UNITED STATES
                      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, 1995
                         Commission file number 1-9735

                            BERRY PETROLEUM COMPANY
            (Exact name of registrant as specified in its charter)

              DELAWARE                                 77-0079387
(State of incorporation or organization) (I.R.S. Employer Identification Number)

                             28700 Hovey Hills Road
                             Taft, California 93268
         (Address of principal executive offices, including zip code)

      Registrant's telephone number, including area code: (805) 769-8811

Securities registered pursuant to Section 12(b) of the Act:

                                                         Name of each exchange
              Title of each class                         on which registered
     Class A Common Stock, $.01 par value                New York Stock Exchange
   (including associated stock purchase rights) 

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

       Indicate by check mark whether the registrant (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 [  ]

       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. [  ]

       As of  March 4, 1996, the registrant had 21,033,055 shares of Class A 
Common Stock outstanding and the aggregate market value of the voting stock
held by nonaffiliates was approximately $112,778,000.  This calculation is
based on the closing price of the shares on the New York Stock Exchange on
March 4, 1996 of $9.625.  The registrant also had 898,892 shares of Class B
Stock outstanding on March 4, 1996, all of which is held by an affiliate of
the registrant.

DOCUMENTS INCORPORATED BY REFERENCE


       Part III is incorporated by reference from the registrant's definitive 
Proxy Statement for its Annual Meeting of Shareholders to be filed, pursuant to
Regulation 14A, no later than 120 days after the close of the registrant's 
fiscal year.    
                                                               



                            BERRY PETROLEUM COMPANY 
                               TABLE OF CONTENTS

                                   PART I


Items 1 
  and 2.  Business and Properties. . . . . . . . . . . . . . . . . . . . .3

Item  3.  Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . .9

Item  4.  Submission of Matters to a Vote of Security Holders. . . . . .  9

          Executive Officers . . . . . . . . . . . . . . . . . . . . . . 10


                                   PART II

Item  5.  Market for the Registrant's Common Equity and 
           Related Stockholder Matters . . . . . . . . . . . . . . . . . 11

Item  6.  Selected Financial Data. . . . . . . . . . . . . . . . . . . . 12

Item  7.  Management's Discussion and Analysis of 
           Financial Condition and Results of Operations . . . . . . . . 13

Item  8.  Financial Statements and Supplementary Data. . . . . . . . . . 16

Item  9.  Changes in and Disagreements with Accountants 
           on Accounting and Financial Disclosure  . . . . . . . . . . . 34   

                                   PART III

Item 10.  Directors and Executive Officers of the Registrant . . . . . . 34

Item 11.  Executive Compensation . . . . . . . . . . . . . . . . . . . . 34

Item 12.  Security Ownership of Certain Beneficial 
           Owners and Management . . . . . . . . . . . . . . . . . . . . 34

Item 13.  Certain Relationships and Related Transactions . . . . . . . . 34

                                   PART IV

Item 14.  Exhibits, Financial Statement Schedules and 
           Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . . 35







                                       2 






                                   Part I


Items 1 and 2.  Business and Properties

Introduction

       Berry Petroleum Company ("Berry" or "Company"), is an independent energy
company engaged in the business of acquisition, exploration, exploitation, 
development, production and marketing of crude oil and natural gas.  The
Company was incorporated in Delaware in 1985 and has been a publicly held
company since 1987.  Berry's principal reserves and producing properties are
located in Kern County and Ventura County, California.  Information contained
in this report on Form 10-K reflects the business of the Company during the
year ended December 31, 1995.  The Company's corporate headquarters are located
on its Berry and Ewing lease in the southern portion of the Midway-Sunset
field, and management believes the current facilities are adequate.

       The Company's mission is to enhance shareholder value and achieve real 
asset growth.  To achieve this, Berry's corporate strategy is to acquire 
primarily proved reserves with exploitation potential and to increase its
proved reserves and production through further development of its existing
properties by application of enhanced oil recovery (EOR) methods, advanced
reservoir management and developmental drilling.  All of the Company's reserves
are located in the United States, and the Company continues to focus on 
opportunities in California and several select basins in the United States.  
While the Company has substantial working capital available for acquisitions, 
the Company will, as necessary, consider long-term debt or issuance of capital
stock to finance future purchases.

       Approximately 89% of the Company's proved reserves are located in the 
Midway-Sunset field in the San Joaquin Valley in California.  The majority of 
these reserves are on properties owned in fee.  Net production from this field 
in 1995 was 3.0 million barrels of oil equivalent (BOE) or 87% of the Company's
total 1995 BOE production.  The Midway-Sunset field contains predominantly
heavy crude oil (under 20 degrees API gravity), the production of which depends
substantially on steam injection.  Berry utilizes primary, cyclic steaming and
steam flooding recovery methods in this field.  Production from the Montalvo 
field in Ventura County, California, which represents approximately 8% of the 
proved reserves, utilizes primary recovery methods.

       Berry operates all of its principal oil producing properties.  Field 
operations include the initial recovery of the crude oil and its transport 
through treating facilities into storage tanks.  After the treating process is 
completed, which includes removal of water and solids by mechanical, thermal
and chemical processes, the crude oil is metered through L.A.C.T. (Lease
Automatic Custody Transfer) facilities and transferred into crude oil pipelines
owned by other oil companies.

Revenues

       The percentage of revenues by source for the prior three years is as 
follows:

     

                                                     1995    1994    1993

       Sales of oil and gas                           89%     95%     97%

       Interest and other income                      11%      5%      3%

See Berry's Statements of Operations and accompanying Notes thereto.



                                       3



Marketing

       The Company believes the market for its crude oil differs substantially 
from the oil market in the remainder of the country.  Two key factors are 
responsible for lower crude prices in California versus the Mid-Continent. The 
first is that the Company's crude oil is primarily lower gravity crude oil and 
must be heated or blended for transport to refineries.  In general, lower 
gravity crude oil results in lower yields of light products, such as gasoline 
and kerosene, in low conversion refineries.  Additional processing, such as 
coking and catalytic cracking, increases light product yields, but at a higher 
capital cost per barrel of crude oil refined.  The refiner or crude oil buyer 
generally pays lower prices for such crude oil, as reflected in lower posted
and spot prices.  The second factor, which may become less of a factor now that
Congress passed and the President signed Senate Bill S.395 to allow the export 
of Alaskan North Slope (ANS) crude oil to foreign countries, was that all ANS
crude oil production was required to go to or by the West Coast which reduced 
the price of both ANS and California crude oil.  This federally mandated policy
prevented free market prices on the West Coast, making California heavy crude 
price variations inconsistent with prevailing changes in market prices in other 
parts of the country.  The Company believes the repeal of the ban of ANS
exports may allow the Company and other West Coast producers to receive a fair
market price for their crude oil.  In addition, increased refining capacity of
heavy crude oil has strengthened prices of heavy crude oil on the West Coast.

       To provide additional market flexibility, the Company owns a blending 
facility located near its homebase properties.  The Company suspended the 
blending operations in December 1993 due to the high cost of natural gasoline, 
the improved demand for the Company's 13 degree heavy crude oil, and the 
narrowing margin between the posted price of the blended crude oil and the
heavy crude oil.  Up to approximately 5,000 barrels per day of the Company's
heavy crude oil can be blended with lighter crude oils and natural gasolines to
produce a blended crude oil of approximately 27 degree API gravity.  At times, 
this blending operation may allow the Company to improve the profit margin on 
the sale of its heavy crude oil.  Blending also allows the Company the option
to ship through common carrier pipelines and sell directly to refiners in the
Los Angeles basin, the San Francisco Bay area and the Mid-Continent.  No
blending occurred during 1995 or 1994.  The Company has the ability to resume
blending operations if warranted by market conditions.

Environmental and Other Regulations

       The operations of Berry are affected in varying degrees by federal, 
state, regional and local laws and regulations, including laws governing 
allowable rates of production, well spacing, air emissions, water discharges, 
endangered species, marketing, pricing, taxes and other laws relating to the 
petroleum industry.  Berry is further affected by changes in such laws and by 
constantly changing administrative regulations.

       Berry, as an owner and operator of oil and gas properties, is subject to
various federal, state, regional and local laws and regulations relating to 
discharge of materials into, and protection of, the environment.  These laws
and regulations may, among other things, impose liabilities on the owner or the
lessee in the case of leased properties for the cost of pollution clean-up 
resulting from operations, subject the owner or lessee to liability for 
pollution damages, require suspension or cessation of operations in affected 
areas, and impose restrictions on the injection of liquids into subsurface 
aquifers that may contaminate groundwater.  Such regulation has increased the 
length of time and cost of planning, designing, drilling, installing, operating
and abandoning the Company's oil and gas wells and other treating facilities.  

       The Company estimates that it spends approximately $.3 million on 
technical and managerial time annually to comply with environmental
regulations.  In addition, the Company spent approximately $.5 million for
capital projects, repairs and maintenance, and permits related to environmental
control facilities in 1995 and anticipates spending approximately $.5 million
for similar expenditures in 1996, with additional expenditures required in
future years.  The Company believes these are necessary business costs in
the domestic oil and gas industry.  Although environmental requirements do have
a substantial
                                                                 
                                   
                                       4

                                    
                                    
impact upon the energy industry, generally these requirements do not appear
to affect Berry to any greater or lesser extent than other companies in
California and in the domestic industry as a whole.  In most cases, foreign
produced crude oil enjoys a competitive advantage since foreign environmental
regulations of oil producing regions are not nearly as stringent or
comprehensive as in the United States and particularly California.

       Berry's properties in the Montalvo field have greater environmental
risks due to their location near the Pacific Ocean.  In Berry's case, a small
oil spill that endangers tidal waters could immediately involve significant
clean-up, regulatory investigation and penalties, any or all of which could
subject the Company to a significant financial burden.  In addition to
purchasing insurance to cover certain environmental risks, the Company
mitigates this exposure by the development and implementation of emergency
response and major oil spill prevention and contingency plans.  The Company
is also a contract associate member of Clean Seas, an organization with
significant experience and resources to contain and minimize the effects of
an oil spill.

       The Company experienced an oil spill due to a ruptured pipe on its West 
Montalvo field in December 1993 which required cleanup of the area directly 
around the pipe, an agricultural runoff pond and the nearby beach and ocean.  
Although 100% of the Montalvo field's wells and facilities are onshore, part of
the spilled crude oil was pumped into the ocean from the agricultural runoff 
pond.  The Company has initiated procedures and made operational improvements
to reduce the likelihood of a similar event.  A regulatory investigation is 
proceeding and the Company is potentially subject to fines and penalties (see

Item 3. "Legal Proceedings" and Note 12 to the Company's financial statements).

       The Company is not aware of any unrecorded environmental claims existing
at December 31, 1995 which would have a material impact on the Company's 
financial condition or results of operations.

Competition

       The oil and gas industry is highly competitive.  As an independent 
producer, the Company does not own any refining or retail outlets.  It has 
little control over the price it receives for its crude oil, and higher costs, 
fees and taxes assessed at the producer level cannot necessarily be passed
on to the Company's customers.  In acquisition activities, significant
competition exists since integrated companies, independent companies and
individual producers and operators are active bidders for desirable oil and
gas properties.  Although many of these competitors have greater financial
and other resources than the Company, Management believes that it is in a
position to compete effectively due to its low cost structure and strong
balance sheet.

 Employees

       The Company had 86 employees at December 31, 1995.

Oil and Gas Properties

       The Company spent a total of $.5 million on property acquisitions, $14.0
million on development programs (including $5.2 million on the purchase of the 
remaining 55% interest in the cogeneration facility) and $1.4 million on 
exploration programs in 1995.  The Company's 1996 budget for capital 
expenditures on development and exploration activities is $9.4 million of which
99% is earmarked for development.  As these activities are influenced by 
numerous factors, many of which are outside the Company's control, the actual 
expenditure level may vary considerably from budgeted levels.
 
       In 1995, the Company sold its Rincon properties which comprised 1,631 
acres and 15 producing wells, representing approximately 3% of its net daily 
production and 2% of its reserves.

       The principal oil and gas producing properties of Berry are located in 
Kern County and Ventura County, California.


                                       5



Development

       Homebase - Berry owns and operates working interests in thirteen 
properties containing 905 acres located in the southern portion of the Midway-
Sunset field.  The Company estimates these properties account for approximately 
76% of the Company's proved oil and gas reserves and approximately 78% of its 
current daily production.  The wells produce from an average depth of 
approximately 1200'.  These properties rely on thermally enhanced oil recovery 
methods, primarily cyclic steaming.  Nine of the thirteen properties are owned 
in fee and are not burdened by royalties.  These nine properties accounted for 
approximately 73% of Berry's average daily production during 1995 and represent
70% of the Company's proved oil and gas reserves.  Berry has a 100% working 
interest in all the Midway-Sunset properties it operates except one, where the
Company owns a 96.875% working interest.

       During 1995, a total of 41 development wells were drilled.  The
objective of this work was to maintain productive capacity and develop
additional reserves in the Company's single largest asset.  In December 1994,
the Company purchased the Alpine property and in 1995, 10 development wells
were drilled to exploit the undeveloped reserves of this property.  On the
Ethel D property, two wells were drilled and followup potential was
established.

       As of January 1, 1995, the Company owned a 45% interest in the 
cogeneration plant located on the homebase properties.  The purchase of the 
remaining 55% interest was completed in August of 1995 for a total cost of 
approximately $5.2 million.  Total steam cost savings through December 1995 
have exceeded $3 million due to favorable natural gas prices, operating 
efficiences and other factors existing in the latter part of 1995.  The
facility produces approximately 12,500 bbls/day of steam, all of which is
used in the steaming operations of the homebase properties. 
    
       Fairfield - Berry owns and operates approximately 1,824 acres in the 
northern portion of the Midway-Sunset field which account for approximately 13%
of the Company's proved oil and gas reserves and approximately 9% of its daily
production.  These properties rely on thermally enhanced oil recovery methods, 
primarily cyclic steaming and steam flooding. Berry's interests consist of four
fee properties comprising 1,009 acres and seven leases comprising 815 acres.  
The wells produce from an average depth of approximately 1200'.

