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U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 0-14846
BONNEVILLE PACIFIC CORPORATION
(Exact Name of Registrant as specified in its charter)
Delaware 87-0363215
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification No.)
50 West 300 South, Suite 300
Salt Lake City, UT 84101
(Address of principal executive offices)
Registrant's telephone number, including area code: (801) 363-2520
Securities registered pursuant to Section 12(b) of the Exchange Act: None
Securities registered pursuant to Section 12(g) of the Exchange Act: $.01
Par Value Common Stock
Check whether the Registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days. Yes
No 4;
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [4]
As of March 15, 1999, 7,227,390 shares of the Registrant's common stock
were issued and outstanding of which 5,138,000 were held by non-affiliates. As
of March 15, 1999, the aggregate market value of shares held by non-affiliates
(based upon the closing price reported by the OTCBB Market System of $6.06) was
approximately $31,150,000.
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING PRECEDING FIVE YEARS
Indicate by check mark whether the Registrant has filed all documents and
reports required to be filed by Section 12,13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court. Yes 4; No
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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INDEX TO FORM 10-K
PART I.
Item 1. Business
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
PART III.
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
PART IV.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
Glossary
PART I
ITEM 1. DESCRIPTION OF BUSINESS
Except for historical financial information contained herein, the matters
discussed by Bonneville Pacific Corporation ("BPC") or its representatives in
this annual report may be considered forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended and subject to the safe
harbor created by the Securities Litigation Reform Act of 1995. Such statements
include declarations regarding the intent, belief or current expectations of the
Company and its management. Prospective investors are cautioned that any such
forward-looking statements are not guarantees of future performance and involve
a number of risks and uncertainties. Actual results could differ materially from
those indicated by such forward-looking statements. Among the important factors
that could cause actual results to differ materially from those indicated by
such forward-looking statements are: (i) that the information is of a
preliminary nature and may be subject to further adjustment, (ii) those risks
and uncertainties identified in this document including, but not limited to
those in Item 1. Description of Business and in Item 7. Management Discussion
and Analysis in this Form 10-K, risk that all or part of the business may be
sold, (iii) the possible unavailability of financing, (iv) risks related to the
development, acquisition and operation of power plants, (v) the impact of
avoided cost pricing, energy price fluctuations and gas price increases, (vi)
the uncertainties created by the proposed restructuring of the electrical
industry in Nevada; (vii) the impact of curtailment, (viii) the seasonal nature
of the Company's business, (ix) start-up risks, (x) general operating risks,
(xi) the dependence on third parties, (xii) risks associated with international
investments, (xiii) risks associated with the power marketing business, (xiv)
changes in government regulation, (xv) the availability of natural gas, (xvi)
the effects of competition, (xvii) the dependence on senior management, (xviii)
volatility in the Company's stock price, (xix) fluctuations in quarterly results
and seasonality, reserve replacement risk, dependence on exploratory and
development drilling risks, risks associated with reserve estimates,
marketability and price risks, operating hazards and uninsured risks,
technological change risk, and (xx) other risks identified from time to time in
the Company's reports and registration statements filed with the Securities and
Exchange Commission.
<PAGE>
GENERAL
Bonneville Pacific Corporation ("BPC") and its subsidiaries (collectively the
"Company") are diversified energy companies involved in various segments of the
energy business. BPC was formed in 1980 under the laws of the State of Utah and
was later reincorporated in Delaware. BPC's common stock was traded on NASDAQ
commencing in 1986 but was delisted by NASDAQ in 1992. On December 18, 1998, the
common stock of the Company was approved to be listed on the Over-the-Counter
Electronic Bulletin Board ("OTCBB"). The Company is based in Salt Lake City,
Utah and has assets, either through BPC or its subsidiaries, in several western
states and Mexico.
For a variety of reasons, as more fully described in the Disclosure Statement
filed with the SEC in Form 8K on May 1, 1998, and the Amended Disclosure
Statement filed on July 23, 1998, on December 5, 1991, BPC filed a petition in
bankruptcy and became a "Debtor-in-possession" under Chapter 11 of the United
States Bankruptcy Code (the "Code"). BPC was a Debtor-in-possession from
December 5, 1991 to June 12, 1992.
Subsequently, the Bankruptcy Court ordered the appointment of an independent
examiner and thereafter a Trustee for the bankruptcy estate of BPC. As a result,
on Friday, June 12, 1992, Roger G. Segal was appointed as the Chapter 11 trustee
for BPC's bankruptcy estate by the Office of the United States Trustee. That
appointment was approved by the Bankruptcy Court and the Trustee assumed control
of BPC on Monday, June 15, 1992.
Subsequent to the bankruptcy filing, BPC disposed of a substantial portion of
its assets. As a result, the Company's current operations are limited to
ownership of an operational cogeneration facility in California, a 50% interest
in another cogeneration facility in Nevada, an 88% interest in a cogeneration
facility under start-up in Mexico, an operation and maintenance company, and an
oil and gas company engaged in oil and natural gas exploration and production,
natural gas gathering and in marketing natural gas and electricity.
From 1991 through 1998, BPC was involved in numerous litigation matters. The
Trustee filed suit against underwriters, law firms, accounting firms, prior
management and others alleging that such parties engaged in wrongful actions
which caused harm to BPC. The Trustee collected, on behalf of the Bankruptcy
Estate, approximately $187,000,000 in settlements from defendants.
On April 22, 1998, the Trustee filed the Plan of Reorganization and the related
Disclosure Statement with the Bankruptcy Court. On June 19, 1998, the Trustee
filed an Amended Plan and Amended Disclosure Statement with the Bankruptcy
Court. On July 1, 1998, the Amended Plan and Amended Disclosure Statement
(collectively, the "Plan") were approved by the Bankruptcy Court and thereafter
copies were distributed to creditors, shareholders and others. On August 26,
1998, a Confirmation Hearing on the Plan was held. On August 27, 1998, the
United States Bankruptcy Court for the District of Utah entered the Order
Confirming the Plan. The effective date of the Confirmed Chapter 11 Plan was
November 2, 1998. To the extent consistent with the Plan, on the effective date,
the Trustee turned over control of the Company to a new Board of Directors.
The Plan classified all claims into 11 classes plus administrative claims and
standardized the way certain claims were calculated. The classes and treatments,
in general, are shown in footnote 2 to the attached Consolidated Financial
Statements.
The Plan provided for a one-for-four reverse stock split effective November 2,
1998. The above claims did not include administrative claims in the amount of
$3,714,000 which were accrued as of December 31, 1998. The administrative claims
were allowed by the Court on January 5, 1999, and were paid during January 1999.
Subsequent to the effective date of the Plan, BPC satisfied all of the claims as
provided for in the Plan. By the terms of the Plan, claimants who were entitled
to less than 100 shares of common stock (giving effect to the reverse stock
split) were paid in cash. Total cash payments for the shares aggregated
approximately $625,000.
As of the date immediately preceding the effective date, the reorganization
value of BPC, as set forth in the Plan, was greater than the sum of the
post-petition liabilities and allowed claims. As a result, generally accepted
accounting principles require that BPC continue to reflect its financial
condition at the lower of historical cost or fair market value.
RETENTION OF FINANCIAL ADVISOR
The Company recently announced that it had appointed CIBC Oppenheimer as the
Company's financial advisor. CIBC Oppenheimer has been retained to assist the
Company in defining strategic and financial alternatives relating to the
Company's power generation operations and its natural gas and oil production and
sales operations.
CIBC Oppenheimer has developed a preliminary analysis of the Company's
operations and potential valuations of the Company under a variety of
alternative strategies. Strategies being considered by the Company's Board of
Directors include, but are not limited to, the continued operation of the
Company, the sale of some of the assets or operations of the Company, or the
sale of the entire Company. The ultimate strategy adopted by the Company will be
at the sole discretion of the Board of Directors.
<PAGE>
BUSINESS OPERATIONS OF THE COMPANY
BPC and its wholly-owned subsidiaries, Bonneville Nevada Corporation, ("BNC"),
Bonneville Pacific Services Company, Inc. ("BPS") and Bonneville Fuels
Corporation ("BFC") are diversified energy companies engaged in various segments
of the energy business. The Company's participation in the energy industry is
typically conducted through subsidiaries. The Company's energy business is
divided into cogeneration operations and oil and gas operations. These two
operating areas are described below.
Cogeneration Operations
Overview
The Company is engaged in the acquisition, development, ownership and operation
of power generation facilities and the sale of electricity and thermal energy in
the United States. The Company is currently developing projects in Mexico which
will provide for the sale of electricity and thermal energy to customers in
Mexico. The Company has interests in three power plants, two are located in the
United States and one is located in Mexico. The Company currently sells
electricity and thermal energy to utilities and other customers, principally
under long-term power sales agreements and thermal energy sales agreements. The
Company intends to terminate its involvement in its California cogeneration
plant during 1999 (See Description of Facilities Kyocera). The Company is
currently investigating cogeneration opportunities in Mexico and, in connection
therewith, has entered into several letters of intent to develop cogeneration
facilities at Mexican manufacturing plant sites and to market electric power and
thermal energy to such manufacturers. The Company is also engaged in analyzing
other cogeneration opportunities in Mexico and the United States.
Description of Facilities
Bonneville Nevada Corporation
BNC was incorporated in Nevada as a wholly-owned subsidiary of BPC in December
of 1988. BNC owns a 50% interest in Nevada Cogeneration Associates #1, a Utah
general partnership ("NCA#1"), an 85 megawatt ("MW") power plant. The other 50%
interest in NCA#1 is owned by Texaco Clark County Cogeneration Company (TCCCC),
a wholly-owned subsidiary of Texaco, Inc.
NCA#1 is a combined cycle, gas fired cogeneration power plant located near Las
Vegas, Nevada. The project is a Qualifying Facility ("QF") under the Public
Utility Regulatory Policies Act ("PURPA"). The net electrical output is
delivered to Nevada Power Company ("NPC") under a 30 year Power Purchase
Agreement ("PPA"). The facility supplies thermal energy, in the form of exhaust
gas from the gas turbines and chilled water, under a 30 year Heat Purchase
Agreement with Georgia Pacific's ("GP") wallboard manufacturing facility located
on adjacent property
During late 1994 and 1995, NPC curtailed purchases of electrical power from
NCA#1. In July of 1995, NCA#1 together with Nevada Cogeneration Associates #2
(NCA#2), an 85 MW "sister" facility, filed a Demand for Arbitration and
Statement of Claims with the Las Vegas office of the American Arbitration
Association seeking redress for the NPC curtailments during 1994-1995.
Arbitration hearings were held and an Interim Arbitration Award was issued. The
award established a guideline for trigger points to be utilized in determining
the level of future curtailments. Subsequently, the parties entered into a
Settlement and Release Agreement wherein NCA#1 was awarded $829,920 for improper
curtailments during the designated period. Electric generation revenues
increased due to this Settlement and Release Agreement because the curtailment
trigger points established in the settlement resulted in lower levels of
curtailment than were experienced in 1995. In 1996, NCA #1 experienced
significantly lower levels of curtailment from NPC.
In 1997, NCA#1 renegotiated the Power Purchase Agreement with NPC, resulting in
an amendment to the Power Purchase Agreement that reduces the overall cost of
power to NPC and eliminates uncompensated curtailment from the contract. The
amendment provides that, under mutual agreement, NPC and NCA#1 can elect to
release a portion of NCA#1's electrical production for a price that is
acceptable to both parties. The parties are to agree upon a dollar rate,
production amount and length of time for released production, based on the
economics at the time. The settlement agreement includes a provision for the
sale of excess energy to NPC under mutual agreement at market rates. With the
new provision that allows for the pricing of excess energy at market rates
instead of the QF short term tariff rate, as provided in the original agreement,
it is projected that NCA#1 may be able to economically produce excess energy at
times in the future. The amendment was approved by the consortium of banks
providing financing for the facility, executed by the parties and approved by
the Public Utility Commission of Nevada ("PUCN"). The amendment replaces the
curtailment trigger points established in the earlier settlement. There were no
curtailments of NCA#1 in 1997, or in 1998.
The NCA#1 facility was financed primarily with non-recourse project financing
that is structured to be serviced out of the cash flows derived from the sale of
electricity and thermal energy produced by NCA#1. The project loan provides that
the obligations to pay interest and principal on the loans are secured by the
capital stock or partnership interests, physical assets, contracts and/or cash
flow attributable to the entities that own the facility.
<PAGE>
Kyocera
The Kyocera facility, located in San Diego, California, has been in commercial
operation since 1989. The project is a 3.2 MW cogeneration power plant. All of
its thermal energy in the form of chilled water and a major portion of its
electricity is sold to Kyocera America, Inc., ("KAI") for use in its microchip
packaging manufacturing process. The Company is paid for electricity and chilled
water as supplied to KAI pursuant to an Energy Supply Agreement ("ESA") which
had an initial term of 10 years and an option for a 10-year extension. The
initial 10-year term of the ESA expires on March 31, 1999.
Following a review of the economics of the facility, the Company's management
decided to sell or dismantle and salvage the Kyocera facility rather than renew
the contract for an additional ten years. Negotiations are currently underway to
either transfer the ownership of the facility to KAI for fair market value as
provided in the ESA, or to terminate operations and remove the equipment and
sell it for salvage.
CONAV
The Company, through BPS, is the majority owner (88%) of Cogeneracion de
Navojoa, S.A. de C.V. (CONAV), a Mexican corporation which owns a 4 MW
inside-the-fence, cogeneration project at a recycled paper and cardboard
manufacturing facility. The manufacturing facility is located near Navojoa,
Sonora, Mexico and is owned by Celulosa y Corrugados de Sonora, S.A. de C.V.
("CECSO"). The project is currently in start-up. The project features
re-conditioned equipment which will be owned and operated by CONAV under a
lease/purchase arrangement with CECSO. All of the power and thermal energy
produced by the project is to be used in the adjacent recycled paper and
cardboard manufacturing company.
Under the lease/purchase agreement with CECSO, most of the operation and
maintenance costs are the responsibility of CECSO. CONAV is responsible for
operation and maintenance of only the steam turbine generator and associated
accessories and oversight of the entire plant. CECSO has responsibility for
boiler operation and maintenance and for providing fuel, which is the largest
variable operating cost. The Company has invested $2,253,748 in this project as
of December 31, 1998.
The CONAV project has been undergoing the start up process for several months.
The water treatment system has experienced operational difficulties in each of
the previous tests. Demands have been sent to the vendor that supplied the water
treatment system stating that the system has to be replaced with one that is
acceptable to CONAV.
The results of the most recent test indicate that the levels of CECSO's steam
demand, in both volume and pressure, are different than design. This situation,
if uncorrected, will reduce the electrical production from the project. A
proposal has been presented to CECSO which is intended to bring the steam demand
in line with design levels. If CECSO does not agree with this proposal, then it
may be necessary for CONAV to terminate the agreement and remove and sell the
equipment. This could result in additional losses to the Company.
General
Insurance coverage for each power generation facility includes commercial
general liability, workers' compensation, employer's liability and property
damage coverage, which generally contains business interruption insurance
covering debt service and continuing expenses for a period ranging from 12 to 18
months.
Operations and Maintenance Activities
BPS provides operation and maintenance related services to cogeneration
facilities. BPS currently operates two 85 MW combined-cycle cogeneration
facilities located in Nevada (NCA#1 and NCA#2) and manages the operation of a
3.2 MW cogeneration facility at Kyocera America, Inc. located in San Diego,
California. BPS is also managing the construction and start-up of the CONAV
project in Navojoa, Mexico as described above and will manage the on-going
operations and maintenance staff for this project if the project continues.
The NCA#1 and NCA#2 facilities provide BPS with a revenue stream from operation
and maintenance agreements which have a 30 year term. These agreements have a
provision for renegotiation of the operating fee after 10 years which requires
mutual agreement between NCA and BPS to obtain an extension of an additional 10
years. These facilities have average reliability factors for the last three
years of 98.4% and 99.3% respectively for the NCA#1 and NCA#2 facilities.
Under the Operations and Maintenance Agreements, BPS is paid an annual operating
fee and an incentive fee. Each facility pays a base operating fee of $260,000
per year which escalates based on increases to the Consumer Price Index.
Incentive fees are based on performance of the facility and have averaged
approximately $331,000 per year for the last three years.
Substantially all of BPS' current revenue is provided from the contracts with
the two NCA facilities. While these contracts provide for assured recovery of
all onsite payroll-related costs, fees received in excess of out-of-pocket costs
are subordinated to project debt service, taxes and insurance. Loss of these
contracts, or substantial changes to the terms of the power sale agreement, or a
change in ownership of BPS, could have a substantial impact on BPS revenues.
<PAGE>
Additionally, revenues of BPS are largely dependent on its continued affiliation
with its parent company. The NCA#1 and NCA#2 Operation and Maintenance
Agreements both contain provisions for replacement of BPS as the operator if
"there is a substantial change in the ownership of the operator. This clause
refers only to a change in the ownership of the operator, and not to a change in
ownership of the parent company.....".
Although BPS is currently managing the operation of the Kyocera plant and the
construction of the CONAV project, management has determined that it will not
renew the lease on the Kyocera plant and may not be able to reach agreement with
CECSO on the proposal to increase thermal demand at the CONAV project. Loss of
these two management contracts will have a small, but insignificant negative
impact on future revenues to BPS as gross revenues to BPS from these two
projects are budgeted at less than $50,000 per year.
BPS' business strategy is to provide growth with additional contracts for power
generation operation and maintenance and to utilize its experience base in other
field to generate other operation and maintenance opportunities.
Strategy
The Company's business strategy is to maximize operating cash flow from its
existing operations and to identify and develop new cogeneration projects within
Mexico and the United States.
Seasonality
Results are subject to quarterly and seasonal fluctuations. Quarterly operating
results have fluctuated in the past and will continue to do so in the future as
a result of a number of factors, including:
*The timing and size of distributions from subsidiaries and incentive
fee payments from operations;
*The completion of development projects; and
*Variations in levels of production.
Market
The Company intends to continue to focus development activities within Mexico
and the United States. The Company, through its BPS subsidiary, is involved as
majority owner of the CONAV project in Mexico. The Company has identified other
opportunities in Mexico that it may pursue. BPS employs a development director
for Mexico and has hired a marketing director and an engineer to support these
activities.
The Mexican regulatory process is much less restrictive than the regulatory
process in the United States. This is particularly true for areas away from the
major industrialized cities, such as Mexico City. Permits for cogeneration
facilities under 50 MWs are approved by the local and state governmental
agencies and do not require an extensive review by Comision de Federal
Electricidad ("CFE"), the Mexican national electric utility. These permits can
generally be obtained in less time than it would take for corresponding permits
in the U.S.. Because of these factors and the large number of opportunities for
development of small cogeneration projects in Mexico, the Company intends to
focus development efforts on projects under 50 MWs.
Because of the limited financial resources of the Company, the Company's
development activities in the U.S. will focus on projects of 50 MW or less. Once
projects have been identified, the Company will then begin the planning and
permitting process.
Competition
The power generation industry is characterized by intense competition from
utilities, industrial companies and other power producers. Most of these
companies have substantially greater resources and/or access to the capital
required to fund such activities than BPC. In recent years, there has been
increasing competition in an effort to obtain new power sales agreements. This
competition has contributed to a reduction in electricity prices. In this
regard, many utilities often engage in "competitive bid" solicitations to
satisfy new capacity demands. This competition adversely affects the ability of
BPC to obtain power sales agreements and the price paid for electricity. There
also is increasing competition between electric utilities. This competition has
put pressure on electric utilities to lower costs, including the cost of
purchased electricity.
Governmental Regulation and Environmental Matters
The construction and operation of power generation facilities require numerous
permits, approvals and certificates from appropriate federal, state and local
governmental agencies, as well as compliance with environmental protection
legislation and other regulations. While management believes that it has
obtained the requisite approvals for its existing operations and that its
business is operated in accordance with applicable laws, BPC remains subject to
a varied and complex body of laws and regulations that both public officials and
private individuals may seek to enforce. There can be no assurance that existing
laws and regulations will not be revised or that new laws and regulations will
not be adopted or become applicable to BPC that may have an adverse effect on
<PAGE>
BPC's business or results of operations, nor can there be any assurance that BPC
will be able to obtain all necessary licenses, permits, approvals and
certificates for proposed projects or that completed facilities will comply with
all applicable permit conditions, statutes or regulations. In addition,
regulatory compliance for the construction of new facilities is a costly and
time consuming process, and intricate and changing environmental and other
regulatory requirements may necessitate substantial expenditures to retrofit
existing facilities or to obtain permits for new facilities and may create a
significant risk of expensive delays or significant loss of value in a project
if the project is unable to function as planned due to changing requirements or
local opposition.
The Company is subject to complex and stringent energy, environmental and other
governmental laws and regulations at the federal, state and local levels in
connection with the development, ownership and operation of its electrical
generation facilities. Federal laws and regulations govern transactions by
electrical and gas utility companies, the types of fuel which may be utilized by
an electric generating plant, the type of energy which may be produced by such a
plant and the ownership of a plant. State utility regulatory commissions must
approve the rates and, in some instances, other terms and conditions under which
public utilities purchase electric power from independent producers and sell
retail electric power. Under certain circumstances where specific exemptions are
otherwise unavailable, state utility regulatory commissions may have broad
jurisdiction over non-utility electric power plants. Energy producing projects
also are subject to federal, state and local laws and administrative regulations
which govern the emissions and other substances produced, discharged or disposed
of by a plant and the geographical location, zoning, land use and operation of a
plant. Applicable federal environmental laws typically have both state and local
enforcement and implementation provisions. These environmental laws and
regulations generally require that a wide variety of permits and other approvals
be obtained before the commencement of construction or operation of an energy-
producing facility and that the facility then operate in compliance with such
permits and approvals.
NCA#1 has been in negotiations with the United States Environmental Protection
Agency (the "EPA") regarding emissions from its gas turbine engines. Subsequent
to December 31, 1998, the EPA filed a lawsuit in the United States District
Court of Nevada against NCA#1, BNC and TCCCC and others seeking damages of
$25,000 per day from an unspecified point in time and requiring the installation
of custom emission control equipment. (United States of America v. Nevada
Cogeneration Associates #1, et al, No. CV-S-99-00107 PMP). NCA#1, BNC and TCCCC,
the partners to NCA#1 and all other defendants, have signed a consent decree
prepared by the U.S. Department of Justice that resolves the above mentioned
lawsuit and requires NCA#1 to pay a $100,000 fine and install additional
emission control equipment. The decree still requires the signature of other
parties to the action. As a condition of settlement with the EPA, NCA#1
installed Selective Catalytic Reduction Equipment ("SCR's") during the spring of
1999 maintenance outage. The cost of purchasing and installing the SCR's and the
proposed fine have been accrued by NCA#1 and the necessary funds are being held
in a control account. NCA#1 believes that it will have no additional liability
for the violations alleged in the above mentioned lawsuit after the consent
decree has been executed and entered by the court.
Federal Energy Regulations
PURPA
The enactment of the Public Utility Regulatory Policies Act of 1978, as amended
("PURPA") and the adoption of regulations thereunder by the Federal Energy
Regulatory Commission ("FERC") provided incentives for the development of
cogeneration facilities and small power production facilities (those utilizing
renewable fuels and having a capacity of less than 80 megawatts).
A domestic electricity generating project must be a QF under FERC regulations in
order to take advantage of certain rate and regulatory incentives provided by
PURPA. PURPA exempts owners of QFs from the Public Utility Holding Company Act
of 1935, as amended ("PUHCA"), and exempts QFs from most provisions of the
Federal Power Act (the "FPA") and, except under certain limited circumstances,
state laws concerning rate or financial regulation. These exemptions are
important to the Company and its competitors. Management believes that each of
the electricity generating projects in the U.S. in which the Company owns an
interest currently meets the requirements under PURPA necessary for QF status.
The projects which the Company is currently planning or developing are expected
to be QFs in the U.S. and cogeneration facilities in Mexico. Mexican law allows
some benefits to cogeneration facilities but does not have the equivalent of QF
status.
PURPA provides two primary benefits to QFs. First, QFs generally are relieved of
compliance with extensive federal, state and local regulations that control the
financial structure of an electric generating plant and the prices and terms on
which electricity may be sold by the plant. Second, the FERC's regulations
promulgated under PURPA require that electric utilities purchase electricity
generated by QFs at a price based on the purchasing utility's "avoided cost,"
and that the utility sell back-up power to the QF on a non- discriminatory
basis. The term "avoided cost" is defined as the incremental cost to an electric
utility of electric energy or capacity, or both, which, but for the purchase
from QFs, such utility would generate for itself or purchase from another
source. The FERC regulations also permit QFs and utilities to negotiate
agreements for utility purchases of power at rates lower than the utility's
avoided costs. Due to increasing competition for utility contracts, the current
practice is for most power sales agreements to be awarded at a rate below
avoided cost. While public utilities are not explicitly required by PURPA to
enter into long-term power sales agreements, PURPA helped to create a regulatory
environment in which it has been common for long-term agreements to be entered
into by the utilities with QFs.
<PAGE>
In order to be a QF, a cogeneration facility must produce not only electricity,
but also useful thermal energy for use in an industrial or commercial process in
certain proportions to the cogeneration facility's total energy output and must
meet certain energy efficiency standards. Finally, a QF (including a geothermal
or hydroelectric QF or other qualifying small power producers) must not be
controlled or more than 50% owned by an electric utility or by most electric
utility holding companies, or a subsidiary of such a utility or holding company
or any combination thereof.
The Company endeavors to develop its projects, monitor compliance of the
projects with applicable regulations and choose its customers in a manner which
minimizes the risks of any project losing its QF status. Certain factors
necessary to maintain QF status are, however, subject to the risk of events
outside the Company's control. For example, loss of a thermal energy customer or
failure of a thermal energy customer to take required amounts of thermal energy
from a QF could cause the facility to fail to meet requirements regarding the
level of useful thermal energy output and thus terminate QF status for the
facility. Upon the occurrence of such an event, the Company would seek to
replace the thermal energy customer or find another use for the thermal energy
which meets PURPA's requirements, but no assurance can be given that such would
be possible.
If one of the projects in which the Company has an interest should lose its
status as a QF, the project would no longer be entitled to the exemptions from
PUHCA and the FPA. This could trigger certain rights of termination under the
power sales agreement, could subject the project to rate regulation as a public
utility under the FPA and state law and could result in the Company
inadvertently becoming a public utility holding company by owning more than 10%
of the voting securities of, or controlling, a facility that would no longer be
exempt from PUHCA. This could cause all of the Company's remaining projects to
lose their qualifying status, because QFs may not be controlled or more than 50%
owned by such public utility holding companies. Loss of QF status may also
trigger defaults under covenants to maintain QF status in the projects' power
sales agreements, steam sales agreements, partnership agreements and financing
agreements and result in termination, penalties or acceleration of indebtedness
under such agreements such that loss of status may be on a retroactive or a
prospective basis.
RISK FACTORS - POWER PLANT DEVELOPMENT AND OPERATIONS
Power Project Development and Acquisition Risks
The development of power generation facilities is subject to substantial risks.
In connection with the development of a power generation facility, the Company
must generally obtain power and/or thermal sales agreements, environmental and
governmental permits and approvals, fuel supply and transportation agreements,
sufficient equity capital and debt financing, electrical transmission
agreements, site agreements and construction contracts, and there can be no
assurance that BPC will be successful in doing so. In addition, project
development is subject to certain environmental, engineering and construction
risks relating to cost-overruns, delays and performance. Although BPC may
attempt to minimize the financial risks in the development of a project by
securing a favorable long-term power sales agreement, entering into power
marketing transactions, obtaining all required governmental permits and
approvals and arranging adequate financing prior to the commencement of
construction, the development of a power project may require BPC to expend
significant sums for project development, preliminary engineering, permitting
and legal and other expenses before it can be determined whether a project is
feasible, economically attractive or financiable. If BPC were unable to complete
the development of a facility, it would generally not be able to recover its
investment in such development project.
The process for obtaining initial environmental, site and other governmental
permits and approvals is complicated and lengthy, often taking more than two to
three years, and is subject to significant uncertainties. As a result of
competition, it may be difficult to obtain a power sales agreement for a
proposed project, and the prices offered in new power sales agreements or
marketing agreements for both electric capacity and energy may be less than the
prices in prior agreements.
BPC believes that although the domestic power industry is undergoing
consolidation and that acquisition opportunities may be available, BPC is likely
to confront significant competition for acquisition opportunities. In addition,
there can be no assurance that BPC will continue to identify attractive
acquisition opportunities at favorable prices or, to the extent that any
opportunities are identified, that BPC will be able to consummate such
acquisitions.
Restructuring of the Domestic Electric Utility Industry
In an attempt toward the deregulation of the United States electric utility
industry, Congress has considered or is considering legislation that could
either repeal or materially amend the PURPA and/or PUHCA. Simultaneously, FERC,
as well as many state legislatures and public utility commissions, including
California and Nevada, are currently implementing or studying the potential
deregulation of the electric power industry. It is clear that the regulation of
the electric utility industry is in a state of flux. It is unclear what measures
will be ultimately adopted and what affect, if any, such measures will have upon
BPC. However, the following trends should be noted.
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First, BPC's historical business operations were highly dependent upon
provisions of PURPA which sanctioned and encouraged the sale of electrical power
by independent power producers to regulated utilities. Any material
modifications or the repeal of PURPA could materially alter both BPC's ability
to compete and its future business strategies.
Second, proposed modifications to PUHCA could permit independent power producers
and vertically integrated utilities to acquire retail utilities, and their
associated transmission systems, without geographic limitations which have been
a cornerstone of the PUHCA legislation. In theory, this could allow power
producers to transmit and sell their power (i.e., free access to wheeling) to
retail markets throughout the country thereby dramatically increasing
competition. If, and to what extent deregulation occurs, BPC may be required to
compete with larger, vertically integrated power producers on an increasing
basis.
Third, in light of lower energy costs anticipated to accompany deregulation,
utility companies are seeking ways to lower their energy costs by attempting to
curtail, terminate or abandon high price facilities and long term supply
contracts. Such actions may be with the tacit encouragement of applicable public
service commissions which seek to pass on reduced power costs to their
ratepayers. Simultaneously, publicly held utilities are seeking to maintain
market share and profit margins for their stockholders. An example of this trend
was the attempt of NPC in 1994, 1995 and 1996 to curtail production from
qualified facilities in NPC's service area including NCA#1. While management
does not believe NPC's efforts were successful, management has recognized that
such market pressures will only increase in the future and management is
attempting to take appropriate steps to minimize impact upon existing long term
contracts.
Fourth, in 1997 the Nevada legislature passed legislation to restructure the
Nevada utility industry. The legislation (AB-366) calls for competition to
commence by January 1, 2000. The eventual outcome of these activities and their
potential impact, if any, upon NCA#1 is not known.
In 1998, Nevada's two utilities, NPC, and Sierra Pacific Company ("SPC"), filed
for approval to merge. The merger was approved by the PUCN in December of 1998,
and, upon satisfactory completion of the conditions to the merger, is to be
effective by the end of 1999. Financing for the NCA#1 facility includes
$27,400,000 in variable rate tax exempt bonds. These bonds are commonly called
"Two-County" bonds because they are limited to utilities that have electrical
distribution territories that include two counties or less. Even though current
plans do not include an interconnection of the service territories of NPC and
SPC, the combined service territory of the two utilities following the merger
will be larger than two counties. Because of this, the NCA#1 partnership may be
compelled to replace the tax-exempt bonds, which currently have an effective
interest rate of 4.4%, with conventional financing, which will have a much
higher interest rate. An increase in the interest rate will have a corresponding
increase in the annual interest expense for NCA#1 and will create a
corresponding decrease in income from the project. The conditions of the merger
have the potential of affecting QF contracts held by each of the utilities in
other ways as well.
In summary, while the final impact of industry trends toward deregulation cannot
be predicted with confidence, it is clear that deregulation will generally lead
toward lower energy costs, smaller profit margins and will favor highly
capitalized vertically integrated power producers. This may provide additional
incentive for foreign development. BPC's ability to compete in a deregulated
industry cannot be predicted at this time.
Energy Price Fluctuations and Natural Gas
Power purchase agreements with utilities typically contain price provisions
which are, in part, linked to the utilities' cost of generating electricity. In
addition, BPC's fuel supply prices may be fixed in some cases or may be linked
to fluctuations in energy prices. In some cases there may be a period of time
where project costs and revenues become unlinked due to regulatory delay. These
circumstances can result in high volatility in gross margins and reduced
operating income, either of which could have an adverse effect on BPC's results
of operations.
Capital Requirements
Each power generation facility acquired or developed by BPC will require
substantial capital investment. BPC's ability to arrange financing and the cost
of such financing are dependent upon numerous factors, including general
economic and capital market conditions, conditions in energy markets, regulatory
developments, credit availability from banks or other lenders, investor
confidence in the industry and BPC, the continued success of BPC's current
facilities, and provisions of tax and securities laws that are conducive to
raising capital. There can be no assurance that financing for new facilities
will be obtained by BPC or be available to BPC on acceptable terms in the
future. In addition, there can be no assurance that all required governmental
permits and approvals for BPC's new or acquired facilities will be obtained,
that BPC will be able to obtain favorable power sales agreements and adequate
financing, or that BPC will be successful in the development of power generation
facilities in the future.
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The limited availability of cash to meet equity requirements for projects will
limit the size and scope of projects and opportunities the Company can
reasonably consider.
BPC has, in the past, guaranteed certain obligations of its subsidiaries and
other affiliates. There can be no assurance that, in respect of any financings
of facilities in the future, lenders or lessors will not require BPC to
guarantee the indebtedness of such future facilities, rendering BPC's general
corporate funds vulnerable in the event of a default by such facility or related
subsidiary.
International Investments
Independent power development is a new industry in Mexico and is subject to
ongoing regulatory change. Development of projects in Mexico is subject to risks
and uncertainties relating to the political, social and economic structures of
Mexico, potential changes to the current regulations, fluctuations of inflation,
currency valuation, currency inconvertibility, currency translation,
expropriation and confiscatory taxation. While current management is not aware
of any regulatory changes in process that would adversely affect the development
activity that BPC currently expects to undertake, there can be no guaranty that
this climate will continue to exist. Another risk is the high rate of inflation
that has been ongoing in Mexico for some time. As a hedge against inflation, BPC
intends to convert all cash flow from pesos into dollars. Arrangements to make
these exchanges have been completed with Mexican banks. An additional hedge
against inflation is that, while there is some lag behind inflation and the
price per kilowatt hour charged by CFE, the price per kilowatt hour generally
follows the inflationary trend and is increasing at similar rates and thereby
provides a natural hedge for inflation. There can, however, be no assurance that
this trend will continue in the future. Investments of U.S. dollars in foreign
countries are also subject to the risk of a foreign currency translation
adjustment. This is the difference of the value of the project as the value of
the local currency moves against the value of the U.S. dollar. In the past, CFE
rates for certain sectors have been subsidized. It is CFE's stated goal to
remove subsidies in the next three year period thereby creating a natural
increase in the price per kilowatt hour charged for power as subsidies are
removed and market rate levels are sought. There can be no assurance that prices
will continue to increase. A decrease in rates charged by CFE would result in a
corresponding decrease in the revenue from projects. In negotiating additional
contracts BPC will attempt to negotiate payment in U.S. dollars instead of in
pesos. Where that is not possible, pesos will be converted into U.S. dollars as
soon as they are received. Another area of risk is the exchange rate risk. In
addition to rapid inflation, and primarily as a result of that inflation,
exchange rates from pesos to dollars have been increasing since 1995 when the
peso went through a massive devaluation. While BPC believes that efforts to
develop additional power projects in Mexico will be successful, there can be no
assurance that any additional projects will be completed.
Start-Up Risks
The commencement of operation of a newly constructed power plant involves many
risks, including, but not limited to, start-up problems, the breakdown or
failure of equipment or processes and performance below expected levels of
output or efficiency. New plants have no operating history and may employ
recently developed and technologically complex equipment. Insurance is
maintained to protect against certain of these risks. Additionally, warranties
are generally obtained for limited periods relating to the construction of each
project and its equipment in varying degrees, and contractors and equipment
suppliers are obligated to meet certain performance levels. Such insurance,
warranties or performance guarantees may not be adequate to cover lost revenues
or increased expenses and, as a result, a project may be unable to fund
principal and interest payments under its financing obligations and may operate
at a loss. A default under such a financing obligation could result in BPC
losing its interest in such power generation facility. Construction in foreign
countries can be difficult to manage and can take significantly more time than
similar projects constructed in the U.S.
In addition, power sales agreements, which are typically entered into with a
utility or user early in the development phase of a project, often enable the
utility or user to terminate such agreement, or to retain security posted as
liquidated damages, in the event that a project fails to achieve commercial
operation or certain operating levels by specified dates or fails to make
certain specified payments. In the event such a termination right is exercised,
a project may not commence generating revenues, the default provisions in a
financing agreement may be triggered (rendering such debt immediately due and
payable) and the project may be rendered insolvent as a result.
General Operating Risks and Environmental Matters
The operation of power generation facilities involves many risks, including the
breakdown or failure of power generation equipment, transmission lines,
pipelines or other equipment or processes and performance below expected levels
of output or efficiency. Although BPC's facilities and future facilities will
contain certain redundancies and back-up mechanisms, there can be no assurance
that any such breakdown or failure would not prevent the affected facility from
performing under applicable power or thermal sales agreements. In addition,
although insurance is maintained to protect against certain of these operating
risks, the proceeds of such insurance may not be adequate to cover lost revenues
or increased expenses, and, as a result, the entity owning such power generation
facility may be unable to service principal and interest payments under its
financing obligations and may operate at a loss. A default under such a
financing obligation could result in BPC losing its interest in such power
generation facility.
Discharges of pollutants into the air, soil or water may give rise to
significant liabilities on the part of BPC to the government and third parties
and may result in the assessment of civil or criminal penalties or require BPC
to incur substantial costs of remediation which could have a material adverse
effect on BPC's results of operations.
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Impact of Curtailment
Power sales and thermal sales agreements contain curtailment provisions pursuant
to which the purchasers of energy or thermal energy are entitled to reduce the
number of hours of energy or amount of thermal purchased thereunder. Curtailment
provisions are customary in power sales and thermal sales agreements. There can
be no assurance that BPC will not experience curtailment. In the event of such
curtailment, BPC's results of operations may be materially adversely affected.
Dependence on Third Parties
The nature of BPC's power generation facilities is such that each facility
generally relies on one power or thermal sales agreement with a single electric
customer for substantially all, if not all, of such facility's revenue over the
life of the project. The power sales agreements and thermal sales agreements are
generally long-term agreements, covering the sale of electricity or thermal
energy for initial terms of 15 or 30 years. However, the loss of any one power
sales or thermal sales agreement with any of these customers could have a
material adverse effect on BPC's results of operations. In addition, any
material failure by any customer to fulfill its obligations under a power sales
or thermal sales agreement could have a material adverse effect on the cash flow
available to BPC and, as a result, on BPC's results of operations.
It is anticipated that power purchase agreements or energy supply agreements
will be entered into with various Mexican companies. The security of the payment
stream generated under these contracts will be dependent upon the strength and
viability of the contracting party.
Furthermore, each power generation facility may depend on a single or limited
number of entities to purchase thermal energy, or to supply or transport natural
gas to such facility. The failure of any one customer, thermal host, gas
supplier or gas transporter to fulfill its contractual obligations could have a
material adverse effect on a power project's qualifying status under PURPA
regulations and on BPC's business and results of operations.
Oil and Gas Operations
Overview
Bonneville Fuels Corporation ("BFC") is a Colorado corporation with its
principal offices located in Denver, Colorado. BFC is an independent oil and gas
company engaged in the exploration, development, and production of natural gas
and crude oil. BFC concentrates its activities in the Piceance and Uintah Basins
in northwestern Colorado and eastern Utah, the San Juan Basin in northwest New
Mexico and the Permian Basin in southeast New Mexico and western Texas. In an
effort to increase production and reduce reliance on natural gas in the Rockies
and southwest, BFC has acquired interests in several exploration projects in
southwestern Kansas.
BFC markets the majority of its own oil and natural gas production from the
wells that it operates. In addition, BFC engages in natural gas and electricity
trading activities which involve purchases from third parties and sales to other
parties. Through these trading activities, BFC obtains knowledge and information
that enables it to more effectively market its own production and to assist BPC
in the management of its core generation assets.
<PAGE>
Description of Properties
The Company's oil and gas properties are located in the western United
States and are principally natural gas properties as discussed below and in Item
2. Properties.
Piceance Basin. The Piceance Basin has been a core production
area since BFC's inception. The productive formations on BFC's current acreage
are the Morrison, Dakota, Mancos, Castle Gate, Mesa Verde and Wasatch
formations. All of these formations primarily produce natural gas; however, in
some areas, the Castle Gate sands formations have significant oil reserves. BFC
operates 132 wells and owns working interests in 147 wells in the Piceance Basin
in Colorado and the Uintah Basin in Utah. Virtually all (98%) of the net proved
reserves of 14 bcfe are gas reserves.
BFC has identified 15 drilling locations for further analysis and possible
future drilling. The continued strong prices for Piceance production have
encouraged BFC to hire additional staff and commit resources to a large regional
study of the area. This study started in June of 1998 and covers the areas of
BFC's largest lease holdings. This ongoing study has identified additional
potential drilling locations. Several hundred wells have been drilled in this
area by BFC and others since BFC's last full review. These wells have added
significant well control information to assist in understanding and mapping of
subsurface formations.
BFC's primary oil production in the Piceance is in the Tiaga Mountain field
area. BFC drilled two wells in this area during 1998, both of which were dry.
During 1998, BFC completed six workovers and recompletions in the Piceance Basin
area and returned the Main Canyon field area to active production. During 1999
BFC expects to: (i) drill 10 wells in the Piceance Basin targeting shallow
Wasatch formation production; (ii) drill up to two additional tests of the
Castlegate and Dakota formations; and (iii) complete several workovers of
existing wells. BFC has made recent efforts to reduce gathering costs. Reduced
gathering costs have led to higher cash flows and greater reserve values.
San Juan Basin. Production in the San Juan Basin of northwest New Mexico and
southwestern Colorado is primarily natural gas. The primary productive
formations on BFC's acreage are the Dakota, Gallup, Pictured Cliffs, and
Fruitland (Coal and Sands). BFC operates 39 of the 40 wells in which it holds an
interest in the San Juan Basin. Primary production is from the Dakota, Gallup,
Pictured Cliffs, and Fruitland formations. BFC believes that the shallow
formation potential of this acreage has been fully developed. Deeper formations
may hold additional opportunities for exploration. Net proved reserves in this
area exceed 3 bcfe of which 99% are gas reserves.
Two well recompletions in the Fruitland Sand in 1998 yielded additional
production and reserves. Subsequent to December 31, 1998, BFC drilled two
Gallup-Dakota development wells and set pipe on both wells. Completion and
testing of these wells is scheduled for the first quarter of 1999. BFC's acreage
in this area is substantially developed.
Permian Basin. BFC's activities in the Permian Basin are both operated and
non-operated in nature. Two fields, the South Humble City Field and Catclaw Draw
Field, make-up over 50% of this area's value to BFC. Most of BFC's oil reserves
are located in the South Humble City Field and in surrounding wells. BFC owns
working interests in 72 wells in the Permian Basin and operates nine of these
wells. Net proved reserves in this area total 7.9 bcfe of which 96% are gas
reserves.
The South Humble City field, located north of Hobbs, New Mexico, produces from
the Upper Strawn formation. BFC operates this field. In 1995, a 3-D seismic
program was completed which defined the primary reservoir of this field. Two
development wells have been drilled successfully in the main field. During 1997,
BFC increased its holding in this field by 50% through a purchase of a third
party's working interest.
The Catclaw Draw field is located northwest of Carlsbad, New Mexico. BFC
has approximately a 25% working interest in this field.
To the east of the Catclaw Draw field, in the Avalon area, BFC drilled two
development wells adjoining the Lake Shore Federal #1 well, which is currently
producing 2,000 mcfd and 30 barrels of condensate per day from the Strawn
formation. The first of the two wells was drilled by Yates Petroleum. This
well's rate of production is currently 2,400 mcfd. BFC owns a 37.5% working
interest in the Yates well. The second well, the Lake Shore 10-2, was drilled by
BFC in 1998 and produced 1,800 mcfd from the Strawn formation. The Morrow
formation has also been completed and tested and preparations are underway to
produce from both zones. BFC owns an 87.5% working interest in this well. In
late 1998 and early 1999, BFC drilled the Lake Shore 10-3. This well has been
drillstem tested and cased. Subsequent to December 31, 1998, operations were
underway to prepare the well to produce from the Strawn formation. BFC has
undertaken a detailed field study of the Catclaw/Avalon area. This study
continues and is the basis for two staked locations and four to six potential
locations that are being reviewed on BFC's acreage. The study was the basis for
BFC's decision to purchase 960 acres for $275,000 in the area during 1998. This
area is very active and BFC has been working with other industry parties to
increase participation in additional drilling locations while reducing interest
in any one drill site.
BFC is pursuing several seismic leads and locations south of Lovington, New
Mexico. Two wells have been included in BFC's 1999 budget. Based on current land
positions, BFC will have a 30% interest in these locations. Subsequent to
December 31, 1998, BFC purchased additional acreage in this area.
Southwestern Kansas. BFC's exploratory effort is currently concentrated in
southwestern Kansas. BFC owns working interests in 28 wells and operates four
wells in this area. In 1997 BFC acquired a 25% interest in the Beauchamp field.
This acquisition was made for the specific purpose of waterflooding the Keys
sands formation in the field. Preparations are being made to unitize the field
in mid 1999 and start water injection when oil prices recover. Timing of the
flood is dependent on oil prices and overall project economics will dictate
timing for additional field work.
BFC drilled eight wells in southwest Kansas during 1998 and is continuing to
complete its regional work identifying additional leads and leasing to acquire
acreage covering its best prospects. Five of the eight new wells were cased for
completion and production. Four of the wells were gas wells and one was an oil
well. Three wells were dry holes. During 1998 and in some cases subsequent to
December 31, 1998, the productive wells were completed and equipped for
production. BFC has purchased 50 miles of seismic data in the area which it is
currently reviewing. Eight prospects are in various stages in making their way
to being drilled in the next 12 months.
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RISK FACTORS - OIL AND GAS OPERATIONS
Reserve Replacement Risk
In general, the rate of production from oil and natural gas properties declines
as reserves are depleted. The rate of decline depends on reservoir
characteristics. Except to the extent that BFC conducts successful exploration
and development activities or acquires properties containing proved reserves, or
both, the proved reserves of BFC will decline as reserves are produced. BFC's
future oil and natural gas production is highly dependent upon its ability to
economically find, develop or acquire reserves in commercial quantities. The
business of exploring for or developing reserves is capital intensive. To the
extent cash flow from operations is reduced and external sources of capital
become limited or unavailable, BFC's ability to make the necessary capital
investment to maintain or expand its asset base of oil and natural gas reserves
would be impaired. In addition, there can be no assurance that BFC's future
exploration and development activities will result in additional proved reserves
or that BFC will be able to drill economical and productive wells. Furthermore,
although BFC's revenues could increase if prevailing prices for oil and natural
gas increase significantly, BFC's finding and development costs could increase.
Dependence on Exploratory and Development Drilling Activities
BFC's revenues, operating results and future rate of growth are partially
dependent upon the success of its exploratory and developmental drilling
activities. Drilling involves numerous risks, including the risk that no
commercially productive oil or natural gas reservoirs will be encountered. The
cost of drilling, completing and operating wells is often uncertain, and
drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, including unexpected drilling conditions, pressure or
irregularities in formations, equipment failures or accidents, adverse weather
conditions, compliance with governmental requirements and shortages or delays in
the availability of drilling rigs and the delivery of equipment. Despite the use
of 2-D and 3-D seismic data and other advanced technologies, exploratory
drilling remains a speculative activity. Even when fully utilized and properly
interpreted, 2-D and 3-D seismic data and other advanced technologies only
assist geoscientists in identifying subsurface structures and do not enable the
interpreter to know whether hydrocarbons are in fact present in those
structures. In addition, the use of 2-D and 3-D seismic data and other advanced
technologies requires greater predrilling expenditures than traditional drilling
strategies, and BPC could incur losses as a result of such expenditures. BFC
usually makes pre-drilling expenditures in areas where it appears that land is
available for leasing. BFC's future drilling activities may not be successful.
There can be no assurance that BFC's overall drilling success rate or its
drilling success rate for activity within a particular region will not decline.
Unsuccessful drilling activities could have a material adverse effect on BFC's
business, results of operations and financial condition. BFC may not have any
option or lease rights in potential drilling locations it identifies. Although
BFC has identified numerous potential drilling locations, there can be no
assurance that the potential drilling locations will ever be leased or drilled
or that oil or natural gas will be produced from these or any other potential
drilling locations. In addition, drilling locations initially may be identified
through a number of methods, some of which do not include interpretation of 2-D,
3-D or other seismic data. Actual drilling results are likely to vary from such
expected results and such variance may be material.
Competition
BFC operates in the highly competitive area of oil and natural gas exploration,
acquisition and production. In seeking to acquire desirable producing properties
or new leases for future exploration and in marketing its oil and natural gas
production, as well as in seeking to acquire the equipment and expertise
necessary to operate and develop those properties, BFC faces intense competition
from a large number of independent, technology-driven companies as well as both
major and other independent oil and natural gas companies. Many of these
competitors have financial and other resources substantially in excess of those
available to BFC. Such companies may be able to pay more for exploratory
prospects and productive oil and natural gas properties and may be able to
define, evaluate, bid for and purchase a greater number of properties and
prospects than BFC's financial or human resources permit.
Governmental Regulation and Environmental Matters
Oil and natural gas operations are subject to various federal, state and local
government laws and regulations, which may be changed from time to time in
response to economic or political conditions. Matters subject to regulation
include discharge permits for drilling operations, drilling bonds, reports
concerning operations, spacing of wells, utilization and pooling of properties,
environmental protection and taxation. From time to time, regulatory agencies
have imposed price controls and limitations on production by restricting the
rate of flow of oil and natural gas wells below actual production capacity in
order to conserve supplies of oil and natural gas. BFC is also subject to
changing and extensive tax laws, the effects of which cannot be predicted. The
development, production, handling, storage, transportation and disposal of oil
and natural gas, by-products thereof and other substances and materials produced
or used in connection with oil and natural gas operations are subject to laws
and regulations primarily relating to protection of human health and the
environment. The discharge of oil, natural gas or pollutants into the air, soil
or water may give rise to significant liabilities on the part of BFC to the
government and third parties and may result in the assessment of civil or
criminal penalties or require BFC to incur substantial costs of remediation.
Legal requirements frequently are changed and subject to interpretation. BFC is
unable to predict the ultimate cost of compliance with these requirements or the
effect of these requirements on BFC's operations. No assurance can be given that
existing laws or regulations, as currently interpreted or reinterpreted in the
future, or future laws or regulations will not materially adversely affect BFC's
business, results of operations and its financial condition.
<PAGE>
Uncertainty of Estimates of Oil and Natural Gas Reserves
Estimates of BFC's proved oil and natural gas reserves and the estimated future
net revenues therefrom are based upon BFC's own estimates or on third party
reserve reports that rely upon various assumptions, including assumptions as to
oil and natural gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The process of estimating oil and
natural gas reserves is complex, requiring significant decisions and assumptions
in the evaluation of available geological, geophysical, engineering and economic
data for each reservoir. As a result, such estimates are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves may vary substantially from those estimated by BFC or
reflected in the reserve reports. Any significant variance in these assumptions
could materially affect the estimated quantity and value of reserves. BFC's
properties also may be susceptible to hydrocarbon drainage from production by
other operators on adjacent properties. In addition, BFC's proved reserves may
be subject to downward or upward revision based upon production history, results
of future exploration and development, prevailing oil and natural gas prices,
mechanical difficulties, government regulation and other factors, many of which
are beyond BFC's control. Actual production, revenues, taxes, development
expenditures and operating expenses with respect to BFC's reserves likely will
vary from the estimates used, and such variances may be material.
The SEC PV 10 value of future net revenues as reflected in the accompanying
financial statements should not be construed as the current market value of the
estimated oil and natural gas reserves attributable to BFC's properties. The
estimated discounted future net cash flows from proved reserves generally are
based on prices and costs as of the date of the estimate, whereas actual future
prices and costs may be materially higher or lower. Actual future net cash flows
also will be affected by increases in consumption by oil and natural gas
purchasers and changes in governmental regulations or taxation. The timing of
actual future net cash flows from proved reserves, and thus their actual present
value, will be affected by the timing of both production and expenditures in
connection with the development and production of oil and natural gas
properties.
Marketability of Production and Price Volatility Risks
The marketability of BFC's production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. BFC delivers over 90% of the natural gas it produces
through gas gathering systems and gas pipelines that it does not own. Federal
and state regulation of oil and natural gas production and transportation, tax
and energy policies, changes in supply and demand and general economic
conditions all could adversely affect BFC's ability to produce and market its
oil and natural gas. Any dramatic change in market factors could have a material
adverse effect on BFC's business, financial condition and results of operations.
Natural gas and oil are both commodities that have a high degree of price
volatility. BFC's production is geographically removed from major pricing points
and so the gas produced has basis and overall price risk. While BFC actively
hedges a portion of its production, that portion of BFC's cash flow which is
unhedged is subject to rapidly changing market prices. Dramatic price decreases
could have a material adverse impact on BFC's financial condition and results of
operations.
Operating Hazards and Uninsured Risks
The oil and natural gas business involves certain operating hazards such as well
blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pipeline ruptures or
spills, pollution, releases of toxic gas and other environmental hazards and
risks, any of which could result in substantial losses to BFC. The availability
of a ready market for BFC's oil and natural gas production also depends on the
proximity of reserves to, and the capacity of, oil and natural gas gathering
systems, pipelines and trucking or terminal facilities. In addition, BFC may be
liable for environmental damage caused by previous owners of property purchased
or leased by BFC. As a result, substantial liabilities to third parties or
governmental entities may be incurred, the payment of which could reduce or
eliminate the funds available for exploration, development or acquisitions or
result in the loss of BFC's properties. In accordance with customary industry
practices, BFC maintains insurance against some, but not all, of such risks and
losses. The occurrence of an event that is not covered, or not fully covered, by
insurance could have a material adverse effect on BFC's business, financial
condition and results of operations. In addition, pollution and environmental
risks generally are not fully insurable. BFC participates in a number of its
wells on a non-operated basis, which may limit BFC's ability to control the
risks associated with oil and natural gas operations.
<PAGE>
Technological Changes
The oil and gas industry is characterized by rapid and significant technological
advancements and introduction of new products and services utilizing new
technologies. As others use or develop new technologies, BFC may be placed at a
competitive disadvantage, and competitive pressures may force BFC to implement
such new technologies at substantial costs. In addition, BFC's competitors may
have greater financial, technical and personnel resources that allow them to
enjoy technological advantages and may in the future allow them to implement new
technologies sooner than BFC. There can be no assurance that BFC will be able to
respond to such competitive pressures and implement such technologies on a
timely basis or at an acceptable cost. One or more of the technologies currently
utilized by BFC or implemented in the future may become obsolete. In such cases,
BFC's business, financial condition and results of operations could be
materially adversely affected. If BFC is unable to utilize the most advanced
commercially available technology, its business, financial condition and results
of operations could be materially and adversely affected.
EMPLOYEES
The Company, including all subsidiaries, currently employs a total of 76 people.
ITEM 2. PROPERTIES
All of the power generation facilities in which the Company has an interest are
located on sites which are leased on a long-term basis.
In addition to the Company's operating power generation facilities previously
described in Item 1, the Company currently leases 8,868 square feet of office
space for its administrative offices at 50 West Broadway, Suite 300, Salt Lake
City, Utah, at the monthly rate of $10,346. The lease has a 13 month term which
is set to expire on March 31, 1999, with two 13-month options to renew. The
monthly lease rate for the first renewal period is $10,900 and for the second
renewal period is $11,824 if exercised. The Company also has offices at 1660
Lincoln, Suite 2200, Denver, Colorado. BFC leases 10,894 square feet at a
monthly rate of $12,205. The lease is set to expire on December 31, 2002 and
escalates in cost each year. Under certain circumstances, the lease can be
terminated earlier than its full term.
Oil and Gas Properties
As described in Item 1, BFC has approximately 200,000 gross, 146,000 net acres
of land in inventory. The majority of BFC's proved reserves are concentrated in
four areas - the Piceance/Uintah Basins, the Permian Basin, the San Juan Basin,
and Southwestern Kansas. All wells and acreage are located in the continental
United States.
Reserves Reported to Other Agencies
The Company has not filed any estimates of total, proved net oil and gas
reserves with, or included in any reports to, any other Federal authority or
agency.
Proved Reserves
The following table sets forth the proved reserves as estimated by the Company's
independent petroleum reserve engineer of both gas and oil for BFC for each of
the three years ended December 31, 1998.
1998 1997 1996
---- ---- ----
Proved Reserves
Gas (mcf) 25,855,000 23,140,000 26,512,000
Oil (bbl) 166,000 298,000 227,000
The Company's reserves are sensitive to natural gas sales prices and their
effect on economic producing rates. The Company's reserves are based on oil and
gas prices in effect for December 1998.
There are a number of uncertainties in estimating quantities of proved reserves,
including many factors beyond the control of the Company and, therefore, the
reserve information in this Form 10K represents only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be measured in an exact manner. The
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates of different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revising the original estimate. Accordingly, reserve estimates are often
different from the quantities of crude oil and natural gas that are ultimately
recovered. The meaningfulness of such estimates depends primarily on the
accuracy of the assumptions upon which they were based. In general, the volume
of production from oil and gas properties owned by the Company declines as
reserves are depleted. Except to the extent the Company acquires additional
properties containing proved reserves or conducts successful exploration and
development activities or both, the proved reserves of the Company will decline
as reserves are produced.
<PAGE>
Production
The following table sets forth annual net production, average sales prices of
oil and gas, exclusive of hedging results, and average production (lifting)
costs per equivalent Mcf for each of the three years ended December 31, 1998.
Average production costs are converted to equivalent units of gas due to the
predominance of gas production during the periods presented.
Gas/Mcf Oil Bbls Average
Production Costs
Production Average Production Average Per Equivalent Mcf
Price Price
1998 3,272,000 $1.76 65,000 $13.26 $.82
1997 3,146,000 $1.99 63,000 $19.48 $.86
1996 2,744,000 $1.64 58,000 $21.10 $.82
BFC operates most of the wells in which it owns interests and holds working
interests in wells operated by third parties. Gas sales are generally made
pursuant to gas purchase contracts with unrelated third parties. Gas sales by
BFC are subject to price adjustment provisions of the gas purchase contracts as
well as general economic and political conditions affecting the production and
price of natural gas.
Productive Wells and Acreage
The following tables set forth the total gross and net productive oil and gas
wells and gross and net developed acres owned by the Company as of December 31,
1998. All wells and acreage are located in the continental United States.
Gas Wells Oil Wells Developed Acres
Gross Net Gross Net Gross Net
- ------- ------- -------------- ---------------
258 167 28 10 116,000 85,000
Undeveloped Acreage
The following table sets forth the gross and net undeveloped acres owned by the
Company as of December 31, 1998. All undeveloped acreage is located in the
continental United States.
Undeveloped Acres
GROSS NET
84,000 61,000
Drilling Activity
The following table sets forth the number of net productive and dry exploratory
and development wells drilled in each of the three years in the period ended
December 31, 1998.
1998
Exploration Development Total
Productive 5 6 11
Dry 2 3 5
--- --- ---
Totals 7 9 16
=== === ===
1997
Exploration Development Total
Productive 0 2 2
Dry 8 1 9
--- --- ---
Totals 8 3 11
=== === ===
1996
Exploration Development Total
Productive 0 4 4
Dry 2 0 2
--- --- ---
Totals 2 4 6
=== === ===
Present Activities
See Item 1 for a description of present activities.
<PAGE>
Delivery Commitments
BFC produces natural gas from four regions in the western United States; the
Permian Basin of southeast New Mexico and west Texas; the San Juan Basin of
northwest New Mexico, the Piceance Basin and Uintah Basin of eastern Utah and
northwestern Colorado and the mid-continent area of southwest Kansas. To
mitigate BFC's exposure to fluctuations in sales prices received for natural gas
in these regions, BFC periodically enters into a variety of contracts including,
but not limited to, commodity futures and options contracts, fixed-price swaps,
and basis swaps, and term sales contracts.
As of December 31, 1998, BFC had financial and physical contracts that hedged
approximately 6 bcf of production through December 31, 2001. Production from
existing properties under existing operating conditions has historically been
sufficient to meet contractual commitments. Management commits production
volumes equal to an amount that is less than the estimated future production
volumes.
Should production not fulfill committed contracts, BFC could acquire natural gas
in the open market; however, BFC could be exposed to market conditions at that
time. In addition, volumes in excess of those contracted are subject to market
prices.
ITEM 3. LEGAL PROCEEDINGS
On December 5, 1991, the Company filed a petition for reorganization under
Chapter 11 of the United States Bankruptcy Code. On June 12, 1992, Roger G.
