payments based on a fixed rate of 4.87%. The counter party to this
agreement is the same counter party to the Coso Joint Ventures. The
carrying amount is a negative $453, representing accrued interest. The
fair value of the interest rate swap is currently negative in the
amount of $5,347 which is based on quoted market prices provided by
the counter party to the swap and hypothetically assumes the Company
closes out the swap agreement prior to the stated maturity. The fair
value at December 31, 1993 was negative in the amount of $642 It is
the Company's intention to hold the swap agreement to its stated
maturity.
4. PROPERTIES AND PLANTS
Properties and plants comprise the following at December 31:
1994 1993
Operating project costs:
Power plants $314,027 $246,219
Wells and resource development 174,651 162,776
Total operating facilities 488,678 408,995
Less accumulated depreciation and amortization (90,457) (69,823)
Net operating facilities 398,221 339,172
Wells and resource development in progress 434 939
Total project costs 398,655 340,111
Upper Mahiao construction in progress 48,554 ---
Mahanagdong construction in progress 21,443 ---
Other international development 2,445 ---
Pacific Northwest geothermal exploration costs 46,620 41,910
Nevada and Utah properties 39,275 35,492
Yuma - construction in progress --- 41,461
Total $556,992 $458,974
OPERATING FACILITIES
The Coso operating facilities comprise the Company's proportionate
share of the assets of three of its Joint Ventures; Coso Finance
Partners (Navy I Joint Venture), Coso Energy Developers (BLM Joint
Venture), and Coso Power Developers (Navy II Joint Venture). With
respect to the Coso Project, distributions from its project control
accounts are made semi-annually to each Coso Joint Venture partner for
profit sharing under a prescribed calculation subject to mutual
agreement by the partners and compliance with the Coso Joint Ventures'
financing documents. As a result of the December 31, 1994 distribution
date falling on a non-banking day, the year end 1994 distributions
occurred on January 3, 1995.
NAVY I PLANT
The Navy I Plant consists of three turbines, of which one unit
commenced delivery of firm power in August 1987, and the second and
third units in December 1988. The 80 NMW Plant is located on land
owned by and leased from the U.S. Navy to December 2009, with a 10
year extension at the option of the Navy. Under terms of the Navy I
Joint Venture, profits and losses are allocated approximately 49%
before payout of Units 2 and 3 and approximately 46.4% thereafter to
the Company. Profits and losses before and after payout of Unit 1 are
allocated 46.19% and 46.49%, respectively. As of December 31, 1994,
payout had been reached on Units 2 and 3 of the Navy I Plant.
BLM PLANT
The BLM Plant consists of two turbines at one site (BLM East), which
commenced delivery of firm power in March and May, 1989, respectively,
and one turbine at another site (BLM West) which commenced delivery of
firm power in August, 1989. The BLM Plant is situated on lands leased
from the U.S. Bureau of Land Management under a geothermal lease
agreement that extends until October 31, 2035. The lease may be
extended to 2075 at the option of the BLM. Under the terms of the BLM
Joint Venture agreement, the Company's share of profits and losses
before and after payout is approximately 45% and 48%, respectively.
The BLM Plant reached payout in June 1994.
NAVY II PLANT
The Navy II Plant consists of three turbines, of which two units
commenced delivery of firm power in January 1990, and the third in
February 1990, respectively. The 80 NMW Plant is located on the
southern portion of the Navy lands. Under terms of the Joint Venture,
all profits, losses and capital contributions for Navy II are divided
equally by the two partners.
SIGNIFICANT CUSTOMER
All of the Company's sales of electricity from the Coso Project, which
comprise approximately 89% of 1994 electricity and steam revenues, are
to Southern California Edison ("SCE") and are under long-term power
purchase contracts. Under the terms of these contracts, SCE pays firm
prices for the energy portion of the contract. The energy payment
escalates pursuant to the contracts at an average rate of
approximately 7.0% per year for the delivery of electricity for ten
years, commencing with the initial delivery of electricity at firm
power; thereafter, the energy payment adjusts to the actual avoided
energy cost experienced by SCE at that time. While SCE's future
avoided energy cost is not presently determinable, it is currently
substantially below the current contract energy prices. The capacity
payment remains fixed during the entire period of the contract. In
addition, the Company is eligible for bonus payments based on the
amount by which the actual output exceeds the contract capacity of
each power plant. Bonus payments aggregated $3,078, $3,050 and $3,257
in the years ended December 31, 1994, 1993 and 1992.
The Company has three contracts for terms of 24, 30 and 20 years,
expiring in 2011, 2019 and 2010, respectively. Delivery of electricity
by the Navy I Joint Venture, the BLM Joint Venture, and Navy II Joint
Venture commenced under those contracts in 1987, 1989 and 1990,
respectively.
ROYALTIES
Royalties comprise the following for the years ended:
1994 1993 1992
Navy I, Unit I $1,641 $1,556 $2,014
Navy I, Units 2 and 3 3,174 2,924 2,628
BLM 2,842 1,868 1,268
Navy II 1,963 1,717 1,509
Other 268 209 291
Total $9,888 $8,274 $7,710
The amount of royalties paid by the Company 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 SCE for
specified quantities of electricity and the price as determined under
the contract (which currently approximates 71% of that paid by the
Navy to SCE), and (ii) $11,600 payable in December 2009. The $11,600
payment is secured by funds placed on deposit monthly, which funds,
plus accrued interest, will aggregate $11,600. The monthly deposit is
currently $23. As of December 31, 1994, the balance of funds deposited
approximated $1,613, which amount is included in restricted cash and
accrued liabilities.