       During 1995, the Company drilled two wells in the Potter sand and one 
well in the Mya sand reservoir.  In addition, one evaluation well was drilled 
and abandoned.  The Mya sand cyclic steam program was successful with four
wells returned to production.  An adjacent 480 acres, comprising the BLM
Sec 12 lease, was purchased in 1995 primarily for Mya development potential.

       Montalvo - Berry owns 100% of the working interest in six leases in 
Ventura County, California in the West Montalvo field.  Two of the six leases 
are owned by the State of California.  The Company estimates current proved 
reserves from West Montalvo account for approximately 8% of Berry's proved oil 
and gas reserves.  Total production from these leases, containing 8,563 acres, 
represents approximately 10% of Berry's total current daily oil and gas 
production.  The wells produce from an average depth of approximately 12,500'.

       Development, redrill and remedial well activities were postponed in 1994
while the Company assessed and implemented facility improvements.  Facility 
improvements were completed and five wells were reworked and returned to 
production in 1995.








                                       6


                                  



                                    
Exploration/Outside Operated

       The Company participated in the drilling of four exploratory wells in 
1995 in which it owned between 12.5% and 18.5% working interest in each well.  
The Company also participated in two workovers on outside operated properties.
                                                               
       Texas - In the Tyler prospect, the Company drilled the M.L. Collins #1 
well to 16,500' and encountered gas shows in three Wilcox intervals between 
13,000' and total depth.  Extensive testing of the three intervals did not
yield commercial production and the cost was written off as a dry hole in 1995.
The Company is presently attempting to farm out its remaining interest in the
prospect.  The Company farmed out its interest in the remaining acreage in the 
Lexi prospect.

       Louisiana - The Earl Chauvin #1 well, a 1993 discovery in the East Lake 
Boudreaux field, began producing water in the first quarter of 1995.  A
workover was completed during the year that was successful in bringing the well
back on production, but at a much lower rate.

       Nevada - In 1995, three exploratory wells were drilled and abandoned as 
dry holes.  The Company has one additional prospect well to drill to fulfill
its commitment in a six well multicompany exploratory program.

Oil and Gas Reserves

       Reserve Reports - The Company engaged DeGolyer and MacNaughton to 
estimate the proved oil and gas reserves of the Company for the years ended 
December 31, 1995 and 1994 for all of the Company's properties and for the year
ended December 31, 1993 for the Midway-Sunset field and certain properties 
located in other fields.  The reserves for 1993 for the Rincon and Montalvo 
fields were prepared by Babson and Sheppard.  These two firms (the Petroleum 
Engineers) were also asked to estimate the future net revenues to be derived 
from such properties.  Each of the Petroleum Engineers is an independent oil
and gas reserve engineering firm. In preparing their respective reports for
December 31, 1995, 1994 or 1993, each Petroleum Engineer reviewed and examined
such geological, economic, engineering and other data provided by the Company
as considered necessary under the circumstances applicable to each reserve
report.  Each Petroleum Engineer also examined the reasonableness of certain
economic assumptions regarding estimated operating and development costs and
recovery rates in light of economic circumstances as of December 31, 1995,
1994 and 1993.  For the Company's operated properties, reserve estimates are
filed annually with the U.S. Department of Energy.  Refer to the Supplemental
information about oil and gas producing activities (unaudited) for the
Company's oil and gas reserve disclosures.

Production

       The following table sets forth certain information regarding production 
for the years ended December 31, as indicated:


                                                  1995      1994      1993
                                                                         
       Net Annual Production(1):
        Oil (Mbbls)                              3,277     3,250     3,617
        Gas (Mmcf)                                 611       793       771
       Average Sales Price:
        Oil (per bbl)                           $13.56    $11.61    $11.43
        Gas (per mcf)                             1.50      1.87      1.96
       Average Production Cost (per BOE)(2)       5.41      6.28      6.35
                                                                         
                                                 
       (1)  Net production represents production owned by Berry and produced to
            its interest, less royalty and other similar interests.  All oil
            and gas produced, other than lease fuel needs, is sold at the well
            site.  Berry does not refine any of its production.
                                                                         
       (2)  Equivalent oil and gas information is at a ratio of 6,000 cubic
            feet of natural gas to one barrel (bbl) of oil.
                                                                         
                                                                         
                                       7


Acreage and Wells

       At December 31, 1995, the Company's properties accounted for the 
following developed and undeveloped acres:


                             Developed Acres         Undeveloped Acres
                                                      
                             Gross       Net         Gross         Net
                              
       California            6,175     6,051         6,846       6,846        
       Nevada                    -         -        55,920       9,247
       Texas                   840       277         9,120       2,889
       Other                 1,130       204         1,173         293
                            ------    ------        ------      ------         
                             8,145     6,532        73,059      19,275        
                            ======    ======        ======      ======
       Gross acres represent all acres in which Berry has a working interest; 
net acres represent Berry's aggregate working interests in the gross acres.   

       Berry currently has 1,551 gross oil wells (1,537 net) and 22 gross gas 
wells (7 net).  Gross wells represent the total number of wells in which Berry 
has a working interest.  Net wells represent the number of gross wells 
multiplied by the percentages of the working interests owned by Berry.  One or
more completions in the same bore hole are counted as one well.  Any well in 
which one of the multiple completions is an oil completion is classified as an 
oil well.

Drilling Activity

       The following table sets forth certain information regarding Berry's 
drilling activities for the periods indicated:


                                 1995           1994           1993
                            Gross    Net   Gross     Net  Gross     Net
                                    
       Exploratory Wells
       Drilled:
        Productive              0   0.0        0     0.0      3     0.7
        Dry (1)                 4   0.7        4     0.8      3     0.5
       Development Wells
       Drilled:
        Productive             44  44.0       14    14.0     18    18.0
        Dry (1)                 1   1.0        0     0.0      0     0.0
       Total Wells Drilled:
        Productive             44  44.0       14    14.0     21    18.7
        Dry (1)                 5   1.7        4     0.8      3     0.5
                                    
(1)    A dry well is a well found to be incapable of producing either oil or
       gas in sufficient quantities to justify completion as an oil or gas
       well.

As of March 4, 1996, no exploratory wells were being drilled.
                          
                      
                                   
                                   
                                   
                              
                                  
                                       8



Title and Insurance

       The Company is not aware of any defect in the title to any of its 
principal properties.  Notwithstanding the absence of a recent title opinion or
title insurance policy, the Company believes it has satisfactory title to these
properties, subject to such exceptions as the Company believes are customary
and usual in the oil and gas industry and which the Company believes will not 
materially impair its ability to recover the proved oil and gas reserves or to
obtain the resulting economic benefits.

       The oil and gas business can be hazardous, involving unforeseen 
circumstances such as blowouts or environmental damage.  To address the hazards
inherent in the oil and gas business, the Company maintains a comprehensive 
insurance program.

Item 3. Legal Proceedings

       On December 25, 1993, a crude oil spill was discovered on the Company's 
West Montalvo field in Ventura County, California.  The Company estimates that 
the total discharge was approximately 2,100 barrels.  The Company is aware that
certain governmental authorities are currently investigating the circumstances 
surrounding the spill.  The Company paid $.6 million to settle all potential 
state criminal claims against the Company in August 1994.  The Company is 
working on dealing with all other potential matters related thereto.  As of the
date of this report, no actions have been filed against the Company in 
connection with the spill.                                                    

       The Company was in a dispute with University Cogeneration Partners Ltd., 
1985-1, regarding certain costs related to the cogeneration facility
operations.  The Company was a minority owner in this partnership of which
the major asset was the cogeneration facility located on the Company's homebase
properties.  The Company purchased the remaining interest in the partnership
in August 1995 and, in connection therewith, both parties agreed to dismiss
all disputed claims.

       The information related to certain issues which have been appealed to
the U.S. Court of Appeals (Ninth Circuit) is set forth in Note 9 to the
Company's financial statements.
 

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

None.
















                                    
                                       9
                                    







                              EXECUTIVE OFFICERS

       Listed below are the names, ages (as of December 31, 1995) and positions 
of the executive officers of Berry and their business experience during at
least the past five years.

       JERRY V. HOFFMAN, 46, President and Chief Executive Officer since May 
1994 and President and Chief Operating Officer from March 1992 until May 1994.  
Mr. Hoffman was added to the Board of Directors in March 1992.  Mr. Hoffman
held the Senior Vice President and Chief Financial Officer positions from 
January 1988 until March 1992.  Mr. Hoffman, CPA, has held a variety of other 
positions with the Company and its prior subsidiaries or successors since 
February 1985.

       DONALD A. DALE, 49, Controller since December 1985.  Mr. Dale, CPA, was 
the Controller for Berry Holding Company from September 1985 to December 1985.

       RALPH J. GOEHRING, 39, Chief Financial Officer since March 1992 and 
Manager of Taxation from September 1987 until March 1992.  Mr. Goehring, CPA,
is also the Assistant Secretary for Berry Petroleum Company.

       CHESTER L. LOVE, 61, Vice President of Engineering since March 1994 and 
Manager of Engineering from May 1992 to March 1994.  Mr. Love, a registered 
petroleum engineer, was previously a Vice President of Consulting for
Scientific Software-Intercomp from 1979 to 1992.

       KENNETH A. OLSON, 40, Corporate Secretary since December 1985 and 
Treasurer since August 1988.  Mr. Olson, CPA, has held a variety of other 
positions with the Company and its prior subsidiaries or successors since July
1985.

       MICHAEL R. STARZER, 34, Manager of Corporate Development since April 
1995.  Mr. Starzer, a registered petroleum engineer, was with Unocal from
August 1983 to May 1991 and from August 1993 to April 1995.  Mr. Starzer was
an engineering consultant and worked with the California State Lands Commission
from May 1991 to August 1993.

       STEVEN J. THOMAS, 45, Manager of Production since March 1993, joined the 
Company's engineering department in September 1992.  Mr. Thomas, a registered 
petroleum engineer, was an engineering and petroleum consultant from 1990 to 
1992 and was employed by Chevron USA from 1979 to 1990 in various drilling, 
production and facilities engineering positions.

















                                                                    

                                      10





                                   PART II


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

       Shares of Class A Common Stock (Common Stock) and Class B Stock,
referred to collectively as the "Capital Stock", are each entitled to one
vote and 95% of one vote, respectively.  Each share of Class B Stock is
entitled to a $1.00 per share preference in the event of liquidation or
dissolution.  Further, each share of Class B Stock is convertible into one
share of Common Stock at the option of the holder.

       In 1989, the Company adopted a Stockholder Rights Agreement and declared
a dividend distribution of one such Right for each outstanding share of Capital
Stock on December 22, 1989.  Each share of Capital Stock issued after December 
22, 1989 includes one Right.  The Rights expire on December 8, 1999. See
Note 7 of Notes to the Financial Statements.

       The Company's Class A Common Stock is listed on the New York Stock 
Exchange under the symbol "BRY".  The Class B Stock is not publicly traded.
The market data and dividends for 1995 and 1994 are shown below:


                                    
                                                              Cash
                                    Low       High         Dividends
       1995
       First Quarter             $ 8 3/4    $ 10           $     .10
       Second Quarter              9          10 7/8             .10
       Third Quarter               9 3/8      10 5/8             .10
       Fourth Quarter              9 7/8      10 7/8             .10

       1994
       First Quarter             $ 8        $  9 7/8       $     .10
       Second Quarter              8          10 3/4             .10
       Third Quarter               8 7/8      10 1/4             .10
       Fourth Quarter              9          11 3/8             .10

       The number of holders of record of the Company's Common Stock and Class 
B Stock as of March 4, 1996 was approximately 1,048 and 1, respectively.

       The Board of Directors' policy is to declare and pay dividends quarterly
in March, June, September and December.  The dividend level may change as it
is subject to Board approval, and such approval is influenced by the price of
crude oil, capital commitments and satisfactory financial results.

       Dividends declared on 4,366,400 shares of certain Common Stock are 
restricted, whereby 37.5% of the dividends declared on these shares are paid by 
the Company to the surviving member of a group of individuals, the B group, for
as long as this remaining member shall live.
                                  
                                 
                                    
                                    
                                    
                                    
                                      11
                                    
                                    
                                    




Item 6.  Selected Financial Data

       The following table sets forth certain financial information with
respect to the Company and is qualified in its entirety by refrence to the
historical financial statements and notes thereto of the Company included
in Item 8, "Financial Statements and Supplementary Data".  The statement of
operations and balance sheet data included in this table for each of the five
years in the period ended December 31, 1995 was derived from the audited
financial statements and the accompanying notes to those financial statements
(in thousands except per share and per barrel data):                          
  
                                1995      1994      1993      1992      1991

Statement of Operations Data:

Operating revenues:
  Sales of oil and gas       $ 45,773  $ 39,451  $ 42,843  $ 49,598   $ 43,439
  Blending, net                    12        87       265    (1,262)    (1,156)

Operating costs 
 (excluding DD&A and 
 exploratory dry hole costs)   18,264    21,224    23,790    20,931     20,575 

General and administrative 
 expenses (excluding DD&A)      4,578     5,118     5,999     5,511      3,840
Depletion, depreciation &                 
 amortization (DD&A)            6,847     7,270     9,983     8,123      5,373
Net income (loss)              12,203    (1,129)       32    10,115     16,597
Net income (loss) 
per share (1)                     .56      (.05)        -       .46        .77 
                                                     
Cash dividends per share          .40       .40       .55       .60        .60
Weighted average number of 
 shares outstanding            21,932    21,932    21,926    21,915     21,539 

Balance Sheet Data:
 Working capital             $ 36,506  $ 38,273  $ 40,418  $ 50,642   $ 54,420
 Shareholders' equity          92,060    88,632    98,323   109,690    113,204
 Total assets                 117,722   118,254   135,159   140,140    145,594 

Operating Data:
 Cash flow from operations     17,070    14,579    10,957    22,169     18,521
 Capital expenditures          15,072     6,934    13,983    12,180     14,028
 Average sales price 
  per barrel of oil             13.56     11.61     11.43     12.83      12.44
 Average production cost 
  per BOE                        5.41      6.28      6.35      5.43       6.03 

Production:
 Oil (Bbls)                     3,277     3,250     3,617     3,683      3,336
 Gas (Mcf)                        611       793       771     1,029        466
 Total (BOE)                    3,379     3,382     3,746     3,855      3,414 


Proved reserves:
 Oil (Bbls)                    77,071    75,996    72,078    72,434     71,054
 Gas (Mcf)                      5,983     6,530     5,476    10,003     11,772
 Total (BOE)                   78,068    77,084    72,991    74,101     73,016 

(1) Less than $.01 per share in 1993.