Segal was appointed Trustee of the Company. On April 22, 1998, the Trustee filed
with the Bankruptcy Court, his original Chapter 11 Plan for the Company and its
related disclosure statement. On June 19, 1998, the Trustee filed the "Trustee's
Amended Chapter 11 Plan for the Estate of Bonneville Pacific Corporation dated
April 22, 1998" (the "Plan") and the related amended disclosure statement with
the Bankruptcy Court. On July 1, 1998, the amended disclosure statement was
approved by the Bankruptcy Court (order entered on July 2, 1998) and thereafter,
copies of the Plan and the related amended disclosure statement were distributed
to creditors, shareholders and others. On August 26, 1998, a confirmation
hearing on the Plan was held and the Plan was confirmed by the Bankruptcy Court.
On August 27, 1998, the Bankruptcy Court entered the Order Confirming the Plan.
On October 30, 1998, the Trustee notified the Bankruptcy Court that all of the
conditions to the Plan becoming effective had been satisfied and that the
Effective Date of the Plan would be November 2, 1998.
On November 2, 1998, the Plan became effective and the Company emerged from
bankruptcy, subject to the completion of the actions required by the Plan, and
to the extent consistent with the Plan, the Trustee turned over control of the
Company to the new Board of Directors.
The Bankruptcy Court held a hearing on March 22, 1999, concerning the "Trustee's
Motion for Entry of a Final Decree". At the hearing, the Bankruptcy Court
entered an order which discharged the Trustee, and, subject to the Plan, closed
BPC's bankruptcy case.
Please refer to Item 1. Business "Governmental Regulation and Environmental
Matters" for a description of the EPA lawsuit against NCA#1, BNC and TCCCC filed
in the United States District Court of Nevada.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to the Company's shareholders for a vote during the
fourth quarter of the year ended December 31, 1998.
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
a. Market Information
During the Company's bankruptcy proceeding, there was a limited market for the
Company's common stock. Following the Company's emergence from bankruptcy on
November 2, 1998, the Company took action necessary to have its common stock
quoted on the OTCBB. The Company's common stock has been quoted on the OTCBB
since December 1998 and is traded in the over-the-counter market under the
Symbol "BPCO". The information contained in the following table was obtained
from NASDAQ and from a broker-dealer and shows the range of representative bid
prices for the Company's common stock for the periods indicated. The following
represents quotations between dealers, prices without retail mark up, mark-down
or commission and may not necessarily represent actual transactions:
Bid Price
1999 High Low
1st Quarter $6.75 $4.75
1998
4th Quarter $5.50 $3.00
Shares Issued in Unregistered Transactions
On or about the Effective Date of the Plan, the Company issued approximately
4,305,000 shares (calculated after a 1-for-4 reverse split under the Plan) of
its common stock to creditors pursuant to the Plan. The shares issued pursuant
to the Plan were not registered with the Securities and Exchange Commission nor
were they registered with any state securities administrator in reliance upon
the exemption from registration contained in Section 1145 (a) of the United
State Bankruptcy Code. The shares issued under the Plan were issued in exchange
for claims in the approximate amount of $63,752,000.
<PAGE>
b. Holders
As of March 10, 1999, there were 2,591 holders of record of Bonneville Pacific
Corporation's common stock. The number of stockholders of record does not
include an undetermined number of stockholders whose shares are held by brokers
in "street name".
c. Dividends
The Company has not paid any cash dividends to date and does not anticipate or
contemplate paying dividends in the foreseeable future.
ITEM 6. SELECTED FINANCIAL DATA
The following table of selected financial data indicates certain trends in the
Company's financial condition and results of operations. An attempt has been
made to segregate the major revenues and expenses which relate directly to BPC's
bankruptcy.
Financial Data*
($ in 000's except per share)
For the year-ended .................. 1998 1997 1996
----------- ----------- -----------
Operating Revenue ............... $ 26,459 $ 21,956 $ 20,694
Operating Profit (loss) ........... (5,246) (34) 3,747
50% interest in NCA#1 earnings .... 5,130 3,902 3,380
Bankruptcy related items:
Gains on litigation settlements ... 0 15,686 156,939
Gains from claims forgiven ........ 23,681 0 0
Interest Income of BPC ............ 6,889 7,580 4,139
Professional fees & costs ......... (4,566) (5,278) (52,587)
Interest expense .................. (6,302) (45,388) 0
Net Income (loss) ................... 20,316 (22,620) 112,827
Dividend Paid ....................... 0 0 0
Per share items: (1)
Net Income (Loss) [basic] $5.60 $(7.74) $24.89
Net Income (Loss) [fully diluted] . 5.60 (7.74) 16.55
Average common shares outstanding (1) 3,629,508 2,921,113 4,532,490
Distributions from NCA#1 .......... 4,350 3,516 6,880
Settlements as Stockholders' Equity 40,630 0 30,621
At year-end
Total Assets $ 46,614 $ 187,626 $ 165,600
Long-term Debt 5,850 2,400 1,700
Senior Liabilities - subject to compromise 0 145,419 99,927
Subordinated Liabilities -
subject to compromise 0 64,021 64,021
Shareholder Equity (Deficit) 28,335 (32,296) (9,609)
Common shares outstanding (1) 7,227,390 2,921,728 2,903,018
*Years 1995 and 1994 are not presented. Because of the bankruptcy
of BPC, these years were not audited in reliance on a No Action
Letter dated April 9, 1992 issued by the Securities and Exchange
Commission.
(1) Restated to reflect 1-for-4 reverse stock split effective
as of November 2, 1998.
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
On December 5, 1991, BPC filed a voluntary petition for relief under Chapter 11
of Title 11 of the Federal Bankruptcy Code. The Bankruptcy Court ordered the
appointment of a Trustee on June 12, 1992. From December 5, 1991 until November
2, 1998, BPC operated under the jurisdiction of the United States Bankruptcy
Court. During that time, many of BPC's assets were sold or returned to creditors
in satisfaction of debt.
LIQUIDITY AND CAPITAL RESOURCES
During November 1998, the Company paid over $152,000,000 and issued
4,305,000 shares of common stock in satisfaction of over $215,300,000 of BPC
bankruptcy claims. This left the Company with $16,018,000 in cash and cash
equivalents as of December 31, 1998. After paying the final bankruptcy related
professional fees of $ 3,714,000 and escrow liability of $2,298,000, the Company
had over $ 10,000,000 in cash to fund day-to-day operations and invest in oil
and gas development and cogeneration projects.
The Company's primary sources of liquidity are existing cash balances, cash
provided by operations and debt financing. The Company's cash needs are for the
acquisition, exploration and development of oil and gas properties and for the
payment of debt obligations and trade payables as well as for the development of
cogeneration projects. In 1998, the Company financed the bulk of its exploration
and development program with internally generated cash plus additional bank
borrowing. Currently, the Company has no major commitments for capital
expenditures in the power generation business; however, it is pursuing
opportunities to develop new cogeneration projects which may require additional
capital expenditures. The Company has budgeted capital expenditures of
$12,500,000 for oil and gas exploration and development in 1999. The remaining
funding requirement for the CONAV project is estimated to be approximately
$350,000.
The sources of funds for this level of spending in the oil and gas business
includes cash generated by existing production, expected cash flow from wells
drilled during the year, bank borrowings and $3,000,000 of cash from corporate
cash reserves. BFC has existing lines of credit to meet the anticipated levels
of borrowing. At this time there are no existing lines of credit for BPC and
BPS.
This level of capital expenditure in the oil and gas area represents a
significant increase over the level of investment made during 1998 and 1997. The
Company anticipates that it will continue to increase its levels of capital
expenditure after 1999, however, such increases are dependent on oil and gas
prices, rates of production and continued availability of credit.
BFC has an asset based line of credit with a bank which provides for revolving
credit up to a specified borrowing base as defined in the agreement. As of
December 31, 1998, the borrowing base was $13,200,000. This represents an
increase of $3,200,000 over the December 31, 1997 borrowing base of $10,000,000.
The amount that can be borrowed from time to time will depend on the bank's
estimate of the value of the production assets. BFC's borrowing base which is
re-determined twice each year was increased to $13,200,000 in 1998 based on an
estimate made by the bank of BFC's reserves and ability to service its debts.
Outstanding revolving loan balances under BFC's revolving facility were
$5,150,000 and $2,400,000 at December 31, 1998 and 1997, respectively. The loan
accrues interest during the revolving period at a rate of LIBOR plus 1.75% or
the bank's prime interest rate at the election of BFC. The credit facility is
collateralized by all of BFC's oil and gas producing properties. The credit
facility provides for, among other things, covenants limiting additional
resource indebtedness, investments or disposition of assets of BFC, certain
restrictions on the payment of cash dividends and requirements that BFC maintain
certain financial ratios. To the extent that interest rates change, the cost of
borrowing under the credit facility will also change. BFC pays an annual
commitment fee of .25% on the unused portion of the facility, a rate of 1.25%
per annum for letters of credit.
BFC also has an additional credit facility which is collateralized by its
marketing accounts receivables. The amount that can be borrowed on this credit
facility varies and is based on 75% of the amount of marketing accounts
receivables that BFC has at any given time. Borrowings under this facility may
not exceed $1,500,000 and actual borrowings were $700,000 and $0 on December 31,
1998 and 1997, respectively. BFC is permitted to use this credit facility for
letters of credit or for cash borrowing as required for the energy marketing
business. BFC pays an annual commitment fee of .25% on the unused portion of the
facility, a rate of 1.25% per annum for letters of credit and a rate equal to
the bank's prime rate for cash advances under the facility.
At this time, the Company does not anticipate additional sales of stock or a
need for additional borrowing capacity under existing lines of credit in order
to operate its businesses. However, as newly developed cogeneration projects
move from development to construction, equity and new project specific lines of
credit will need to be added.
<PAGE>
RESULTS OF OPERATIONS
With the high number of non-recurring transactions resulting from the
bankruptcy, a careful review of the operating results becomes very important. In
order to facilitate a more orderly presentation and comparison of the results
from 1998, 1997, and 1996, the presentations of the results and accompanying
discussion is presented for 1998 and 1997. Following completion of that
discussion, similar data is presented for 1997 and 1996.
For the year ended December 31, 1998 Compared to the year ended December 31,
1997.
The Company reported a net income of $20,316,000 for the year ended December 31,
1998 compared to a net loss of $22,620,000 for the year ended December 31, 1997.
The $42,936,000 increase in net income was due primarily to non-recurring
bankruptcy related and asset impairment items as follows:
($ in 000's) 1998 1997 Difference
-------- -------- -----------
Interest Expense related to bankruptcy ($ 6,302) ($45,388) $ 39,086
Settlements & gain on debt extinguishments 23,681 15,686 7,995
Asset impairment charges ( 4,399) ( 312) ( 4,087)
Other 7,336 7,394 ( 58)
-------- -------- ---------
Net Income $ 20,316 ($22,620) $ 42,936
BPC received a substantial cash payment from settlements of bankruptcy
litigation matters. This cash was used to repay creditors of the BPC bankruptcy
estate. In late 1997, the Trustee reached agreement with several large creditors
which provided that creditors be paid interest during the bankruptcy period. In
1997 BPC accrued $45,388,000 in interest expense covering the entire bankruptcy
period from December 5, 1991 to December 31, 1997. In 1998 BPC accrued an
additional $6,302,000 of interest expense. Shortly after November 2, 1998, the
effective date of the Plan of Reorganization, BPC paid all senior liabilities
together with interest of $51,690,000.
Most of the Company's litigation was settled in 1997 and 1996. Income in 1998
was primarily the result of compromises made by certain classes of BPC's
creditors. These creditors received only a percentage of their original claims
and were paid in BPC common stock. This reduction of debt resulted in income of
$23,681,000, and an increase in stockholders equity of $40,630,000.
Following the emergence from bankruptcy, the Company undertook a review of all
of its corporate assets. This review, combined with an independent consultant's
report on oil and gas properties, generated impairment charges for 1998 totaling
$4,399,000. Impairments were related to the following assets: land in Vermont
held for sale ($148,000); the Kyocera facility, a 3.2 MW cogeneration plant in
San Diego, California ($1,583,000); CONAV, a 4 MW Cogeneration facility in the
start-up phase in Navajoa, Sonora, Mexico ($810,000); and oil and gas reserves
of Bonneville Fuels ($1,858,000). In 1997, an impairment charge of $312,000 was
taken on oil and gas properties.
Following is a discussion of results of operations by line of business.
Electric Cogeneration Operations
Results of the Company's electrical cogeneration operations are as follows:
Bonneville Nevada Corporation (BNC) and Nevada Cogeneration Associates #1
(NCA#1)
NCA#1's operating results are not consolidated as BNC is not a majority owner of
NCA#1, but BNC's portion of operating profit is part of the consolidated
results. BNC had no operations apart from NCA #1. NCA#1 operating results are as
follows:
($ in 000's) 1998 1997 Difference
Revenues $47,339 $45,684 $ 1,655
Expenses 37,080 37,880 800
------- ------- -------
Partnership Net Income 10,259 7,804 2,455
BNC's 50% ownership interest 5,130 3,902 1,228
Distributions from NCA#1 to BNC 4,350 3,516 834
Revenues increased by $1,655,000 as on-time operations increased the delivery
of power from 97.0% in 1997 to 98.8% in 1998, and the prices received for
electrical sales increased in 1998.
The increased revenue was partially offset by a $1,100,000 increase in fuel
costs. Fuel consumption increases as electrical production increases. An area of
savings was a decrease in major maintenance expenses as a new major maintenance
contractor was utilized which resulted in a lower maintenance cost. Interest
expenses were lower as a result of reduced debt.
BNC's only income, other than profits from NCA#1, came from interest on balances
held at the BNC level. Interest income decreased by $143,000 from 1997 to 1998
as $7,100,000 held in reserve at the BNC level were dividended to BPC at the end
of 1997 and were not available to earn interest at the BNC level in 1998.
BNC expenses related to NCA#1 are for travel associated with partnership
administration and management committee activities. Expenses increased from
$22,000 in 1997 to $42,000 in 1998 because of involvement by the management
committee in the NPC-SPC merger hearings and in the proposed restructuring of
the electrical industry in Nevada.
Kyocera Project
The Kyocera project is a 3.2 MW cogeneration facility owned by the Company which
is located in San Diego, California. Operating results from the project are as
follows:
($ in 000's) 1998 1997 Difference
------ ------ ----------
Revenues $1,653 $1,759 ($ 106)
Expenses
(excluding impairment) 1,503 1,611 108
------- ------ ----------
Gross Profit $ 150 $ 148 $ 2
Revenues in 1998 were $106,000 lower than in 1997 as the project experienced
forced outages related to unscheduled maintenance. The $108,000 reduction in
expenses was the result of lower fuel cost ($100,000), lower consulting expenses
($43,000) and lower permit and licensing fees ($29,000) being partially offset
by higher maintenance expenses ($83,000).
Following review, it was the decision of the Company to sell or dismantle and
salvage, as provided in the Energy Supply Agreement, the Kyocera facility rather
than renew the initial contract which expires on March 31, 1999. This decision
resulted in the Company taking an impairment charge of $1,583,000 in 1998. The
agreement will expire March 31, 1999. Negotiations are currently underway to
either transfer the ownership of the facility to KAI for fair market value as
provided in the ESA, or terminate operations and remove the equipment and sell
it for salvage.
CONAV
CONAV is a 4 MW cogeneration facility 88% owned by BPS, a wholly-owned
subsidiary of BPC. CONAV is located in Mexico. The project is currently in
start-up and is expected to be operational in mid 1999. Due to additional
construction costs and rework costs associated with defective work completed by
the original developers on this project, an $810,000 impairment charge was taken
on this facility in 1998. The financial results for CONAV are included in the
following discussion of Operating and Maintenance Operations.
Operating and Maintenance Operations
The results of the O & M group are as follows:
($ in 000s) 1998 1997 Difference
Revenues $ 4,107 $ 4,127 $ (20)
Operating Expenses (3,037) (2,957) (80)
Depreciation ( 17) ( 16) (1)
Impairment - CONAV ( 810) 0 (810)
General and Administrative ( 636) ( 542) ( 94)
Interest Income 103 329 (226)
Segment Profit (Loss) before
Reorganization Items and Taxes $(290) $ 941 $ (1,231)
BPS operates two facilities near Las Vegas, Nevada. By the terms of the O & M
agreements, revenues from the Las Vegas facilities are based on a fixed fee
adjusted annually by the CPI, a cost-plus fee on certain O & M expenses, and an
incentive fee based on a predetermined formula. During 1998 the $20,000 decrease
in revenues was primarily the result of a decrease in reimbursable salaries Even
though reimbursable salaries declined, overall operating expenses increased by
$80,000 as non-reimbursable expenses more than offset salary savings. The
non-reimbursable expense increases were higher due to increases in travel,
training and incentive pay.
Interest income was much lower in 1998 as $ 3,900,000 of cash reserves held
at BPS during 1997 were dividended to BPC in December, 1997. General and
administrative expenses were $ 94,000 higher in 1998. In 1997, BPC accrued
$179,000 for a court approved employee retention program related to the
bankruptcy. Consulting fees, primarily related to development, totaled $133,000
in 1998 and development salaries were an additional $94,000 as a development
team was added for Mexico. Office expenses, travel and a variety of other
expenses also increased. As CONAV is 88% owned by BPS, the $810,000 impairment
taken in 1998 is reflected in the O&M group.
Oil and Gas Operations and Energy Marketing
The results of oil and gas operations and energy marketing are as follows:
($ in 000's) 1998 1997 Difference
----------- ----------- ------------
Oil and Gas Operations
Revenues $ 6,758 $ 6,429 $ 329
Expenses 3,006 2,779 (227)
----------- ----------- -----------
Gross Profit from Production $ 3,752 $ 3,650 $ 102
Energy Marketing Activities
Revenues $ 13,941 $ 9,641 $ 4,300
Expenses 13,811 9,050 (4,761)
----------- ----------- ----------
Gross Profit from Marketing.... $ 130 $ 591 $ (461)
Depreciation, Depletion,
Amortization $ 2,083 $ 1,942 ($ 141)
Exploration & other oil & gas expense 556 772 216
Impairment 1,858 312 (1,546)
General and Administrative 1,234 990 (244)
Interest and Other Income ( 393) (469) (76)
Interest Expense 239 83 (156)
----------- ----------- -----------
Segment Profit (Loss) before
Reorganization Items and Taxes $ (1,695) $ 611 ($ 2,306)
Oil and gas production revenue increased $329,000 or 5.1% to $6,758,000 in
1998 compared to $6,429,000 in 1997. Natural gas volumes produced in 1998
increased 127,000 mcf or 4.0% to 3,273,000 mcf from 3,146,000 mcf in 1997. Oil
volumes produced increased 2,000 bbls or 3.2% to 65,000 bbls in 1998 from 63,000
bbls in 1997. The production increases resulted from successful drilling and
recompletion results in various basins. Some of these increases were partially
offset by production declines on previously existing properties.
Oil and gas production costs consist of lease operating expense and
production/severance taxes. Total production cost increased 8% in 1998 to
$3,006,000 from $2,779,000 in 1997. Total production cost per mcf
equivalent decreased 10% to $.82 per mcfe in 1998 from $.91 mcfe in 1997.
Gas marketing revenue increased 44% in 1998 to $13,900,000 from $9,135,000 in
1997. Gas marketing related expenses increased 53% to $13,800,000 in 1998, from
$9,000,000 in 1997. Certain high margin contracts expired early in 1997. The
related margins were accordingly not present in most of 1997, and in 1998.
Depreciation, Depletion and Amortization (DD&A) expense increased 7% in 1998 to
$2,083,000 from $1,942,000 in 1997. DD&A per mcfe of gas produced increased 6%
in 1998 to $.57 per mcfe over $.54 per mcfe in 1997.
Impairment of proved oil and gas properties increased $1,546,000 to $1,858,000
in 1998 from $312,000 in 1997. These impairment charges resulted from a decline
in the estimated value of producing properties related to oil and gas prices
which were substantially lower at year end 1998 than at year end 1997, and from
downward revisions of previous oil and gas reserve estimates.
Exploration expense primarily includes dry hole cost, and geological and
geophysical (G&G) cost. Exploration expense decreased 28% in 1998 to $556,000
from $772,000 in 1997. The amount related to unsuccessful drilling in 1997 was
significantly higher than in 1998, while G&G costs have increased in 1998 from
1997 as a result of increased activity.
General and administrative expenses are presented net of amounts charged
directly to lease operations and net of amounts billed to unrelated third
parties. These expenses increased 24.6% in 1998 to $1,234,000 from $990,000 in
1997. The increase in 1998 was primarily due to increased costs associated with
additional staffing related to an anticipated increase in drilling activity.
Interest expense increased 187% in 1998 to $238,000 from $83,000 in 1997. The
increase in 1998 is due to higher levels of borrowing in 1998 than in 1997. The
higher levels of borrowing in 1998 were a consequence of the increased cash
demands resulting from a combination of increased drilling and development
activity, and lower prices received from production.
BPC - Corporate
BPC's general and administrative expenses increased by $384,000 from
$876,000 in 1997 to $1,260,000 in 1998 primarily as a result of $223,000 in plan
confirmation bonuses paid to employees. This expense combined with higher
franchise taxes, health insurance, and expenses relating to the new Board of
Directors were the prime factors in the increase in administrative expenses over
1997 levels.
For the year ended December 31, 1997 compared to the year ended December 31,
1996:
The Company reported a net loss of $22,620,000 for the year ended December 31,
1997 as compared to net income of $112,827,000 for the year ended December 31,
1996. The $135,447,000 decline in net income was attributed primarily to
non-recurring items as follows:
($ in 000's) 1997 1996 Difference
--------- --------- ----------
Interest expense related
to bankruptcy ($ 45,388) $ 0 ($ 45,388)
Settlements & debt
extinguishments 15,686 156,939 (141,253)
Interest Income 7,580 4,139 3,441
Professional fees & costs ( 5,278) (52,587) 47,309
Other 4,780 4,336 444
--------- --------- ---------
Net Income ($ 22,620) $ 112,827 ($135,447)
As identified in the 98-97 comparison, in late 1997 the Trustee reached an
agreement with several large creditors with regard to the payment of interest on
outstanding claims and an interest charge of $45,388,000 was recorded in 1997
for the period December 5, 1991 to December 31, 1997. There were no such charges
in 1996.
BPC's litigation efforts were successful in recovering a total of
$157,000,000 in 1996 in litigation settlements. Settlements received in
1997 totalled approximately $16,000,000. A settlement with a large
stockholder in 1996 added an additional $30,621,000 to stockholders equity.
Attorneys hired to prosecute the BPC's litigation were reimbursed on a
percentage of the settlements and fees were paid as proceeds of settlements were
received and approved by the Bankruptcy Court. Attorneys fees for settlements
and their associated costs were approximately $53,000,000 in 1996 compared to
approximately $5,000,000 in 1997
Since most of these settlements came in middle to late 1996, the interest
income in 1997 was $3,000,000 higher than interest recorded in 1996 as average
cash balances were higher in 1997.
BPC - Corporate
BPC's general and administrative expenses decreased by $120,000 in 1997 as 1996
expenses included a wide variety of expenses relating to a bankruptcy damage
study, publication and other expenses related to a new claims bar date and
expenses associated with moving of corporate offices.
Net results of operations from power generation, operations and maintenance and
oil and gas and gas marketing remained relatively stable.
Electric Cogeneration Operations
The results of the Company's electric cogeneration operations are as follows:
Bonneville Nevada Corporation (BNC) and Nevada Cogeneration Associates #1
(NCA#1)
($ in 000's) 1997 1996 Difference
------- ------- ----------
Revenues....................... $45,684 $45,593 $ 91
Expenses ...................... 37,880 38,834 954
------- ------- -------
Partnership Net Income ........ $ 7,804 $ 6,759 $ 1,045
======= ======= =======
BNC's 50% ownership interest .. $ 3,902 $ 3,380 $ 522
Distributions from NCA#1 to BNC $ 3,516 $ 6,880 ($3,364)
Energy revenues were $978,000 higher in 1997 than in 1996 as on-time operations
increased the delivery of power from 95.1% in 1996 to 97.0% in 1997. Interest
and other income were down $887,000 as an arbitration settlement relating to
curtailments in 1994 and 1995 was settled for $830,000 in 1996. Expenses were
lower as a result of reduced interest costs as debt was decreased. NCA#1 had
reduced legal and fuel expenses in 1997.
BNC's only income, other than profits from NCA#1, came from interest on balances
held at the BNC level. Interest income increased by $149,000 from 1996 to 1997
as partnership distributions from NCA#1 were held in reserve at the BNC level in
1997. The distribution from NCA#1 in 1996 was unusually high because it
contained the operating profit from NCA#1 in 1996 ($3,380), and BNC's portion of
the proceeds from the arbitration settlement and reserve accounts held by the
banks that were released upon execution of an amendment to the project finance
documents.
BNC expenses related to NCA#1 are for travel associated with partnership
administration and management committee activities. Expenses decreased from
$30,000 in 1996 to $22,000 in 1997 because of reduced travel expenses associated
with the arbitration hearings and renegotiations of the Power Purchase Agreement
with NCA that ended early in 1997.
Kyocera Project
($ in 000's) .. 1997 1996 Difference
------ ------ ----------
Revenues ...... $1,759 $1,732 $ 27
Expenses ...... 1,611 1,445 (166)
------ ------ ------
Gross Profit .. $ 148 $ 287 $ (139)
Revenues increased by 1.5%, from 1996 to 1997. Expenses increased by 11.5% from
1996 to 1997. The increase in expenses resulted primarily from an increase in
the cost of fuel during the first four months of fiscal 1997 coupled with an
acceleration of maintenance during December 1997 which was originally scheduled
for April 1998.
Operating and Maintenance Operations
The results of the Company's operations and maintenance operations are as
follows:
($ in 000's) 1997 1996 Difference
------ ------ -----------
Revenues .................................. $4,127 $4,150 ($ 23)
Operating Expenses ........................ 2,957 3,059 102
Depreciation .............................. 16 11 ( 5)
General and Administrative ................ 542 207 (335)
Interest and Other Income ................. 329 887 (558)
------ ------ ------
Segment Profit (Loss) before
Reorganization Items and Taxes ... $ 941 $1,760 ($ 819)
During fiscal 1997, revenues decreased by $23,000, or 1%, primarily as a result
of a decline in the incentive fee income, expenses also decreased by $102,000,
or 3% as insurance costs and incentive payments to employees decreased.
General and administrative expenses increased as a result of the $179,000
employee retention program instituted in 1997. Salaries related to development
increased $75,000 while travel and a variety of development related expenses
also increased. Increases in interest income is a result of higher average cash
balances in 1997 as short term rates remained relatively stable. Also other
income was higher in 1996 as BPC received large Workmen's Compensation refund
relating to prior years from the State of California, as well as forgiveness of
an accrued insurance liability from the NCA project and settlements with
Westinghouse and Siemens.
<PAGE>
Oil and Gas and Energy Marketing Operations
The results of oil and gas operations and energy marketing are as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
($ in 000's) 1997 1996 Difference
------ ------ ----------
Oil and Gas Operations
Revenues ................................................................... $ 6,429 $ 5,262 $ 1,167
Expenses ................................................................... 2,779 2,095 (684)
---------- ---------- ----------
Gross Profit from
Production ..................................................................... $ 3,650 $ 3,167 $ 483
Energy Marketing
Activities
Revenues ....................................................................... $ 9,641 $ 9,550 $ 91
Expenses ....................................................................... 9,050 6,910 (2,140)
---------- ---------- ----------
Gross Profit from Marketing .................................................... $ 591 $ 2,640 ($ 2,049)
Depreciation, Depletion and
Amortization ................................................................. $ 1,942 $ 1,205 ($ 737)
Exploration & other oil &
gas expense .................................................................... 772 419 (353)
Impairment ..................................................................... 312 0 (312)
General and Administrative ..................................................... 990 472 (518)
Interest and Other Income ...................................................... (469) (255) 214
Interest Expense ............................................................... 83 272 189
---------- ---------- ----------
Segment Profit (Loss) before
Reorganization Items and Taxes ................................................ $ 611 $ 3,694 ($ 3,083)
</TABLE>
The 1997 oil and gas production revenue of $6,429,000 increased 22% or
$1,167,000 over production revenue in 1996 of $5,262,000. The 1997 production of
3,146,000 mcf was an increase of 402,000 mcf or 14.6% over 1996 natural gas
production of 2,744,000 mcf. Oil volumes produced in 1997 of 63,000 bbls
increased 5,000 bbls or 8.6% over 1996 oil production of 58,000 bbls. These
production levels have increased as indicated as extensions and discoveries
outpaced production declines on previously existing properties. The 1997 average
price of $19.48 per bbl received for oil was down 7.6% from the 1996 price of
$21.10 The 1997 average price received for gas of $1.99 per mcf was up 21.3%
from the 1996 price of $1.64.
The production increases resulted from successful drilling and recompletion
results in various basins. Some of these increases were partially offset by
production declines on previously existing properties.
<PAGE>
Oil and gas production costs consist of lease operating expense and
production/severance taxes. The 1997 expense of $2,779,000 was an increase of
33% over the cost in 1996 of $2,095,000. The increase in 1997 from 1996 was
largely the result of increased spending for environmental remediation purposes.
In addition to environmental spending, severance taxes were up 40%. Total
production cost per mcf equivalent increased 11% to $.91 per mcfe in 1997 over
the 1996 cost of $.82 per mcfe.
Gas marketing revenue of $9,135,000 in 1997 decreased 4% from the 1996 level of
$9,500,000. Gas marketing expense of $9,000,000 in 1997 was 31% higher than the
1996 level of $6,900,000. Certain high margin contracts which were in effect in
1996 expired early in 1997. The related margins were accordingly not present in
most of 1997.
Depreciation, depletion and amortization (DD&A) expense increased 61% to
$1,942,000 in 1997 over the 1996 levels of $1,205,000. The 1997 increase was
primarily a result of increased production from high DD&A cost properties, and
from an additional charge of $200,000 taken in 1997 to amortize future plugging
and abandonment cost. DD&A per mcfe of gas produced increased 35% to $.54 per
mcfe in 1997 over 1996 levels of $.40 per mcfe.
Impairment of proved oil and gas properties was $312,000 in 1997 and $0 in
1996. The impairment charges resulted from a decline in the estimated value
of unproved properties.
Exploration expense primarily includes dry hole cost, and geological and
geophysical (G&G) cost. Exploration expense of $772,000 in 1997 was an increase
of 84% over the $419,000 expensed in 1996. The amount related to unsuccessful
drilling in 1997 was significantly higher than in 1996, while G&G costs
increased in 1997 from 1996 as a result of increased activity.
General and administrative expenses are presented net of amounts charged
directly to lease operations and net of amounts billed to unrelated third
parties. These expenses increased 110% to $990,000 in 1997 from the 1996 expense
of $472,000. The major increase in 1997 over 1996 was due to the 1997 accrual of
$425,000 in court approved retention compensation.
The 1997 interest expense of $83,000 in 1997 decreased 69% from the 1996
interest expense of $272,000. The change from 1996 to 1997 is related to lower
levels of borrowing through the year in 1997.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards No. 133 ("SFAS #133"), Accounting for
Derivative Instruments and Hedging Activities. SFAS #133 will be effective for
fiscal years beginning after June 15, 1999. Earlier application is encouraged,
however, the Company does not anticipate adopting SFAS #133 until the fiscal
year beginning January 1, 2000. SFAS #133 requires that entities recognize all
derivatives as assets or liabilities in the statement of financial position and
measure those instruments at fair value. The Company does not believe the
adoption of SFAS #133 will have a material impact on assets, liabilities, or
equity. The Company has not yet determined the impact of SFAS #133 on the
statement of operations, or the impact on the comprehensive statement of
operations.
TRENDS, RISKS AND UNCERTAINTIES
Sale of all or part of the Company
The Company recently announced that it had appointed CIBC Oppenheimer as the
Company's financial advisor. CIBC Oppenheimer has been retained to assist the
Company in defining strategic and financial alternatives relating to the
Company's power generation operations and its oil and natural gas activities.
CIBC Oppenheimer has developed a preliminary analysis of the Company's
operations and potential valuations of the Company under a variety of
alternative strategies. Strategies being considered by the Company's Board of
Directors include, but are not limited to, the continued operation of the
Company, the sale of some of the assets or operations of the Company, or the
sale of the entire Company. As part of the consideration of alternative
strategies, CIBC Oppenheimer will solicit bids from interested parties for some
or all of the operations of the Company. The ultimate strategy adopted by the
Company will be at the sole discretion of the Board of Directors after the Board
and CIBC Oppenheimer have evaluated the results of the bidding process.
Deregulation
In 1997, the Nevada state legislature passed AB-366, which provides for
restructuring of the electric market in the State of Nevada. Hearings are being
held by the PUCN. There are several dockets related to restructuring issues that
are currently being heard by the PUCN. Several of these dockets have the
potential of affecting existing QF contracts.
Significant Customer Merger Announcement
Please see Item 1. Description of Business under the heading Cogeneration
Operation, Risk Factors, Power Plant Development and Operations, "Restructuring
of the Domestic Electric Utility Industry".
International
It is anticipated that power purchase agreements or energy supply agreements
will be entered into with various Mexican companies. The security of the payment
stream expected to be generated under these contracts will be dependent upon the
strength and viability of the contracting party.
Year 2000 Issue
BPC has reviewed compliance issues and upgrades have been made to systems and
software that are warranted by the vendor to be Y2K compatible. The Company's
Y2K compliance effort is ongoing and BPC, BFC, BPS and NCA#1 are also monitoring
non-information technology exposure elements, i.e. card key systems, embedded
chips, elevators, etc. The project is on schedule and expected to be completed
by September of 1999.
The Company has communicated with certain key vendors and has determined that
all are making progress toward their respective Y2K compliance.
The Company is aware of the issues associated with the "Y2K" problem both in
program codes and in hardware systems. The Company has taken and continues to
take steps to assure that disruption from the problem with internal software and
third party hardware and software vendors will not adversely affect operations.
The Company believes that any potential liability is with third party vendors
such as gas marketers, field service providers, and product purchasers. In all
cases BFC represents a minute portion of those vendors business and has no
influence on those vendors Y2K compliance. Although there can be no assurance
that all Y2K issues will be resolved, and that there will not be any significant
impact on the Company from these issues, it is not expected that significant
detrimental effects will occur.
The financial institutions with whom the Company has its material relationships
have each represented to the Company that their respective Y2K compliance
programs are underway with final testing to be completed in the first half of
1999.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
The Company's exposure to market risk for changes in interest rates relates
primarily to the Company's investment portfolio and long-term debt obligations.
The Company does not use derivative financial instruments in its investment
portfolio. The Company places its investments with high credit quality issuers
and by policy, is averse to principal loss and seeks to protect the safety and
preservation of its invested funds by limiting default risk and reinvestment
risk. As of December 31, 1998, the Company's investment consisted primarily of
municipal and government securities that mature in one year or less.
The NCA#1 cogeneration facility uses interest rate swap agreements to mitigate
their exposure to interest rate fluctuations. Please refer to the discussion in
"Notes to Consolidated Financial Statements".
Foreign Currency Risk
The Company does not use foreign currency forward exchange contracts or
purchased currency options to hedge local currency cash flows or for trading
purposes. All income received from international customers, with the exception
of balances in local operating accounts, are converted to U.S. dollars. The
Company has subsidiary operations in Mexico which are subject to currency
fluctuations. These foreign subsidiaries are limited in their operations and
level of investment by the parent company so that the risk of currency
fluctuations is minimized.
Commodity Price Risk
Oil and gas commodity markets are influenced by global as well as regional
supply and demand. Worldwide political events can also impact commodity prices.
Management's policy is to mitigate its exposure to fluctuations in sales prices
received for natural gas production through the use of various hedging tools.
These tools include, but are not limited to: commodity futures and option
contracts; fixed-price swaps; basis swaps; and term sales contracts. Contract
terms generally range from one month to three years. While BFC mitigates its
exposure to declining natural gas sales prices, it may be subject to lost
opportunity costs resulting from increasing natural gas prices in excess of
those committed.
Should production from existing facilities under existing operating conditions
not fulfill committed contracts, BFC may be required to acquire natural gas in
the open market and, In addition, volumes produced in excess of those contracted
are sold at market prices.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary data required by Item 8 are included
in Appendix I which precedes the Exhibit Index in this document and the Exhibits
attached to this document.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
In reliance upon a No Action Letter dated April 9, 1992 issued by the Securities
and Exchange Commission ("SEC") and pursuant to the SEC's Staff Legal Bulletin
No. 2, the Company did not file its 10K and 10Q reports and did not audit its
consolidated financial statements for the fiscal years ended December 31, 1992,
1993, 1994, 1995, 1996 and 1997. During this period, no firm acted as the
Company's certifying accountant. Prior to the Effective Date of the Plan, the
Trustee designated, with Bankruptcy Court approval, the accounting firm of Hein
+ Associates, LLP to be the Company's certifying accountant to audit the
Company's financial statements for the fiscal years ended December 31, 1996 and
1997 and to prepare an audited balance sheet in accordance with SEC Staff Legal
Bulletin No. 2. On November 2, 1998, the new Board of Directors of the Company
ratified Hein + Associates, LLP as the Company's certifying accountant.
PART III.
Item 10. Directors and Executive Officers of the Registrant
A. Identification of Directors and Executive Officers.
The current directors and officers of the Company, who will serve until the next
annual meeting of shareholders or until their successors are elected or
appointed and qualified, are set forth below:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Name Age Position(s) Held Office Since
James W. Bernard 61 Chairman of the Board, Chairman of Executive Comm. 1998
Clark M. Mower 52 Chief Executive Officer and President 1992
Steven H. Stepanek 43 Director; Secretary; President, Bonneville Fuels 1994*
Ralph F. Cox 66 Director, Chairman of Compensation Committee 1998
Michael R. Devitt 41 Director 1998
Harold E. Dittmer 58 Director 1998
Michael D. Fowler 55 Director, Chairman of Audit Committee 1998
Harold H. Robinson,III 59 Director 1998
R.Stephen Blackham 51 Treasurer, Assistant Controller
(Principal Financial Officer) 1990
</TABLE>
*Mr. Stepanek has been an officer since 1994, but was appointed
Director on November 2, 1998
James W. Bernard. Mr. Bernard, Chairman of the Board of Directors, retired
from Univar Corporation in 1995, after having held the position of President and
Chief Executive Officer since 1986. Mr. Bernard joined Univar Corporation in
1960 upon graduating from the University of Oregon with a B.S. in Chemistry. He
became a Vice President in 1967 and Senior Vice President in 1982. Mr. Bernard
has held various directorship positions and is currently a director of
VWR/Scientific Products, Hatch & Kirk and The Nature Conservancy of Idaho. He is
also a Trustee of the University of Oregon Foundation.
Clark M. Mower. Mr. Mower, has been serving since 1992 as President of
Bonneville Pacific Corporation and Chairman of Bonneville Fuels Corporation and
Bonneville Pacific Services Company, Inc. Mr. Mower also currently serves as a
member of the Management Committee of NCA#1. Mr. Mower was Vice President of
Development for BPC from 1990 to 1992. Mr. Mower joined BPC in 1988, after
having been Senior Vice President, Chief Operating Officer and Director of
Bingham Engineering Company. Mr. Mower joined Bingham Engineering Company in
1973. During the period of BPC's bankruptcy, Mr. Mower was the President.
Steven H. Stepanek. Mr. Stepanek has been a Director since 1998, and
President of Bonneville Fuels Corporation since 1994. Mr. Stepanek joined
Bonneville Fuels Corporation in 1989 as Vice President of Marketing. He also
serves as a member of the Management Committee of NCA#1. Mr. Stepanek has a B.S.
in Industrial Engineering from the University of Iowa and a Masters in Business
Administration from the University of Utah. During the period of the BPC
bankruptcy, Mr. Stepanek was General Manager and subsequently became President
of Bonneville Fuels Corporation.
R. Stephen Blackham. Mr. Blackham is Assistant Controller for Bonneville Pacific
Corporation and has been serving as Treasurer since 1998. Mr. Blackham has been
with BPC since 1990. He has served as Vice President and Chief Financial Officer
of Deseret Federal Savings and Loan Association, and Vice President of Rainier
Bank Oregon. During the period of BPC's bankruptcy, Mr. Blackham was Assistant
Controller of BPC.
Ralph F. Cox Mr. Cox, has been involved in the petroleum industry since 1953. He
is currently a management consultant working primarily with clients engaged in
the petroleum industry. From 1989 to 1994, he was the CEO of Greenhill Petroleum
Corporation. From 1985 to 1989 he was President of Union Pacific Resources, a
subsidiary of Union Pacific Corporation. From 1953 to 1985, he worked for
Atlantic Richfield Corporation (ARCO) where he rose to the position of Vice
Chairman and Chief Operating Officer. Mr. Cox is currently a director of Waste
Management, Inc., Rio Grande, Inc and Daniel Industries. He also serves as an
Independent Trustee for The Fidelity Group of funds.
Michael R. Devitt. Mr. Devitt, a Director since 1998, has been a practicing
attorney since 1984 after graduating from the University of Illinois Law School.
He currently is a managing member of Beus, Gilbert & Devitt, P.L.L.C. located in
Phoenix, Arizona. He is also an Adjunct Professor of Law at the Georgetown
University Law Center and the University of San Diego School of Law. Mr. Devitt
earned a Certified Public Accountant Certificate in 1980.
Harold E. Dittmer. Mr. Dittmer was made a Director in 1998 and has been the
President and CEO of Wellhead Electric Company, Inc. (a power generation project
developer and owner) for the past 15 years. He is also the President and CEO of
Wellco Services (a power plant and energy facilities operations and maintenance
company) and Power Exchange Corporation (a power marketing company). Prior to
founding Wellhead Electric Company, Inc., Mr. Dittmer was a management
consultant with Cresap McCormick & Paget, an international management consulting
firm. In 1974, Mr. Dittmer founded the Sierra Resource Group, a management and
financial consulting firm specializing in energy and natural resources
industries. Mr. Dittmer is also a principal in the BPIRP Group described in Item
12 below.
Michael D. Fowler. Mr. Fowler, a Director since 1998, and Chairman of the Audit
Committee, has, since 1997, been employed as the Chief Financial Officer of Howa
Construction, Inc., a regional commercial construction firm. Previously, he has
served as the senior financial executive for various public and private entities
engaged in natural gas transportation, natural gas marketing, commercial
banking, medical device manufacturing and precious metals production. From 1990
until 1996, Mr. Fowler served as Vice President and Treasurer of Grand Valley
Gas Company and Director of Risk Management of its successor company, Associated
Natural Gas Corporation. Mr. Fowler holds a Bachelor of Science Degree in
Electrical Engineering and a Master of Business Administration, both from the
University of Utah.
Harold H. Robinson, III. Mr. Robinson, was made a Director in 1998, and has
been a Venture Capitalist/Management Consultant since 1991. From 1983 to 1991 he
was employed by California Energy Company, Inc. where he served as a director
and Chief Operating Officer. Mr. Robinson previously practiced law and is
currently of-counsel with Lanahan & Reilley, LLP in Santa Rosa, California. He
is a member of several advisory boards including the Advisory Board of
Plantagenet Capital Fund described in Item 12 below..
B. Significant Employees.
Todd L. Witwer. Mr. Witwer has been President of Bonneville Pacific
Services Company, Inc. since 1992. Mr. Witwer joined Bonneville Pacific
Corporation in 1988. Mr. Witwer was previously employed by Westinghouse Electric
Corporation. Mr. Witwer has a B.S. in Engineering from California State
University - Chico.
C. Family Relationships.
There are no family relationships among the Company's officers and directors.
D. Other Involvement in Certain Legal Proceedings.
Except for the Company's Chapter 11 Bankruptcy proceeding, there have been no
events under any bankruptcy act, no criminal proceedings and no judgments or
injunctions material to the evaluation of the ability and integrity of any
director or executive officer during the last five years.
E. Compliance With Section 16(a).
Section 16 of the Securities Exchange Act of 1934 requires the filing of reports
for sales of the Company's common stock made by officers, directors and 10% or
greater shareholders. A Form 4 must be filed within ten days after the end of
the calendar month in which a sale or purchase occurred. Based upon the review
of the Form 4's filed with the Company, no disclosure is required relating to
late filings.
ITEM 11. EXECUTIVE COMPENSATION
The following table sets forth the aggregate compensation paid by the Company
for services rendered during the last three years to the Company's chief
executive officer and to the Company's most highly compensated executive
officers other than the chief executive officer, whose annual salary and bonus
exceeded $100,000:
<PAGE>
<TABLE>
<CAPTION>
SUMMARY COMPENSATION TABLE
Annual Compensation
Name and Principal Position Year Salary Commissions and Bonuses
<S> <C> <C> <C>
Clark M. Mower 1998 $178,164.70 $82,491.72
President 1997 $162,545.16 $10,000.00
1996 $150,632.70 $16,500.00
Steven H. Stepanek 1998 $140,173.92 $93,432.21
Secretary (1) 1997 $135,152.16 $15,000.00
1996 $129,445.92 $23,578.00
Todd L. Witwer (2) 1998 $118,363.00 $61,210.26
1997 $109,578.42 $10,000.00
1996 $107,735.82 $14,000.00
</TABLE>
(1)Mr. Stepanek is the president of Bonneville Fuels Corporation, a
wholly-owned subsidiary of the Company.
(2)Mr. Witwer is the president of Bonneville Pacific Services Company,
Inc., a wholly-owned subsidiary of the Company.
Stock Options
There were no stock options granted during fiscal 1998 to the named executive
officers. Subsequent to December 31, 1998, the executive officers of the Company
were granted stock options under the Executive Officers' 1999 Stock Option Plan.
The stock options are discussed below under "Employment Agreements".
Compensation of Directors
The Chairman of the Board is paid an annual compensation of $18,000. The
Company's non-employee directors are paid $1,000 for each Board of Directors
meeting attended and $750 for each Committee Meeting attended. Directors are
compensated for special assignments at the rate of $1,000 per day. In addition,
Committee Chairmen are paid $1,000 per meeting. On November 2, 1998, the Company
adopted, the 1998 Non-Employee Director's Stock Option Plan. The Plan provides
that each non-employee director who was a director as of November 2, 1998, be
issued an option to purchase 7,500 shares of the Company's common stock at $9.44
per share. The options are exercisable for a period of ten years commencing
November 2, 1998.
Employment Agreements
The Company is currently a party to the following Employment Agreements:
Clark M. Mower. The Company entered into an Employment Agreement with
its President/CEO on January 1, 1999. The Agreement has a two year term and
replaced and superseded a previously executed agreement. The Agreement may be
terminated by the Company without notice and without cause. The Agreement may be
terminated by Mr. Mower upon thirty days written notice. The Agreement provides
for a base annual salary of $174,000. The Agreement contains provisions relating
to death and disability during the term of employment. The Company is obligated
to compensate Mr. Mower for three times the sum of salary, bonus and profit
sharing for an average of the five fiscal years preceding termination in the
event the Company terminates the Agreement other than for cause. Mr. Mower has
an option granted January 7, 1999 for 100,000 shares of stock, priced at $5.00,
exercisable at 20,000 shares on January 7, 1999 and 20,000 shares per year until
the expiration of the grant in January of 2003. All options fully vest upon sale
or change of control of the Company.
Steven H. Stepanek. The Company's subsidiary, BFC, entered into an
Employment Agreement with Mr. Stepanek effective on July 1, 1997. The Agreement
has a two year term and replaced and superseded a previously executed agreement.
The Agreement may be terminated by the Company without notice and without cause.
The Agreement may be terminated by Mr. Stepanek upon sixty days written notice.
The Agreement provides for a base annual salary of $140,000. The Agreement
contains provisions relating to death and disability during the term of
employment. The Company is obligated to compensate Mr. Stepanek for three times
the sum of salary, bonus and profit sharing for an average of the two fiscal
years preceding termination in the event the Company terminates the Agreement
other than for cause. In the event the Company terminates the Agreement, the
Company is obligated to compensate Mr. Stepanek for an additional 24 months
salary reduced by one month per month of service after the date of the first
anniversary of the effective date of BPC's confirmed bankruptcy plan down to a
minimum benefit of 12 months. Mr. Stepanek has an option granted January 7, 1999
for 75,000 shares of stock, priced at $5.00, exercisable at 15,000 shares on
January 7, 1999 and 15,000 per year until the expiration of the grant in January
of 2003. All options fully vest upon sale or change of control of the Company.
A new two year contract for Mr. Stepanek, approved by the Board of
Directors and similar to the contracts executed by Mr. Mower and Mr. Witwer,
provides that the Company will be obligated to compensate Mr. Stepanek for two
times the sum of salary, bonus and profit sharing for an average of the five
fiscal years preceding termination in the event the Company terminates the
Agreement other than for cause. The contract has not been executed as of the
date of this filing.
Todd L. Witwer. The Company's subsidiary, Bonneville Pacific Services
Company, Inc., entered into an Employment Agreement with Mr. Witwer effective on
January 1, 1999. The Agreement may be terminated by the Company with sixty days
written notice and without cause. The Agreement may be terminated by Mr. Witwer
upon sixty days written notice. The Agreement provides for a base annual salary
of $125,000. The Agreement contains provisions relating to death and disability
during the term of employment. The Company will be obligated to compensate Mr.
Witwer for two times the sum of salary, bonus and profit sharing for an average
of the five fiscal years preceding termination in the event the Company
terminates the Agreement other than for cause. Mr. Witwer has an option granted
January 7, 1999 for 65,000 shares of stock, priced at $5.00, exercisable at
13,000 shares on January 7, 1999 and 13,000 shares per year until the expiration
of the grant in January of 2003. All options fully vest upon sale or change of
control of the Company.
Bonneville Pacific Corporation 401(k) Plan
BPC provides a 401(k) Plan for the benefit of all full-time employees who are
eligible beginning the first full month after date of hire. Effective January
1999, the Company pays a matching contribution of 50% of employee's deferral up
to a maximum of 6% of their total deferral.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Security Ownership of Certain Beneficial Owners
The following table sets forth information regarding shares of the Company's
common stock beneficially owned as of March 10, 1999 by: (i) each officer and
director of the Company; (ii) all officers and directors as a group; and (iii)
each person known by the Company to beneficially own 5 percent or more of the
outstanding shares of the Company's common stock.
Name Amount
and Address and Nature Percent
of Beneficial of Beneficial of Class(1)
Owner Ownership Ownership
Clark M. Mower (2) 22,472 *
50 West 300 South, #300
Salt Lake City, UT 84101
Steven H. Stepanek (3) 15,754 *
50 West 300 South, #300
Salt Lake City, UT 84101
James W. Bernard (4) 7,500 *
17120 SE 58th Street
Bellevue, WA 98006
Ralph F. Cox (5) 76,350 1.06%
4615 Post Oak Place, #140
Houston, TX 77207
Michael R. Devitt (4) 7,500 *
7614 Eads Avenue
La Jolla, CA 92037
Harold E. Dittmer (6) 910,986 12.59%
650 Bercut Drive, # C
Sacramento, CA 95814
Michael D. Fowler (4) 7,500 *
1297 Tomahawk Drive
Salt Lake City, UT 84103
Harold H. Robinson, III (4) 7,500 *
3558 Round Barn Blvd., #300
Santa Rosa CA 95403
Todd L. Witwer (7) 14,267 *
50 West 300 South, Suite 300
Salt Lake City, UT 84101
R. Stephen Blackham -0- -0-
50 West 300 South, #300
Salt Lake City, UT 84101
BPIRP Group (8) 985,362 13.6%
650 Bercut Drive, # C
Sacramento, CA 95814
Plantagenet Capital Fund 537,986 7.4%
220 Sansome Street, Suite 400
San Francisco, CA 94104
Portland General Holdings 500,000 6.9%
121 SW Salmon Street
Portland, OR 97204
All Officers and Directors (9) 1,069,829 14.61%
as a Group (10 Persons)
*Less than one percent
Unless otherwise indicated in the footnotes below, the Company has been
advised that each person above has sole voting power over the shares indicated
above. All of the individuals listed above are officers or directors or key
employees of the Company, or are companies or persons beneficially owning or
controlling 5 percent or more of the Company's outstanding shares of common
stock.
(1) As of March 10, 1999, there were 7,227,390 shares of the
Company's common stock issued and outstanding.
(2) Includes 2,472 shares owned of record and 20,000 shares issuable
upon the exercise of a currently exercisable stock option. This does
not include an additional 80,000 shares which underlie non-vested stock
options.
(3) Includes 629 shares owned of record by Mr. Stepanek, 125 shares
owned jointly by Mr. Stepanek and 15,000 shares issuable upon the
exercise of a currently exercisable stock option. This does not include
an additional 60,000 shares which underlie non-vested stock options.
(4) Represents 7,500 shares issuable upon the exercise of a currently
exercisable stock option.
(5) Includes 68,850 shares individually owned by Cox and 7,500 shares
issuable upon the exercise of a currently exercisable stock option.
(6) Includes 7,500 shares issuable upon the exercise of a currently
exercisable stock option. Mr. Dittmer has sole voting and dispositive
power over the shares issuable upon exercise of the stock option, as
well as 6,618 shares actually owned by him. Mr. Dittmer has shared
voting and dispositive power (a) with his wife, with respect to 1,269
shares owned by an individual retirement account for the benefit of
Mrs. Dittmer, and (b) with certain affiliates (members of the BPIRP
Group), with respect to 895,599 shares. Please refer to Note (8) below.
(7) Includes 1,267 shares owned of record and 13,000 shares issuable
upon the exercise of a currently exercisable stock options. This does
not include an additional 52,000 shares which underlie non-vested stock
options.
(8) The following persons report beneficial ownership of the Company's
common stock as a group (the "BPIRP Group"): Harold E. Dittmer, a
director of the Company; Frank A. Klepetko, Kenneth B. Salvagno; BP
Investment Recovery Partners, L.P.; Campus Financial Corporation;
ANGIC, LLC; Fresno Power Investors L.P.; FCGP, Inc.; Thomas A Tinucci;
and Joseph A. Wagda. The BPIRP Group has sole voting and dispositive
power with respect to the shares it beneficially owns, which include
7,500 shares issuable upon the exercise of a currently exercisable
stock option held by Mr. Dittmer. The shares reported as beneficially
owned by the BPIRP Group do not include 229,405 shares held by a third
party with respect to which the BPIRP Group has certain rights,
including a right of first refusal.
(9) See Notes 2-6 above. Includes 93,000 shares issuable upon the
exercise of currently exercisable stock options. The total includes the
shares beneficially owned or controlled by Harold E. Dittmer (see
footnote 6) but does not double count the duplicate ownership of the
BPIRP Group (see footnote 8).
Security Ownership of Management
Please refer to Item 12(a) above.
Changes in Control
The Company recently announced that it had appointed CIBC Oppenheimer as the
Company's financial advisors. CIBC Oppenheimer has been retained to assist the
Company in defining strategic and financial alternatives relating to the
Company's power generation operations and its natural gas and oil activities.
CIBC Oppenheimer has developed a preliminary analysis of the Company's
operations and potential valuations of the Company under a variety of
alternative strategies. Strategies being considered by the Company's Board of
Directors include, but are not limited to, the continued operation of the
Company's existing subsidiaries, the sale of some of the assets or operations of
the company, or the sale of the entire company. As part of the consideration of
alternative strategies, CIBC Oppenheimer will solicit bids from interested
parties for some or all of the operations of the Company. The ultimate strategy
adopted by the Company will be at the sole discretion of the Board of Directors
after the Board and CIBC Oppenheimer have evaluated the results of the bidding
process.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Michael R. Devitt, a member of the Board of Directors, is a member in the law
firm of Beus, Gilbert & Devitt, P.L.L.C. and is also a member of Beus, Gilbert &
Morrill, P.L.L.C. Beus, Gilbert & Morrill, P.L.L.C. was appointed by the
Bankruptcy Court upon application by the trustee as special counsel to pursue
litigation in the BPC bankruptcy matter. The law firm of Beus, Gilbert &
Morrill, P.L.L.C. received the sum of $1,816,409.66 in 1998 as attorney's fees
and reimbursable costs. The law firm of Beus, Gilbert & Morrill, P.L.L.C. has
also received significant legal fees and reimbursable costs in previous years as
detailed in the Disclosure Statement. Beus, Gilbert & Morrill, P.L.L.C.'s final
fee application was approved by the Bankruptcy Court on April 13, 1998.
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
a. Documents Filed as a Part of the Report
1. Financial Statements
Independent Auditors' Report
Consolidated Balance Sheets as of December 31, 1998 and 1997
Consolidated Statements of Operations for each of the three
years in the period ended December 31, 1998
Consolidated Statements of Stockholders' Equity for each of
the three years in the period ended December 31, 1998
Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 1998
2. Exhibits
3.1 Restated Certificate of Incorporation of the Registrant
(1)
3.2 Bylaws of the Registrant (1)
10.1 Non-Employee Directors' Stock Option Plan
10.2 1999 Executive Officers Stock Option Plan
10.3 Employment Agreement - Clark M. Mower
10.4 Employment Agreement - Steven H. Stepanek
10.5 Employment Agreement - Todd L. Witwer
10 6 Amended and Restated General Partnership Agreement for Nevada
Cogeneration Associates #1 by and between Bonneville Nevada
Corporation and Texaco Clark County Cogeneration Company dated
November 1, 1990
10.7 Bonneville Nevada Contract A with Nevada Power Company for Long-Term
Power Purchases from Qualifying Facilities dated May 2, 1989
10.8 Heat Purchase Agreement by and between Bonneville Nevada Corporation
and Georgia-Pacific Corporation dated September 12, 1989
21.1 Subsidiaries of Registrant
27.1 Financial Data Schedule
(1) Incorporated by reference to the exhibits to the Form 8-K filed
November 2, 1998.
b. Reports on Form 8-K.
1. On November 2, 1998, the Registrant filed a Form 8-K, under
Item 3,Bankruptcy or Receivership, and Item 5, Other Events.
2. On November 15, 1998, the Registrant filed a Form 8-K, under
Item 3, Bankruptcy or Receivership, and Item 5, Other Events.
With respect to Item 3, the Registrant filed its Monthly
Financial Report - Chapter 11 for the period October 1 to
October 31, 1998 with the Clerk of the United States
Bankruptcy Court for the District of Utah, Central Division,
Case No. 91A-27701.
3. On December 15, 1998, the Registrant filed a Form 8-K, under
Item 3.
Bankruptcy or Receivership, and Item 5, Other Events, which included
the audited consolidated financial statements for year ended December
31, 1997 and 1996.
4. On February 18, 1999, the Registrant filed an amended Form 8-K
previously filed on November 2, 1998, which included the
"Bonneville Pacific Corporation (Chapter 11 Debtor)
Consolidated Balance Sheet for period ended October 31, 1998".
c. Additional Financial Statements
1. Nevada Cogeneration Associates #1 Audited Financial Statements as of
December 31, 1998 and 1997
2. Nevada Cogeneration Associates #1 Audited Financial Statements as of
December 31, 1997 and 1996
<PAGE>
GLOSSARY
As used in this document, the following terms have the following specific
meanings.
Bbl means barrel.
Bcf means billion cubic feet.
Bcfe means billion cubic feet of gas equivalent.
Capital expenditures means all costs associated with exploratory and drilling,
leasehold acquisitions, land costs and related expenditures, costs of
construction, equipment costs, legal and other contract costs, construction
loan fees and capitalized interest, and all other costs related to the
completion of a well or other project.
Development well is a well drilled as an additional well to the same horizon or
horizons as other producing wells on a prospect, or a well drilled on a
spacing unit adjacent to a spacing unit with an existing well capable of
commercial production and which is intended to extend the proven limits of
a prospect.
Facility means a cogeneration power plant.
FERC means Federal Energy Regulatory Commission.
Inside-the-fence means that the net energy (electric and/or thermal) produced by
the facility is sold directly to the consumer(s) (customers) facility which
is either integrally connected or adjacent to the power or cogeneration
facility.
Mcf means thousand cubic feet.
Mcfe means thousand cubic feet equivalent.
Net gas and oil wells or "net" acres are determined by multiplying "gross"
wells or acres by BFC's working interest in those wells or acres.
NOL is Net Operating Loss.
OTCBB is the Over-the-Counter Electronic Bulletin Board
PURPA means Public Utility Regulatory Policies Act.
QF means Qualifying Facility under PURPA.
Reserves means natural gas and crude oil, condensate and natural gas liquids on
a net revenue interest basis, found to be commercially recoverable. "Proved
developed reserves" includes proved developed producing reserves and proved
developed behind-pipe reserves. "Proved developed producing reserves"
includes only those reserves expected to be recovered from existing
completion intervals in existing wells. "Proved developed
behind-pipe-reserves" includes those reserves that exist behind the casing
of existing wells when the cost of making such reserves available for
production is relatively small compared to the cost of a new well. "Proved
undeveloped reserves" includes those reserves expected to be recovered from
new wells on proved undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
SEC PV 10 is the method, as defined by the Securities and Exchange Commission's
regulation S-X, for determining the present value of proven oil and gas
reserves on a 10 percent discount rate.