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.
YUMA PROJECT
During 1992, the Company acquired a development stage 50 MW natural
gas-fired cogeneration project in Yuma, Arizona (the "Yuma Project").
The Yuma Project is designed to be a Qualifying Facility ("QF") under
PURPA and to provide 50 MW of electricity to San Diego Gas & Electric
Company ("SDG&E") under an existing 30-year power purchase contract.
The electricity is sold at SDG&E's avoided cost of energy. The power
is wheeled to SDG&E over transmission lines constructed and owned by
Arizona Public Service Company ("APS"). An agreement for
interconnection and a firm transmission service agreement have been
executed between APS and the Yuma Project entity and have been
accepted for filing by the Federal Energy Regulatory Commission.
The Yuma Project commenced commercial operation in May 1994. The
project entity has executed steam sales contracts with an adjacent
industrial entity to act as its thermal host in order to maintain its
status as a QF, which is a requirement of its SDG&E contract. Since
the industrial entity has the right under its contract to terminate
the agreement upon one year's notice if a change in its technology
eliminates its need for steam, and in any case to terminate the
agreement at any time upon three years' notice, there can be no
assurance that the Yuma Project will maintain its status as a QF.
However, if the industrial entity terminates the agreement, the
Company anticipates that it will be able to locate an alternative
thermal host in order to maintain its status as a QF or build a
greenhouse at the site for which the Company believes it would obtain
QF status. A natural gas supply and transportation agreement has been
executed with Southwest Gas Corporation, terminable under certain
circumstances by the Company and Southwest Gas Corporation.
PACIFIC NORTHWEST GEOTHERMAL EXPLORATION COSTS
In the Pacific Northwest, the Company has acquired leasehold rights
and has performed certain geological evaluations to determine the
resource potential of the underlying properties. Recovery of those
costs is ultimately dependent upon the Company's ability to prove
geothermal reserves and sell geothermal steam, or to obtain financing,
build power plants, gain access to high voltage transmission lines,
and sell the resultant electricity at favorable prices or, sell its
leaseholds. In the opinion of management, the Company will be able to
recover its exploration costs through the generation of electricity
for sale. In September 1994, the Company executed the Final Power
Purchase Agreements with Bonneville Power Administration and Eugene
Water and Electric Board for a 30 MW geothermal pilot project planned
to be constructed at the Newberry site near Bend, Oregon. The purchase
contracts are for 50 years and the project is currently scheduled to
be operational in 1997.
NEVADA AND UTAH PROPERTIES
On May 3, 1990, the Company entered into a definitive purchase
agreement with a subsidiary of Chevron Corporation ("Chevron") for the
acquisition of certain geothermal operations, including interests in
approximately 83,750 acres of geothermal properties in Nevada and
Utah, for an aggregate purchase price of approximately $51,100. These
property interests consist largely of leasehold interests, including
properties leased from the BLM and from private landowners.
The property acquired from Chevron includes a 10 MW power plant at
Desert Peak, Nevada ("Desert Peak"), and a 70% interest in a steam
field at Roosevelt Hot Springs, Utah ("Roosevelt Hot Springs"). The
facility at Desert Peak is currently selling electricity to Sierra
Pacific Power Company under a contract that runs through 1995 and then
may be extended on a year-to-year basis if agreed to by both parties.
The price for electricity under this contract is 6.5 cents per kWh,
comprising an energy payment of 2.0 cents per kWh (which is adjustable
pursuant to an inflation based index) and a capacity payment of 4.5
cents per kWh. The Roosevelt Hot Springs site has a contract to sell
steam to a 25 MW power plant owned by Utah Power and Light Company
("UP&L") and to dispose of the brine that is a by-product of the
electricity production process. The Company financed a portion of the
acquisition of Roosevelt Hot Springs through a $20,317 pre-sale of
steam from the Roosevelt Hot Springs field to the utility-owned power
plant located at the site, and seller financing.
As part of the Nevada and Utah properties acquisition, the Company
acquired leasehold interests in an aggregate of approximately 20,000
acres at the Roosevelt Hot Springs site in Utah and approximately
63,750 acres at four sites in Nevada. The Roosevelt Hot Springs and
Desert Peak properties have been the subject of exploration and
testing by Chevron and its predecessors. Based on these tests and
reports of independent engineering companies, the Company believes
that there are significant geothermal resources available for
commercial development at these sites. Other tests conducted by
Chevron and its predecessors indicate that commercially viable amounts
of geothermal resources may underlie the other Chevron properties.
5. PROJECT LOANS
Project loans, which are non-recourse to the Company, comprise the
following at December 31:
1994 1993
PROJECT LOANS with fixed interest rates (weighted average interest
rates of 8.13% and 8.04% at December 31, 1994 and 1993,
respectively) with scheduled
repayments through December 2001 $233,080 $ 246,880
The project loans are from Coso Funding Corp. ("Funding Corp.").
Funding Corp. is a single-purpose corporation formed to issue notes
for its own account and as an agent acting on behalf of Navy I, BLM,
and Navy II Joint Ventures, collectively the "Coso Joint Ventures".
Pursuant to separate credit agreements executed between Funding Corp.
and each Coso Joint Venture on December 16, 1992, the proceeds from
Funding Corp.'s note offering were loaned to the Coso Joint Ventures.
