SECURITIES AND EXCHANGE COMMISSION

                             Washington, D.C. 20549

                                   FORM 10-KSB
(Mark One)

/x/     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
        ACT OF 1934
                      For the fiscal year ended March 31, 1999

/ /     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES
        EXCHANGE ACT OF 1934
                       For the transition period from _________ to _________


                                    0-24493
                                    -------
                               Commission File No.


                          Cambridge Energy Corporation
                          ----------------------------
             (Exact name of registrant as specified in its charter)


          Nevada                                                  59-3380009
          ------                                                  ----------
(State or other jurisdiction of                               (I.R.S. Employer
incorporation or organization)                               Identification No.)


           215. South Riverside Drive, Suite 12, Cocoa, Florida 32922
           ----------------------------------------------------------
                    (Address of principal executive offices)


Registrant's telephone number, including area code:   (407) 636-6165

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:  Common Stock,
                                                             $.0001 par value

     Check whether the issuer (1) has filed all reports  required to be filed by
Section 13 or 15(d) of the Securities  Exchange Act of 1934 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 __x__ No _____

     Check if there is no disclosure  of  delinquent  filers in response to Item
405 of Regulation S-B is not contained in this form,  and no disclosure  will 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-KSB
or any amendment to this Form 10-KSB. [ ]

     State issuer's revenues for its most recent fiscal year. $562,026

     State he aggregate market value of the voting and non-voting  common equity
held by  non-affiliates  computed by  reference to the price at which the common
equity was sold, or the average bid and ask price of such common equity, as of a
specified date within the past 60 days.

     As of March 31, 1999 there were outstanding  11,634,827 shares of Cambridge
Energy Corporation's common stock, par value $.0001 per share .
<PAGE>

                          CAMBRIDGE ENERGY CORPORATION
                     Form 10-KSB Report for the Fiscal Year
                              Ended March 31, 1999

                                TABLE OF CONTENTS


                                                                         Page



                                     PART I

Item 1. Business .......................................................  1

Item 2. Properties .....................................................  8

Item 3. Legal Proceedings ..............................................  11

Item 4. Submission of Matters to a Vote of Security Holders ............  12



                                     PART II

Item 5. Market for Registrant's Common Stock and
          Related Stockholder Matters ..................................  12

Item 6. Management's Discussion and Analysis of Financial
          Condition and Results of Operations ..........................  12

Item 7. Selected Financial Data ........................................  14

Item 8. Changes in and Disagreements with Accountants on
          Accounting and Financial Disclosure ..........................  14



                                    PART III

Item 9. Directors and Executive Officers of the Registrant ............   15

Item 10. Executive Compensation ........................................  16

Item 11. Security Ownership of Certain Beneficial
          Owners and Management ........................................  17

Item 12. Certain Relationships and Related Transactions ................  17



                                     PART IV

Item 13. Exhibits, Financial Statement Schedules and
          Reports on Form 8-K ..........................................  18







                                       1
<PAGE>
                                     PART I

Item 1.  Business

     (a) General Development of Business

     CAMBRIDGE ENERGY CORPORATION, (the Company) was incorporated under the laws
of the State of Nevada on April 9, 1996. At inception the Company's  Articles of
Incorporation Authorized 2,000,000 Common Shares at $.001 Par Value, and 100,000
Preferred  Shares at $.001  Par  Value.  In June  1997,  the Board of  Directors
approved an amendment to the Company's Articles of Incorporation  increasing the
authorized  Common  Shares of the Company  from  2,000,000  to  50,000,000,  and
increasing the number of authorized Preferred Shares from 100,000 to 25,000,000.
At that time the Board also changed the Par Value of each class of stock to from
$.001 to $.0001 per share.  The  amended  Articles  were filed with the State of
Nevada on July 7, 1997.  The  Company  then  undertook  a Private  Placement  of
1,935,000  of its  Common  Shares  to raise  capital  for the  execution  of its
business  plan. In November 1997, the Company began trading its Common Shares on
the OTC Bulletin Board under symbol CNGG.

     (b) Business of Issuer

The Company.

     Cambridge Energy  Corporation was formed for the purpose of development and
operation of oil and gas properties with proven reserves. The Company's strategy
is to focus in domestic  areas where major oil and gas producing  companies have
reduced their exploration efforts to move offshore and overseas in search of the
larger  reserves.  Considerable  oil  and  gas in  proven  fields  remain  to be
exploited by well-managed  independent oil companies capable of extracting these
reserves  at lower  risk and  lower  cost  than  unproved  prospects.  Cambridge
Energy's initial development strategy has been to acquire such proven fields and
increase  production  through the  application  of advanced  technology  and the
exploration of other proven formations in the same fields.

     Cambridge Energy's primary  operational  strategy includes the operation of
its own projects,  giving it  substantial  control over drilling and  production
costs. The Company has associated highly experienced exploration and development
engineering  and geology  personnel that strive to add production at lower costs
through development drilling, workovers, behind pipe recompletions and secondary
recovery operations.

 Operations

     The Company expects that it will continue to engage in both development and
exploratory  drilling  operations.  Such activities were limited in 1998 and are
expected to be limited in 1999, due to industry conditions. However, the Company
intends  to  pursue a  diversified  inventory  of  exploratory  and  development
prospects. The current portfolio includes lower-risk development and exploratory
prospects,  as well as higher risk exploratory prospects with greater potential.
The objective of the Company's  near-term  strategy is maximization of the value
of its existing prospect inventory while reducing its cost and risk exposure. In
the near term, the Company plans to retain a 10% to 50% direct working  interest
in each prospect,  plus any carried or reversionary interest retained as part of
sales to industry partners.  Direct participation may increase as corporate cash
flows and capital  resources  increase.  Drilling  prospects may result from the
evaluation  of  acquisitions.   Drilling  activities,   whether  exploratory  or
developmental,   are  subject  to  many  risks,   including  the  risk  that  no
commercially  productive  reservoirs  will  be  encountered.  There  can  be  no
assurance  that any new wells  drilled by the  Company  will  recover all or any
portion  of the  related  investment.  The  cost  of  drilling,  completing  and
operating  wells is often  uncertain and cost overruns can occur.  The Company's
drilling  operations  might be  curtailed,  delayed or  canceled  as a result of
numerous factors, many of which are beyond the Company's control.  These factors
include  financial  resources of the Company or its partners,  commodity prices,
land and title issues,  mechanical  problems,  weather conditions and compliance
with  governmental  requirements.  Unsuccessful  drilling  activities may have a
material adverse effect on the Company.

                                       2
<PAGE>

     The company has acquired an  Indonesian  subsidiary,  Intermega  Energy Pte
Ltd. The company  received  from F.K. Ho, 100% of the stock of Intermega  Energy
Pte Ltd. which includes three fields in eastern  Indonesia and executive offices
in Jakarta for liaison with  Pertamina,  the  government  owned oil company that
controls  all of  Indonesian  oil  and  gas.  We are  adding  approximately  100
employees by this. They include:

          Technical  Assistasnce  Contract/Contract  Area:  Salawati  A,  D  and
     Sabaku.    ownership   by   INTERMEGA   of   the   Technical    Assistasnce
     Contract/Contract  Area:  Salawati  A,  D and  Sabaku,  originally  between
     Perusahaan Pertambangan Dan Gas Bumi Negara (Pertamina) and PT. Siddhakarya
     Pilona Sabaku dated  January 9, 1995.  This contract area covers 5.97 sq Km
     for Salawati "A" and "D" and .50 sq Km for Sabaku.