Working interest in a gas and oil lease is an interest that gives the owner the
right to drill, produce and conduct operating activities on the property
and to receive a share of production of any hydrocarbons covered by the
lease. A working interest in a gas and oil lease also entitles its owner to
a proportionate interest in any well located on the lands covered by the
lease, subject to all royalties, overriding royalties and other burdens, to
all costs and expenses of exploration, development and operation of any
well located on the lease, and to all risks in connection therewith.
<PAGE>
INDEPENDENT AUDITOR'S REPORT
To the Board of Directors
Bonneville Pacific Corporation
Salt Lake City, Utah
We have audited the accompanying consolidated balance sheets of Bonneville
Pacific Corporation and subsidiaries as of December 31, 1998 and 1997, and the
related statements of operations, stockholders' equity (deficiency) and cash
flows for each year in a three-year period ended December 31, 1998. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
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 audits to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the consolidated financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
consolidated financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Bonneville
Pacific Corporation and subsidiaries as of December 31, 1998 and 1997, and the
results of their operations and their cash flows for each year in a three-year
period ended December 31, 1998 in conformity with generally accepted accounting
principles.
HEIN + ASSOCIATES LLP
Denver, Colorado
February 19, 1999
<PAGE>
<TABLE>
<CAPTION>
BONNEVILLE PACIFIC CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
($ In Thousands)
December 31
1998 1997
ASSETS
CURRENT ASSETS:
<S> <C> <C>
Cash and cash equivalents ........................................ $ 16,018 $ 154,065
Restricted Cash .................................................. 534 63
Receivables ...................................................... 5,755 9,127
Income tax receivable ............................................ 500 --
Other current assets ............................................. 343 237
Total Current Assets ........................................... 23,150 163,492
PROPERTY, PLANT AND EQUIPMENT:
Oil and gas properties, at cost, under the
successful efforts method ........................................ 32,424 28,591
Other property, plant and equipment .............................. 10,086 10,643
Accumulated depreciation, depletion,
amortization and impairment ...................................... (26,991) (22,287)
15,519 16,947
INVESTMENTS AND OTHER ASSETS:
Investments in and advance to affiliated
companies, at cost, plus equity in
undistributed earnings ........................................... 7,584 6,804
Other Assets ..................................................... 361 383
Total Other Assets ............................................. 7,945 7,187
TOTAL ASSETS ..................................................... $ 46,614 $ 187,626
See accompanying notes to these consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIENCY)
December 31,
1998 1997
LIABILITIES NOT SUBJECT TO COMPROMISE:
<S> <C> <C>
Current liabilities:
Post-petition accounts payable ................................... $ 6,683 $ 1,611
Accrued professional fees ........................................ 3,714 2,132
Other current liabilities ........................................ 2,032 2,721
Total current liabilities ........................................ 12,429 6,464
LONG-TERM LIABILITIES -
Bank debt ........................................................ 5,850 2,400
TOTAL LIABILITIES NOT SUBJECT TO COMPROMISE ...................... 18,279 8,864
SENIOR LIABILITIES SUBJECT TO COMPROMISE:
Pre-petition accounts payable .................................... -- 3,665
Convertible debentures and pre-petition
accrued interest ................................................. -- 64,750
Bank debt and pre-petition accrued interest ...................... -- 31,512
Accrued interest ................................................. -- 45,431
Priority claims .................................................. -- 61
Total senior liabilities subject to compromise ................... -- 145,419
SUBORDINATED LIABILITIES SUBJECT TO COMPROMISE:
Pre-petition selling debentures claims (Class 5) ................. -- 5,332
Post-petition selling debentures claims (Class 6) ................ -- 6,901
Limited partner claims (Class 7) ................................. -- 721
Deeply subordinated claims (Class 8) ............................. -- 8,945
Selling stockholders 510(b) claims (Class 9) ..................... -- 31,122
Cigna claim (Class 10) ........................................... -- 11,000
Total subordinated liabilities subject to
compromise ....................................................... -- 64,021
TOTAL LIABILITIES SUBJECT TO COMPROMISE .......................... -- 209,440
Total liabilities ................................................ 18,279 218,304
See accompanying notes to these consolidated financial statements
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
December 31,
1998 1997
MINORITY INTEREST IN CONSOLIDATED
SUBSIDIARY COMPANY .............................................. -- 1,618
COMMITMENTS AND CONTINGENCIES (Notes 6 and 8)
STOCKHOLDERS' EQUITY (DEFICIENCY):
Preferred stock - $.01 par value;
cumulative; 5,000,000 shares authorized;
no shares issued and outstanding ................................. -- --
Common stock - $.01 par value; 50,000,000
shares authorized; 7,227,000 and
5,344,000 shares issued, respectively ............................ 72 53
Additional paid-in capital ....................................... 160,735 127,763
Accumulated deficit .............................................. (132,090) (152,406)
Cumulative translation adjustment ................................ (382) (67)
28,335 (24,657)
Treasury stock - -0- and 2,422,000 shares,
respectively, at cost ............................................ -- (7,639)
Total stockholders' equity (deficiency)
(Note 11) ........................................................ 28,335 (32,296)
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY (DEFICIENCY) .............................................. $46,614 $ 187,626
See accompanying notes to these consolidated financial statements
</TABLE>
<PAGE>
BONNEVILLE PACIFIC CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
($ In Thousands)
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
1998 1997 1996
<S> <C> <C> <C>
REVENUES:
Oil and gas sales ................................................ $ 6,758 $ 6,429 $ 5,262
Energy marketing revenues ........................................ 13,941 9,641 9,550
Facilities operations and maintenance
revenues ......................................................... 4,107 4,127 4,150
Electric cogeneration ............................................ 1,653 1,759 1,732
Total revenues ................................................... 26,459 21,956 20,694
OPERATING EXPENSES:
Oil and gas production ........................................... 3,006 2,779 2,095
Energy marketing costs ........................................... 13,811 9,050 6,910
Facilities, operations and maintenance
costs ............................................................ 3,037 2,957 3,059
Electric cogeneration and cost of
electricity ...................................................... 1,503 1,611 1,445
Depreciation, depletion, amortization
and impairment ................................................... 6,622 2,387 1,314
Exploration and other oil and gas expense ........................ 556 772 419
Selling, general and administrative
expense .......................................................... 3,170 2,434 1,705
Total operating expenses ......................................... 31,705 21,990 16,947
OPERATING PROFIT (LOSS) .......................................... (5,246) (34) 3,747
OTHER INCOME (EXPENSE):
Interest expense ................................................. (6,541) (45,471) (555)
Other income (expense), net ...................................... 862 995 1,072
Total other income (expense) ..................................... (5,679) (44,476) 517
INCOME (LOSS) FROM CONSOLIDATED
COMPANIES ........................................................ (10,925) (44,510) 4,264
Equity in net earnings of affiliated
company .......................................................... 5,130 3,902 3,380
INCOME (LOSS) BEFORE REORGANIZATION
ITEMS, TAXES, AND EXTRAORDINARY ITEMS ............................ (5,795) (40,608) 7,644
Reorganization items (Note 5) .................................... 1,930 17,988 108,491
INCOME (LOSS) BEFORE TAXES AND
EXTRAORDINARY ITEMS .............................................. (3,865) (22,620) 116,135
PROVISION (BENEFIT) FOR INCOME TAXES ............................. (500) -- 3,308
INCOME (LOSS) BEFORE EXTRAORDINARY ITEMS ......................... (3,365) (22,620) 112,827
EXTRAORDINARY ITEMS, net of taxes of $-0- ........................ 23,681 -- --
NET INCOME (LOSS) ................................................ $ 20,316 $ (22,620) $ 112,827
OTHER COMPREHENSIVE INCOME -(LOSS)
Foreign currency translation
adjustments ...................................................... (315) (67) --
COMPREHENSIVE INCOME (LOSS) ...................................... $ 20,001 $ (22,687) $ 112,827
Basic earnings (loss) per share:
Income (loss) before extraordinary
items ............................................................ $ (.93) $ (7.74) $ 24.89
Extraordinary items .............................................. $ 6.53 $ -- $ --
Net income (loss) ................................................ $ 5.60 $ (7.74) $ 24.89
Diluted earnings (loss) per share:
Income (loss) before extraordinary
items ............................................................ $ (.93) $ (7.74) $ 16.55
Extraordinary items .............................................. $ 6.53 $ -- $ --
Net income (loss) ................................................ $ 5.60 $ (7.74) $ 16.55
See accompanying notes to these consolidated financial statements
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BONNEVILLE PACIFIC CORPORATION
AND SUBSIDIARIES
STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIENCY)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996
($ In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
ADDITIONAL CUMMULATIVE
COMMON STOCK PAID-IN ACCUMULATED TRANSLATION TREASURY
SHARES AMOUNT CAPITAL DEFICIT ADJUSTMENT STOCK TOTAL
BALANCES, January 1, 1996 5,344,000 $53 $ 91,996 $(242,613) $ - $(2,308) ($152,872)
Forgiveness of debt
payable to
stockholder - - 30,621 - - - 30,621
Forfeiture of stock by
stockholder - - 5,146 - - (5,146) -
Forfeiture of stock by
officers and
directors - - - - - (185) (185)
Net income - - - 112,827 - - 112,827
BALANCES,
December 31, 1996 5,344,000 53 127,763 (129,786) - (7,639) (9,609)
Foreign currency
translation - - - - (67) - (67)
Net loss - - - (22,620) - - (22,620)
BALANCES,
December 31, 1997 5,344,000 53 127,763 (152,406) (67) (7,639) (32,296)
Retirement of treasury
stock (2,422,000)(24) (7,615) - - 7,639 -
Common stock issued in
satisfaction of
claims 4,305,000 43 40,587 - - - 40,630
Foreign currency
Translation - - - - (315) - (315)
Net income - - - 20,316 - - 20,316
BALANCES,
December 31, 1998 7,227,000 $72 $160,735 $(132,090) $(382) $ - $ 28,335
See Accompanying notes to these financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S>
BONNEVILLE PACIFIC CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
($ In Thousands)
FOR THE YEARS ENDED
DECEMBER 31,
<C> <C> <C>
1998 1997 1996
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)(1) ...................................................... $20,316 $(22,620) $112,827
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Depreciation, depletion and
amortization .............................................................. 2,467 2,075 1,314
Impairment of property, plant and
equipment ................................................................. 4,399 324 --
Equity in investee earnings ............................................... (5,130) (3,902) (3,380)
Extraordinary gain ........................................................ (23,681) -- --
Gain on acquisition of treasury
stock ..................................................................... -- -- (185)
Changes in assets and
liabilities:
Accounts receivable ..................................................... 3,372 5,638 (11,909)
Inventories ............................................................. (65) -- --
Other current assets .................................................... (541) 118 (33)
Accounts payable and
accrued liabilities ..................................................... (43,742) 43,168 2,374
Other ................................................................... (317) -- --
Net cash provided by (used for)
operating activities ...................................................... (42,922) 24,801 101,008
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of marketable
securities ................................................................ -- 104,740 --
Purchase of marketable securities ......................................... -- -- (86,371)
(Increase) decrease in restricted cash .................................... (471) 152 (61)
Purchase of property, plant and
equipment ................................................................. (5,439) (5,771) (2,310)
Proceeds from sale of property, plant
and equipment ............................................................. -- 319 346
Distributions received from equity
investment ................................................................ 4,350 3,516 6,880
(Increase) decrease in other assets ....................................... 24 (40) 836
Net cash provided by (used for)
investing activities ...................................................... (1,536) 102,916 (80,680)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of long-term debt and
bankruptcy claims ......................................................... (95,421) -- (6,071)
Proceeds from long-term debt .............................................. 3,450 756 --
Increase (decrease) in minority
interest .................................................................. (1,618) 693 593
Net cash provided by (used for)
financing activities ...................................................... (93,589) 1,449 (5,478)
INCREASE (DECREASE) IN CASH ............................................... (138,047) 129,166 14,850
CASH AND EQUIVALENTS at
beginning of year ......................................................... 154,065 24,899 10,049
CASH AND EQUIVALENTS at end of year........................................ $ 16,018 $154,065 $24,899
CASH PAID FOR INCOME TAXES ................................................ $ - $ 541 $ 2,767
CASH PAID FOR INTEREST .................................................... $ - $ 83 $ 303
(1) Included in net income are non-recurring net gains from reorganization items of $1,930, $17,988 and $108,491
in 1998, 1997, and 1996, respectively. Also included in 1998 is an extraordinary gain from settlement of claims
of $23,681.
See accompanying notes to these financial statements
</TABLE>
<PAGE>
Bonneville Pacific Corporation
and Subsidiaries
Notes to the Financial Statement
1. REORGANIZATION AND LEGAL MATTERS:
Bonneville Pacific Corporation ("BPC"), but none of its partially- or
wholly-owned subsidiaries, filed a voluntary petition for relief under Chapter
11 of Title 11 of the Federal Bankruptcy Code (the "Code") on December 5, 1991
(the "petition date"). From the petition date to June 12, 1992, BPC operated as
a Chapter 11 Debtor-in-Possession subject to the jurisdiction of the United
States Bankruptcy Court for the District of Utah, Central Division (the
"Court"). On June 12, 1992, the Court ordered the appointment of a Chapter 11
Trustee (the "Trustee").
On June 19, 1998, the Trustee filed with the Court the "Trustee's Amended
Chapter 11 Plan for the Estate of Bonneville Pacific Corporation dated April 22,
1998" (the "Plan"). This Plan was confirmed on August 27, 1998 and was effective
on November 2, 1998.
2. CHAPTER 11 PLAN:
The Plan classified all claims into 11 classes plus administrative claims
and standardized the way certain claims were calculated. The classes and
treatments, in general, were as follows:
($ in 000's)
Class Type of Claim Allowed Amount of
Amount Settlement Treatment
1 Priority Claims $ 7 $ 7 Allowed claim paid in full in
cash at distribution date.
2 Bank Debt
Claims 31,512 31,512 Allowed claim paid in full in
cash at distribution date;
post-petition simple interest
at 8.03% per annum through
December 5, 1997 and 8.10%
thereafter.
3 Trade and Other
General
Unsecured Claims 3,750 3,750 Allowed claim paid in full in
cash at distribution date;
post-petition simple interest
at 5.5% per annum.
4 Current Debentures
Claims 64,750 64,750 Allowed claim paid in full in cash
at distribution date; post
petition simple interest at 7.32%
per annum.
5 Pre-petition Selling
Debenture Claims 5,333 5,333 Claim amount as unformly
calculated by the Trustee allowed
and paid in Plan common stock.
6 Post-petition Selling
Debenture Claims 6,901 6,901 Claim amount as uniformly
calculated by the Trustee allowed
and paid in Plan common stock.
7. Limited Partner
Claims 721 721 Claim amount as uniformly
calculated by the Trustee allowed
and paid in Plan common stock.
8 Deeply Subordinated
Claims 8,945 895 10% of allowed claim paid in Plan
common stock.
9 Equity Claims (For
Loss of Value on
Equity, also known
as 510(b) equity
claims 30,852 20,202 Allowed claim as uniformly
calculated by the Trustee paid in
Plan common stock with a value
estimated to be approximately 65%
of such claim.
10 CIGNA Claim 11,000 7,203 Allowed as an $11 million 510(b)
equity claim; claimant to receive
Plan common stock with a value
estimated to be approximately 65%
of such claim.
11 Equity Interest
(Existing Common
Stock) Existing common stock was retianed
by the interestholders and their
rights in the reorganized debtor
were unaltered.
The Plan also provided for a one-for-four reverse stock split.
The split was effective on November 2, 1998. The above claim
amounts do not include accrued administrative claims in the amount
of $3,714,000. These administrative claims were paid subsequent
to December 31, 1998 as allowed by the bankruptcy court on
January 5, 1999. BPC paid cash and issued stock in satisfaction
of the above claims as provided for in the Plan. Pursuant to the
Plan, claimants who were to receive less than 100 shares of Plan
common stock (taking into account the reverse stock split)
received cash in lieu of such stock. These cash payments totaled
approximately $625,000.
The value of BPC as set forth in the Plan (reorganization value)
as of the date immediately preceding the effective date was
greater than the sum of post-petition liabilities and allowed
claims. The Company did not qualify for fresh start accounting
and it has continued to report its assets and liabilities at
historical costs, rather than at the reorganization value.
The following table summarizes the adjustments required to record
the reorganization of the Company and the implementation of the
confirmed Plan, as of the effective date, November 2, 1998.
<PAGE>
Pre-Effective Balance
Date Plan After Plan
Balance Sheet Debt Debt
(in 000's) Discharge Discharge
CURRENT ASSETS:
Cash and cash equivalents ............. $ 163,991 $(156,578) $ 7,413
Other current assets .................. 4,817 -- 4,817
Total current assets .................. 168,808 (156,578) 12,230
PROPERTY, PLANT AND EQUIPMENT
net ................................... 14,411 -- 14,411
Investments in and advances to
affiliated companies, at cost
plus equity in undistributed
earnings .............................. 9,744 -- 9,744
Other assets .......................... 383 -- 383
TOTAL ASSETS .......................... $ 193,346 $(156,578) $36,768
LIABILITIES NOT SUBJECT TO COMPROMISE:
Current liabilities:
Post-petition accounts
payable ............................... $ 3,134 $ -- $ 3,134
Accrued professional fees ............. 4,281 (4,281) --
Other current liabilities ............. 1,139 -- 1,139
Total current liabilities ............. 8,554 (4,281) 4,273
Bank debt ............................. 3,900 -- 3,900
TOTAL LIABILITIES NOT SUBJECT TO
COMPROMISE ............................ 12,454 (4,281) 8,173
SENIOR LIABILITIES SUBJECT
TO COMPROMISE ......................... 151,575 (151,575) --
SUBORDINATED LIABILITIES SUBJECT TO
COMPROMISE ..................... ...... 63,752 (63,752) --
TOTAL LIABILITIES SUBJECT
TO COMPROMISE ........................ 215,327 (215,327) --
Total liabilities ..................... 227,781 (219,608) 8,173
STOCKHOLDERS' (DEFICIENCY) EQUITY:
Preferred stock ....................... -- -- --
Common stock .......................... 53 19 72
Additional paid-in capital ............ 127,763 32,970 160,733
Accumulated deficit ................... (154,183) 22,402 (131,781)
Cumulative translation
adjustment ............................ (429) -- (429)
Treasury stock ........................ (7,639) 7,639 --
Total stockholders'
(deficiency) equity ................... (34,435) 63,030 28,595
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $193,346 $(156,578) $ 36,768
3. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation - The consolidated financial
statements include the accounts of BPC and its majority-owned
subsidiaries (collectively referred to as "the Company"). All
significant intercompany balances and transactions have been
eliminated in consolidation. The following majority-owned
subsidiaries had activities during 1998, 1997, and 1996:
Bonneville Fuels Corporation ("BFC"), Bonneville Pacific Services
Company, Inc. ("BPS"), and Bonneville Nevada Corporation ("BNC").
Organization and Nature of Operations - The entity which
ultimately became BPC was initially incorporated in the State of
Utah in March 1980, and changed its state of incorporation to the
State of Delaware in June 1986. Subsequent to the bankruptcy
filing, BPC disposed of a substantial portion of its assets.
Consequently, the Company's current operations include the
ownership of one operational cogeneration facility, a 50% interest
in another cogeneration facility, a cogeneration operations and
management company and an oil and gas company engaged in the
exploration and production of oil and natural gas and in the
gathering and marketing of natural gas. At December 31, 1998 and
1997, BPS had an interest in an additional cogeneration facility
in Mexico. This facility was under construction at December 31,
1997 and was in the start-up phase at December 31, 1998.
Bankruptcy Reporting - The accompanying financial statements have
been prepared in accordance with the American Institute of
Certified Public Accountants Statement of Position 90-7 (SOP 90-7)
for reporting bankruptcy related items. SOP 90-7 requires BPC to
record claims at the amount allowed or the amount estimated to be
allowed as opposed to the amount for which the liabilities are
expected to be settled. SOP 90-7 also requires separate balance
sheet classification for liabilities subject to compromise, and
requires disclosure of certain bankruptcy related items.
Generally, the statement also requires reorganization items to be
separately reported as such in the income statement.
Cash and Cash Equivalents - The Company considers all highly-
liquid investments with an original maturity of three months or
less to be cash equivalents. Periodically, BPC had cash and cash
equivalents which exceeded the Federal Deposit Insurance
Corporation's insurance limit of $100,000.
Investment in Partnership - BPC through its wholly-owned
subsidiary, BNC, is a 50% general partner in Nevada Cogeneration
Associates #1 ("NCA #1"). The investment in NCA #1, accounted for
under the equity method, is recorded at cost, as adjusted for
BNC's share of earnings and distributions received.
Energy Marketing Arrangements - In 1998, BFC entered into an
agreement to manage certain natural gas contracts of an unrelated
entity. For some contracts, BFC takes title to the gas purchased
to service these contracts prior to the sale under the contracts.
For these contracts, BFC consolidates all revenue, expenses,
receivables and payables associated with the contracts. In
contracts where title is not taken, BFC only records the margin
associated with the transaction.
Use of Estimates in the Preparation of Financial Statements - The
preparation of financial statements in conformity with generally
accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenue and expenses during the reporting
period. Actual results could differ from those estimates.
Significant estimates include oil and gas reserve information,
which is the basis for the calculation of depletion and for the
calculation of impairments related to oil and gas properties.
Oil and Gas Properties - BFC follows the "successful efforts"
method of accounting for its oil and gas properties, all of which
are located in the continental United States. Under this method
of accounting, all property acquisition costs and costs of
exploratory and development wells are capitalized when incurred,
pending determination of whether the well has found proved
reserves. If an exploratory well has not found proved reserves,
the costs of drilling the well are charged to expense. The costs
of development wells are capitalized whether productive or
nonproductive.
Geological and geophysical costs and the costs of carrying and
retaining undeveloped properties are expensed as incurred.
Depreciation and depletion of capitalized costs for producing oil
and gas properties is provided for using the units-of-production
method based upon proved reserves for each field.
In 1997, BFC began to accrue for future plugging, abandonment, and
remediation using the negative salvage value method whereby costs
are expensed through additional depletion expense over the
remaining economic lives of the wells. Management's estimate of
the total future costs to plug, abandon, and remediate BFC's share
of all existing wells, including those currently shut-in, is
approximately $3,800,000, net of salvage values of which $406,000
has already been accrued for. The amounts expensed related to
this liability were $206,000 and $200,000 for the years ended
December 31, 1998 and 1997, respectively.
Gains and losses are generally recognized upon the sale of
interests in proved oil and gas properties based on the portion
of the property sold. For sales of partial interests in unproved
properties, BFC reflects the proceeds as a recovery of costs with
no gain recognized until all costs have been recovered.
Other Property and Equipment - Depreciation of other property and
equipment is calculated using the straight-line method over the
estimated useful lives (ranging from 3 to 25 years) of the
respective assets. The cost of normal maintenance and repairs is
charged to operating expenses as incurred. Material expenditures
which increase the life of an asset are capitalized and
depreciated over the estimated remaining useful life of the asset.
When properties are sold, or otherwise disposed of, the cost of
the property and the related accumulated depreciation or
amortization are removed from the accounts, and any gains or
losses are reflected in current operations.
Impairment of Assets - The Company follows Statement of Financial
Accounting Standards (SFAS) No. 121, Accounting for Impairment
of Long-Lived Assets. When facts and circumstances indicate that
the carrying value of an asset is impaired, the Company estimates
the future undiscounted cash flows from that asset and compares
that amount to the carrying value. If it is determined that an
impairment is required, the asset is written to its fair market
value. Net capitalized costs of oil and gas properties are
limited to the aggregate undiscounted future net revenues related
to each field. If the net capitalized costs exceed the
limitation, impairment is provided to reduce the carrying value
of the oil and gas properties to fair market value.
Income Taxes - The Company accounts for income taxes under the
liability method of SFAS No. 109, Accounting for Income Taxes.
SFAS No. 109 requires recognition of deferred tax assets and
liabilities for the expected future tax consequences of events
that have been included in the financial statements or tax
returns. Under this method, deferred tax assets and liabilities
are determined based on the difference between the financial
statement and tax bases of assets and liabilities using enacted
tax rates in effect for the year in which the differences are
expected to reverse.
Accounting for Hedged Transactions - In order to mitigate the risk
of market price fluctuations, BFC enters into futures and swap
contracts as hedges of commodity prices associated with its oil
and gas production and the purchase and sale of natural gas.
Changes in the market value of futures and swap contracts are
deferred until the gain or loss is recognized on the hedged
production or transactions. Payments received or made under these
contracts are included oil and gas sales or marketing income as
applicable.
Segment Reporting - The Company has adopted SFAS No. 131,
Disclosures About Segments of an Enterprise and Related
Information. SFAS No. 131 replaces SFAS No. 14 and utilizes the
"management approach" whereby external financial reporting is
aligned with internal reporting. SFAS No. 131 defines an
operating segment as a component of an enterprise that engages in
business activity for which it may earn revenues and incur
expenses, whose operating results are regularly reviewed by the
entity's chief operating decision maker to allocate resources and
assess performance, and for which discrete financial information
is available. The Company has identified the following reportable
operating segments: Bonneville Fuels Corporation, Bonneville
Pacific Services Company, and Bonneville Nevada Corporation.
Comprehensive Income - The Company has adopted SFAS No. 130,
Reporting Comprehensive Income, issued in June 1997. SFAS No. 130
requires the reporting and display of comprehensive income, which
is composed of net income and other comprehensive income items,
in a full set of general purpose financial statements. Other
comprehensive income items are revenues, expenses, gains and
losses that under generally accepted accounting principles are
excluded from net income and reflected as a component of equity.
The only other comprehensive income component the Company has is
the change in foreign currency translation.
Earnings Per Share - BPC follows SFAS No. 128 when calculating
earnings per share. Basic earnings per share is computed using
only the weighted average number of shares outstanding. Diluted
earnings per share includes potential common stock from the
assumed conversion of the convertible debentures. All outstanding
convertible debentures were retired pursuant to the Plan.
Reclassifications - Certain reclassifications have been made to
conform the 1997 and 1996 financial statements to the presentation
in 1998. The reclassifications had no impact on net income
(loss).
Impact of Recently Issued Accounting Pronouncements (Unaudited)
- - In June 1998, the Financial Accounting Standards Board issued
SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities. This statement is effective for fiscal years
beginning after June 15, 1999. Earlier application is encouraged;
however, the Company does not anticipate adopting SFAS No. 133
until the fiscal year beginning January 1, 2000. SFAS No. 133
requires that an entity recognize all derivatives as assets or
liabilities in the statement of financial position and measure
those instruments at fair value. The Company does not believe the
adoption of SFAS No. 133 will have a material impact on assets,
liabilities or equity. The Company has not yet determined the
impact of SFAS No. 133 on the income statement or the impact on
comprehensive income.
SFAS No. 132, Employers' Disclosures about Pensions and Other
Postretirement Benefits and SFAS No. 134, Accounting for Mortgage-
Backed Securities Retained after the Securitization of Mortgage
Loans Held for Sale by a Mortgage Banking Enterprise were issued
in 1998 and are not expected to impact the Company regarding
future financial statement disclosures, results of operations and
financial position.
In November 1998, the Emerging Issues Task Force reached a
consensus on issue #98-10, Accounting for Contracts Involved in
Energy Trading and Risk Management Activities. Due to the recent
issuance of the consensus, management has not yet determined the
impact of the consensus on the Company's financial statements.
4. IMPAIRMENT OF LONG-LIVED ASSETS:
The analysis of future cash flows of the Company's oil and gas
properties and the related fair value of those properties by BFC
resulted in an impairment charge of $1,858,000 in 1998.
After the effective date of the Plan, the Company's newly
appointed Board of Directors determined that it would not renew
the contract related to a small cogeneration plant which will now
expire pursuant to its terms on March 31, 1999. The Company also
reviewed the carrying value of the small cogeneration plant in
Mexico that is in the start-up phase and determined that it should
be impaired. Consequently, the Company took impairment charges
for the cogeneration assets of approximately $2,393,000 in 1998,
to reduce the net book value of these assets to their fair value.
The Company also reviewed the carrying value of a certain parcel
of undeveloped real estate and recorded approximately $148,000
impairment in 1998.
<PAGE>
5. REORGANIZATION AND EXTRAORDINARY ITEMS:
The effects of transactions and adjustments related specifically
to bankruptcy were as follows:
For the Years Ended
December 31,
1998 1997 1996
Reorganization items:
Gains from litigation
settlements ............... $ - $ 15,686 $ 156,939
Professional fees ......... (4,566) (5,278) (52,587)
Interest earned on accumulated
cash resulting from Chapter 11
proceedings ............... 6,889 7,580 4,139
Other ..................... (393) -- --
Total Reorganization Items $ 1,930 $ 17,988 $ 108,491
Extroadinary gain from claims
forgiven .....................$23,681 $ -- $ --
6. INVESTMENT IN NCA#1 PARTNERSHIP
BPC, through BNC, is a 50% general partner in the NCA #1
partnership. The remaining 50% is owned by Texaco Clark County
Cogeneration Company ("TCCCC"). The NCA #1 partnership owns and
operates an 85 megawatt electric generating facility (the
"Facility") in Clark County, Nevada. BNC receives a 50%
allocation of income (loss), depreciation expense and other tax
benefits from the operations of NCA #1. In accordance with the
partnership agreement, BNC initially received a 66 2/3% share of
net cash distributions until such net cash distributions equaled
approximately $18,876,000 (September 1997) at which time BNC's
share of net cash distributions changed to 50%. The NCA #1
partnership will terminate, unless terminated earlier by partner
agreement, on the latter of April 30, 2023, or the date that NCA
#1 elects to cease operations.
Summary condensed financial statement data and significant
accounting disclosures for NCA #1 as of December 31, 1998, 1997,
and 1996 and for the years then ended are as follows:
1998 1997 1996
($ in 000's)
Assets
Cash and cash equivalents ................... $ 5,301 $ 5,416 $ 5,822
Other current assets ........................ 8,273 5,998 5,646
Operating facility and
equipment, net ................. ............ 79,380 82,652 86,053
Other assets ................................ 8,060 10,087 9,810
$101,014 $104,153 $107,331
Liabilities and partners'
equity:
Project financing loan
payable and bonds payable .................. $ 73,768 $ 78,264 $ 81,842
Notes and other
payables to affiliates ....................... 1,474 1,513 1,447
Other liabilities ............................ 4,781 4,945 5,713
Partners' equity:
Bonneville Nevada ............................ 7,584 6,804 6,419
TCCCC ........................................ 13,407 12,627 11,910
$101,014 $104,153 $107,331
Revenues ........................................$ 47,339 $ 45,684 $ 45,593
Costs and expenses:
Plant and other
operating ..................................... 25,934 26,194 26,356
Depreciation and
amortization .................................. 3,533 3,482 3,601
General and
administrative ................................ 1,646 1,677 2,176
Interest ...................................... 5,774 6,187 6,702
Impairment expense ............................ 193 340 --
Total costs and expenses ........................ 37,080 37,880 38,835
Net income ...................................... $10,259 $ 7,804 $ 6,758
<PAGE>
The Facility was completed during 1992 and commercial operation
began on June 18, 1992. All costs, including interest and field
overhead expenses, incurred prior to commercial operations were
capitalized as part of the Facility. The Facility is being
depreciated on a straight-line basis over 30 years. Expenditures
for maintenance, repairs and minor renewals are charged to
expense as incurred, and expenditures for additions and
improvements are capitalized. Each of the Facility's gas turbines will require
a hot section replacement and a major overhaul approximately every 25,000 and
50,000 operating hours, respectively. The expected cost of this maintenance is
accrued using a straight-line method over the respective periods.
Due to fluctuations in the extent of repairs, prices and changes in the timing
of the scheduled events, the estimated costs of these events can differ
from actual costs incurred. All legal and financing fees associated with
NCA #1's project financing loan and bonds payable including the cost of
subsequent amendments were deferred and are being amortized over the terms of
the financing.
In April 1993, NCA #1 entered into a term loan in the amount of
$64,350,000. The debt is scheduled to be reduced on dates and by
amounts as specified in the loan agreement through October 2007,
unless terminated earlier as provided for in the loan agreement.
The amount outstanding under this term loan was $46,368,000 at
December 31, 1998. The loan agreement places certain
restrictions on cash accounts, capital distributions and
permitted investments. The term loan is collateralized by
substantially all of the assets of NCA #1, as well as BNC's
interest in the NCA #1 partnership.
The amount outstanding under the term loan bears interest at a
market rate plus a margin. NCA #1 has entered into interest rate
swap agreements with commercial banks to reduce the exposure to
higher interest rates. If the variable interest exceeds the
fixed rate established by the swap agreements, NCA #1 could be
exposed to the risk of higher interest costs in the event of
nonperformance by the commercial banks. The weighted average
interest rate, inclusive of the effect of the swap agreements, on
the outstanding loan balance was 7.20% and 7.74% at December 31,
1998 and 1997, respectively.
The future minimum payments on the term loan outstanding and the
letters of credit supporting the tax-exempt bonds at December 31,
1998, are as follows: 1999 - $5,138,000; 2000 - $5,689,000; 2001
- - $6,239,000; 2002 - $6,881,000; 2003 - $7,799,000, and for the
years thereafter a total of $14,622,000.
NCA #1 also obtained $27,400,000 of long-term project financing in the form
of variable rate industrial development revenue bonds.
BPC and the parent of TCCCC have guaranteed repayment of these bonds.
The bonds are due and payable on November 1, 2020 and November 1, 2021.
The interest rate on the bonds was 6.31% and 6.26% at December 31, 1998
and 1997, respectively. BPC and the parent of TCCCC have guaranteed
repayment of the industrial revenue bonds. NCA #1 is considering
refinancing these bonds.
NCA #1 has an agreement for long-term power purchases of energy
and capacity by Nevada Power Company (NPC) that terminates on
April 30, 2023. NCA #1 is paid for energy delivered based upon
fixed rates, as defined in the agreement, adjusted annually at
120% of the change in the CPI. NPC also pays NCA #1 for firm
capacity based upon fixed rates, as defined, increased annually
by 2%. During 1997, NCA #1 negotiated an amendment to the
agreement severely limiting NPC's curtailment rights in exchange
for a price discount of $.25 per megawatt hour. Pursuant to the
amended agreement, NCA #1 has the right to release NPC from its
purchase obligation for an agreed upon payment per released
megawatt.
NCA #1 also has a long-term process heat sales agreement with
Georgia-Pacific Corporation which terminates on April 30, 2023,
or earlier, as defined in the agreement. NCA #1 has a number of
long-term fuel-gas purchase contracts with various parties
including affiliates of TCCCC. NCA #1 also has an equipment
lease agreement which requires monthly payments of $24,000 plus
sales tax over a 10-year term ending December 31, 2002.
The Facility is operated and maintained by BPS. BPS is paid
for all costs incurred in connection with the operation and
maintenance of the Facility including an annual operating fee of
$260,000, adjusted annually by the Consumer Price Index. BPS
also may earn a performance bonus upon meeting specified
operating goals, as defined in the agreement.
NCA #1, under agreements, pays for certain engineering and
administrative expenses and other costs to TCCCC and its affiliates. TCCCC may
earn a performance bonus based upon the plant achieving certain operational
goals, as defined in the agreement.
In 1997, the Nevada Legislature passed legislation to restructure
the Nevada electric utility industry. The legislation (AB366)
calls for competition to commence by January 1, 2000. The
eventual outcome of these activities and their potential impact,
if any, upon NCA #1 is not known.
Income taxes are not recorded by NCA #1 since the net income or
loss allocated to the partners is included in each partner's
respective income tax return.
Under the terms of the NCA #1 Partnership Agreement, at TCCCC's
option, BNC will be obligated to purchase or cause to be
purchased, TCCCC's ownership interest in NCA #1 at fair market
value as determined by an independent appraisal. TCCCC's option
becomes effective on June 18, 2012.
NCA #1 has been in negotiations with the United States
Environmental Protection Agency (the "EPA") regarding emissions
from its gas turbine engines. Subsequent to December 31, 1998,
the EPA filed a lawsuit against NCA #1, BNC and TCCCC, seeking
damages of $25,000 per day from an unspecified point in time and
the installation of custom emission controlling equipment. NCA
#1, BNC and TCCCC, the partners to NCA #1, have signed a consent
decree prepared by the U.S. Department of Justice that resolves
the above mentioned lawsuit and requires NCA #1 to pay a $100,000
fine and install the emission controlling equipment. The decree
still requires the signature of the other parties to the action.
The cost of purchasing and installing the equipment and the
proposed fine have been accrued by NCA #1 and are being held in
a control account. NCA #1 believes that it will have no
additional liability for the violations alleged in the above
mentioned lawsuit after the consent decree has been executed and
entered in the court.
Subsequent to December 31, 1998, the Nevada Public Utilities
Commission gave tentative approval for the merger of the
Company's main customer with another utility company in Nevada.
The ultimate outcome of this merger on NCA #1 is not known at
this time.
7. LONG-TERM DEBT:
BFC has an asset-based line-of-credit with a bank which provides
for borrowing up to the borrowing base (as defined). The
borrowing base was $13,200,000 at December 31, 1998. At
December 31, 1998, outstanding borrowings amounted to $5,150,000,
with interest at a variable rate that approximated 7% at
December 31, 1998. BFC has issued letters of credit totaling
$3,100,000 which further reduces the amount available for
borrowing under the base. This facility is collateralized by
certain oil and gas properties of BFC and is scheduled to convert
to a term note on July 1, 2001. This term loan is scheduled to
have a maturity of either the economic half life of BFC's
remaining reserves on the date of conversion, or July 1, 2006,
whichever is earlier. The borrowing base is based upon the
lender's evaluation of BFC's proved oil and gas reserves,
generally determined semi-annually. The future minimum principal
payments under the term note will be dependent upon the bank's
evaluation of BFC's reserves at that time.
BFC also has an accounts receivable-based credit facility which
includes a revolving line-of-credit with the bank which provides
for borrowings up to $1,500,000. Outstanding borrowings under
this facility amounted to $700,000 at December 31, 1998. This
facility bears interest at prime (7.75% at December 31, 1998).
This facility is collateralized by certain trade receivables of
BFC and has a maturity date of July 1, 1999.
The credit agreement contains various covenants which prohibit or
limit the subsidiary's ability to pay dividends, purchase
treasury shares, incur indebtedness, repay debt to BPC, sell
properties or merge with another entity. Additionally, BFC is
required to maintain certain financial ratios.
As of the petition date, in accordance with current accounting
pronouncements, BPC discontinued accruing interest on its pre-
petition debt obligations except to the extent that the
obligations are secured by collateral believed to have value in
excess of the amounts of the related obligations. If such
interest had continued to be accrued, based on contractual terms
without increase for default provisions, interest expense for
1996 would have been increased by approximately $8,300,000.
During 1996, BPC received approximately $104 million in
litigation settlement proceeds (net of related costs). In 1997,
the Trustee entered into a conditional settlement agreement with
the holders of certain senior claims with respect to the
calculation and payment of post-petition interest and with the
holders of certain subordinated and equity claims who agreed to
not oppose the Plan. Therefore, in 1997, BPC resumed accrual of
interest expense at the amount expected to be paid pursuant to
the Plan (ranging from 5.5% to 8.10%). Accrued interest from the
petition date, or date of the claim, if later, amounting to
$6,302,000 and $45,388,000 was charged to operations in 1998 and
1997, respectively.
See Note 6 for a discussion of long-term debt of NCA #1.
<PAGE>
8. COMMITMENTS:
Office Lease - The Company leases office space under
noncancellable operating leases. Total rental expense was
$216,000; $187,000; and $163,000, in the years ended December
1998, 1997, and 1996, respectively. The total minimum rental
commitments at December 31, 1998 are as follows:
($ in 000's)
1999 $151
2000 124
2001 129
2002 88
$492
9. INCOME TAXES:
Pretax accounting income from continuing operations for the years
ended December 31, 1998, 1997, and 1996 was taxed solely under
domestic jurisdictions. The provision for income taxes was as
follows:
$ in 000's)
1998 1997 1996
Current tax expense (benefit):
U.S. Federal .............................. $ -- $ -- $ 3,917
State ........ ........................... (500) -- 991
Total current tax expense (benefit) . ...... (500) -- 4,908
Deferred tax benefit ....................... -- -- (1,600)
$ (500) $ -- $ 3,308
The difference between the provision for income taxes and the
amounts which would have been reported by applying the statutory
Federal income tax rate to income before provision for income
taxes is as follows:
1998 1997 1996
Tax expense (benefit) by applying
the statutory Federal income tax
rate to pretax income (loss) ...... $ 7,057 $(7,917)$ 39,489
Net operating losses .............. (5,763) 873 (32,582)
State taxes, net of Federal benefit ( 500) -- 689
Effect of alternative minimum tax . -- -- (4,288)
794 (7,044) 3,308
Change in valuation allowance ..... (1,294) 7,044 --
$( 500) $ - $ 3,308
Long-term deferred tax assets and liabilities are comprised of
the following as of December 31, 1998 and 1997:
1998 1997
($ in 000's)
Deferred tax assets:
Net operating loss
carryforward .............. $ 14,630 $ 8,337
Depreciation, depletion,
amortization and impairment 1,188 900
Liabilities recognized for
book purposes prior to
realization for tax
purposes .................. -- 14,839
Gross deferred tax assets . 15,818 24,076
Deferred tax liabilities:
Investment in NCA #1,
primarily depreciation,
depletion and
amortization .............. (1,787) (1,401)
Net deferred tax asset .... 14,031 22,675
Valuation allowance ....... (14,031) (22,675)
$ - $ -
<PAGE>
At December 31, 1998, the Company had Federal income tax net
operating loss carryforwards of $41,800,000 which expire from
2010 through 2013
Under Section 382 of the Internal Revenue Code of 1986, as
amended, if certain significant ownership changes occur, there
could be an annual limitation on the amount of net operating loss
carryforwards which may be utilized. The Company may have
experienced a change in ownership under these rules prior to
December 31, 1997. Consequently, certain net operating loss
carryforwards may be limited. There may be additional
limitations due to the confirmation of the Plan.
10 EMPLOYEE BENEFITS:
Stock Options - In 1998, the Company's Board of Directors
approved the issuance of 45,000 options to its outside directors
to purchase common stock at $9.44 per share. These options
expire in the year 2008
Pro Forma Stock-Based Compensation Disclosures - The Company
applies APB Opinion 25 and related interpretations in accounting
for stock options and warrants which are granted to employees.
Accordingly, no compensation cost has been recognized for grants
of options and warrants to employees since the exercise prices
were not less than the fair value of the Company's common stock
on the grant dates. Had compensation cost been determined based
on the fair value at the grant dates for awards under those plans
consistent with the method of FAS 123, the Company's net loss and
loss per share would have been changed to the pro forma amounts
indicated below.
Year Ended
December 31, 1998
Reported Pro Forma
Loss before extraordinary items ........$ (3,365) $ (3,552)
Extraordinary items .................... 23,681 23,681
Net income .............................$ 20,316 $ 20,129
Basic and diluted earnings per
common share:
Loss before extraordinary items ........$ (.93) $ (.99)
Extraordinary items ....................$ 6.53 $ 6.53
Net income ............................ $ 5.60 $ 5.54
No other options were issued in 1998, 1997 or 1996.
The fair value of each employee option granted in 1998 was
estimated on the date of grant using the Black-Scholes option-
pricing model with the following weighted average assumptions:
Year Ended
December 31,
1998
Expected volatility 73%
Risk-free interest rate 5.5%
Expected dividends -
Expected terms (in years) 10
Subsequent to year-end, the Company issued 240,000 non-qualified
options at an exercise price of $5.00, which expire in the year
2009.
Employee Stock Ownership Plan - On April 28, 1989, BPC adopted the
Bonneville Pacific Corporation Employee Stock Ownership Plan (the
"ESOP"). The ESOP had an allowed claim against BPC of $984,000.
The ESOP was terminated in 1997.
Employee Qualified 401(k) Retirement Plan - Effective January 1,
1990, BPC adopted a qualified retirement plan under Sections
401(a) and 401(k) of the Internal Revenue Code. The Company may
match employees' contributions at the Company's discretion. The
Company did not contribute in 1998, 1997, or 1996.
Management Retention Program - In 1997, the Court approved a
management retention program in order to retain certain key
employees of the subsidiary companies. The retention program
provides for the payment of certain cash severance benefits upon
(a) an employee's termination without cause absent a change in
control, or (b) termination from a change in control.
Additionally, the retention programs provide benefits upon (a) the
death of the employee or (b) the successful confirmation of the
Plan. BFC and BPS accrued $600,000 for the retention program in
1997. In 1998, the Company's Board of Directors expanded the
program to include benefits to some additional company employees.
BPC accrued $316,000 for the retention programs in 1998.
Employment Agreements and Severance and Retention Programs - The Company
has entered into employment contracts with certain key employees. In the event
of a change in control of the Company or termination without cause, the Company
may have to pay the employees an amount based on the average of their previous 5
years compensation. The Company also has a plan which would compensate all
employees in the event of termination without cause. The potential
amount payable under both plans would aggregate $3,974,000.
11. STOCKHOLDERS' EQUITY:
Reverse Stock Split - The Plan provided for a one-for-four reverse
stock split of the Company's common stock. This reverse stock
split was effective November 2, 1998. All references to number
of shares, except shares authorized, and to per share information
in the consolidated financial statements have been adjusted to
reflect the reverse stock split on a retroactive basis.
Treasury Stock - In 1996, 2,289,000 shares of common stock were
returned to BPC as the result of litigation settlements.
1,961,000 shares were received from a significant stockholder, and
recorded as additional paid-in capital at a fair market value of
$5,146,000. The remaining settlements were not with significant
stockholders and therefore, in 1996, BPC recognized a gain of
$185,000 from these transactions. In 1997, an additional
19,000 shares were returned to the Company, at no cost.
At the effective date of the Plan, the treasury stock held by the
Company and the Company stock held by the Trustee was cancelled
with the Company now holding such stock as authorized but not
issued common stock.
Shares Issued - Pursuant to the Plan, during 1998, the Company
issued stock in satisfaction of certain claims. See Note 2 for
a discussion of the shares issued.
Earnings (Loss) Per Common Share - The components of basic and
diluted earnings per share were as follows:
1998 1997 1996
($ in 000's)
Net income (loss) ...................... $ 20,316 $(22,620) $112,827
Average outstanding common
shares ............ ..................... 3,630 2,921 4,533
Dilutive effect of convertible
debentures ................................ -- -- 2,286
Total potential common stock ................. 3,630 2,921 6,819
Earnings (loss) per share:
Basic ........................................ 5.60 (7.74) 24.89
Diluted ...................................... 5.60 (7.74) 16.55
No adjustments were made to net income because the impact of
potential common stock would have been antidilutive to income for
continuing operations in 1998 and 1997, and in 1996 no interest
expense was recorded in accordance with the provisions of SOP 90-7.
Due to the issuance of common stock in conjunction with the
effectiveness of the Plan, the earnings per share noted above may
not be reflective of earnings in future periods.
12. CONCENTRATIONS OF CREDIT RISK:
Approximately 87% of the Company's accounts receivable at
December 31, 1998 result from BFC's crude and natural gas sales
and/or joint interest billings to companies in the oil and gas
industry. This concentration of customers and joint interest
owners may impact the Company's overall credit risk, either
positively or negatively, since these entities may be similarly
affected by changes in economic or other conditions. In
determining whether or not to require collateral from a customer
or joint interest owner, the Company analyzes the entity's net
worth, cash flows, earnings, and credit ratings and other factors.
Receivables are generally not collateralized. Historical credit
losses incurred on trade receivables by the Company have been
insignificant.
The nature of the power generation business is such that each
facility generally relies on one power or thermal sales agreement
with a single electric customer for substantially all, if not all,
of such facility's revenue over the life of the project. The
power and thermal sales agreements are generally long-term
agreements, covering the sale of electricity or thermal for
initial terms of 20 or 30 years. However, the loss of any one
major power or thermal sales agreement with any of these customers
could have a material adverse effect on cash flow and, as a
result, on results of operations.
Furthermore, each power generation facility may depend on a single
or limited number of entities to purchase thermal energy, or to
supply or transport natural gas to such facility. The failure of
any one customer, thermal host, gas supplier or gas transporter
to fulfill its contractual obligations could have a material
adverse effect the Company's business and results of operations.
13. FINANCIAL INSTRUMENTS:
Statement of Financial Accounting Standards No. 107 and 127
requires certain entities to disclose the fair value of certain
financial instruments in their financial statements. Accordingly,
management's best estimate is that the carrying amount of cash,
receivables, notes payable, accounts payable, undistributed
revenue, and accrued expenses approximates fair value of these
instruments.
Energy Financial Instruments - BFC uses energy financial
instruments and long-term user contracts to minimize its risk of
price changes in the spot and fixed price natural gas and crude
oil markets. Energy risk management products used include
commodity futures and options contracts, fixed-price swaps, and
basis swaps. Pursuant to Company guidelines, BFC is to engage in
these activities only as a hedging mechanism against price
volatility associated with pre-existing or anticipated gas or
crude oil sales in order to protect profit margins. As of
December 31, 1998, BFC has financial and physical contracts which
hedge approximately 6 bcf of production through December 2001.
Current market value of the hedging contracts was a favorable
$701,000 and an unfavorable $60,000 as of December 31, 1998 and
1997, respectively. These amounts are not reflected in the
accompanying financial statements. In the event energy financial
instruments do not qualify for hedge accounting, the difference
between the current market value and the original contract value
would be currently recognized in the statement of operations. In
the event that the energy financial instruments are terminated
prior to the delivery of the item being hedged, the gains and
losses at the time of the termination are deferred until the
period of physical delivery. Such deferrals were immaterial in
all periods presented.
<PAGE>
14. SEGMENT INFORMATION:
The Company has identified the following segments: BFC, BNC, and
BPS. BFC is primarily engaged in oil and gas production and gas
marketing. BNC owns a 50% interest in a company engaged in
cogeneration activities. BPS is primarily engaged in providing
operational and maintenance services to cogeneration plants. At
December 31, 1998, BPS also had an interest in an additional
cogeneration facility in the start-up phase in Mexico.
The accounting policies of the segments are the same as those
described in the summary of significant accounting policies. The
Company evaluates performance based on profit or loss from
operations before reorganization items and income taxes.
<TABLE>
<CAPTION>
BFC BNC BPS Corporate Total
1998
($ in 000's)
<S> <C> <C> <C> <C> <C> <C>
Revenues from external
customers $ 20,699 - $ 4,107 $ 1,653 $ 26,459
Interest income from
non-reorganization items 57 34 103 182 376
Interest expense 239 - - 6,302 6,541
Operating expenses,
including impairment 21,312 - 3,864 3,359 28,535
Selling, general and
administrative 1,232 42 636 1,260 3,170
Equity in investee earnings - 5,130 - - 5,130
Segment profit (loss)
before reorganization
items, taxes, and
extraordinary items ....... (1,693) 5,122 (290) 8,934 (5,795)
Segment assets ............ 22,894 10,669 3,561 9,490 46,614
1997
Revenues from external
customers .................... $ 16,071 $ - $ 4,127 $ 1,758 $ 21,956
Interest income from
non-reorganization items ..... 62 179 329 - 570
Interest expense ............. 83 - - 45,388 45,471
Operating expenses,
including impairment ........ 14,855 - 2,973 1,728 19,556
Selling, general and
administrative ............... 990 22 546 876 2,434
Equity in investee earnings .. - 3,902 - - 3,902
Segment profit (loss)
before reorganization
items and taxes ............ 611 4,059 941 (46,219) (40,608)
Segment assets .............. 16,054 7,397 6,702 157,473 187,626
1996
Revenues from external
customers $ 15,026 $ - $ 4,155 $ 1,513 $ 20,694
Interest income from
non-reorganization items 41 30 282 51 404
Interest expense 272 - - 283 555
Operating expenses,
including impairment 10,629 - 3,070 1,543 15,242
Selling, general and
administrative 472 30 207 996 1,705
Equity in investee earnings - 3,380 - - 3,380
Segment profit (loss)
before reorganization
items and taxes 3,694 3,378 1,760 (1,188) 7,644
Segment assets 14,524 10,438 7,973 132,665 165,600
</TABLE>
<PAGE>
15 OIL AND GAS PRODUCING ACTIVITIES:
BFC's oil and gas producing activities are all located in the
United States. The following is certain information with respect
to the activities.
<TABLE>
<CAPTION>
($ in 000's)
<S> December 31,
<C> <C>
1998 1997
Capitalized Costs Relating to Oil and Gas Properties
Unproved oil and gas properties ............................ $ 2,745 $ 1,900
Proved oil and gas properties .............................. 29,521 26,533
Gas gathering system ....................................... 158 158
32,424 28,591
Accumulated depreciation, depletion,
amortization and
impairment ............................................... (18,681) (16,709)
Net capitalized costs ...................................... $ 13,743 $ 11,882
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
December 31,
1998 1997 1996
($ in 000's)
Costs Incurred in Oil and Gas Property
Acquisition, Exploration and Development
Activities
<S> <C> <C> <C>
Acquisition of properties:
Proved $ 95 $ 2,230 $ 63
Unproved 473 - -
568 2,230 63
Exploration costs 1,932 599 299
Development costs 3,784 1,812 959
$6,284 $ 4,641 $1,321
Results of Operations from Producing
Activities
Oil and gas sales $6,758 $ 6,429 $5,262
Expenses:
Production costs 3,004 2,779 2,285
Exploration costs 556 772 299
Depreciation, depletion, amortization and
impairment 3,944 2,199 1,143
Total Expenses 7,504 5,750 3,727
Results of operations from producing
activities (excluding corporate overhead
and interest costs) $ (746) $ 679 $1,535
</TABLE>
Oil and Gas Reserves - The following quantity and value information is based on
prices as of the end of each respective reporting period. No price escalations
were assumed. Operating costs and production taxes were deducted in determining
the quantity and value information. Such costs were estimated based on current
costs and were not adjusted to anticipate increases due to inflation or other
factors. No deductions were made for general overhead, depreciation and
interest.
The determination of oil and gas reserves is based on estimates and is highly
complex and interpretive. The estimates are subject to continuing change as
additional information becomes available and an accurate determination of the
reserves may not be possible for several years after discovery. Reserve
information presented herein is based on reports prepared by an independent
petroleum engineer.
Estimated Quantities of Proved Oil and Gas Reserves - The following is a
reconciliation of BFC's interest in net quantities of proved oil and gas
reserves. Proved reserves are the estimated quantities of crude oil and
natural gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Estimated reserves of oil
(barrels) and natural gas (thousands of cubic feet) as of December 31, 1998,
1997, and 1996, and the changes thereto for the years then ended are as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
For the Years Ended December 31,
1998 1997 1996
Gas Oil Gas Oil Gas Oil
------------------------------------------
Proved developed and
undeveloped reserves:
Beginning of year 23,140 298 26,512 227 19,807 207
Extensions and discoveries 5,011 34 427 32 935 44
Purchases of minerals in place - - 916 99 506 -
Production (3,272) (65) (3,146) (63) (2,744) (58)
Revisions of previous estimates 976 (101) (1,569) 3 8,008 34
End of year 25,855 166 23,140 298 26,512 227
Proved developed reserves:
Beginning of year 22,623 298 25,483 188 19,290 168
End of year 25,855 166 22,623 298 25,483 188
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves
Estimated discounted future net cash flows and changes therein
were determined in accordance with Statement of Financial
Accounting Standards No. 69. Certain information concerning the
assumptions used in computing the valuation of proved reserves
and their inherent limitations are discussed below. The Company
believes such information is essential for a proper understanding
and assessment of the data presented.
Future cash inflows are computed by applying year-end prices of
oil and gas relating to BFC's proved reserves to the year-end
quantities of those reserves.
The assumptions used to compute the proved reserve valuation do
not necessarily reflect BFC's expectations of actual revenues to
be derived from those reserves nor their present worth.
Assigning monetary values to the reserve quantity estimation
process does not reduce the subjective and ever-changing nature
of such reserve estimates.
Additional subjectivity occurs when determining present values
because the rate of producing the reserves must be estimated. In
addition to subjectivity inherent in predicting the future,
variations from the expected production rate also could result
directly or indirectly from factors outside BFC's control, such
as unintentional delays in development, environmental concerns
and changes in prices or regulatory controls.
The reserve valuation assumes that all reserves will be disposed
of by production. However, if reserves are sold in place,
additional economic considerations also could affect the amount
of cash eventually realized.
Future development and production costs are computed by
estimating the expenditures to be incurred in developing and
producing the proved oil and gas reserves at the end of the year,
based on year-end costs and assuming continuation of existing
economic conditions.
Future income tax expense has not been provided based on the
availability of net operating loss carryforwards and other
deductions. The usage of these carryforwards may be limited
based upon a past change in ownership of BPC. There may be
additional limitations on the availability of net operating loss
carryforwards due to the confirmation of the Plan.
A discount rate of 10% per year was used to reflect the timing of
the future net cash flows.
<TABLE>
<S>
At December 31,
($ in 000's)
<C> <C> <C>
1998 1997 1996
Future cash inflows ............................................. $ 49,428 $46,859 $89,985
Future production and development
costs ........................................................... (18,507) (18,155) (26,608)
30,921 28,704 63,377
10% annual discount for estimated
timing of cash flows ............................................ (10,426) (9,075) (23,366)
Standardized measure of discounted
future net cash flows ........................................... $ 20,495 $19,629 $40,011
</TABLE>
The following are principal sources of changes in the
standardized measure of discounted net cash flows:
<TABLE>
For the Years Ended
December 31,
1998 1997 1996
($ in 000's)
<S> <C> <C> <C>
Standardized measure of
discounted future net cash
flows, beginning of year ........................................ $ 19,629 $ $ 40,011 $ 10,233
Sales and transfers of oil and
gas produced, net of
production costs ................................................ (3,754) (3,650) ( 2,977)
Net changes in prices and
production costs ................................................ (999) (20,485) 19,056
Extensions, discoveries, and
improved recovery, less
related costs ................................................... 4,699 756 3,226
Purchases of reserves in-place .................................. 147 1,610 436
Revisions of future
development costs ............................................... 87 1,069 (1,200)
Revisions of previous quantity
estimates ....................................................... 279 (1,098) 12,475
Accretion of discount ........................................... 1,963 4,001 1,023
Changes in production rates
(timing) and other .............................................. (1,556) (2,585) (2,261)
Standardized measure of
discounted future net cash
flows, end of year .............................................. $ 20,495 $ $ 19,629 $ 40,011
</TABLE>
Oil and gas prices at December 31, 1998, 1997, and 1996 of
$10.69, $16.91, and $25.60, respectively, per barrel of oil and
$1.84, $1.81, and $3.17, respectively, per thousand cubic feet of
gas were used in the estimation of BFC's reserves and future net
cash flows.
<PAGE>
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
BONNEVILLE PACIFIC CORPORATION
Date: March 30, 1999 (s)Clark M. Mower, President
(Principal Executive Officer)
Date: March 30, 1999 (s)R. Stephen Blackham
(Principal Financial and
Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
Date: March 30, 1999 (s)James W. Bernard, Chairman
Date: March 30, 1999 (s)Ralph F. Cox, Director
Date: March 30, 1999 (s)Michael R. Devitt, Director
Date: March 30, 1999 (s)Harold E. Dittmer, Director
Da (s)Michael D. Fowler, Director
Date: March 30, 1999 (s)Harold H. Robinson, III,
Director
Date: March 30, 1999 (s)Steven H. Stepanek, Director
ARTICLE 1 - PURPOSES, EFFECTIVENESS AND TYPE OF PLAN
1.1. Purposes. The purposes of this Plan are to promote the
success of the Company and advance the interests of the Company and
its shareholders by providing an additional means through the grant
of stock options to attract, motivate, retain and reward non-
employee directors of the Company with incentives for high levels
of individual performance and improved financial performance of the
Company.
1.2. Effectiveness. This Plan shall be effective as of
November 2, 1998. This Plan will remain in effect until it is
terminated by the Committee or until November 2, 2008, whichever
occurs first.
1.3. Type of Plan. This Plan is a non-statutory or non-
qualified stock option plan pursuant to which Options may be
granted to non-employee directors of the Company. This Plan is
intended to meet the requirements of Rule 16b-3 of the Exchange
Act.
ARTICLE 2 - DEFINITIONS
2.1. Definitions. Unless the context requires otherwise, the
following defined terms will govern the construction of this Plan
and of any stock option agreements entered into pursuant to this
Plan:
2.1.1. "Board" shall mean the Board of Directors of the
Company.
2.1.2. "Commission" shall mean the Securities and
Exchange Commission.
2.1.3. "Committee" shall mean the Compensation Committee
of the Board. The Committee shall administer the Plan.
2.1.4. "Common Stock" shall mean the Common Stock of the
Company and such other securities or property as may become subject
to Options, pursuant to an adjustment made under Section 4.3 of
this Plan.
2.1.5. "Company" shall mean Bonneville Pacific
Corporation
2.1.6. "Eligible Participant" shall mean non-employee
directors of the Company as of November 2, 1998..
2.1.7. "Exchange Act" shall mean the Securities Exchange
Act of 1934, as amended from time to time.
2.1.8. "Grant Agreement" shall mean the agreement
between the Company and the Non-Employee Director of the Company
that grants such Non-Employee Director Option pursuant to this
Plan.