The proceeds of $560,245 were used by the Coso Joint Ventures to (i)
purchase and retire project finance debt comprised of the term loans
and construction loans in the amount of $424,500, (ii) fund
contingency funds in the amount of $68,400, (iii) fund debt service
reserve funds in the amount of $40,000, and (iv) finance $27,345 of
capital expenditures and transaction costs. The contingency fund and
debt service reserve fund were required by the project loan
agreements.
The contingency fund represented the approximate maximum amount, if
any, which could theoretically have been payable by the Coso Joint
Ventures to third parties to discharge all liens of record and other
contract claims encumbering the Coso Joint Ventures' plants at the
time of the project loans. The contingency fund was established in
order to obtain investment-grade ratings to facilitate the offer and
sale of the notes by Funding Corp., and such establishment did not
reflect the Coso Joint Ventures' view as to the merits or likely
disposition of such litigation or other contingencies. On June 9,
1993, MPE and the Mission Power Group, subsidiaries of SCECorp., and
the Coso Joint Ventures reached a final settlement of all of their
outstanding disputes and claims relating to the construction of the
Coso Project. As a result of the various payments and releases
involved in such settlement, the Coso Joint Ventures agreed to make a
net payment of $20,000 to MPE from the cash reserves of the Coso
Project contingency fund and MPE agreed to release its mechanics'
liens on the Coso Project. After making the $20,000 payment, the
remaining balance of the Coso Project contingency fund (approximately
$49,300) was used to increase the Coso Project debt reserve fund from
approximately $43,000 to its maximum fully-funded requirement of
$67,900. The remaining $24,400 balance of contingency fund was
retained within the Coso Project for future capital expenditures and
for Coso Project debt service payments. Since the Coso Project debt
service reserve is fully funded in advance, Coso Project cash flows
otherwise intended to fund the Coso Project debt service reserve fund,
subject to satisfaction of certain covenants and conditions contained
in the Coso Joint Ventures' refinancing documents, may be available
for distribution to the Company in its proportionate share.
The loans are collateralized by, among other things, the power plants,
geothermal resource, debt service reserve funds, contingency funds,
pledge of contracts, and an assignment of all such Coso Joint
Ventures' revenues which will be applied against the payment of
obligations of each Coso Joint Venture, including the project loans.
Each Coso Joint Venture's assets will secure only its own project
loan, and will not be cross-collateralized with assets pledged under
other Coso Joint Venture's credit agreements. The project loans are
non-recourse to any partner in the Coso Joint Ventures and Funding
Corp. shall solely look to such Coso Joint Venture's pledged assets
for satisfaction of such project loans. However, the loans are
cross-collateralized by the available cash flow of each Coso Joint
Venture. Each Coso Joint Venture after satisfying a series of its own
obligations has agreed to advance support loans (to the extent of
available cash flow and, under certain conditions, its debt service
reserve funds) in the event revenues from the supporting Coso Joint
Ventures are insufficient to meet scheduled principal and interest on
their separate project loans.
The Company's share of annual repayments of the project loans for the
years beginning January 1, 1995 and thereafter are as follows:
1995 $ 45,908
1996 38,826
1997 41,729
1998 38,912
1999 31,717
Thereafter 35,988
$233,080
Based on quoted market rates of the Funding Corp. notes, the fair
value of the Company's share of the project loan was approximately
$227,144 and $260,276 at December 31, 1994 and 1993, respectively.
6. CONSTRUCTION LOANS
The construction loans which are non-recourse to the Company, comprise
the following at December 31, 1994:
1994
UPPER MAHIAO CONSTRUCTION LOAN with variable interest rates (weighted
average interest rate of 8.6%) with scheduled repayments through 2006 $24,508
MAHANAGDONG CONSTRUCTION LOAN with variable interest rates (weighted average
interest rate of 8.4%) with scheduled repayments through 2007 6,995
$ 31,503
Draws on the construction loan and accrued liabilities for the Upper
Mahiao geothermal power project at December 31, 1994 totalled $24,508
and $10,278, respectively. The Project will have a total project cost
of approximately $218,000, including capitalized interest during
construction, project contingency costs and a debt service reserve
fund. The Company's equity contribution to the project is $56,000. A
syndicate of international commercial banks is providing the
construction financing with interest rates at LIBOR or "Prime" with
interest payments due the earlier of every quarter and LIBOR maturity.
The Export-Import Bank of the U.S. ("Ex-Im Bank") is providing
political risk insurance to commercial banks on the construction loan
and will provide the majority of the project term financing of
approximately $162,000 upon satisfaction of the conditions associated
with commercial operation. The term financing from the Ex-Im Bank will
be for a ten-year term at a fixed interest rate of 5.95%. The term
loan will be amortized in approximately equal quarterly principal
payments over the term of the loan. The fair value of the construction
loan approximates the current loan balance. The covenants on the
construction loan are standard for loans of this type. The accrued
liabilities represent invoices which were received, but not paid, by
December 31, 1994 and retention on the construction and supply
contracts.
The Company's share of draws on the construction loan and accrued
liabilities for the Mahanagdong geothermal power project at December
31, 1994 totalled $6,995 and $5,603 respectively. The project will
have a total project cost of approximately $320,000, including
interest during construction, project contingency costs and a debt
service reserve fund. The capital structure consists of a term loan of
$240,000 and approximately $80,000 in equity contributions. The
Company's equity contribution to the project is $40,000. The
construction debt financing is provided by the Overseas Private
Investment Corporation ("OPIC") and a consortium of commercial lenders
led by Bank of America NT&SA. The construction loan interest rates are
at LIBOR or "Prime" with interest payments due the earlier of
quarterly and LIBOR maturity. The debt provided by the commercial
lenders will be insured by the Export-Import Bank of the U.S. ("Ex-Im
Bank") against political risks. Ten-year term debt financing, of which
the Company's share is approximately $120,000, will be provided by
Ex-Im Bank (which will replace the bank construction debt) and by
OPIC. The majority of the term financing is expected to be provided by
the Ex-Im Bank at a fixed interest rate of 6.92%. The term loan will
be amortized in approximately equal quarterly principal payments over
the term of the loan. The fair value of the construction loan
approximates the current loan balance. The covenants on the
construction loan are standard for loans of this type. The accrued
liabilities represent invoices which were received, but not paid, by
December 31, 1994 and retention on the construction and supply
contracts.