          Technical Assistasnce  Contract/Contract Area: Salawati C, E, F and N.
     ownership by INTERMEGA of the Technical Assistasnce Contract/Contract Area:
     Salawati C, E, F and N, originally between Perusahaan  Pertambangan Dan Gas
     Bumi Negara  (Pertamina) and PT.  Siddhakarya Pilona Salawati dated January
     9, 1995. This contract area covers 23.05 sq. Km.

          Technical  Assistasnce  Contract/Contract  Area:  Linda A,  C/G  Sele.
     ownership by INTERMEGA of the Technical Assistance  Contract/Contract Area:
     Linda A, C/G Sele, originally between Perusahaan  Pertambangan Dan Gas Bumi
     Negara  (Pertamina)  and  Intermega  Linda Sele Pte Ltd. This contract area
     covers 12.35 sq. Km.

     The Company's  future  performance  depends upon its ability to acquire and
develop additional oil and gas reserves that are economically  recoverable.  The
Company   intends  to  continue  its   acquisition,   development  and  drilling
activities.  The Company expects to close  additional  acquisitions and drill or
participate  in sixteen wells in 1999 and 2000;  however,  no assurances  can be
given that the Company will be successful or will have  sufficient  cash flow or
sources of external capital to acquire,  develop or discover additional reserves
at  an  economical  cost.  Without  successful   acquisition,   development  and
exploration activities the Company's reserves will decline.

 Competitive Business Conditions

     The  Company  encounters  strong  competition  from  major and  independent
companies  in  acquiring  properties  and  leases  for  production   operations,
exploration  and  development.   The  principal   competitive   factors  in  the
acquisition of such oil and gas properties  include the staff and data necessary
to identify,  investigate and purchase such leases, and the financial  resources
necessary to acquire and develop such leases. Many of the Company's  competitors
have financial resources, staffs and facilities substantially greater than those
of the Company.

 Distribution

     The  Company's  oil  and  gas  production  is  marketed  to  third  parties
consistent with industry  practices.  Typically,  oil is sold at the wellhead at
field posted prices,  plus or minus adjustments for quality and  transportation.
Natural gas is usually  sold under a contract at a  negotiated  price based upon
factors normally considered in the industry, such as gas quality,  distance from
the well to the pipeline,  estimated  reserves,  liquid  hydrocarbon  content of
natural gas and prevailing supply/demand conditions.

 Joint Operations With Others; Non-Operator Status

     The Company owns less than 100% of the working  interest in some of its oil
and gas  properties.  Operations on such  properties  are likely to be conducted
jointly with other working  interest  owners.  Joint operating  arrangements are
customary in the oil and gas industry and are generally  conducted pursuant to a
joint operating agreement, whereby a single working interest owner is designated
the operator. At present, the Company is the operator of the majority of its oil
and gas properties. The Company is also a nonoperating working interest owner in
other wells.  For properties where the Company owns less than 50% of the working
interest,  drilling  and  operating  decisions  may not be  entirely  within the


                                       3
<PAGE>

Company's  control.  If the Company disagrees with the decision of a majority of
working interest owners, it may be required, among other things, to postpone the
proposed   activity,   relinquish   or  farm-out  its  interest  or  decline  to
participate.  If the  Company  declines  to  participate,  it might be forced to
relinquish its interest or may be subject to certain non-consent  penalties,  as
provided in the applicable operating  agreement.  Such penalties typically allow
participating   working   interest  owners  to  recover  from  the  proceeds  of
production,  if any,  an  amount  equal to  200%-500%  of the  non-participating
working interest owner's share of the cost of such operations.

     Under most  operating  agreements,  the  operator is given  direct and full
control  over  all  operations  on the  property  and is  obligated  to  conduct
operations in a workman-like manner; however, the operator is usually not liable
to the working interest owners for losses sustained or for liabilities incurred,
except those resulting from its own gross negligence or willful misconduct. Each
working  interest  owner is  generally  liable  for its  share  of the  costs of
developing and operating jointly owned  properties.  The operator is required to
pay the  expenses of  developing  and  operating  the  property and will invoice
working  interest  owners  for  their  proportionate  share  of such  costs.  In
instances  where the Company is a non-operating  working  interest owner, it may
have a limited  ability to exercise  control over  operations and the associated
costs of such  operations.  The  success  of the  Company's  investment  in such
non-operated  activities may,  therefore,  be dependent upon a number of factors
that are outside of the Company's direct control.

     Under most operating  agreements and the laws of certain states,  operators
of oil and gas properties may be granted liens on the working interests of other
non-operating  owners in the well to  secure  the  payment  of  amounts  due the
operator.  The  bankruptcy or failure of the operator or other working  interest
owners to pay vendors who have  supplied  goods or services  applicable to wells
could  result  in filing of  mechanics'  and  materialmens'  liens  which  would
encumber the well and the interests of all joint owners.

Forward-Looking Information:

     All statements  other than statements of historical  fact contained  herein
are  forward-looking  statements.   Forward  looking  statements  are  generally
accompanied by words such as  "anticipate,"  "believe,"  "estimate,"  "project,"
"potential"  or "expect" or similar  statements.  Although the Company  believes
that  the  expectations   reflected  in  such  forward-looking   statements  are
reasonable, no assurance can be given that such expectations will prove correct.
Factors could cause the Company's  results to differ materially from the results
discussed in such forward-looking  statements.  Such factors include such things
as uncertainty of costs associated with exploratory  drilling,  drilling results
and  reserve  estimates,   operating  hazards,   need  for  additional  capital,
competition from other exploration,  development and production  companies,  the
fluctuations of prices received or demand for the Company's oil and gas, and the
effects  of  governmental  and  environmental  regulation.  All  forward-looking
statements  contained  herein are expressly  qualified in their  entirety by the
cautionary statements in this paragraph.

Environmental and Government Compliance and Costs:

     Operations of the Company are subject to numerous Federal, state, and local
laws and  regulations  governing the discharge of materials into the environment
or otherwise  relating to environmental  protection.  These laws and regulations
may require the acquisition of a permit before drilling  commences;  restrict or
prohibit the types,  quantities  and  concentration  of  substances  that can be
released  into the  environment  in  connection  with  drilling  and  production
activities;  prohibit or limit drilling activities on certain lands lying within
wetlands  or other  protected  areas;  and impose  substantial  liabilities  for
pollution  resulting from past or present  drilling and  production  operations.
Moreover,  changes in Federal and state environmental laws and regulations could
occur and may result in more stringent and costly  requirements which could have
a  significant  impact  on  the  operating  costs  of  the  Company.  The  state
authorities  regulating oil and gas activities have primary regulatory authority
over environmental matters. In general,  under various applicable  environmental
programs,  the  Company  may be  subject  to  enforcement  action in the form of
injunctions,  cease and desist  orders and  administrative,  civil and  criminal


                                       4
<PAGE>
penalties for violations of environmental  laws. The Company may also be subject
to liability from third parties for civil claims by affected  neighbors  arising
out of a pollution event.  Laws and regulations  protecting the environment may,
in certain circumstances,  impose strict liability rendering a person liable for
environmental  damage  without regard to negligence or fault on the part of such
person.  Such laws and  regulations  may expose the Company to liability for the
conduct of or conditions caused by others, or for acts of the Company which were
in compliance  with all  applicable  laws at the time such acts were  performed.
Management  believes that the Company is in substantial  compliance with current
applicable environmental laws and regulations and that continued compliance with
existing  requirements  will not have a material  adverse impact on the Company.
Insofar as such laws and regulations are expanded, amended or reinterpreted, the
Company is unable to predict the future cost or impact of compliance.