                                      12





Item 7.  Management's Discussion and Analysis of Financial Condition and 
         Results of  Operations                             
                   
       The following discussion provides information on the results of 
operations for the three years ended December 31, 1995 and the financial 
condition, liquidity and capital resources as of December 31, 1995.  The 
financial statements and the notes thereto contain detailed information that 
should be referred to in conjunction with this discussion.

       The profitability of the Company's operations in any particular 
accounting period will be directly related to the average realized prices of
oil and gas sold, the type and volume of oil and gas produced and the results
of acquisition, development and exploration activities.  The average realized
prices of oil and gas will fluctuate from one period to another due to world 
market conditions and other factors.  The California crude oil prices are 
especially sensitive since a significant portion of California's crude oil
needs are met by imports from Alaska.  The aggregate amount of oil and gas
produced may fluctuate based on development and exploitation of oil and gas
reserves pursuant to current reservoir management plans.  Production rates,
steam costs, labor and maintenance expenses are expected to be the principal
influences on operating costs.  Accordingly, the results of operations of the
Company may fluctuate from period to period based on the foregoing principal
factors, among others.

                             Results of Operations

       The Company returned to profitability in 1995, earning net income of 
$12.2 million, up significantly from a net loss of $1.1 million in 1994 and net
income of $32,000 in 1993.  This significant improvement was due primarily to 
higher oil prices, lower steam costs due to the acquisition of the remaining 
interest in the cogeneration facility, a 1995 gain on the sale of the Rincon 
properties, the reduction of exploratory dry hole costs in 1995, and the 
impairment of properties and oil spill costs recorded in 1994 and 1993 with no
comparable charge in 1995.     

                                              1995      1994     1993

Production - BOE Per Day                     9,258     9,266   10,261
Average Sales Price - Per BOE               $13.48    $11.60   $11.43
Operating Cost - Per BOE                      5.41      6.28     6.35
DD&A - Per BOE                                1.88      1.96     2.47

       Operating income from producing operations was $21.2 million in 1995,
up 83% and 114% from $11.6 million and $9.9 million in 1994 and 1993,
respectively.  This improvement was due primarily to higher oil prices and
reduced operating costs.

       The average sales price received per BOE during 1995 of $13.48 was 16% 
and 18% higher than the prices received in 1994 and 1993, respectively.  Oil
and gas production in 1995 was comparable to 1994, but down 10% from 1993.  On
November 1, 1995, the Company sold its Rincon properties which accounted for 
approximately 283 BOE/day of production. In addition, the Company shut in a 
number of marginal wells in 1994 and reduced steaming operations from 1993 
levels on certain marginally economic properties.

       To protect the Company's revenues from potential price declines, 
effective August 1, 1995, the Company entered into a bracketed zero cost collar
hedge contract with a California refiner for a term of 18 months related to 
approximately 22% of its crude oil production.  The posted price of the 
Company's 13 degree API gravity crude oil was used as the basis for the hedge. 
There is no initial cost to the Company and there will be no material financial
impact unless crude oil prices increase or decrease significantly from current 
levels.  A similar contract for an additional 11% of the Company's crude 
production with a 12 month term was entered into in early 1996.

       Operating costs per BOE in 1995 declined 14% from 1994 to $5.41 due 
largely to a reduction in steam costs which have historically represented the 
largest component of operating costs to the Company.  As part of the Company's 
continuing effort to reduce operating costs, the Company purchased the
remaining 55% interest in the cogeneration plant which provides steam to the
Company's homebase properties located in the Midway-Sunset field.  In addition,
the Company increased production from the Montalvo field during 1995 and sold
its Rincon properties on November 1, 1995, both of which incurred higher
operating costs relative to the other properties operated by the Company.
Due to these events and the Company's ongoing cost reduction program, operating
costs per BOE continued to decline to $4.63 in the fourth quarter of 1995
from $5.19 and $5.80 in the third and second quarters of 1995, respectively.
                                    
                                      13
       

       DD&A per BOE declined to $1.88 in 1995 from $1.96 and $2.47 in 1994 and
1993, respectively.  This decline was due primarily to the lower depletable 
basis of the Company's assets resulting from the impairment, dry hole and 
abandonment charges recorded in 1994.

       On November 1, 1995, the Company sold its Rincon properties located in 
Ventura County, California for approximately $5.8  million plus certain 
reimbursements, which resulted in a pre-tax gain of approximately $3.1 million. 
Net daily production from the six leases represented approximately 3% of the 
Company's 1995 production levels.  This property was considered non-core, was 
expensive to operate and would have required significant capital outlays to 
maximize the property's value.

General

       Interest income in 1995 was $2 million, up from $1.6 million and $1.9 
million in 1994 and 1993, respectively, due primarily to higher average
interest rates on invested cash balances in 1995.

       General and administrative expenses were $4.6 million in 1995, down 10% 
and 23% from $5.1 million and $6 million incurred in 1994 and 1993, 
respectively.  The Company is focused on cost reduction and incurred lower 
payroll related costs due to attrition, the consolidation of certain 
administrative functions and lower medical costs. 

       The Company's effective income tax rate in 1995 was 37%.  The pre-tax 
losses incurred in 1994 and 1993 resulted in effective tax benefits of 42% and 
102%, respectively.  The most important factor affecting 1994 and 1993 was the 
impact of certain tax benefits, primarily enhanced oil recovery credits and 
percentage depletion, as applied to the pre-tax losses in those years.

       In the fourth quarter of 1995, the Company adopted Financial Accounting 
Standard (SFAS) No. 121,  "Accounting for the Impairment of Long-Lived Assets 
and for Long-Lived Assets to Be Disposed Of".  This adoption resulted in no 
charges to the Company's financial statements for 1995, and is not
significantly different than the Company's impairment policy in effect prior
to the adoption.

             Financial Condition, Liquidity and Capital Resources
                                    
       Working capital at December 31, 1995 was $36.5 million, down from $38.3 
million and $40.4 million at December 31, 1994 and 1993, respectively. Cash
flow provided by operating activities of $17.1 million was up 17% and 55% from
$14.6 million and $11.0 million in 1994 and 1993, respectively.  Cash flow was
higher in 1995 due to higher oil prices and lower operating costs due primarily
to the purchase of the cogeneration facility in 1995.  The Company sold its
Rincon properties in 1995 for an additional $5.8 million in cash plus certain 
reimbursements.  However, working capital declined 5% due to capital 
expenditures of $15.1 million incurred during the year, which included 
approximately $5.2 million on the purchase of the remaining 55% interest in the 
Company's cogeneration facility, $4.8 million on the further development of the 
homebase properties, including the drilling of 45 additional development wells, 
and $1.9 million on the further development of the Montalvo field, including 
the conversion of two wells to a long-stroke rod pump system and the return to 
production of four wells on the PRC 735 lease.  In 1995, the Company paid $8.8 
million in dividends to its shareholders.  In addition, $2.9 million was paid
in federal and state income taxes resulting from an adverse judgment by the
U.S. Tax Court against the Company (see Note 9 to the Company's financial 
statements).








                                      14


                                    
                                    
       The Company had a $1 million Revolving Credit and Term Loan Agreement 
with a major California bank until early 1996.  There were no outstanding 
borrowings under this line.  The Company is working on obtaining a new Revolving
Credit/Term Loan Facility which, when completed, may be used for future 
acquisitions or other corporate purposes.

       The total proved reserves at December 31, 1995 were 78.1 million BOE, up 
from 77.1 million BOE at December 31, 1994 and 73.0 million BOE at December 31, 
1993.  Although the Company produced 3.4 million BOE during the year and sold 
its Rincon properties, the Company saw an increase in reserves due primarily to 
the further development of the Company's PRC 735 lease, the development of the 
Alpine lease purchased in the fourth quarter of 1994, the acquisition of the
USL 12 lease in the Midway-Sunset field, higher oil prices and lower estimated 
future operating costs.  The 1995 development program (excluding the purchase 
of the remaining interest in the cogeneration facility) and USL 12 lease 
acquisition were successful in adding proved reserves, replacing 182% of 
production at an average cost of $1.71 per BOE.  The Company's estimated future
pre-tax discounted cash flow, using a 10% discount rate, increased 17% and 516% 
to $308.4 million at December 31, 1995 from $263.9 million at December 31, 1994 
and $50.1 million at December 31, 1993, respectively.

                              Future Developments

       In 1996, the Company plans to adopt the disclosure option of SFAS No. 
123, "Accounting for Stock-Based Compensation".

       Senate Bill S.395  allowing the export of ANS crude oil has been passed 
by Congress and signed by the President, and is currently undergoing limited 
public hearings.  Because of this legislation, the Company expects that a 
larger portion of this crude oil will be sold in markets other than California 
beginning in the second quarter of 1996.  The long term impact may be to reduce 
the differential between crude oil prices on the West Coast and other parts of 
the country.

       The Company currently sells the electricity produced by its cogeneration 
facility to a large California-based utility under a contract (Standard
Offer 2) which determines the electricity payment based upon electrical
capacity and by energy provided.  This contract will expire on January 15,
1997.  Under current law, the Company has the right to enter into a similar
contract (Standard Offer 1) upon expiration with the same utility at the same
energy payment but a lower capacity payment.  The Company is analyzing its
options with respect to future electricity sales.  Management believes that
the deregulation in the electrical utility industry (currently targeted for
1998 in California) may provide opportunities for the Company to maximize the
benefits of its cogeneration facility.  However, failure to achieve a similar
or better contract than the existing contract will likely result in higher
operating costs related to steam generation than exist currently.

       A portion of the natural gas purchases made by the Company for use 
primarily in its steaming operations is subject to an existing long-term 
transportion agreement with a California utility.  The resulting transportation 
charges related to the gas obtained are significantly above current prevailing 
market rates.  The agreement will expire in April 1997 and the Company expects 
to realize a reduction in operating costs related to this event in 1997 and 
beyond.

       On February 10, 1996, the President signed into law a bill which 
authorizes the sale, within two years, of the Elk Hills Naval Petroleum Reserve 
located in Kern County, California.  The Company believes the sale may result
in a significant concentration of the ownership of the light crude oil used as
blending stock for the heavy crude oil produced in the San Joaquin Valley.  If 
such concentration were to occur, it is possible that the lack of light oil 
availability could have an adverse impact on the marketability and prices 
received for this heavy crude oil.

                              Impact of Inflation
                                    
       The impact of inflation on the Company has not been significant in
recent years because of the relatively low rates of inflation experienced
in the United States.



                                      15


                                    

I
tem 8.  Financial Statements and Supplementary Data

                            BERRY PETROLEUM COMPANY
                       Index to Financial Statements and
                              Supplementary Data


                                                                   Page

Report of Coopers & Lybrand L.L.P., Independent Accountants  . . .  17

Balance Sheets at December 31, 1995 and 1994 . . . . . . . . . . . .18

Statements of Operations for the
  Years Ended December 31, 1995, 1994 and 1993   . . . . . . . . . .19        

Statements of Shareholders' Equity
  for the Years Ended December 31, 1995, 1994 and 1993 . . . . . . .20

Statements of Cash Flows for the
  Years Ended December 31, 1995, 1994 and 1993 . . . . . . . . . . .21

Notes to the Financial Statements. . . . . . . . . . . . . . . . . .22

Supplemental Information About Oil & Gas Producing Activities. . . .32


Financial statement schedules have been omitted since they are either not 
required, are not applicable, or the required information is shown in the 
financial statements and related notes.




















                                      16





                                    

                       REPORT OF INDEPENDENT ACCOUNTANTS



To the Board of Directors
Berry Petroleum Company

We have audited the accompanying balance sheets of Berry Petroleum Company as 
of December 31, 1995 and 1994, and the related statements of operations, 
shareholders' equity and cash flows for each of the three years in the period 
ended December 31, 1995.  These financial statements are the responsibility of 
the Company's management.  Our responsibility is to express an opinion on these 
financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing 
standards.  Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement.  An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.  We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present fairly, in 
all material respects, the financial position of Berry Petroleum Company as of 
December 31, 1995 and 1994, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles.



COOPERS & LYBRAND L.L.P.


/s/ Coopers & Lybrand L.L.P.

February 21, 1996

Los Angeles, California

















                                      17






                           BERRY PETROLEUM COMPANY
                                Balance Sheets
                          December 31, 1995 and 1994
                  (In Thousands Except Share Information)


                                                         1995          1994
                     ASSETS

Current assets:
 Cash and cash equivalents                           $  18,759      $   7,466
 Short-term investments available for sale              15,695         27,617
 Accounts receivable                                     8,414          9,471
 Deferred income taxes                                   1,175          3,315
 Prepaid expenses and other                              1,157          1,073
                                                       -------        -------
          Total current assets                          45,200         48,942

Oil and gas properties (successful efforts basis),      
 buildings and equipment, net                           72,042         66,915
Other assets                                               480          2,397
                                                       -------        -------  
                                                     $ 117,722      $ 118,254
                                                       =======        =======

                     LIABILITIES AND SHAREHOLDERS' EQUITY
                                    
Current liabilities:
 Accounts payable                                    $   3,086      $   5,913
 Accrued liabilities                                     3,912          4,637
 Federal and state income taxes payable                  1,696            119 
                                                       -------        -------
 Total current liabilities                               8,694         10,669


Deferred income taxes                                   16,968         18,953

Contingencies (Note 12)

Shareholders' equity:
 Preferred stock, $.01 par value; 
   2,000,000 shares authorized;
   no shares outstanding
 Capital stock, $.01 par value:                              -              -
    Class A Common Stock, 
      50,000,000 shares authorized;
      21,033,055 shares issued and outstanding             210            210
    Class B Stock, 1,500,000 shares authorized;
      898,892 shares issued and outstanding 
      (liquidation preference of $899)                       9              9
Capital in excess of par value                          52,850         52,852
Retained earnings                                       38,991         35,561
                                                       -------        -------
     Total shareholders' equity                         92,060         88,632
                                                       -------        -------
                                                     $ 117,722      $ 118,254
                                                       =======        =======

The accompanying notes are an integral part of these financial statements.