2.1.9. "Grant Date" shall mean the date upon which the
Option is granted.
2.1.10. "Option" shall mean an option to purchase Common
Stock under this Plan.
2.1.11. "Option Agreement" shall mean any writing
setting forth the terms of an Option that has been authorized by
the Committee.
2.1.12. "Option Period" shall mean the period beginning
on the Grant Date and ending ten years thereafter, unless the Grant
Agreement provides for a different Option Period.
2.1.13. "Option Price" shall mean $9.44 per share.
2.1.14. "Option Stock" shall mean Common Stock issued or
issuable by the Company pursuant to the valid exercise of an
Option.
2.1.15. "Participant" shall mean a person who has been
granted an Option under this Plan.
2.1.16. "Plan" shall mean this 1998 Non-Employee
Director's Stock Option Plan.
2.1.17 "Securities Act" shall mean the Securities Act of
1933, as amended from time to time.
ARTICLE 3 - ADMINISTRATION
3.1. Committee. This Plan shall be administered by the
Committee. All actions of the Committee with respect to the
administration of this Plan shall be taken pursuant to a majority
vote or by the unanimous written consent of its members. If the
Board, in its discretion, does not appoint such a Committee, the
Board itself shall administer this Plan and take such actions as
the Committee is authorized to take hereunder.
3.2. Plan Options; Interpretation; Powers of Committee.
Subject to the express provisions of this Plan, the Committee shall
have the authority:
(a) to approve the forms of Option Agreements;
(b) to construe and interpret this Plan and any
agreements defining the rights and obligations of the Company
and Participants under this Plan, further define the terms
used in this Plan, and prescribe, amend and rescind rules and
regulations relating to the administration of this Plan; and
(c) to make all other determinations and take such other
action as contemplated by this Plan or as may be necessary or
advisable for the administration of this Plan and the
effectuation of its purposes.
3.3. Binding Determinations. Any action taken by, or
inaction of, the Company, the Board or the Committee relating or
pursuant to this Plan shall be within the absolute discretion of
that entity or body and shall be conclusive and binding upon all
persons. No member of the Board or the Committee or officer of the
Company or any Subsidiary, shall be liable for any such action or
inaction of the entity or body, of another person or, except in
circumstances involving bad faith, of himself or herself. Subject
only to compliance with the express provisions hereof, the Board
and the Committee may act in their absolute discretion in matters
within their authority related to this Plan.
3.4. Reliance on Experts. In making any determination or in
taking or not taking any action under this Plan, the Committee may
obtain and may rely upon the advice of experts, including
professional advisors to the Company. No director, officer or
agent of the Company shall be liable for any such action or
determination taken or made or omitted in good faith.
3.5. Delegation. The Committee may delegate ministerial,
non-discretionary functions to individuals who are officers or
employees of the Company.
ARTICLE 4 - SHARES AVAILABLE FOR OPTIONS
4.1. Shares Available for Options. The capital stock that
may be delivered under this Plan shall be shares of the Company's
authorized but unissued Common Stock and any shares of its Common
Stock held as treasury shares.
4.2. Number of Shares. The maximum number of shares of
Common Stock of the Company that may be issued pursuant to Options
granted to Participants under this Plan is 45,000 shares, subject
to adjustments contemplated by Section 4.3.
4.3. Adjustments. If there shall occur any extraordinary
dividend or other extraordinary distribution in respect of the
Common Stock (whether in the form of cash, Common Stock, other
securities or other property) or any recapitalization, stock split,
reorganization, merger, combination, consolidation, split-up, spin-
off, combination, repurchase or exchange of Common Stock or other
securities of the Company, or if there shall occur any other like
corporate transaction or event with respect to the Common Stock,
then the Committee shall, in such manner and to such extent (if
any) as it deems appropriate and equitable: (1) proportionately
adjust any or all of (a) the number and type of Common Stock which
thereafter may be made the subject of Options (including the
specific maximum number of shares set forth elsewhere in this
Plan), (b) the amount of Common Stock subject to any or all
outstanding Options, (c) the grant, purchase or exercise price of
any or all outstanding Options, and (d) the Common Stock issuable
upon exercise of any or all outstanding Options; or (2) in the case
of an extraordinary dividend or other distribution, merger,
reorganization, consolidation, combination, sale of assets, split-
up, exchange or spin-off, make provision for a cash payment or for
the substitution or exchange of any or all outstanding Common Stock
deliverable to the holder of any or all outstanding Options based
upon the distribution or consideration payable to holders of the
Common Stock or other securities of the Company upon or with
respect to such event.
ARTICLE 5 - GRANT PROVISIONS
5.1. Participation. Options under this Plan shall be made
only to persons who are non-employee directors of the Company as of
November 2, 1998.
5.2. Grant of Option. Each person who was a non-employee
Director of the Company as of November 2, 1998 is hereby granted
an option to purchase 7,500 shares of the Company's Common Stock
at the price of $9.44 per share (adjusted for a November 3, 1998 1-
for-4 reverse split).
5.3. Payment of Option Price. The Option Price will be
payable to the Company in United States Dollars in cash or by
check, or such other legal consideration as may be approved by the
Committee, in its discretion. For example, the Committee, in its
discretion, may permit a particular Optionee to pay all or a
portion of the Option Price, and/or the tax withholding liability
set forth in Section 6.1 below, with respect to the exercise of an
Option either by surrendering shares of Common Stock already owned
by such Optionee or by withholding shares of Option Stock, provided
that the Committee determines that the fair market value of such
surrendered Common Stock or withheld Option Stock is equal to the
corresponding portion of such Option Price and/or tax withholding
liability, as the case may be, to be paid for therewith.
5.4. Option Period and Exercisability. Each Option granted
under this Plan and all rights or obligations thereunder shall
commence on the Grant Date and expire at the earlier of ten (10)
years thereafter.
5.5. Procedure to Exercise Option. Any exercisable Option
shall be deemed to be exercised when the Secretary of the Company
receives written notice of such exercise from the Participant
specifying the number of full shares of Common Stock to be
purchased and (i) accompanied by full payment of the option price
thereof and the amount of applicable withholding taxes, or (ii) in
the event that the Committee elects in accordance with Section 6.1
of this Plan to withhold a portion of the Common Stock, upon
determination by the Committee that written notice is accompanied
by sufficient payment of the option price to permit exercise of the
Option.
ARTICLE 6 - TAX WITHHOLDING
6.1. Tax Withholding. Upon any exercise of any Option, the
Company shall have the right at its option to (i) require the
Participant to pay or provide for payment of the amount of any
taxes which the Company may be required to withhold with respect to
such transaction. In any case where a tax is required to be
withheld in connection with the delivery of Common Stock under this
Plan, the Committee may grant (either at the time the Option is
granted or thereafter) to the Participant the right to elect,
pursuant to such rules and subject to such conditions as the
Committee may establish, to have the Company reduce the number of
shares to be delivered by (or otherwise reacquire) the appropriate
number of shares valued at their then fair market value, to satisfy
such withholding obligation.
6.2. Tax Loans. The Committee may, in its discretion,
authorize a loan to a Participant in the amount of any taxes which
the Company may be required to withhold with respect to Common
Stock received by the Participant. Such a loan shall be for a
term, at a rate of interest and pursuant to such other terms and
conditions as the Committee, under applicable law, may establish.
ARTICLE 7 - TRANSFER RESTRICTIONS
7.1. Limited Transferability of Shares. Each Participant is
required to understand that the Common Stock has not been
registered under the Securities Act, and that such Common Stock may
not be freely transferable and must be held indefinitely unless
such Common Stock is either registered under the Securities Act or
an exemption from registration is available. Each Participant is
required to understand that the Company is under no obligation to
register the Common Stock. Upon exercise of any Option, the
Participant must agree to purchase the Common Stock for his or her
own account and not with a view to distribution within the meaning
of the Securities Act.
ARTICLE 8 - MISCELLANEOUS.
8.1. Choice of Law. This Plan, all Options, all Option
Agreements and all other related documents shall be governed by,
and construed in accordance with, the laws of the State of Delaware
8.2. Compliance with Laws. This Plan, the granting and
vesting of Options under this Plan and the issuance and delivery of
Common Stock under this Plan or under Options granted hereunder are
subject to compliance with all applicable federal and state laws,
rules and regulations (including, but not limited to, state and
federal securities laws and federal margin requirements) and to
such approvals by any listing, regulatory or governmental authority
as may, in the opinion of counsel for the Company, be necessary or
advisable in connection therewith. Any securities delivered under
this Plan shall be subject to such restrictions, and the person
acquiring such securities shall, if requested by the Company,
provide such assurances and representations to the Company as the
Company may deem necessary or desirable to assure compliance with
all applicable legal requirements.
8.3. Severability. In the event that any provision of this
Plan shall be held by a court of competent jurisdiction to be
invalid and unenforceable, the remaining provisions of this Plan
shall continue in full force and effect.
8.4. Captions. Captions and headings are given to the
sections and subsections of this Plan solely as a convenience to
facilitate reference. Such headings shall not be deemed in any way
material or relevant to the construction or interpretation of this
Plan or any provision thereof.
8.5. Non-Exclusivity of Plan. Nothing in this Plan shall
limit or be deemed to limit the authority of the Board or the
Committee to grant options or authorize any other compensation,
with or without reference to the Common Stock, under any other plan
or authority.
This Plan was adopted November 2, 1998 by the Board of
Directors of the Company.
BONNEVILLE PACIFIC CORPORATION
1999
EXECUTIVE OFFICERS
STOCK OPTION PLAN
ARTICLE 1 - PURPOSES, EFFECTIVENESS AND TYPE OF PLAN
1.1. Purposes. The purposes of this Plan are to promote the
success of the Company and advance the interests of the Company and
its shareholders by providing an additional means through the grant
of stock options to attract, motivate, retain and reward the
current Executive Officers of the Company with incentives for high
levels of individual performance and improved financial performance
of the Company.
1.2. Effectiveness. This Plan shall be effective as of
January 7, 1999. This Plan will remain in effect until it is
terminated by the Committee or until 12:00 midnight, January 6,
2009, whichever occurs first.
1.3. Type of Plan. This Plan is a non-statutory or non-
qualified stock option plan pursuant to which Options may be
granted to the current Executive Officers of the Company. This
Plan is intended to meet the requirements of Rule 16b-3 of the
Exchange Act.
ARTICLE 2 - DEFINITIONS
2.1. Definitions. Unless the context requires otherwise, the
following defined terms will govern the construction of this Plan
and of any stock option agreements entered into pursuant to this
Plan:
2.1.1. "Board" shall mean the Board of Directors of the
Company.
2.1.2. "Commission" shall mean the Securities and
Exchange Commission.
2.1.3. "Committee" shall mean the Compensation Committee
of the Board. The Committee shall administer the Plan.
2.1.4. "Common Stock" shall mean the Common Stock of the
Company and such other securities or property as may become subject
to Options, pursuant to an adjustment made under Section 4.3 of
this Plan.
2.1.5. "Company" shall mean Bonneville Pacific
Corporation
2.1.6. "Eligible Participant" shall mean Clark M. Mower,
Steven H. Stepanek and/or Todd L. Witwer.
2.1.7. "Exchange Act" shall mean the Securities Exchange
Act of 1934, as amended from time to time.
2.1.8. "Executive Officers" shall mean Clark M. Mower,
Steven H. Stepanek and Todd L. Witwer.
2.1.9. "Grant Agreement" shall mean the agreement
between the Company and the Executive Officers of the Company that
grants such Executive Officers Options pursuant to this Plan.
2.1.10. "Grant Date" shall mean January 7, 1999.
2.1.11. "Option" shall mean an option to purchase Common
Stock under this Plan.
2.1.12. "Option Period" shall mean the period beginning
on the Grant Date and ending ten years thereafter, unless the Grant
Agreement provides for a different Option Period.
2.1.13. "Option Price" shall mean $5.00 per share, the
closing price of the Company's common stock on January 7, 1999 as
reported by the OTC Electronic Bulletin Board.
2.1.14. "Option Shares" or "Option Stock" shall mean
Common Stock issued or issuable by the Company pursuant to the
valid exercise of an Option.
2.1.15. "Participant" shall mean a person who has been
granted an Option under this Plan.
2.1.16. "Plan" shall mean this 1999 Executive Officers
Stock Option Plan.
2.1.17 "Securities Act" shall mean the Securities Act of
1933, as amended from time to time.
ARTICLE 3 - ADMINISTRATION
3.1. Committee. This Plan shall be administered by the
Committee. All actions of the Committee with respect to the
administration of this Plan shall be taken pursuant to a majority
vote or by the unanimous written consent of its members. If the
Board, in its discretion, does not appoint such a Committee, the
Board itself shall administer this Plan and take such actions as
the Committee is authorized to take hereunder.
3.2. Plan Options; Interpretation; Powers of Committee.
Subject to the express provisions of this Plan, the Committee shall
have the authority:
(a) to approve the form of Grant Agreements;
(b) to construe and interpret this Plan and any
agreements defining the rights and obligations of the Company
and Participants under this Plan, further define the terms
used in this Plan, and prescribe, amend and rescind rules and
regulations relating to the administration of this Plan; and
(c) to make all other determinations and take such other
action as contemplated by this Plan or as may be necessary or
advisable for the administration of this Plan and the
effectuation of its purposes.
3.3. Binding Determinations. Any action taken by, or
inaction of, the Company, the Board or the Committee relating or
pursuant to this Plan shall be within the absolute discretion of
that entity or body and shall be conclusive and binding upon all
persons. No member of the Board or the Committee or officer of the
Company or any Subsidiary, shall be liable for any such action or
inaction of the entity or body, of another person or, except in
circumstances involving bad faith, of himself or herself. Subject
only to compliance with the express provisions hereof, the Board
and the Committee may act in their absolute discretion in matters
within their authority related to this Plan.
3.4. Reliance on Experts. In making any determination or in
taking or not taking any action under this Plan, the Committee may
obtain and may rely upon the advice of experts, including
professional advisors to the Company. No director, officer or
agent of the Company shall be liable for any such action or
determination taken or made or omitted in good faith.
3.5. Delegation. The Committee may delegate ministerial,
non-discretionary functions to individuals who are officers or
employees of the Company.
ARTICLE 4 - SHARES AVAILABLE FOR OPTIONS
4.1. Shares Available for Options. The capital stock that
may be delivered under this Plan shall be shares of the Company's
authorized but unissued Common Stock and any shares of its Common
Stock held as treasury shares.
4.2. Number of Shares. The maximum number of shares of
Common Stock of the Company that may be issued pursuant to Options
granted to Participants under this Plan is 240,000 shares, subject
to adjustments contemplated by Section 4.3.
4.3. Adjustments. If there shall occur any extraordinary
dividend or other extraordinary distribution in respect of the
Common Stock (whether in the form of cash, Common Stock, other
securities or other property) or any recapitalization, stock split,
reorganization, merger, combination, consolidation, split-up, spin-
off, combination, repurchase or exchange of Common Stock or other
securities of the Company, or if there shall occur any other like
corporate transaction or event with respect to the Common Stock,
then the Committee shall, in such manner and to such extent (if
any) as it deems appropriate and equitable: (1) proportionately
adjust any or all of (a) the number and type of Common Stock which
thereafter may be made the subject of Options (including the
specific maximum number of shares set forth elsewhere in this
Plan), (b) the amount of Common Stock subject to any or all
outstanding Options, (c) the grant, purchase or exercise price of
any or all outstanding Options, and (d) the Common Stock issuable
upon exercise of any or all outstanding Options; or (2) in the case
of an extraordinary dividend or other distribution, merger,
reorganization, consolidation, combination, sale of assets, split-
up, exchange or spin-off, make provision for a cash payment or for
the substitution or exchange of any or all outstanding Common Stock
deliverable to the holder of any or all outstanding Options based
upon the distribution or consideration payable to holders of the
Common Stock or other securities of the Company upon or with
respect to such event.
ARTICLE 5 - GRANT PROVISIONS
5.1. Participation. Options under this Plan shall be made
only to persons who are Executive Officers of the Company as of
January 7, 1999, which are the following: Clark M. Mower, Steven H.
Stepanek and Todd L. Witwer.
5.2. Grant of Option. The Company hereby grants, pursuant to
this Plan, each of the Participants, an Option to purchase the
following number of shares of the Company's Common Stock: (a)
Clark M. Mower-100,000 Shares; (b) Steven H. Stepanek- 75,000
Shares; and (c) Todd L. Witwer - 65,000 Shares
5.3. Vesting of Options. The Options granted pursuant
to the Plan shall vest in five equal installments ("Vesting
Periods"), each of which shall entitle the Participant to purchase
twenty percent (20%) of the total Option Stock related to such
Option. Subject to the applicable terms of Section 5.6 hereof, the
Options granted under this Plan shall vest as follows:
Clark M. Mower
Vesting Date Number of Option Shares
January 7, 1999 20,000
January 1, 2000 20,000
January 1, 2001 20,000
January 1, 2002 20,000
January 1, 2003 20,000
Total 100,000
Steven H. Stepanek
Vesting Date Number of Option Shares
January 7, 1999 15,000
January 1, 2000 15,000
January 1, 2001 15,000
January 1, 2002 15,000
January 1, 2003 15,000
Total 75,000
Todd L. Witwer
Vesting Date Number of Option Shares
January 7, 1999 13,000
January 1, 2000 13,000
January 1, 2001 13,000
January 1, 2002 13,000
January 1, 2003 13,000
Total 65,000
5.4 Accelerated Vesting for Change of Control. In the event
there is a "Change of Control Event" as described in this Plan, the
Options shall vest immediately. For purposes of this Plan, a
"change in control" will be deemed to have occurred on the first to
occur of any of the following events:
(a) As a result of a cash tender offer, stock exchange
offer or other takeover device, any person, as that
term is used in Section 13(d) and 14(b)(2) of the
Securities Exchange Act of 1934, is or becomes a
beneficial owner, directly or indirectly, of stock of
Employer representing thirty percent (30%) or more of
the total voting power of Employer's then outstanding
securities;
(b) Any material realignment of the Board of Directors
of Employer or change in officers of Employer
resulting from a concerted shareholder action,
including without limitation a proxy fight, voting
trusts or pooling arrangements;
(c) Any merger, consolidation or other reorganization of
Employer with any entity, other than its affiliates,
whereby Employer is not the surviving entity or the
shareholders of Employer otherwise fail to retain
substantially the same direct or indirect ownership in
Employer or its affiliates immediately after any such
merger, consolidation or reorganization;
(d) The sale of all or substantially all of the assets
of the Company, including all or substantially all of
the company's interest in either the assets or the
stock of either of the Company's two subsidiaries,
Bonneville Nevada Corporation (BNC) with its interest
in the Nevada Cogeneration Project (NCA#1), or
Bonneville Fuels Corporation (BFC).
5.5. Payment of Option Price. The Option Price will be
payable to the Company in United States Dollars in cash or by
check, or such other legal consideration as may be approved by the
Committee, in its discretion. For example, the Committee, in its
discretion, may permit a particular Optionee to pay all or a
portion of the Option Price, and/or the tax withholding liability
set forth in Section 6.1 below, with respect to the exercise of an
Option either by surrendering shares of Common Stock already owned
by such Optionee or by withholding shares of Option Stock, provided
that the Committee determines that the fair market value of such
surrendered Common Stock or withheld Option Stock is equal to the
corresponding portion of such Option Price and/or tax withholding
liability, as the case may be, to be paid for therewith.
5.6. Option Period and Exercisability. Each Option shall
become exercisable by the Participant beginning on the date of
vesting and must be exercised, if at all, by 12:00 midnight,
January 6, 2009. In order for an installment of an Option granted
under this Plan to vest as provided in Section 5.3 hereof, the
Participant must be an employee of the Company, or of a subsidiary
of the Company, on the Vesting Date. All Option installments
which do not vest pursuant to paragraph 5.3 hereof, shall
immediately expire. Notwithstanding anything else contained herein
to the contrary, in the event of the death of a Participant, the
Option Shares which would have vested on the next Vesting Date,
shall vest on the date of the death of such Participant if such
Participant was an employee of the Company or of a subsidiary of
the Company on the date of his death.
5.7. Procedure to Exercise Option. Any vested Option shall
be deemed to be exercised when the Secretary of the Company
receives written notice of such exercise from the Participant
specifying the number of full shares of Common Stock to be
purchased and (i) accompanied by full payment of the option price
thereof and the amount of applicable withholding taxes, or (ii) in
the event that the Committee elects in accordance with Section 6.1
of this Plan to withhold a portion of the Common Stock, upon
determination by the Committee that written notice is accompanied
by sufficient payment of the option price to permit exercise of the
Option. Subject to the requirements of Regulation T (as in effect
from time to time) promulgated under the Securities Exchange Act of
1934, as amended, the Board of Directors may implement procedures
to allow a broker chosen by a Participant to make payment of all or
any portion of the option price payable upon the exercise of an
Option and receive, on behalf of such Optionee, all or any portion
of the shares of the Common Stock issuable upon such exercise.
ARTICLE 6 - TAX WITHHOLDING
6.1. Tax Withholding. Upon any exercise of any Option, the
Company shall have the right at its option to (i) require the
Participant to pay or provide for payment of the amount of any
taxes which the Company may be required to withhold with respect to
such transaction. In any case where a tax is required to be
withheld in connection with the delivery of Common Stock under this
Plan, the Committee may grant (either at the time the Option is
granted or thereafter) to the Participant the right to elect,
pursuant to such rules and subject to such conditions as the
Committee may establish, to have the Company reduce the number of
shares to be delivered by (or otherwise reacquire) the appropriate
number of shares valued at their then fair market value, to satisfy
such withholding obligation.
6.2. Tax Loans. The Committee may, in its discretion,
authorize a loan to a Participant in the amount of any taxes which
the Company may be required to withhold with respect to Common
Stock received by the Participant. Such a loan shall be for a
term, at a rate of interest and pursuant to such other terms and
conditions as the Committee, under applicable law, may establish.
ARTICLE 7 - TRANSFER RESTRICTIONS
7.1. Restriction on Transfer. An Option granted under the
Plan is not transferable by the Participant otherwise than by
testamentary will or the laws of descent and distribution and,
during the Participant's lifetime, may be exercised only by the
Participant or the Participant's guardian or legal representative.
Except as permitted by the preceding sentence, neither this Option
nor any of the rights and privileges conferred thereby shall be
transferred, assigned, pledged, or hypothecated in any way (whether
by operation of law or otherwise), and no such option, right, or
privilege shall be subject to execution, attachment, or similar
process. Upon any attempt to transfer this Option, or of any right
or privilege conferred thereby, contrary to the provisions hereof,
or upon the levy of any attachment or similar process upon such
option, right, or privilege, this Option and any such rights and
privileges shall immediately become null and void.
7.2. Registration of Option Shares. The Option Shares have
not been registered with the Securities and Exchange Commission.
The Common Stock issuable upon the exercise of an Option may not
be freely transferable and must be held indefinitely unless such
Common Stock is either registered under the Securities Act or an
exemption from registration is available. The Company shall use its
best efforts to register the shares underlying the options on Form
S-8 and keep such Registration in effect with the Securities and
Exchange Commission as soon as practical.
ARTICLE 8 - MISCELLANEOUS.
8.1. Choice of Law. This Plan, all Options, all Option
Agreements and all other related documents shall be governed by,
and construed in accordance with, the laws of the State of Delaware
8.2. Compliance with Laws. This Plan, the granting and
vesting of Options under this Plan and the issuance and delivery of
Common Stock under this Plan or under Options granted hereunder are
subject to compliance with all applicable federal and state laws,
rules and regulations (including, but not limited to, state and
federal securities laws and federal margin requirements) and to
such approvals by any listing, regulatory or governmental authority
as may, in the opinion of counsel for the Company, be necessary or
advisable in connection therewith. Any securities delivered under
this Plan shall be subject to such restrictions, and the person
acquiring such securities shall, if requested by the Company,
provide such assurances and representations to the Company as the
Company may deem necessary or desirable to assure compliance with
all applicable legal requirements.
8.3. Severability. In the event that any provision of this
Plan shall be held by a court of competent jurisdiction to be
invalid and unenforceable, the remaining provisions of this Plan
shall continue in full force and effect.
8.4. Captions. Captions and headings are given to the
sections and subsections of this Plan solely as a convenience to
facilitate reference. Such headings shall not be deemed in any way
material or relevant to the construction or interpretation of this
Plan or any provision thereof.
8.5. Non-Exclusivity of Plan. Nothing in this Plan shall
limit or be deemed to limit the authority of the Board or the
Committee to grant options or authorize any other compensation,
with or without reference to the Common Stock, under any other plan
or authority.
This Plan was adopted January 7, 1999 by the Board of
Directors of the Company.
THIS AGREEMENT is made and shall be effective as of the 1st day of January,
1999 by and between BONNEVILLE PACIFIC CORPORATION, a Delaware corporation (the
"Employer") and CLARK M. MOWER, an individual and resident of the State of Utah
(the "Employee").
RECITALS:
A. The Employer is engaged in the business of developing,
owning and operating independent power facilities, and is also in
the oil and gas business.
B. The Employee has, for some time, served as the
President and Chief Executive Officer (CEO) for the Employer.
C. The Employer desires to employ the Employee to serve as
the President and CEO for the Employer, and the Employee is
willing to serve the Employer in that capacity.
D. The Employer and the Employee have agreed to enter into
this Agreement in order to set forth the terms and conditions
upon which the Employee will serve as the President and CEO for
the Employer.
AGREEMENT:
NOW, THEREFORE, in consideration of the foregoing Recitals and the mutual
covenants and promises contained herein, together with other good and valuable
consideration, the receipt and sufficiency of which is hereby acknowledged, the
parties agree as follows:
1. Employment. The Employer hereby employs the Employee and the Employee
hereby accepts employment with the Employer as the President and CEO for
Bonneville Pacific Corporation.
2. Term. (a) The initial Term ("Initial Term") of this Agreement shall be
for a period of two (2) years, commencing January 1, 1999, subject to the
termination provisions contained herein. This Agreement shall automatically
renew for additional one (1) year Terms ("Extended Terms") unless terminated by
either the Employer or the Employee in accordance with this Agreement. (b) It is
specifically agreed that, notwithstanding any provision of this Agreement to the
contrary, the obligations imposed upon the Employee by paragraph 14 hereof shall
survive the termination or expiration of this Agreement, or the termination of
the Employee's employment with the Employer, whether voluntary or otherwise. (c)
It is specifically agreed that notwithstanding any provision of this Agreement
to the contrary, the obligations imposed upon the Employer by paragraph 5 and 10
hereof shall survive the termination of this Agreement, or the termination of
the Employee's employment with the Employer, whether voluntary or otherwise.
3. Compensation. For all services as President which are rendered by the
Employee to the Employer pursuant to this Agreement, the Employer shall pay to
the Employee an annual salary of $174,000.00 payable in accordance with the
normal salary practices of the Employer. The annual salary of the Employee may
be increased and bonuses may be paid, at the discretion of the Board of
Directors of the Employer, or by the action of an appropriate Committee of the
Board of Directors.
4. Duties. The Employee shall have such duties and responsibilities as are
normally associated with his position, together with such specific duties as
shall be determined from time to time by the Board of Directors of the Employer.
5. Indemnification. The Employer hereby agrees to indemnify the Employee to
the maximum extent provided in the currently existing Articles and Bylaws in
effect at the time of the execution of this Agreement.
6. Extent of Services. During the entire term of this Agreement, the
Employee shall devote substantially his entire time, attention and energy to the
business of the Employer during regular business hours; provided, however, that
nothing herein shall prevent Employee from entering into business ventures which
do not interfere with his duties to the Employer and any business venture in
related fields which are not in competition with the Employer, and any business
venture in related fields which are in competition with the Employer, as long as
such competitive business ventures in related fields have been approved by the
Employer, such approval to not be unreasonably withheld. Nothing in this
paragraph shall be construed to limit the Employee's investment in any publicly
traded stock or commonly available investment vehicles including bonds, mutual
funds and other similar investments.
7. Employee Benefits. The Employer shall provide the Employee, during the
entire term of this Agreement, with the opportunity to participate in any health
and medical insurance plans provided by the Employer to other employees.
Additionally, during the term hereof, the Employee shall be entitled to
participate in all other benefit programs, which the Employer may establish and
maintain for the benefit of its employees generally. During the entire term of
this Agreement, the levels and type of benefits provided shall be at least at
the level in existence at the time of the execution of this Agreement.
8. Death During Employment. If the Employee dies during the term of this
Agreement, the Employer shall promptly pay to the estate of the Employee
compensation as described under paragraph 10(d) hereof. Such payment shall be
designated as a "Survivor's Allowance".
9. Termination. (a) Termination for Cause. "Termination for Cause" shall
mean termination by Employer of Employee's employment by the Employer for reason
of willful unlawful or illegal acts by the Employee which has resulted in
material injury to the Employer. The Employer may terminate the Employee's
employment under this Agreement, with good cause, at any time upon written
notice to the Employee. (b) Termination Without Cause. "Termination Without
Cause" shall mean any termination of Employee's employment by Employer other
than For Cause or by reason of death. The Employer, with Board approval, may
terminate the Employee's employment under this Agreement at any time, without
cause, upon sixty (60) days written notice to the Employee of the effective date
of such termination. (c) Voluntary Termination. "Voluntary Termination" shall
mean termination by Employee of Employee's employment by Employer other than (i)
as a result of a "Change in Control" as described in Section 11, (ii) as a
result of a "Deemed Termination of Employment" as described in Section 12, or
(iii) as the result of termination by reason of Employee's death as described in
Section 8. The Employee may terminate his employment under this Agreement, for
any reason upon sixty (60) days written notice to the Employer. (d) Change of
Control or Deemed Termination. In the event of a Change of Control event as
defined in Section 11 of this Agreement or a Deemed Termination as defined in
Section 12 of this Agreement, the Employee may terminate his employment under
this Agreement, for any reason, upon thirty (30) days written notice to the
Employer.
10. Compensation Upon Termination or Death. (a) Termination for Cause. Upon
Termination for Cause, the Employer shall promptly pay Employee all accrued
compensation (including accrued vacation pay) and benefits as of the date of
Termination for Cause and all accrued expenses which are unpaid at the date of
Termination for Cause. (b) Termination Without Cause. Upon Termination Without
Cause, the Employer shall promptly pay Employee all accrued compensation
(including accrued vacation pay) and benefits as of the date of Termination
Without Cause and all accrued expenses which are unpaid at the date of
Termination Without Cause. Additionally, the Employer shall pay to the Employee,
a lump sum on the first regularly scheduled payday of the Employer which follows
the effective date of such termination, an amount equal to two (2) times the
average of the sum of amounts paid to the Employee for salary, bonus, including
any amount received as Plan confirmation bonus, and profit sharing for the five
fiscal years immediately preceding the effective date of the Termination Without
Cause. Any amounts paid to Employee pursuant to this paragraph shall be subject
to any applicable federal, state and local income tax withholding. (c) Deemed
Termination of Employment. In the event there is a "Deemed Termination" of
employment as described in Section 12 of this Agreement, the Employer shall pay
to the Employee the same compensation which Employee would be entitled if the
termination would have been a Termination Without Cause under Section 10(b)
above. (d) Change of Control. In the event there is a "Change of Control Event"
as described in Section 11 of this Agreement, the Employer shall pay to the
Employee, a lump sum on the first regularly scheduled payday of the Employer
which follows the effective date of such termination, an amount equal to three
(3) times the average of the sum of amounts paid to the Employee for salary,
bonus, including any amount received as Plan confirmation bonus, and profit
sharing for the five fiscal years immediately preceding the effective date of
the Termination Without Cause. Any amounts paid to Employee pursuant to this
paragraph shall be subject to any applicable federal, state and local income tax
withholding. (e) Death. In the event of Employee's death during the term of this
Agreement, the Employer shall promptly pay to the Employee's beneficiaries, all
accrued compensation (including accrued vacation pay) and benefits as of the
date of death and all accrued expenses which are unpaid at the date of death,
together with an additional amount equal to one year's salary. (f) Voluntary
Termination. In the event of a Voluntary Termination, Employer shall pay to
Employee all accrued compensation (including accrued vacation pay) and benefits
as of the date of Voluntary Termination and all accrued expenses which are
unpaid at the date of Voluntary Termination.
11. Definition of Change in Control. For purposes of this Agreement, a
"change in control" will be deemed to have occurred on the first to occur of any
of the following events: (a) As a result of a cash tender offer, stock exchange
offer or other takeover device, any person, as that term is used in Section
13(d) and 14(b)(2) of the Securities Exchange Act of 1934, is or becomes a
beneficial owner, directly or indirectly, of stock of Employer representing
thirty percent (30%) or more of the total voting power of Employer's then
outstanding securities; (b) Any material realignment of the Board of Directors
of Employer or change in officers of Employer resulting from a concerted
shareholder action, including without limitation a proxy fight, voting trusts or
pooling arrangements; (c) Any merger, consolidation or other reorganization of
Employer with any entity, other than its affiliates, whereby Employer is not the
surviving entity or the shareholders of Employer otherwise fail to retain
substantially the same direct or indirect ownership in Employer or its
affiliates immediately after any such merger, consolidation or reorganization.
12. Deemed Termination of Employment. Employee shall be entitled to receive
the payment described in paragraph 10 above if any of the following occur during
the term of this Agreement: (a) Employee is removed or released from any of his
material titles, positions or offices under this agreement, or Employee's duties
and responsibilities in such titles, positions or offices are materially
changed; (b) Employee's base salary is reduced; (c) Employee is removed from
participation in any of Employer's bonus or profit sharing programs, or any
bonus or profit sharing programs in which Employee was entitled to participate
immediately prior to the change; or (d) Employee's office is based more than 50
miles from the location of the principal office at which Employee was based
immediately prior to the change.
13. Covenant Not to Compete. During the entire period that the Employee
remains employed by the Employer pursuant to this Agreement, up to the effective
date of termination, the Employee shall not engage either directly or indirectly
in any activity or business, whether as an officer, director, sole proprietor,
employee, partner, majority shareholder, consultant or adviser, which is in
direct competition with any business engaged in by the Employer, except as
otherwise approved by the Employer.
14. Confidentiality. The business plans, marketing plans, development
plans, acquisition plans, construction plans, and financial data (the
"Confidential Information") of the Employer are, and shall remain, the valuable,
special, unique and proprietary assets of the Employer, access to and knowledge
of which are essential to the performance by the Employee of his duties under
this Agreement. The Employee shall not, during the term of this Agreement,
except as is necessary to promote the business of the Employer, or after the
term of his employment hereunder disclose the Confidential Information, in whole
or in part, to any person, firm, corporation, association, or other entity for
any reason or purpose whatsoever, nor shall the Employee make use of the
Confidential Information for the benefit of any person, firm, corporation or
other entity (except the Employer) under any circumstances during or after the
term of his employment. Upon the termination of this employment pursuant to this
Agreement, the Employee shall promptly return to the Employer any originals and
all copies of any Confidential Information which are in his possession. All
information shall cease to be Confidential Information at such time as it enters
the public domain, other than through the breach by the Employee of his
obligations under this paragraph 14.
15. Default. Should default occur in the performance of any of the
obligations set forth in this Agreement, the non- defaulting party shall be
entitled to obtain an injunction compelling the cure of such default and the
specific performance of the obligations of this Agreement in addition to any
action for damage or other relief which may be available to the non- defaulting
party. The defaulting party shall, in addition to any damages which may result
from said default, pay to the non- defaulting party the costs, including
reasonable attorney's fees, incurred by the non-defaulting party in curing such
default or in enforcing the terms and conditions of this Agreement. If a bond is
required by the Court, the parties agree that a bond in the amount of $500.00
shall suffice. The Employee understands and agrees that the Employer shall
suffer irreparable harm in the event that the Employee breaches any of the
Employee's obligations under this Agreement and that monetary damages shall be
inadequate to compensate the Employer for such breach.
16. Entire Agreement. This Agreement supersedes any prior understandings or
agreements, whether written or oral, between the parties hereto in regard to the
subject matter hereof and contains the entire agreement between the parties in
that regard. This Agreement may not be changed or modified orally, but only by
an agreement, in writing, signed by both of the parties.
17. Notices. Any notice which is required or permitted to be given to
either party to this Agreement shall be deemed to have been given only if such
notice is reduced to writing and delivered, by United States mail, with postage
prepaid and return receipt requested, to the appropriate party as set forth
below:
Employer: Bonneville Pacific Corporation
50 West 300 South, Suite 300
Salt Lake City, Utah 84101
Attn: Chairman
Employee: Clark M. Mower
4315 Daisy Drive
Mountain Green, Utah 84050
Either party may change his address by giving notice of the change in the
manner set forth above. Any notice given shall be deemed delivered upon its
receipt in the United States mail.
18. Arbitration of Disputes. Any controversy, dispute or claim arising out
of or relating to this Agreement, or the breach thereof, which cannot be
resolved amicably by the parties shall be settled by arbitration in accordance
with the Rules of the American Arbitration Association, except in cases where
immediate action is required whether or not arbitration has been requested or is
in process, nothing herein shall prevent any party from pursuing equitable
remedies, including interim relief, in any court of competent jurisdiction, and
except as may be unanimously otherwise agreed by the parties. In the event of
arbitration, the cost of arbitration, including all reasonable attorney's fees
and costs, incurred by the successful party shall be borne by the unsuccessful
party unless otherwise ordered by arbitration.
19. Savings Clause. Should any part of a provision of this Agreement be
rendered or declared invalid by reason of any state or federal law, or by decree
of any court of competent jurisdiction, such invalidation of said part or
provision of this Agreement shall not invalidate the remaining portions hereof,
and the remaining parts and provisions of this Agreement shall remain in full
force and effect. 20. Governing Law. The parties specifically agree that this
Agreement shall be governed by and interpreted in accordance with the laws of
the State of Utah, without giving effect to the choice of law rules thereof. IN
WITNESS WHEREOF the parties hereto have executed this Employment Agreement as of
the date first herein written.
EMPLOYER
BONNEVILLE PACIFIC CORPORATION
By:
(s)---------------------------
JAMES W. BERNARD
Chairman
EMPLOYEE
(s)---------------------------
CLARK M. MOWER
Employment Agreement January 1, 1999
THIS AGREEMENT is made and shall be effective as of the
1st day of July, 1997 by and between BONNEVILLE FUELS
CORPORATION, a Colorado corporation (the "Employer") and
STEVEN H. STEPANEK, an individual and resident of the State
of Utah (the "Employee").
RECITALS:
A. The Employer is engaged in the business of
exploration for and production of oil and gas reserves,
marketing of natural gas, and gathering of natural gas.
B. The Employee has, for some time, served as the
President of the Employer, and on its Board of Directors.
C. The Employer desires to employ the Employee to
serve as the President of the Employer, and on the
Employer's Board of Directors, and the Employee is willing
to serve the Employer in those capacities.
D. The Employer and the Employee have agreed to enter
into this Agreement in order to set forth the terms and
conditions upon which the Employee will serve as the
President of the Employer, and on the Employer's Board of
Directors.
AGREEMENT:
NOW, THEREFORE, in consideration of the foregoing Recitals and the mutual
covenants and promises contained herein, together with other good and valuable
consideration, the receipt and sufficiency of which is hereby acknowledged, the
parties agree as follows: 1. Employment. Bonneville Fuels Corporation hereby
employs the Employee and the Employee hereby accepts employment with the
Employer as the President of Bonneville Fuels Corporation and its subsidiaries,
and as a member of the Board of Directors of Bonneville Fuels Corporation.
2. Term. (a) The term of this Agreement shall commence as of July 1, 1997
and, subject to the provisions for termination set forth in paragraph 13 hereof,
shall continue until June 30, 2000, and shall be adjusted to a remaining term of
24 months upon the effective date of the confirmed plan in the Bonneville
Pacific Corporation ("BPC") Chapter 11 Bankruptcy Case Number 91-27701 in the
United States Bankruptcy Court for the District of Utah. The term of this
Agreement may be extended or renewed by mutual agreement of the parties. (b) It
is specifically agreed that, notwithstanding any provision of this Agreement to
the contrary, the obligations imposed upon the Employee by paragraph 16 hereof
shall survive the termination or expiration of this Agreement, or the
termination of the Employee's employment with the Employer, whether voluntary or
otherwise. (c) It is specifically agreed that notwithstanding any provision of
this Agreement to the contrary, the obligations imposed upon the Employer by
paragraphs 5 and 14 hereof shall survive the termination or expiration of this
Agreement, or the termination of the Employee's employment with the Employer,
whether voluntary or otherwise.
3. Compensation. For all services as President of the Employer, and on its
Board of Directors which are rendered by the Employee to the Employer pursuant
to this Agreement, the Employer shall pay to the Employee an annual salary of
$130,000 payable in accordance with the normal salary practices of the Employer.
The annual salary of the Employee may be increased and an annual bonus may be
paid, at the discretion of the Board of Directors of the Employer, or by the
action of an appropriate Committee of the Board of Directors.
4. Duties. The Employee shall have such duties and responsibilities are as
normally associated with his position, together with the duties and
responsibilities of a Director of Bonneville Fuels Corporation, and together
with such specific duties as shall be determined from time to time by the Board
of Directors of the Employer.
5. Indemnification. (a) Indemnification. The Employer shall indemnify the
employee if: (i) The Employee was or is a party or is threatened to be made a
party to any threatened, pending or completed action, suit or proceeding,
whether civil, criminal, administrative or investigative (other than an action
by or in the right of the Employer) by reason of the fact that said person is or
was an employee of the Employer, or is or was serving at the request of the
Employer as a director, officer, employee or agent of this and or another
employer, partnership, joint venture, trust or other enterprise, against
expenses (including reasonable attorney's fees), judgments, fines and amounts
paid in settlement actually and reasonably incurred by said person in connection
with such action, suit or proceeding if said person acted in good faith and in a
manner said person reasonably believed to be in the normal course and in the
best interests of the Employer, and said person did not receive or expect to
receive monetary benefit other than provided by terms of this Employment
Agreement and said person acted in accordance with standard industry practice of
similarly sized oil and gas companies. (ii) The Employee was or is a party or is
threatened to be made a party to any threatened, pending or completed action or
suit by or in the right of the Employer to procure a judgment in its favor by
reason of the fact that said person is or was a director, officer, employee or
agent of the Employer, or is or was serving at the request of the Employer as a
director, officer, employee or agent of another employer, partnership, joint
venture, trust or other enterprise, against expenses (including reasonable
attorney's fees) actually and reasonably incurred by said person in connection
with the defense or settlement of such action or suit if said person acted in
good faith and in a manner said person reasonably believed to be in the normal
course and in the best interests of the Employer. However, no indemnification
shall be made in respect to any claim, issue or matter as to which such person
shall have been adjudged to be liable for negligence or misconduct in the
performance of said person's duty to the Employer unless and only to the extent
that the court in which such action or suit was brought shall determine upon
application that, despite the adjudication of liability but in view of all
circumstances of the case, such person is fairly and reasonably entitled to
indemnity for such expenses which such court shall deem proper. The standard of
conduct as set forth above shall be that a reasonable man, i.e. that of a
fictitious person of ordinary prudence under the circumstances exercising
reasonable care, i.e. that degree of care which a person of ordinary prudence
would exercise in the same or similar circumstance. (b) Automatic
Indemnification. To the extent that the Employee has been successful on the
merits or otherwise in the defense of any action, suit or proceeding specified
in Section (a) of this Article, or in the defense of any claim, issue or matter
therein, the Employee shall be indemnified against expenses (including
attorney's fees) actually and reasonably incurred by Employee in connection
therewith. (c) Advancements. Expenses incurred in defending a civil or criminal
action, suit or proceeding will be paid by the Employer as incurred and in
advance of the final disposition of such action, suit or proceeding for which
the Employer may ultimately be liable under Section (a) of this Article.
However, the Employer may, for good cause in the event the claim for
indemnification arises out of an action, suit or proceeding based upon
allegations of fraud or alleged criminal action, demand that an undertaking
acceptable to both parties be posted by the Employee prior to dollars being
advanced and as a condition of payment in advance of the final disposition of
such action, suit or proceeding. If it is ultimately determined by a court of
law that the Employee is not entitled to be indemnified by the Employer,
Employee shall upon terms acceptable to both parties, repay such amount paid by
the Employer for said expenses. (d) Other Indemnification. The indemnification
herein provided shall not be deemed exclusive of any other rights to which the
Employee may be entitled under any bylaw, agreement, vote of stockholders or
disinterested directors, or otherwise, both as to action in said person's
official capacity and as to action in another capacity while holding such
office, and shall continue as to a person who has ceased to be an Employee, and
shall inure to the benefit of the heirs, executors and administrators of such
person. (e) Insurance. The Board of Directors may, in its discretion, direct
that the Employer purchase and maintain insurance on behalf of any person who is
or was an employee or Director of the Employer, or is or was serving at the
request of the Employer as an employee or Director of another employer,
partnership, joint venture, trust or other enterprise, against any liability
asserted against Employee and incurred by Employee in any such capacity, or
arising out of Employee's status as such, whether or not the Employer would have
the power to indemnify Employee against liability under the provisions of this
Article. (f) Settlement by Employer. The right of Employee to be indemnified
shall be subject always to the right of the Employer by the Board of Directors,
in lieu of such indemnity, to settle any such claim, action, suit or proceeding
at the expense of the Employer by the payment of the amount of such settlement
and the costs and expenses incurred in connection therewith.
6. Extent ofServices. During the entire term of this Agreement, the
Employee shall devote substantially his entire time, attention and energy to the
business of the Employer during regular business hours; provided, however, that
nothing herein shall prevent Employee from entering into business ventures which
do not interfere with his duties to the Employer and any business venture in
related fields which are not in competition with the Employer, and any business
venture in related fields which are in competition with the Employer, as long as
such competitive business ventures in related fields have been approved by the
Employer, such approval to not be unreasonably withheld. Nothing in this
paragraph shall be construed to limit the Employee's investment in any publicly
traded stock or commonly available investment vehicles including bonds, mutual
funds and other similar investments.
7. Expenses. The Employee is authorized to incur reasonable expenses in
promoting the business of the Employer, including expenses for entertainment,
travel, and similar items. In any event, such expenses shall not exceed
$2,000.00 outstanding at any one time, without the prior approval of the
Chairman of the Board of Directors. The Employer shall reimburse Employee for
all such reasonable expenses actually incurred by the Employee upon the
presentation by the Employee, from time to time, of an itemized account of such
expenses sufficient to enable the Employer to comply with applicable IRS
reporting requirements.
8. Vacations. The Employee shall be entitled, during the term of this
Agreement, to an annual vacation of twenty (20) paid days. The Employee has the
option of being paid for or carrying forward, up to a maximum of ten (10) days,
any accrued unused vacation of the preceding year.
9. Employee Benefits. The Employer shall provide the Employee, during the
entire term of this Agreement, with the opportunity to participate in any health
and medical insurance plans provided by the Employer to other Employees.
Additionally, during the term hereof, the Employee shall be entitled to
participate in all other benefit programs which the Employer may establish and
maintain, from time to time, for the benefit of its employees generally.
10. Relocation Expenses. In the event Employer requires Employee to
relocate out of Salt Lake City, Utah as a condition of continued employment and
Employee chooses to continue such employment and relocate, Employer shall
promptly pay Employee the amount of Employee's actual moving expenses up to a
maximum of $15,000.00 upon presentation of paid invoices for moving expense
incurred and shall also promptly pay to Employee up to $15,000.00 of actual real
estate commissions paid by Employee with regard to the sale of Employee's
personal residence upon presentation of a Seller's Closing Statement or other
similar documentation from the sale of said personal residence.
11. Disability.If the Employee is unable to perform the duties called for
by paragraph 4 hereof by reason of illness, incapacity or disability for a
period of thirteen (13) consecutive weeks, the Employer shall have the right to
terminate this Agreement pursuant to paragraph 13(c) or 13(d) hereof. If during
the sixty (60) day notice period provided in paragraph 13(c) or 13(d), Employee
regains the ability to resume his duties, the Employer may, at its discretion,
reinstate the Employee for the term of this contract. Notwithstanding the above,
in the event that Employee becomes disabled, the Employer shall maintain short
term disability insurance coverage that provides, at a minimum that once the
conditions of the policy have been met, the Employee will be paid at least Five
Hundred Dollars ($500.00) per week to the maximum of thirteen (13) weeks. Said
short term disability compensation shall begin on the 8th day of disability
caused by sickness and on the 1st day of disability caused by any other reason,
except for a disability which would be covered by workman's compensation
insurance. If the short term disability policy in place at the time of the
illness has provisions which are more beneficial to the Employee than those
outlined above, the policy in force at the time of the illness shall have
precedence over the benefits as described above. The Employer shall also
maintain long term disability coverage for the Employee comparable to the
coverage provided as of January 1, 1997 by the Prudential Insurance Company of
America.
12. Death During Employment. If the Employee dies during the term of this
Agreement, the Employer shall promptly pay to the estate of the Employee
compensation as described under paragraph 14(g) hereof. Such payment shall be
designated as a "Survivor's Allowance".
13. Termination. (a) The Employer may terminate the Employee's employment
under this Agreement, with good cause, at any time upon written notice to the
Employee. "Good cause" is defined for the purpose of this Agreement as that
which the Employer, in its reasonable discretion, determines to be a reasonable
business necessity as a consequence of Employee's conduct, acts or omissions. In
no event shall employees refusal to deviate from commonly accepted industry
practices and procedures be construed to be good cause. (b) The Employee may
terminate his employment under this Agreement, for any reason, upon sixty (60)
days written notice to the Employer. (c) The Employer, with Board approval, may
terminate the Employee's employment under this Agreement at any time without
good cause, prior to confirmation of a plan in the BPC Chapter 11 Bankruptcy
Case, upon sixty (60) days written notice to the Employee of the effective date
of such termination. (d) The Employer may terminate the Employee's employment
under this Agreement at any time, without good cause, after the effective date
of confirmation of a plan in the BPC Chapter 11 Bankruptcy Case, upon sixty (60)
days written notice to the Employee of the effective date of such termination.
(e) The Employee may terminate his employment upon thirty (30) days written
notice to the Employer in the event Employer requires Employee to locate outside
of Salt Lake City, Utah as a condition of employment and Employee, for whatever
reason, declines to relocate. (f) Non-renewal of this Agreement shall be
considered an event of termination.
14. Compensation Upon Termination or Death. (a) If the Employer shall
terminate the Employee's employment under this Agreement pursuant to paragraph
13(a) hereof, for good cause, the Employer shall be obligated to pay to the
Employee, in cash and upon the effective date of such termination, those
portions of the Employee's annual salary provided for by paragraph 3 hereof
which have accrued, but remain unpaid, up to and including the date upon which
such termination becomes effective, together with an amount calculated pursuant
to the Employer's normal policy for any unused vacation days due the Employee.
The Employee shall not be entitled to any additional severance payments or
benefits except as set forth herein except as may be provided by Federal and
State law. (b) If the Employee shall terminate his employment under this
Agreement pursuant to paragraph 13(b) hereof, the Employer shall be obligated to
pay to the Employee in cash, upon the effective date of such termination, those
portions of the Employee's annual salary provided for by paragraph 3 hereof
which have accrued, but remain unpaid, up to and including the date upon which
such termination becomes effective, together with an amount calculated pursuant
to the Employer's normal policy for any unused vacation days due the Employee.
The Employee shall not be entitled to any additional severance payments or
benefits except as set forth herein except as may be provided by Federal and
State law. (c) If the Employer shall terminate the Employee's employment under
this Agreement pursuant to paragraph 13(c) hereof, the Employer shall be
obligated to pay to the Employee in cash upon the effective date of such
termination, those portions of the Employee's annual salary provided for by
paragraph 3 hereof which have accrued, but remain unpaid, up to and including
the date upon which such termination becomes effective together with an amount
calculated pursuant to the Employer's normal policy for unused vacation days due
the Employee, together with an additional amount equal to the salary said
Employee would have been entitled to pursuant to paragraph 14(i) hereof had the
employment not been terminated for a period of thirty (30) months following the
effective date of termination. (d) If the Employer shall terminate the
Employee's employment under this Agreement pursuant to paragraph 13(d) hereof,
the Employer shall be obligated to pay to the Employee, in cash upon the
effective date of such termination, those portions of the Employee's annual
salary provided for by paragraph 3 hereof which have accrued, but remain unpaid,
up to and including the date upon which such termination becomes effective,
together with an amount calculated pursuant to the Employer's normal policy for
unused vacation days due the Employee, together with an additional amount equal
to the salary said Employee would have been entitled to pursuant to paragraph
14(i) hereof had the employment not been terminated, for a period of twenty-
four (24) months following the effective date of such termination. The
twenty-four (24) month termination benefit shall be reduced by 1 month per month
of service after the date of the first anniversary of the effective date of the
confirmed plan in the Bonneville Pacific Corporation Chapter 11 bankruptcy case
down to a minimum termination benefit of twelve (12) months. (e) If the Employer
shall terminate the Employee's employment under this Agreement pursuant to
paragraph 13(e) hereof, the Employer shall be obligated to pay to the Employee,
in cash upon the effective date of such termination, those portions of the
Employee's annual salary provided for by paragraph 3 hereof which have accrued,
but remain unpaid, up to and including the date upon which such termination
becomes effective, together with an amount calculated pursuant to the Employer's
normal policy for any unused vacation days due the Employee, together with an
additional amount equal to the salary said Employee would have been entitled to
pursuant to paragraph 14(i) hereof had the employment not been terminated for a
period of a period twelve (12) months following the effective date of
termination. (f) If the Employer shall terminate the Employee's employment under
this Agreement pursuant to paragraph 13(f) hereof, the Employer shall be
obligated to pay to the Employee, in cash upon the effective date of such
termination, those portions of the Employee's annual salary provided for by
paragraph 3 hereof, which have accrued, but remain unpaid, up to and including
the date upon which such termination becomes effective together with an amount
calculated pursuant to the Employer's normal policy for unused vacation days due
the Employee, together with an additional amount equal to the salary said
Employee would have been entitled to pursuant to paragraph 14(i) hereof had the
employment not been terminated for a period of twelve (12) months following the
effective date of termination. (g) If the Employee dies during the term of his
employment under this Agreement pursuant to paragraph 12 hereof, the Employer
shall be obligated to pay to the estate of the Employee, in cash within five (5)
working days of his death, those portions of the Employee's annual salary
provided for by paragraph 3 hereof which have accrued, but remain unpaid, up to
and including the date upon which such death occurred, together with an amount
calculated pursuant to the Employer's normal policy for unused vacation days due
the Employee, together with an additional amount equal to the salary said
Employee would have been entitled to pursuant to paragraph 14(i) hereof had the
employment not been terminated for a period of twelve (12) months following the
effective date of termination. (h) The sixty (60) days written notice required
pursuant to paragraphs 13(c) and 13(d) and the thirty (30), twenty-four (24),
twelve (12), and twelve (12) months salary provided for in paragraph 14(c)
through 14(g) above, calculated from the effective date of termination, shall
not be shortened or diminished in any way or in any amount by virtue of the fact
that the notice of termination occurs at a point in time when less than the
requisite number of days and/or the requisite number of months remains in the
term of this Agreement. (i) Calculation of the compensation provided pursuant to
this Section 14 will be accomplished by averaging for the last two (2) years the
total annual compensation including salary and bonus provided by Section 3 but
not including any BPC Plan confirmation bonus.
15. Covenant Not to Compete.During the entire period that the Employee
remains employed by the Employer pursuant to this Agreement, up to the effective
date of termination, the Employee shall not engage either directly or indirectly
in any activity or business, whether as an officer, director, sole proprietor,
employee, partner, majority shareholder, consultant or adviser, which is in
direct competition with any business engaged in by the Employer, except as
otherwise approved by the Employer.
16. Confidentiality. The business plans,marketing plans, development plans,
acquisition plans, construction plans, and financial data (the "Confidential
Information") of the Employer are, and shall remain, the valuable, special,
unique and proprietary assets of the Employer, access to and knowledge of which
are essential to the performance by the Employee of his duties under this
Agreement. The Employee shall not, during the term of this Agreement, except as
is necessary to promote the business of the Employer, or after the term of his
employment hereunder disclose the Confidential Information, in whole or in part,
to any person, firm, employer, association, or other entity for any reason or
purpose whatsoever, nor shall the Employee make use of the Confidential
Information for the benefit of any person, firm, employer or other entity
(except the Employer) under any circumstances during or after the term of his
employment [unless ordered to do so under appropriate court order],. Upon the
termination of this employment pursuant to this Agreement, the Employee shall
promptly return to the Employer any originals and all copies of any Confidential
Information which are in his possession. All information shall cease to be
Confidential Information at such time as it enters the public domain, other than
through the breach by the Employee of his obligations under this paragraph 16.
17. Default. Should default occur in the performance of any of the
obligations set forth in this Agreement, the non-defaulting party shall be
entitled to obtain an injunction compelling the cure of such default and the
specific performance of the obligations of this Agreement in addition to any
action for damage or other relief which may be available to the non-defaulting
party. The defaulting party shall, in addition to any damages which may result
from said default, pay to the non-defaulting party the costs, including
reasonable attorney's fees, incurred by the non-defaulting party in curing such
default or in enforcing the terms and conditions of this Agreement. If a bond is
required by the Court, the parties agree that a bond in the amount of $500.00
shall suffice. The Employee understands and agrees that the Employer shall
suffer irreparable harm in the event that the Employee breaches any of the
Employee's obligations under this Agreement and that monetary damages shall be
inadequate to compensate the Employer for such breach.
18. Entire Agreement. This Agreement supersedes any prior understandings or
agreements, whether written or oral, between the parties hereto in regard to the
subject matter hereof and contains the entire agreement between the parties in
that regard. This Agreement may not be changed or modified orally, but only by
an agreement, in writing, signed by both of the parties.
19. Assignment and Binding Effect. This Agreement shall be binding upon and
shall inure to the benefit of the parties hereto, their successors and permitted
assigns. The term "Employer" as used in this Agreement shall mean Bonneville
Fuels Corporation, its successor and successors, any surviving corporation into
which it may be merged, or any Employer resulting from its consolidation with
any other corporation or corporations, and the successor or successors of any
such surviving or consolidated corporation. This Agreement may not be assigned
by the Employee.
20. Notices Any notice which is required or permitted to be given to either
party to this Agreement shall be deemed to have been given only if such notice
is reduced to writing and delivered, by United States mail, with postage prepaid
and return receipt requested, to the appropriate party as set forth below:
Employer: Bonneville Fuels Corporation
50 West 300 South, Suite 300
Salt Lake City, Utah 84101
Attn: Chairman
with a copy to:
Roger G. Segal,
Chapter 11 Trustee for
Bonneville Pacific Corporation
COHNE, RAPPAPORT & SEGAL,
P.C.
525 East 100 South, Suite 500
Salt Lake City, Utah 84102
Employee: Steven H. Stepanek
671 Aloha Road
Salt Lake City, UT 8410
Either party may change his address by giving notice of the change in the
manner set forth above. Any notice given shall be deemed delivered upon its
receipt in the United States mail.
21. Arbitration of Disputes. Any controversy,dispute or claim arising out
of or relating to this Agreement, or the breach thereof, which cannot be
resolved amicably by the parties shall be settled by arbitration in accordance
with the Rules of the American Arbitration Association, except in cases where
immediate action is required whether or not arbitration has been requested or is
in process, nothing herein shall prevent any party from pursuing equitable
remedies, including interim relief, in any court of competent jurisdiction, and
except as may be unanimously otherwise agreed by the parties. In the event of
arbitration, the cost of arbitration, including all reasonable attorney's fees
and costs, incurred by the successful party shall be borne by the unsuccessful
party unless otherwise ordered by arbitration.
22. Savings Clause. Should any part of a provision of this Agreement be
rendered or declared invalid by reason of any state or federal law, or by decree
of any court of competent jurisdiction, such invalidation of said part or
provision of this Agreement shall not invalidate the remaining portions hereof,
and the remaining parts and provisions of this Agreement shall remain in full
force and effect.
23. Governing Law. The parties specifically agree that this Agreement shall
be governed by and interpreted in accordance with the laws of the State of
Colorado, without giving effect to the choice of law rules thereof.
IN WITNESS WHEREOF, the parties hereto have executed this Employment
Agreement as of the date first herein written. EMPLOYER BONNEVILLE FUELS
CORPORATION
(s):_________________________________
Clark M. Mower
Chairman
EMPLOYEE
____________________________________
STEVEN H. STEPANEK
Approved:
____________________________________
Roger G. Segal, Chapter 11 Trustee for
Bonneville Pacific Corporation
Employment Agreement September 11, 1997
Employment Agreement 7 January 1, 1999
EMPLOYMENT AGREEMENT
THIS AGREEMENT is made and shall be effective as of the 1st day of
January, 1999 by and between BONNEVILLE PACIFIC SERVICES COMPANY, INC., an Idaho
corporation (the "Employer") and TODD L. WITWER, an individual and resident of
the State of Utah (the "Employee").
RECITALS:
A. The Employer is engaged in the business of developing, constructing,
operating and servicing electrical energy facilities.
B. The Employee has, for some time, served as the President for the
Employer.
C. The Employer desires to employ the Employee to serve as the President
for the Employer, and the Employee is willing to serve the Employer in that
capacity.