     The primary  environmental,  statutory,  regulatory and safety  regulations
that affect the Company's operations include:

     Oil  Pollution  Act and Clean  Water  Act.  The Oil  Pollution  Act of 1990
("OPA") amends certain  provisions of the Federal Water Pollution Control Act of
1972, commonly referred to as the Clean Water Act ("CWA"), and other statutes as
they  pertain to the  prevention  of and  response to oil spills into  navigable
waters. Under OPA, a person owning a facility or equipment from which there is a
discharge  or threat of a  discharge  of oil into or upon  navigable  waters and
adjoining  shorelines is liable as a  "responsible  party" for removal costs and
damages.  Federal law imposes strict,  joint and several liabilities on facility
owners for containment  and clean-up costs and certain other damages,  including
natural resource damages,  arising from a spill.  Responsible  parties under OPA
include  owners or operators  of onshore or offshore  drilling  facilities.  OPA
requires  responsible  parties to maintain proof of financial  responsibility to
cover some portion of the cost of a potential  spill and to prepare an oil spill
contingency  plan.  Failure to comply  with  these  requirements  or  inadequate
cooperation  in a spill  event  may  subject  a  responsible  party  to civil or
criminal  enforcement  action.  The CWA and  similar  state  laws  regulate  the
discharge of pollutants,  including dredged or fill materials,  to waters of the
United States, including wetlands. A permit is required for such discharges, and
permit  requirements  may result  either in operating  limitations  or treatment
requirements.

     Clean Air Act.  The  operations  of the Company may be subject to the Clean
Air Act ("CAA"),  as amended,  and comparable state statutes.  Amendments to the
CAA contain provisions that may result in the imposition of certain requirements
for air pollution control equipment,  obtaining operating permits and approvals,
and other  emission-related  requirements which may require capital expenditures
by the Company.

     Superfund  The  Comprehensive  Environmental  Response,   Compensation  and
Liability Act ("CERCLA"),  commonly  referred to as the "Superfund" law, imposes
strict,  joint and several  liability on certain classes of persons with respect
to  the  release  or  threatened  release  of  a  hazardous   substance  to  the
environment.  These  persons  include:  (i) the owner and operator of a facility
from which  hazardous  substances  are released;  (ii) owners and operators of a
facility at the time any hazardous substances were disposed; (iii) generators of
hazardous  substances that were released at such facility;  and (iv) parties who
arranged for the  transportation of hazardous  substances to such facility.  The
Company may be responsible under CERCLA for all or part of the costs to clean up
sites at which hazardous substances have been released. Some states have similar
provisions. In certain circumstances, neighbors and other third parties may file
claims  based on common law tort  liability  theories  for  personal  injury and
property  damage  allegedly  caused by the release of hazardous  substances at a
CERCLA site.

     Resource  Conservation  and Recovery  Act.  The  Company's  operations  may
generate  and  result in the  transportation,  treatment  and  disposal  of both
hazardous and nonhazardous  solid wastes that are subject to the requirements of
the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
and local  requirements.  Although  many of the  Company's  wastes are presently
exempt from requirements  applicable to hazardous  wastes,  legislation has been
proposed in Congress from time to time that would reclassify certain oil and gas
wastes as "hazardous wastes" under RCRA, which  reclassification would make such
solid wastes subject to much more stringent handling,  transportation,  storage,
disposal and cleanup  requirements.  State initiatives to increase regulation of
oil and gas wastes could have a similar impact.

                                       5
<PAGE>

     NORM.  Oil  and  gas  exploration  and  production   activities  have  been
identified as generators of naturally-occurring  radioactive materials ("NORM").
Some states currently regulate the generation, handling and disposal of NORM due
to oil and gas  exploration  and  production  activities.  The Company  does not
believe that its compliance with such regulations will have a material effect on
its  operations  or financial  condition,  but there can be no assurance in this
regard.

 Safety Regulations

     OSHA. The Occupational Safety and Health Act of 1970, as amended,  ("OSHA")
establishes employer responsibilities, including maintenance of a workplace free
of recognized  hazards likely to cause death or serious injury,  compliance with
standards promulgated by the Occupational Safety and Health

     Administration,  and various  record  keeping,  disclosure  and  procedural
requirements.  Various  standards,  including  standards for notices of hazards,
safety in excavation  and  demolition  work,  and the handling of asbestos,  may
apply to the Company's operations.

 Oil and Gas Regulation

     The  Federal  government  and  various  state  and local  governments  have
adopted, and the Company's operations are continuously affected by, numerous and
complex  laws and  regulations  related  to  exploration  and  drilling  for and
production, transportation and marketing of oil and natural gas. State and local
laws and  regulations  usually cover such matters as  permitting  and spacing of
wells, unitization and pooling of oil and gas properties,  maximum and allowable
production rates, environmental protection, pollution control, taxation, bonding
and insurance,  surface restoration,  plugging and abandonment of wells, flaring
of gas,  underground  injection of saltwater and oilfield wastes,  gathering and
transportation  of oil  and  gas and  other  related  matters.  State  laws  and
regulations regarding spacing, unitization and pooling often dictate whether and
how much of the Company's  leases will be entitled to  participate in production
from oil and gas wells in which the Company has invested.  Local governments are
becoming  increasingly  active in regulating oil and gas activities,  especially
activities such as the location, drilling and operation of oil and gas wells and
the construction and operation of pipelines in or near populated areas.

     In 1992, the Federal Energy Regulatory Commission ("FERC-) issued Order No.
636, which  generally  required  interstate  pipelines to "unbundle" or separate
their  previously  combined  services  for  purchasing,  transporting,  selling,
gathering and storing natural gas. Currently, producers sell gas at uncontrolled
market prices. The Federal government and various state governments have adopted
laws and regulations  regarding the methods of calculating lease royalties,  the
time by which  proceeds of  production  attributable  to the interests of others
must be paid by producers  and the rights of  producers to suspend  payments for
the proceeds of  production  attributable  to others.  Federal,  state and local
governments and their agencies are constantly  revising the laws and regulations
affecting the oil and gas industry.  Such continuing revisions in Federal, state
and local regulation could affect the operations of the Company.

     The Company's  operations are subject to all of the risks normally incident
to the production of oil and gas, including blowouts, mechanical failure, casing
collapse,  oil spills and fires,  each of which could result in severe damage to
or destruction of oil and gas wells, production facilities or other property, or
injury to persons. The energy business also is subject to environmental hazards,
such as oil spills, gas leaks, and ruptures and discharge of toxic substances or
gases that could expose the Company to  substantial  liability  due to pollution
and  other  environmental  damage.  The  Company  maintains  insurance  coverage
considered  to be customary in the  industry,  either  directly or through third
party operators who are contractually  obligated to provide insurance  coverage.
The Company may not,  however,  be fully insured against certain of these risks,
either because such insurance is not available or because of high premium costs.
The  occurrence of a significant  event that is not fully insured  against could
have a material adverse effect on the Company's financial position.


                                       6
<PAGE>

Oil and Gas Operations: (see also Management Discussion and Analysis)

     The Company  realized from the sale of its  production  for the fiscal year
ended  March 31,  1999,  $11.93 per barrel of oil and $1.86 per mcf of gas.  The
Company's  average lifting cost was $.83 per BOE for the same period on the sale
of 35,528.99 BOE.