                                
                                    
                                      18



     
                            BERRY PETROLEUM COMPANY
                            Statements of Operations
                 Years ended December 31, 1995, 1994 and 1993
                     (In Thousands Except Per Share Data)


                                          1995        1994        1993   
Revenues:
 Sales of oil and gas                  $  45,773  $  39,451    $  42,843
 Interest                                  2,040      1,616        1,893
 Gain (loss) on sale of assets             3,073        113       (1,100)
 Other income, net                           304        155          460
                                         -------    -------      -------
                                          51,190     41,335       44,096 
                                         -------    -------      -------
Expenses:
 Operating costs                          18,264     21,224       23,790
 Depreciation, depletion & amortization    6,847      7,270        9,983
 Impairment of properties                      -      2,915        2,911
 Oil spill costs                               -      1,344        2,004
 Exploratory dry hole costs                2,012      5,414          788
 General and administrative                4,578      5,118        5,999
                                         -------    -------      -------
                                          31,701     43,285       45,475 
                                         -------    -------      -------
Income (loss) before income taxes         19,489     (1,950)      (1,379)
Provision (benefit) for income taxes       7,286       (821)      (1,411)
                                         -------    -------      -------
Net income (loss)                      $  12,203  $  (1,129)   $      32 
                                         =======    =======      =======
Net income (loss) per share            $     .56  $    (.05)   $       - 
                                         =======    =======      =======

Weighted average number of shares 
   of capital stock used to calculate 
   earnings per share                     21,932     21,932       21,926 
                                         =======    =======      =======














The accompanying notes are an integral part of these financial statements.

                                   
                                 
                                    
                                      19




                            BERRY PETROLEUM COMPANY
                      Statements of Shareholders' Equity
                 Years Ended December 31, 1995, 1994 and 1993
                     (In Thousands Except Per Share Data)

                     Capital Stock    Capital in       
                                       Excess of     Retained    Shareholders'
                   Class A   Class B   Par Value     Earnings       Equity
                               
Balances at 
 January 1, 1993   $  210   $    9    $  51,977     $  57,494     $  109,690 

Stock options 
 exercised              -        -          664             -            664
 Cash dividends 
 declared -      
 $.55 per share         -        -            -       (12,063)       (12,063) 
Net income              -        -            -            32             32
                   ------   ------      -------       -------        -------
Balances at 
 December 31, 1993    210        9       52,641        45,463         98,323 


Stock options 
 expired                -        -          211             -            211
Cash dividends 
 declared -
 $.40 per share         -        -            -        (8,773)        (8,773)
Net loss                -        -            -        (1,129)        (1,129)  
                   ------   ------      -------       -------        ------- 
Balances at 
 December 31, 1994    210        9       52,852        35,561         88,632 


Stock retired           -        -           (2)            -             (2)   
Cash dividends 
 declared -
 $.40 per share         -        -            -        (8,773)        (8,773)
 Net income             -        -            -        12,203         12,203
                   ------   ------      -------       -------        -------
Balances at 
 December 31, 1995 $  210   $    9    $  52,850     $  38,991     $   92,060 
                   ======   ======      =======       =======        =======
















The accompanying notes are an integral part of these financial statements.


                                      20




                            BERRY PETROLEUM COMPANY
                            Statements of Cash Flows
                  Years Ended December 31, 1995, 1994 and 1993
                                 (In Thousands)

Cash flows from operating activities:          1995       1994        1993
 
 Net income (loss)                         $ 12,203    $ (1,129)   $     32
 Depletion, depreciation and amortization     6,847       7,270       9,983
 (Gain) loss on sale of assets               (3,073)       (113)      1,100
 Exploratory dryhole costs                    1,990       5,090         170
 Impairment of properties                         -       2,915       2,911
 Increase (decrease) in deferred income                     
  tax liability                              (1,985)       (762)      1,536
 Other, net                                     (50)        504        (377)  
                                            -------     -------     -------
Net working capital provided by 
 operating activities                        15,932      13,775      15,355 

Decrease (increase) in current assets 
 other than cash, cash equivalents and 
 short-term investments                       3,113       7,256      (9,248)
 Increase (decrease) in current liabilities  (1,975)     (6,452)      4,850 
                                            -------     -------     -------
Net cash provided by operating activities    17,070      14,579      10,957 
                                            -------     -------     -------
Cash flows from investing activities:
  Capital expenditures                      (15,072)     (6,934)    (13,983)
  Proceeds from sale of assets                6,242         327         413
  Purchase of short-term investments         (3,078)    (30,524)    (15,560)
  Maturities of short-term investments       15,000      29,874      30,290
  Other, net                                    (96)       (540)       (610)
                                            -------     -------     -------
Net cash provided by (used in) 
 investing activities                         2,996      (7,797)        550 
                                            -------     -------     ------- 
Cash flows from financing activities:

Dividends paid                               (8,773)     (8,773)    (12,063)
Proceeds from exercise of stock options           -           -         664 
                                            -------     -------     -------
Net cash used in financing activities        (8,773)     (8,773)    (11,399)
                                            -------     -------     -------
Net increase (decrease) in cash and          
 cash equivalents                            11,293      (1,991)        108
Cash and cash equivalents at 
 beginning of year                            7,466       9,457       9,349 
                                            -------     -------     -------
Cash and cash equivalents at 
 end of year                               $ 18,759    $  7,466    $  9,457 
                                            =======     =======     =======
Supplemental disclosures of 
 cash flow information:

Interest paid                              $     12    $      5    $      8 
                                            =======     =======     =======
Income taxes paid                          $  5,554    $    484    $    765 
                                            =======     =======     =======



The accompanying notes are an integral part of these financial statements.
                            
                                    
                                      21







                            BERRY PETROLEUM COMPANY

                      Notes to the Financial Statements

1.  General

       The Company is an independent energy company engaged in the acquisition,
exploration,  exploitation, development, production, and marketing of crude oil
and natural gas.  All of the Company's oil and gas reserves are located in the 
United States, with 89%  of the reserves located in the Midway-Sunset field in 
the San Joaquin Valley in California.  Approximately 97% of the Company's 
production is crude oil, which is principally sold to other oil companies for 
processing in refineries located in California.

       The preparation of financial statements in conformity with generally 
accepted accounting principles requires management to make estimates and 
assumptions that affect the reported amounts of assets and liabilities and 
disclosure of contingent assets and liabilities at the date of the financial 
statements and the reported amounts of revenues and expenses during the 
reporting period.  Actual results could differ from those estimates.

2.  Summary of significant accounting policies

Cash and cash equivalents

       Cash equivalents consist principally of commercial paper and money
market funds.  The Company considers all highly liquid investments purchased
with a remaining maturity of three months or less to be cash equivalents. Cash
equivalents of $13.4 million and $6.0 million at December 31, 1995 and 1994, 
respectively, are stated at cost, which approximates market.

Short-term investments

       All short-term investments are classified as available for sale.  Short-
term investments consist principally of United States treasury notes, corporate
notes, state and local municipal bonds and auction market preferred stock with 
remaining maturities of more than three months at date of acquisition.  Such 
investments are stated at cost, which approximates market.  The Company
utilizes specific identification in computing realized gains and losses on
investments sold.  For the three years ended December 31, 1995, realized and
unrealized gains and losses were insignificant to the financial statements.
United States treasury notes with an aggregate market value of $.6 million are
pledged as collateral to the California State Lands Commission as a performance
bond on the Company's Montalvo properties.

Oil and gas properties, buildings and equipment

       The Company accounts for its oil and gas exploration and development 
costs using the successful efforts method.  Under this method, costs to acquire
mineral interests in oil and gas properties, to drill and complete development 
wells and drill and complete exploratory wells that find proved reserves are 
capitalized.  Exploratory dryhole costs and other exploratory costs, including
geological and geophysical costs, are charged to expense when incurred.  The 
costs of carrying and retaining unproved properties are also expensed when 
incurred.  Depletion of oil and gas producing properties is computed using the
units-of-production method.  The estimated costs, net of salvage value, of 
plugging and abandoning oil and gas wells and related facilities are accrued 
using the units-of-production method and are taken into account in determining
depletion, depreciation and amortization expense.

       Buildings and equipment are recorded at cost.  Depreciation is provided 
on a straight-line basis over estimated useful lives ranging from 5 to 30 years
for buildings and improvements and 3 to 10 years for machinery and equipment.  
When assets are sold, the applicable costs and accumulated depreciation are 
removed from the accounts and any gain or loss is included in income.  
Expenditures for maintenance and repairs are expensed as incurred.

                                      22
                                    
                                    
                                    
                                    
                            BERRY PETROLEUM COMPANY
                       Notes to the Financial Statements
                       
2.  Summary of significant accounting policies (cont'd) 

       In the fourth quarter of 1995, the Company adopted Statement of 
Financial Account Standards (SFAS) No. 121, "Accounting for the Impairment of 
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."  This change 
had no effect on the Company's financial statements.  Pursuant to this
standard, assets are grouped at the lowest level for which there are
identifiable cash flows.  If it is determined that the book value of long-lived
assets cannot be recovered by estimated future undiscounted cash flows, they
will be written down to fair value.

Steam Costs

       The costs of producing steam by the cogeneration plant are recorded as
an operating expense of the Company. Proceeds received from the sale of
electricity produced by the plant are reported as a reduction to operating
costs in the Company's financial statements.

Income Taxes

       Income taxes are provided based on the liability method of accounting 
pursuant to SFAS No. 109, "Accounting for Income Taxes".  The provision for 
income taxes is based on pretax financial accounting income.  Deferred tax 
assets and liabilities are recognized for the future expected tax consequences 
of temporary differences between income tax and financial reporting and 
principally relate to differences in the tax bases of assets and liabilities
and their reported amounts, using enacted tax rates in effect for the year
in which differences are expected to reverse.  If it is more likely than not
that some portion or all of a deferred tax asset will not be realized, a
valuation allowance is recognized.

Earnings per share

       Earnings per share is computed by dividing net income by the weighted 
average number of capital shares and dilutive common stock equivalents, if any,
outstanding during the year.

Reclassifications

       Certain reclassifications have been made to the 1994 and 1993 financial 
statements to conform with the 1995 presentation.

3.  Fair value of financial instruments

       Financial instruments consist of cash and short-term investments, whose 
carrying amounts are not materially different from their fair values because of
the short maturity of those instruments.  The Company's short-term investments 
available for sale at December 31, 1995 consist primarily of United States 
treasury notes (71%) and corporate notes (29%).  All of the short-term 
investments at December 31, 1995 mature in one year or less.

       To protect the Company's revenues from potential price declines, 
effective August 1, 1995, the Company entered into a bracketed zero cost collar
hedge contract with a California refiner for a term of 18 months related to 
approximately 22% of its crude oil production.  The posted price of the 
Company's 13 degree API gravity crude oil was used as the basis for the hedge.
There is no initial cost to the Company and there will be no material financial
impact unless crude oil prices increase or decrease significantly from current 
levels.  A similar contract for an additional 11% of the Company's crude oil 
production with a 12 month term was entered into in early 1996.


                                    
                                      23


                                    
                            BERRY PETROLEUM COMPANY
                       Notes to the Financial Statements

4.  Concentration of Credit Risks

       The Company sells oil, gas and natural gas liquids to pipelines and 
refineries.  Credit is extended based on an evaluation of the customer's 
financial condition.  For the three years ended December 31, 1995, the Company 
has experienced no credit losses on the sale of oil, gas and natural gas 
liquids.

       The Company places its temporary cash investments with high credit 
quality financial institutions and limits the amount of credit exposure to any 
one financial institution.  For the three years ended December 31, 1995, the 
Company has not incurred losses related to these investments.

       The following summarizes the accounts receivable balances at December
31, 1995 and sales activity with significant customers for each of the years
ended December 31, 1995, 1994 and 1993 (in thousands):

                           Accounts                    Sales
                          Receivable       For the Year Ended December 31,
        Customer       December 31, 1995    1995        1994        1993
                                
           A               $  1,372      $ 12,641     $ 16,027    $ 16,747
           B                    961        12,918       11,319      11,686
           C                    724         9,214            -           -
           D                      -         5,265            -           -
                            -------       -------      -------     -------
                           $  3,057      $ 40,038     $ 27,346    $ 28,433    
                            =======       =======      =======     =======

       The loss of any of these customers could have a temporarily adverse 
impact on the Company's revenues.

