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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.

<PAGE>
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.

<PAGE>
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.

<PAGE>
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.

<PAGE>
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