                                    Percent
                                   Increase       Year Ended      Year Ended
                                  (decrease)    March 31, 1999   March 31, 1998
                                 ------------   --------------   --------------
Gas Production (mcf)                 137%          200,985            84,460
Oil Production (bbls)                115%          4162.53              1927
Barrel of Oil Equivalent           95.72%        37660.057             19241
Average Price of Gas (per mcf)      (9.8%)           $1.86             $2.06
Average Price of Oil (per bbls)    (31.3%)          $11.93            $17.20



Well Services Business:

     At the end of Fiscal Year 1999,  the  Company  acquired  Triton  Wellhead &
Manufacturing,  Inc.,  a  manufacturer  of wellhead  and valve  devices  serving
primarily  the oil and gas industry . The  acquisition  includes a 14,000 square
foot  manufacturing  facility  in  Broussard,   Louisiana,  along  with  machine
equipment,  raw stock and finished product inventory,  and engineering  drawings
for its product catalog. This transaction added approximately $925,000 in assets
to the  Company,  and  $388,000  in long term  debt.  An added  benefit  of this
acquisition is the vertical  integration aspect,  whereby the Company can obtain
these products for use on its own properties from Triton,  ensuring availability
and lower  cost.  The  transaction  was closed  during the third  quarter of the
fiscal year end.

     The transfer of the ownership of Triton Wellhead & Manufacturing,  Inc. has
necessitated  the  recertification  of the  facility  under  American  Petroleum
Institute (API) guidelines in order to assure acceptance of its products in both
U.S. and  International  markets.  The facility has operated on a limited  basis
primarily  completing work for the Company.  The facilities have previously been
certified  and the  Company  expects to complete  the process  during the coming
fiscal year,  although  there is no  assurance  that the  certification  will be
issued for the facility.

Employees, Consultants and Contractors:

     The Company  currently has four full-time  employees mainly involved in the
management,  administration  and  investor  relations  aspects of the  Company's
business.  Most of the  engineering  and geology for the  Company's  projects is
performed by consulting  firms, and the actual drilling,  rework and other field
operations performed on a project basis by contractors who bid for the work, the
most cost-effective manner of operation,  as the range of expertise and services
required varies by project and time duration.

     Intermega Energy Ltd. employs 12-15 people in the Jakarta office and in the
field there are approximately 60-70 people employed though a labor contract that
work in the company's Indonesian fields.

     Cambridge Energy employs G & A International, Inc., a petroleum engineering
firm in  Lafayette,  Louisiana,  to  perform  all of the  Company's  engineering
analysis and project design, drilling and rework supervision. In addition, G & A
provide office space and support for the Company's office in Lafayette.  Much of
the  engineering  and geological  analyses are reimbursed on a project basis pro
rata by the working interest partners participating in each project. The Company
also employs an oil and gas accounting firm,  Investors  Petroleum  Consultants,
Inc. in Lafayette,  Louisiana, to provide accounting and disbursement reports on
all of the lease and other royalty and working  interest  percentages of each of
the  company's  projects  as well as to prepare oil and gas  production  revenue
disbursements.

                                       7
<PAGE>

Item 2.  Description of Properties

     The  corporate  offices  of  Cambridge  Energy  Corporation  are in  Cocoa,
Florida,  and consist of approximately 1200 square feet of office space owned by
an officer and  director of the  Company.  The Company has  utilized  this space
since its  inception.  It has paid no lease  payments on this space to date.  As
revenues  increase  the  Company  intends  to either  purchase  or lease  larger
facilities for its headquarters at another location.

     The Company also maintains engineering offices in Lafayette,  Louisiana, as
part of its consulting  contract with G & A International,  Inc. for engineering
services.  The  Company  is  obligated  for a fee of  $14,000  per month for the
engineering  services  and office  space and  support,  a portion of which it is
reimbursed as  engineering  costs for each project are attributed to the working
interest partners.

Current Oil and Gas Properties:

     Houma Field - Calvert & Todd No. 1 Well: A 12,500' gas well that  Cambridge
Energy  drilled,  completed and brought on line in  Terrebonne  Parish at Houma,
Louisiana.  The  Company  drilled  this  well at the end of 1997 on an  assigned
farmout from UNOCAL.  The natural gas is being sold by contract to Eagle Natural
Gas Company,  and the  oil/condensate is being sold to UNOCAL in accordance with
their  assigned  farmout  agreement with  Cambridge  Energy.  The Company owns a
34.375% working  interest in the well.  Cambridge  Energy is the operator of the
well.

     During  the  last  month  of  the  fiscal  year,  Unocal  undertook  rework
operations  on the Calvert & Todd #13 well,  in which the Company has a 4.70217%
working interest. The recompletion was successful and the well has produced more
than  250,000  mcf  of  gas  and  12000  barrels  of oil  condensate  since  the
recompletion.  Unocal is the operator of this well. During the yeat, the Company
acquired  an  additional  117 acres under lease next to its Calvert & Todd No. 1
well in Houma.

     Houma  Field  Continued  Development:  The Houma  Field  project  initially
consisted  of  two  wells,  one  development  well  to be  drilled  to  gas  and
oil/condensate  that remain in  reservoirs  that produced in wells down dip from
the  Calvert & Todd No. 1  development  well  location or  reservoirs  that were
productive  by log  analysis but never  produced,  and one well to be drilled to
test the upthrown  untested  fault block on the acreage.  The initial well,  the
Calvert & Todd No.1,  described above, was a 12,500' normal pressured  Krumbhaar
Sand test drilled on the crest of a downthrown fault closure to produce bypassed
pay in the First Krumbhaar Sand as well as recoverable  reserves from as many as
five partially depleted  Krumbhaar gas sand reservoirs.  There were also several
Tex.  W. and Big (3) Sands that were  logged as pay in the new well.  The second
location  is a  proposal  to test an  upthrown  fault  closure  on north dip for
Krumbhaar Sands that lie between two proven  productive  fault blocks,  updip to
good sidewall core shows.

     The  Formation  Test of 4,000 PSI taken in the  Krumbhaar 4 Sand during the
drilling of Calvert & Todd No.1 indicates that a partial water drive has allowed
this reservoir to re-pressure  since the last  production and a P/Z curve allows
the determination of the remaining  reserves in this sand. There was no pressure
data taken in the  Krumbhaar 3 Sand that logged 10' - 14' of net gas pay, nor in
the Krumbhaar 1A Sand that logged 8' of net gas pay. The new well logged 28 feet
of net gas pay with no known  water  level in the Big (3) No. 3 Sand at 11,536'.
The 8950' Sand was shaled out. The Big (3) No.1 Sand that  produced 15.3 billion
cubic  feet  (BCF) in the  Calvert  & Todd No.  14-1  logged as  productive  and
depleted  with a possible  low BHP. The Prentice and 1st Gaidry Sands as well as
the 9600 Foot Sand in the Tex W. interval also logged as productive.  There also
appears to be  production  in other  intervals  that may add to  reserves to the
above  mentioned  reservoirs for a second well to be drilled through the Big (3)
section at the optimum  structural  position  on this  feature.  Completions  in
similar pays in the Big (3) and Tex W. intervals  have had excellent  recoveries
in other wells in the Houma Field. The modern suite of logs that were run in the
Calvert & Todd No. 1 well for porosity and shaley sand resolution (FDC-CNL,  GR,
CAL) defined additional pay zones that have not been produced. A well drilled at
the  apex  of  this  structure  will  penetrate  several  potential   productive


                                       8
<PAGE>

reservoirs that appear anomalous on electric logs of existing wells in the areas
that were  drilled in the 1950s and 1960s.  Cambridge  Energy plans at least one
additional  wells for its farmout  properties at Houma to access proven reserves
identified and logged during the drilling of the Calvert & Todd No. 1 well.