5.  Oil and gas properties, buildings and equipment

       Oil and gas properties, buildings and equipment consist of the following
at December 31 (in thousands):

                                                     1995           1994
Oil and gas:
  Proved properties:
    Producing properties, including 
     intangible drilling costs                     $ 55,202       $ 56,216
    Lease and well equipment                         75,470         67,232
  Unproved properties                                   162            383
                                                    -------        -------
                                                    130,834        123,831
  Less accumulated depletion, depreciation          
   and amortization                                  61,456         59,909
                                                    -------        -------
                                                     69,378         63,922   
                                                    -------        -------
Commercial and other:
  Land                                                  151            151
  Buildings and improvements                          3,734          3,806
  Machinery and equipment                             4,026          3,969
                                                    -------        -------
                                                      7,911          7,926   
Less accumulation depreciation                        5,247          4,933
                                                    -------        -------
                                                      2,664          2,993
                                                    -------        -------
                                                   $ 72,042       $ 66,915
                                                    =======        =======
                                    
                                      24



                            BERRY PETROLEUM COMPANY
                       Notes to the Financial Statements

5.  Oil and gas properties, buildings and equipment (cont'd)

       The following sets forth costs incurred for oil and gas property 
acquisition, exploration and development activities, whether capitalized or 
expensed (in thousands):



                                          1995       1994       1993

Acquisition of properties              $    503   $  1,023   $      -
Exploration                               1,420      1,701      3,336
Development                              14,034      4,678     10,958
                                        -------    -------    -------
                                       $ 15,957   $  7,402   $ 14,294
                                        =======    =======    =======

Results of operations from oil and gas producing and exploration activities

       The results of operations from oil and gas producing and exploration 
activities (excluding blending operations, corporate overhead and interest 
costs) for the three years ended December 31 are as follows (in thousands):



                                          1995       1994       1993

Sales to unaffiliated parties          $ 45,773    $ 39,451   $ 42,843
Production costs                        (18,264)    (21,224)   (23,790)
Exploration expenses                     (2,012)     (5,414)      (788)
Depletion, depreciation and 
 amortization                            (6,354)     (6,627)    (9,143)
                                        -------     -------    ------- 
                                         19,143       6,186      9,122
Income tax expenses                      (6,433)     (1,723)    (2,225)
                                        -------     -------    -------
Results of operations from producing 
 and exploration activities            $ 12,710    $  4,463   $  6,897
                                        =======     =======    =======
 
       In 1994, the Company recorded an impairment writedown of $2.9 million 
related to its Poso Creek and Kern Front properties and a producing well at 
Rincon.  Similarly, in 1993 the Company recorded an impairment writedown of 
$2.9 million related to certain properties in East Texas which were
subsequently assigned to another company in December 1994. 

6.  Debt obligations

       The Company had a $1 million Revolving Credit and Term Loan Agreement 
(Agreement) with a major California bank which was terminated in early 1996.
At December 31, 1995, the Company had no outstanding borrowings or letters of 
credit under the Agreement.







                                      25
                                    



                                    
                                    
                            BERRY PETROLEUM COMPANY
                       Notes to the Financial Statements
                                    
7.  Shareholders' equity

       Shares of Class A Common Stock (Common Stock) and Class B Stock,
referred to collectively as the "Capital Stock" are each entitled to one vote
and 95% of one vote, respectively.  Each share of Class B Stock is entitled
to a $1.00 per share preference in the event of liquidation or dissolution.
Further, each share of Class B Stock is convertible into one share of Common
Stock at the option of the holder.
     
       In December 1989, the Company adopted a Stockholder Rights Agreement and
declared a dividend distribution of one Right for each outstanding share of 
Capital Stock.  Each Right, when exercisable, entitles the holder to purchase 
one one-hundredth of a share of a Series A Junior Participating Preferred
Stock, or in certain cases other securities, for $38.00.  The exercise price
and number of shares issuable are subject to adjustment to prevent dilution.
The Rights would become exercisable, unless earlier redeemed by the Company,
10 days following a public announcement that a person or group has acquired,
or obtained the right to acquire, 20% or more of the outstanding shares of
Common Stock or, 10 business days following the commencement of a tender or
exchange offer for such outstanding shares which would result in such person
or group acquiring 20% or more of the outstanding shares of Common Stock,
either event occurring without the prior consent of the Company.

       The Rights will expire in December 1999 or may be redeemed by the
Company at 1 cent per Right prior to that date unless they have theretofore
become exercisable.  The Rights do not have voting or dividend rights, and
until they become exercisable, have no diluting effect on the earnings of the
Company.  250,000 shares of the Company's Preferred Stock have been designated
Series A Junior Participating Preferred Stock and reserved for issuance upon
exercise of the Rights.

       The Company issued no shares in 1995 or 1994 through its stock option 
plans.  During 1993, 44,536 shares were issued through these plans.

       Dividends declared on 4,366,400 shares of certain Common Stock are 
restricted, whereby 37.5% of the dividends declared on these shares are paid by
the Company to the surviving member of a group of individuals, the B Group, as 
long as this remaining member shall live.

8.  Transactions with affiliates

       The University Cogeneration Partners, Ltd. 1985-1, a limited
partnership, was formed in 1985 to finance the construction of a cogeneration
plant on the Company's properties.  The Company also committed to purchase
the steam generated by the plant and supply the natural gas to fuel the plant.
 At December 31, 1994  the receivable due from the Cogeneration Partnership for
natural gas purchases, net of the steam sales to the Company, was $.8 million. 
The Company owned approximately 45% of the partnership and its investment of 
$1.9 million was accounted for at cost.  On August 1, 1995, the Company 
purchased the remaining 55% interest in the cogeneration plant for
approximately $5.2 million.  The total cost of the cogeneration plant is
included in lease and well equipment at December 31, 1995.  Amounts paid by
the Company for the steam in 1995 (through July), 1994 and 1993 were
$2.6 million, $4.6 million and $4.3 million, respectively.


                                      26

                                    
                            BERRY PETROLEUM COMPANY
                       Notes to the Financial Statements
                                    
9.  Income taxes

       The provision (benefit) for income taxes consists of the following (in 
thousands):

                                      1995      1994       1993

Current:
  Federal                           $ 5,089   $   158    $  (873)
  State                               2,042       (56)       (74)
                                    -------   -------    -------
                                      7,131       102       (947)
                                    -------   -------    -------
Deferred:
  Federal                               828    (1,077)      (369)
  State                                (673)      154        (95)      
                                    -------   -------    -------  
                                        155      (923)      (464)             
                                    -------   -------    -------
                                    $ 7,286   $  (821)   $(1,411)
                                    =======   =======    =======

       The current deferred tax assets and liabilities are offset and presented
as a single amount in the financial statements.  Similarly, the noncurrent 
deferred tax assets and liabilities are presented in the same manner.  The 
following table summarizes the components of the total deferred tax assets and 
liabilities before such financial statement offsets.  The components of the net
deferred tax liability are as follows (in thousands):



                                                   Dec. 31,         Dec. 31,
                                                    1995              1994
Deferred tax asset
  Federal benefit of state taxes                  $  1,756          $  1,334
  Differences between financial reporting
    and tax bases of assets acquired                     -             3,226
  Net operating loss carryforwards                     171             1,470
  Credit/deduction carryforwards                       634             3,037
  Other, net                                           368               712
  Valuation allowance                                    -            (3,089)
                                                   -------           -------
                                                     2,929             6,690
                                                   -------           -------
Deferred tax liability                             (15,195)          (16,567)
  Depreciation and depletion                        (3,122)           (3,795)
  State taxes, net                                    (405)           (1,966)
                                                   -------           -------
  Other, net                                       (18,722)          (22,328)
                                                   -------           -------
 
 Net deferred tax liability                       $(15,793)         $(15,638) 
                                                   =======           =======






                                      27




                            BERRY PETROLEUM COMPANY
                       Notes to the Financial Statements

9.  Income taxes (cont'd)

       Income taxes computed by applying U.S. statutory federal rates to income
(loss) before income taxes are reconciled to the provision (benefit) for income
taxes as follows (in thousands):


                                               1995       1994         1993

Tax (benefit) computed at statutory 
 federal rate                               $  6,821   $   (663)   $   (469)  

Increase (decrease) in taxes 
 resulting from:

Asset acquisition/sale differences             1,315        394         637
Nontaxable income                                (28)      (171)       (323)
Percentage depletion                            (402)      (290)       (286)
State taxes, net                                 888         98        (113)
Enhanced oil recovery, nonconventional
 fuel tax and alternative minimum 
 tax credits                                  (1,115)      (406)      (1199)
Other, net                                      (193)       217         342    
                                             -------    -------     -------
                                            $  7,286   $   (821)   $ (1,411)   
                                             =======    =======     =======
Effective tax rate                              37.4%     (42.1)%    (102.3)%  

 
       The Company has $.5 million of loss carryforwards which may be utilized 
in future years to reduce the Company's federal income taxes.  These loss 
carryforwards expire in the year 2000.  The Company also has approximately $.6 
million of various tax credit carryforwards available to reduce future federal 
income taxes.  If not fully utilized, certain enhanced oil recovery tax credits 
of $.5 million will expire in the year 2009.  The other credits may be carried 
forward indefinitely.

       The Company went to trial in April 1993 before the U.S. Tax Court on 
certain unresolved federal tax issues relating to the years 1987 through 1989.  
The Court's decision was rendered in May of 1995, resulting in an approximate 
$.5 million charge in the second quarter of 1995 and the payment of 
approximately $2.9 million in federal and state taxes.  Due to this decision, 
the Company no longer has benefit of certain loss carryforwards and asset
bases.  Therefore, these deferred tax assets, as well as the valuation
allowance provided against these assets, have been removed.  All federal and
state taxes and accrued interest owed with respect to these issues have been
paid.  The Company is pursuing an appeal of the Court's decision with respect
to certain issues to the U.S. Court of Appeals (Ninth Circuit).










                                      28







                            BERRY PETROLEUM COMPANY
                       Notes to the Financial Statements

10.  Stock option and stock appreciation rights plans

       The Company has a 1987 Nonstatutory Stock Option Plan (the NSO Plan) and 
a 1987 Stock Appreciation Rights Plan (the SAR Plan).  The NSO Plan provided
for the granting of options (Options) to purchase up to an aggregate of 700,000
shares of Common Stock.  The SAR Plan originally authorized a maximum of
700,000 shares of Common Stock subject to stock appreciation rights (SARs).
Holders of SARs have the right upon exercise to receive a payment, payable at
the discretion of the Compensation Committee in cash or in shares of Common
Stock, equal to the amount by which the market price exceeds the Base Price (as
defined) with respect to the shares subject to such SARs on the date of 
exercise.  In December 1994, the Board of Directors adopted a resolution to 
terminate the 1987 Stock Appreciation Rights Plan without utilizing the 307,860
SARs which were still available for issuance.  The 39,740 currently outstanding
SARs are still available for exercise under the original terms of issuance.

       On December 2, 1994, the Board of Directors of the Company adopted the 
Berry Petroleum Company 1994 Stock Option Plan (the 1994 Plan).  The 1994 Plan 
was approved by the shareholders in May 1995 and provides for the granting of
stock options to purchase up to an aggregate of 1,000,000 shares of Common 
Stock.  All Options, with the exception of the formula grants to non-employee 
directors, will be granted at the discretion of the Compensation Committee of 
the Board of Directors.  The term of each Option may not exceed ten years from 
the date the Option is granted.  

       On December 2, 1994, 300,000 Options were issued to certain key
employees at an exercise price of $10.75 per share, which was the closing
market price of the Company's Class A Common Stock on the New York Stock
Exchange on that date.  The Options vest 25% per year for four years.
The Options granted on December 2, 1994 utilized all 193,800 remaining
Options from the 1987 Nonstatutory Stock Option Plan and 106,200 shares
from the 1994 Plan.  The 1994 Plan also allows for Option grants to the
Board of Directors under a formula plan whereby all non-employee directors
are eligible to receive Options.  33,000 Options were issued on December 2,
1994 and 1995, (3,000 Options to each of the eleven non-employee directors
each year) at an exercise price of $10.75 and $10.625 per share,
respectively.  The Options granted to the non-employee directors vest 
immediately.  The formula plan provides for the annual grant of 3,000 Options
to each non-employee director holding office on each December 2nd at the fair
market value on the date of grant.

       Included in general and administrative expenses is $9,000 in 1995, $0 in
1994 and $(18,000) in 1993 for compensation expense related to the Options and 
SARs granted to date.  The credit in 1993 was due to the decline in the 
Company's stock price during that year.  Because the options issued on December
2, 1994 and 1995 were all issued at current market value, there was no 
accounting charge to the Company in connection with the Option grants.  The 
accrued liabilities for the NSO and SAR Plans are $.2 million at December 31, 
1995 and 1994.

       In 1996, the Company plans to adopt the disclosure option of SFAS No. 
123,  "Accounting for Stock-Based Compensation".










                                   
                                      29






                             BERRY PETROLEUM COMPANY
                        Notes to the Financial Statements

10.  Stock option and stock appreciation rights plans (cont'd) 
             
                                              1995                 1994
                                       Options     SARs     Options     SARs
                                    
Balance outstanding, January 1        398,141   39,740     142,941      69,020
  Granted                              33,000        -     333,000           -
  Exercised                                 -        -           -      (5,380)
  Canceled/expired                          -        -     (77,800)    (23,900)
                                      -------  -------     -------     -------
Balance outstanding, December 31      431,141   39,740     398,141      39,740 
                                      =======  =======     =======     ======= 
Balance exercisable at December 31    223,941   39,740      65,141      39,740
                                      =======  =======     =======     =======
Available for future grant            827,800        -     860,800           - 
                                      =======  =======     =======     ======= 
Exercise Price                      $   9.80  $   9.80    $   9.80  $    9.80
                                    to 10.75  to 10.00    to 10.75   to 10.00  
                                      =======  =======     =======    =======
                                                                    $   10.50
Market price at date of exercise    $      -  $      -    $      -  to 10.875
                                      =======  =======     =======    =======

       During 1993, 270,961 Options and 142,980 SARs were exercised at an 
exercise price ranging from $9.80 to $10.00 and a market price ranging from 
$11.63 to $13.13.

11. Retirement Plan

       The Company sponsors a defined contribution retirement or thrift plan 
(401(k) Plan) to assist all employees in providing for retirement or other 
future financial needs.  Employee contributions (up to 6% of their earnings)
are matched by the Company dollar for dollar.  Effective November 1, 1992, the 
401(k) Plan was modified to provide for increased Company matching of employee 
contributions whereby the monthly Company matching contributions will range
from 6% to 9% of eligible participating employee earnings, if certain financial
results are achieved.  Due to improved financial results, the monthly matching 
contributions ranged from 6% to 9% during 1995.  For 1994 and 1993, all
matching contributions were at the 6% rate.  The Company's contributions to
the 401(k) Plan were $.2 million in 1995,  $.2 million in 1994 and $.3 million
in 1993.  Total contributions in 1995 were lower than in 1993 due to a decline
in the number of employees at the Company.