7. SENIOR DISCOUNT NOTES
In March 1994, the Company issued $400,000 of 10 1/4% Senior Discount
Notes which accrete to an aggregate principal amount of $529,640 at
maturity in 2004. The original issue discount (the difference between
$400,000 and $529,640) will be amortized from issue date through
January 15, 1997, during which time no cash interest will be paid on
the Senior Discount Notes. Commencing July 15, 1997, cash interest on
the Senior Discount Notes will be payable semiannually on January 15
and July 15 of each year. The Senior Discount Notes are redeemable at
any time on or after January 15, 1999. The redemption prices
commencing in the twelve month period beginning January 15, 1999
(expressed in percentages of the principal amount) are 105.125%,
103.417%, 101.708%, and 100% for 1999, 2000, 2001, and 2002,
respectively, plus accrued interest through the redemption date in
each case. The Senior Discount Notes are unsecured senior obligations
of the Company. The fair value of the Senior Discount Notes as of
December 31, 1994 was approximately $413,013, which is based on quoted
market rates.
8. SENIOR NOTES
The Company's Senior Notes in the principal amount of $35,730 which
were due in March 1995, together with the fixed 12% interest due
thereon, were defeased in the first quarter of 1994 in conjunction
with the issuance of the Senior Discount Notes. The 1994 contingent
interest component of these Senior Notes, calculated by reference to
the Company's share of available cash flow from the Coso Project,
remained undefeased and outstanding through the end of the calculation
period, December 31, 1994.
9. CONVERTIBLE SUBORDINATED DEBENTURES
In June of 1993, the Company issued $100,000 principal amount of 5%
Convertible Subordinated Debentures due July 31, 2000. The Convertible
Subordinated Debentures are convertible into shares of the Company's
common stock at any time prior to redemption or maturity at a
conversion price of $22.50 per share, subject to adjustment in certain
circumstances. Interest on the Convertible Subordinated Debentures is
payable semi-annually in arrears on July 31 and January 31 of each
year, commencing on July 31, 1993. The Convertible Subordinated
Debentures are redeemable for cash at any time on or after July 31,
1996 at the option of the Company. The redemption prices commencing in
the twelve month period beginning July 31, 1996 (expressed in
percentages of the principal amount) are 102%, 101%, 100% and 100% in
1996, 1997, 1998 and 1999, respectively. The Convertible Subordinated
Debentures are unsecured general obligations of the Company and
subordinated to all existing and future senior indebtedness of the
Company. The fair value of the Convertible Subordinated Debentures as
of December 31, 1994 and 1993 was approximately $82,300 and $103,250,
respectively, which is based on quoted market rates.
10. INCOME TAXES
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standard No. 109 ("FAS 109"), "Accounting for Income
Taxes". The adoption of FAS 109 changed the Company's method of
accounting for income taxes from the deferred method as required by
Accounting Principles Board Opinion No. 11 to an asset and liability
approach. Under FAS 109, the net excess deferred tax liability as of
January 1, 1993 was determined to be $4,100. This amount was reflected
in 1993 income as the cumulative effect of a change in accounting
principle. It primarily represents the recognition of the Company's
tax credit carryforwards as a deferred tax asset. There was no cash
impact to the Company upon the required adoption of FAS 109. Under FAS
109, the effective tax rate increased to approximately 30% in 1993
from 23.5% in 1992. This increase was due to the Company's tax credit
carryforward being recognized as an asset and unavailable to reduce
the effective tax rate for computing the Company's provision for
income taxes after 1992.
Provision for income tax is comprised of the following for the years
ended December 31:
1994 1993 1992
Currently payable:
State $ 1,970 $ 3,300 $ 2,300
Federal 5,829 7,686 4,444
7,799 10,986 6,744
Deferred:
State 1,017 385 1,607
Federal 7,241 6,813 2,038
8,258 7,198 3,645
Total after benefit of
extraordinary item 16,057 18,184 10,389
Tax benefit attribute to
extraordinary item 945 --- 1,533
Total before benefit of
extraordinary item $17,002 $18,184 $11,922
The deferred expense is primarily temporary differences associated
with depreciation and amortization of certain assets.
A reconciliation of the federal statutory tax rate to the effective
tax rate applicable to income before provision for income taxes
follows:
1994 1993 1992
Federal statutory rate 35.00% 35.00% 34.00%
Percentage depletion in excess of
cost depletion (6.85) (6.70) (6.81)
Investment and energy tax credits (3.04) (4.62) (10.52)
State taxes, net of federal tax
effect 4.48 3.90 5.83
Cumulative effect of change in
federal tax rate --- 1.90 ---
Other .86 .20 1.00
30.45% 29.68% 23.50%
Deferred tax liabilities (assets) are comprised of the following at
December 31:
1994 1993
Depreciation and amortization, net $119,947 $111,117
Other 3,590 1,733
123,537 112,850
Deferred income (2,190) (2,415)
Loss carryforwards (31,592) (39,529)
Energy and investment tax credits (40,748) (40,106)
Alternative minimum tax credits (22,379) (12,018)
Other (60) (472)
(96,969) (94,540)
Net deferred taxes $ 26,568 $ 18,310
As of December 31, 1994, the Company has an unused net operating loss
(NOL) carryover of approximately $90,262 for regular federal tax
return purposes which expires primarily between 2003 and 2007. In
addition, the Company has unused investment and geothermal energy tax
credit carryforwards of approximately $40,748 expiring between 2002
and 2009. The Company also has approximately $22,379 of alternative
minimum tax credit carryforwards which have no expiration date.