     Big Island Field:  This is a 140 acre property  Cambridge  Energy has under
lease in Rapides Parish, Louisiana, which includes an existing oil well known as
the Floyd  A-1 well.  Geologically,  the Floyd A-1 well is  situated  at the net
oil's edge of a Hudson Sand channel and  produces  water along with the oil from
this Wilcox Sand. As part of the continued  development of the Big Island Field,
this  well  will be  enhanced  by  equipping  it  with a  larger  pump.  Current
production of Floyd A-1 well is 8-12 BOPD after some rework was  accomplished in
December  1997,  which is sold to Scurlock  Permian  Corporation a subsidiary of
Ashland,  Inc. of Houston,  Texas.  Production  is expected to increase to 15-17
BOPD with the larger  equipment.  The Wilcox  formation  throughout  this region
produces water along with the oil shortly after being placed on production.  The
amount of water  increases  in the later life of the  wells.  The Floyd A-1 well
should  produce  for another  10-20  years.  The Company  purchased a salt water
disposal well as part of the Big Island acreage that services the Floyd A-1 well
and will service the two additional wells that the Company is preparing to drill
on these properties.

     Big Island Field Continued Development. The Big Island and North Big Island
Oil  Fields of North  Central  Louisiana  are  located in  Rapides  and  LaSalle
Parishes,  Louisiana.  Production  from these two fields is  generated  from the
Wilcox formation of Eocene Age, and to a lesser degree from the lower Tuscaloosa
formation.  The Wilcox  formation will be the primary target of the  development
drilling program currently  planned by the Company.  Production in this area was
established  in 1950 by Union  Production  Company,  (now known as Pennzoil) who
along with Crow Drilling & Production  Company,  were instrumental in developing
these  two large  fields.  There  are 11  productive  sands in each of these two
fields that have  produced  nearly 30 million  barrels of oil to date.  The post
production history,  as well as the exploration  techniques employed in drilling
these fields by Union  Production  Company,  and the recent infield  drilling by
other  independent  companies,  suggest  only a  fraction  of the oil  has  been
discovered in or recovered  from these two fields.  The concept of  horizontally
infield  drilling  can be employed in this  program as well as the  targeting of
untapped reservoirs in this region of established production. These efforts will
concentrate  on  horizontally  drilling an up dip  direction  to wells that have
watered out and drilling a channel-sand  type reservoir  between wells that have
ceased to produce because of premature water encroachment.

     The first well will be a 5,800'  straight  hole test  drilled to the Hudson
Sand  reservoir,  where the electric log and side wall cores will  determine the
net feet of oil pay in the drainage area of one or two  horizontal  wells.  This
evaluation  well is also  drilled to  complete  in the 5,200 Foot Sand that also
produced in offset,  down dip of this field. An additional well may be necessary
during the producing life of the first straight hole to  economically  drain the
entire  remaining  reserves in this sand.  The initial  straight  hole well will
evaluate  the net oil  thickness  and other data for the first  horizontal  well
project,  and  the  requirement  for a  second  horizontal  well  later  in  the
productive life of the first horizontal well drilled.

     West Lake Arthur  Field:  This is a 352 acre oil  producing  property  that
Cambridge  Energy has under  lease in  Jefferson  Davis  Parish,  Louisiana . It
includes an existing well bore that the Company intends to recomplete in new pay
zones shown on the logs, as well as one new "sidetrack" well the Company intends
to drill.  The first project will be the Edgewater (TGT) Morgan  Plantation No.1
well as a re-entry and re-completion  project of a previously produced well. The
well was originally  drilled by Tennessee Gas  Transmission in 1957. It is still
completed in the original perforated interval and no additional work was done to
alter this completion  since that date. The Company has purchased this well bore
and  equipment  from the land  owners and owns the rights to the  reservoirs  to
13,500' by virtue of the lease agreement. A re-completion in this well bore will
be only one of the revenue streams  possible from the reservoirs under the lease
block owned by the Company in this field.  These  evaluations will be made after
this first well has been put on  production.  The  Edgewater  well bore has four
zones that are productive by either down dip production  history,  core analysis
and/or  log  analysis.  The  re-entry  and  workover  will  provide  a five year
moratorium of severance taxes that amounts to 12.5% of gross sales.

                                       9
<PAGE>

     The second well is planned to be directionally drilled from the plugged and
abandoned  Miller,  Morgan  Plantation  No. 1 well.  The well is planned to be a
replacement  well  to the  Tenneco,  Morgan  Plantation  well  that  experienced
collapsed casing after producing  428,683 barrels of oil from the 2nd Marg howei
Sand.  This  directionally  drilled  well is  planned  so as to have  1,050'  of
horizontal displacement at the top of the 1st Marg howei Sand as seen at 12,775'
in the Tenneco,  Morgan  Plantation  No.1 well.  The new well should be slightly
high to the 2nd Marg howei completion in the Tenneco well.  Tenneco had proposed
a  recompletion  in the 1st Marg howei Sand but the collapsed  casing  prevented
this operation.  The fault block of interest has excellent productive sands from
the log analysis and production histories of down dip wells. The Company expects
to  confirm  four to five  productive  zones with this well.  The  re-entry  and
sidetrack   procedure,   as  compared  to  drilling  a  new  vertical  hole,  is
approximately  half the  price  and  will  provide  a five  year  moratorium  of
severence  taxes also which will pay for the cost of drilling and completing the
well. An additional development well will have to be considered if the sidetrack
hole confirms the presence of reserves as calculated from the study of the older
well logs in this fault block.

     Cambridge Bayou Blue Field: This is an 80 acre oil producing  property that
the Company has under lease in Iberville  Parish  Louisiana.  This  property has
three wells that are candidates for re-entry so as to workover and recomplete in
zones that were not  produced  to their  economic  limits  and were  prematurely
plugged  during low oil prices in the 1960s.  In addition to 7 productive  sands
that have  produced  oil and gas in the  past,  there  are also  other  possible
productive  zones that have never been  produced.  One of the wells on the lease
can be converted into a salt water disposal well.

     The Cambridge  Energy lease is located on the  southwest  flank of the salt
dome.  The  structural  oil and gas  trapping  mechanism  is  truncation  of the
sediments  against the  impermeable  salt plug in the deeper  sediments  and the
shallow  sediments are draped  across the top of the salt plug.  Salt domes have
historically  been the most  prolific oil fields in South  Louisiana.  The Bayou
Blue Field is not an exception. The Cambridge lease has previously produced over
1.2 million barrels of oil.

     Cambridge  Energy's  approach to  re-developing  this field is to drill one
well up dip to the well known as the Grief  Brothers  No. 3 well and putting the
Grief  Brothers No. 3 well and the Grief  Brothers No. 4 well back on production
by re-entry into these existing well bores.  The Grief Brothers No. 2 well could
then be re-completed at a later date, depending upon production results from the
other wells. This project is projected to produce up to 250 BOPD and access over
1 million barrels of proven reserves.

     Cambridge  Arnaudville  Field.  This is a 312 acre  gas and  oil/condensate
property  Cambridge  Energy has under  lease in St.  Martin  Parish,  Louisiana.
Initial project plans call for two  development  wells to be drilled to reserves
that remain in reservoirs that previously produced down dip from the prospective
development well location or shown productive by log analysis.  The initial well
is a 10,400' normal pressured  Tweedel Sand test updip from a well that produced
form the  Nodosaria  3 Sand as well as from the  Homeseekers  "B" and 9,400 Foot
Sand.  The main  objective is the Nodosaria 3 Sand that produced in the down dip
Slick Oil Company,  Singleton No. 1 well.  Cores from the down dip well indicate
an oil level in this  reservoir  that will  result in a low gas-oil  ratio.  The
production  from this down dip well was  probably  curtailed  as the bottom hole
location at this  Nodosaria 3 Sand depth was drilled  very near the fault.  This
project is projected to produce up to 4.6 BCF of gas and 172 thousand barrels of
oil.