12. Oil Spill

       On December 25, 1993, the Company experienced a crude oil spill on its 
PRC 735 State lease located in the West Montalvo field in Ventura County, 
California.  The spill required clean-up of the area directly around the pipe
as well as the nearby ocean and an agricultural runoff pond.  Working closely
with the United States Coast Guard, the California Department of Fish and Game,
and other regulatory agencies, the Company substantially completed the clean-up
of the spill in January 1994.  The Company negotiated a resolution of the state
criminal investigation for a total of $.6 million in August 1994.  Governmental
investigations continue regarding potential civil and federal criminal 
penalties, if any.

       Management believes the Company has an adequate amount of insurance 
coverage for the majority of the costs associated with the spill and has 
received preliminary coverage letters from its insurance carriers tendering 
coverage, subject to certain reservations.  Definitive determination will not 
become known until some time in the future.  The Company estimates the total 
cost of the spill, net of insurance reimbursement, to be a minimum of $3.3 
million and a maximum of $5.1 million.  Since no other amount in the range is 
more likely to occur, the minimum amount was expensed by the Company ($1.3 
million in the second quarter of 1994 and $2 million in 1993).  The costs 
incurred and estimated to be incurred in connection with the 
                                   
                                      30
                                    
                                    

                            BERRY PETROLEUM COMPANY
                       Notes to the Financial Statements

12. Oil Spill (cont'd)

spill not yet paid by the Company are included in accrued liabilities at 
December 31, 1995, and the probable remaining minimum insurance reimbursement
is included in accounts receivable.  As of December 31, 1995, the Company had 
received approximately $8.1 million under its insurance coverage as 
reimbursement for costs incurred and paid by the Company associated with the 
spill.

13. Quarterly financial data (unaudited)

       The following is a tabulation of unaudited quarterly operating results 
for 1995 and 1994 (in thousands). 
                                                                   Net Income
                      Operating         Gross        Net Income      (Loss)
1995                 Revenues (A)     Profit (A)       (Loss)       Per Share

First Quarter         $ 10,445        $  3,872        $  2,210      $    .10
Second Quarter          12,436           5,933           2,876           .13
Third Quarter           12,172           5,688           3,374           .16
Fourth Quarter          10,732           3,394           3,743           .17
                       -------         -------         -------       -------
                      $ 45,785        $ 18,887        $ 12,203      $    .56
                       =======         =======         =======       =======
1994

First Quarter         $  7,205        $    (18)       $   (598)     $   (.03)
Second Quarter           9,827          (5,916)(B)      (4,665)(B)      (.21)
Third Quarter           11,640           4,602           2,609           .12
Fourth Quarter          10,866           3,141           1,525           .07
                       -------         -------         -------       -------
                      $ 39,538        $  1,809        $ (1,129)     $   (.05) 
                       =======         =======         =======       =======  

     
 (A) Includes sales of oil and gas and blending, net.

 (B)  Includes property impairment of $2.9 million and additional oil spill 
      costs accrual of $1.3 million.





                                    
                                    
                                    
                                    
                                    
                                   
                           
                                 
                                 
                                    
                                      31






                                     
                             BERRY PETROLEUM COMPANY

Supplemental Information About Oil & Gas Producing Activities (Unaudited)

       The following estimates of proved oil and gas reserves, both developed 
and undeveloped, represent interests owned by the Company located solely within
the United States.  Proved reserves represent 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.  Proved developed oil and gas
reserves are the quantities expected to be recovered through existing wells
with existing equipment and operating methods.  Proved undeveloped oil and gas
reserves are reserves that are expected to be recovered from new wells on 
undrilled acreage, or from existing wells for which relatively major 
expenditures are required for completion.

       Disclosures of oil and gas reserves which follow are based on estimates 
prepared primarily by independent engineering consultants for the three years 
ended December 31, 1995.  Such estimates are subject to numerous uncertainties 
inherent in the estimation of quantities of proved reserves and in the 
projection of future rates of production and the timing of development 
expenditures.  These estimates do not include probable or possible reserves.

Changes in estimated reserve quantities

       The net interest in estimated quantities of proved developed and 
undeveloped reserves of crude oil and natural gas at December 31, 1995, 1994
and 1993, and changes in such quantities during each of the years then ended
were as follows (in thousands):
                                  1995             1994             1993
                              Oil     Gas      Oil      Gas      Oil     Gas
                             Mbbls    Mmcf    Mbbls     Mmcf    Mbbls    Mmcf
                                                                     
Proved developed and
 undeveloped reserves:
 Beginning of year          75,996   6,530    72,078    5,476   72,434  10,003
 Revision of previous 
  estimates                  5,266     803     6,002    1,847    3,203  (5,735)
 Production                 (3,277)   (611)   (3,250)    (793)  (3,617)   (771)
 Discoveries                     -       -         -        -       58   1,979
 Sale of reserves 
  in place                  (1,698)   (739)        -        -        -       -
 Purchase of reserves 
  in place                     784       -     1,166        -        -       -
                            ------  ------    ------   ------   ------  ------ 
 End of year                77,071   5,983    75,996    6,530   72,078   5,476
                            ======  ======    ======   ======   ======  ======
 Proved developed reserves:
 Beginning of year          62,718   4,727    62,261    4,810   65,516   6,797
                            ======  ======    ======   ======   ======  ====== 
 End of year                62,856   3,380    62,718    4,727   62,261   4,810 
                            ======  ======    ======   ======   ======  ======
                                                                         
                                                                         
                                                                         
                                                                         
                                                                         
                                                                         
                                                                         
                                                                         

                                                                         
                                                                        
                                                                         
                                                                         
                                                                         
                                                                        
                                                                         
                                                                         
                                                                         
                                      32





                            BERRY PETROLEUM COMPANY

Supplemental Information About Oil & Gas 
 Producing Activities (Unaudited)(Cont'd)

       Standardized measure of discounted future net cash flows from estimated 
 production of proved oil and gas reserves (in thousands):

       The standardized measure has been prepared assuming year-end sales
prices adjusted for fixed and determinable contractual price changes, year-end
costs and statutory income tax rates previously legislated, and a ten percent
annual discount rate.  No deduction has been made for depletion, depreciation
or any indirect costs such as general corporate overhead or interest expense.


                                                 1995        1994        1993
                                            
Future cash inflows                          $1,039,150   $ 960,412   $ 607,137
Future production and development costs         311,955     317,735     473,903
Future income tax expenses                      245,416     213,225      37,332
                                              ---------    --------    --------
Future net cash flows                           481,779     429,452      95,902


10% annual discount for estimated timing
 of cash flows                                  273,478     248,499      59,276
                                              ---------    --------    --------
Standardized measure of discounted future
  net cash flows                             $  208,301   $ 180,953   $  36,626
                                              =========    ========    ========
Pre-tax standardized measure of discounted 
  future net cash flows                      $  308,370   $ 263,890   $  50,124
                                              =========    ========    ========

Average sales prices at December 31:

                          Oil  ($/Bbl)          $ 13.39     $ 12.49      $ 8.25
                          Gas ($/Mcf)              1.45        1.78        2.18

Changes in standardized measure of discounted future net cash flows from proved
oil and gas reserves (in thousands):



                                                 1995        1994        1993


Standardized measure - beginning of year      $ 180,953   $  36,626   $ 101,054 
                                               --------    --------    -------- 
Sales of oil and gas produced, 
 net of production costs                        (27,509)    (18,227)    (18,697)
Revisions to estimates of proved reserves:
   Net changes in sales prices and 
    production costs                             41,726     194,099    (110,914)
   Revisions of previous quantity estimates      23,584      24,315       2,261
   Change in estimated future development 
    costs                                       (14,234)     (5,470)      6,751
Extensions, discoveries and improved recovery 
 less related costs                                   -           -       2,929
Purchases of reserves in place                    2,316       3,815           -
Sale of reserves in place                        (8,645)          -           -
Development costs incurred during the period     14,034       4,678      10,958
Accretion of discount                             2,639       4,602      15,555
Income taxes                                    (13,126)    (68,416)     36,920
Other                                             6,563       4,931     (10,191)
                                               --------    --------    -------- 
Net increase (decrease)                          27,348     144,327     (64,428)
                                               --------    --------    --------
Standardized measure - end of year            $ 208,301   $ 180,953   $  36,626 
                                               ========    ========    ========
                                    
                                      33


                            BERRY PETROLEUM COMPANY


I
tem 9. Changes in and Disagreements with Accountants on Accounting and 
        Financial Disclosure

        None

                                   PART III


Item 10. Directors and Executive Officers of the Registrant

       The information called for by Item 10 is incorporated by reference from 
information under the caption "Election of Directors" in the Company's 
definitive proxy statement to be filed pursuant to Regulation 14A no later than
120 days after the close of its fiscal year.  The information on Executive 
Officers is contained in Part I of this Form 10-K.


Item 11. Executive Compensation

       The information called for by Item 11 is incorporated by reference from 
information under the caption "Executive Compensation" in the Company's 
definitive proxy statement to be filed pursuant to Regulation 14A no later than
120 days after the close of its fiscal year.


Item 12.  Security Ownership of Certain Beneficial Owners and Management
         
       The information called for by Item 12 is incorporated by reference from 
information under the caption "Voting Securities" and "Principal Shareholders 
and Ownership by Management" in the Company's definitive proxy statement to be 
filed pursuant to Regulation 14A no later than 120 days after the close of its 
fiscal year.

       Section 16(a) of the Securities Exchange Act of 1934 requires the 
Company's executive officers and directors and persons beneficially owning 
greater than ten percent of the outstanding Shares to file reports of ownership
and changes in ownership with the Securities and Exchange Commission.  Based 
solely on a review of the copies of such forms furnished to the Company, or 
written representations that no Form 5 was required, the Company believes that
all Section 16(a) filing requirements were complied with, except that one
report for one transaction was filed late by Mr. Chester L. Love.


Item 13.  Certain Relationships and Related Transactions

       The information called for by Item 13 is incorporated by reference from
information under the caption "Certain Relationships and Related Transactions" 
in the Company's definitive proxy statement to be filed pursuant to Regulation 
14A no later than 120 days after the close of its fiscal year.














                                    
                                      34




                                    PART IV


Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K

A.     Financial Statements and Schedules

       See Index to Financial Statements and Supplementary Data in Item 8.

B.     Reports on Form 8-K

       None

C.     Exhibits

Exhibit No.        Description of Exhibit                                  Page

3.1*   Registrant's Restated Certificate of Incorporation 
        (filed as Exhibit 3.1 to the Registrant's Registration 
        Statement on Form S-1 filed on June 7, 1989, File No. 33-29165)
3.2*   Registrant's Restated Bylaws (filed as Exhibit 3.2 to the 
        Registrant's Registration Statement on Form S-1 on June 7, 
        1989, File No. 33-29165)
3.3*   Registrant's Certificate of Designation, Preferences and Rights 
        of Series A Junior Participating Preferred Stock (filed as 
        Exhibit 3.3 to the Annual Report on Form 10-K for the year 
        ended December 31, 1989, File No. 0-11708)
4.1*   Rights Agreement between Registrant and Bank of America dated as 
        of December 8, 1989 (filed as Exhibit 1 to Form 8-K filed on 
        December 20, 1989, File No. 0-11708)
10.1*  Description of Cash Bonus Plan of Berry Petroleum Company (filed 
        as Exhibit 10.7 to the Annual Report on Form 10-K for the year 
        ended December 31, 1990, File No. 1-9735)
10.2*  Salary Continuation Agreement dated as of March 20, 1987, as 
        amended August 28, 1987, by and between Registrant and Jerry V. 
        Hoffman (filed as Exhibit 10.11 to the Registration Statement 
        on Form S-1 filed on June 7, 1989, File No. 33-29165)
10.3*  Form of Salary Continuation Agreements dated as of March 20, 
        1987, as amended August 28, 1987, by and between Registrant and 
        selected employees of the Company (filed as Exhibit 10.12 to 
        the Registration Statement on Form S-1 filed on June 7, 1989, 
        File No. 33-29165)
10.4*  Instrument for Settlement of Claims and Mutual Release by and 
        among Registrant, Victory Oil Company, the Crail Fund and 
        Victory Holding Company effective October 31, 1986 (filed as 
        Exhibit 10.13 to Amendment No. 1 to the Registrant's 
        Registration Statement on Form S-4 filed on May 22, 1987, File 
        No. 33-13240)
10.5*  1987 Nonstatutory Stock Option Plan and 1987 Stock Appreciation 
        Rights Plan as amended March 18, 1988 (filed as Exhibit 10.14 
        in Registrant's Registration Statement on Form S-8 filed on 
        July 28, 1988, File No. 33-23326)
10.6*  Service Contract by and between Registrant and Pride Petroleum 
        Services, Inc. dated November 1, 1989 (filed as Exhibit 10.23 
        to the Registrant's Annual Report on Form 10-K for the year 
        ended December 31, 1989, File No. 0-11708)



                                   
                                    
                                      35


                                    
C.   Exhibits (cont'd)

Exhibit No.        Description of Exhibit                                  Page

10.7*  1994 Stock Option Plan (filed as Exhibit 10.8 in Registrant's 
        Annual Report on Form 10-K for the year ended December 31, 
        1994, File No. 1-9735)                      
10.8   Standard Offer #2 Power Purchase Agreement dated May 1984, as        38
        amended by and between Registrant and Pacific Gas and Electric 
        Company                                                             
23.1   Consent of Coopers & Lybrand L.L.P.                                 119 
23.2   Consent of Babson and Sheppard                                      120 
23.3   Consent of DeGolyer and MacNaughton                                 121 
27. ** Financial Data Schedule                                             122 
99.1   Undertaking for Form S-8 Registration Statements                    123 
99.2*  Form of Indemnity Agreement of Registrant (filed as Exhibit 28.2 
        in Registrant's Registration Statement on Form S-4 filed on 
        April 7, 1987, File No. 33-13240)
99.3*  Form of "B" Group Trust (filed as Exhibit 28.3 to Amendment 
        No. 1 to Registrant's Registration Statement on Form S-4 filed 
        on May 22, 1987, File No. 33-13240)


*  Incorporated by reference
** Included in the Company's electronic filing on EDGAR
























                                     


                                      36







       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, thereto duly authorized on March 15, 1996.