D. The Employer and the Employee have agreed to enter into this Agreement
in order to set forth the terms and conditions upon which the Employee will
serve as the President for the Employer
AGREEMENT:
NOW, THEREFORE, in consideration of the foregoing Recitals and the
mutual covenants and promises contained herein, together with other good and
valuable consideration, the receipt and sufficiency of which is hereby
acknowledged, the parties agree as follows:
1. Employment. The Employer hereby employs the Employee and the
Employee hereby accepts employment with the Employer as the President for
Bonneville Pacific Services Company, Inc.
2. Term.
(a) The initial Term ("Initial Term") of this Agreement shall be for a
period of two (2) years, commencing January 1, 1999, subject to the termination
provisions contained herein. This Agreement shall automatically renew for
additional one (1) year Terms ("Extended Terms") unless terminated by either the
Employer or the Employee in accordance with this Agreement.
(b) It is specifically agreed that, notwithstanding any provision of this
Agreement to the contrary, the obligations imposed upon the Employee by
paragraph 14 hereof shall survive the termination or expiration of this
Agreement, or the termination of the Employee's employment with the Employer,
whether voluntary or otherwise.
(c) It is specifically agreed that notwithstanding any provision of this
Agreement to the contrary, the obligations imposed upon the Employer by
paragraph 5 and 10 hereof shall survive the termination of this Agreement, or
the termination of the Employee's employment with the Employer, whether
voluntary or otherwise.
3. Compensation. For all services as President which are rendered by
the Employee to the Employer pursuant to this Agreement, the Employer shall pay
to the Employee an annual salary of $125,008.00 payable in accordance with the
normal salary practices of the Employer. The annual salary of the Employee may
be increased and bonuses may be paid, at the discretion of the Board of
Directors of the Employer, or by the action of an appropriate Committee of the
Board of Directors.
4. Duties. The Employee shall have such duties and responsibilities as
are normally associated with his position, together with such specific duties as
shall be determined from time to time by the President or Board of Directors of
the Employer.
5. Indemnification. The Employer hereby agrees to indemnify the
Employee to the maximum extent provided in the currently existing Articles and
Bylaws of Bonneville Pacific Corporation (the "Parent Company") in effect at the
time of the execution of this Agreement.
6. Extent of Services. During the entire term of this Agreement, the
Employee shall devote substantially his entire time, attention and energy to the
business of the Employer during regular business hours; provided, however, that
nothing herein shall prevent Employee from entering into business ventures which
do not interfere with his duties to the Employer and any business venture in
related fields which are not in competition with the Employer, and any business
venture in related fields which are in competition with the Employer, as long as
such competitive business ventures in related fields have been approved by the
Employer, such approval to not be unreasonably withheld. Nothing in this
paragraph shall be construed to limit the Employee's investment in any publicly
traded stock or commonly available investment vehicles including bonds, mutual
funds and other similar investments.
7. Employee Benefits. The Employer shall provide the Employee, during
the entire term of this Agreement, with the opportunity to participate in any
health and medical insurance plans provided by the Employer to other employees.
Additionally, during the term hereof, the Employee shall be entitled to
participate in all other benefit programs, which the Employer may establish and
maintain for the benefit of its employees generally. During the entire term of
this Agreement, the levels and type of benefits provided shall be at least at
the level in existence at the time of the execution of this Agreement.
8. Death During Employment. If the Employee dies during the term of
this Agreement, the Employer shall promptly pay to the estate of the Employee
compensation as described under paragraph 10(e) hereof. Such payment shall be
designated as a "Survivor's Allowance".
9. Termination.
(a) Termination for Cause. "Termination for Cause" shall mean termination
by Employer of Employee's employment by the Employer for reason of willful
unlawful or illegal acts by the Employee which has resulted in material injury
to the Employer. The Employer may terminate the Employee's employment under this
Agreement, with good cause, at any time upon written notice to the Employee.
(b) Termination Without Cause. "Termination Without Cause" shall mean any
termination of Employee's employment by Employer other than For Cause or by
reason of death. The Employer, with Board approval, may terminate the Employee's
employment under this Agreement at any time, without cause, upon sixty (60) days
written notice to the Employee of the effective date of such termination.
(c) Voluntary Termination. "Voluntary Termination" shall mean termination
by Employee of Employee's employment by Employer other than (i) as a result of a
"Change in Control" as described in Section 11, (ii) as a result of a "Deemed
Termination of Employment" as described in Section 12, or (iii) as the result of
termination by reason of Employee's death as described in Section 8. The
Employee may terminate his employment under this Agreement, for any reason upon
sixty (60) days written notice to the Employer.
(d) Change of Control or Deemed Termination. In the event of a Change of
Control event as defined in Section 11 of this Agreement or a Deemed Termination
as defined in Section 12 of this Agreement, the Employee may terminate his
employment under this Agreement, for any reason, upon thirty (30) days written
notice to the Employer..
10. Compensation Upon Termination or Death.
(a) Termination for Cause. Upon Termination for Cause, the Employer shall
promptly pay Employee all accrued compensation (including accrued vacation pay)
and benefits as of the date of Termination for Cause and all accrued expenses
which are unpaid at the date of Termination for Cause. Any amounts paid to
Employee pursuant to this paragraph shall be subject to any applicable federal,
state and local income tax withholding.
(b) Termination Without Cause. Upon Termination Without Cause, the Employer
shall promptly pay Employee all accrued compensation (including accrued vacation
pay) and benefits as of the effective date of Termination Without Cause and all
accrued expenses which are unpaid at the effective date of Termination Without
Cause. Additionally, the Employer shall pay to the Employee, a lump sum on the
first regularly scheduled payday of the Employer which follows the effective
date of such termination, an amount equal to two (2) times the average of the
sum of amounts paid to the Employee for salary, bonus, including any amount
received as a Plan Confirmation Bonus and profit sharing for the five fiscal
years immediately preceding the effective date of the Termination Without Cause.
Any amounts paid to Employee pursuant to this paragraph shall be subject to any
applicable federal, state and local income tax withholding.
(c) Deemed Termination of Employment. In the event there is a "Deemed
Termination" of employment as described in Section 12 of this Agreement, the
Employer shall pay to the Employee the same compensation which Employee would be
entitled if the termination would have been a Termination Without Cause under
Section 10(b) above.
(d) Change of Control. In the event there is a "Change of Control Event" as
described in Section 11 of this Agreement, the Employer shall promptly pay to
the Employee, a lump sum on the first regularly scheduled payday of the Employer
which follows the effective date of such termination, an amount equal to two (2)
times the average of the sum of amounts paid to the Employee for salary, bonus,
including any amount received as Plan Confirmation Bonus, and profit sharing for
the five fiscal years immediately preceding the effective date of the
Termination Without Cause. Any amounts paid to Employee pursuant to this
paragraph shall be subject to any applicable federal, state and local income tax
withholding.
(e) Death. In the event of Employee's death during the term of this
Agreement, the Employer shall promptly pay to the Employee's beneficiaries, all
accrued compensation (including accrued vacation pay) and benefits as of the
date of death and all accrued expenses which are unpaid at the date of death,
together with an additional amount equal to one year's salary.
(f) Voluntary Termination. In the event of a Voluntary Termination,
Employer shall pay to Employee all accrued compensation (including accrued
vacation pay) and benefits as of the date of Voluntary Termination and all
accrued expenses which are unpaid at the date of Voluntary Termination.
11. Definition of Change in Control. For purposes of this Agreement, a
"change in control" will be deemed to have occurred on the first to occur of any
of the following events:
(a) As a result of a cash tender offer, stock exchange offer or other
takeover device, any person, as that term is used in Section 13(d) and 14(b)(2)
of the Securities Exchange Act of 1934, is or becomes a beneficial owner,
directly or indirectly, of stock of Employer or stock of Parent Company
representing thirty percent (30%) or more of the total voting power of
Employer's then outstanding securities;
(b) Any material realignment of the Board of Directors of Employer, or
Parent Company, or change in officers of Employer, or Parent Company, resulting
from a concerted shareholder action, including without limitation a proxy fight,
voting trusts or pooling arrangements;
(c) Any merger, consolidation or other reorganization of Employer, or
Parent Company, with any entity, other than its affiliates, whereby Employer, or
Parent Company, is not the surviving entity or the shareholders of Employer
otherwise fail to retain substantially the same direct or indirect ownership in
Employer or its affiliates immediately after any such merger, consolidation or
reorganization.
12. Deemed Termination of Employment. Employee shall be entitled to receive
the payment described in paragraph 10(b) above if any of the following occur
during the term of this Agreement:
(a) Employee is removed or released from any of his material titles,
positions or offices under this agreement, or Employee's duties and
responsibilities in such titles, positions or offices are materially changed;
(b) Employee's base salary is reduced; (c) Employee is removed from
participation in any of Employer's bonus or profit sharing programs, or any
bonus or profit sharing programs in which Employee was entitled to participate
immediately prior to the change; or (d) Employee's office is based more than 50
miles from the location of the principal office at which Employee was based
immediately prior to the change.
13. Covenant Not to Compete. During the entire period that the Employee
remains employed by the Employer pursuant to this Agreement, up to the effective
date of termination, the Employee shall not engage either directly or indirectly
in any activity or business, whether as an officer, director, sole proprietor,
employee, partner, majority shareholder, consultant or adviser, which is in
direct competition with any business engaged in by the Employer, except as
otherwise approved by the Employer.
14. Confidentiality. The business plans, marketing plans, development
plans, acquisition plans, construction plans, and financial data (the
"Confidential Information") of the Employer are, and shall remain, the valuable,
special, unique and proprietary assets of the Employer, access to and knowledge
of which are essential to the performance by the Employee of his duties under
this Agreement. The Employee shall not, during the term of this Agreement,
except as is necessary to promote the business of the Employer, or after the
term of his employment hereunder disclose the Confidential Information, in whole
or in part, to any person, firm, corporation, association, or other entity for
any reason or purpose whatsoever, nor shall the Employee make use of the
Confidential Information for the benefit of any person, firm, corporation or
other entity (except the Employer) under any circumstances during or after the
term of his employment. Upon the termination of this employment pursuant to this
Agreement, the Employee shall promptly return to the Employer any originals and
all copies of any Confidential Information which are in his possession. All
information shall cease to be Confidential Information at such time as it enters
the public domain, other than through the breach by the Employee of his
obligations under this paragraph 14.
15. Default. Should default occur in the performance of any of the
obligations set forth in this Agreement, the non-defaulting party shall be
entitled to obtain an injunction compelling the cure of such default and the
specific performance of the obligations of this Agreement in addition to any
action for damage or other relief which may be available to the non-defaulting
party. The defaulting party shall, in addition to any damages which may result
from said default, pay to the non-defaulting party the costs, including
reasonable attorney's fees, incurred by the non-defaulting party in curing such
default or in enforcing the terms and conditions of this Agreement. If a bond is
required by the Court, the parties agree that a bond in the amount of $500.00
shall suffice. The Employee understands and agrees that the Employer shall
suffer irreparable harm in the event that the Employee breaches any of the
Employee's obligations under this Agreement and that monetary damages shall be
inadequate to compensate the Employer for such breach.
16. Entire Agreement. This Agreement supersedes any prior understandings or
agreements, whether written or oral, between the parties hereto in regard to the
subject matter hereof and contains the entire agreement between the parties in
that regard. This Agreement may not be changed or modified orally, but only by
an agreement, in writing, signed by both of the parties.
17. Notices. Any notice which is required or permitted to be given to
either party to this Agreement shall be deemed to have been given only if such
notice is reduced to writing and delivered, by United States mail, with postage
prepaid and return receipt requested, to the appropriate party as set forth
below:
Employer: Bonneville Pacific Services Co., Inc.
50 West 300 South, Suite 300
Salt Lake City, Utah 84101
Attn: Chairman
Employee: Todd L. Witwer
11991 S. Nicklaus Road
Sandy, Utah 84092
Either party may change his address by giving notice of the change in the
manner set forth above. Any notice given shall be deemed delivered upon its
receipt in the United States mail.
18. Arbitration of Disputes. Any controversy, dispute or claim arising out
of or relating to this Agreement, or the breach thereof, which cannot be
resolved amicably by the parties shall be settled by arbitration in accordance
with the Rules of the American Arbitration Association, except in cases where
immediate action is required whether or not arbitration has been requested or is
in process, nothing herein shall prevent any party from pursuing equitable
remedies, including interim relief, in any court of competent jurisdiction, and
except as may be unanimously otherwise agreed by the parties.
In the event of arbitration, the cost of arbitration, including all
reasonable attorney's fees and costs, incurred by the successful party shall be
borne by the unsuccessful party unless otherwise ordered by arbitration.
19. Savings Clause. Should any part of a provision of this Agreement be
rendered or declared invalid by reason of any state or federal law, or by decree
of any court of competent jurisdiction, such invalidation of said part or
provision of this Agreement shall not invalidate the remaining portions hereof,
and the remaining parts and provisions of this Agreement shall remain in full
force and effect. 20. Governing Law. The parties specifically agree that this
Agreement shall be governed by and interpreted in accordance with the laws of
the State of Utah, without giving effect to the choice of law rules thereof.
IN WITNESS WHEREOF the parties hereto have executed this Employment
Agreement as of the date first herein written.
EMPLOYER
BONNEVILLE PACIFIC SERVICES COMPANY, INC.
By: /s/ Clark M. Mower
---------------------------------
CLARK M. MOWER
Chairman
EMPLOYEE
/s/ Todd L. Witwer
---------------------------------
TODD L. WITWER
AMENDED AND RESTATED
GENERAL PARTNERSHIP AGREEMENT
FOR
NEVADA COGENERATION ASSOCIATES #1
BY AND BETWEEN
BONNEVILLE NEVADA CORPORATION
AND
TEXACO CLARK COUNTY COGENERATION COMPANY
<PAGE>
TABLE OF CONTENTS
ARTICLE I.
FORMATION OF PARTNERSHIP
A. Formation of Partnership
B. Purposes
C. Name and Principal Place of Business
D. Term
ARTICLE II.
CONTRIBUTION OF THE PARTIES
A. Initial Capital
B. Additional Funding
C. Ownership Interest
D. Capital Accounts
E. Loan Account
ARTICLE III.
MANAGEMENT AND OPERATIONS
A. Management of the Partnership
B. The Executive Director and Other Officers
C. Day to Day Management by Executive Director
D. Management Committee
E. Insurance
F. Restrictions on the Partners; Acts Requiring Unanimous
Vote of the Management Committee
G. Reimbursement of Expenses
ARTICLE IV.
TAX MATTERS
A. Considered a Partnership
B. Allocation
C. Preparation of Tax Returns
D. Tax Matters Partner
E. Section 754 Election
ARTICLE V
DISTRIBUTIONS
A. Distributions
ARTICLE VI.
ACCOUNTING AND RECORDS
A. Books and Records
B. Reports
C. Fiscal year
D. Bank Accounts
ARTICLE VII.
TRANSFER OF PARTNERSHIP INTERESTS
A. Restrictions on Transfer
B. Right of First Refusal
C. Mortgage of Partnership Interest
D. General Transfer Provisions
E. Compliance
F. Prohibited Transfers
G. Repurchase of TCCCC's Interest in the Partnerships
H. Termination in Event of Delayed Startup
ARTICLE VIII.
DEFAULTS AND REMEDIES
A. Default of a Partner
B. Buy-Sell Procedure at Option of the Non-Defaulting Partner
ARTICLE IX.
RESOLUTION OF DISPUTES - ARBITRATION
A. Subjects of Arbitration
B. Agreement to Arbitrate
C. Submission to Arbitration and Selection of Arbitrators
D. Arbitration Procedure
E. Successor Arbitrators
F. Cost of Arbitration
ARTICLE X.
CONTRIBUTIONS TO PARTNERSHIP AND LIABILITIES OF PARTNERS
A. Contributions
B. Indemnification
ARTICLE XI.
DISSOLUTION AND WINDING UP
A. Dissolution
B. Winding Up
C. Compliance with Timing Requirements of Regulations
D. Rights of Partners
E. Waiver of Partition
ARTICLE XII.
GENERAL PROVISIONS
A. Integration
B. Interpretation
C. Negotiation and Enforcement of Contracts with Partners
D. Force Majeure
E. Successors and Assigns
F. Severability
G. Amendments and Waivers
H. Remedies
I. Binding Nature of This Agreement
J. Construction
K. Time
L. Headings
M. Incorporation by Reference
N. Additional Documents
O. Variation of Pronouns
P. Counterpart Execution
Q. Notices
R. Maintaining "Qualified Facility" Status
<PAGE>
THIS AMENDED AND RESTATED GENERAL PARTNERSHIP AGREEMENT
(hereinafter referred to as "Agreement") is made and entered into as of the
1stday of November, 1990, by and between TEXACO CLARK COUNTY COGENERATION
COMPANY, a Delaware corporation, (hereinafter referred to as "TCCCC", a wholly
owned subsidiary of TEXACO INC., a Delaware corporation, (hereinafter referred
to as "TI" and Bonneville Nevada Corporation, a Nevada corporation, (hereinafter
referred to as "Bonneville"), a wholly-owned subsidiary of Bonneville Pacific
Corporation, a Delaware corporation, (Hereinafter referred to as "BPC"). TCCCC
and Bonneville are each hereinafter referred to individually as a "Partner" and
collectively as "Partners". TI and BPC are each hereinafter sometimes referred
to individually as "Parent".
W I T N E S S E T H
1. WHEREAS, Bonneville and Bonneville General Corporation (hereinafter
"Bonneville General"), a Utah corporation and a wholly-owned subsidiary of
BPC have entered into a General Partnership Agreement dated October 8, 1990
("Partnership Agreement"), whereby a Utah general partnership was formed
("Partnership") for the purpose of designing, constructing, owning and
operating a Cogeneration facility (hereinafter referred to as "Cogeneration
Facility") which cogeneration facility is a qualifying facility as
described in the Public Utility Regulatory Policies Act of 1978, and the
regulations promulgated thereunder, all as amended (hereinafter referred to
as "PURPA"), to be located at Georgia-Pacific Corporation's
("Georgia-Pacific") gypsum plant in Clark County, Nevada, for the purpose
of (1) selling electric energy and capacity (hereinafter referred to as
"electric power") to (a) Nevada Power Company (hereinafter referred to as
"Nevada Power") and (b) any other entity (subject to limits of state and
federal law) and (2) selling thermal energy to (a) Georgia-Pacific and/or
(b) to any other entity; and
2. WHEREAS, TCCCC and Bonneville have agreed to jointly own, operate and
Contract for any future expansions of the Cogeneration Facility on the
Georgia-Pacific project site; and
3. WHEREAS, TCCCC has purchased from Bonneville General its fifty percent
(50%) interest leaving Bonneville and TCCCC, each with a fifty percent
general partnership ownership interest in said Partnership (the
"Partnership Interest" or "Ownership Interest") and leaving Bonneville
General with no interest therein;
4. WHEREAS, Texaco Gas Marketing Inc., a Delaware corporation ("TM") and
Texaco Producing Inc., a Delaware corporation ("TIP") both a subsidiary of
Texaco Inc., Texaco Cogeneration and Power Company, a division of Texaco
Inc., ("TCP"), Bonneville and BPC have executed a Memorandum of
Understanding dated October 5, 1990 (the "MOU") specifying the commercial
terms and conditions by which TCCCC was to acquire the Partnership
Interest, and it is the intention of the parties hereto that this Agreement
hereby incorporates, supersedes and takes precedence over said MOU with
respect to the subject matter hereof;
5. WHEREAS, pursuant to the terms of the MOU, Bonneville and TGMI have
negotiated the Partnership will execute concurrently with this Agreement, a
Gas Supply Agreement and Fuel Management Agreement;
6. WHEREAS, The Partners desire to revise and restate the previously executed
Partnership Agreement by and between Bonneville and Bonneville General and
it is the intention of the parties hereto that this Agreement hereby
supersedes and takes precedence over said Partnership Agreement.
NOW, THEREFORE, IN CONSIDERATION OF THE MUTUAL COVENANTS AND AGREEMENTS
CONTAINED HEREIN, THE PARTIES HERETO AGREE THAT THE PARTNERSHIP AGREEMENT IS
HEREBY AMENDED AND RESTATED IN ITS ENTIRETY AS FOLLOWS;
ARTICLE I.
FORMATION OF PARTNERSHIP.
A. Formation of Partnership. Bonneville and TCCCC hereby acknowledge the
formation of a general partnership between them under the provisions of the
Uniform Partnership Act of the State of Utah.
B. Purposes.
1. The primary purpose of the Partnership is to design, construct, own, and
operate the Cogeneration Facility in order to:
a. Provide electric power for Nevada Power Company and any other entity
with which the Partnership may contract to deliver lactic power; Make
Bonneville's capital contributions and treat such contributions as a loan to the
Partnership, secured by Bonneville's Ownership Interest, as defined in paragraph
C., below; and
b. Provide thermal energy required for Georgia-Pacific or any other thermal
host acceptable under PURPA ("Thermal Hosts) at the same or different location
to which the Partnership may choose to relocate the Cogeneration Facility; and
c. Cause said Cogeneration Facility to qualify and continue as a qualifying
Cogeneration facility exempted from specific federal and state regulations by
Federal Energy Regulatory Commission regulations issued under Section 210 of
PURPA.
2. Further, it is the intent of the Partners that the Partnership:
a. Carry on any business whatsoever that it may deem proper or convenient
in connection with any of the foregoing purposes or otherwise, or that it may
deem calculated, directly or indirectly, to improve the interests of this
partnership.
b. Have and exercise the power to do all things specified in the Uniform
Partnership Act; and
c. Have and exercise all powers conferred by the laws of the State of Utah,
as such laws are now in effect or may at any time hereafter be amended.
3. Anything in the foregoing statement of purposes to the contrary
notwithstanding, it is specifically agreed that the Partnership shall
not dedicate any of its property, including the Cogeneration Facility,
to the service of the public or any portion thereof as a public
utility. Any service rendered by the Partnership for the sale of
electric power or thermal energy shall be limited to sales under
specific contract, terminable in accordance with the terms thereof, and
at prices specifically set forth or determined by formula therein and
in a manner that does not adversely affect, from the Partners'
standpoint, the qualifying facility status of the Cogeneration
Facility.
C. Name and Principal Place of Business. The business of the Partnership will
be conducted under the name of Nevada Cogeneration Associates #1
(hereinafter referred to as "NCA1") and its principal place of business
shall be maintained at 257 East 200 South, Suite 800, Salt Lake City, Utah
84111. The principal place of business may be changed from time to time,
and other places of business may be established by actions taken in
accordance with provisions of this Agreement that govern management of the
Partnership's business and affairs. Each Partner shall execute and timely
file all requisite statements of doing business under a fictitious name and
execute, record and maintain in currently effect statements of partnership
or other documentation in the form and locations as required by law.
D. Term. The Partnership commenced as of October 8, 1990 and shall be
dissolved and its affairs wound up, unless sooner dissolved pursuant to
this Agreement, on the later of April 30, 2023, or the date the Partnership
elects to cease operating the Cogeneration Facility. ARTICLE II.
CONTRIBUTIONS OF THE PARTIES
A. Initial Capital. The Partners have determined the amount of capital
initially required To be contributed to make the construction and operation
of the Cogeneration Facility financially viable (hereinafter referred to as
"Initial Capital"). Monetary contributions and percentage interests of the
Partners upon execution of this Agreement are set forth Exhibit A, attached
hereto.
1. Bonneville has assigned or will assign to the Partnership for the
Partnership for the Partnership's benefit, subject to the provisions of
paragraph 2 below, certain identified no-cash contributions, including
certain agreements, licenses and permits as identified on Exhibit B. Such
contributions shall specifically exclude rights to bid contemplated in the
Amended and Restated Business Agreement on paragraph 12, page 10, dated
September 12, 1989 between Georgia-Pacific and Bonneville. The non-cash
contributions include expenditures and agreements that carry obligations
and liabilities, which are to be assumed by the Partnership.
2. Bonneville shall retain in its name for the benefit of the Partnership such
permits, licenses and/or other rights as would be difficult or
disadvantageous to transfer to the Partnership until such time as the
Partners agree that it is possible and preferable to transfer such permits,
licenses and/or other rights to the partnership. Such permits, licenses,
and/or other rights not assigned to the Partnership shall be dedicated by
Bonneville to the exclusive use of the Partnership and held in escrow by an
agent of the Partnership at a time and place as set forth by the Management
Committee for the benefit of the Partnership Interest in the event of
default by Bonneville as described in Article VIII., "DEFAULTS AND
REMEDIES," below. Bonneville shall not sell, pledge, assign, loan or
otherwise encumber such permits to any other party without the express
written consent of TCCCC, except as required for Financing the Cogeneration
Facility. The partnership will indemnify, defend and hold Bonneville
harmless from any and all claims, costs, loss or liabilities resulting form
any partnership's action (s) or inactions of the Partnership regarding the
permits.
3. Bonneville shall continue to use diligent efforts until such time as all
assignable rights, title and interest have been assigned to the Partnership
and shall attempt to accomplish this within ninety (90) days after the
execution date of this Agreement. To the best of Bonneville's knowledge,
Exhibit B contains all permits, licenses and other rights held by
Bonneville for the benefit of the Cogeneration Facility or which may be
obtained in the name of Bonneville for the benefit of the Cogeneration
Facility. If any permits, licenses or real property rights required for the
Cogeneration Facility are later obtained by the partners and found not to
be listed in Exhibit B, such shall be transferred to the Partnership
without charge except for out of pocket costs incurred in the transfer.
4. Additional Funding. The Partners shall attempt to obtain non-recourse
Financing (the "Financing") for the Cogeneration Facility in the
approximate amount of One Hundred Seven Million Dollars ($107,000,000). The
Partners shall provide all reasonably necessary guarantees and assurances,
provided that the Partners acknowledge that the foregoing is subject to
further approval by their respective Board of Directors in such board's
sole discretion. Upon the close of Financing for the Cogeneration Facility,
the Partnership shall remit development fees, repayment of loans for
project construction work in progress and other payments to the partners as
agreed upon by the Partners. The Partnership shall attempt to acquire
equipment for the Cogeneration Facility on extended payment terms or other
financing terms acceptable to the Partners. The Partnership shall exercise
its best efforts to obtain any letters of credit required to obtain such
extended payment of financing terms. Upon unanimous vote by the Management
Committee in accordance with Article III, paragraph F, the Partnership
shall reimburse the Partners from the Financing for any advances made to
the Partnership under this paragraph.
1. All working capital contributions of TCCCC and Bonneville made to the
Partnership prior to obtaining Financing shall be in the form of an equity
contribution, and such contribution may be recovered with proceeds obtained from
draws from the Financing for the project.
2. Working capital, in excess of the funds being provided by the Financing,
required by the Partnership shall be provided by equity contributions of the
Partners upon the unanimous approval of the Management Committee. Specifically,
the Partners shall share on going, third party development costs or expenses
incurred on the Partnership's behalf on an equal basis.
3. All capital contributions shall be made in pro rata shares based upon
each Partner's ownership interest in the Partnership.
4. Failure by TCCCC to honor its capital contribution obligations within
thirty (30) days after written notification by the Partnership shall entitle
Bonneville to the following:
a. Bonneville may make TCCCC's capital contributions and treat such
contributions as a loan to the Partnership, secured by TCCCC's Ownership
Interest, as defined in paragraph C., below; and
b. Bonneville may assume day-to-day management of the Partnership.
5. Failure by Bonneville to honor its capital contribution obligations
within thirty (30) days after written notification by the Partnership shall
entitle TCCCC to the following:
a. TCCCC may make Bonneville's capital contributions and treat such
contributions as a loan to the Partnership, secured by Bonneville's
ownership Interest, as defined in paragraph C., below; and
b. TCCCC may assume day-to-day management of the Partnership.
C. Ownership Interest. The term "Ownership 'Interest" means all of a Partner's
rights and interests in the Partnership. Subject to the provisions of
ARTICLE VIII, Defaults and Remedies, each Partner shall have an equal
Ownership Interest in the Partnership. Both TCCCC and Bonneville have
contributed cash and non-cash contributions to the Partnership. For all
value added on formation of the Partnership, both cash and non-cash,
TCCCC's and Bonneville's ownership Interests in the Partnership shall each
be fifty percent (50%). Said Ownership Interests shall be reflected in the
Capital Accounts of the Partnership as referenced below in paragraph D.
D. Capital Accounts. Partnership capital transactions shall be recorded in
individual capital accounts (hereinafter referred to as "Capital Accounts")
established and maintained for each Partner. Such Capital Account shall be
1) increased by: a) its share of any additional capital contributions, and
b) its share of Partnership profits, and 2) decreased by: a) its share of
Partnership losses, b) any withdrawals or distributions of initial or
additional capital contributions, c) any distributions of Partnership cash,
and d) any other distributions made to the Partners.
E. Loan Account. A Loan Account shall be established and maintained for each
Partner separate from the Partner's Capital Account. Loans made by each
Partner to the Partnership will be credited to that Partner's Loan Account.
Loans by the Partnership to a Partner shall be debited to that Partner's
Loan Account. Interest on, and repayment terms and conditions for, advances
through the Loan Accounts shall be determined by the Management Committee
referred to in ARTICLE III; provided, however, that if the Management
Committee is unable to agree, then the interest shall be at the floating
prime rate established by the Bank of America, NT & SA, San Francisco,
California, in effect from time to time. A credit balance in the Partner' s
Loan Account shall constitute a liability of the Partnership to that
Partner; it shall not constitute a part of that Partner's Capital Account.
A debit balance in a Partner's Loan Account shall constitute an obligation
of that Partner to the Partnership and shall not constitute a part of that
Partner's Capital Account.
ARTICLE III.
MANAGEMENT AND OPERATIONS.
A. Management of the Partnership. Each of the Partners shall have equal
rights in the management of the business of the Partnership and shall exercise
such rights through a management committee (hereinafter referred to as
"Management Committee") consisting of two representatives from each Partner.
B. The Executive Director and other Officers. The Executive Director shall
be appointed by the Management Committee to direct the day-to-day activities of
the Partnership, as defined in paragraph C. below, prepare the agenda for
Management Committee meetings, assure that all contracts and payments for
supplies and services rendered are conducted in an "arm's length" fashion in
accordance with Article XII, paragraph C., and perform only such duties as from
time to time may be directed by the Management Committee. The Executive Director
shall be an employee of either Partner on loan to the Partnership. The Executive
Director shall be officed at the Partnership's principal place of business as
stated in Article I, paragraph C. Both Partners understand and agree that the
Executive Director and all other officers so assigned to the Partnership have a
fiduciary duty to the Partnership and, as such, will preserve, protect and
defend the subject matter of the Partnership. The Management Committee may also
appoint additional officers, such as a Secretary and a Treasurer" as it deems
necessary and desirable, who shall perform such functions and duties as the
Management Committee may, from time-to-time, direct. The Executive Director and
any other officer may be removed at any time by unanimous vote of the Management
Committee for any reason and by any Partner for reasonable cause, provided that
if the other Partner objects to such removal, reasonable cause for the removal
shall be determined by arbitration under the provisions of Article IX.
C. Day-to-Day Management by Executive Director. Subject to supervision of
the Management Committee, and the limitations and restrictions set forth in this
Agreement, including, without limitation, those set forth in this Article III,
the Executive Director shall act on behalf of the Partnership in all matters
affecting the day-to-day management and supervision of the Partnership and its
business affairs, including implementing the then applicable Business Plan, as
defined below, and shall have all rights and powers generally conferred by law
or otherwise necessary, advisable or consistent therewith. In addition to any
other rights and powers, the Executive Director may exercise the following
specific rights and powers without any further consent of the Partners being
required, except to the extent provided in paragraph F. below: 1. To expend any
monies of the Partnership to the extent permitted by this Agreement and in
accordance with the then applicable Business Plan;
2. To ask for, collect and receive any rents, issues and profits
or income from any property of the Partnership, or any part or
parts thereof, and to disburse Partnership funds in accordance
with the approved Business Plan and this Agreement.
3. To purchase from or through others, contracts of liability,
casualty or other insurance for the protection of the
properties or affairs of the Partnership or the Partners, or
for any business purpose convenient or beneficial to the
Partnership as instructed by the Management Committee;
4. To pay all taxes, licenses or assessments of whatever kind or
nature imposed upon or against the Partnership or the Project,
and for such purposes to make such returns and do all other
such acts or things as may be deemed necessary and advisable
by the Partnership. Since TCCCC is the tax matters partner, as
defined in Article IV. "TAX MATTERS" below, TCCCC shall be
responsible for preparing said returns with the assistance and
review of the Executive Director.
5. To establish, maintain and supervise the deposit of any monies
or securities of the Partnership with federally insured
banking institutions or other institutions, in accounts in the
name of the Partnership with such institutions as instructed
by the Management Committee;
6. With the unanimous vote of the Management Committee, to
institute, prosecute, defend, settle, compromise and dismiss
lawsuits or other judicial or administrative proceedings or
arbitration proceedings brought on or in behalf of, or
against, the Partnership or the partners in connection with
activities arising out of, connected with or incidental to
this Agreement, and to engage counsel or others in connection
therewith;
7. To execute for and on behalf of the Partnership, and with
respect to the Project, all such applications for permits and
licenses as he/she deems necessary and advisable, and to
execute and cause to be filed and recorded all such
subdivision, parcel or similar maps covering or relating to
the Project deemed advisable;
8. To perform all ministerial acts and duties relating to the
payment of all indebtedness, taxes and assessments due or to
become due with regard to the Cogeneration Facility, and to
give and receive notices, reports and other communications
arising out of or in connection with the ownership,
indebtedness or maintenance of the Project; and
9. To conduct the affairs of the Partnership as specifically set forth
herein.
D. Management Committee.
1. The Management Committee shall meet as often as any member thereof
reasonably determines is necessary. -Members may participate in meetings
personally or telephonically. Records of proceedings of the Management Committee
shall be prepared by the Executive Director or Secretary and shall be approved
by the Management Committee members.
2. At least five (5) days advance written notice of each meeting of the
Management Committee shall be provided to each member, unless a member not
receiving advance notice waives the advance notice requirement. The Management
Committee shall act upon the majority vote of a quorum of its members properly
attending a duly convened meeting of the Committee, except when unanimous vote
of the Management Committee is required as provided elsewhere in this Agreement.
Members of the Management Committee may designate an alternate for the purpose
of votes and attendance. The Management Committee may also take any action
permitted to be taken herein at a meeting of the Committee, by written consent
joined in by all of the members of the Committee.
3. The Management Committee shall make all policy and general business
decisions of the Partnership and shall supervise the day-to-day activities of
the Executive Director. The Management Committee shall hear progress reports
from the Executive Director and the Partner and employees of the Partners who
are engaged in conduct of the Partnership's business, and the Management
Committee shall instruct each Partner as necessary and proper in conducting the
Partnership's business. The responsibilities of the Management Committee shall
include, among other things, action of the following matters:
a. Adoption of significant policies.
b. Approval of distributions of Partnership cash.
c. c. Voluntary prepayment or extension of debt incurred to
purchase, construct, refinance, develop or operate the
Partnership facilities.
d. The selection, removal, and changes in authority and
responsibility of the Executive Director, operator or any
other Partnership officers and the operations as provided for
in the operations and Management Agreement
e. The selection of lawyers, accountants, independent third party
auditors, bankers, investment bankers and any other
consultants or employees.
f. Any loans or other forms of indebtedness by the Partnership to the Partners.
g. Approval of any press release by the Partnership.
h. Engaging in any business on behalf of the Partnership other
than that referred to in Article I, paragraph B.
i. Appointment of select subcommittees to facilitate problem
resolution and technical liaison functions. Such subcommittees
shall report directly to and shall be under the exclusive
control of the Management Committee. Initially there shall be
appointed by the Management Committee the following
subcommittees: 1) Legal Contracts; 2) Finance; and 3)
Operations-Engineering.
4. The Management Committee shall determine whether a Business Plan
will be prepared by the Executive Director on a quarterly or semiannual basis.
At least fifteen (15) days prior to' the first Management Committee meeting of
each quarter or half-year as determined by the Management Committee, at which
such Business Plan will be considered, the Executive Director shall prepare and
distribute for the consideration and approval of the Management committee a
Business Plan for the next quarter or half-year, as applicable. The Business
Plan shall be approved by unanimous vote of the Management Committee. The
Executive Director without the prior unanimous vote of the Management Committee
shall make no material changes or departures from any item in the Business Plan.
The Executive Director or Treasurer, or his designee, shall report to the
Management Committee during the same meeting on the Business Plan, the current
and/or forecasted financial status of the Partnership funds and Financing. The
Business Plan shall include the following:
a. A narrative description of any activity proposed to be undertaken;
b. a projected annual income statement (accrual basis) on a quarter-by-quarter
basis;
c. a projected balance sheet as of the end of the period;
d. a schedule of projected operating cash flow (including itemized operating
Revenues, Project costs and Cogeneration Facility expenses) for such fiscal
year on a quarter-by-quarter basis, including a schedule of projected
operating deficits, if any, and a calculation of debt service ratios;
e. A description of any proposed construction and capital expenditures,
including projected dates for commencement and completion of the foregoing;
f. A development schedule identifying the projected development periods as
well as the times for completion of the various stages of the development
of Cogeneration Facility and the costs attributable to each such stage;
g. A description of the proposed investment of any funds of the Partnership
which are (or are expected to become) available for investment;
h. A description of any proposed sale of the Project;
i. Description, including the identity of the recipient (if known) and the
amount and purpose, of all fees and other payments proposed or expected to
be paid for professional services and, if a fee or payment exceeds
@?50,000, for other services rendered to the Partnership by third parties;
j. A detailed description of such other information, plans, maps, contracts,
agreements or other matters that are reasonably necessary in order to
inform the Management Committee of matters relevant to the development,
operation, management and sales of the Cogeneration Facility or any portion
thereof or to enable the Management Committee to make an informed decision
with respect to its approval of such Business Plan or as may be reasonably
desired by the Management Committee; and
k Any other matters with respect to the operation and management of the
Partnership that the Executive Director determines to include therein,
provided that such Business Plan shall not include any proposal for
additional working, development or pre-construction capital contributions
from the Partners for the purpose of additional financing or refinancing of
the Cogeneration Facility (any such proposal shall be separately considered
by the Management Committee and shall require the unanimous vote of the
Committee pursuant to paragraph F below).
E. Insurance. The Executive Director shall at the direction of the Management
Committee procure and maintain, or cause to be procured and maintained
insurance sufficient to enable the Partnership to comply with applicable
laws, regulations and requirements. If requested by the other Partners, the
Executive Director shall furnish the Partners, no less frequently than
annually, a schedule of such insurance and copies of certificates
evidencing the same.
F. Restrictions on the Partners: Acts Requiring Unanimous Vote of the
Management Committee. Notwithstanding anything in this Agreement to the
contrary, the following acts shall require approval by a unanimous vote of
the Management Committee and neither the Executive Director nor any Partner
shall have any authority to do any of the following acts on behalf of the
Partnership without the unanimous vote of the Management Committee (except
to the extent that the matter in question is included in, and budgeted for
or permitted by, the then effective Business Plan):
1. Sale or encumbrance of all or a major portion of the Partnership's assets.
2. Adoption of a quarterly and/or semi-annual business plan And budget for the
Cogeneration Facility's operations.
3. Executing additional or modifying existing contracts (i.e., those for fuels
management, natural gas sales., etc.).
4. Expenditures above the Cogeneration Facility's approved budget.
5. Any indebtedness not approved in the Cogeneration Facility's Business
Plan(s) and/or budget.
6. Admission of a new general partner to the Partnership.
7. Tax decisions or elections of the Partnership.
8 All distributions and returns of capital to the Partners from the
Partnership.
9. All decisions regarding the composition of fuel supply to be used or
acquired for the Cogeneration Facility.
10. Dissolution of the Partnership.
11. All cash flows to or from the Partners from Financing.
12. All decisions regarding changes to be made to the Facility (i.e., locating
a new thermal host) so that the qualified facility status under PURPA can
be maintained.
13. Changing the principal place of business as stated in Article I, paragraph
C.
14. Removal of the Executive Director and any other officer as provided for in
Article III, paragraph B.
15. Selection of outside independent auditors as required by lenders or for
other independent audits as desired by the Management Committee.
Notwithstanding the above, the Executive Director has the right to take such
actions as it, in its reasonable judgment, deems necessary for the protection of
life or health or the preservation of Partnership assets if, under the
circumstances, in the good faith estimation of the Executive Director, there is
insufficient time to allow the Executive Director to obtain the approval of the
Partners or the Management Committee to such action and any delay would
materially increase the risk to life or health or preservation of assets.
G. Reimbursement of Expenses. The Partnership shall reimburse each Partner or
any parent or affiliate of a Partner for the actual cost, both direct and
indirect and properly allocated overhead, incurred in pursuit of the
Partnership's business consistent with the provisions of this Agreement. Such
expenses shall be deducted from the income of the Partnership in the same manner
as any other operating expense in determining profits Or losses-
1. Without limitation, reimbursement expenses shall include travel
expenses and that portion of expenses incurred by a Partner to maintain
and support on-site personnel who conduct Partnership business that is
reasonably allocable (based upon time records, etc.) to the business
and operations of the Partnership, and non-reimbursable expenses shall
include any expenses attributable to any Partner's headquarters
management and staff time to develop the Cogeneration Facility.
2. The Partnership may agree upon a fixed rate, which the management
committee shall determine for such indirect cost and properly allocated
overhead. The Management Committee shall agree upon an appropriate
method for determining any such actual costs and upon an appropriate
billing method.
Each of the Partners shall have the right to audit the books and records of
any Partner, its parent or any affiliate, but only with respect to the costs
of any employee which are charged to the Partnership pursuant to this section.
This right to audit with respect to any such employee costs shall expire two
(2) years after the close of the fiscal year in which the Partnership was
charged for such employee costs. Each Partner may also take written exception
to such employee costs within such two (2) year period. The cost of any such
audit will be borne solely by the Partner requesting the audit.
ARTICLE IV.
TAX MATTERS.
A. Considered a Partnership. The Partners intend that, pursuant to the
provisions of Subchapter K of Chapter 1 of Subtitle A of the Internal Revenue
Code of 198 6 (hereinafter referred to as "Code") , the Partnership will be
treated as a partnership for United States, state and local income tax purposes.
Specifically, each Partner agrees not to make an election, as permitted by Code
Section 761, to be excluded from the application of the provisions of Subchapter
K. Each Partner also agrees not to give any notices or take any other action
inconsistent with the Partnership election.
B. Allocation. All items of income, gain, loss, deduction or credit shall be
allocated to each Partner on the basis of its Ownership Interest" as defined in
Article II Section C, except, (a) property contributed to the Partnership by a
Partner, for which depreciation, depletion or gain or loss shall , pursuant to
"Code Section 704(c) and the attendant regulations thereto, be shared among the
Partners so as to take account of the variation between the basis of the
property to the Partnership and its fair market value at the time of
contribution and (b) tax credits assigned by one Partner to the other; and (c)
as set forth in Article V, paragraph B.
C. Preparation of Tax Returns. The Tax Matters Partner shall cause the
preparation and filing of United States, state and local tax returns on behalf
of the Partnership. Any costs paid by the Tax Matters Partner including costs of
preparation and the taxes and fees paid will be reimbursed by the Partnership.
Each Partner agrees to furnish the Tax Matters Partner such information as each
Partner may have which is required for the proper and timely preparation of such
returns. on behalf of the Partnership, the Tax Matters Partner shall make the
following elections under the Code and the attendant regulations thereto and any
similar state statutes:
1. To elect to adopt the calendar year as the annual accounting period.
2. To elect to adopt the accrual method of accounting.
3. To elect to compute the allowance for depreciation utilizing the shortest
life permissible under the Accelerated Cost Recovery System or other
applicable depreciation system.
4. To elect to amortize start-up expenditures, if any, over sixty (60) month
period in accordance with Code Section 195(c) and any similar state
statutes; and
5. To make such other elections as may be approved by the Partners; provided,
however, that if such approval is not achieved,, then all such elections
and other tax decisions shall be made is such a way as to reduce
Partnership taxable income to the maximum extent possible and take
deductions in the earliest taxable year possible.
D. Tax Matters Partner. TCCCC is hereby designated by each Partner to act as the
Tax Matters Partner for purposes of representing the Partnership on all tax
matters and before all tax agencies.
E. Section 754 Election. The Partnership shall, if requested by any Partner,
make the election under Code Section 754.
ARTICLE V.
DISTRIBUTIONS.
Partnership net cash from operations shall be allocated and distributed
regularly to the Partners in amounts mutually agreed upon from Partnership
operations less the portion thereof used to pay or establish reserves for all
Partnership expenses, debt payments, capital improvements, replacements and
contingencies, all as may be determined by the Partners (hereinafter referred to
as "Net Cash Distributions").
A. Bonneville and TCCCC shall share in cash distributions and allocations of
depreciation expenses and other tax benefits from the Cogeneration Facility on
an equal basis, except as provided below.
B. Notwithstanding paragraph A. above, Bonneville shall be entitled to a
sixty-six and two-thirds percent (66 2/3%) disproportionate share of Net Cash
Distributions and TCCCC shall be entitled to a thirty-three and one-third
percent (33 1/3%) share of Net Cash Distributions until such time as 16 2/3% of
the cumulative Net Cash Distributions equals $2'f45d,000 ("Disproportionate
Increment"). The $2,450,000 Disproportionate Increment will be increased by
$40,000 for each $1,000,000 of allocation for tax exempt financing that is
obtained over and above the first $10 million of / 'allocation for the
Cogeneration Facility prior to the Cogeneration Facility's commercial operation
date.
ARTICLE VI.
ACCOUNTING AND RECORDS.
A. Books and Records. The Executive Director shall keep at his or her of f ices
or at any other of f ice approved by unanimous vote of the Management Committee
separate books of account for the Partnership. Such books of account shall show
a true and accurate record of all costs and expenses incurred, all charges made,
all credits made and received and all income derived in connection with the
operation of the Partnership business in accordance with generally accepted
accounting principles consistently applied. In its discretion the Executive
Director may cause accountants who are employees of the Executive Director to
keep the Partnership' s books of account or the Executive Director may hire
/third party accountants to keep the Partnership's books of account. Expenses
chargeable to the Partnership shall include only those expenses which are
reasonable and necessary for the ordinary and efficient operation of the
Partnership business and the performance of the obligations of the Partnership
under any leases or other agreements relating to the Project or the business of
the Partnership, and are within the Business Plan. Contracts between the
Partnership and a Partner will not violate this requirement as long as the
contracts have been approved in accordance with Article III, paragraph F and are
in conformance with Article XII, paragraph C. Each Partner shall, at its sole
expense, have the right, at any time without notice to the other, to examine,
copy and audit the Partnership's books and records during normal business hours.
C. Reports.
1. The Executive Director shall be responsible for the preparation of
financial Reports of the Partnership and the coordination of financial matters
of the Partnership with the Partnership's accountants. Within ninety (90) days
after the end of each fiscal year and within forty-five (45) days after the end
of any fiscal quarter, the Executive Director shall cause each Partner to be
furnished with a copy of the balance sheet of the Partnership as of the last day
of the applicable period, and a statement of income or loss for the Partnership
for such period, which shall be prepared from the books and records of the
Partnership. The Partnership's annual statements shall be prepared in accordance
with generally accepted accounting principles consistently applied and shall be
audited by a firm of independent public accountants of national standing, unless
the Management Committee, by unanimous vote, shall determine that such audit is
not required. The Executive Director shall also cause to be prepared a statement
showing any item of income, deduction, credit or loss allocable for federal
income taxes purposes pursuant to the terms of this Agreement. The Partnership's
quarterly financial statements shall be prepared on a basis generally consistent
with the audited annual financial statements.
2. At any time any Partner may, at the Partner's own expense, cause the
Partnership' s
financial statements or books of account to be reviewed by accountants,
auditors, attorneys or other authorized representatives of the Partner.
D.. Fiscal Year. The fiscal year of the Partnership shall be from January I
through December 31, unless otherwise approved by the Partners. As used in this
Agreement, a fiscal year shall include any partial fiscal year at the beginning
and end of the Partnership term.
E. Bank Accounts. The Executive Director shall have fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Executive Director's immediate possession or
control. The funds of the Partnership shall not be commingled with the funds of
any Partner or any other person, and the Management Committee shall not employ,
or permit any other person to employ, such funds in any manner except for the
benefit of the Partnership. The bank accounts of the Partnership shall be
maintained in the name of the Partnership in such banking institutions as are
approved by the Management Committee and withdrawals shall be made only in the
regular course of Partnership business and as otherwise authorized in this
Agreement on such signature or signatures as the Executive Director may
determine. All funds of the Partnership shall be invested in accordance with the
then applicable Business Plan.
ARTICLE VII.
TRANSFER OF PARTNERSHIP INTERESTS.
A. Restrictions on Transfer. Except as expressly provided for in this Agreement,
no Partner may, without the prior written consent of the other Partner, which
consent shall not be unreasonably withheld, -mortgage (except as provided in
paragraph D. below) , pledge, sell, transfer or otherwise dispose of
("Transfer") all or any portion of the Partner's Partnership Interest or any
interest the Partner may have in any property of the Partnership or withdraw or
retire from the Partnership. Provided however, a Partner may, without the prior
written consent of the other Partner, transfer its Partnership Interest or any
interest it may have in any property of the Partnership to a wholly owned direct
or indirect subsidiary of the Partner or a wholly owned direct or indirect
subsidiary of the parent of a Partner. Any such attempted Transfer, withdrawal
or retirement not permitted hereunder shall be null and void.
B. Right of First Refusal.
If the other Partner approves a proposed Transfer or the prohibitions
contained in paragraph A above are determined by a court of competent
jurisdiction to be unenforceable, then the Partner desiring to Transfer all or a
portion of its Partnership interest shall send a notice ("Offering Notice") to
the other Partner(s) . The offering Notice shall be in writing and shall inform
the non-transferring Partner of the transferring Partner's intention to
effectuate a Transfer. The Offering Notice shall specify the nature of the
Transfer, the consideration to be received therefor, the identity of the
proposed purchaser (or lender, as the case may be), and the terms upon which the
transferring Partner intends to undertake such Transfer.
The non-transferring Partner(s) shall have the right to elect to purchase from
the transferring Partner all (but not less than all) of the Partnership Interest
referred to in the Offering Notice at the same price and on the same terms as
specified in the Offering Notice for a period of thirty (30) days after the date
of the offering Notice (or the non transferring Partners) shall be entitled to
make the loan, if the same involves an encumbrance, hypothecation or mortgage,
upon the same terms on which said loan was to be made) by delivering in writing
to the transferring Partner an offer to purchase (or loan) that portion of the
Partnership Interest of the transferring Partner covered by the Offering Notice.
If more than one Partner elects to so purchase (or encumber), the offered
Partnership interest shall be sold to (or the loan shall be made by) the
electing non-transferring Partner(s) in proportions that their respective
Percentage Interests bear to the total of the Percentage Interests of all
electing non transferring Partners). Within forty-five (45) days thereafter, the
purchase by the non-transferring Partner (s) of said Partnership interest shall
be consummated on the terms and conditions set forth in the Offering Notice of
the transferring Partner (or if the same involves a mortgage, encumbrance or
other hypothecation, the loan shall be consummated upon the terms and conditions
of the loan set forth in the Offering Notice).
If the non-transferring Partner fails to elect to purchase within the 30-day
period the transferring Partner's Partnership Interest covered by such offering
Notice (or to elect to make the loan specified therein), the transferring
Partner may undertake and complete the Transfer to any Person whose identity was
disclosed in the Offering Notice. The Transfer shall not be undertaken with
respect to any portion of the transferring Partner's Partnership Interest other
than as set forth in such Offering Notice, at a lower price or upon more
favorable terms to the purchaser (or lender) than specified in the Offering
Notice. If the transferring Partner does not consummate such Transfer within
sixty (60) days after the date of the Offering Notice, or within the time
scheduled for closing pursuant to the offering Notice, whichever is later, then
all restrictions of this paragraph B shall apply as though no Offering Notice
had been given.
D. Nothing in this ARTICLE VII shall preclude a merger, sale of assets,
sale of stock, consolidation, combination or other corporate reorganization by
or of a Partner or a corporation which on the date of this Agreement owns
directly or indirectly the stock of a Partner.
E. Mortgage of Partnership Interest. Both Partners may mortgage their
Partnership Interests in order to obtain Financing.
F. General Transfer Provisions. All Transfers shall contain an agreement by the
Transferee of its intention to accept the assignment and to accept and adopt and
be bound by all of the terms and provisions of this Agreement, as the same may
have been amended, and shall provide for the payment by the transferring Partner
of all reasonable expenses incurred by the Partnership in connection with such
assignment, including, without limitation, the necessary amendments to this
Agreement to reflect such Transfer. The transferring Partner shall execute and
acknowledge all such instruments, in form and substance necessary or desirable
to effectuate such Transfer. In no event shall the Partnership dissolve or
terminate (other than for tax purposes, to the extent provided by the Code and
Regulations) upon the admission of any Partner to the Partnership or upon any
permitted Transfer of an interest in the Partnership by any Partner.
G.. Compliance. Notwithstanding anything to the contrary in this Agreement,
at law or in equity, no Partner shall Transfer or otherwise deal with any
Partnership interest in a way that would cause a default under any material
agreement to which the Partnership is a party or by which it is bound, nor in
such a way to give a greater than fifty percent (50%) partnership interest to
any public utility whether such greater than 50-t interest is created by the
single transfer of a partner, by a combination of transfers by a Partner or
Partners, or by the corporate structure of the Partners and/or their parent
companies.
H. Prohibited Transfers. Notwithstanding this ARTICLE VII or any other
applicable paragraph in this Agreement, no Partner may at any time assign,
convey, mortgage, pledge, sell, transfer, or otherwise dispose of all or part of
its Ownership Interest or interest in this Agreement to any person or entity
whose ownership of an interest in the Partnership or in this Agreement would
cause the Cogeneration Facility not to be a qualified cogeneration facility, as
defined in, and pursuant to, PURPA.
I. Repurchase of TCCCC's Interest in the Partnerships.. At TCCCC's sole
option, Bonneville shall have the obligation to repurchase or caused to be
purchased, TCCCC's Ownership Interest in the Partnership on the later of twenty
(20) years from the date of commencement of commercial operations or December
31, 2011, whichever is later, at fair market value as determined by an
independent appraiser agreed upon by TCCCC and Bonneville.
1. In the event that the Partners cannot agree upon the appraiser, each
shall select an appraiser and the two appraisers shall select a third.
In such event the fair market value shall be an average of all three
appraisals.
2. In the event that TCCCC exercises its option, Bonneville shall
release, indemnify, defend and hold TCCCC harmless from any loss, cost
or liabilities occurring after the repurchase date relating to any
failure by Bonneville under the Long Term Power Purchase contract with
Nevada Power or under the Business Agreement with Georgia-Pacific and
its ancillary agreements, as described in Exhibit B attached hereto.
3. Such release and indemnification shall not apply to any liabilities
resulting from any negligent or intentional act of TCCCC or for any
liabilities resulting from any decisions made pursuant to the Agreement
while TCCCC was a Partner.
J.. Termination in Event of Delayed Startup. If construction of the cogeneration
Facility has not commenced by October 31, 1991, then each Partner shall have the
option to offer its Partnership Interest, upon written notice to the other
Partner on or before December 31, 1991. The option price shall be based upon the
fair market value as determined by an independent appraiser agreed upon by the
Partners. In the event the Partners cannot agree upon an appraiser, then each
shall nominate one appraiser who shall select a third appraiser. The option
price shall be an average of all three appraisals. If the option price is not
paid within ninety days, the provisions of Article XI shall apply.
ARTICLE VIII.
DEFAULTS AND REMEDIES.
A. Default of a Partner.. If any of the following events occur:
1. The entry of a decree or order by a court having proper jurisdiction
in the premises adjudging a Partner bankrupt or insolvent, or approving as
properly filed a petition seeking reorganization, arrangement, adjustment or
composition or in respect of the Partner under any bankruptcy, insolvency, or
other similar law, state or federal, or appointing a receiver, liquidator,
assignee, trustee, sequestrator (or other similar official) of the Partner or of
any substantial part of its property, or ordering the winding up or liquidation
of its affairs, and the continuance of any such decree or order unstayed and in
effect for a period of ninety (90) consecutive days; or
2. The institution by a Partner of proceedings to be adjudicated as
bankrupt or insolvent, or the consent by it to the institution of bankruptcy or
insolvency proceedings against it, or the filing of a petition or answer or
consent seeking reorganization or relief under any bankruptcy, insolvency, or
other similar law, state or federal, or the consent by it to the filing of such
petition or to the appointment of a receiver, liquidator, assignee, trustee,
sequestrator (or similar official) of the Partner or of any substantial part of
its property, or the making by it of an assignment for the benefit of creditors,
or the admission by it in writing of its inability to pay its debts generally as
they become due, or the taking of corporate action by the Partner in furtherance
of any such action, or
3. Any part of the Ownership Interest of a Partner is seized by a
creditor of such Partner, and the same is not released from seizure or bonded
out within thirty (30) days from the date of notice of seizure, or
4. A Partner fails to advance funds as required by ARTICLE II, Section
B or any other provision of this Agreement, or to perform any other material
obligation imposed upon such Partner under any agreement relating to borrowed
money of the Partnership, or attempts to transfer any of its Ownership Interest
in the Partnership except as otherwise provided in ARTICLE VII of this
Agreement, then such Partner shall be deemed to be in default hereunder and
shall be referred to as the "Defaulting Partner", and the other Partner shall be
referred to as the "Non-Defaulting Partner". The Non-Defaulting Partner shall
have the right to give the Defaulting Partner a "Notice of Default", which shall
be in writing, shall set forth the nature of the obligations which the
Defaulting Partner has not performed, or is in breach of, and shall set forth
the date by which such default must be cured which date shall be ten (10)
business days after receipt of the Notice of Default if payment of money is
required, or thirty (30) business days after receipt of the Notice of Default
for defaults other than payments of money or such shorter period as may be
necessary in the good faith judgment of the Non-Defaulting Partner to prevent a
default under any agreement for borrowed money to which the Partnership is a
party or to avoid jeopardizing its investment in the Partnership. If within the
period specified in the Notice of Default, the Defaulting Partner cures such
default, the Notice of Default shall be inoperative and the Defaulting Partner
shall lose no right hereunder. If, within such specified period, the Defaulting
Partner does not cure such default, the Non- Defaulting Partner at the
expiration of such period shall have the rights hereinafter specified.
B. Buy-Sell Procedure at option of the Non-Defaulting Partner. If a Partner
becomes a Defaulting Partner pursuant to the provisions of ARTICLE VIII, Section
A and the default is not cured within the specified period, then, in such event,
the Non Defaulting Partner shall have the right, at its option, to proceed under
the provisions of this ARTICLE VIII, Section B to either:
1. Expel the Defaulting Partner from the Partnership by giving written
notice specifying the expulsion date and purchase, as of the expulsion date, all
of the Defaulting Partner's Ownership Interest in the Partnership at a price,
which for such purpose, shall be equal in amount to the fair market value as
determined by an independent appraiser, less, any costs of remedying the default
and any damages or costs to the Partnership or the Non-Defaulting Partner
resulting from the default. Payment to the Defaulting Partner may take the form
of a ten (10) year note with interest at the floating prime rate established by
the Bank of America, N.T. & S.A., San Francisco, California, in effect from time
to time.
2. Cure the def ault and the cost of such curing shall be charged
against the Defaulting Partner's Capital Account and credited to the
Non-Defaulting Partner' s Capital Account. The Ownership Interests, as defined
in Article II, paragraph C shall be adjusted to reflect these charges and
credits to the Partner's Capital Accounts, provided, however, that the
Defaulting Partner's liability for any obligations to or of the Partnership,
other than those involved in the curing of the default, in respect of a period
prior to the effective date of the curing of the default, shall not be affected;
or
3. Cure the default, assume day-to-day operations of the Cogeneration
Facility and cause the cost of the cure to be charged against a special account
established for the Defaulting Partner until the entire cost thereof with
interest at the floating prime rate established by the Bank of America, N.T. &
S.A., San Francisco, California, in effect at the time of such default on the
unpaid balance shall have been paid or reimbursed to the Non-Defaulting Partner.
The Non-Defaulting Partner may elect to be repaid the cost of curing the default
from any subsequent distributions made pursuant to this Agreement to which the
Defaulting Partner would otherwise have been entitled, which amount shall be
paid first as interest and then principal, until the cost is paid in full. Until
payment or reimbursement has been completed, the Defaulting Partner's right to
cast its vote on the Management Committee and to withdraw funds from any account
of the Partnership from which the Defaulting Partner could withdraw funds will
be suspended.