     The initial  development  well is to be drilled so as to be 1,650 feet east
of the Singleton No. 1 well.  The up dip bottom hole location in the Nodosaria 3
Sand should  provide 20 feet of net gas/oil  condensate  pay with a possible oil
level.  There  should be no water level as the well should be 22-25 feet high as
mapped.  The Tweedel  Sand should log 15-40 feet of pay with a possible  oil and
water level. The second development well,  Arnaudville Field-West Prospect is to
the west in a  downthrown  fault  block.  This is a well to be drilled  updip to
reservoirs  that  produced in this separate  fault block.  These sands will also
produce gas condensate reserves.

                                       10
<PAGE>
     The SE Crescent  Field:  There is existing  well,  the A.  Wilbert's  Sons,
L.L.C.  No 1. well was drilled by Bishop  Petroleum,  Inc. in January 1982.  The
well logged pay in the Miogyp.  Sand and a Repeat  Formation Test confirmed this
zone to be gas  productive.  This horizon  produces oil in the  Sullivan's  Lake
Field to the west as well as in two established fields to the east of the Bishop
well. The low gas prices at this time may have been a determining  factor in the
well not being  completed in this gas sand.  The reservoir may very well have an
oil column  downdip.  The Anson,  S. Jones No. 1 well is 2,500' away and 70 feet
downdip to the Bishop  well.  A  mid-point  between  these two wells  provides a
reservoir area of  approximately  296 acres from the re-entry well. The drainage
acreage to the downdip well,  where the highest known water level is logged,  is
485 acres.  The log of the Bishop Petroleum well indicates 8-10 feet of gas. The
downdip  well  indicates  10-15 feet of sand that appears to be more porous than
the  well  to be  re-entered  which  could  provide  for  more  accumulation  of
hydrocarbons than indicated.  The Miogyp. Sand is the objective sand in the well
at 11,652 feet which a sand at 22 feet of thickness.

     Linda A, C/G Field: This field is located on Mainland, Irian Jaya Province,
Indonesia.  The field was  originally  discovered and operated by PERTAMINA Unit
EP-V in 1971. In 1977, the Linda-A  structure had been found and drilled and oil
was located at the LDA-2 well. Further exploration was carried out in 1979 and a
total of eleven  wells  have been  drilled  in the Linda A reef.  In 1982 , more
extensive exploration activity resulted in the discovery of Textularis II in the
Linda-C structure.  Well LDC-2 was drilled in 1985 and oil was found in the Kais
formation.  A total of five wells have been  drilled.  The Linda-G reef was also
discovered in 1985 and a total of 4 wells have been drilled.

     Sele  Field:  This  field is  located on  Mainland,  Irian  Jaya  Province,
Indonesia. The field was originally discovered in 1954 with the drilling of well
S-41 to a  depth  of 769  meters.  Further  development  resulted  in two  other
successful wells, S-44 and S-48. Seismic surveys were conducted in 1973 and 1975
and SS-1 was  drilled.  Located  to the  southern  part of the Sele  reef,  SS-1
produced  oil. In 1978 a drilling  program was  initiated  and three  successful
wells were added  including:  SP-1,  SP-3 and SP-4.  Sele Field is pinnacle reef
development  built-up on the Kais  platform  limestone.  A total of 12 wells are
currently  producing.  The Sele reservoir of Cambridge's Sabaku Field is located
on Salawati  Island,  Irian Jaya Province,  Indonesia.  The field was originally
discovered by Phillips  Petroleum  Indonesia in 1974. Well TBN-1 was drilled and
tested at a rate  approaching  12,186 BOPD.  After an eight-day test in December
1975 the water cut increased from dry oil to 80% which could have been caused by
the high rate of production. The field has not been developed further.

     Salawati  Fields A, C, E, and F:  These  fields  are  located  on  Salawati
Island, Irian Jaya Province,  Indonesia.  The field was originally discovered by
Phillips  Petroleum  Indonesia in 1975.  The Salawati A structure  was the first
commercial oil field on the island. Oil production started in November 1977 from
wells A-1,  A-2, A-3 and A-4.  Currently  three wells A-2, A-7 and A-8 are still
producing.  A major  amount of the  field's  oil has been  produced by well A-2,
which still  dominates  present  production.  This field has no initial free gas
cap.  The area extent of the field is  approximately  182 feet.  Oil  production
commenced in Salawati C Field from well C-2 in November  1977. The well is still
producing with gas lift system at a rate of  approximately  225 bopd. This field
has no initial  free gas cap. The field area extent is  approximately  180 acres
with a range  net  oil  column  thickness  of 225  feet.  Salawati  E Field  was
discovered  when drilling E-1 and has been producing  since January 1972. Two of
the five wells are still producing with Reda pumps at a rate of approximately 30
to 40 BOPD and  fluid  production  of about  800-1200  Barrels  of Fluid Per Day
(BFPD) per well. The field area extent is  approximately  171 acres.  Salawati F
Field  commenced  production of well F-1 in December 1977. The well was the only
well  drilled  and is still  producing  with gas lift.  The field area extent is
approximately 33 acres with a range net oil pay thickness of 177 feet.

Item 3.  Legal Proceedings

     The Company is not a party to any pending material legal proceeding. To the
knowledge  of  management,  no federal,  state or local  governmental  agency is
presently  contemplating any proceeding against the Company. To the knowledge of
management,  no director,  executive  officer or  affiliate of the Company,  any
owner of record or beneficially of more than 5% of the Company's common stock is
a party adverse to the Company or has a material interest adverse to the Company
in any proceeding.

                                       11
<PAGE>
Item 4.  Submission of Matters to a Vote of Security Holders.

     None

                                     PART II

Item 5.   Market for Registrant's Common Stock and Related Stockholder Matters

     (a) Market Information

     The Company's common stock is listed on the OTC Bulletin Board of the NASD,
and began  trading on November 24,  1997.  The high and low bid prices since the
quarter then ending March 31, 1999, are as follows:

Quarter Ending:

                                             Bid

                                    High              Low

March 31, 1998                      1 1/8              1 1/8
June 30, 1998                       1 7/8              1
September 30, 1998                  1 1/2              3/4
December 31, 1998                   1 1/16             .81
March 31, 1999                        7/8              5/16

     These bid prices were obtained from Prophet Information Services,  Inc. and
do not necessarily reflect actual transactions,  retail mark-ups,  mark-downs or
commissions. The transactions include inter-dealer transactions.

     (b) Holders

     As of March 31, 1999, the number of holders of the Company's  common shares
was 123.

     (c) Dividends

     There are presently no material  restrictions that limit the ability of the
Company to pay dividends on common stock. The Company has not paid any dividends
with respect to its common  stock,  and does not intend to pay  dividends in the
foreseeable future.



Item 6.  Management's Discussion and Analysis of Financial Condition
         And Results of Operation

     The Company is engaged in engaged in the  exploration  and  development oil
and natural gas reserves  through the  acquisition and development of properties
primarily with proven reserves.  The Company's ability to grow shareholder value
through growth of assets, earnings and cash flows if dependent on its ability to
acquire and development commercial quantities of oil and natural gas that can be
produced and marketed at a profit. Product prices,  primarily crude oil, dropped
significantly  during the Company's fiscal year. This drop is adversely affected
the  revenues  and cash flows of the  company as well as most  companies  in the
industry.  An additional  effect of this significant drop in prices has been the
reduction of  exploration  and  development  budgets of major oil  companies and
independents,  causing  reduction or  elimination  of new  ventures,  work force
reductions  and  reorganizations.  Such  changes may result in a decrease in the
ability of the Company to solicit  industry  partners to participate in projects
undertaken  by  Cambridge  Energy  Corporation  on a promoted  basis.  They have
resulted  in some delays by partners  in making  partner  contributions  putting
additional demands on the Company's cash flow.


     Although  product  prices  have  started to  recover,  company  budgets are
generally created on a fiscal year basis, so management  believes that a general
industry  wide recovery will take well into the first part of calendar year 2000
to achieve any meaningful levels.