                            BERRY PETROLEUM COMPANY


/s/ JERRY V. HOFFMAN      /s/ RALPH J. GOEHRING           /s/ DONALD A. DALE
JERRY V. HOFFMAN         RALPH J. GOEHRING                DONALD A. DALE
President and Chief      Chief Financial Officer          Controller (Principal
Executive Officer        (Principal Financial Officer)    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 on the dates so indicated.

     Name                                 Office                     Date


/s/ Harvey L. Bryant             Chairman of the Board and      March 15, 1996
Harvey L. Bryant                 Director

/s/ Jerry V. Hoffman             President, Chief Executive     March 15, 1996
Jerry V. Hoffman                 Officer and Director           

/s/ Benton Bejach                Director                       March 15, 1996
Benton Bejach

/s/ William F. Berry             Director                       March 15, 1996
William F. Berry

/s/ Gerry A. Biller              Director                       March 15, 1996
Gerry A. Biller

/s/ Ralph B. Busch, Jr.          Director                       March 15, 1996
Ralph B. Busch, Jr.

/s/ William E. Bush, Jr.         Director                       March 15, 1996
William E. Bush, Jr.

/s/ William B. Charles           Director                       March 15, 1996
William B. Charles

/s/ Richard F. Downs             Director                       March 15, 1996
Richard F. Downs

/s/ John A. Hagg                 Director                       March 15, 1996
John A. Hagg

/s/ Thomas J. Jamieson           Director                       March 15, 1996
Thomas J. Jamieson

/s/ Roger G. Martin              Director                       March 15, 1996
Roger G. Martin

                                      37









                       PACIFIC GAS AND ELECTRIC COMPANY

                              STANDARD OFFER #2

                           POWER PURCHASE AGREEMENT

                                     FOR

                           FIRM CAPACITY AND ENERGY









































                                   MAY 1984



                                                                  S.O. #2
                                                                  May 7, 1984
                                       1



                              STANDARD OFFER #2:

                           FIRM CAPACITY AND ENERGY

                           POWER PURCHASE AGREEMENT


CONTENTS


Article                                                     Page

    1   QUALIFYING STATUS                                                 3

    2   PURCHASE OF POWER                                                 4

    3   PURCHASE PRICE                                                    6

    4   NOTICES                                                           6

    5   DESIGNATED SWITCHING CENTER                                       7

    6   TERMS AND CONDITIONS                                              7

    7   TERM OF AGREEMENT                                                 7


Appendix A:   GENERAL TERMS AND CONDITIONS

Appendix B:   ENERGY PRICES

Appendix C:   FIRM CAPACITY PRICE SCHEDULE

Appendix D:   ADJUSTMENT OF CAPACITY PAYMENTS IN THE EVENT OF 

              TERMINATION OR REDUCTION

Appendix E:   INTERCONNECTION


















                                                                 S.O. #2
                                                                 May 7, 1984

                                       
                                       2



 

                           FIRM CAPACITY AND ENERGY

                           POWER PURCHASE AGREEMENT

                                    BETWEEN

                       UNIVERSITY COGENERATION INC., 1985-1

                                      AND

                         PACIFIC GAS AND ELECTRIC COMPANY



     UNIVERSITY COGENERATION INC., 1985-1 (Seller), and PACIFIC GAS AND
ELECTRIC COMPANY (PGandE), referred to collectively as Parties and
individually as Party, agree as follows:

                         ARTICLE 1   QUALIFYING STATUS

     Seller warrants that, at the date of first power deliveries from Seller's
Facility ((1)) and during the term of agreement, its Facility shall meet the
qualifying facility requirements established as of the effective date of this
Agreement by the Federal Energy Regulatory
 Commission's rules (18 Code of
Federal Regulations 292) implementing the Public Utility Regulatory Policies
Act of 1978 (16 U.S.C.A. 796, et seq.).






                                                          
((1))  Underlining identifies those terms which are defined in Section A-1     
       of Appendix A.


                                                                 S.O. #2
                                                                 May 7, 1984

                                       3


                         ARTICLE 2   PURCHASE OF POWER

     (a)     Seller shall sell and deliver and PGandE shall purchase and
accept delivery of firm capacity and energy at the voltage level of______((1))
kV as indicated below --
               1.     Contract capacity - 34,000 kW; and
               2.     Energy - net energy output ((2)).
             Seller may convert its energy sale option as provided in Section
A-3 of Appendix A.

     (b)     Seller shall provide the firm capacity and energy set forth above
from its 38,000 kW (ISO) Facility located at Section 28, township 12 north,
range 24 west, 3 1/2 miles south of Taft, Kern County, California.

     (c)     The scheduled operation date of the Facility is November 1986. 
At the end of each calendar quarter Seller shall give written notice to PGandE
of any change in the scheduled operation date.  






                                                          
((1)) The Seller requests, and PGandE consents, that this blank not be         
      filled in at the time of executing the Agreement, because the Seller,    
      recognizing that the information is not yet available to make a          
      definitive determination of the number to be inserted in this blank,     
      shall request PGandE to perform an interconnection study to be done in   
      its accustomed manner of making such studies to determine the number to  
      be inserted.

((2)) Insert either net energy output or surplus energy output to show the     
      energy sale option selected by Seller.

                                                                 S.O. #2 
                                                                 May 7, 1984
                                       4


      (d)     To avoid exceeding the physical limitations of the               
interconnection facilities, Seller shall limit the Facility's               
actual rate of delivery into the PGandE system to ________ ((1)) kW.

     (e)     The primary energy source for the Facility is natural gas.

     (f)    If Seller does not begin construction of its Facility by June
1986, PGandE may reallocate the existing capacity on PGandE's transmission
and/or distribution system which would have been used to accommodate Seller's
power deliveries to other uses.  In the event of such reallocation, Seller
shall pay PGandE for the cost of any upgrades or additions to PGandE's system
necessary to accommodate the output from the Facility.  Such additional
facilities shall be installed, owned, and maintained in accordance with the
applicable PGandE tariff.

     (g)    The transformer loss adjustment factor is __________((1))((2)).



                                                          
((1)) The Seller requests, and PGandE consents, that this blank not be filled  
      in at the time of executing the Agreement, because the Seller,           
      recognizing that the information is not yet available to make a          
      definitive determination of the number to be inserted in this blank,     
      shall request PGandE to perform an interconnection study to be done in   
      its accustomed manner of making such studies to determine the number to  
      be inserted.

((2)) If Seller chooses to have meters placed on Seller's side of the          
      transformer, an estimated transformer loss adjustment factor of 2        
      percent, unless the Parties agree otherwise, will be applied.  This      
      estimated transformer loss figure will be adjusted to a measurement of   
      actual transformer losses performed at Seller's request and expense.
 


                                                                 S.O. #2
                                                                 May 7, 1984

                                       5


                          ARTICLE 3   PURCHASE PRICE


      (a)     PGandE shall pay Seller for firm capacity at the contract
capacity price under Option 1 set forth in Section C-5 of Appendix C.  The
contract capacity price is derived from PGandE's full avoided costs as
approved by the CPUC.  PGandE's obligation to pay for the contract capacity
shall begin on the actual operation date.  Seller elects to have its contract
capacity price determined from the firm capacity price schedule in effect on
the date of execution of this Agreement((1)).  The contract capacity price
shall be subject to adjustment as provided for in Appendix D.

      (b)     PGandE shall pay Seller for energy at prices equal to PGandE's
full short run avoided operating costs as approved by the CPUC.

      (c)     The contract capacity price is applicable to deliveries of
capacity beginning after December 30, 1982.

                              ARTICLE 4   NOTICES

     All written notices shall be directed as follows:
     To PGandE:     Pacific Gas and Electric Company
                    Attention: Vice President-
                       Electric Operations
                    77 Beale Street
                    San Francisco, CA 94106










                                                          
((1)) Insert either the date of execution of this Agreement or the actual      
   operation date.

                                                                 S.O. #2
                                                                 May 7, 1984
                                       6



      To Seller:   University Cogeneration Inc.
                   University Energy
                   Attention:   Secretary
                   3430 Camino Del Rio North
                   Suite 200
                   San Diego, CA 92108


                    ARTICLE 5   DESIGNATED SWITCHING CENTER


      The designated PGandE switching center shall be unless changed by 
PGandE:

                   PGandE Midway Substation
                   Buttonwillow, CA
                   (805) 764-5229


                       ARTICLE 6   TERMS AND CONDITIONS


      This Agreement includes the following appendices which are attached and
incorporated by reference:
      Appendix A -   GENERAL TERMS AND CONDITIONS
      Appendix B -   ENERGY PRICES
      Appendix C -   FIRM CAPACITY PRICE SCHEDULE
      Appendix D -   ADJUSTMENT OF CAPACITY PAYMENTS IN THE EVENT OF 
                     TERMINATION OR REDUCTION
      Appendix E -   INTERCONNECTION


                         ARTICLE 7   TERM OF AGREEMENT


      This Agreement shall be binding upon execution and remain in effect
thereafter for 10 years from the actual operation date; provided, however,
that it shall terminate if the actual operation date does not occur within
five years of the execution date.

                                                                 S.O. #2
                                                                 May 7, 1984


                                       7


      IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be
executed by their duly authorized representatives and effective as of the last
date set forth below.

UNIVERSITY COGENERATION INC., 1985-1          PACIFIC GAS AND ELECTRIC COMPANY


BY:    /s/ John R. Zanot                       By:      /s/ Nolan Davies      
           JOHN R. ZANOT                                 NOLAN DAVIES
TITLE:       Secretary                         TITLE:    Vice President -
                                                         Planning and Research
DATE SIGNED:   April 16, 1985                  DATE SIGNED:  April 23, 1985






                                                                 S.O. #2   
                                                                 May 7, 1984
                                       8


























                                  APPENDIX A

                         GENERAL TERMS AND CONDITIONS


                                    CONTENTS


Section                                                                        
                                                                          Page

 A-1    DEFINITIONS                                                       A-2

 A-2    CONSTRUCTION                                                      A-6

 A-3    ENERGY SALE OPTIONS                                               A-10

 A-4    OPERATION                                                         A-12

 A-5    PAYMENT                                                           A-16

 A-6    ADJUSTMENTS OF PAYMENTS                                           A-17

 A-7    ACCESS TO RECORDS AND PGandE DATA                                 A-17

 A-8    CURTAILMENT OF DELIVERIES AND HYDRO SPILL CONDITIONS              A-18

 A-9    FORCE MAJEURE                                                     A-21

 A-10   INDEMNITY                                                         A-22

 A-11   LIABILITY; DEDICATION                                             A-23

 A-12   SEVERAL OBLIGATIONS                                               A-24

 A-13   NON-WAIVER                                                        A-24

 A-14   ASSIGNMENT                                                        A-25

 A-15   CAPTIONS                                                          A-25

 A-16   CHOICE OF LAWS                                                    A-25

 A-17   GOVERNMENTAL JURISDICTION AND AUTHORIZATION                       A-26

 A-18   NOTICES                                                           A-26

 A-19   INSURANCE                                                         A-27

 A-20   REASONABLE ACTION BY EACH PARTY                                   A-29




                                                                               
                                                                               



                                                                 S.O. #2
                                                                 May 7, 1984
           
                                    

                                  APPENDIX A

                          GENERAL TERMS AND CONDITIONS


A-1   DEFINITIONS

     Whenever used in this Agreement, appendices, and attachments hereto, the
following terms shall have the following meanings:

      Actual operation date - The day following the day during which all
features and equipment of the Facility are demonstrated to PGandE's
satisfaction to be capable of operating simultaneously to deliver power
continuously into PGandE's system as provided in this Agreement.

      Adjusted capacity price - The $/kW-year purchase price from Table B,
Appendix C for the period of Seller's actual performance.

      Capacity sale reduction - A reduction in the amount of capacity provided
or to be provided under this Agreement, other than a temporary reduction
during probationary periods under Section C-5.

      Contract capacity - That capacity identified in Article 2(a) except as
otherwise changed as provided herein.





                                                                          

                                                                 S.O. #2
                                                                 May 7, 1984


                                      A-2


      Contract capacity price - The capacity price applicable for the period
from the actual operation date through the term of agreement from either the
firm capacity price schedule, Table B of Appendix C, or the successor to Table
B in effect on the Actual operation date.  Seller has indicated its choice of
firm capacity price schedule in Article 3(a).

      Contract termination - The early termination of this Agreement.

      CPUC - The Public Utilities Commission of the State of California.

      Current firm capacity price - The $/kW-year capacity price from the firm
capacity price schedule published by PGandE at the time notice of termination
or reduction of contract capacity is given, for a term equal to the period
from the date of termination or reduction to the end of the term of agreement.

      Designated PGandE switching center - That switching center or other
PGandE installation identified in Article 5.

      Dispatchable - The Facility is operable and can be called upon at any
time to increase its deliveries of capacity to any level up to the contract
capacity.














                                                                 S.O. #2
                                                                 May 7, 1984


                                      A-3




      Facility - That generation apparatus described in Article 2 and all
associated equipment owned, maintained, and operated by Seller.

      Firm capacity price schedule - The periodically published schedule of
the $/kW-year prices that PGandE offers to pay for capacity.  See Table B,
Appendix C.

      Forced outage - Any outage resulting from a design defect, inadequate
construction, operator error or a breakdown of the mechanical or electrical
equipment that fully or partially curtails the electrical output of the
Facility.