11. PREFERRED STOCK
Series A:
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-hundredth of a
share of Series A junior preferred stock for $52. The rights may be
redeemed by the Board of Directors up to ten days after an event
triggering the distribution of certificates for the rights. The rights
plan was amended in February 1991 so that the agreement with Kiewit
Energy (see Note 13) would not trigger the exercise of the rights. The
rights will expire, unless previously redeemed or exercised, on
November 30, 1998. The rights are automatically attached to, and trade
with, each share of common stock.
Series B:
On November 15, 1990, the Company sold 357.5 shares of convertible
preferred stock, Series B at $14 per share. Each share of the
convertible preferred stock was convertible into two shares of common
stock, and had a dividend rate of 15% through November 15, 1992, 10%
from November 16, 1992 to November 15, 1994 and 5% from November 16,
1994 to November 15, 1996. The dividends were payable semi-annually in
convertible preferred stock, Series B.
On November 15, 1992, the Company called the preferred stock for
conversion into common stock. Each Series B preferred stock was
converted into two shares of common stock; accordingly, the Company
issued 954.9 shares of common stock.
Series C:
On November 19, 1991, the Company sold one thousand shares of
convertible preferred stock, Series C at $50,000 per share to Kiewit
Energy, in a private placement. Each share of the Series C preferred
stock is convertible at any time at $18.375 per common share into two
thousand seven hundred and twenty-one shares of common stock subject
to customary adjustments. The Series C preferred stock has a dividend
rate of 8.125%, commencing March 15, 1992 through conversion date or
December 15, 2003. The dividends, which are cumulative, are payable
quarterly in convertible preferred stock, Series C, through March 15,
1995 and in cash on subsequent dividend dates.
The Company is obligated to redeem 20% of the outstanding preferred
stock, Series C each December 15, commencing 1999 through 2003 at a
price per share equal to $50,000, plus accrued and unpaid dividends.
At any time after December 15, 1994, upon 20 days written notice, the
Company may redeem all, or any portion consisting of at least $5,000,
of the preferred stock, Series C, then outstanding, provided that the
Company's common stock has traded at or above 150% of the then
effective conversion price, for any 20 trading days out of 30
consecutive trading days ending not more than five trading days prior
to notice of redemption.
The Company may also exchange the preferred stock, Series C, in whole
or part on any dividend date commencing December 15, 1994, for 9.5%
convertible subordinated debentures of the Company due 2003. On March
15, 1995, the Company intends to exchange the Series C preferred stock
for the convertible subordinated debentures.
Each share of preferred stock, Series C shall be entitled to the
number of votes equal to $50,000 per share divided by the then
effective conversion price. If cash dividends are in arrears six
consecutive quarters, Kiewit Energy shall have the exclusive right,
voting separately as a class, to elect two directors of the Company.
No cash dividends shall be paid or declared on the Company's common
stock unless all accumulated dividends on the Series C preferred stock
have been paid.
12. STOCK OPTIONS AND WARRANTS
The Company has issued various stock options and warrants. As of
December 31, 1994, a total of 9,687 shares are reserved for stock
options, of which 9,601 shares have been granted and remain
outstanding at prices of $3.00 to $19.00 per share.
STOCK OPTIONS
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. As of December 31, 1994, the total options
granted for the non-1986 plan and the 1986 plan are 6,067 and 7,308,
respectively. 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 1986 Plan become exercisable over a period of three to five
years and expire if not exercised within ten years from the date of
grant or, in some instances a lesser term. Prior to the 1986 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 1986 Plan. The
non-1986 plan options are primarily options granted to Kiewit Energy;
see Note 13.
TRANSACTIONS IN STOCK OPTIONS
OPTIONS OUTSTANDING
SHARES
AVAILABLE
FOR GRANT
UNDER 1986
OPTION OPTION PRICE
PLAN SHARES PER SHARE TOTAL
Balance, January 1, 1992 1,238 8,970* $3.00 - $14.875 $83,670
Options granted (551) 751 $11.90 - $15.938 11,262
Options terminated 129 (780) $3.00 - $11.625 (7,839)
Options exercised --- (1,544) $3.00 - $11.625 (7,072)
Balance December 31, 1992 816 7,397* $3.00 - $15.938 80,021
Options granted (1,396) 1,396 $17,75 - $19,00 26,209
Options terminated 19 (20) $2.00 - $14.875 (114)
Options exercised --- (259) $3.00 - $14.875 (1,185)
Additional shares reserved
under 1986 Options Plan 1,000 --- --- ---
Balance December 31, 1993 439 8,514* $3.00 - $19.00 $104,931
Options granted (954) 1,243 $16.00 - $17.25 19,260
Options terminated 15 (15) $3.00 - $15.938 (205)
Options exercised --- (141) $3.00 - $15.938 (709)
Additional shares reserved
under 1986 Options Plan 586 --- --- ---
Balance December 31, 1994 86 9,601* $3.00 - $19.00 $123,277
Options which became exercisable during:
Year ended December 31, 1994 1,015 $11.625 - $19.00 $15,776
Year ended December 31, 1993 592 $3.00 - $19.00 $10,180
Year ended December 31, 1992 333 $3.00 - $15.938 $ 3,693
Options exercisable at:
December 31, 1994 7,897* $3.00 - $19.00 $93,705
December 31, 1993 7,026* $3.00 - $19.00 $78,644
December 31, 1992 6,708* $3.00 - $15.938 $69,739
*Includes Kiewit Energy options. See Note 13.