                                       12
<PAGE>

     Company  management  has  used  this  period  to put in place  the  initial
elements of its growth  strategies so that it can maximize the positive  results
from the recovery of the industry including:

     1.   To actively  pursue  acquisition of significant  producing  properties
          with development  potential which can be exploited with lower cost and
          with lower risk than unproven prospects;

     2.   The selection,  engineering review and rework of workover prospects on
          existing properties to maximize production from existing assets;

     3.   To  continue  to  solicit  institutional  and  industry  partners  for
          promoted  transactions as well as increasing equity and long financing
          to support this expanded level of projects and operations;

     4.   To significantly add to the company's technical  capabilities  through
          the selective addition of technical  personnel and the development and
          acquisition of advanced reservoir and engineering software.


     Management  believes  that this  plan will  position  the  Company  to take
advantage of  opportunities  that it expects to occur as the  industry  recovers
from the recent  period of low prices.  While  management  believes  that it has
worked toward the successful  completion of this plan, there can be no assurance
that the  intended  results  will be achieved or that funds will be available to
accomplish the plan.

Results of Operations

Twelve  months  ended March 31, 1999  compared to twelve  months ended March 31,
1998

     The Company recorded net loss of $843,493 for the year ended March 31, 1999
(FY99)  down  from  $1,016,531  for the year  ended  March  31,  1998.  Revenues
increased to $562,026  over $127,  188 the previous  year due to the increase in
U.S. production and to service income and international  production added toward
the end of the fiscal year..  General and  Administrative  expenses increased to
$1,078,481  over  $237,528  for the  previous  year due to  increases in current
depreciation expenses to $181,340 and consulting fees to $421,600.  The increase
in  consulting  fees was  substantially  the  result  of  increased  engineering
activities associated with acquisitions and proposed acquisitions and to certain
consulting fees paid to a former director as part of a settlement package.

     The Company realized some added gains in production  during the year due to
added production period resulting in the following:

                                       Percent              Year Ended
                                       Increase              March 31,
                                      (Decrease)       1998           1999
                                      ----------       ----           ----
Gas Production (Mcf)                     137%         84,460         200,985
Oil Production (bbls)                    115%          1,927           4,163
Barrel of Oil Equivalent               95.76%         19,241          37,660
Average Price of Gas (per mcf)          (9.8%)         $2.06           $1.86
Average Price of Oil (per bbls)        (31.3%)        $17.20          $11.93


     Based  upon  increases  in the  prices  of oil and gas since the end of the
fiscal year,  management expects that prices received for the Company's products
during the next fiscal year will be higher.

     Due to industry  conditions and resulting delays in partner  contributions,
the Company's  drilling program proceeded at a slower pace than expected through
the engineering phase and the Company expects to have drilling  operations under
this program  underway  during the third quarter of the current  fiscal year. In
addition to the SE Crescent  Property added during FY99, the Company  expects to
increase it acquisition activity during the current fiscal year.

                                       13
<PAGE>

Liquidity:

     The Company  expects to finance  its future  acquisition,  development  and
exploration  activities  through cash flow from  operating  activities,  various
means of corporate  and project  finance and through the issuance of  additional
securities.  In addition the Company  expects to continue to subsidize  drilling
activities through the sale of participation to industry partners on a promoted
basis,  whereby the Company working interests in reserves and production greater
than its proportionate share capital costs.

     During Fiscal Year 1999 the Company raised additional capital in the amount
of $335,000 through private sale of preferred  shares.  Based upon  acquisitions
currently in  negotiation,  the Company  expects to begin  negotiations  for the
placement  of a  significant  financial  institution  credit  facility  or other
structured  debt  facility  during the coming  fiscal year.  This would  provide
additional  funds for expansion to consistent with the Company growth  strategy.
Although  management  believes that this will be accomplished during the current
fiscal year,  there can be no assurance that such a facility will be forthcoming
or that  sufficient  funds will be  available  to meet the  requirements  of the
Company's growth strategy.


Material Commitments for Capital Expenditures:

     The Company  has made no material  commitments  for these  future  projects
other than to acquire and pay for the respective  leases.  Each drilling  and/or
rework project is stand-alone and although the Company is in constant discussion
with  prospective   working  interest   partners  on  each  potential   project,
commitments  for the actual drilling or rework and site  preparation  operations
are generally not made for each project until the Company has received the funds
from its working interest  partners and the funds for its portion of the working
interest  are in place.  The leases the  Company  holds are  renewable  annually
unless "held by production". If the leased property has a producing well that is
providing royalty payments to the  leaseholders,  then annual lease payments and
renewals are not required.  Cambridge  Energy strives to accomplish the drilling
or rework planned for each property within the year first leased. When that does
not occur  however,  management  reviews the  potential of each  property as its
leases  come up for  renewal  and makes a decision  whether or not to renew each
lease in light of the Company's business planning at that time. During FY99, the
Company had $181,340 in lease depreciation expenditures.

     The  company has  committed  to provide  $750,000 in final  payment for the
purchase of Indonesian production now under contract, which was due on or before
January 4, 1999. The  transaction  was closed with the exchange of stock between
the Company and the owners of the company which owned the  production.  Although
the certain monies have been paid on behalf of the  transaction,  the Company is
obligated to pay additional amounts to the sellers as a part of the transaction.
The Company has under  negotiation  several  facilities  to provide  these funds
however, it does not have a commitment in place and there is no assurance when a
commitment will be forthcoming.


Item 7.  Selected Financial Data.

     The  necessay  financial  information  needed  is not  available  from  the
Company's  certified  public  accountant  due to  the  acquisition  of a  forein
subsidiary,  Intermega Energy,  PTE, LTD. Although Intermega was audited through
the previous fiscal year, the certified public accountant are still working with
Intermega to finish the audit of this current fiscal years financials.


Item 8.  Changes in and Disagreements with Accountants on Accounting
         And Financial Disclosure.

     None.


                                       14
<PAGE>
                                    PART III

Item 9.  Directors and Executive Officers of the Registrant

     (a) Identification of Directors and Executive Officers.

     (1)                  (1)                (2)                (3)
     Name                 Age               Term*              Served

Perry Douglas West                         Elected             Since
Chairman and CEO           52              Annually          Inception



     *All   directors   hold  office  until  the  next  annual  meeting  of  the
stockholders and the election and  qualification of their  successors.  Officers
are elected  annually by the Board of Directors  and serve at the  discretion of
the Board.

     The  following is a brief  description  of the business  background  of the
directors and executive officers of the Company:

     Perry Douglas West  co-founded the Company in April 1996, and has served as
Chairman  of  the  Board,  President  and  Chief  Executive  Officer  since  its
inception.   He  was  Chairman  and  Chief  Executive   Officer  of  Interactive
Technologies  Corporation (ITC) from 1995 until January 1998. ITC is a developer
and producer of television, interactive television and interactive digital media
programming.  Mr. West  co-founded  American  Financial  Network in 1985,  which
operated a national computerized mortgage loan origination network. He served as
Executive Vice  President/Director  and General  Counsel of this publicly traded
company from 1985 to 1991.  He was also  previously a partner in the  consulting
firm of  Cambridge  Equity,  Inc.,  which  structured  oil and gas  projects  in
Indonesia.  Mr.  West has  practiced  law in Florida  since  1974,  representing
various business institutions in the financial,  computer, natural resources and
general business  industries and  international  transactions.  He was graduated
with a Bachelor of Arts degree from The  Florida  State  University  in 1968 and
with a Juris Doctorate degree from The Florida State  University  College of Law
in 1974.