If the Non-Defaulting Partner elects to follow the procedure set forth in
paragraph 1. above, it may, after giving notice of expulsion but prior to the
expiration date of the Partnership, substitute another person or entity not
affiliated with the Non Defaulting Partner as a Partner in the Partnership as
successor to the Defaulting Partner in such manner as to preserve the
continuation of the Partnership and its status as the owner of a qualifying
cogeneration facility under PURPA. If the Non-Defaulting Partner elects to
follow the procedure set forth in paragraph 2 above, and if the resulting
adjustment of Ownership Interests of the Partners would cause the loss of the
Partnership or its Partners of one or more exemptions available under PURPA, the
Non-Defaulting Partner may, after notice to the Defaulting Partner of its
intention to do so, cause the addition of another Partner, not affiliated with
the Non-Defaulting Partner, with an ownership Interest equal to the amount by
which the adjusted ownership Interest in the Non-Defaulting Partner's Capital
Account exceeds a fifty percent (50%) Ownership Interest. In such case, this
Agreement shall be deemed amended without further action of any Partner to
become a Partnership consisting of three Partners, each entitled to
representation on the Management Committee and each entitled to vote in
proportion to its ownership Interest, and with such other amendments as are
necessary to accommodate three (3) partners until otherwise provided in this
Agreement.
In addition to the foregoing, the Non-Defaulting Partner may, at its option, at
any time within one (1) year following the uncured default, cause the
Partnership to terminate any contracts existing between the Partnership and the
Defaulting Partner or its Parent or any of its affiliated entities on not less
than ninety (90) days written notice.
The right of the Non-Defaulting Partner to proceed under this ARTICLE VIII,
Section B shall be in addition to all other rights and remedies of the
Non-Defaulting Partner, either at law or in equity..
ARTICLE IX.
RESOLUTION OF DISPUTES - ARBITRATION.
A. Subjects of Arbitration. In the event of disagreement between the Partners
with respect to:
1. Any question of fact involved in the application of this Agreement or of
any action of the Management Committee, or
2. The interpretation of any provision of this Agreement or any action of
the Management Committee,the matter involved in the disagreement shall, upon
demand of either Partner, be submitted to arbitration in the manner hereinafter
provided. Submission to arbitration, as hereinafter provided, shall be a
condition precedent to any right to institute proceedings at law or in equity
concerning such matter, except for injunctive relief or other provisional relief
pending the arbitration of a matter subject to arbitration pursuant to this
Agreement.
B. Agreement to Arbitrate. The Partners will make every reasonable effort to
Resolve disputes, claims and controversies through decisions of the Management
Committee prior to any such dispute, claim or controversy reaching a state that
requires implementation of this ARTICLE IX for resolution. However, should any
controversy arise between the Partners as to which the Partners are unable to
effect a satisfactory resolution and which, under the terms and provisions of
this Agreement may be submitted to arbitration, such controversy shall be
submitted to arbitration in accordance with the terms and provisions of this
ARTICLE IX, and in accordance with the rules of the American Arbitration
Association (or any successor organization).
C. Submission to Arbitration and selection of Arbitrators. A Partner desiring to
submit to arbitration any such controversy shall furnish its demand for
arbitration in writing to the other Partner, which demand shall contain a brief
statement of the matter in controversy, as well as a list containing the names
of three suggested arbitrators from which list, or from other sources, the
Partners shall choose one mutually acceptable arbitrator. If the Partners are
unable to agree upon the identity of a single arbitrator, within ten (10) days
from the receipt of such notice, they shall each, within a period of five (5)
additional days, name one arbitrator by written notice to the other Partner.
Within ten (10) days after such last mentioned notice, the two arbitrators shall
choose a third arbitrator. If any Partner fails to name an arbitrator within the
ten (10) day period, then either Partner, on behalf of and on notice to the
other Partner, may request appointment by the American Arbitration Association
(or any successor organization) in accordance with its rules then prevailing of
the required additional arbitrators so that there shall be a panel of three
arbitrators. If the American Arbitration Association (or successor organization)
should fail to appoint the necessary arbitrators within fifteen (15) days after
such request is made, then either Partner may apply, on notice to the other
party, to a court of competent jurisdiction for the appointment of such
necessary additional arbitrators. Each of the arbitrators chosen or appointed
pursuant to this Article shall be a person having at least ten (10) years
experience in the United States in a profession related to the subject matter
involved in the dispute and shall not be a past or present officer, director or
employee of either of the parties or any parent or affiliate corporation.
D. Arbitration Procedure. Each Partner shall furnish the arbitrator and any
other Partner with a written statement of matters it deems to be in controversy
for purposes of the arbitration procedures. Such statement shall also include
all arguments, contentions and authorities which it contends substantiate its
position. Any hearings concerning such controversy shall be conducted in Las
Vegas, Nevada, and in accordance with the rules of the American Arbitration
Association. If only one arbitrator is appointed pursuant to ARTICLE IX hereof,
such arbitrator shall render his decision and award as soon as possible but no
later than thirty (30) days after conclusion of hearings before such arbitrator.
If, however, three arbitrators are appointed, they shall render their decision
and award, upon the concurrence of at least two of their number, as soon as
possible but no later than 30 days after conclusion of hearings before such
arbitrators. The decision and award shall in either case be in writing and
counterpart copies hereof shall be delivered to each of the Partners. Such
decision shall be based solely upon the written arguments and contentions
coupled in appropriate cases with evidence and/or legal authorities submitted by
each. Except with the consent of each Partner, the arbitrator shall not retain
or consult any experts in arriving at the decision. In rendering such decision
and award, the arbitrators shall not add to, subtract from or otherwise modify
the provisions of this Agreement. Each Partner agrees that judicial judgment may
be had on the decision and award of the arbitrators so rendered and may be
enforced in accordance with the laws of the State of California.
E. Successor Arbitrators. If any arbitrator appointed by a Partner dies, refuses
to act, or becomes incapable of acting, then such Partner shall appoint a
successor arbitrator within five days of the
notice of disability. If such Partner fails to appoint the required successor
within such time, the other Partner, on notice to such party, may apply to the
court for the appointment of such necessary arbitrator.
F. Cost of Arbitration. Each Partner shall bear the expense of the arbitrator
appointed by or for such Partner, its own counsel, experts and presentation of
proof. The Partners shall share equally the expense of the additional
arbitrators (or the expense of the single arbitrator if only one arbitrator is
appointed) , and all other expenses of the arbitration.
ARTICLE X.
CONTRIBUTIONS TO PARTNERSHIP AND LIABILITIES OF PARTNERS.
A. Contributions. If either Partner pays any portion of a Partnership liability
or obligation in excess of the amount thereof attributable to its Ownership
Interest, that Partner shall be entitled to contributions from the other Partner
for such excess. This right of contribution is in addition to any other right
which night be provided by law or under this Agreement.
B. Indemnification. Each Partner agrees to, and does hereby indemnify and save
and hold harmless the other Partner, and to the extent set forth below each
affiliate and Parent of the other Partner, from and against all claims, causes
of action, liabilities, payments, obligations, expenses (including without
limitation reasonable fees and disbursements of counsel) or losses (each a
"claim, liability, or loss") arising out of a Partnership liability or
obligation to the extent necessary to accomplish the result that neither Partner
(together with its Affiliates and its Parent) shall bear any portion of
liability or obligation of the Partnership in excess of the percentage thereof
equal to such Partner's ownership Interest in the Partnership at the time the
basis for the claim, liability or loss occurred.
1. Without limiting the generality of the foregoing, a claim, liability or loss
shall be deemed to arise out of a Partnership liability or obligation if it
arises out of, or is based upon, the conduct of the business of the Partnership
or the ownership or operation of the Cogeneration Facility or any property of
the Partnership (the cogeneration Facility or other property of the Partnership
hereinafter referred to as "Partnership Property") . The foregoing
indemnification shall be available to an affiliate and the parent with respect
to a claim, liability, or loss arising out of a Partnership liability or
obligation which is paid by or incurred by such affiliate or parent as a result
of such affiliate or parent directly or indirectly owning or controlling a
Partner, or as a result of the fact that an individual employed or engaged by
the Partnership or a contractor is also a director, officer or employee of such
affiliate or parent.
2. The foregoing shall not inure to the benefit of any Partner (or affiliate or
parent of any Partner) in respect of any claim, liability, or loss which:
a. arises out of,, or is based upon, the gross negligence or willful
misconduct of such Partner or an affiliate or the parent of such Partner, or
b. Is a tax, levy or governmental charge not imposed upon the Partnership
or upon Partnership property.
The foregoing indemnity shall apply only to a claim, liability, or loss to
the extent that it is uninsured by the Partnership.
ARTICLE XI.
DISSOLUTION AND WINDING UP
A. Dissolution. The Partnership shall dissolve upon the first to occur of
any of the following events:
1. The expiration of the term of the Partnership;
2. The sale of all or substantially all of the
property of the Partnership; or the unanimous
election of the Partners to dissolve the
Partnership.
B. Winding Up. Upon a dissolution of the Partnership the Partners shall take
full account of the Partnership's liabilities and property of the Partnership.
The property of the Partnership shall be liquidated as promptly as is consistent
with obtaining the fair value thereof, and the profits and losses therefrom
shall be allocated among the Partners as provided in Article II. The proceeds
therefrom, to the extent sufficient therefor, shall be applied and distributed
in the following order:
1. To the payment and discharge of all of the Partnership's debts and
liabilities, including the establishment of any necessary reserves; and
2. Repay capital account balances; and
3. Distribute the balance in accordance with the Partner's ownership interest;
and
4. Take all actions as required by Code Section 704(b) and all regulations
promulgated thereunder.
C.. Compliance with Timing Requirements of Regulations. In the event the
Partnership is "liquidated" within the meaning of Code Regulations Section
1.704-1(b)(2)(ii)(g) , then (a) distributions shall be made pursuant to this
Article (if such liquidation constitutes a dissolution of the Partnership) or
hereof (if it does not) to the Partners who have positive Capital Accounts in
compliance with Regulations Section 1.704-1(b)(2)(ii)(b)(2) if any Partner's
Capital Account has a deficit balance (after giving effect to all contributions,
distributions and allocations for all taxable years, including the year during
which such liquidation occurs) , such Partner shall contribute to the capital of
the Partnership the amount necessary to restore such deficit balance to zero in
compliance with Code Regulations Section 1.704I(b) (2) (ii) (b) (3). In the
event of imminent dissolution and at the discretion of the Management Committee,
a pro rata portion of the distributions that would otherwise be made to the
Partners pursuant to the preceding sentence may be:
1. Distributed to a trust established for the benefit of the Partners for the
purposes of liquidating Partnership assets, collecting amounts owed to the
Partnership, and paying any contingent or unforeseen Liabilities or obligations
of the Partnership or of the Partners arising out of or in connection "the
Partnership. The assets of any such trust shall be distributed to the partners
from time to time, in the reasonable discretion of the Management Committee, in
the same proportions as the amount distributed to such trust by the Partnership
would otherwise have been distributed to the Partners pursuant to this
Agreement; or
2. Withheld to provide a reasonable reserve for Partnership liabilities
(contingent or otherwise) and to reflect the unrealized portion of any
installment obligations owed to the Partnership, provided that such withheld
amounts shall be distributed to the Partners as soon as practical.
D. Riqhts of Partners. Except as otherwise provided in this Agreement, each
Partner shall look solely to the assets of the Partnership for the return of the
Partner's capital contributions and shall have no right or power to demand or
receive property other than cash from the Partnership. No Partner shall have
priority over any other Partner as to the return of such Partner's capital
contributions, distributions or allocations unless otherwise provided in this
Agreement.
E. Waiver of Partition. No Partner shall, either directly or indirectly, take
any action to require partition or appraisal of the Partnership or of any of its
assets or properties or cause the sale of the Project and notwithstanding any
provisions of applicable law to the contrary, each Partner (and its legal
representatives, successors or assigns) hereby irrevocably waives any and all
right to maintain any action for partition or to compel any sale with respect to
its Partnership interest, or with respect to any assets or properties of the
Partnership, except as expressly provided in this Agreement.
ARTICLE XII.
GENERAL PROVISIONS.
A. Integration. This Agreement is the entire agreement by and between the
parties hereto with respect to the subject matter hereof. Any prior,
contemporaneous, or ancillary agreements, promises, negotiations, or
representations not expressly set forth herein shall have no force and effect.
No alteration, modification, amendment, or interpretation hereof shall be
binding unless reduced to writing and signed by the Partners.
B. Interpretation. The laws of the state of California shall govern the
interpretation and effect of this Agreement.
D. Negotiation and Enforcement of Contracts with Partners. Notwithstanding
anything to the contrary in this Agreement, with respect to the negotiation or
approval of any contract or enforcement or protection of rights, including
property rights and interests arising under any contract or lease between the
Partnership and a Partner or the parent or affiliate of any Partner, the
Partnership will act through a Partner who is not and whose parent or affiliate
is not or will not be a party to the contract.
E. Force Majeure. The respective obligations of each Partner hereto, other than
the obligation to pay money, shall be suspended while it is prevented from
complying therewith, in whole or in part, by weather conditions, labor accidents
or incidents, rules and regulations of any federal, state, or other governmental
agency, delays in transportation, inability to obtain necessary materials in the
open market, or other cause of the same or other character beyond the reasonable
control of such Partner. Any Partner asserting a force majeure condition shall
immediately notify the other Partner in writing of the occurrence of such
condition, and the estimated duration thereof. In addition, the Partner affected
by the force majeure shall immediately notify the other Partner upon cessation
thereof. Each Partner shall cooperate so as to remedy the force majeure
condition as expeditiously as reasonably possible.
F. Successors and Assigns. This Agreement shall inure to the benefit of and be
binding upon the parties hereto and their respective successors and assigns,
except to the extent of any contrary provision of this Agreement.
G. Severability. If any provision of this Agreement or the application thereof
to any party or circumstances shall be invalid, void, or otherwise unenforceable
to any extent, the remainder of this Agreement and the application thereof to
other parties or circumstances shall not be affected thereby and shall in no way
be impaired or invalidated.
H. Amendments and Waivers. This Agreement and all exhibits and schedules hereto
may be modified only by a written instrument duly executed by the Partners. No
breach of any agreement, warranty or representation or violation of any other
term of this Agreement shall be deemed waived unless expressly waived in writing
by the party who might assert such breach or violation. No waiver of any right
hereunder shall operate as a waiver of any other right or of the same or a
similar right on another occasion.
I. Remedies. No remedy conferred by any of the specific provisions of this
Agreement is intended to be exclusive of any other remedy. Each and every remedy
shall be cumulative and shall be in addition to every other remedy given
hereunder now or hereafter existing at law or in equity or by statute or
otherwise, and the election by a party of one or more remedies shall not
constitute a waiver of the party's right to pursue any other available remedies.
J. Binding Nature of This Agreement. This Agreement shall be binding upon and
inure to the benefit of the parties hereto and their respective legal
representatives, successors and assigns. construction. Every covenant, term and
provision of this Agreement shall be construed simply according to its fair
meaning and not strictly for or against any Partner.
K. Time. Time is of the essence with respect to this Agreement.
L. Headings.. Section and other headings contained in this Agreement are for
reference purposes only and are not intended to describe, interpret, define or
limit the scope, extent or intent of this Agreement or any provision hereof.
M. Incorporation by Reference Every exhibit, schedule and other appendix
attached to this Agreement and referred to herein is hereby incorporated in this
Agreement by reference.
N. Additional Documents. Each Partner agrees to perform all further acts
and execute, acknowledge and deliver any documents which may be reasonably
necessary, appropriate or desirable to carry out the provisions of this
Agreement.
O. Variation of Pronouns. All pronouns and any variations thereof shall be
deemed to refer to masculine, feminine or neuter, singular or plural, as the
identity of the person(s) -may require.
P. Counterpart Execution. This Agreement may be executed in any number of
counterparts with the same effect as if all of the Partners had signed the same
document. All counterparts shall be construed together and shall constitute one
agreement.
Q. Notices. All notices, requests and other communications required or permitted
to be given to, or made upon, any party hereto shall be in writing and shall be
personally delivered or sent by certified mail, postage prepaid, or shall be
delivered by nationally recognized overnight courier or shall be sent by
telecopy::
(i) if to Bonneville, to:
Bonneville Nevada Corporation
257 East 200 South, Suite 800
Salt Lake City, Utah 84111
Attention: President
Telecopy No.: (801) 363-9557
(ii) if to TCCCC, to:
Texaco Clark County Cogeneration Company
10 Universal City Plaza , Suite 700
Universal City, California 91608
Attention: Vice President
Telecopy No.: (818) 505-3190
Any notice, request or other communication so addressed or so addressed to such
other address as shall be designated by such party in a written notice to the
other party complying as to delivery with the terms of this Section, when (i)
hand delivered, shall be deemed to be given the same day such notice, request or
other communication is hand delivered, (ii) delivered by nationally recognized
overnight courier, shall be deemed to be given the same day such notice, request
or other communication is so delivered, (iii) mailed, shall be deemed to be
given two business days after such notice, request or other communication is
mailed, or (iv) telecopied, shall be deemed to be given on the same day such
telecopy is received.
R. Maintaining "Qualified Facility" Status. Bonneville acknowledges that it
possesses certain information and knowledge concerning the qualification of
facilities that meet PURPA requirements. In the event of failure of the current
qualifying facility status, Bonneville shall use reasonable efforts to apply
this knowledge to maintain qualified facility status under PURPA in the event of
failure of the current project qualification, to advise and make recommendation
to the Management Committee concerning the following: locating a new thermal
host, exploring with current thermal host reduction in modification of thermal
requirements, or developing a plan for the Partnership to use the Cogeneration
Facility's heat energy. In accordance with Article III, paragraphs D(3) and F,
by unanimous vote, the Management Committee shall take whatever actions it deems
appropriate under the circumstances. Any capital requirements for such
obligations shall be an obligation of the Partnerships.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed
and their respective corporate seals to be affixed and attested hereto, all as
of the day and year first written above.
TEXACO CLARK COUNTY COGENERATION COMPANY
By: James C. Houck
Its: Vice President
BONNEVILLE NEVADA CORPORATION
By: Robert A Keegan
Its: President
STATE OF UTAH )
SS.
COUNTY OF SALT LAKE )
On this 5th day of November, 1990, personally appeared before me,
Tricia F. Pannier, a Notary Public in and for said County and State, James C.
Houck, the Vice President of Texaco Clark County Cogeneration Company, a
Delaware corporation, who acknowledged to me that he executed the within and
foregoing instrument by authority of the Bylaws of said corporation or a
resolution duly adopted by the Board of Directors of said corporation, and said
James C. Houck duly acknowledged to me that said corporation executed the same.
IN WITNESS WHEREOF, I have set my hand and official seal as of the date
first above written.
-----------------------------------------------
NOTARY PUBLIC
My Commission Expires: Residing at: Salt Lake City
May 25, 1993
STATE OF UTAH )
: ss.
COUNTY OF SALT LAKE )
On this 5th day of November, 1990, personally appeared before me,
Tricia F. Pannier, a Notary Public in and for said County and State, Robert A.
Keegan, the President of Bonneville Nevada Corporation, a Nevada corporation,
who acknowledged to me that he executed the within and foregoing instrument by
authority of the Bylaws of said corporation or a resolution duly adopted by the
Board of Directors of said corporation, and said Robert A. Keegan duly
acknowledged to me that said corporation executed the same.
IN WITNESS WHEREOF, I have set my hand and official seal as of the date
first above Written.
-----------------------------------------------
NOTARY PUBLIC
My Commission Expires: Residing at: Salt Lake City
May 25, 1993
<PAGE>
EXHIBIT "A"
NEVADA COGENERATION ASSOCIATES #1 PARTNERSHIP
PARTNERS CONTRIBUTIONS AND PARTNERSHIP INTEREST
PARTNER CONTRIBUTION OWNERSHIP INTEREST
BONNEVILLE $1,000 50-%
TCCCC $1,000 50 %
Capital originally contributed by Bonneville General corporation, predecessor in
interest to TCCCC.
<PAGE>
EXHIBIT "B"
NEVADA COGENERATION ASSOCIATES #1
AGREEMENTS, PERMITS AND OBLIGATIONS
I. INTRODUCTION. The following is a list of the agreements, permits, and
obligations that will be assigned by Bonneville Nevada Corporation to the
Nevada Cogeneration Associates #1 Partnership.
1. Amended and Restated Business Agreement dated September 12, 1989 between
Georgia-Pacific Corporation and Bonneville Nevada Corporation, as amended,
but excluding from such assignment rights to bid contemplated in paragraph
12, page 10.
2. Heat Purchase Agreement dated September 12, 1989 between Georgia-Pacific
Corporation and Bonneville Nevada Corporation, as amended.
3. Memorandum of Understanding Regarding Real Estate Interests dated September
12, 1989 between Georgia-Pacific corporation and Bonneville Nevada
Corporation.
4. Bonneville Nevada Contract A with Nevada Power Company for Long Term Power
Purchases from Qualifying Facilities dated May 2, 1989 between Bonneville
Nevada Corporation and Nevada Power Company.
5 BLM Right-of-Way.
6. Approach Permit.
7. Utility Environmental Protection Act Permit.
8. Water Permit Application No. 54129.
9. Conditional Use Permit.
10. Artificial Pond Permit.
11. Evaporation Pond Permit.
12. Union Pacific Encroachment Permit.
13. Authority to construct No. A360.
14. Firm Transportation service Agreement dated February 8, 1990 between Kern
River Gas Transmission Company and Bonneville Nevada Corporation, as
amended February 8, 1990. 2
15. Precedent Agreement dated February 8, 1990 between Kern River Gas
Transmission Company and Bonneville Nevada Corporation, as amended February
8, 1990. 2
16. Financial assets and liabilities, including but not limited to the
following project costs: obligations for wells, electrical interconnect
payments, major equipment deposits, survey and title expenditures, thermal
host interconnect fees and all other items that are considered direct
capital costs of the Project.
17. Stewart & Stevenson Services, Inc.
Commercial Proposal TG90- 2500-6085, Rev. 2.
18. Gas Sales Agreement
between Bonneville Nevada Corporation and Celsius Energy Company. 1
19. Consulting Agreement dated April 23, 1990 between Roland D. Westergard and
Bonneville Nevada Corporation. '
20. Purchase Orders for Dames and Moore for Consulting services.
21. Army Corps of Engineers Permit.
22. FERC Certificate of Qualifying Facility Status Docket No. 90210-000.
23. Fee and Services Agreement dated September 19, 1990 between Bonneville
Nevada Corporation and Smith Capital Markets.
I These rights are applicable to both the Project and a cogeneration project
at the Georgia-Pacific gypsum facility in Clark County (the
"Georgia-Pacific Project") . The assignment of such rights will allocate
the rights between the Project and the Georgia-Pacific Project.
2 These rights are applicable to the Project, the Georgia Pacific project,
and other projects owned by Bonneville Pacific Corporation subsidiaries.
The assignment of such rights will allocate the rights between the Project,
the Georgia-Pacific Project, and other applicable Bonneville Pacific
corporation projects.
<PAGE>
FIRST AMENDMENT TO AMENDED AND RESTATED
GENERAL PARTNERSHIP AGREEMENT FOR
NEVADA COGENERATION ASSOCIATES #1
THE GEORGIA-PACIFIC PROJECT
BY AND BETWEEN
BONNEVILLE NEVADA CORPORATION
AND
TEXACO CLARK COUNTY COGENERATION COMPANY
This First Amendment to Amended and Restated General Partnership Agreement
for Nevada Cogeneration Associates #1 is entered into this 8th day of November,
i990 by and between Bonneville Nevada Corporation, a Nevada corporation
(IIBNCII) and Texaco Clark County Cogeneration Company, a Delaware corporation
("TCCCC).
BNC and TCCCC are sometimes referred to herein collectively as "Parties",
and individually as a "Party". All capitalized terms used herein shall have the
meanings assigned to them in the Partnership Agreement (as defined hereinbelow).
RECITALS
A. The Parties have entered into that certain Amended and Restated General
Partnership Agreement for Nevada Cogeneration Associates #1 the Georgia-Pacific
Project as of November 1, 1990 (the "Partnership Agreement").
B. The Parties wish to amend a certain portion of the Partnership
Agreement.
AGREEMENT
1. The Partnership Agreement is hereby amended and restated to provide that
the business of the Partnership shall be conducted under the name of Nevada
Cogeneration Associates I.
2. Except as expressly amended hereby, the Partnership Agreement remains in
full force and effect and is not changed or amended hereby.
In witness whereof, the parties hereto have caused this Agreement to be
executed as of the day and year first written above.
TEXACO CLARK COUNTY COGENERATION COMPANY
By:
Its:
BONNEVILLE NEVADA CORPORATION
By:
Its:
b:amendment
<PAGE>
STATE OF UTAH
COUNTY OF SALT LAKE )
On this 8th day of November, 1990, before me, Mark E. Rinehart, notary
public, personally appeared James C. Houck, known or identified to me to be the
Vice President of Texaco Clark County Cogeneration Company and the person who
executed the foregoing instrument on behalf of Texaco Clark County Cogeneration
Company.
IN WITNESS WHEREOF, I have hereunto set my hand and my official seal the
day and year in this certificate
-------------------------------------------
NOTARY PUBLIC
Residing at:
My Commission Expires:
STATE OF UTAH
:Ss.
COUNTY OF SALT LAKE )
On this 8th day of November, 1990, before me, Mark E. Rinehart, notary
public, personally appeared Robert A. Keegan, known or identified to me to be
the President of Bonneville Nevada Corporation and the person who executed the
foregoing instrument on behalf of Bonneville Nevada Corporation.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official
seal the day and year in this certificate first above written.
---------------------------------
NOTARY PUBLIC
Residing at:
My Commission Expires:
<PAGE>
SECOND AMENDMENT TO AMENDED AND RESTATED
GENERAL PARTNERSHIP AGREEMENT FOR
NEVADA COGENERATION ASSOCIATES I
THE GEORGIA-PACIFIC PROJECT
BY AND BETWEEN
BONNEVILLE NEVADA CORPORATION
AND
TEXACO CLARK COUNTY COGENERATION COMPANY
This Second Amendment to Amended and Restated General Partnership
Agreement for Nevada Cogeneration Associates I is entered into as of the lst day
of December, 1990 by and between Bonneville Nevada Corporation, a Nevada
corporation ("BNC") and Texaco Clark County Cogeneration Company, a Delaware
corporation ("TCCCC").
BNC and TCCCC are sometimes referred to herein collectively as
"Parties", and individually as a "Party".
All capitalized terms used herein shall have the meanings assigned to
them in the Partnership Agreement (as defined hereinbelow).
RECITALS
A. The Parties have entered into that certain Amended and Restated General
Partnership Agreement for Nevada Cogeneration Associates #1 the
Georgia-Pacific Project as of November 1, 1990, as amended November 8,
1990 (the "Partnership Agreement").
B. The Parties wish to amend a certain portion of the Partnership Agreement.
AGREEMENT
1. The Partnership Agreement is hereby amended and restated to provide that
the business of the Partnership shall be conducted under the name of Nevada
Cogeneration Associates #1, but the Partnership may also be known as Nevada
Cogeneration Associates I. 2.
Except as expressly amended hereby, the Partnership Agreement
in full force and effect and is not changed or amended hereby.
In witness whereof, the parties hereto have caused this
Agreement to be executed as of the day and year first written above.
TEXACO CLARK COUNTY COGENERATION COMPANY
By:
Its:
BONNEVILLE NEVADA CORPORATION
By:_
It s
State of __________
County of _________
On this _______day of _________19____, before me,__________, a
notary public, personally appeared _________________, known or identified to me
to be the ________________of Bonneville Nevada Corporation ("Corporation") that
executed the above instrument or the person who executed the instrument on
behalf of the Corporation and acknowledged to me that said Corporation executed
the same.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my
official seal the day and year in this certificate first above written.
____________________________
Notary Public
Residing at:_________________
My Commission Expires:_____________
<PAGE>
State of __________
County of _________
On this _______day of _________19____, before me,__________, a notary public,
personally appeared _________________, known or identified to me to be the
________________of Bonneville Nevada Corporation ("Corporation") that executed
the above instrument or the person who executed the instrument on behalf of the
Corporation and acknowledged to me that said Corporation executed the same.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my
official seal the day and year in this certificate first above written.
Notary Public
Residing at:_________________
My Commission Expires:_____________
BONNEVILLE NEVADA CONTRACT A
with
NEVADA POWER COMPANY
FOR
LONG TERM POWER PURCHASES
FROM
QUALIFYING FACILITIES
May 2, 1989
<PAGE>
TABLE OF CONTENTS
SECTION DESCRIPTION
1 Project Summary
2 Definitions
3 Contract Termination
4 Seller's Facilities
5 Nevada's Facilities
6 Interconnection Facilities Agreement
7 Operations Coordination Agreement
8 Improvements Agreements
9 Capacity and Energy Metering
10 Capacity Provisions
11 Escrow Provisions
12 Billing Provisions
13 Capacity and Energy Payment Provisions
14 Taxes
15 Liability
16 Insurance
17 Uncontrollable Forces
18 Non-dedication of Facilities
19 Amendments
20 Previous Communications
21 Non-Waiver
22 Disputes
23 Remedies
24 Assignment and Delegation
25 Governing Law
26 Nature of Obligations
27 Commission Approval
28 Signatures
<PAGE>
NEVADA POWER COMPANY
STANDARD CONTRACT
LONG TERM POWER PURCHASE
1. PROJECT SUMMARY
This Contract Is entered Into between NEVADA POWER COMPANY ("Nevada") and
Bonneville Nevada Corporation ("Seller"). Seller shall own, operate, and
maintain a Qualifying Facility and shall sell electric capacity and energy to
Nevada and Nevada shall purchase that electric capacity and energy pursuant to
the terms and conditions set forth herein.
1.1 Notices to Seller:
1.1.1 Written notices and correspondence shall be sent to Seller at the
following address:
Bonneville Nevada Corporation
257 East 200 South, Suite 800
Salt Lake City, Utah 84111
Attn: Vice President, Engineering and Construction
With a copy to:
1.1.2 Oral notices shall be conveyed to Seller via telephone. The number
shall be: (801) 363-2520.
1.1.3 Notices to Seller shall be effective upon receipt by Seller.
1.2 Notices to Nevada:
1.2.1 Written notices and correspondence shall be sent to Nevada at the
following address:
Nevada Power Company
Attention: Secretary
P.O. Box 230
Las Vegas, Nevada 89151
with a copy to Nevada's Operating Representative at the same address.
1.2.2 Nevada's Operating Representative shall be Frank K. Loudon; Gary E.
Craythorn shall be Nevada's Alternate Operating Representative.
<PAGE>
1.2.3 Oral notices shall be conveyed to Nevada's Operating Representative
via telephone. The number shall be: (702) 367-5383.
1.2.4. Notices to Nevada shall be effective upon receipt by Nevada.
1.3 Seller's Generating Facility:
1.3.1 Prior to Firm Operation, Seller shall obtain Qualifying Facility
status for Seller's Generating Facility. Seller shall maintain
qualification throughout the Contract Term.
1.3.2 Location: Georgia Pacific Plant
Las Vegas, Nevada
1.3.3 1.3.3 Expected Firm Operation Date: June 1, 1993
1.4 Contract Capacity 85,000 M
-----------------
1.5 Expected Annual Energy Delivery: 680,000,000 kWh.
1.6 Contract Termination Date: Apr 30, 2023.
1.7 Operating Options: A portion of the electric energy output of Seller's
Generating Facility is dedicated to Seller's requirements; excess
output Is dedicated to Nevada.
1.8 Capacity Payment:
1.8.1 Starting with Firm Operation and continuing through the Contract
Term, Seller shall be paid for Capacity at Capacity rates agreed upon
by the Parties and set forth In Exhibit A.
1.8.2 Prior to Firm Operation, Seller shall not be paid for capacity
unless Nevada, because of operating conditions, experienced a capacity
requirement that was mat by Seller's Capacity, in which case Seller
shall be paid for Capacity at Nevada's Tariff Schedule QF-Short Term
Capacity rates effective at the time of delivery.
1.8.3 Seller shall not be paid for Excess Capacity unless Nevada,
because of operating conditions, experienced a capacity requirement
that was met by Seller's Excess Capacity, In which case Seller shall be
paid for Excess Capacity at Nevada's Tariff Schedule QF-Short Term
Capacity rates effective at the time of delivery.
1.8.4 If Seller obtained Qualifying Facility status prior to Firm
Operation and subsequently lost such status for reasons beyond Seller's
reasonable control, Seller shall be paid for Capacity delivered to
Nevada, during the periods that Seller did not have Qualifying Facility
status, at Capacity rates equal to eighty (80) percent of the Capacity
rates otherwise agreed upon by the Parties.
1.9 Energy Payment:
1.9.1 Starting with Firm Operation and continuing through the
Contract Term, Seller shall be paid for Energy at Energy rates
agreed upon by the Parties and set forth In Exhibit A.
1.9.2 Prior to Firm Operation, Seller shall be paid for Energy
at Nevada's Tariff Schedule OF-Short Term Energy rates
effective at the time of delivery.
1.9.3 Seller shall be paid for Excess Energy at Nevada's
Tariff Schedule QF-Short Term Energy rates effective at the
time of delivery.
1.9.4 If Seller obtained Qualifying Facility status prior to
Firm Operation and subsequently lost such status for reasons
beyond Seller's reasonable control, Seller shall be paid for
Energy delivered to Nevada, during the periods that Seller did
not have Qualifying Facility status, at Energy rates equal to
eighty (80) percent of the Energy rates otherwise agreed upon
by the Parties.
2. DEFINITIONS: Common electric utility Industry terms shall have the
meaning ascribed to them In the Edison Electric Institute "Glossary of
Electric Utility Terms" (Pub. No. 04-84-06). When a term Is Initially
capitalized and used In the singular or the plural, It shall have the
following cited definition.
2.1 Applicable Laws: Any law, treaty, rule, regulation, ordinance, order,
code, judgment, decree, Injunction, permit, or decision of any Federal, state,
or local government, authority, agency, court, or other governmental body having
jurisdiction over the matter In question, as In effect from time to time.
2.2 Applicable Permits: Any action, approval, consent. waiver, exemption,
variance, franchise, order, permit, authorization, right, or license required to
be obtained and/or maintained in connection with Seller's Facilities.
2.3 Capacity: The kilowatts produced by Seller's Generating Facility that
shall be purchased by Nevada.
2.4 Commission: The Public Service Commission of Nevada
2.5 Contract: This document and the exhibits referenced herein, If
applicable; as amended from time to time. Exhibits shall be attached hereto and
shall be made a part hereof to the same extent as If set forth herein.
2.6 Contract Capacity: The electric power producing capability of Seller's
Generating Facility that shall be dedicated to Nevada
2.7 Contract Term: The period during which Nevada shall purchase capacity
and energy from Seller. The Contract Term shall end on the Contract Termination
date set forth In Section 1.6.
2.8 Electric System Integrity: The state of operation of an electric system
that maximizes the health, welfare, and safety of personnel and the general
public; minimizes the risk of Injury to personnel and the general public;
minimizes the risk of damage to property; and maximizes the system's ability to
provide electric service to customers In accordance with electric utility
Industry standards.
2.9 Emergency: Any condition that, In Nevada's judgment, adversely affects
Nevada's Electric System Integrity.
2.10 Energy: The kilowatt hours produced by Seller's Generating Facility
that shall be purchased by Nevada.
2.11 Excess Capacity: Capacity that exceeds deliveries at Contract
Capacity.
2.12 Excess Energy: Energy associated with capacity that exceeds deliveries
at Contract Capacity. Excess Energy shall be determined by multiplying Contract
Capacity by the number of hours In the month and subsequently subtracting the
product from actual energy.
2.13 Exhibit A: Payment Provisions.
2.14 Exhibit B: Interconnection Facilities Agreement
2.15 Exhibit C: Operations Coordination Agreement.
2.16 Exhibit D: Improvement Agreement(s), if applicable.
2.17 Exhibit E: Provisions for Establishing Firm Operation.
2.18 Exhibit F: Form of Insured Endorsement.
2.19 Exhibit G: Standby Service Agreement, f applicable.
2.20 Firm Operation: The date, agreed upon by the Parties, on which Seller
compiled with the provisions of Exhibit E.
2.21 Forced Outage: Any outage, other than a Scheduled Outage, that fully
or partially curtails the production or delivery of Seller's energy to Nevada.
2.22 Generating Facility: A plant containing prime movers, electric
generators, and auxiliary equipment required to produce electric energy.
2.23 Interconnection Facilities: The facilities that shall be required to
connect a Generating Facility to an electric system and the Incremental
facilities that shall be required to transmit the output of a Generating
Facility to distribution points on that electric system.
2.24 Interconnection Point: The point, which shall be so designated by
Nevada In Exhibit B, where the transfer of electric energy between Nevada and
Seller will take place.
2.25 Lender: The entity(ies) that have provided financing for Seller's
Facilities.
2.26 Maintenance Months: Those months that have been so designated In
Exhibit A.
2.27 Nevada: Nevada Power Company, Its directors, officers, employees, and
agents with authority to act on Its behalf
2.28 Off-Peak Hours: Those hours that have been so designated in Exhibit A.
2.29 On-Peak Hours: Those hours that have been so designated In Exhibit A.
2.30 Operating Communications: The routine transmittals of information
between the Parties that shall be required to ensure Nevada's Electric System
Integrity. Provisions for Operating Communications have been set forth In
Exhibit C.
2.31 Operating Representative: The Individual(s) that shall be appointed by
each Party to ensure effective communication, coordination, and cooperation
between the Parties. Either Party shall have the right to change that Party's
Operating Representative by providing written notice of the change to the other
Party; such changes shall not be deemed amendments for the purposes of this
Contract.
2.32 Party: Nevada or Seller.
2.33 Qualifying Facility: A Cogeneration or Small Power Production Facility
that masts the criteria defined In Title 18, Code of Federal Regulations,
Section 292.201 through 292.207.
2.34 Scheduled Outage: Any outage, other than a Forced Outage, that has
fully or partially curtailed the production or delivery of Seller's electric
energy to Nevada and that had been noticed In accordance with the provisions of
this Contract.
2.35 Seller: The entity designated in Section 1, its directors, officers,
employees, and agents with authority to act on its behalf.
2.36 Tariff: The rate schedules and service rules that have been
promulgated by Nevada and approved by the Commission; as amended from time to
time. Nevada's Tariff shall be on file with the Commission.
2.37 Uncontrollable Force: Any occurrence beyond the reasonable control of
a Party that has rendered a Party Incapable of performing Its obligations
hereunder. Uncontrollable Forces shall include, but not be limited to floods,
droughts, earthquakes, storms, fires, pestilence, lightning or other natural
catastrophes; epidemics; wars; riots, civil disturbance or other civil
disobedience; strikes or other labor disputes; action or Inaction of
legislative, judicial, regulatory, or other governmental bodies that may render
or may have rendered Illegal action In accordance with the provisions of this
Contract; and failure, threat of failure, or sabotage of facilities that had
been operated and maintained In accordance with the provisions of this Contract.
3. CONTRACT TERMINATION:
3.1 This Contract shall become effective upon execution by the Parties.
3.2 This Contract shall be terminated on the Contract Termination Date
specified In Section 1.6 unless:
3.2.1 Commission approval of this Contract, In accordance with the
provisions of Section 27, has not been received within six (6) months of the
date on which the Commission received the Contract from Nevada for review and
approval, In which case this Contract shall be terminated six (6) months after
the date on which the Commission received the Contract for review and approval;
or
3.2.2 An Interconnection Facilities Agreement has not been executed within
six (6) months of Contract execution; or
3.2.3 An Operations Coordination Agreement has not been executed within six
(6) months of Contract execution; or
3.2.4 Seller has not secured construction financing for Seller's Facilities
before November 1, 1991; or
3.2.5 Seller has not obtained the primary construction permits for Seller's
Facilities before November 1, 1991; or
3.2.6 Seller has not awarded the major equipment contracts for Seller's
Facilities before November 1, 1991; or
3.2.7 Seller has not secured a "thermal host" for Seller's Facilities
before December 31, 1991; or
3.2.8 Seller has not secured a source of fuel and related transportation
services before December 31, 1991; or
3.2.9 Construction of Seller's Facilities has not begun before November 1,
1991; or
3.2.10 Delivery of Seller's major equipment to Seller's construction site
has not been completed before November 1, 1992; or
3.2.11 Seller has not obtained Qualifying Facility status for Seller's
Generating Facility before July 1, 1993; or
3.2.12 Firm Operation has not occurred before July 1, 1993 In which case
this Contract shall be terminated thirty (30) days after Seller's failure to
meet the specified deadline unless such failure has been caused by Nevada, In
which case the affected date(s) shall be adjusted to reflect the delay(s) caused
by Nevada, or unless such failure has been cured by Lender within thirty (30)
days of Seller's failure to meet the specified deadline.
3.3 Documentation required to confirm compliance with the deadlines
specified in Section 3.2 shall be In a form reasonably required by Nevada.
3.4 Termination of this Contract shall not excuse either Party from
obligations, other than Seller's obligation to deliver additional Capacity and
Energy to Nevada, Incurred by either Party prior to termination of this
Contract. This Contract shall remain effective until both Parties have
discharged their obligations In accordance with the provisions of this Contract
and have exercised their rights and remedies In accordance with the provisions
of this Contract. This Contract shall expire after both Parties' obligations
have been discharged and both Parties rights and remedies have been exercised.
4. SELLER'S FACILITIES: Seller's Facilities shall Include Seller's
Generating Facility and Seller's Interconnection Facilities. Seller's
Interconnection Facilities shall be so designated In Exhibit B.
4.1 Ownership: Seller's Facilities shall be leased or owned, designed,
constructed, operated, maintained, and Improved by Seller. All costs associated
with Seller's Facilities, whether Incurred by Nevada or by Seller, shall be
borne by Seller.
4.2 General:
4.2.1 Nevada shall have the right, without liability, to refuse to connect
Seller's Facilities to Nevada's electric system or to Isolate Seller's
Facilities from Nevada's electric system If Seller falls to comply with any of
the provisions of this Contract that adversely affect Nevada's Electric System
Integrity.
Nevada shall also have the right, without liability, to refuse to connect
Seller's Facilities to Nevada's electric system or to Isolate Seller's
Facilities from Nevada's electric system If Nevada's failure to refuse
Interconnection or to Isolate would render Illegal Nevada's actions In
accordance with the provisions of this Contract. Nevada's refusal or Isolation
shall be limited to the period during which Nevada's failure to refuse
Inter-connection or to Isolate would render Illegal Nevada's actions In
accordance with the provisions of this Contract plus a reasonable period of time
for the restoration of Nevada's electric system to a condition that enables
Nevada to resume compliance with the provisions of this Contract.
4.2.2 Seller shall neither solicit nor accept advice from any Nevada
representative except Nevada's Operating Representative. If requested by Seller,
Nevada's Operating Representative shall offer, to the extent possible, advice to
Seller relative to the design, construction, operation, maintenance, and
Improvement of Seller's Facilities. Such advice shall be offered as a courtesy.
Seller shall save harmless and Indemnify Nevada from any loss and liability,
whether direct or Indirect and Including attorney's fees and other costs of
litigation, resulting from Seller's Implementation of Nevada advice.
4.2.3 Seller shall design, construct, operate, maintain, and improve
Seller's Facilities In accordance with prudent engineering, construction,
operation, and maintenance practices. Seller shall comply with all Applicable
Laws even if compliance necessitates Improvements to Seller's Facilities or
Interferes with the operation of Seller's Facilities. In addition, Seller shall
operate Seller's Facilities so as to ensure, to a reasonable extent, the
uninterrupted production and delivery of electric energy to Nevada consistent
with Nevada's requirements. If Seller failed to comply with the provisions of
this section, Seller shall save harmless and Indemnify Nevada from any loss and
liability, whether direct or Indirect and Including attorney's fees and other
costs of litigation, resulting from Seller's failure to comply with these
provisions.
4.2.4 Nevada shall have the right, without liability, to monitor and make
recommendations to Seller regarding any aspect of the construction, operation,
maintenance, and Improvement of Seller's Facilities provided that such
recommendations, If Implemented, would not unreasonably
Interfere with the construction, operation, maintenance, or improvement of
Seller's Facilities and that such recommendations are required, In Nevada's
reasonable judgment, to maintain Nevada's Electric System Integrity or to ensure
compliance with the provisions of this Contract. Nevada's recommendations shall
be made as a courtesy. Seller shall save harmless and indemnify Nevada from any
loss and liability, whether direct or Indirect and Including attorney's fees and
other costs of litigation resulting from Seller's Implementation of Nevada's
recommendations.
4.2.5 Seller shall acquire and maintain al Applicable Permits for Seller's
Facilities.
4.2.6 Seller shall acquire and maintain all easements, rights--of-way, and
land rights required for Seller's Facilities.
4.2.7 Seller shall complete all environmental Impact studies required for
Seller's Facilities.
4.2.8 Seller shall complete al feasibility studies required for Seller's
Facilities.
4.3Design:
4.3.1 Seller shall design Seller's Facilities so that those facilities
should not Impose upon Nevada's system any voltage or current that could
Interfere with Nevada's operations, lower the quality of service to Nevada
customers, or Interfere with the operation of any communication facilities.
Seller shall design Seller's Facilities so that those facilities will be
protected from damage that could otherwise result from disturbances on Nevada's
electric system or the electric systems to which Nevada's electric system Is
connected.
4.3.3 Seller shall design Seller's Facilities so that those Facilities
Incorporate reactive power equipment capable of maintaining a power factor
ranging from 0.90 lagging to 0.90 leading at the Interconnection Point whenever
Contract Capacity Is being delivered to Nevada at that point.
4.3.4 Seller shall design Seller's Facilities so that those facilities
Incorporate provisions for storage and utilization of backup fuel. The capacity
of the storage facilities, which shall be established during subsequent
discussions between the Parties, shall be sufficient to ensure the availability
of Seller's Generating Facility during periods when natural gas delivery can be
reasonably expected to be curtailed.
4.3.5 Seller shall provide those drawings and specifications reasonably
required by Nevada to accomplish Its design review. Nevada shall review and
specify modifications to the design of Seller's Facilities to the extent
necessary to maintain Nevada's Electric System Integrity and to ensure
compliance with the provisions of this Contract. In conjunction with Nevada's
design review, Nevada shall designate the minimum set of protective devices that
shall be required to protect Nevada's electric system whenever any of Seller's
Facilities are connected to Nevada's electric system. Nevada shall not
unreasonably withhold or delay its review of any design related drawing or
specification that has been submitted to Nevada for review and approval.
4.3.6 Seller shall modify Seller's design as required by Nevada to maintain
Nevada's Electric System Integrity or to ensure compliance with the provisions
of this Contract and shall provide revised drawings and specifications that
shall be reasonably required by Nevada to confirm compliance with Nevada's
requirements.
4.4 Construction:
4.4.1 Prior to the start of Seller's construction, Seller shall furnish a
construction schedule for Seller's Facilities to Nevada. Seller shall notify
Nevada, upon receipt of pertinent Information, of any changes In that
construction schedule that may affect or may have affected Firm Operation.
4.4.2 Seller shall construct Seller's Facilities In accordance with
Seller's design as modified to reflect the changes, If any, that had been
reasonably required by Nevada. Seller shall furnish and Install all equipment
that had been reasonably required by Nevada to maintain Nevada's Electric System
Integrity and to ensure compliance with the provisions of this Contract.
4.4.3 Seller shall provide to Nevada, as shall be reasonably required by
Nevada, "as built" drawings and specifications for Seller's Facilities.
4.5 Initial Operation:
4.5.1 Seller shall not connect any of Seller's Facilities to Nevada's
electric system or operate any of Seller's generators In parallel with Nevada's
electric system without the prior written approval of Nevada's Operating
Representative and without having properly calibrated, tested, and fully
operational protective devices, as designated by Nevada, in service. Nevada's
approval shall not be unreasonably withheld or delayed. If Nevada's approval has
been withheld, Nevada shall provide a written explanation, which Includes a list
of required remedial actions, to Seller within fifteen (15) days of the date on
which Nevada's approval was withheld.
4.5.2 Seller shall notify Nevada's Operating Representative at least
fifteen (15) days prior to the Initial energization of any of Seller's
Interconnection Facilities. Nevada shall Inspect and approve Seller's
Interconnection Facilities prior to that Initial energization If Seller's
Facilities can be energized, In Nevada's reasonable judgment, without adversely
affecting Nevada's Electric System Integrity. Nevada's approval shall be In
writing.
4.5.3 Seller shall notify Nevada's Operating Representative at least
fifteen (15) days prior to the Initial testing and calibration of Seller's
protective devices. Nevada shal Inspect and approve Seller's protective devices
after that Initial testing and calibration If Seller has demonstrated, to
Nevada's reasonable satisfaction, the correct calibration and operation of
Seller's protective devices. Nevada's approval shall be In writing.
4.5.4 Seller shall notify Nevada's Operating Representative at least
fifteen (15) days prior to the Initial operation of any of Seller's generators
In parallel with Nevada's electric system. Nevada shall Inspect and approve
Seller's generators prior to the Initial operation of those generators In
parallel with Nevada's electric system If Seller has demonstrated, to Nevada's
reasonable satisfaction, the ability to synchronize Seller's generators with
Nevada's electric system, to connect Seller's generators to Nevada's electric
system, and to operate Seller's generators In parallel with Nevada's electric
system without adversely affecting Nevada's Electric System Integrity. Nevada's
approval shall be in writing.
4.5.5 Prior to Firm Operation, Seller shall demonstrate, to Nevada's
reasonable satisfaction, the ability to produce and deliver Contract Capacity to
Nevada. Seller's demonstration shall be In accordance with the procedures that
have been set forth In Exhibit E. If Seller failed to demonstrate the ability to
produce and deliver Contract Capacity to Nevada, Nevada shall have the right
without liability, to reduce Contract Capacity to the level Seller was able to
produce and deliver.
4.6 Operation and Maintenance:
4.6.1 To the extent set forth In Exhibit C, Seller shall maintain Operating
Communications with Nevada.
4.6.2 Seller shall neither connect any of Seller's Facilities to Nevada's
electric system nor operate a generator in parallel with Nevada's electric
system without the prior approval of Nevada's Operating Representative.
Procedures for obtaining such approval have been set forth In Exhibit C.
4.6.3. Nevada shall have the right to require Seller to reduce the output
of Seller's Generating Facility or to Isolate any of Seller's Facilities from
Nevada's electric system If, In Nevada's reasonable Judgment, such actions are
required to facilitate the maintenance of any of Nevada's facilities or to
maintain Nevada's Electric System Integrity. Nevada shall, within a reasonable
period of time and to the extent possible, endeavor to correct the condition
that necessitated the reduction or Isolation. The duration of such reduction or
Isolation shall be limited to the period of time that the condition existed plus
a reasonable period of time for the restoration of Nevada's electric system to
an operating condition that allows Nevada to resume the discharge of Its
obligations In accordance with the provisions of this Contract.
Nevada shall also have the right to require Seller to reduce the delivery
of electric energy to Nevada during any period In which, due to operational
circumstances other than economic dispatch, purchases from Seller would have
resulted In costs greater than those that Nevada would otherwise have Incurred
If Nevada generated or purchased an equivalent amount of energy as set forth In
18 C.F.R. Section 292.304(f) and as described at 45 Federal Register 12227-12228
(February 29, 1980). Nevada shall provide one (1) hour's oral notice of such
reduction to Seller. The exercise of Nevada's right shall be subject to a
calendar year energy limitation equal to the product of Contract Capacity and
one thousand (1,000) hours. The amount of energy that has been curtailed shall
be established by multiplying the reduction In Seller's deliveries to Nevada,
from Seller's average rate of delivery (kW) to Nevada during the hour
Immediately preceding the curtailment, by the duration of the curtailment In
hours.
If Nevada has required Seller to reduce the output of Seller's Generating
Facility or to Isolate any of Seller's Facilities from Nevada's electric system,
Seller shall neither Increase the output nor reconnect the Isolated facilities
without the prior approval of Nevada's Operating Representative. Provisions for
obtaining such approval have been set forth In Exhibit C.
4.6.4 Seller shall endeavor to avoid the Imposition of any voltage or
current upon Nevada's electric system that Interferes with Nevada's operations;
distorts the electric service provided to Nevada's customers, or interferes with
the operation of any communication facilities. If Seller imposes such a voltage
or current upon Nevada's electric system, Seller shall, immediately upon receipt
of knowledge of such condition, pursue and Implement remedial measures.
4.6.5 Except as otherwise agreed upon by the Parties' Operating
Representatives, Seller shall have all of Seller's protective devices, as
designated by Nevada, in service whenever Seller's Facilities are connected to
Nevada's electric system.
4.6.6 Seller shall provide Seller's reactive power requirements. Seller
shall also provide reactive power reasonably required by Nevada to maintain
Nevada's Electric System Integrity provided that such requirements are
consistent with the capabilities of Seller's Facilities and do not adversely
affect Seller's ability to provide Capacity and Energy to Nevada In accordance
with the provisions of this Contract. Seller shall not deliver excess reactive
power to Nevada without the prior approval of Nevada's Operating Representative.
Provisions for obtaining such approval have been set forth In Exhibit C.
4.6.7 Seller shall maintain operation and maintenance logs for Seller's
Facilities that contain such data as have been set forth In Exhibit C. Nevada
shall have the right to Inspect and/or request a copy of Seller's operation and
maintenance logs. If so requested, Seller shall provide the copy within five (5)
days of Seller's receipt of Nevada's request.
4.6.8 Seller shall notify Nevada's Operating Representative of any
condition that may affect or may have affected Seller's ability to produce and
deliver Contract Capacity to Nevada. Provisions for such notice have been set
forth in Exhibit C.
4.6.9 If Nevada, as a result of Nevada's participation in a power pool or
coordinating council, has been required to routinely demonstrate the capacity of
its generating facilities, Seller shall routinely demonstrate, to Nevada's
reasonable satisfaction, the ability to produce and deliver Contract Capacity to
Nevada. Seller's demonstrations shall be In accordance with the procedures
established by the power pool or coordinating council.
4.6.10 If Nevada, as a result of Nevada's participation in a power pool or
coordinating council, has been required to comply with the operating criteria of
that power pool or coordinating council, Seller shall also comply with those
operating criteria. The criteria, with which Seller shall comply, shall be set
forth in Exhibit C.
4.6.11 Seller shall notify Nevada's Operating Representative in advance of
all Scheduled Outages. Unless the Parties' operating Representatives otherwise
agree, the minimum required advance notice shall be two (2) days if the expected
outage duration Is less than one (1) day, five (5) days If the expected outage
duration is between one (1) day and five (5) days, and fifteen (15) days If the
expected outage duration Is longer than five (5) days. Provisions for Seller's
notices have been set forth In Exhibit C.
Unless operating conditions otherwise dictate, Seller shall schedule all
outage of expected duration less than five (5) days for completion during the
period designated by Nevada's Operating Representative. Unless operating
conditions otherwise dictate, Seller shall schedule all outages of expected
duration greater than five (5) days for completion during the period designated
by Nevada's Operating Representative, which shall be during Maintenance Months.
4.6.12 Seller shall, If requested by Nevada's Operating Representative and
at no additional cost to Nevada, make every reasonable effort to produce
Contract Capacity during an Emergency. If Seller had scheduled an outage
coincident with the Emergency, Seller shall make every reasonable effort to
reschedule that outage. Nevada shall be deemed to have waived the minimum notice
requirements of Section 4.6.11 if Seller has not taken a properly scheduled
outage at Nevada's request and subsequently seeks to reschedule that outage.
4.6.13 Seller shall test and calibrate Seller's protective devices at
Intervals agreed upon by the Parties' Operating Representatives, but not to
exceed four (4) years. Seller shall notify Nevada's Operating Representative at
least thirty (30) days prior to such testing and calibration. Provisions for
Seller's notices shall have been set forth In Exhibit C.
If Nevada, because of an analysis of operating conditions or because of the
addition of facilities to Nevada's electric system or the modification of
facilities on Nevada's electric system, has reason to doubt the effectiveness of
Seller's protective devices, Nevada shall have the right, without liability, to
require Seller to retest and recalibrate those devices and to demonstrate, to
Nevada's reasonable satisfaction and at no additional cost to Nevada, the proper
calibration and operation of those devices. If operating conditions dictate,
Nevada shall also have the right, without liability, to retest and recalibrate
those devices and to bill Seller for associated costs In accordance with the
provisions of Section 5.5 or Exhibit B; whichever Is applicable.
4.6.14 Seller shall maintain a supply of backup fuel, the quantity of which
shall be established during subsequent discussions, sufficient to ensure the
availability of Seller's Generating Facility during periods when natural gas
delivery can be reasonably expected to be curtailed.
4.7 Nevada's Review: Any review of the design, construction, operation,
maintenance, or Improvement of Seller's Facilities by Nevada is solely for
Nevada. Nevada makes no representation as to the economic or technical
feasibility and suitability of any of Seller's Facilities for any purpose.
Seller shall not represent to any third party that Nevada's review constitutes
such a representation.
5. NEVADA'S FACILITIES: Nevada shall, as agreed upon by the Parties and set
forth In Exhibit 8, provide facilities required to affect the provisions of this
Contract. Nevada's Facilities shall be those facilities so designated In Exhibit
B.
5.1 Ownership: Nevada's Facilities shall be owned, designed, constructed,
operated, maintained, and Improved by Nevada. Unless otherwise agreed upon by
the Parties and set forth I Exhibit B, all costs associated with Nevada's
Facilities, whether Incurred by Nevada or by Seller, shall be borne by Seller.
5.2 Construction Deposits:
5.2.1 Unless otherwise agreed upon by the Parties and set forth In Exhibit
B, Seller shall, upon execution of Exhibit B, deposit the estimated cost of
Nevada's Facilities with Nevada. Seller's cost for the design and construction
of that portion of Nevada's Facilities for which Seller has deposited the
estimated cost with Nevada shall be adjusted to Nevada's actual cost after the
facilities have been completed. If Seller's construction deposits exceed
Nevada's actual cost, Nevada shall refund the excess deposits to Seller within
sixty (60) days of the completion of those Facilities. If Nevada's actual cost
exceeded Seller's construction deposits, Nevada shall render a bill to Seller
for the excess cost.
5.2.2 If that portion of Nevada's Facilities for which Seller has deposited
the estimated cost with Nevada shall be used for the sale of electric energy to
Seller and related parties as defined In Internal Revenue Service Advance Notice
88-129 and If the electric energy that shall be sold to Seller and related
parties has been projected to exceed five (5) percent of the electric energy
that shall be sold to Nevada by Seller under the provisions of this Contract,
the estimated cost of such facilities shall be Increased by 30.185 percent to
cover the Income tax liability attributable to such facilities.
5.2.3 If that portion of Nevada's Facilities for which Seller has deposited
the estimated cost with Nevada had been deemed "nontaxable" for the purposes of
Section 5.2.2 and if those facilities subsequently became taxable during the
term of this Contact because electric energy sales to Seller and related parties
exceeded five (5) percent of the electric energy purchased by Nevada under the
provisions of this Contract during any three (3) years of a five (5) year
period, Nevada shall have the right to bill Seller for the Income tax liability
attributable to such facilities because of the sales to Seller and related
parties.
5.3 Construction: Prior to the start of Nevada's construction, Nevada shall
furnish a construction schedule for Nevada's Facilities to Seller. Nevada shall
notify Seller, upon receipt of pertinent Information, of any changes in that
construction schedule that may affect or may have affected Firm Operation.
Seller shall release Nevada from any loss and liability, whether direct or
Indirect and Including attorney's fees and other costs of litigation, resulting
from any delay In the completion of Nevada's Facilities that has been caused by
Seller or by circumstances beyond Nevada's reasonable control.
5.4 Project Abandonment: If this Contract has been terminated prior to Firm
Operation, Seller shall bear all costs associated with Nevada's Facilities that
were incurred by Nevada prior to Contract termination plus all removal and/or
abandonment costs Incurred by Nevada subsequent to contract termination.
Seller's cost for the design, construction, and removal and/or abandonment of
Nevada's Facilities shall be adjusted to Nevada's actual cost not of salvage
value after Nevada's removal and/or abandonment efforts have been completed. If
Seller's construction deposits exceed Nevada's actual cost, Nevada shall refund
the excess deposits to Seller within sixty (60) days of the completion of
Nevada's efforts. If Nevada's actual cost exceeded Seller's construction
deposits, Nevada shall render a bill to Seller for the excess cost.
5.5 Billing Provisions: Unless otherwise agreed upon by the Parties and set
forth In Exhibit 8, Nevada shall render monthly bills to Seller for operation
and maintenance costs, both direct and Indirect, associated with Nevada's
Facilities that were Incurred by Nevada during the billing period. Indirect
costs shall Include but not be limited to labor loadings for administrative and
general, FICA, bodily Injury Insurance, property damage Insurance, group
Insurance, Industrial Insurance, holiday pay, sick leave, vacation pay, pension
plans, supervision, tools, transportation, and unemployment taxes.
5.6 Operation and Maintenance:
5.6.1. Nevada shall operate and maintain Nevada's Facilities in accordance
with Nevada's methods of operation and maintenance.
5.6.2 Nevada shall notify Seller's Operating Representative of any
condition that may affect or may have affected Seller's ability to produce and
deliver Contract Capacity to Nevada.
6. INTERCONNECTION AGREEMENT FACILITIES: The Parties shall execute an
Interconnection Facilities Agreement. Upon execution, that agreement shall be
attached to this Contract as Exhibit B.
7. OPERATIONS COORDINATION AGREEMENT: The Parties shall execute an
Operations Coordination Agreement. Upon execution, that agreement shall
be attached to this Contract as Exhibit C.