WARRANTS
The Company has granted warrants in connection with various financing
activities to purchase shares of common stock as follows:
WARRANTS OUTSTANDING
PRICE
WARRANT PER
SHARES SHARE TOTAL
Balance, January 1, 1992 1,889 $2.04 $ 3,853
Warrants exercised (612) $2.04 (1,247)
Warrants repurchased (1,277) $2.04 (2,606)
Balance December 31, 1992 --- $ ---
On October 13, 1992, the Company repurchased, and cancelled, certain
warrants exercisable for 1,025 shares of unregistered common stock at
$2.04 per share, for a purchase price of $9.16 per share or $9,389 in
aggregate. Separately, Kiewit Energy simultaneously purchased and
exercised other warrants to purchase 600 shares of unregistered common
stock at $2.04 per share, providing the Company with proceeds of $1,224.
On October 27, 1992, the Company repurchased, and cancelled, certain
warrants exercisable for 250 shares of unregistered common stock at $2.04
per share, for a purchase price of $9.316 per share or $2,329 in
aggregate.
13. COMMON STOCK SALES & RELATED OPTIONS
The Company and Kiewit Energy signed a Stock Purchase Agreement and
related agreements, dated as of February 18, 1991. Kiewit Energy is a
subsidiary of Peter Kiewit Sons', Inc. of Omaha, Nebraska, a large
construction, mining, and telecommunications company with diversified
operations. Under the terms of the agreements, Kiewit Energy purchased
4,000 shares of common stock at $7.25 per share and received options to
buy 3,000 shares at a price of $9 per share exercisable over three years
and an additional 3,000 shares at a price of $12 per share exercisable
over five years (subject to customary adjustments).
In May 1994, pursuant to a special antidilution provision of the 1991
Stock Purchase Agreement between the Company and Kiewit Energy, the
Company increased Kiewit Energy's existing option (granted in 1991) to
purchase 3,000 shares at $12 per share by an additional 289 shares as a
final adjustment under such provisions.
In connection with this initial stock purchase, the Company and Kiewit
Energy also entered into certain other agreements pursuant to which (i)
Kiewit Energy and its affiliates agreed not to acquire more than 34% of
the outstanding common stock (the "Standstill Percentage") for a five-year
period, (ii) Kiewit Energy became entitled to nominate at least three of
the Company's directors, and (iii) the Company and Kiewit Energy agreed to
use their best efforts to negotiate and execute a joint venture agreement
relating to the development of certain geothermal properties in Nevada and
Utah.
On June 19, 1991, the board approved a number of amendments to the Stock
Purchase Agreement and the related agreements. Pursuant to those
amendments, the Company reacquired from Kiewit Energy the rights to
develop the Nevada and Utah properties, and Kiewit Energy agreed to
exercise options to acquire 1,500 shares of common stock at $9.00 per
share, providing the Company with $13,500 in cash. The Company also
extended the term of the $9.00 and $12.00 options to seven years; modified
certain of the other terms of these options; granted to Kiewit Energy an
option to acquire an additional 1,000 shares of the outstanding common
stock at $11.625 per share (closing price for the shares on the American
Stock Exchange on June 18, 1991) for a ten year term; and increased the
Standstill Percentage from 34% to 49%.
On November 19, 1991, the Board approved the issuance by the Company to
Kiewit Energy of one thousand shares of Series C preferred stock for
$50,000, as described in Note 11 above. In connection with the sale of the
Series C preferred stock to Kiewit Energy, the Standstill Agreement was
amended so that the 49% Standstill Percentage restriction would apply to
voting stock rather than just common stock.
14. LITIGATION
As of December 31, 1994 there were no material outstanding lawsuits.
15. RELATED PARTY TRANSACTIONS
The Company charged and recognized a management fee and interest on
advances to its Coso Joint Ventures, which aggregated approximately
$5,569, $5,354 and $4,246 in the years ended December 31, 1994, 1993 and
1992. The Company's note receivable from the Coso Joint Ventures bears a
fixed interest rate of 12.5% and is payable on or before March 19, 2002.
This note is subordinated to the senior project loan on the project. The
fair value of the note approximates its carrying value.
The Mahanagdong Project is being constructed by a consortium (the "EPC
Consortium") of Kiewit Construction Group, Inc. ("KCG") and the Ben Holt
Company ("BHCO"), a wholly owned subsidiary of the Company, pursuant to
fixed-price, date-certain, turnkey supply and construction contracts
(collectively, the "Mahanagdong EPC"). The obligations of the EPC
Consortium under the Mahanagdong EPC are supported by a guaranty of KCG at
an aggregate amount equal to approximately 50% of the Mahanagdong EPC
price. The Mahanagdong EPC provides for maximum liability for liquidated
damages of up to $100,500 and total liability of up to $201,000. KCG, a
wholly owned subsidiary of Peter Kiewit Sons', Inc. ("PKS"), is the lead
member of the EPC Consortium, with an 80% interest, KCG performs
construction services for a wide range of public and private customers in
the U.S. and internationally. BHCO will provide design and engineering
services for the EPC Consortium, and holds a 20% interest. The Company has
provided a guaranty of BHCO's obligations under the Mahanagdong EPC
Contract.