     There are no other significant employees of the business,  and there are no
family  relationships  among  the  directors,   executive  officers  or  persons
nominated or chosen by the Company to become  directors  or executive  officers.
None of the Company's directors,  executive officers or nominees for such office
have been involved in any legal  proceedings  related to bankruptcy of an entity
where  they held such  positions;  nor  charged  or  convicted  in any  criminal
proceedings;  nor  subject  to any order,  judgment,  or decree  permanently  or
temporarily  enjoining,   barring,  suspending  or  other  wise  limiting  their
involvement in any type of business, securities or banking activities; nor found
in any manner  whatsoever  to have  violated a federal  or state  securities  or
commodities law.


                                       15
<PAGE>
Item 10.  Executive Compensation

     Cash Compensation:

     The following table sets forth the aggregate cash  compensation paid by the
Company for services  rendered during the periods indicated to its directors and
executive officers:


                           SUMMARY COMPENSATION TABLE


Name & Position         Fiscal Year      Salary      Bonus    Other Compensation

Perry D. West               1997(1)        -0-        -0-               -0-
Chairman/CEO                1998(2)     $40,615       -0-             $45,000
                            1999(3)     $55,385       -0-               -0-


1)April 9, 1996 (Inception) - March 31, 1997

2)April 1, 1997 - March 31, 1998

3)April 1, 1998 - March 31, 1999

     Mr.  West  has an  Executive  Compensation  Agreement  in  effect  with the
Company,  approved by the Board of Directors.  This Agreement is for a five year
term,  and is  incentive  based over and above the basic  salary of $150,000 per
annum for Mr. West.  Salary  increases are based on gross revenue  achievements.
The first two full fiscal years' gross  revenue  goals for salary  increases are
$4,000,000,  and  $8,000,000  respectively.  Third,  Fourth and Fifth year gross
revenue  goals will be set by the Board of Directors  prior to the  beginning of
those years.  Additional  benefits  include  medical and dental coverage for Mr.
West and family;  disability  coverage;  vacation;  automobile  or allowance for
automobile; and a death benefit. Mr. West is also entitled to participate in the
Company's Key Employee Stock Option Plan which has been  authorized by the Board
of Directors but not implemented as of the fiscal year ended March 31, 1998. Mr.
West will also be entitled to  participate  in the Company's  401(K)  retirement
plan,  which the  Company  intends to offer to its  employees.  This  employment
contract  may be  terminated  for cause,  and it  provides  for  payments to the
executive  in the  event  there is a change  of  control  of the  Company  which
adversely affects their employment.  Mr. West has agreed to defer all or partial
salary and other benefits from his compensation  agreements  during fiscal years
ended March 31, 1998 and 1999.

     The following  table sets forth the options  granted  during the last three
fiscal years to each of the directors and executive officers:

 Option/SAR Grants in Last Fiscal Year   (Individual Grants):

                       Number of       Percent of total
                       Securities        Options/SARs
                       Underlying          granted to                Exercise or
                      Options/SARS       employees in    base price   Expiration
        Name            Granted           fiscal year    ($/Share)       date
       -----          ------------     ----------------  ----------  -----------

Perry D. West          1,000,000             16.7           $ .50      6/9/02
                       1,000,000             16.7           $1.00      6/9/02
                       1,000,000             16.7           $1.50      6/9/02

Lee M. Payne(*)        1,000,000             16.7           $ .50      6/9/02
                       1,000,000             16.7           $1.00      6/9/02
                       1,000,000             16.7           $1.50      6/9/02

     *Mr. Payne has released these rights. (See Item 12 below)

     No options  granted to the directors and executive  officers were exercised
during the fiscal year ended March 31, 1998 and 1999.

                                       16
<PAGE>
Item 11.   Security Ownership of Certain Beneficial Owners and Management

         (a)      Security Ownership of Certain Beneficial Owners

--------------------------------------------------------------------------------
(1)            (2)                      (3)                      (4)
Title of       Name and Address         Amount and Nature        Percent of
Class          of Beneficial Owner      of Beneficial Owner      Class
--------------------------------------------------------------------------------

Common       Lee M. Payne               Former Executive Vice
             1295 Rockledge Drive       President/Director
             Rockledge, Florida 32955   3,192,393 Shares*        38.3


         (b)      Security Ownership of Management

         The  following  table sets forth the share  holdings  of the  Company's
directors and executive  officers as of March 31, 1998, with these  computations
based upon 8,334,786  shares of common stock being  outstanding,  and no options
granted being exercised.
--------------------------------------------------------------------------------
(1)            (2)                      (3)                      (4)
Title of       Name and Address         Amount and Nature        Percent of
Class          of Beneficial Owner      of Beneficial Owner      Class
--------------------------------------------------------------------------------

Common       Perry Douglas West         Chairman and CEO         38.3
             P.O. Box 1656              3,192,393 Shares*
             Cocoa, Florida 32923

Common       Lee M. Payne
             1295 Rockledge Drive
             Rockledge, Florida 32955   3,192,393 Shares**       38.3

Common       Officers and Directors
             as a Group                 6,384,786 Shares         76.6

* Mr. West has  options to purchase  1,000,000  shares of the  Company's  Common
Stock at $.50; 1,000,000 shares at $1.00; and 1,000,000 shares at $1.50 any time
within sixty months of June 9, 1997 when the options were granted.

**After  Mr.  Payne,  a former  officer and  director  of the company  resigned,
several  agreements  were entered  into  between the Company,  Mr. Payne and Mr.
West. The Company  entered into a share purchase  agreement with Mr. Payne dated
October 15, 1998,  for the  purchase of 1,000,000  shares of common stock over a
five year period for a total purchase price of $400,000. On October 7, 1998, the
Company  entered into a  Consulting  Agreement  with Mr. Payne  agreeing for the
payment  of  $5,000.00  per  month  for  consulting  services  up to a total  of
$400,000. It was agreed that all payments made to Mr. Payne under the Consulting
Agreement  referenced above would be considered payment of stock under the share
purchase  agreement.  In  addition,  Mr. Payne and Mr. West entered into a share
purchase  agreement  dated  October 15, 1998 for the  purchase by Mr. West of an
additional  2,000,000  shares of Mr.  Payne's  stock over a period of five years
with 500,000 shares to be purchased at $0.50 per share, 500,000 shares purchased
at $0.75 per share,  500,000  shares  purchased  at $1.00 per share and  500,000
shares purchased at $1.25 per share.


     Management has no knowledge of the existence of any arrangements or pledges
of the  Company's  securities  which may  result in a change in  control  of the
Company.

Item 12.  Certain Relationship and Related Transactions

     Shareholder  Loans.  During the fiscal  year  ending  March 31,  1999,  the
executive officer and director of the Company,  Mr. West, made shareholder loans
to the Company for operating expenses totaling $55,400,  for a total outstanding
shareholder  loans  of  $92,134.  These  amounts  were  initially  loaned  at no
interest, and will be reimbursed at such time as cash flow permits.

                                       17
<PAGE>

     Other   Material   Transactions.   With  the  exception  of  the  Executive
Compensation  Agreements and the Executive  Stock Option  Agreements of Mr. West
and Mr.  Payne,  there  have been no  material  transactions,  series of similar
transactions  or  currently  proposed  transactions  to which the Company or any
officer, director, their immediate families or other beneficial owner is a party
or has a material interest in which the amount exceeds $60,000.

                                     PART IV

Item 13.  Exhibits, Financial Statement Schedules  and Reports on Form 8-K












                                       18
<PAGE>

                                   SIGNATURES

     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.



                                    CAMBRIDGE ENERGY CORPORATION


Dated: August 20, 1999                 By:  /s/ Perry West
                                       -------------------
                                         Perry Douglas West
                                         Chairman and Chief Executive Officer





                                       19
<PAGE>