8. IMPROVEMENTS AGREEMENTS: Improvements shall Include any modifications
and additions to Seller's Interconnection Facilities or Nevada's
Facilities that are required to maintain Nevada's Electric System
Integrity or to comply with the directive of any governmental body. If
Improvements are required, the Parties shall execute Improvements
Agreements. Upon execution, those agreements shall be attached to this
Contract as Exhibit D.
The execution of Improvements Agreements shall not obligate Nevada to
Increase the rates set forth In Exhibit A or to otherwise compensate
Seller for costs Incurred by Seller as a result of Implementation of
the Improvements Agreements.
9 CAPACITY AND ENERGY METERING:
9.1 Unless otherwise agreed upon by the Parties and set forth In
Exhibit B, meters and metering equipment used to measure Capacity and
Energy shall be provided, owned, operated, and maintained by Nevada as
Nevada's Facilities.
9.2 Meters and metering equipment shall be Installed In locations
designated by Nevada In Exhibit B. If the meters and metering equipment
have been installed at locations other than the Interconnection Point,
Nevada shall have the right to install loss compensation equipment to
reflect the losses that would have been recorded by the meters if the
meters and metering equipment had been Installed at the Interconnection
Point.
9.3 Seller shall not undertake any action that could interfere with the
operation of Nevada's meters and metering equipment. If Seller falls to
comply with the provisions of this section, Nevada shall have the
right, without liability, to isolate Seller's Facilities from Nevada's
Electric System until Nevada's meters and metering equipment have been
reinstalled In a location that Is Inaccessible to Seller.
9.4 Nevada's meters and metering equipment shall be tested and
calibrated upon Installation and thereafter at Intervals not to exceed
two (2) years and In accordance with the provisions of the American
National Standard Institute Code for Electricity Metering (ANSI C12.1,
latest revision). Nevada shall provide fifteen (15) days prior written
notice of meter testing to Seller. Seller shall have the right to
monitor Nevada's meter testing.
Seller shall also have the right to request additional testing and
calibration of Nevada's meters and metering equipment. If so requested
in writing, Nevada shall test and calibrate Nevada's meters and
metering equipment within thirty (30) days of Nevada's receipt of
Seller's request. If the accuracy of Nevada's meters and metering
equipment Is found to be within the limits established In ANSI C12.1,
Seller shall bear the cost of such additional tests. Billing for such
costs shall be In accordance with the provisions of Section 5.5 or
Exhibit 8; whichever Is applicable. If the accuracy of Nevada's meters
and metering equipment Is found to be outside the limits established In
ANSI C12.1, Nevada shall bear the cost of such additional tests.
9.5 If the accuracy of Nevada's meters and metering equipment has been
found to be outside the limits established In ANSI C12.1, Nevada shall
repair and recalibrate or replace Nevada's meters and metering
equipment, and Nevada shall adjust payments to Seller for Capacity and
Energy delivered to Nevada during the period in which the inaccuracy
existed. If the period In which the Inaccuracy existed cannot be
determined, adjustments shall be made for a period equal to one-half of
the elapsed time since the last test and calibration of Nevada's meters
and metering equipment; however, the adjustment period shall not exceed
six (6) months. If adjustments are required, Nevada shall render a
statement describing the adjustments to Seller within thirty (30) days
of the date on which the Inaccuracy was rectified. If applicable,
additional payments to Seller shall accompany Nevada's statement. If
applicable, Nevada's bill for refunds due Nevada shall accompany
Nevada's statement.
9.6 If Nevada's meters fall to register, Nevada shall render payments
to Seller that have been based upon Nevada's estimate of Seller's
Capacity and Energy. Nevada's estimated payments shall have the same
force and effect as actual payments.
10. CAPACITY PROVISIONS: Unless otherwise provided within this section,
Uncontrollable Forces shall not excuse Seller from the performance
requirements of this section.
10.1 Performance Requirements: Unless otherwise instructed by Nevada,
Seller shall make Contract Capacity available to Nevada during the
Contract Term. Seller shall be deemed to have met that obligation
whenever Seller's deliveries meet or exceed deliveries specified
herein.
10.1.1 Summer Season: For the purposes of this section, a
summer season shall Include May, June, July, August, and
September. During a summer season, total Energy produced and
delivered to Nevada during the on-peak hours of that season
must meet or exceed the product of Contract Capacity, the
number of on-peak hours during that season, and 0.90.
10.1.2 Winter Season: For the purposes of this section, a
winter season shall Include the months of December, January,
and February. During a winter season total Energy produced and
delivered to Nevada during the on peak hours of that season
must meet or exceed the product of Contract Capacity, the
number of on-peak hours during that season, and 0.90.
10.1.3 For the purposes of this section, on-peak hours shall
be those hours so designated In Exhibit A for the summer and
winter seasons less any hours associated with the occurance of
the events expressly excluded In Sections 10.2.1 and 10.3.1,
respectively.
10.2 Summer Probation:
10.2.1 If Seller failed; for reasons other than limitations
imposed by Nevada, natural catastrophes, epidemics, wars,
civil disobedience, or failure, threat of failure, sabotage of
facilities that have been maintained In accordance with the
provisions of this Contract to the extent that such failure,
threat of failure, or sabotage renders Seller incapable of
performance in accordance with the provisions of this Contract
for a period of not less than two (2) months and not greater
than twenty-four (24) months; to meet the performance
requirements of this section during any summer season, Seller
shall be placed on summer probation for a period not to exceed
twelve (12) months.
10.2.2 If Seller failed, for reasons other than limitations
imposed by Nevada, to produce and deliver Energy to Nevada
that meets or exceeds the product of Contract Capacity, the
number of on-peak hours in the month, and 0.90 during any
month of a summer season within a summer probationary period,
Nevada shall have the right to extend the summer probationary
period for an additional twelve (12) months or to reduce
Contract Capacity to a level not less than the average
capacity level achieved by Seller during the on-peak hours of
the preceding summer season.
10.2.3 If Seller has met the performance requirements of this
Contract during each month of a summer season within a summer
probationary period, Seller shall be taken off summer
probation. Seller shall also be taken off summer probation if
Seller has demonstrated, to Nevada's reasonable satisfaction,
that the problems, which caused Seller to be placed on summer
probation, had been rectified and that Seller Is able to
produce and deliver Contract Capacity to Nevada in accordance
with the provisions of this Contract.
10.3 Winter Probation:
10.3.1 If Seller failed, for reasons other than limitations
imposed by Nevada, natural catastrophes, epidemics, wars,
civil disobedience, or failure, threat of failure, sabotage of
facilities that have been maintained In accordance with the
provisions of this Contract to the extent that such failure,
threat of failure, or sabotage renders Seller Incapable of
performance In accordance with the provisions of this Contract
for a period of not less than two (2) months and not greater
than twenty-four (24) months; to meet the performance
requirements of this section during any winter season, Seller
shall be placed on winter probation for a period not to exceed
twelve (12) months.
10.3.2 If Seller failed, for reasons other than limitations
Imposed by Nevada, to produce and deliver Energy to Nevada
that meets or exceeds the product of Contract Capacity, the
number of on-peak hours In the month, and 0.90, during any
month of a winter season within a winter probationary period,
Nevada shall have the right to extend the winter probationary
period for an additional twelve (12) months or to reduce
Contract Capacity to a level not less than the average
capacity level achieved by Seller during the on-peak hours of
the preceding winter season.
10.3.3 If Seller has met the performance requirements of this
Contract during each month of a winter season within a winter
probationary period, Seller shall be taken off winter
probation. Seller shall also be taken off winter probation if
Seller has demonstrated, to Nevada's reasonable satisfaction,
that the problem, which caused Seller to be placed on winter
probation, had been rectified and that Seller Is able to
provide Contract Capacity In accordance with the provisions of
this Contract.
10.4 Contract Capacity Reduction: If Contract Capacity has been reduced
for any reason, the provisions of this Contract shall be applicable to
the reduced Contract Capacity.
If Contract Capacity has been reduced for any reason, Seller shall,
upon receipt of Nevada's bill, refund to Nevada, with Interest at the
rate established by the Commission for Nevada's overall rate of return,
all payments to Seller In excess of the amount that would have been
paid If advance notice of Contract Capacity reduction had been provided
In accordance with the following table.
Contract Capacity Advance
Reduction Notice
0 to 1,000 kW 1 Year
1,001 to 70,000 kW 3 Years
over 70,000 kW 5 Years
10.6 Contract Capacity Increase: If Contract Capacity has been
increased for any reason, the provisions of this Contract shall be
applicable to the Increased Contract Capacity.
11. ESCROW PROVISIONS: Upon execution of this Contract, Seller shall
deposit with Nevada an amount equal to fifty cents ($0.50) per kilowatt
of Contract Capacity. Within thirty (30) days of Commission approval of
this Contract, Seller shall deposit with Nevada an additional amount
equal to four dollars and fifty cents ($4.50) per kilowatt of Contract
Capacity. Seller's deposits shall be In addition to any other deposits
required under this Contract. Seller's deposits shall be placed In
escrow and shall accrue Interest at the rate set by the Commission for
Interest paid on customer deposits.
11.1 If this Contract has not been approved by the Commission In
accordance with the provisions of Section 27, Seller's escrow deposit
plus accrued Interest shall be refunded to Seller. Seller's refund
shall be sent to Seller within sixty (60) days of the Commission's
failure to approve this Contract.
11.2 If Seller achieved Firm Operation at the level of capacity
specified in Section 1.4, Seller's escrow deposits plus accrued
Interest shall be refunded to Seller. Seller's refund shall be sent to
Seller within sixty (60) days of Firm Operation.
If Seller achieved Firm Operation at a level of capacity less than the
level of capacity specified In Section 1.4, Seller's escrow deposits
plus accrued Interest shall be prorated on the basis of actual
performance. That portion of Seller's escrow deposits plus accrued
Interest attributed to Seller's actual performance shall be refunded to
Seller; the balance shall be forfeited to Nevada. Seller's refund shall
be sent to Seller within sixty (60) days of Firm Operation.
11.4 If Seller failed to achieve Firm Operation, Seller's escrow
deposits plus accrued Interest shall be forfeited to Nevada.
11.5 Seller shall have the right to substitute irrevocable letters of
credit or surety bonds In the amounts of the escrow deposits for cash
deposits. Such Irrevocable letters of credit or surety bonds shall be
in a form acceptable to Nevada.
12 BILLING PROVISIONS: Nevada's bills, which have been rendered by Nevada
In accordance with the provisions of this Contract, shall be due upon
receipt by Seller and payable within twenty (20) days of receipt by
Seller. Seller shall make every reasonable effort to pay Nevada's bills
promptly. If Seller failed to make timely payment of any of Nevada's
bills, Nevada shall have the right, without liability to withhold the
amount due Nevada from payments due Seller for Capacity and Energy. If
Seller failed to make timely payment of any of Nevada's bills, Nevada
shall also have the right to exercise any other rights and remedies
available to Nevada In accordance with the provisions of this Contract.
13. CAPACITY AND ENERGY PAYMENT PROVISIONS:
13.1 Nevada shall send to Seller, not later than thirty (30) days after
the end of each monthly payment period, Nevada's statement showing the
Capacity and Energy received by Nevada during the payment period and
Nevada's check In payment of the amount due Seller. If two or more
rates were applicable to any payment period, Nevada's payment shall be
based upon the amount of Capacity and Energy received by Nevada during
the period each rate was applicable, or, If such Information was
unavailable, Nevada's payment shall be based upon the number of days
each rate was applicable.
13.2 Seller shall have the right of access to Nevada's records that are
reasonably required to confirm the accuracy of Nevada's statement.
Seller shall, within thirty (30) days of Seller's receipt of Nevada's
statement, notify Nevada In writing of any error In Nevada's statement.
If Seller failed to provide such notice, Seller shall have waived all
rights to an adjusted payment for the subject payment period.
If Seller notified Nevada of an error In Nevada's statement or If
Nevada discovered an error In Nevada's statement within thirty (30)
days of the Issuance of Nevada's statement, Nevada shall provide an
adjusted statement to Seller. If Nevada's error resulted In an
additional payment to Seller, Nevada's check In payment of the amount
due Seller shall accompany the adjusted statement. If Nevada's error
resulted In a refund to Nevada, Nevada's bill for the amount due Nevada
shall accompany the adjusted statement.
14. TAXES:
14.1 Seller shall pay ad valorem and other taxes properly attributed to
Seller's Facilities.
14.2 Nevada shall pay ad valorem and other taxes properly attributed to
Nevada's Facilities.
14.3 Seller and Nevada shall provide Information concerning either
Party's Facilities to any requesting taxing authority.
14.4 Nevada shall pay franchise and other taxes properly attributed to
Nevada's resale of Capacity and Energy.
15. LIABILITY:
15.1 Neither Party shall be saved harmless and indemnified from any
loss and liability resulting from that Party's negligence or willful
misconduct.
15.2 Each Party shall release the other Party from any loss and
liability, whether direct or Indirect and Including attorney's fees and
other costs of litigation, resulting from damages to property of the
releasing Party arising out of the other Party's efforts to perform Its
obligations under this Contract to the extent that such damages were
not caused by negligence or willful misconduct of the Indemnified
Party.
15.3 Each Party shall be solely responsible for the costs and liability
of all claims brought by Its employees or contractors and shall save
harmless and Indemnify the other Party from all such costs and
liability. Costs arising out of worker's compensation laws shall be
deemed employee related claims for the purposes of this section.
15.4 Each Party shall save harmless and indemnify the other Party from
any loss and liability, whether direct or Indirect and Including
attorney's fees and other costs of litigation, resulting from the
Injury or death of any person and damages to any property of a third
party arising out of the Indemnifying Party's performance of
obligations under this Contract to the extent that such Injury, death,
or damages were not caused by negligence or willful misconduct of the
Indemnified Party.
16. INSURANCE: Until this Contract has been terminated, Seller shall
maintain comprehensive general liability coverage with a minimum
combined single limit per occurrence of five million dollars
($5,000,000.00). Seller's Insurance policy shall be subject to Nevada's
approval. Seller shall deliver a copy of Seller's Insurance policy to
Nevada prior to the date Seller's Interconnection Facilities are first
energized. Seller's Insurance policy shall provide for thirty (30) days
written notice of alteration or termination to Nevada. Seller shall
also provide an Insured endorsement to Nevada in the form set forth In
Exhibit F.
If Seller failed to comply with the provisions of this section, Seller
shall save harmless and indemnify Nevada from any loss and liability,
whether direct or Indirect and Including attorney's fees and other
costs of litigation, resulting from the Injury or death of any person
or damage to any property to the extent that Nevada would have been
protected had Seller compiled with these provisions. If Seller failed
to comply with the provisions of this section, Nevada shall have the
right, without liability, to refuse to connect or to Isolate Seller's
Facilities from Nevada's system. Once Isolated, Seller's Facilities
shall remain isolated until Seller Is In compliance with these
provisions.
17. UNCONTROLLABLE FORCES: Except as otherwise provided in Section 10, if
Uncontrollable Forces rendered a Party wholly or partially unable to
perform any obligations under this Contract, the non-performing Party shall
be excused from such performance provided that Party delivered a written
description of the problem to the other Party within two weeks of the
occurrence; that the suspension of performance was no greater In magnitude
and no longer In duration than was dictated by the problem; that the
non-performing Party made every reasonable effort to alleviate the problem
except that neither Party shall be required to settle any labor dispute on
terms that It deemed contrary to Its best Interest; and that the
non-performing Party notified the other Party In writing as soon as the
non-performing Party was able to resume full performance of Its obligations
under this Contract.
18. NON-DEDICATION OF FACILITIES: By this Contract, neither Party dedicated
any part of Its facilities to the public or to the service provi'ded
under this Contract. Such service shall cease upon termination of this
Contract.
19. AMENDMENTS: Unless otherwise specified herein, all modifications to
this Contract shall require amendments to this Contract. Amendments to
this Contract shall be In writing and shall be executed by both
Parties.
20. PREVIOUS COMMUNICATIONS: This Contract contains the entire agreement
and understanding between the Parties thereby merging and superseding
all prior agreements and representations by the Parties.
21. NON-WAIVER: Any waiver of the provisions of this Contract shall be ir
writing. The failure of either Party to Insist upon strict performance
of Contract provisions or to exercise any Contract right shall not be
construed as a waiver of such Contract provision or a relinquishment of
such Contract right.
22. DISPUTES: The Parties shall negotiate In good faith and attempt to
resolve any dispute arising between the Parties and requiring an
Interpretation of the provisions of this Contract. However, If the
Parties are unable to resolve any such dispute, either Party shall
have the right to submit a demand that such dispute be arbitrated to
the other Party. If such a demand is submitted, the dispute shall be
resolved by arbitration conducted In accordance with the rules of the
American Arbitration Association (AAA). If such a dispute arises, the
demanding Party shall file a request with the AAA for the selection,
pursuant to the AAA rules, of a member of the AAA In good standing who
shall serve as the sole arbitrator. After the arbitrator has been
selected, the arbitration shall be held In Las Vegas, Nevada. The
Parties shall proceed with the arbitration expeditiously and shall
conclude all proceedings thereunder so that a decision may be rendered
within one hundred twenty (120) days of the submittal of the demand
for arbitration. Pending resolution of dispute, the Parties shall
proceed diligently with the performance of their obligations under
this Contract. The award of the arbitrator shall be final and binding
on both Parties and shall be enforceable by any court having
Jurisdiction over the Party against which enforcement is sought. Each
Party shall bear Its own costs associated with resolution of the
dispute except that all costs associated with the arbitration shall be
apportioned In the award of the arbitrator based upon the respective
merit of the claims of the Parties.
23. REMEDIES: Except as otherwise set forth in this Contract, each Party,
upon the other Party's failure to perform in accordance with the
provisions of this Contract, shall have the right to exercise any
right or remedy that Party may have at law or in equity including but
not limited to compensation for monetary damages such as the cost of
removal and/or abandonment of Nevada's Facilities and the incremental
cost of replacement power plus the incremental installed cost of
replacement generation and transmission facilities, injunctive relief,
and specific performance except that neither Party shall be liable for
any indirect, consequential, incidental, punitive, or exemplary
damages. If applicable, forfeited escrow deposits and/or refunded
Capacity and Energy payments shall be subtracted from monetary damages
due Nevada in accordance with the provisions of this section.
24. ASSIGNMENT AND DELEGATION: Neither Party shall assign any right nor
delegate any duty under this Contract without the written consent of
the other Party; except Seller shall have the right to assign Seller's
rights under this Contract as collateral In conjunction with project
financing without Nevada's consent. Consent for assignment or
delegation shall not be unreasonably withheld or delayed.
If Seller assigns Seller's rights as collateral In conjunction with
project financing, Lender shall have the right to appoint, subject to
Nevada's prior written approval, operating agents who shall assume
responsibility for the construction, operation, and maintenance of
Seller's Facilities if Seller falls to perform in accordance with the
provisions of this Contract. Nevada's approval shall not be
unreasonably withheld or delayed. If Lender's operating agent(s) fall
to cure Seller's default within thirty (30) days of such default,
Nevada shall have the right, without liability, to terminate this
Contract. If Lender's operating agent(s) fall to perform in accordance
with the provisions of this Contract, Nevada shall have the right,
without liability, to terminate this Contract.
25. GOVERNING LAW: This Contract shall be interpreted under the laws of the
State of Nevada as if executed and performed wholly within that state.
26. NATURE OF OBLIGATIONS: Unless otherwise agreed upon by the Parties and
set forth herein, the duties, obligations, and liabilities of the
Parties shall be several; not joint or collective. The provisions of
this Contract shall not be construed as creating an association, trust,
partnership, or joint venture; as Imposing a trust or partnership duty,
obligation, or liability on either Party; or as creating any
relationship between the Parties other than that of Independent
contractors for the sale and purchase of electric capacity and/or
energy. Nothing in this Contract nor any action taken hereunder shall
be construed as creating any duty, liability or standard of care to any
person not a Party to this Contract.
27. COMMISSION APPROVAL: Within thirty (30) days of Contract execution,
Nevada shall submit this Contract to the Commission for review and
approval. This Contract shall be void unless approved by the Commission
as executed.
28. SIGNATURES:
IN WITNESS WHEREOF, the Parties hereto have executed this Contract this
Second day of May, 1989.
BONNEVILLE NEVADA CORPORATION:
By:
Name: R. A. Keegan
Title: President
NEVADA POWER COMPANY:
By:
Name: Charles A. Lenzie
Title: Chairman of the Board
SCHEDULE I
HEAT PURCHASE AGREEMENT
THIS HEAT PURCHASE AGREEMENT (the "Agreement") is made and entered into this
12th day of September, 1989, by and between BONNEVILLE NEVADA CORPORATION, a
Nevada corporation ("Bonneville Nevada") and GEORGIA-PACIFIC CORPORATION, a
Georgia corporation (11G-P11). G-P and Bonneville Nevada are referred to
collectively herein as "Parties".
RECITALS:
A. Bonneville Nevada and G-P have entered into an Amended and Restated Business
Agreement (the "Business Agreement") of even date herewith whereunder, subject
to the terms and conditions therein contained, Bonneville Nevada has agreed to
construct, operate and maintain an approximately 85 megawatt cogeneration
facility (the "Facility") lying adjacent to G-P's existing gypsum plant located
in Clark County, Nevada (the "Plant").
B. Under the terms of the Business Agreement, Bonneville Nevada agrees to supply
to G-P and G-P agrees to purchase from Bonneville Nevada heat (the "Thermal
Output") produced by the Facility for the use by G-P in the Plant
The Parties desire hereby to set forth their agreement and understanding with
respect to the provisions and purchase of the Thermal Output.
NOW, THEREFORE, in consideration of the mutual covenants and
agreements herein contained, and for other good and valuable consideration,
the receipt and adequacy of which are hereby acknowledged, the Parties
hereto agree as follows:
AGREEMENT
1. Characteristics and Thermal Requirements of the Equipment. The Plant as
currently designed and operated includes one 2-zone kiln and four gypsum
calcining mills (the "Equipment"). The Plant's current operating statistics are
approximately as follows:
(a) Line Speeds: 130 fpm for 1/2 inch board and 100 fpm for 5/8 inch
board;
Evaporative Estimate: 800 pounds every 2 minutes for a total of 24,000 pph;
Normal Control Temperatures: Kiln Zone 1 - 600 degrees - 650 F; Kiln Zone 2
- - 450 degrees F
Total Present Gas Usage: Approximately 1,100 MCF per day all natural gas
values in this Agreement assume 1,000
BTU/CF) of which approximately 60 percent goes to the kiln and
approximately 40 percent goes to the gypsum mills;
(e) Plant Operating Schedule: 6 2/3 days per week, 24 hours per day;
Based upon the foregoing characteristics, the Equipment, as currently
configured, requires approximately 45.7 MMBTUs of heat delivered to the Delivery
Point(s) as hereinafter described during each hour of Plant operation.
It is anticipated that the Plant's capacity will be increased during the term of
this Agreement. The defined term "Equipment" shall hereinafter refer to the kiln
and calcining mills, as they may be configured now or in the future. defined
term "Thermal Requirements" shall hereinafter refer to heat requirements of the
Equipment, as it is configured now or in the future. The parties agree that the
maximum amount of heat delivered under this Agreement following potential future
expansion of the Plant shall be the equivalent of 1900 MCF/day (annual average)
with a winter daily peak of up to 2100 MCF/day and such maximum amount may be
relied upon by Bonneville Nevada in designing and constructing the Facility.
2. Characteristics and Thermal Output of the Facility. The Facility is shown on
the drawing, attached hereto as Exhibit "A" and by this reference made a part
hereof. The Facility consists of three combustion gas turbine generators
headered together on the high temperature discharge gas exhaust. Process heat is
supplied to the two zones of the kiln and the four mills by control dampers.
Excess exhaust heat is ducted to a dual drum heat recovery steam generator to
produce superheated steam and dearator,makeup steam
Additional electrical power is produced in a combined cycle using a condensing
steam turbine. The system configuration is as follows:
Threelcombustion gas turbine generators (CGTGs) at approximately
21,383 KW each corrected for site conditions;
Three heat recovery steam generators (HRSG) at approximately 62,500
pph, 850 psig and 900 degrees F; and
One steam turbine condensing at 3.0 inches HgA at approximately 25,000 KW.
Total useful thermal output presently available to G-P for use at the Plant
"Thermal Output") is 45.7 MMBTU/hr Bonneville Nevada shall at all times maintain
a temperature range between 950 and 975 degrees Fahrenheit for heat as it enters
the mills and kiln, and a reasonably constant pressure of between 8 and 10
inches of water, unless a different temperature or pressure range is agreed by
the parties in writing. The Thermal Output shall not contain unburned
hydrocarbons or any other compounds in sufficient quantities to cause any
staining on the surface of the wallboard as currently produced at the Plant
3. Agreement to Sell and Purchase. Based upon the foregoing Plant and
Facility characteristics, and subject to the terms and conditions contained
herein, Bonneville Nevada agrees to provide and sell to G-P on a continuous
basis, heat in accordance with the specifications set out in Paragraph 3(c)
below, and G-P agrees to accept and purchase from Bonneville Nevada such heat
for all of the Thermal Requirements of the Equipment on the following terms and
conditions:
Commencement of Supply. Bonneville Nevada shall commence supplying the Thermal
Requirements upon the date of Firm Operation, as that term is defined in the
Standard Contract for Long-Term Power Purchases from Qualifying Facilities
between Bonneville Nevada and Nevada Power, dated May 2, 1989 (the "Power
Purchase Agreement"), a copy of which has been provided to G-P and the receipt
of which is hereby acknowledged, subject to Force Majeure Conditions, which
conditions may include Georgia-Pacific's inability to accept the Thermal Output
on the date of Firm Operation. In the event Bonneville Nevada is capable of
supplying the Thermal Requirements on a continuous basis prior to the date of
Firm operations, it shall so notify G-P and supply of the Thermal Requirements
shall commence on such earlier date. The initial Contract Year, as that term is
used hereinafter, shall begin on the date Bonneville Nevada commences supplying
Thermal Output to the Plant. Each subsequent Contract Year shall begin on the
anniversary of the initial Contract Year.
Integration of Facility with Plant. Bonneville Nevada shall design and
construct the Facility in such a manner so as to provide for full integration of
the Facility with the Plant without significant or adverse impacts on Plant
operations. The Parties agree to cooperate in scheduling and implementing such
integration procedures based upon plans, designs, specifications for the
Facility, and an integration plan approved in advance by both parties Bonneville
Nevada agrees to pay one million five hundred thousand dollars ($1,500,000) for
modification of the kiln system and pay one million four hundred eighty seven
thousand dollars ($1,487,000) for modification of the mill system. Such payments
shall be made in 21 equal monthly installments of one hundred forty two thousand
two hundred thirty eight and 09/100 dollars ($142,238.09) beginning on June 30,
1990. Bonneville Nevada shall also pay G-P the sum of five hundred thousand
dollars ($500,000) as the agreed reimbursement for anticipated costs associated
with construction downtime and start-up losses. This payment shall be made
within thirty (30) days after Bonneville Nevada's first delivery of Thermal
Output to G-P. Such payments shall constitute Bonneville Nevada's sole
obligations relating to G-P's costs of Equipment modification and G-P's costs
associated with construction downtime and start-up losses. All other costs
incurred in connection with full, integration of the Facility with the
Equipment, if any, shall be borne by G-P.
(c) Point(s) of Delivery and Maximum Thermal Requirements. The Thermal
Output of the Facility sufficient to the Thermal Requirements of the Equipment
shall be delivered to a point or points reasonably designated by G-P. "Delivery
Point(s)") The Delivery Points shall be designated and described by G-P and
shall be shown as a part of Exhibit "B", attached hereto and by this reference
made"a part hereof.
(d) Redundancy of Facility Operations; G-P Back-up System The Facility
shall be designed and constructed in such a manner and with sufficient
redundancy capabilities to ensure to the reasonable satisfaction of G-P the
availability of the Facility to consistently and continuously meet the maximum
Thermal Requirements of the Equipment. G-P shall have right to review and
approve all plans and specifications of the Facility as they relate to this
redundancy requirement. Notwithstanding the foregoing, G-P agrees to keep its
gas line "System") presently used to meet the Thermal Requirements, in place and
operational throughout the term of this Agreement such that in the event of
Facility failure or shut-down, the existing System may be used to meet the
Thermal Requirements. Costs to maintain the existing System shall be borne by
G-P.
(e) Purchase Price. The purchase price for the Thermal Output shall be an
amount equal to sixty-five percent (65%) of the energy costs of operating the
Equipment on natural gas through the use of the Plant's existing System. The
basis determining natural gas costs shall be the lower of the following, as of
the first day of the calendar month during which payment is made: (I The
"Indexed Gas Cost", as defined in the following sentence or (2) the Facility's
average delivered price of gas during the preceding month under contracts
similar to those available to industrial gas users in North Las Vegas on
Southwest Gas's Apex Lateral. The Indexed Gas Cost shall be determined by taking
the sum of (i) the most currently available McGraw Hill Publication "Inside
FERC's Gas Marketing Report" index price for natural gas delivered into El Paso
Pipeline, New Mexico (San Juan Basin), plus (ii) the El Paso and Southwest Gas
tariff rates for interruptible service from the El Paso connection to the Plant,
including all required compression, transportation, processing, delivery ACA,
GRI, and/or other applicable charges. Bonneville Nevada shall notify G-P within
ten 10) days after the beginning of each calendar month of its average delivered
price of its contract gas, as defined above, during the preceeding month. In the
event that the publication ceases to maintain the subject index, or that the
index does not reflect available market price, the parties will substitute the
most appropriate then-currently available index.
In the event that an available alternative energy source could be utilized
to meet the Thermal Requirements of the Equipment at a cost less than that of
natural gas, the purchase price of the Thermal Output shall be adjusted for the
energy costs of this alternative energy source. The cost of any alternative
energy source shall include the estimated capital costs of installing and
permitting the capability to utilize that energy source, with such capital
cost amortized on a straight line basis over fifteen years. The purchase price
shall be adjusted from time to time, but mot more frequently than quarterly,
to continuously reflect a net thirty-five percent (35%) savings by G-P over
cost for energy displaced which G-P would otherwise pay to operate the
Equipment.
(f) Quantity. Due to the uncertainty and difficulty of metering the Thermal
Output utilized by the Equipment as it is introduced into the Equipment, it is
agreed that the Thermal Output utilized by the equipment will be determined by
the formula set forth in detail in Exhibit "C" attached hereto and by this
reference made a part hereof.
(g) Other Sources of Heat - Notwithstanding the foregoing, G-P may use
other sources of heat in the event of a Force Majeure Condition, as defined in
Paragraph 7; in the event Bonneville Nevada does not provide heat in the
quantity or quality required by this Agreement; in order to meet Thermal
Requirements in excess of the maximum amount of heat available under this
Agreement, as specified in Paragraph 1(e); or in order to increase the
temperature of the Thermal Output in the event G-P chooses to operate the mills
at a temperature higher than that of the Thermal Output. Any and all increased
operating and fuel expenses incurred as a result of G-P electing to operate the
Equipment at a higher temperature shall be borne by G-P, except to the extent
that G-Pls cost of fuel exceeds the lower of the indexed gas price or Bonneville
Nevada's cost of contract gas, as described in the second sentence of Paragraph
3(e). Any such cost differential shall be paid by Bonneville Nevada. G-P shall
use reasonable efforts to minimize the cost of fuel used in operating the
Equipment at higher* temperatures.
Billing. Within thirty days following the end of each fiscal month, G-P
will prepare a statement of the amount of energy utilized by the Equipment,
based upon the formula described in Exhibit C. The statement shall also state
the amount and cost of sources of energy for the Equipment other than the
Thermal Output which G-P paid during the fiscal month and reflect adjustments in
the amounts due Bonneville Nevada as a result of utilizing such other sources of
energy. G-P shall mail said statement to Bonneville Nevada, together with the
amount due Bonneville Nevada for such usage. In the event that the statement
reflects a net credit to G-P, where the costs of energy from other sources
exceed the costs associated with energy from Bonneville Nevada, then Bonneville
Nevada shall pay the credit amount to G-P within 30 days of date of receipt of
the statement. Since the results of G-P's operation are considered highly
confidential by G-P, Bonneville Nevada covenants that it will not disclose to
others any information relating to the reported operations of G-P, which is
necessarily the basis of the monthly statement prepared by G-P. G-P shall
provide Bonneville Nevada reasonable access to the Plant's relevant operating
records for the purpose of Bonneville Nevada verifying the accuracy of the
monthly statements.
4. Commitment to Use Thermal Output. G-P understands and acknowledges that
the Facility will be a Qualifying Facility under the Public Utility Regulatory
Policies Act of 1978 ("PURPA" In order to continuously qualify under PURPA and
the rules and regulations promulgated thereunder by the Federal Energy
Regulatory Commission ("FERC"), Bonneville Nevada must be assured of the likely
availability of a user of the Thermal Output for the entire term of the Power
Purchase Agreement. G-P agrees to provide Bonneville Nevada with such
information as may be reasonably necessary to complete all certification
requirements of PURPA and the regulations promulgated thereunder by FERC,
provided that this information is reasonably available to G-P without additional
expense
(a) Plant Operation. G-P hereby represents to Bonneville Nevada that it has
sufficient gypsum reserves, based upon its current projections, to operate the
plant for the entire term of this Agreement. G-P has no current intention to
permanently curtail production at the Plant or to close the Plant during the
term of this Agreement, but G-P does not warrant that it will operate the Plant
in any specified manner or for any specified period of time, subject to the
provisions of this Paragraph 4.
(b) Minimum Thermal Usage. Bonneville Nevada represents that in order to
keep the Facility qualified under PURPA the Plant must use a minimum of 168,000
MMBTUS (annualized) during each Contract Year (the "Minimum Thermal Usage"). In
the event that G-P elects to expand its Plant operations, the Minimum Thermal
Usage requirement shall increase by a percentage equal to the percentage of
increased MCF per day used by the Plant over the 1,100 MCF per day presently
used by the Plant. For example, in the event the Plant expands and uses 1,500
MCF per day, such use shall constitute a 27% increase over the 1100 MCF per day
specified in paragraph 1 hereof. Pursuant to the foregoing, the minimum Thermal
Usage will likewise increase by 27%, and in this example would constitute
213,360 MMBTUs. G-P agrees that it will meet or exceed the Minimum Thermal Usage
requirement specified herein, subject to the provisions of this Agreement,
through the consumption of BTUs used in (1) the operation of the Equipment, (2)
the chilling of water by Bonneville Nevada for the amount of chilled water
utilized at the Plant, and (3) any other use by the Plant of heat from the
Facility. In the event that G-P forcasts that it will not satisfy the Minimum
Thermal Usage for a Contract Year, it shall give the notice hereinafter
specified, provided that the forecasted inability to satisfy the Minimum Thermal
Usage is not caused by a Force Majeure Condition as described in Paragraph 7 of
this Agreement or the inability of Bonneville Nevada to provide Thermal Output
to the Plant.
(c) Notice of Early Termination. If G-P, in its sole discretion, elects
(1) to indefinitely reduce production such that its energy use falls below the
Minimum Thermal Usage or (2) to indefinitely shut down the Plant, shall give
Bonneville Nevada not less than three years prior written notice of such
proposed reduction or shut down, provided that such reduction or shut down is
not caused Force Majeure Condition as described in Paragraph 7 of this
Agreement. G-P shall continue to operate the Plant and effectively use the
Minimum Thermal Usage for the remaining notice period; provided, however, that
the price for the Thermal Output required to be paid hereunder shall be adjusted
so as to allow the Plant to operate at a break even point. In no event shall the
cost to G-P of the Thermal Output be less than Ten Dollars ($10) per month, nor
greater than the cost otherwise specified in this Agreement. The term "break
even point" shall mean that revenues from the Plant shall be sufficient to cover
all direct costs associated with the Plant, as those costs are determined by
G-P's standard internal accounting practices.
(d) Plant Lease Alternative. At any time during said notice period, G-P may
nonetheless choose to terminate its operation of the Plant upon 60 days prior
notice to Bonneville Nevada. Bonneville Nevada shall have the right, but not the
obligation, to assume and conduct operation of the Plant and related quarry for
the remaining term of the three years notice period under a lease as mutually
negotiated in good faith by the parties. The lease shall provide for rental
payments to G-P in the amount of G-P's book depreciation and depletion for the
Plant and related quarry plus G-P's property expense for the Plant, with such
rental not to exceed $20,000 per month. In addition, Bonneville Nevada shall
agree to properly maintain all equipment at the plant and its related quarry,
ordinary wear and tear excepted, and shall pay all costs associated with the
Plant's operation within the lease period.
5. Term. Subject to the provision of Paragraph 7 hereof and other provisions
relating to early termination, the term of this Agreement shall be from the date
hereof to and including the earliest of a) April 30, 2023, or the (b)
termination date of the Power Purchase Agreement or any subsequent agreement
with Nevada Power Company, its successors or assigns relating to the sale of
power from the Facility, or
(c) December 31, 1989 if Bonneville Nevada has not obtained by that date an
exemption from jurisdiction of the Nevada Public Service Commission, pursuant to
NRS 704.310 and a Force Majeure Condition, as described in Paragraph 7 of
Schedule I, has not occurred. However, in the event that physical construction
of the Facility has not commenced before November 1, 1991, in the event that the
date of Firm Operation has not occurred before July 1, 1993, or in the event
that the Power Purchase Agreement is terminated and not replaced within ninety
(90) days of such termination with a comprable power purchase agreement, then
G-P may, at its option, terminate this Agreement.
6. Power Sales. As further detailed in Paragraph 2(c) of the Business
Agreement Bonneville Nevada agrees to provide G-P with workable electrical power
for use by G-P in the Plant. In the event G-P elects to purchase such power, all
facilities necessary to deliver such power to the Plant shall be constructed at
G-P's expense and G-P shall purchase such power at the lesser of (1) the
industrial rate of Nevada Power Company which would have applied to the Plant or
(2) cogeneration rate paid by Nevada Power Company to Bonneville Nevada under
the Power Sale Agreement at 'such time that G-P makes the election to purchase
such power. A failure by Bonneville Nevada to provide electrical power to G-P
for any reason whatsoever shall not constitute a default hereunder or under the
Business Agreement on the part of Bonneville Nevada. However, the price paid for
heat purchased under this Agreement shall be adjusted to reflect a credit to
account for G-P's cost for purchasing power from another source in excess of the
rate forth in this Paragraph.
7. Force Majeure. A Force Majeure Condition, as term is hereinafter used,
shall refer to any occurrence beyond the reasonable control of a Party that
renders a Party incapable of performing its obligations hereunder. Force Majeure
Conditions shall include, but not be limited to floods, droughts, earthquakes,
storms, fires, pestilence, lightning or other natural catastrophes; epidemics;
wars; riots, civil disturbance, or other civil disobedience; strikes or other
labor disputes; action or inaction of legislative, judicial regulatory, or other
governmental bodies that may render illegal action taken in accordance with the
provisions of this Agreement, provided that the party claiming a Force Majeure
Condition has used its best efforts to attempt to secure appropriate regulatory
or administrative authorization; and failure or sabotage of facilities that have
been operated and maintained in accordance with the provisions of this
Agreement. If a Force Majeure Condition renders a Party wholly or partially
unable to perform any obligations under this Agreement, the non-performing Party
shall be excused from such performance provided that Party delivers a written
description of the problem to the other Party within two weeks of the
occurrence; that the suspension of performance is no greater in scope and no
longer in duration than is dictated by the problem; that the non-performing
Party makes every reasonable effort to alleviate the problem except that neither
Party shall be required to settle any labor dispute on terms that it deems
contrary to its best interest; and that the non-performing Party notifies the
other Party in writing as soon as the non-performing Party is able to resume
full performance of its Z,/ obligations under this-Contract.
8. Entire Agreement. This Agreement and the Business Agreement constitute the
entire agreement of the Parties relating to the subject matter hereof and
supercede any prior agreements, understandings, or communications between the
Parties with respect to the subject matter hereof. This Agreement shall not be
further modified or amended except by written instrument executed by the Parties
hereto.
9. Binding Agreement. This Agreement shall be binding upon and
inure to the benefit of the Parties hereto and their respective successors
and permitted assigns.
10. Assignment. In the event that Bonneville Nevada, G-P or any subsequent
owner transfers all or a portion of its ownership of the Facility or Plant, the
transferring Party shall require the acquiring party to assume all of the
transferring Party's rights and responsibilities set out in this Agreement or
any agreement referred to herein or contemplated hereby. In any event, the
transferring Party shall remain liable to the other Party for all obligations
arising out of this Agreement or any agreement referred to herein or
contemplated hereby. Notwithstanding the foregoing, neither this Agreement nor
any agreement referred to herein or contemplated hereby shall be assigned by any
Party hereto unless and until prior written approval is received from the other
Party, which approval will not be unreasonably withheld. It is understood and
agreed that notwithstanding the foregoing, in the event it is necessary to
assign any rights or interests hereunder to any financially stable and reputable
lenders or lessors providing construction or permanent financing or leveraged
leasing for the Facility or the Plant, the Parties hereto shall approve and do
hereby approve such assignments.
11. Default - Remedies; Liguidated Damages. In the event of default by
either Party hereunder, the non-defaulting Party shall have all rights and
remedies available in law or equity against such defaulting Party; provided,
however, that in the event of default by Bonneville Nevada in the provision of
Thermal Output sufficient to meet the Thermal Requirements, G-P's sole remedy
against Bonneville Nevada shall be recovery of all actual costs and losses
incurred by G-P as a direct result of such default including, but not limited
to, the thirty-five percent (35%) savings in the costs of natural gas or other
energy source used in operating G-P's existing facilities to provide the Thermal
Output necessary to meet the Thermal Requirements and the costs of lost
production associated with the changeover to natural gas or other energy source.
Bonneville Nevada shall not be liable for other incidental or consequential
damages resulting from its failure to provide Thermal Output. Likewise, G-P
shall not be liable to Bonneville Nevada for a reduction in its use of the
Thermal Output or for closure of the Plant and the resulting failure to use the
Minimum Thermal Usage provided that G-P has given the prior written notice
required hereunder. In the event that G-P does not give Bonneville Nevada this
required notice, Bonneville Nevada's sole remedy, at Bonneville Nevada's
election, shall be either (1) recovery of the sums G-P would have paid for the
Thermal Output during the Contract Year had the Equipment been running at full
capacity plus the amounts payable to Bonneville Nevada under Paragraph 4(c
hereof, or (2) the right to lease the plant as specified in Paragraph 4 hereof.
The foregoing limitations constitute valid and mutually agreed liquidated
damages and shall be binding upon the Parties hereto. In the event of default,
the defaulting Party shall pay all costs and fees incurred by the non-defaulting
Party in enforcing this Agreement against such defaulting Party to the extent
that it can be enforced subject to the liquidated damages provisions herein
contained.
12. Notices. All notices required or permitted hereunder shall be deemed
duly delivered when personally delivered or three (3) days after being sent by
United States mail, or one (1) day after being sent by overnight express
delivery, postage or service fee pre-paid, and addressed to the Parties at the
following addresses:
If to Bonneville Nevada: Bonneville Nevada Corporation 257 East 200
South, Suite 800 Salt Lake City, Utah 84111
Attention: President
If to G-P: Georgia-Pacific Corporation
133 Peachtree Street, N.E.
Atlanta, Georgia 30303
Attention: Vice President -
Gypsum and Roofing Division
13. Governing Law. This Agreement shall be governed by and construed in
accordance with the laws of the state of Nevada.
IN WITNESS WHEREOF, the Parties hereto have caused these presents to be executed
by their duly authorized officers the day and year first above written.
BONNEVILLE NEVADA CORPORATION
By(s)
Its President
GEORGIA-PACIFIC CORPORATION
By
Vice President
Gypsum and Roofing Division
Exhibit C
Computation of Heat Used by Plant
In order to initially determine the amount of heat used by the Equipment for
billings and other purposes relating to this Agreement, G-P shall use its Plant
Energy reports to tdetermine energy usage of the Equipment over the twelve month
period immedilatey preceding the month G-P initially utilizes heat provided by
Bonneville Nevada. In order to compute energy usage by the mills, G-P shall
calculate the number of BTU's per ton of calcined stucco produced during the
prior tweleve months. In order to compute energy usage by the kilns, G-P shall
calculate the average number of BTU's required to evaporate a pound of water
in the wallboard drying process during the prior twelve months. The quantity of
stucco produced and the quantity of water evaporated shall be based upon the
gross square footage of wallboard produced. The resulting calculated values
shall hereinafter be referred to as the "Mill Energy Factor" and "Kiln Energy
Factor" respectively.
For each billing period, the amount of energy utilized by the Equipment, in gas
equivalent BTU's, shall be computed under the following formula:
Mill Heat Usage = Mill Energy Factor X tons of Stucco Produced.
Kiln Heat Usage = Kiln Energy Factor x Pounds of Water Evaporated.
Billings for energy may then be based upon the following:
(Mill Heat Usage + Kiln Heat Usage) x Gas Costs Per BTU (as determined by
Paragraph 3(e).
The parties acknowledge that, due to equipment and operational changes, the
energy efficiency of the Equipment may change during the term of this agreement.
This formula shall be subject to revision from time to time, but not more
frequently than annually, to reflect such changes. In the event either party
believes that the Mill Energy Factor or Kiln Energy Factor no longer accurately
reflect the average energy usage of the Equipment over the course of a year, the
parties shall discuss modification of the formula. In the event that the parties
can not agree on a revised formula, either party may request a verification
testj using metered natural gas as the sole source of energy to operate the mill
or kiln. The procedures for the test shall be as agreed by the parties, except
that all tests shall be of a minimum duration of one(l) day for the kiln and
four(4) days for the mill and must include adjustment for seasonal factors. In
the event that the parties cannot agree on such test procedures, they shall
mutually appoint a consultant to determine the test procedures. The
determination of the consultant shall.be binding upon both parties. The Party
requesting such verification shall pay all costs associated with it, except that
if the results of the verification indicate that the formula currently in use is
in error by a factor of 5% or more to the advantage of the nonrequesting Party,
then such nonrequesting Party shall pay all costs associated with the
verification.
Bonneville Pacific Corporation
February 21, 1989
Daniel Renbarger, Esq.
Georgia Pacific Corporation
133 Peachtree Street N.E.
Atlanta, Georgia 30303
Dear Mr. Renbarger
David Hirschi asked me to forward the following language to you for use in the
Heat Purchase Agreement, Page 6, Paragraph 3E, 2nd sentence:
The basis for determining natural gas costs should be by utilizing the McGraw
Hill Publication "Inside FERCIs Gas Marketing Report" index price for natural
gas delivered into El Paso Pipeline, New Mexico (San Juan Basin). This commodity
cost shall be added to El Paso and SWGas tariff rates for interruptible service,
including all required compression, transportation, processing, delivery, ACA,
GRI, and/or other applicable charges. A sample calculation with documentation is
attached as Exhibit "D". If, for reasons beyond BPC's control, gas is not
available or cannot be transported from the San Juan Basin, BPC shall notify G-P
and keep detailed records of actual commodity and transportation costs into El
Paso Pipeline. These costs shall become the basis for determining natural gas
commodity cost for the period of time that gas cannot be supplied from the San
Juan Basin.
In the event that the publication ceases to maintain the subject index, or that
the index does not reflect available market price, the parties will agree on an
alternative index.
This language was developed through conversations between Greg Twombly
of Bonneville Fuels and J. Pat Hudgens of Georgia Pacific.
If you have any questions, please contact me.
Sincerely,
Jim Matheson
Development Manager
CC: Dave Hirschi
257 East 200 South, Suite 800 / Salt Lake City, Utah 84111 / 801-363-2520
MEMORANDUM DR
DATE: JULY 6, 1989
TO: DAVID P. HIRSHI
FROM: VAL R. ANTCZAK AND JONATHAN K. BUTLER
RE: EFFICIENCY STANDARDS FOR TOPPING CYCLE COGENERAI
FACILITIES/ BONNEVILLE PACIFIC CORPORATION AND GEOF
PACIFIC
You have requested a brief discussion of the efficiency standards and
consequent minimum heat load, of the Public Uti ties Regulatory Policies Act of
1978 ("PURPA" , and the regu tions under PURPA set forth in 18 C.F.R. 292.201 et
S In order to meet the criteria for a qualifying facil under PURPA a
cogeneration facility must meet the efficie standard promulgated by the Federal
Energy Regulatory Commissi The efficiency standard for a qualified gas fired
topping-cy cogeneration facility is:
(2 Efficiency standard. (i) For any topping-cycle cogeneration facility for
which any of the energy input is natural gas or oil, and the installation of
which begain on or after March 13, 1980, the useful power output of the facility
plus one-half! the useful thermal energy output, duringi any calendar ycar must:
(A) Subject to paragraph (a)(2)(~)(B) of this section be no less than 42.5
percent of 4%..he total energy input of natural gas and oil to the facility; or
(B) If the useful thermal energy output is less than 15 percent of the total
energy output of the facility, be no less thain 45 percent of the total energy
input of natural gas and oil to the facility.
18 C.F.R. 5 292.205(a)(2)(i)
purposes of the efficiency standard, the "useful power output,-,
"Useful thermal energy," "total energy input" aare defined as follows:
(g) "Useful power output" of a cogeneration facility means the electric or
mechanical energy made available for use, exclusive of any such energy used in
the power production process;
(h) "useful. thermal energy output" of a topping-cycle cogeneration
facility means the thermal energy made available for use in any industridl or
commercial use in any industrial or commercial use, or used in. any heating or
cooling application;
(i) "total energy output- of a topping-cycle cogeneration facility is the
sum of the useful power output and useful thermal energy output; and
(j) "total energy input" means the total energy of all forms supplied from
external sources;
18 C. F.R. S 292.202f (g)(h)(i)(j).
Stated simply, the electric energy made, available use plus one-half of the
thermal energy made available for must either (a) equal or exceed 42 1/2% of the
total energy input of the facility; or equal or exceed 45% of the total energy
input of the facility if the facility's thermal energy output less than 15%
of the facility's total energy output. As shown above, a facility's total energy
output is the thermal energy outpuot plus the electric energy output.
The efficiency standard effectively imposes minimum on the "useful thermal
energy output" from a cogeneration plant. Specifically, the useful thermal
output for the Georgia Pacific Plant must allow the cogeneration plant to
qualify under one of the alternative efficiency standards established in 18
C.F.R.292.205(a)(2)(i) quoted above. The cogeneration plant in question will
have a generation capacity of 85,000 KW and W~ operate 8,000 hours per year. An
electric plant of that s requires a minimum of 168,000 MMBTU be "made available
for use in any industrial or commercial use". As part of qualifying under PURPA,
Bonneville must therefore certify that efficiency standard is met and that
foregoing heat use is used at a minimum.
The actual calculation for purposes of qualifying un4er the PURPA efficiency
standard, for the Georgia Pacific wallboL plant in Las Vegas, Nevada, is set
forth on the attached Exhibit A.
252;070689B
VAL R. ANTCZAK
FIRST AMENDMENT TO HEAT
PURCHASE AGREEMENT
This First Amendment to Heat Purchase Agreement the "Heat Purchase Agreement" is
made and entered into this IS +,% day of August, 1990, by and between BONNEVILLE
NEVADA CORPORATION, a Nevada corporation ("Bonneville Nevada" and
GEORGIA-PACIFIC CORPORATION, a Georgia corporation (11G-P11). G-P and Bonneville
Nevada are referred to collectively herein as "Parties
RECITALS:
A Bonneville Nevada and G-P have entered into a Heat Purchase Agreement dated
September 12, 1989 whereby Bonneville Nevada has agreed to supply to G-P and G-P
has agreed to purchase from Bonneville Nevada heat (the "Thermal Output"
produced by an approximately 85 megawatt cogeneration facility (the
"Facility" for use in G-Pls existing gypsum plant located in Clark County,
Nevada the "Plant" B. The Heat Purchase Agreement forms Schedule I of an Amended
and Restated Business Agreement dated September 12, 1989, between the Parties
and Bonneville Pacific Corporation relating to the Facility and the Plant.
C. Bonneville Nevada and G-P desire to amend the Heat Purchase Agreement in the
particulars set forth below.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein
contained, and for other good and valuable consideration, the receipt and
adequacy of which are hereby acknowledged, the Parties hereto agree as follows:
AGREEMENT
1. Paragraph 3(b) of the Heat Purchase Agreement shall be amended to read in its
entirety as follows:
Integration of Facility with Plant. Bonneville Nevada shall design and
construct the Facility in such a manner so as provide for full integration of
the Facility with the Plant without significant or adverse impacts on Plant
operations. The Parties agree to cooperate in scheduling and implementing such
integration procedures based upon plans, designs, sepcifications for the
Facility, and an integration plan approved in advance by both parties.
Bonneville Nevada agrees to pay One Million Five Hundred Thousand Dollars
($1,500,000) for modification of the kiln system and pay One Million Four
Hundred Eighty Seven Thousand Dollars ($1,487,000) for modification of the mill
system, for a total of Two Million Nin Hundred Eighty-Seven Thousand Dollars
$(2,987,000). This sum shall be paid as follows:
(i The first payment shall be made on or before August 17, 1990 in the
amount of Two Hundred Thousand Dollars ($200,000)
(ii) The second payment shall be made on or before earlier of 1 two
business days following closing of Bonneville Nevada's construction financing
for the Facility, or December 31, 1990. The amount shall be One Hundred
FortyThousand Two Hundred Thirty-Eight and 09/100 Dollars ($142,238.09) times
the number of full or partial calendar months beginning with June, 1990 and
ending with the month of payment, minus Two Hundred Thousand Dollars ($200,000).
(For example, if construction financing is closed on October 16, 1990,
Bonneville Nevada shall make a second payment to G-P on or before October 18,
1990 in the amount of Five Hundred Eleven Thousand One Hundred Ninety and
45/100.Dollars ($511,190.45).
In the event that Bonneville Nevada has not closed financing by December
31, 1990, then, at Bonneville Nevada's option, payments may begin as described
below or they may be delayed until the close of financing or June 30, 1991,
whichever is earlier. In the event of a delay, Bonneville Nevada will increase
the total amount payable to G-P by the change in the consumer price index
(11CPI11 from June 1990 up to and including the month that payments commence As
used herein, 11CPI11 shall mean and refer to the Consumer Price Index for all
Urban Consumers, U.S. City Average for all Items, published by the Department of
Labor. For example, should closing occur January 15, 1991, then the payment due
on January 17, 1991 will be One Hundred Forty-Two Thousand Two Hundred
Eighty-Three and 09/100 Dollars ($142,283.09) times the months from June through
January 8 months). The remaining monthly payments shall be increased to account
for the total change in the installation price that has occurred assuming the
CPI increased five percent 5%) from June 1990 through the end of January 1991.
Then the remaining payments are computed as follows:
Original Costs = 2,987,000.00
Prelim Engineering Pmt. = - 200,000.00
------------
2,787,000.00
Change in Cost = $2,787,000.00 X 1.05
= 2,926,350
Payment on January 17
$142,238.09 X 8 = $1,137,904.72
200,000.00
-------------
$ 937,904.72
Remaining monthly $2,926,350.00
- 937,904.72
-------------
$1,988,455.28
13
$ 152,957.33
(iii) The remaining payments shall be'made on or before last day of each
month, beginning the calendar month after second payment is made and ending with
a payment on or before February 29, 1992. The amount of the remaining payments
shall be One Hundred Forty-Two Thousand Two Hundred Thirty Eight and 09/100
Dollars ($142,238.09) per month, unless that amount is modified pursuant to
Paragraph 3(b)(ii) above.
Bonneville Nevada shall also pay G-P the sum of Five Hundred Thousand
Dollars ($500,000) as the agreed reimbursement anticipated costs associated with
construction downtime and start-up losses. This payment shall be made within
thirty (30 days after Bonneville Nevada's first delivery of Thermal Output to
G-P Such payment shall constitute Bonneville Nevada's sole obligation relating
to G-PIs costs of Equipment modification G-PIs costs associated with
construction downtime and start-up losses. All other costs incurred in
connection with full integration of the Facility with the Equipment, if shall be
borne by G-P, G-P agrees that it will not make commitments for equipment
purchase required for the facility modification prior to receipt of the second
payment referenced above, unless it receives prior written approval from
Bonneville Nevada. All modifications to the Plant's kiln and mill systems shall
be completed within twenty-one months after G-Pls receipt of the second payment,
provided that Bonneville Nevada makes all payments required under this
subparagraph on a timely basis.
2. All other provisions of the Heat Purchase Agreement shall remain as
originally set forth.
IN WITNESS WHEREOF, the Parties hereto have caused Amendment to be executed as
of the day and year first above written.
BONNEVILLE NEVADA CORPORATION
By:
By:
Its: Sehior Vice President
SECOND AMENDMENT TO HEAT PURCHASE AGREEMENT
This Second Amendment to the Heat Purchase Agreement (this "Amendment") is
made and entered into this 14th day of January, 1991, by and between Bonneville
Nevada COrporation, a Nevada corporation, (Bonneville Nevada") and Georgia-
Pacific Corporation, a Georgia corportation ("G-P"). Bonneville nEvada and G-P
are referred to collectively herein as "Parties". Capitalized terms not defined
herein shall have the meanings given them in the Heat Purchase Agreemnt (as
defined hereinbelow).
Recitals
A. Bonneville Nevada and G-P have entered into that certain Heat Purchase
Agreemet dated September 12, 1989, as amended August 15, 1990 (the "Heat
Purchase Agreement").
B. The Parties desire to amend the Heat Purchase Agreement in the particulars
set forth below:
Agreement
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein
contained, and forother good and valuable consideration, the receipt and
adequacy of which are hereby acknowledged, the Parties hereto agree as follows:
`. Paragraph 10 of the Heat Purchase Agreement shall be amended in its
entirety to read as follows:
10. Assignment. In the envent that Bonneville Nevada, G-P or any susequent
owner transfers all or a portion of its ownership of the Facility or Plant, the
transferring Party shall require the acquiring party to assume all of the
transferring Party's rights and responsibilities set out in this Agreement or
any agreement referred to herein or contimplated hereby. In any event, unless
otherwise agreed in the document assigning the obligation, the transferring
Party shall remain liable to the other Party for allobligatins arising out of
this Agreement or any agreement referred to herein or contimeplated hereby,
which obligations arise prior to the date of the assignment. Notwithstanding
the foregoing neither this Agreement nor any agreement refereed to herein or
contiemplated hereby shall be assigned by any Party hereto unless and until
prior written approval is received from the other Party, which approval will not
be unreasonably withheld. It is understood and agreed that notwithstanding the
foregoing, in the envent it is necessary to assign any rights or interests
hereunder to any financically stable and reputable lenders or lesssors providing
construction or premanent financiang or leveraged leasing for the Facility or
the Plant, the Parties hereto shall approve and do hereby approve such
assignments.
All other provisions of the Heat Purchase Agreement shall remain as
originally set forth.
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be
executed as of the day and year first above written.
BONNEVILLE NEVADA CORPORATION
BY: (s)--------------------------
Its: President
GEORGIA PACIFIC CORPORATION
By: (s)--------------------------
It's Vice President
Gypsum and Roofing Division
tfp/a/o2977
EXHIBIT A
a. PURPA calculation for Georgia Pacific wallboard plant in Las Vegas, Nevada.
P = (85,000 KW) (3,413 BTU/KWH) (8,000 hra/yr)
= 2.32 x 10 12 BTU/yr
T = 1.68 x 10 11 BTU/yr (per heat purchase agreement)
N = (667.0 x 10 6 BTU/hr) (8,000 hrs/yr)
= 5.336 x 10 12 BTU/yr
b. Efficiency Standard
P + 0.5T = (2.32 X 10 12) + 0.5 (1.68 X 10 11)
______________________________________________
N 5.336 x 10 12
= .4505 or 45.05%
252:070689A
THIRD AMENDMENT TO HEAT PURCHASE AGREEMENT
This Third Amendment to the Heat Purchase Agreement (this "Amendment") is made
and entered into this 3,6,- day of July, 1991, by and between Nevada
Cogeneration Associates 11, a Utah general partnership ("NCA11") and
Georgia-Pacific Corporation, a Georgia corporation ("G-P"). NCAj1 and G-P are
referred to collectively herein as "parties". Capitalized terms not defined
herein shall have the meanings given them in the Heat Purchase Agreement (as
defined hereinbelow).
Recitals
A. Bonneville Nevada Corporation and G-P entered into that certain Heat Purchase
Agreement dated September 12, 1989, as amended August 15, 1990 and January 14,
1991, and as assigned by Bonneville Nevada Corporation to Nevada Cogeneration
Associates #1 January 29, 1991 (the "Heat Purchase Agreement").
B. The Parties desire to amend the Heat Purchase Agreement in the particulars
set forth below.