The Company participates in an international joint venture agreement with
PKS which the Company believes enhances its capabilities in foreign power
markets. The joint venture agreement is limited to international
activities and provides that if both the Company and PKS agree to
participate in a project, they will share all development costs equally.
Each of the Company and PKS will provide 50% of the equity required for
financing a project developed by the joint venture and the Company will
operate and manage such project. The agreement creates a joint development
structure under which, on a project by project basis, the Company will be
the development manager, managing partner and/or project operator, and
equal equity participant and PKS will be the preferred turnkey
construction contractor. The joint venture agreement may be terminated by
either party on 15 days written notice, provided that such termination
cannot affect the pre-existing contractual obligations of either party.
16. EXTRAORDINARY ITEM
The refinancing of the Coso Joint Ventures' project financing debt in
1992 resulted in an extraordinary item in the amount of $4,991, after the
tax effect of $1,533. The extraordinary item represents the unamortized
portion of the deferred financing costs and related repayment costs
associated with the original Coso Joint Ventures' project financing debt.
In conjunction with the Company's Senior Discount Note offering (See Note
7), the 12% Senior Notes were defeased, resulting in an extraordinary item
in the amount of $2,007, after the income tax effect of $945. The
extraordinary item represents the amount necessary to defease the interest
payments and the unamortized portion of the deferred financing costs on
the $35,730 Senior Notes. The 1994 contingent interest component of these
Senior Notes, calculated by reference to the Company's share of available
cash flow from the Coso Project, remains undefeased and outstanding
through the end of the calculation period, December 31, 1994.
17. SUBSEQUENT EVENT (UNAUDITED)
The Company has acquired all of the outstanding equity interest in Magma
Power Company ("Magma") in a two-step transaction to be accounted for as a
purchase according to the terms of a merger agreement whereby on January
10, 1995, the Company acquired approximately 51% of the outstanding shares
of Magma common stock (the "Magma Common Stock") through a cash tender
offer (the "Magma Tender Offer") and on February 24, 1995 the Company
acquired the remaining 49% of Magma Common Stock not owned by the Company
through a merger (the "Merger"). Each outstanding share of Magma Common
Stock (other than shares of Magma Common Stock held by the Company, CE
Acquisition Company, Inc., a wholly owned subsidiary of the Company, or
any other direct or indirect subsidiary of the Company and shares of Magma
Common Stock held in the treasury of Magma) was converted into the right
to receive an average of approximately $38.75 per share of Magma Common
Stock. The Company paid the Merger consideration solely in cash, funded
with the net proceeds of a public common stock offering of 15,170 shares
(the "Offering") and the proceeds of a direct sale of 1,500 shares to
Peter Kiewit Sons', Inc. (the "Direct Sale") at $17.00 per share which
together netted $275,653, over-allotment proceeds of a $24,735 on the sale
of 1,500 shares, borrowings of $500,000 under bank credit facilities, and
general corporate funds of the Company. On February 10, 1995, the
Company's stockholders approved an increase in its authorized Common Stock
to 80,000 shares.Magma is engaged in independent geothermal power
operations and development activities similar to those of the Company.
The Magma Tender Offer was financed with a $245,600 facility from Credit
Suisse (the "Tender Facility"). Loans under the Tender Facility were made
to the Company on a non-recourse basis, secured by the Magma stock
acquired, and the Company lent the proceeds of such loans to Magma in
exchange for a secured term note of Magma (the "Tender Note"). The loans
under the Tender Facility were repaid from funds received from the Merger
Facilities.
A total of approximately $957,000 was required to refinance the Tender
Facilities and to complete the Magma Acquisition. Up to $500,000 in
secured bank financing was provided by Credit Suisse (the "Merger
Facilities") on specified terms and subject to customary conditions. Such
funds, together with the net proceeds of the Offering and over-allotment,
the proceeds of the Direct Sale and general corporate funds of the
Company, were used to complete the Magma Acquisition.
The Merger Facilities are comprised of (i) a six-year term loan ("Term
Loan A") in a principal amount of up to the difference between $500,000
and the principal amount of Term Loan B (as defined below), to be
amortized in semi-annual payments, and (ii) an eight-year term loan ("Term
Loan B") in a principal amount of $150,000, to be amortized in semi-annual
payments in the seventh and eighth years of such Term Loan. Loans under
the Merger Facilities were made to the Company on a non-recourse basis,
and the Company lent the proceeds of such loans to Magma in exchange for a
secured term note of Magma (the "Magma Note"). The loans under the Merger
Facilities will be amortized from payments received by the Company from
Magma on the Magma Note which is expected to be amortized from internally
generated funds of Magma. Loans under the Merger Facilities are secured by
an assignment and pledge by the Company of the Magma Note and 100% of the
capital stock of Magma. The Magma Note is secured by an assignment of
certain unencumbered assets of Magma.
Interest on loans under the Merger Facilities are payable at spreads of
2.50% above LIBOR (adjusted for reserves) or 1.50% above the Base Rate for
Term Loan A, and 3.00% above LIBOR (adjusted for reserves) or 2.00% above
the Base Rate for Term Loan B. The LIBOR spreads are subject to upward
adjustment in certain instances. The Company may elect to have loans bear
interest based on either LIBOR or the Base Rate (as defined in the Merger
Facilities).