Agreement
NOW, THEREFORE, in consideration of the mutual covenants and agreements
herein contained, and for other good and valuable consideration, the receipt and
adequacy of which are hereby acknowledged, the Parties hereto agree as follows:
1. Section 1 of the Heat Purchase Agreement shall be amended and
restated in its entirety to read as follows:
Characteristics and Thermal requirements of the Ecruipment. The Plant as
currently designed and operated includes one 2-zone kiln and four gypsum
calcining mills (the "Equipment"). The Plant I s current operating statistics as
of September 12, 1989 were approximately as follows:
(a) Line Speeds: 130 fpm for 1/2 inch board and 100 fpm for 5/8 inch
board;
(b) Evaporative Estimate: 800 pounds every 2 minutes for a total of
24,000 pph;
(c) Normal Control Temperatures: Kiln Zone 1 600 degrees F; Kiln Zone
2 - 450 degrees F;
(d) Total Present Gas Usage: Approximately 1,100 MCF per day (all natural gas
values in this Agreement assume 1,000 BTU/CF) of which approximately 60 percent
goes to the gypsum kilns and approximately 40 percent goes to the gypsum mills;
and
(e) Plant operating Schedule: 6 2/3 days per week, 24 hours per day.
Based upon the foregoing characteristics and anticipated future Plant expansion,
Bonneville Nevada will design and construct the Facility to provide a maximum
total Thermal Output to the Delivery Point(s) in the following amounts:
Combustion Turbine
Season Exhaust Gas Flow, lbs/hr
Summer 380,000
Winter 400,000
Measurement of the above exhaust gas flows shall be based upon the Facility
instrumentation for daily operational purposes, but not for billing purposes.
Summer shall be defined as the months of May, June, July, August and September.
Winter shall be defined as the months of October, November, December, January,
February, March and April.
The last paragraph of section 2, Characteristics and Thermal Output of the
Facility, shall be amended and restated in its entirety to read as follows:
Bonneville Nevada shall at all times maintain a temperature range between 920
and 970 degrees Fahrenheit for the Thermal Output at the Delivery Point(s), and
a reasonably constant pressure of between 8 and 10 inches of water. During
normal operation of the Facility and the Plant, the maximum pressure fluctuation
within that range shall be +/1/2 inch of water. In the event of an upset
condition in the process, Bonneville Nevada shall make every effort to
expeditiously recover to the pressure condition as maintained prior to the
occurrence of the upset condition. The Thermal Output shall not contain unburned
hydrocarbons or any other compounds in sufficient quantities so as to cause any
staining on the surface of the wallboard as currently produced at the Plant.
3. Subparagraph 3 (b) (ii of the Heat Purchase Agreement shall be amended
and restated to read as follows:
(ii) The second payment shall be made on or before the earlier of (1) two
business days following closing of Bonneville Nevada's construction financing
for the Facility, or (2) December 31, 1990. The amount shall be One Hundred
Forty-Two Thousand Two Hundred Thirty Eight and 09/100 Dollars ($142,238.09)
times the number of full or partial calendar months beginning with June, 1990
and ending with the month of payment, minus Two Hundred Thousand Dollars
($200,000). (For example, if construction financing is closed on October 16,
1990, Bonneville Nevada shall make a second payment to G-P on or before October
18, 1990 in the amount of Five Hundred Eleven Thousand One Hundred Ninety and
45/100 Dollars ($511,190.45)). In the event that Bonneville Nevada has not
closed financing by December 31, 1990, then, at Bonneville Nevada's option,
payments may begin as described below or they may be delayed until the close of
financing or August 1, whichever is earlier. In the event of a delay, Bonneville
Nevada will increase the total amount payable to G-P by the change in the
consumer price index ("CPI") from June 1990 up to and including the month that
payments commence. As used herein, "CPI" shall mean and refer to the Consumer
Price Index for all Urban Consumers, U.S. City Average for all Items, published
by the Bureau of Labor Statistics, U.S. Department of Labor. For example, should
closing occur January 15, 1991, then the payment due on January 17, 1991 will be
One Hundred Forty-Two Thousand Two Hundred Eighty-Three and 09/100 Dollars
($142,283.09) times the months from June through January (8 months) . The
remaining monthly payments shall be increased to account for the total change in
the installation price that has occurred assuming the CPI increased f ive
percent (5%) from June 1990 through the end of January 1991. Then the remaining
payments are computed as follows:
Original Cost = 2,987,000.00
Prelim Engineering Pmt - 200,000.00
------------
2,787,000.00
Change in Cost 2,787,000.00 x 10.05
2,926,350
Payment on January 17
$142,238.09 X 8 = $1,137,904.72
- 200,000.00
____________
$ 937,904.72
Remaining monthly
payments (13) 2,926,350.00
- 937,904.72
------------
1,988,445.28
13
= $ 152,957.33
4. Subparagraph 3(c) of the Heat Purchase Agreement shall be amended and
restated to read as follows:
(c) Point(sl of Delivery and Maximum Thermal Reauirements. The Thermal Output of
the Facility shall be delivered four points reasonably designated by G-P (the
"Delivery Points") . The Delivery Points shall be designated and described by
G-P and shall be shown as a part of Revised Exhibit "B", attached hereto and by
this reference made a part hereof.
5. Subparagraph 3 (e) of the Heat Purchase Agreement shall be amended and
restated in its entirety to read as follows:
(e) Purchase Price. The purchase price for the Thermal Output shall be
related to the level of production of gypsum products at the Plant. The "Primary
Production Level" as hereinafter used shall refer to that average amount of
Plant production that would be produced when the Equipment, utilizing only
natural gas as a heat source, consumes 1900 MCF/day. The Thermal Output utilized
by the Plant for production up to the Primary Production Level shall have a
purchase price equal to sixty-f ive percent (65%) of the energy costs of
operating the Equipment on natural gas through the use of the Plant's existing
System (the "Discounted Purchase Price") . The Thermal Output utilized for that
increment of Plant production in excess of the Primary Production Level shall
have a purchase price equal to one hundred percent (100%) of the energy costs of
operating the Equipment on natural gas through the Plant's existing System (the
"Non-Discounted Purchase Price"). The basis for determining natural gas costs
shall be the lower of the following, as of the first day of the calendar month
during which payment is made: (1) The "Indexed Gas Cost"I as defined in the
following sentence or (2) the Facility's average delivered price of gas during
the preceding month under contracts similar to those available to industrial gas
users in North Las Vegas on Southwest Gas's Apex Lateral. The Indexed Gas Cost
shall be determined by taking the sum of (i) the most currently available McGraw
Hill Publication "Inside FERC's Gas Marketing Report" index price for natural
gas delivered into El Paso Pipeline, New Mexico (San Juan Basin), plus (ii) the
El Paso and Southwest Gas tariff rates for interruptible service from the El
Paso connection to the Plant, including all required compression,
transportation, processing, delivery, ACA, GRI, and/or other applicable charges.
Bonneville Nevada shall notify G-P within ten (10) days after the beginning of
each calendar month of its average delivered price of its contract gas, as
defined above, during the preceding month. In the event that the publication
ceases to maintain the subject index, or that the index does not reflect
available market price, the parties will substitute the most appropriate
thencurrently available index.
In the event that an available alternative energy source could be utilized to
meet the Thermal Requirements of the Equipment at a cost less than that of
natural gas, the Discounted Purchase Price and the Non-Discounted Purchase Price
of the Thermal Output shall be adjusted for the energy costs of this alternative
energy source. The cost of any alternative energy source shall include the
estimated capital cost of installing and permitting the capability to utilize
that energy source, with such capital cost amortized on a straight line basis
over fifteen years. Both the discounted Purchase Price and the Non-Discounted
Purchase Price shall be adjusted from time to time, but not more frequently than
quarterly, to continuously reflect a net thirty-five percent (35%) savings by
G-P for the Thermal output utilized in production up to the Primary Production
Level over cost for energy displaced which G-P would otherwise pay to operate
the Equipment.
6. A new subparagraph 3(1) shall be added to the Heat Purchase Agreement,
which shall read as follows:
(i) Plant Modification. Bonneville Nevada shall have the right to review and
approve (such approval shall not be unreasonably withheld) all plans and
specifications for modification or expansion of the Plant that relate to or
potentially affect the ability of the Plant to take the Thermal Output.
Notwithstanding the foregoing, Bonneville Nevada shall also have the right,
throughout the term of this Agreement, to obtain, collect and/or receive Plant
operating data to ensure that the Plant is utilizing the Thermal Output
according to the terms of this Agreement.
Subparagraph 4(b) shall be amended and restated in read as follows:
(b) minimum Thermal Usage. Bonneville Nevada represents that in order to
keep the Facility qualified under PURPA, the Plant must use a minimum of 168,
000 MMBTUs during each calendar year (the "Minimum Thermal Usage") . The Minimum
Thermal Usage shall be prorated f or the portion of the calendar years during
which the Facility begins and ceases operation. In the event that G-P elects to
expand its Plant operations, the Minimum Thermal Usage requirement shall
increase by a percentage equal to the percentage of increased MCF per day used
by the Plant over the 1,100 MCF per day presently used by the Plant. For
example, in the event the Plant expands and uses 1,500 MCF per day, such use
shall constitute a 36% increase over the 1,100 MCF per day specified in section
1 hereof. Pursuant to the foregoing, the Minimum Thermal Usage will likewise
increase by 36%, and in this example would constitute 228,480 MMBTUs. G-P agrees
that it will meet or exceed the Minimum Thermal Usage requirement specified
herein, subject to the provisions of this Agreement, through the consumption of
BTUs used in (1) the operation of the Equipment, (2) the chilling of water by
Bonneville Nevada for the amount of chilled water utilized at the Plant, and (3)
any other use of heat from the Facility by the Plant. In the event that G-P
forecasts that it will not satisfy the Minimum Thermal Usage for a calendar
year, it shall give the notice hereinafter specified, provided that the
forecasted inability to satisfy the Minimum Thermal Usage is not caused by a
Force Majeure Condition as described in Paragraph 7 of this Agreement or the
inability of Bonneville Nevada to provide Thermal Output to the Plant. In no
event shall the Maximum Thermal Usage be greater than 290,000 MMBTUs per
calendar year.
S. The following shall be added to the end of subparagraph 4(c, of the Heat
Purchase Agreement:
Bonneville Nevada shall have the right to obtain and review copies of all
computations done, or caused to be done by G-P associated with determining the
break even point. Bonneville Nevada shall also have the right to request an
audit by an independent certified public accountant or independent certified
public accounting firm of the computations done, or caused to be done by G-P
associated with determining the break event point. Bonneville Nevada shall bear
the entire cost of the audit, unless the audit properly determines that G-P's
determination of the break event point was in error by 5% or more in G-P's
favor, then G-P shall bear the entire cost of the audit.
The following shall be added to the end of subparagraph 4(d) of the Heat
Purchase Agreement:
The lease shall be a net lease to Bonneville Nevada, and shall include
standard terms of commercial leases. Any dispute over lease terms which cannot
be resolved amicably between the parties shall be submitted to arbitration
pursuant to section 14 hereof.
10. A new section 14 shall be added to the Heat Purchase Agreement, which
shall read as follows:
14. Arbitration. Any controversy, dispute or claim arising out of or relating to
this Agreement, or the breach thereof, which cannot be resolved amicably by the
parties shall be settled by arbitration in accordance with the Rules of the
American Arbitration Association, except that whether or not arbitration has
been requested or is in process, nothing herein shall prevent any party from
pursuing equitable remedies, including interim relief, in any court of competent
jurisdiction, and except as may be unanimously otherwise agreed by the parties.
(a) The place of arbitration shall be Las Vegas, Nevada, unless in any
particular case the parties agree upon a different venue. There shall be three
(3) arbitrators of all disputes arising under this Agreement. All of the three
arbitrators shall be chosen by the American Arbitration Association in
accordance with its rules, interpreted to give effect to the provisions of this
Agreement.
(b) The parties will proceed with the arbitration expeditiously and will
conclude all arbitration proceedings in order that a decision may be rendered
within 180 days from the service of the demand for arbitration by the initiating
party, unless the party requesting arbitration also requests immediate
arbitration, in which case the arbitrators shall use their best efforts to
render their decision within 60 days after the appointment. Subject to the
foregoing time limitations in connection with the arbitration, the parties shall
be afforded reasonable opportunity for deposition and document discovery,
subject to limitations determined by the arbitrators. The dispute shall be
resolved by majority vote of the three arbitrators, if three are acting. Such
decision shall be expressed in writing, including the reasons for such decision
in reasonable detail.
(c) The award of the arbitrators shall be final and binding upon the parties,
and judgment thereon may be entered in any court having jurisdiction thereof. In
the event that the arbitrators determine by majority vote that the claim or
defense of any party involved in the arbitration was frivolous (i.e., "without
justifiable merit"), the arbitrators may by majority vote require that the party
at fault pay or reimburse the other party for any or all of the following: (1)
all fees and expenses of. the arbitrators, (2) the reasonable attorneys' fees of
such other party, and (3) any other reasonable outof-pocket expenses incurred by
such other party in connection with the arbitration proceeding. The arbitrators
shall determine and decide all issues that arise in carrying out the purposes
and intent of the foregoing unless specific provision is made herein for
resolving such issues.
The first sentence of the second paragraph of Exhibit 11C11 to the Heat
Purchase Agreement shall be amended to read as follows:
For each billing period, the amount of energy utilized by the Equipment shall be
computed under the following formula:
Mill Heat Usage = Mill Energy Factor x tons of Stucco Produced
Kiln Heat Usage = Kiln Energy Factor x Pounds of Water Evaporated.
Billings for energy may then be based upon the following:
(Mill Heat Usage + Kiln Heat usage) x Gas Costs Per BTU (as determined by
Paragraph 3(e).
All other provisions of the Heat Purchase Agreement shall remain as
previously set forth.
13. IN WITNESS WHEREOF, the parties have caused this
Amendment to be executed as of the day and year first above written.
NEVADA COGENERATION ASSOCIATES 11
By: (s)------------------------------
Harry,#. Hall,- Executive Director
GEORGIA-PACIFIC CORPORATION
By: (s)-----------------------------
Its Vice President
EXHIBIT 21.1
Subsidiaries of Registrant
1. Bonneville Fuels Corporation
a. Bonneville Fuels Marketing Corporation
b. Bonneville Fuels Operating Corporation
c. Bonneville Fuels Management Corporation
d. Colorado Gathering Corporation
2. Bonneville Pacific Services Company, Inc.
a. Cogeneracion de Navojoa S.A. de C.V. (CONAV)
b. Proveedora de Energia Servicios y Conexos, S. de R.L. de C. V. (PESCO)
3. Bonneville Nevada Corporation
4. Bonneville Las Vegas Corporation
5. Nevada Cogeneration Associates #1
6. Nevada Cogeneration Associates #3
7. Bonneville McKenzie Energy Corporation
NEVADA COGENERATION ASSOCIATES #1
FINANCIAL STATEMENTS
AS OF DECEMBER 31, 1997 AND 1996
TOGETHER WITH AUDITORS' REPORT
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Management Committee of
Nevada Cogeneration Associates #1:
We have audited the accompanying balance sheets of NEVADA COGENERATION
ASSOCIATES #1 (a Utah general partnership) as of December 31, 1997 and 1996, and
the related statements of income and partners' equity and cash flows for the
years then ended. These financial statements are the responsibility of the
Partnership'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, the financial statements referred to above present fairly, in
all material respects, the financial position of Nevada Cogeneration Associates
#1 as of December 31, 1997 and 1996, and the results of its operations and its
cash flows for the years then ended in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN & COMPANY
Los Angeles, California
February 27, 1998
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
BALANCE SHEETS - DECEMBER 31, 1997 AND 1996
1997 1996
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 5,416,442 $ 5,821,900
Receivables:
Nevada Power Company 3,632,944 3,414,709
Other (amounts include $153,417 and
$48,348 receivable from related parties
in 1997 and 1996, respectively) 171,100 141,808
Inventories 1,018,796 1,084,093
Prepaid expenses 376,900 78,000
Current portion of restricted cash 798,000 927,404
------------- ------------
Total current assets 11,414,182 11,467,914
------------- ------------
OPERATING FACILITY AND EQUIPMENT,
at cost, net of accumulated
depreciation of $18,560,822 and
$15,290,009 in 1997 and 1996,
respectively 82,652,388 86,053,302
------------- ------------
OTHER ASSETS:
Deferred financing costs, net of
accumulated amortization of $421,795
and $335,388 in 1997 and 1996,
respectively 1,603,434 1,689,841
Restricted cash,
net of current portion 8,483,222 8,119,520
------------- -------------
Total other assets 10,086,656 9,809,361
------------- -------------
$104,153,226 $107,330,577
============= =============
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
BALANCE SHEETS - DECEMBER 31, 1997 AND 1996
LIABILITIES AND PARTNERS' EQUITY
1997 1996
CURRENT LIABILITIES:
Project financing loan payable $ 4,495,786 $ 3,578,280
Current portion of major maintenance
accrual 798,000 843,051
Payables:
Texaco Inc. and subsidiaries 1,231,534 1,135,747
Trade and other (amounts include
$282,431 and $311,483 payable to
related parties in 1997 and 1996,
respectively) 1,680,586 1,568,667
Accrued liabilities 409,531 387,491
------------ ------------
Total current liabilities 8,615,437 7,513,236
------------ ------------
PROJECT FINANCING LOAN PAYABLE, net
of current portion 46,367,601 50,863,386
BONDS PAYABLE 27,400,000 27,400,000
COMMITMENTS AND CONTINGENCIES (Note 7)
MAJOR MAINTENANCE ACCRUAL, net of current
portion 2,338,333 3,225,659
----------- -------------
Total liabilities 84,721,371 89,002,281
------------ -------------
PARTNERS' EQUITY:
Texaco Clark County Cogeneration
Company 12,627,350 11,909,571
Bonneville Nevada Corporation 6,804,505 6,418,725
------------- ------------
Total partners' equity 19,431,855 18,328,296
------------- ------------
$104,153,226 $107,330,577
============= ============
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
STATEMENTS OF INCOME AND PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1996
1997 1996
REVENUES:
Sales of energy to Nevada Power
Company $44,018,349 $43,283,499
Sales of heat to Georgia-Pacific
Corporation 839,273 596,194
Interest and other income 826,534 1,713,702
------------ ------------
Total revenues 45,684,156 45,593,395
------------ ------------
COSTS AND EXPENSES:
Plant and other operating expenses 26,193,641 26,356,012
Depreciation and amortization 3,482,077 3,600,671
General and administrative expenses 1,677,147 2,176,360
Interest expense 6,187,432 6,702,212
Asset impairment expense 340,300 -
------------- ------------
Total costs and expenses 37,880,597 38,835,255
------------ ------------
NET INCOME $ 7,803,559 $ 6,758,140
------------ ------------
PARTNERS' EQUITY AT BEGINNING OF YEAR $18,328,296 $21,890,156
NET INCOME 7,803,559 6,758,140
DISTRIBUTION TO PARTNERS (6,700,000) (10,320,000)
------------ ------------
PARTNERS' EQUITY AT END OF YEAR $19,431,855 $18,328,296
------------ ------------
The accompanying notes are an integral part of these financial statements
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997 and 1996
1997 1996
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 7,803,559 $ 6,758,140
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 3,482,077 3,600,671
Asset impairment expense 340,300 -
Changes in operating assets and liabilities:
(Increase) decrease in receivables (247,527) 289,840
(Increase) decrease in prepaids (298,900) 83,790
Decrease in inventories 65,297 12,996
(Decrease) increase in major
maintenance accrual (932,375) 627,966
Increase (decrease) in payables 207,706 (76,697)
Increase (decrease) in accrued liabilities 22,040 (348,718)
------------- -------------
Net cash provided by operating activity 10,442,177 10,947,988
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (454,181) (55,011)
Proceeds from refund of sales tax
relating to operating facility
and equipment 119,124 -
------------- -------------
Net cash used in investing activities (335,057) (55,011)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners (6,700,000) (10,320,000)
Proceeds from restricted cash accounts 1,745,606 6,282,698
Deposits into restricted cash accounts (1,979,905) (2,466,186)
Payments for deferred sales tax payable - (474,561)
Payments on project financing (3,578,279) (3,027,775)
------------- -------------
Net cash used in financing activities (10,512,578) (10,005,824)
------------- -------------
NET (DECREASE) INCREASE IN CASH
AND CASH EQUIVALENTS (405,458) 887,153
CASH AND CASH EQUIVALENTS,
at beginning of year 5,821,900 4,934,747
------------- -------------
CASH AND CASH EQUIVALENTS,
at end of year $ 5,416,442 $5,821,900
============= =============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for
interest $ 6,228,487 $6,720,590
============= =============
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1997
1. General
Nevada Cogeneration Associates #1 (the Partnership) is a general partnership
between Texaco Clark County Cogeneration Company (TCCCC), a wholly-owned
subsidiary of Texaco Inc. (Texaco), and Bonneville Nevada Corporation (BNC), a
wholly-owned subsidiary of Bonneville Pacific Corporation (BPC). The Partnership
was organized under Utah law on October 8, 1990. The Partnership was organized
to design, construct, own and operate a cogeneration facility (the Facility)
located in Clark County, Nevada for the purpose of selling electric energy to
Nevada Power Company (NPC) for resale to its customers and selling thermal
energy to Georgia-Pacific Corporation (Georgia- Pacific) for use in its
wallboard facility.
The partners share equally in the allocations of income (loss), depreciation
expenses and other tax benefits from operations of the Partnership. In
accordance with the general partnership agreement, BNC initially received a 66-
2/3 percent and TCCCC a 33-1/3 percent disproportionate share of net cash
distributions until such time as net cash distributions equaled approximately
$18,876,000 (September, 1997) at which time BNC's and TCCCC's share of net cash
distributions changed to 50 percent. The Partnership shall terminate, unless
terminated at an earlier date pursuant to the general partnership agreement, on
the latter of April 30, 2023, or the date the Partnership elects to cease
operations.
The Facility consists of three combustion turbine generators which exhaust heat
into three heat recovery steam generators, producing electricity, process heat
and steam sequentially using one fuel source. Additionally, in a combined cycle
facility, electricity is produced by a condensing steam turbine. The Facility is
designed to support the name plate production of 85 megawatts of electric energy
and 275,000 pounds per hour of process heat. Commercial operations commenced on
June 18, 1992.
2. Summary of Significant Accounting Policies
a. Operating Facility and Equipment
All costs (including interest and field overhead expenses) incurred
during the construction and the precommission phase of the Facility were
capitalized as part of the cost of the Facility. Revenue earned during the
precommission phase was offset against the costs of the Facility. The Facility
and related equipment are being depreciated on a straight-line basis over 30
years, the estimated useful life of the Facility and the life of the Power
Purchase Agreement with Nevada Power Company.
<PAGE>
b. Deferred Financing Costs
All legal and financing fees associated with the Construction Loan, Term
Loan and Reimbursement Agreement (the Agreement) (see Note 3) and the Bonds
Payable (see Note 4) were deferred and are being amortized over the respective
term of the financing.
c. Major Maintenance Accrual
Each of the Facility's gas turbines will require a hot section replacement and a
major overhaul approximately every 25,000 and 50,000 operating hours,
respectively. Expenses for these events are accrued for on a straight-line basis
over the expected operating-hour interval between each like maintenance event.
Expenditures for minor maintenance, repairs and renewals are charged to expense
as incurred. Expenditures for additions and improvements are capitalized.
The accruals for major repair and maintenance events are based on management's
estimates of what these events will cost at the time the events occur. Due to
fluctuations in the extent of repairs, prices and changes in the timing of the
scheduled events, the estimated costs of these events can differ from actual
costs incurred.
d. Statements of Cash Flows
For purposes of reporting cash flows, the Partnership considers
short-term investments with an original maturity of three months or less, to be
cash equivalents.
e. Fair Value of Financial Instruments
The carrying amount of the short-term investments approximates fair
value due to the short maturity of those instruments. Based on the borrowing
rates currently available to the Partnership for long-term debt with similar
terms and maturities as the project financing loan payable and bonds payable,
the carrying amounts of the project financing loan payable and bonds payable
approximate fair value. Taking into consideration the prevailing interest rates
at December 31, 1997 and the Partnership's credit worthiness, the Partnership
would have had to pay approximately $3,970,940 to buy-out the remaining portion
of the interest rate swap agreements (See Note 3).
f. Pervasiveness of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
<PAGE>
The Partnership's results of operations for any particular year may be impacted
by fluctuations in the price of natural gas.
g. Restricted Cash Accounts
The Partnership is required by the Agreement to maintain a debt service reserve
account. The funds in this restricted account are maintained until such time
that the Agreement is fully satisfied. These funds may be used by the
administrative agent of the Agreement to pay fees, costs, principal, and
interest associated with the Agreement. The balance in this account was
$5,347,409 and $4,990,090 as of December 31, 1997 and 1996, respectively.
Due to amendments adopted during 1996, the Partnership is no longer required to
maintain a balance in the thermal host restricted reserve account. This account
could become active again under certain circumstances in which the Thermal Host
(Georgia-Pacific) does not purchase sufficient thermal energy, and other
situations, as defined. The account balance was $0 on December 31, 1997 and
1996, respectively.
Another of the restricted cash accounts is designated for major maintenance
events (see c. above). This account is funded in order to reserve sufficient
cash to allow payment of the cost of the major maintenance events, when they
occur. Funds for this account are deposited on a systematic basis for events
occurring within the next 36 months and are used to service the cost of each
event. This account will be maintained for the duration of the Agreement. The
balance in this account at December 31, 1997 and 1996 was, $2,235,811 and
$2,448,193, respectively.
The Partnership also maintains a Selective Catalytic Reduction (SCR) reserve
account with balances of $1,698,002 and $1,608,641 at December 31, 1997 and
1996, respectively.
All restricted cash accounts are required by the Agreement and earn interest at
the current market rate. Upon authorization from certain parties to the
Agreement, funds from any of the above accounts may be used for items other than
their restricted purpose.
3. Project Financing
On April 28, 1993 the Partnership converted their construction financing to
term financing. The financing obtained consisted of term loans of approximately
$64,350,000 and letters of credit issued in support of $27,400,000 of tax exempt
bonds. Amounts outstanding under the Agreement are reduced by quarterly payments
in February, May, August and November, with the final payment due November 2007.
The term loan balance at December 31, 1997 was $50,863,387. The Agreement places
certain restrictions on cash accounts, capital distributions and permitted
investments. The Agreement is secured by substantially all of the assets of the
Partnership.
<PAGE>
The Partnership has entered into six interest rate swap agreements with
commercial banks. Three swaps (amortizing swaps) had an aggregate initial
notional principal amount of $45 million ($31,770,000 at December 31, 1997)
which decreases over the ten-year term of the agreements. These agreements
essentially change the Partnership's interest rate exposure on the notional
amount to a fixed 8.85 percent per annum plus the lenders' margin. The other
three interest rate swap agreements (bullet swaps) have an aggregate notional
principal amount of $15 million which remains constant over their ten-year term.
These swap agreements essentially change the Partnership's interest rate
exposure on the notional amount to a fixed 7.71 percent per annum plus the
lenders' margin.
If the variable rate applicable to the notional amount exceeds the fixed rate
established by the swap agreements, the Partnership could be exposed to the risk
of higher interest costs in the event of non-performance by the commercial
banks. The Partnership does not, however, anticipate non-performance by the
commercial banks.
Amounts outstanding (other than those noted above) bear interest at LIBOR plus a
margin of .875 percent and are paid monthly. The weighted average interest rate,
inclusive of the effect of the swap agreements, on the outstanding loan balance
at December 31, 1997 and 1996 was 7.74 percent and 7.58 percent, respectively.
The future minimum payments on the debt outstanding and the letters of credit
supporting the tax-exempt bonds at December 31, 1997, are as follows:
1998 4,495,786
1999 5,138,041
2000 5,688,546
2001 6,239,050
2002 6,881,304
Thereafter 22,420,660
-------------
$50,863,387
=============
4. Bonds Payable
The Partnership initially obtained tax-exempt bond financing in the amount of
$19,400,000 from Clark County, Nevada in the form of Industrial Development
Revenue Bonds. These Variable Rate Demand Industrial Development Revenue Bonds
are due and payable on November 1, 2020. Interest is currently payable monthly
and the interest rate was 6.26 and 6.16 percent at December 31, 1997 and 1996,
respectively.
<PAGE>
The Partnership obtained additional project bond financing of $8,000,000 on
February 11, 1992, from Clark County Nevada. These Variable Rate Demand
Industrial Development Revenue Bonds are due and payable on November 1, 2021.
Interest is currently payable monthly and the interest rate was 6.26 percent and
6.16 percent at December 31, 1997 and 1996.
5. Related-Party Transactions
a. Gas Sales and Purchase Agreements
The Partnership has long-term agreements for the purchase of fuel gas
(in addition to those described in Note 7) with Texaco Natural Gas Inc. (TNGI),
a wholly owned subsidiary of Texaco and Texaco Exploration & Production Inc.
(TEPI), a wholly owned subsidiary of Texaco.
The maximum daily contract quantities of gas available under the TNGI
and TEPI agreements are 6,250 and 5,250 MMBtu per day, respectively. The
agreements require the Partnership to take delivery of and/or pay for a volume
of gas up to 90 percent of the TNGI agreement quantities and 75 percent of the
TEPI agreement quantities. The Partnership has two and one-half years under the
TNGI agreement and five years under the TEPI agreement to take delivery of any
gas not taken but paid for in any one contract year, as defined in the
agreements.
The initial weighted average price under the TNGI agreement was $2.29
per MMBtu and $2.13 per MMBtu under the TEPI agreement commencing May 1, 1993
until May 1, 2007. The price paid under these agreements is adjusted annually by
the change in the Consumer Price Index (CPI) each May 1. The TNGI agreement has
additional increases, as defined in the agreement, starting May 1, 2007. The
weighted average price as of December 31, 1997 was $2.63 per MMBtu and $2.45 per
MMBtu for TNGI and TEPI, respectively.
The TNGI agreement remains in effect until the latter of December 31,
2011, or twenty years from the commencement date (June 18, 1992), as defined in
the agreement. Under the TNGI agreement, an additional 8,250 MMBtu per day was
replaced with other suppliers' long-term gas contracts (Replacement Contracts).
TNGI will provide up to 8,250 MMBtu per day to the Partnership in the event of
default under the Replacement Contracts. The amounts incurred under the TNGI
agreement were $6,180,013 and $6,290,456 in 1997 and 1996, respectively.
The TEPI agreement remains in effect until the latter of December 31,
2007 or fifteen years from the commencement date (June 18, 1992), as defined in
the agreement. The amounts incurred under the TEPI agreement were $3,162,641 and
$3,340,878 in 1997 and 1996, respectively.
<PAGE>
b. Fuels Management Agreement
The Partnership is party to an agreement with TNGI, whereby TNGI is to procure,
at prices based upon the spot market, and manage all fuel-gas supplies and
transportation for the Partnership (except those fuel- gas supplies procured and
delivered under tariff-gas contracts, those fuel-gas supplied under an excepted
contract and other fuel-gas supplies excluded from this agreement by the mutual
consent of TNGI and TEPI until termination of the agreement.
The agreement will remain in effect until the latter of December 31,
2011, or twenty years from the commercial operations date (June 18, 1992). TNGI
receives a fixed service fee of $0.04 per MMBtu on short-term contracts (one
year or less). TNGI also receives a fixed service fee of $0.04 per MMBtu, which
is adjusted annually by the change in the CPI, each May 1, for the volume of gas
delivered under the Replacement Contracts. TNGI received fixed service fees
under short-term and Replacement Contracts of $191,241 and $216,142 in 1997 and
1996, respectively.
c. Operation and Maintenance Agreement
The Partnership has an agreement with Bonneville Pacific Services, Inc.
(BPSI), a wholly-owned subsidiary of BPC, whereby BPSI performs all operation
and maintenance activities necessary for the production of electrical energy and
process heat. The agreement became effective August 1, 1991, and will remain in
effect for 30 years from the commercial operations date (June 18, 1992), subject
to earlier termination after 10 years from the commercial operations date as
defined in the agreement.
BPSI is paid for all costs incurred in connection with operating and
maintaining the Facility and is paid an annual operating fee of $260,000, which
is adjusted annually by the change in the CPI. BPSI may earn an incentive bonus
which is based upon BPSI achieving certain operating goals, as defined in the
agreement. The costs incurred under this agreement were $1,729,752 and
$1,731,625 in 1997 and 1996, respectively. Incentive bonuses earned were
$333,065 and $412,352 in 1997 and 1996, respectively.
d. Engineering and Administrative and Other Costs
The Partnership, under agreements, pays for certain engineering and
administrative expenses and other costs to Texaco and its subsidiaries. Texaco
may also earn a performance bonus based upon the plant achieving certain
operational goals, as defined in the agreement. The fees incurred under these
agreements totaled $525,159 and $567,128 in 1997 and 1996, respectively.
Performance incentives earned were $333,065 and $412,352 in 1997 and 1996,
respectively.
<PAGE>
6. Income Taxes
Income taxes are not recorded by the Partnership since the net income or loss
allocated to the partners is included in their respective income tax returns.
7. Commitments and Contingencies
a. Power Purchase Agreement
The Partnership has an agreement for long-term power purchases of energy
and capacity by NPC which terminates on April 30, 2023. The Partnership is paid
for energy delivered based upon fixed rates, as defined in the agreement,
adjusted annually at 120 percent of the change in the CPI. NPC also pays the
Partnership for firm capacity based upon fixed rates, as defined in the
agreement, increased annually by two percent.
During 1997 the Partnership negotiated an amendment to the agreement
severely limiting NPC's curtailment rights in exchange for a price discount of
$.25 per megawatt hour. The amendment was signed on October 3, 1997 and is
awaiting Nevada Public Utility Commission approval.
Pursuant to the amended agreement, the Partnership has the right to
release NPC from its purchase obligation for an agreed upon payment per released
megawatt. In 1997, the Partnership received $1,101,320 for released megawatts.
In conjunction with the above the Partnership was able to manage its fuel cost
through non-acceptance or sell to others.
b. Heat Purchase Agreement
The Partnership has an agreement for the long-term sale of process heat
to Georgia-Pacific. The agreement became effective January 29, 1991, and will
terminate on April 30, 2023, or earlier, as defined in the agreement. The
Partnership is paid for process heat delivered at an amount equal to 65 percent
of the energy cost of operating Georgia-Pacific's kiln and gypsum calcining
mills on the lowest alternative energy. Process heat sold under this contract
has been sufficient for the Partnership to meet its annual qualifying facility
status and is expected to be sufficient for the Partnership to meet its annual
qualifying facility requirements in the future.
c. Gas Sales and Purchase Agreements
The Partnership has two long-term agreements for the purchase of fuel gas (other
than those described in Note 5) with unrelated parties. The first of these
agreements remains in effect until the earlier of March 1, 2008, or fifteen
years from the commercial operations date (June 18, 1992).
<PAGE>
The second agreement remains in effect until the latter of December 31, 2007, or
fifteen years from the commercial operations date (June 18, 1992).
The maximum daily contract quantities available under these agreements total
7,000 MMBtu per day. The agreements require the Partnership to take delivery of
and/or pay for a volume of gas up to 75 percent of the average maximum daily
contract quantities available under these agreements. The Partnership has two
years (under the 2,000 MMBtu per day contract) and five years (under the 5,000
MMBtu per day contract) to take delivery of any gas not taken but paid for in
any one contract year, as defined in the agreements.
The Partnership initially paid a fixed price ($2.00 to $2.20 per MMBtu) for the
quantities of fuel gas delivered under these contracts. The price paid on the
5,000 MMBtu per day contract is adjusted annually by the change in the CPI. The
price on the 2,000 MMBtu per day contract will be adjusted by 90 percent of the
change in the CPI, twenty-five months after the start of gas deliveries (June
18, 1992), and annually each May 1 thereafter. The price paid under these
contracts was $2.30 to $2.37 during 1997.
d. Equipment Lease
The Partnership and Nevada Cogeneration Associates #2 jointly entered into an
equipment lease agreement, with an unrelated party, on December 31, 1992. The
agreement requires monthly payments of $48,747 plus sales tax over the ten year
term. The Partnership's share is one-half of the monthly payments.
e. Environmental Matters
As a result of issues brought forth during 1996 regarding SCR, the
Partnership has negotiated with the EPA for the installation of two SCR units.
The schedule calls for the installation to take place by March 1999.
Funds for the installations will come from the SCR reserve account,
current reserves are considered adequate to cover the cost of the installations.
f. Electric Utility Deregulation
In 1997, The Nevada Legislature passed legislation to restructure the
Nevada electric utility industry. The legislation (AB366) calls for competition
to commence by January 1, 2000. The eventual outcome of these activities and
their potential impact, if any, upon the Partnership is not known.
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
FINANCIAL STATEMENTS
AS OF DECEMBER 31, 1998 AND 1997
TOGETHER WITH AUDITORS' REPORT
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Management Committee of
Nevada Cogeneration Associates #1:
We have audited the accompanying balance sheets of NEVADA COGENERATION
ASSOCIATES #1 (a Utah general partnership) as of December 31, 1998 and 1997, and
the related statements of income and partners' equity and cash flows for the
years then ended. These financial statements are the responsibility of the
Partnership'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, the financial statements referred to above present fairly, in
all material respects, the financial position of Nevada Cogeneration Associates
#1 as of December 31, 1998 and 1997, and the results of its operations and its
cash flows for the years then ended in conformity with generally accepted
accounting principles.
Arthur Andersen & Company
Los Angeles, California
February 12, 199
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
BALANCE SHEETS - DECEMBER 31, 1998 AND 1997
1998 1997
ASSETS
CURRENT ASSETS:
Cash and cash equivalents .................. $ 5,300,921 $ 5,416,442
Receivables:
Nevada Power Company ..................... 3,708,360 3,632,944
Other
(amounts include $71,275 and
$153,417 receivable from
related parties in 1998 and
1997, respectively) .................... 161,330 171,100
Inventories .............................. 899,758 1,018,796
Prepaid expenses ......................... -- 376,900
Current portion of
restricted cash .......................... 3,503,948 798,000
----------- -----------
Total current assets ....................... 13,574,317 11,414,182
----------- -----------
OPERATING FACILITY AND EQUIPMENT,
at cost, net of accumulated
depreciation of $21,996,892 and
$18,560,822 in 1998 and 1997,
respectively ............................... 79,379,670 82,652,388
------------ ------------
OTHER ASSETS:
Deferred financing costs, net of
accumulated amortization of $508,201
and $421,795 in 1998 and 1997,
respectively ............................... 1,517,028 1,603,434
Restricted cash, net of
current portion ............................ 6,543,469 8,483,222
------------ ------------
Total other assets .......................... 8,060,497 10,086,656
------------ ------------
$101,014,484 $104,153,226
============ ============
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
BALANCE SHEETS - DECEMBER 31, 1998 AND 1997
LIABILITIES AND PARTNERS' EQUITY
1998 1997
CURRENT LIABILITIES:
Project financing loan payable $5,138,041 $ 4,495,786
Current portion of major
maintenance accrual ......................... 1,852,814 798,000
Payables:
Texaco Inc. and subsidiaries ............... 1,218,316 1,231,534
Trade and other (amounts include
$256,066 and $282,431 payable to
related parties in 1998 and 1997,
respectively) .............................. 1,391,250 1,680,586
Accrued liabilities ........................ 447,373 409,531
------------ ------------
Total current liabilities .................. 10,047,794 8,615,437
------------ ------------
PROJECT FINANCING LOAN PAYABLE, net
of current portion ........................... 41,229,559 46,367,601
BONDS PAYABLE ................................ 27,400,000 27,400,000
COMMITMENTS AND CONTINGENCIES (Note 8)
MAJOR MAINTENANCE ACCRUAL, net of current
portion .................................... 1,345,894 2,338,333
------------ ------------
Total liabilities ............................ 80,023,247 84,721,371
------------ ------------
PARTNERS' EQUITY:
Texaco Clark County Cogeneration
Company ...................................... 13,407,042 12,627,350
Bonneville Nevada Corporation ................ 7,584,195 6,804,505
------------ ------------
Total partners' equity ....................... 20,991,237 19,431,855
------------ ------------
$101,014,484 $104,153,226
============ ============
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
STATEMENTS OF INCOME AND PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
1998 1997
REVENUES:
Sales of energy to Nevada Power
Company .................................... $ 45,733,059 $ 44,018,349
Sales of heat to Georgia-Pacific
Corporation ................................ 716,084 839,273
Interest and other income .................. 889,688 826,534
------------ ------------
Total revenues ............................. 47,338,831 45,684,156
------------ ------------
COSTS AND EXPENSES:
Plant and other operating expenses ....... 25,933,891 26,193,641
Depreciation and amortization ............ 3,532,448 3,482,077
General and administrative expenses ...... 1,646,608 1,677,147
Interest expense ......................... 5,773,559 6,187,432
Asset impairment expense ................. 192,943 340,300
------------ ------------
Total costs and expenses ................... 37,079,449 37,880,597
------------ ------------
NET INCOME ................................. $ 10,259,382 $ 7,803,559
============ ============
PARTNERS' EQUITY AT
BEGINNING OF YEAR .......................... $ 19,431,855 $ 18,328,296
NET INCOME ................................. 10,259,382 7,803,559
DISTRIBUTION TO PARTNERS ................... (8,700,000) (6,700,000)
------------ ------------
PARTNERS' EQUITY AT END
OF YEAR .................................... $ 20,991,237 $ 19,431,855
============ ============
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
1998 1997
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ..................................... $ 10,259,382 $ 7,803,559
Adjustments to reconcile net
income to net cash provided by
operating activities:
Depreciation and amortization .................. 3,532,448 3,482,077
Asset impairment expense ....................... 192,943 340,300
Changes in operating assets and liabilities:
(Increase) in receivables ...................... (65,646) (247,527)
Decrease (increase) in prepaids ................ 376,900 (298,900)
Decrease in inventories ........................ 119,038 65,297
Increase (decrease) in major
maintenance accrual ............................ 62,375 (932,375)
(Decrease) increase in payables ................ (302,554) 207,706
Increase in accrued liabilities ................ 37,842 22,040
------------ ------------
Net cash provided by operating
activities ..................................... 14,212,728 10,442,177
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ....................... (366,267) (454,181)
Proceeds from refund of sales tax
relating to operating facility
and equipment .............................. -- 119,124
------------ ------------
Net cash used in investing
activities ................................. (366,267) (335,057)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners ................ (8,700,000) (6,700,000)
Proceeds from restricted
cash accounts ............................ 877,697 1,745,606
Deposits into restricted
cash accounts ............................ (1,643,892) (1,979,905)
Payments on project financing ............ (4,495,787) (3,578,279)
------------ ------------
Net cash used in financing
activities ................................. (13,961,982) (10,512,578)
------------ ------------
NET DECREASE IN CASH AND
CASH EQUIVALENTS ........................... (115,521) (405,458)
CASH AND CASH EQUIVALENTS,
at beginning of year ....................... 5,416,442 5,821,900
------------ ------------
CASH AND CASH EQUIVALENTS,
at end of year ............................. $ 5,300,921 $ 5,416,442
============ ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year
for interest .................................. $5,736,092 $ 6,228,487
============ ============
The accompanying notes are an integral part of these financial statements.
<PAGE>
NEVADA COGENERATION ASSOCIATES #1
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1998
1. General
Nevada Cogeneration Associates #1 (the Partnership) is a general partnership
between Texaco Clark County Cogeneration Company (TCCCC), a wholly-owned
subsidiary of Texaco Inc. (Texaco), and Bonneville Nevada Corporation (BNC), a
wholly-owned subsidiary of Bonneville Pacific Corporation (BPC). The Partnership
was organized under Utah law on October 8, 1990. The Partnership was organized
to design, construct, own and operate a cogeneration facility (the Facility)
located in Clark County, Nevada for the purpose of selling electric energy to
Nevada Power Company (NPC) for resale to its customers and selling thermal
energy to Georgia-Pacific Corporation (Georgia-Pacific) for use in its wallboard
facility.
The partners share equally in the allocations of income (loss), depreciation
expenses and other tax benefits from operations of the Partnership. In
accordance with the general partnership agreement, BNC initially received a
66-2/3 percent and TCCCC a 33-1/3 percent disproportionate share of net cash
distributions until such time as net cash distributions equaled approximately
$18,876,000 (September, 1997) at which time BNC's and TCCCC's share of net cash
distributions changed to 50 percent. The Partnership shall terminate, unless
terminated at an earlier date pursuant to the general partnership agreement, on
the latter of April 30, 2023, or the date the Partnership elects to cease
operations.
The Facility consists of three combustion turbine generators which exhaust heat
into three heat recovery steam generators, producing electricity, process heat
and steam sequentially using one fuel source. Additionally, in a combined cycle
facility, electricity is produced by a condensing steam turbine. The Facility is
designed to support the name plate production of 85 megawatts of electric energy
and 275,000 pounds per hour of process heat. Commercial operations commenced on
June 18, 1992.
2. Summary of Significant Accounting Policies
a. Operating Facility and Equipment
All costs (including interest and field overhead expenses) incurred
during the construction and the precommission phase of the Facility were
capitalized as part of the cost of the Facility. Revenue earned during the
precommission phase was offset against the costs of the Facility. The Facility
and related equipment are being depreciated on a straight-line basis over 30
years, the estimated useful life of the Facility and the life of the Power
Purchase Agreement with Nevada Power Company.
b. Inventories
Inventories consist primarily of spare parts and are stated at average cost,
which did not exceed market.
c. Deferred Financing Costs
All legal and financing fees associated with the Construction Loan, Term
Loan and Reimbursement Agreement (the Agreement) (see Note 3) and the Bonds
Payable (see Note 4) were deferred and are being amortized over the respective
term of the financing.
d. Major Maintenance Accrual
Each of the Facility's gas turbines will require a hot section replacement and a
major overhaul approximately every 25,000 and 50,000 operating hours,
respectively. Expenses for these events are accrued for on a straight-line basis
over the expected operating-hour interval between each like maintenance event.
Expenditures for minor maintenance, repairs and renewals are charged to expense
as incurred. Expenditures for additions and improvements are capitalized.
The accruals for major repair and maintenance events are based on management's
estimates of what these events will cost at the time the events occur. Due to
fluctuations in the extent of repairs, prices and changes in the timing of the
scheduled events, the estimated costs of these events can differ from actual
costs incurred.
e. Statements of Cash Flows
For purposes of reporting cash flows, the Partnership considers
short-term investments with an original maturity of three months or less, to be
cash equivalents.
f. Fair Value of Financial Instruments
The carrying amount of the short-term investments approximates fair
value due to the short maturity of those instruments. Based on the borrowing
rates currently available to the Partnership for long-term debt with similar
terms and maturities as the project financing loan payable and bonds payable,
the carrying amounts of the project financing loan payable and bonds payable
approximate fair value. Taking into consideration the prevailing interest rates
at December 31, 1998 and the Partnership's credit worthiness, the Partnership
would have had to pay approximately $3,848,420 to buy-out the remaining portion
of the interest rate swap agreements (See Note 3).
g. Pervasiveness of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
The Partnership's results of operations for any particular year may be impacted
by fluctuations in the price of natural gas.
h. Restricted Cash Accounts
The Partnership is required by the Agreement to maintain a debt service reserve
account. The funds in this restricted account are maintained until such time
that the Agreement is fully satisfied. These funds may be used by the
administrative agent of the Agreement to pay fees, costs, principal, and
interest associated with the Agreement. The balance in this account was
$5,383,604 and $5,347,409 as of December 31, 1998 and 1997, respectively.
Due to amendments adopted during 1997, the Partnership is no longer required to
maintain a balance in the thermal host restricted reserve account. This account
could become active again under certain circumstances in which the Thermal Host
(Georgia-Pacific) does not purchase sufficient thermal energy, and other
situations, as defined. The account balance was $0 on December 31, 1998 and
1997, respectively.
Another of the restricted cash accounts is designated for major maintenance
events (see d. above). This account is funded in order to reserve sufficient
cash to allow payment of the cost of the major maintenance events, when they
occur. Funds for this account are deposited on a systematic basis for events
occurring within the next 36 months and are used to service the cost of each
event. This account will be maintained for the duration of the Agreement. The
balance in this account at December 31, 1998 and 1997 was, $3,012,679 and
$2,235,811, respectively.
The Partnership also maintains a Selective Catalytic Reduction (SCR) reserve
account with balances of $1,651,134 and $1,698,002 at December 31, 1998 and
1997, respectively. (See Note 8e).
All restricted cash accounts are required by the Agreement and earn interest at
the current market rate. Upon authorization from certain parties to the
Agreement, funds from any of the above accounts may be used for items other than
their restricted purpose.
i. New Statement of Position
On April 3, 1998, the American Institute of Certified Public Accountants issued
Statement of Position 98-5 Reporting on the Costs of Start-Up Activities (the
Statement). The Statement provides guidance on the financial reporting of
start-up costs and organization costs. It requires costs of start-up activities
and organization costs to be expensed as incurred. The Partnership is required
to adopt the Statement on January 1, 1999. Management believes adoption of the
Statement will not have a material impact on the Partnership's financial
position or results of operations.
3. Project Financing
On April 28, 1993 the Partnership converted their construction financing to term
financing. The financing obtained consisted of term loans of approximately
$64,350,000 and letters of credit issued in support of $27,400,000 of tax exempt
bonds. Amounts outstanding under the Agreement are reduced by quarterly payments
in February, May, August and November, with the final payment due November 2007.
The term loan balance at December 31, 1998 was $46,367,600. The Agreement places
certain restrictions on cash accounts, capital distributions and permitted
investments. The Agreement is secured by substantially all of the assets of the
Partnership.
The Partnership has entered into six interest rate swap agreements with
commercial banks. Three swaps (amortizing swaps) had an aggregate initial
notional principal amount of $45 million ($27,360,000 at December 31, 1998)
which decreases over the ten-year term of the agreements. These agreements
essentially change the Partnership's interest rate exposure on the notional
amount to a fixed 8.85 percent per annum plus the lenders' margin. The other
three interest rate swap agreements (bullet swaps) have an aggregate notional
principal amount of $15 million which remains constant over their ten-year term.
These swap agreements essentially change the Partnership's interest rate
exposure on the notional amount to a fixed 7.71 percent per annum plus the
lenders' margin.
If the variable rate applicable to the notional amount exceeds the fixed rate
established by the swap agreements, the Partnership could be exposed to the risk
of higher interest costs in the event of non-performance by the commercial
banks. The Partnership does not, however, anticipate non-performance by the
commercial banks.
Amounts outstanding (other than those noted above) bear interest at LIBOR plus a
margin of .875 percent and are paid monthly. The weighted average interest rate,
inclusive of the effect of the swap agreements, on the outstanding loan balance
at December 31, 1998 and 1997 was 7.20 percent and 7.74 percent, respectively.
The future minimum payments on the debt outstanding and the letters of credit
supporting the tax-exempt bonds at December 31, 1998, are as follows:
1999 $ 5,138,041
2000 5,688,546
2003 6,239,050
2004 6,881,304
2005 7,798,813
Thereafter 14,621,846
-----------
$46,367,600
===========
4. Bonds Payable
The Partnership initially obtained tax-exempt bond financing in the amount of
$19,400,000 from Clark County, Nevada in the form of Industrial Development
Revenue Bonds. These Variable Rate Demand Industrial Development Revenue Bonds
are due and payable on November 1, 2020. Interest is currently payable monthly
and the interest rate was 6.31 and 6.26 percent at December 31, 1998 and 1997,
respectively.
The Partnership obtained additional project bond financing of $8,000,000 on
February 11, 1992, from Clark County, Nevada. These Variable Rate Demand
Industrial Development Revenue Bonds are due and payable on November 1, 2021.
Interest is currently payable monthly and the interest rate was 6.31 percent and
6.26 percent at December 31, 1998 and 1997.
5. Related-Party Transactions
a. Gas Sales and Purchase Agreements
The Partnership has long-term agreements for the purchase of fuel gas
(in addition to those described in Note 8) with Texaco Natural Gas Inc. (TNGI),
and Texaco Exploration & Production Inc. (TEPI), both wholly owned
subsidiaries of Texaco.
The maximum daily contract quantities of gas available under the TNGI
and TEPI agreements are 6,250 and 5,250 MMBtu per day, respectively. The
agreements require the Partnership to take delivery of and/or pay for a volume
of gas up to 90 percent of the TNGI agreement quantities and 75 percent of the
TEPI agreement quantities. The Partnership has two and one-half years under the
TNGI agreement and five years under the TEPI agreement to take delivery of any
gas not taken but paid for in any one contract year, as defined in the
agreements. As of December 31, 1998, the Partnership had satisfied the minimum
volumetric contract obligations.
The initial weighted average price under the TNGI agreement was $2.29
per MMBtu and $2.13 per MMBtu under the TEPI agreement commencing May 1, 1993
until May 1, 2007. The price paid under these agreements is adjusted annually by
the change in the Consumer Price Index (CPI) each May 1. The TNGI agreement has
additional increases, as defined in the agreement, starting May 1, 2007. The
weighted average price as of December 31, 1998 was $2.68 per MMBtu and $2.49 per
MMBtu for TNGI and TEPI, respectively.
The TNGI agreement remains in effect until the latter of December 31,
2011, or twenty years from the commencement date (June 18, 1992), as defined in
the agreement. Under the TNGI agreement, an additional 8,250 MMBtu per day was
replaced with other suppliers' long-term gas contracts (Replacement Contracts).
TNGI will provide up to 8,250 MMBtu per day to the Partnership in the event of
default under the Replacement Contracts. The amounts incurred under the TNGI
agreement were $6,992,359 and $6,180,013 in 1998 and 1997, respectively.
The TEPI agreement remains in effect until the latter of December 31,
2007 or fifteen years from the commencement date (June 18, 1992), as defined in
the agreement. The amounts incurred under the TEPI agreement were $3,529,193 and
$3,162,641 in 1998 and 1997, respectively.
b. Fuels Management Agreement
The Partnership is party to an agreement with TNGI, whereby TNGI is to procure,
at prices based upon the spot market, and manage all fuel-gas supplies and
transportation for the Partnership (except those fuel- gas supplies procured and
delivered under tariff-gas contracts, those fuel-gas supplied under an excepted
contract and other fuel-gas supplies excluded from this agreement by the mutual
consent of TNGI and TEPI until termination of the agreement).
The agreement will remain in effect until the latter of December 31,
2011, or twenty years from the commercial operations date (June 18, 1992). TNGI
receives a fixed service fee of $0.04 per MMBtu on short-term contracts (one
year or less). TNGI also receives a fixed service fee of $0.04 per MMBtu for the
volume of gas delivered under the Replacement Contracts. TNGI received fixed
service fees under short-term and Replacement Contracts of $229,452 and $191,241
in 1998 and 1997, respectively.
c. Operation and Maintenance Agreement
The Partnership has an agreement with Bonneville Pacific Services, Inc.
(BPSI), a wholly-owned subsidiary of BPC, whereby BPSI performs all operation
and maintenance activities necessary for the production of electrical energy and
process heat. The agreement became effective August 1, 1991, and will remain in
effect for 30 years from the commercial operations date (June 18, 1992), subject
to earlier termination after 10 years from the commercial operations date as
defined in the agreement.
BPSI is paid for all costs incurred in connection with operating and
maintaining the Facility and is paid an annual operating fee of $260,000, which
is adjusted annually by the change in the CPI. BPSI may earn an incentive bonus
which is based upon BPSI achieving certain operating goals, as defined in the
agreement. The costs incurred under this agreement were $1,637,953 and
$1,729,752 in 1998 and 1997, respectively. Incentive bonuses earned were
$321,010 and $333,065 in 1998 and 1997, respectively.
d. Engineering and Administrative and Other Costs
The Partnership, under agreements, pays for certain engineering and
administrative expenses and other costs to Texaco and its subsidiaries. Texaco
may also earn a performance bonus based upon the plant achieving certain
operational goals, as defined in the agreement. The fees incurred under these
agreements totaled $474,377 and $525,159 in 1998 and 1997, respectively.
Performance incentives earned were $321,010 and $333,065 in 1998 and 1997,
respectively.
6. Asset Impairment Expense
During 1997, the Partnership replaced an outdated reverse osmosis system with
newer technology. As a result, an impairment expense of $340,000 was recognized
for the year ending December 31, 1997 on the old reverse osmosis system. At
December 31, 1997, the Partnership's estimate of fair value of the reverse
osmosis system based on market quotes was $200,000.
At December 31, 1998 the reverse osmosis system was deemed unsaleable;
accordingly, the Partnership wrote down the remaining value of the system to $0.
7. Income Taxes
Income taxes are not recorded by the Partnership since the net income or loss
allocated to the partners is included in their respective income tax returns.
8. Commitments and Contingencies
a. Power Purchase Agreement
The Partnership has an agreement for long-term power purchases of energy
and capacity by NPC which terminates on April 30, 2023. The Partnership is paid
for energy delivered based upon fixed rates, as defined in the agreement,
adjusted annually at 120 percent of the change in the CPI. NPC also pays the
Partnership for firm capacity based upon fixed rates, as defined in the
agreement, increased annually by two percent.
During 1997 the Partnership negotiated an amendment to the agreement
severely limiting NPC's curtailment rights in exchange for a price discount of
$0.25 per megawatt hour. The amendment was signed on October 3, 1997 and
received Nevada Public Utility Commission's approval on April 3,1998.
Pursuant to the amended agreement, the Partnership has the right to
release NPC from its purchase obligation for an agreed upon payment per released
megawatt. For the year ended December 31, 1998 and 1997, the Partnership
received $1,549,480 and $1,101,320, respectively for released megawatts. In
conjunction with the above the Partnership was able to manage its fuel cost
through non-acceptance or resale to others.
b. Heat Purchase Agreement
The Partnership has an agreement for the long-term sale of process heat
to Georgia-Pacific. The agreement became effective January 29, 1991, and will
terminate on April 30, 2023, or earlier, as defined in the agreement. The
Partnership is paid for process heat delivered at an amount equal to 65 percent
of the energy cost of operating Georgia-Pacific's kiln and gypsum calcining
mills on the lowest alternative energy. Process heat sold under this contract
has been sufficient for the Partnership to meet its annual qualifying facility
status and is expected to be sufficient for the Partnership to meet its annual
qualifying facility requirements in the future.
c. Gas Sales and Purchase Agreements
The Partnership has two long-term agreements for the purchase of fuel gas (other
than those described in Note 5) with unrelated parties. The first of these
agreements remains in effect until the earlier of March 1, 2008, or fifteen
years from the commercial operations date (June 18, 1992).
The second agreement remains in effect until the latter of December 31,
2007, or fifteen years from the commercial operations date (June 18, 1992). The
maximum daily contract quantities available under these agreements total 7,000
MMBtu per day. The agreements require the Partnership to take delivery of and/or
pay for a volume of gas up to 75 percent of the average maximum daily contract
quantities available under these agreements. The Partnership has two years
(under the 2,000 MMBtu per day contract) and five years (under the 5,000 MMBtu
per day contract) to take delivery of any gas not taken but paid for in any one
contract year, as defined in the agreements. As of December 31, 1998, the
Partnership had satisfied the minimum volumetric contract obligations.
The Partnership initially paid a fixed price ($2.00 to $2.20 per MMBtu) for the
quantities of fuel gas delivered under these contracts. The price paid on the
5,000 MMBtu per day contract is adjusted annually by the change in the CPI. The
price on the 2,000 MMBtu per day contract will be adjusted by 90 percent of the
change in the CPI, twenty-five months after the start of gas deliveries (June
18, 1992), and annually each May 1 thereafter. The price paid under these
contracts was $2.41 during 1998.
d. Equipment Lease
The Partnership and Nevada Cogeneration Associates #2 jointly entered into an
equipment lease agreement, with an unrelated party, on December 31, 1992. The
agreement requires monthly payments of $48,747 plus sales tax over the ten year
term. The Partnership's share is one-half of the monthly payments.
e. Environmental Matters
As a result of issues brought forth during 1997 regarding SCR, the
Partnership has negotiated with the Environmental Protection Agency for the
installation of two SCR units. The schedule calls for the installation to take
place by March 1999.
Funds for the installations will come from the SCR reserve account,
current reserves are considered adequate to cover the cost of the installations.
f. Electric Utility Deregulation
In 1998, The Nevada Legislature passed legislation to restructure the Nevada
electric utility industry. The legislation (AB366) calls for competition to
commence by January 1, 2000. The eventual outcome of these activities and their
potential impact, if any, upon the Partnership is not known.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
BONNEVILLE PACIFIC CORPORATION'S FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1
<CURRENCY> U.S. Dollar
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> Dec-31-1998
<PERIOD-START> Jan-01-1998
<PERIOD-END> Dec-31-1998
<EXCHANGE-RATE> 1.00
<CASH> 16,018
<SECURITIES> 0
<RECEIVABLES> 6,255
<ALLOWANCES> 0
<INVENTORY> 65
<CURRENT-ASSETS> 812
<PP&E> 42,510
<DEPRECIATION> (26,991)
<TOTAL-ASSETS> 46,614
<CURRENT-LIABILITIES> 0
<BONDS> 0
72
0
<COMMON> 0
<OTHER-SE> 28,263
<TOTAL-LIABILITY-AND-EQUITY> 46,614
<SALES> 26,459
<TOTAL-REVENUES> 26,459
<CGS> 31,705
<TOTAL-COSTS> 31,705
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 6,541
<INCOME-PRETAX> (3,865)
<INCOME-TAX> 500
<INCOME-CONTINUING> (3,865)
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<EXTRAORDINARY> 23,681
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<NET-INCOME> 20,316
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</TABLE>