The Merger Facilities contain affirmative and negative covenants
customary for similar non-recourse credit facilities. Such covenants
include a negative pledge of all stock and unencumbered assets of Magma; a
limitation on guaranties by Magma; a limitation on mergers and sales of
assets by Magma; a limitation on investments in other persons by Magma; a
prohibition on dividends and other payments by Magma to the Company unless
the proceeds are used to pay down the Merger Facilities; a prohibition on
the sale of ownership interests in Magma; a limitation on the incurrence
of additional debt by Magma; a requirement that the Company deliver each
fiscal quarter a certificate as to the absence of material adverse changes
in the Company or Magma which could reasonably be expected to materially
affect the ability of the Company to repay the Merger Facilities or the
ability of the lenders to realize on the collateral for the Merger
Facilities; and a restriction on a change in the nature of the business of
the Company and Magma.
The Merger Facilities also contain financial covenants and customary
events of default, including events of default based on breaches of
certain representations, warranties and covenants; cross defaults with
respect to certain debt of the Company and Magma; bankruptcy and similar
events; the failure to pay certain final judgments; the failure to make a
payment with respect to the Merger Facilities when due; and the failure of
the pledge agreement with respect to the capital stock of Magma and the
Magma Note to be in full force and effect.
The preliminary unaudited proforma combined condensed balance sheet of
the Company and Magma as if the acquisition had occurred on December 31,
1994 after giving effect to certain proforma adjustments is as follows:
ASSETS
Cash, restricted cash, short-term investments,
and marketable securities $ 408,622
Accounts receivable 58,122
Property and equipment, net 1,319,482
Notes receivable, deferred charges, and other assets 207,540
Excess of cost over fair value of net assets acquired 326,424
$2,320,190
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities $1,758,860
Deferred income 19,851
Redeemable preferred stock 63,600
Shareholders' equity 477,879
$2,320,190
The preliminary unaudited proforma combined results of operations of the
Company and Magma for the year ended December 31, 1994 as if the
acquisition had occurred at the beginning of the year, after giving effect
to certain proforma adjustments related to the acquisition and excluding
non-recurring costs incurred by Magma is as follows:
Revenue $ 368,887
Net income available to common stockholders $ 38,777
Net income per common share available to
common stockholders $ 0.72
During the fourth quarter of 1994, Magma provided reserves for certain
accounts receivable related to royalties. Excluding the effect of these
reserves, proforma net income available to common stockholders and
proforma net income per common share would have been $47,552 and $0.88,
respectively.
18. QUARTERLY FINANCIAL DATA (UNAUDITED)
Following is a summary of the Company's quarterly results of operations
for the years ended December 31, 1994 and December 31, 1993.
THREE MONTHS ENDED *
March 31, June 30, Sept. 30, Dec. 31,
1994 1994 1994 1994
Revenue:
Sales of electricity and steam $30,819 $36,850 $49,498 $37,395
Other income 4,591 8,404 9,026 9,271
Total revenue 35,410 45,254 58,524 46,666
Total costs and expenses 22,753 33,198 37,771 36,296
Income before provision for income
taxes 12,657 12,056 20,753 10,370
Provision for income taxes 4,050 3,677 6,340 2,935
Net income before extraordinary item 8,607 8,379 14,413 7,435
Extraordinary item (2,007) ----- ----- -----
Net income 6,600 8,379 14,413 7,435
Preferred dividends 1,200 1,236 1,275 1,299
Net income attributable to common
shares $ 5,400 $ 7,143 $13,138 $ 6,136
Net income per share before
extraordinary item $ 0.20 $ 0.20 $ 0.38 $ 0.18
Net income per share -
extraordinary item (0.06) ----- ----- -----
Net income per share $ 0.14 $ 0.20 $ 0.38 $ 0.18
THREE MONTHS ENDED *
March 31, June 30, Sept. 30, Dec. 31,
1993 1993 1993 1993
Revenue:
Sales of electricity and steam $ 27,617 $ 31,996 $ 41,433 $ 31,013
Other income 3,544 3,926 4,824 4,900
Total revenue 31,161 35,922 46,257 35,913
Total costs and expenses 20,314 21,833 22,087 23,761
Income before provision for income taxes
and change in accounting principle 10,847 14,089 24,170 12,152
Provision for income taxes 3,363 3,439 7,493 3,889
Net income before change in
accounting principle 7,484 10,650 16,677 8,263
Cumulative effect of change in
accounting principle 4,100 ----- ----- -----
Net income 11,584 10,650 16,677 8,263
Preferred dividends 1,107 1,143 1,179 1,201
Net income attributable to common shares $ 10,477 $ 9,507 $ 15,498 $ 7,062
Net income per share before change in
accounting principle $ .16 $ .25 $ .41 $ .18
Cumulative effect of change in
accounting principle per share .11 ----- ----- -----
Net income per share $ .27 $ .25 $ .41 $ .18
* The Company's operations are seasonal in nature with a disproportionate
percentage of income earned in the second and third quarters.
Independent Auditors' Report
Board of Directors and Shareholders
California Energy Company, Inc.
Omaha, Nebraska
We have audited the accompanying consolidated balance sheets of California
Energy Company, Inc. and subsidiaries as of December 31, 1994 and 1993, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1994. 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 California Energy Company, Inc.
and subsidiaries at December 31, 1994 and 1993 and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note 10, the consolidated financial statements give effect to
the Company's adoption, effective January 1, 1993, of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes".
Deloitte & Touche LLP
Omaha, Nebraska
February 3, 1995