      Interconnection facilities - All means required and apparatus installed
to interconnect and deliver power from the Facility to the PGandE system
including, but not limited to, connection, transformation, switching,
metering, communications, and safety equipment, such as equipment required to
protect (1) the PGandE system and its customers from faults occurring at the
Facility, and (2) the Facility from faults occurring on the PGandE system or
on the systems of others to which the PGandE system is directly or indirectly
connected.  Interconnection facilities also include any necessary additions
and reinforcements by PGandE to the PGandE system required as a result of the
interconnection of the Facility to the PGandE system.







                                                                 S.O. #2
                                                                 May 7, 1984
                                      A-4



      Net energy output - The Facility's gross output in kilowatt-hours less
station use and transformation and transmission losses to the point of
delivery into the PGandE system.  Where PGandE agrees that it is impractical
to connect the station use on the generator side of the power purchase meter,
PGandE may, at its option, apply a station load adjustment.

      Prudent electrical practices - Those practices, methods, and equipment,
as changed from time to time, that are commonly used in prudent electrical
engineering and operations to design and operate electric equipment lawfully
and with safety, dependability, efficiency, and economy.

      Scheduled operation date - The day specified in Article 2(c) when the
Facility is, by Seller's estimate, expected to produce energy and capacity
that will be available for delivery to PGandE.

      Special facilities - Those additions and reinforcements to the PGandE
system which are needed to accommodate the maximum delivery of energy and
capacity from the facility as provided in this Agreement and those parts of
the interconnection facilities which are owned and maintained by PGandE at
Seller's request, including metering and data processing equipment.  










                                                                 S.O. #2
                                                                 May 7, 1984

                                      A-5



All special facilities shall be owned, operated, and maintained pursuant to
PGandE's electric Rule No. 21, which is attached hereto.

      Station use - Energy used to operate the Facility's auxiliary equipment. 
The auxiliary equipment includes, but is not limited to, forced and induced
draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant
lighting, fuel handling systems, control systems, and sump pumps.

      Surplus energy output - The Facility's gross output, in kilowatt-hours,
less station use, and any other use by Seller, and transformation and
transmission losses to the point of delivery into the PGandE system.

      Term of agreement - The period of time during which this Agreement will
be in effect as provided in Article 7.

      Voltage level - The voltage at which the Facility interconnects with the
PGandE system, measured at the point of delivery.

A-2      CONSTRUCTION
A-2.1    Land Rights

      PGandE's equipment is to be installed on property owned by other than
Seller.  Seller shall, at its own cost and expense, obtain from the owners 





                                                                 S.O. #2
                                                                 May 7, 1984

                                      A-6



thereof all necessary rights of way and easements, in a form satisfactory to
PGandE, for the construction, operation, maintenance, and replacement of
PGandE's equipment upon such property.  If Seller is unable to obtain such
rights of way and easements, Seller shall reimburse PGandE for all costs,
including attorney's fees and litigation expenses, incurred by PGandE in
obtaining them.  PGandE shall at all times have the right of ingress to and
egress from the Facility at all reasonable hours for any purposes reasonably
connected with this Agreement or the exercise of any and all rights secured to
PGandE by law or its tariff schedules.

A-2.2   Design, Construction, Ownership, and Maintenance

      (a)   Seller shall design, construct, install, own, operate, and
maintain all interconnection facilities, except special facilities, to the
point of interconnection with the PGandE system as required for PGandE to
receive firm capacity and energy from the Facility.  The Facility and
interconnection facilities shall meet all requirements of applicable codes and
all standards of prudent electrical practices and shall be maintained in a
safe and prudent manner.  A description of the interconnection facilities for
which Seller is solely responsible is set forth in Appendix E, or if the
interconnection requirements have not yet been determined at the time of the
execution of this Agreement, the description of such facilities will be






                                                                 S.O. #2
                                                                 May 7, 1984

                                      A-7



appended to this Agreement at the time such determination is made.

      
      (b)   Seller shall submit to PGandE the design and all specifications
for the interconnection facilities (except special facilities) and, at
PGandE's option, the Facility, for review and written acceptance prior to
their release for construction purposes.  PGandE shall notify Seller in
writing of the outcome of PGandE's review of the design and specifications for
Seller's interconnection facilities (and the Facility, if requested) within 30
days of the receipt of the design and all of the specifications for the
interconnection facilities (and the Facility, if requested).  Any flaws
perceived by PGandE in the design and specifications for the interconnection
facilities (and the Facility, if requested) will be described in PGandE's
written notification.  PGandE's review and acceptance of the design and
specifications shall not be construed as confirming or endorsing the design
and specifications or as warranting their safety, durability, or reliability. 
PGandE shall not, by reason of such review or lack of review, be responsible
for strength, details of design, adequacy, or capacity of equipment built
pursuant to such design and specifications, nor shall PGandE's acceptance be
deemed to be an endorsement of any of such equipment.  Seller shall change the
interconnection facilities as may be reasonably required by PGandE to meet
changing requirements of the PGandE system.







                                                                 S.O. #2
                                                                 May 7, 1984

                                      A-8




      (c)   In the event it is necessary for PGandE to install interconnection
facilities for the purposes of this Agreement, they shall be installed as
special facilities.

      (d)   Upon the request of Seller, PGandE shall provide a binding
estimate for the installation of interconnection facilities by PGandE.

A-2.3 Meter Installation

      (a)   PGandE shall specify, provide, install, own, operate, and maintain
as special facilities all metering and data processing equipment for the
registration and recording of energy and other related parameters which are
required for the reporting of data to PGandE and for computing the payment due
Seller from PGandE.

      (b)   Seller shall provide, construct, install, own, and maintain at
Seller's expense all that is required to accommodate the metering and data
processing equipment, such as, but not limited to, metal-clad switchgear,
switchboards, cubicles, metering panels, enclosures, conduits, rack
structures, and equipment mounting pads.

      (c)   PGandE shall permit meters to be fixed on PGandE's side of the
transformer.  If meters are placed on PGandE's side of the transformer,
service will be provided at the available primary voltage and no transformer
loss adjustment will be made.  If Seller chooses to have meters placed on 


                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-9




Seller's side of the transformer, an estimated transformer loss adjustment
factor of 2 percent, unless the Parties agree otherwise, will be applied.

A-3   ENERGY SALE OPTIONS

A-3.1 General

      Seller has two energy sale options, net energy output or surplus energy
output.  Seller has made its initial selection in Article 2(a).

A-3.2 Energy Sale Conversion

      (a)   Seller is entitled to convert from one option to the other 12
months after execution of this Agreement, and thereafter at least 12 months
after the effective date of the most recent conversion, subject to the
following conditions:

            (1)   Seller shall provide PGandE with a written request to       
convert its energy sale option.
            (2)   Seller shall comply with all applicable tariffs on file with 
the CPUC and contracts in effect between the Parties at the time of conversion
covering the existing and proposed (i) facilities used to serve Seller's





                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-10



premises and (ii) interconnection facilities.
            (3)   Seller shall install and operate equipment required by       
PGandE to prevent PGandE from serving any part of Seller's load which is      
served by the Facility and not under contract for PGandE standby       
service.  At Seller's request PGandE shall provide this equipment as       
special facilities.
            (4)   If the energy sale conversion results in a capacity sale     
reduction, the provisions in Appendix D shall apply.
  
      (b)   If, as a result of an energy sales conversion, Seller no longer
requires the use of interconnection facilities installed and/or operated and
maintained by PGandE as special facilities under a Special Facilities
Agreement, Seller may reserve these facilities, for its future use, by
continuing its performance under its Special Facilities Agreement.  If Seller
does not wish to reserve such facilities, it may terminate its Special
Facilities Agreement.

            If Seller's energy sale conversion results in its discontinuation
of its use of PGandE facilities not covered by Seller's Special Facilities
Agreement, Seller cannot reserve those facilities for future use.  Seller's
future use of such facilities shall be contingent upon the availability of 







                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-11



such facilities at the time Seller requests such use.  If such facilities are
not available, Seller shall bear the expense necessary to install, own, and
maintain the needed additional facilities in accordance with PGandE's
applicable tariff.

      (c)   PGandE shall process requests for conversion in the order
received.  The effective date of conversion shall depend on the completion of
the changes required to accommodate Seller's energy sale conversion.

A-4   OPERATION

A-4.2 Inspection and Approval

      Seller shall not operate the Facility in parallel with PGandE's system
until an authorized PGandE representative has inspected the interconnection
facilities, and PGandE has given written approval to begin parallel operation. 
Seller shall notify PGandE of the Facility's start-up date at least 45 days
prior to such date.  PGandE shall inspect the interconnecting facilities
within 30 days of the receipt of such notice.  If parallel operation is not
authorized by PGandE, PGandE shall notify Seller in writing within five days
after inspection of the reason authorization for parallel operation was
withheld.






                                                                 S.O. #2
                                                                 May 7, 1984

                                      A-12



A-4.2 Facility Operation and Maintenance

      Seller shall operate and maintain its Facility according to prudent
electrical practices, applicable laws, orders, rules, and tariffs and shall
provide such reactive power support as may be reasonably required by PGandE to
maintain system voltage level and power factor.  Seller shall operate the
Facility at the power factors or voltage levels prescribed by PGandE's system
dispatcher or designated representative.  If Seller fails to provide reactive
power support, PGandE may do so at Seller's expense.

A-4.3 Point of Delivery

      Seller shall deliver the energy at the point where Seller's electrical
conductors (or those of Seller's agent) contact PGandE's system as it shall
exist whenever the deliveries are being made or at such other point or points
as the Parties may agree in writing.  The initial point of delivery of
Seller's power to the PGandE system is set forth in Appendix E.

A-4.4 Operating Communications

      (a)   Seller shall maintain operating communications with the designated
PGandE switching center.  The operating communications shall include, but not
be limited to, system paralleling or separation, schedule and unscheduled





                                                                 S.O. #2
                                                                 May 7, 1984

                                      A-13



shutdowns, equipment clearances, levels of operating voltage or power factor
and daily capacity and generation reports.

      (b)   Seller shall keep a daily operations log for each generating unit
which shall include information on unit availability, maintenance outages,
circuit breaker trip operations requiring a manual reset, and any significant
events related to the operation of the Facility.

      (c)   If Seller makes deliveries greater than one megawatt, Seller shall
measure and register on a graphic recording device power in kW and voltage in
kV at a location within the Facility agreed to by both parties.

      (d)   If Seller makes deliveries greater than one and up to and
including ten megawatts, Seller shall report to the designated PGandE
switching center, twice a day at agreed upon times for the current day's
operation, the hourly readings in kW of capacity delivered and the energy in
kWh delivered since the last report.

      (e)   If Seller makes deliveries of greater than ten megawatts, Seller
shall telemeter the delivered capacity and energy information, including real
power in kW, reactive power in kVAR, and energy in kWh to a switching center
selected by PGandE.  PGandE may also required Seller to telemeter transmission 






                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-14



kW, kVAR, and kV data depending on the number of generators and transmission
configuration.  Seller shall provide and maintain the data circuits required
for telemetering.  When telemetering is inoperative, Seller shall report daily
the capacity delivered each hour and the energy delivered each day to the
designated PGandE switching center.

      (f)   If Seller provides dispatchable capacity greater than ten
megawatts pursuant to Option 1 in Section C-5 of Appendix C, Seller may be
required by PGandE to provide telemetering and control equipment to allow the
Facility to respond to system load frequency requirements on digital control
from PGandE.

A-4.5 Meter Testing and Inspection

      (a)   All meters used to provide data for the computation of the
payments due Seller from PGandE shall be sealed, and the seals shall be broken
only by PGandE when the meters are to be inspected, tested, or adjusted.

      (b)   PGandE shall inspect and test all meters upon their installation
and annually thereafter.  At Seller's request and expense, PGandE shall
inspect or test a meter more frequently.  PGandE shall give reasonable notice
to Seller of the time when any inspection or test shall take place, and Seller
may have representatives present at the test or inspection.  If a meter is
found to be inaccurate or defective, PGandE shall adjust, repair, or replace
it at its expense in order to provide accurate metering.



                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-15


A-4.6 Adjustments to Meter Measurements

      If a meter fails to register, or if the measurement made by a meter
during a test varies by more than two percent from the measurement made by the
standard meter used in the test, an adjustment shall be made correcting all
measurements made by the inaccurate meter for -- (1) the actual period during
which inaccurate measurements were made, if the period can be determined, or
if not, (2) the period immediately preceding the test of the meter equal to
one-half the time from the date of the last previous test of the meter,
provided that the period covered by the correction shall not exceed six
months.

A-5   PAYMENT

      PGandE shall mail to Seller not later than 30 days after the end of each
monthly billing period, (1) a statement showing the capacity and energy
delivered to PGandE during on-peak, partial-peak, and off-peak periods during
the monthly billing period, (2) PGandE's computation of the amount due Seller,
and (3) PGandE's check in payment of said amount.  Except as provided in
Section A-6, if within 30 days of receipt of this statement Seller does not
make a report in writing to PGandE of an error, Seller shall be deemed to have







                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-16



waived any error in PGandE's statement, computation, and payment, and they
shall be considered correct and complete.

A-6   ADJUSTMENTS OF PAYMENTS

      (a)   In the event adjustments to payments are required as a result of
inaccurate meters, PGandE shall use the corrected measurements described in
Section A-4.6 to recompute the amount due from PGandE to Seller for the firm
capacity and energy delivered under this Agreement during the period of
inaccuracy.

      (b)   The additional payment to Seller or refund to PGandE shall be made
within 30 days of notification of the owing Party of the amount due.

A-7   ACCESS TO RECORDS AND PGandE DATA

      Each Party, after giving reasonable written notice to the other Party,
shall have the right of access to all metering and related records including
operations logs of the Facility.  Data filed by PGandE with the CPUC pursuant
to CPUC orders governing the purchase of power from qualifying facilities
shall be provided to Seller upon request; provided that Seller shall reimburse
PGandE for the costs it incurs to respond to such request.






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                                                                 May 7, 1984

                                     A-17



A-8   CURTAILMENT OF DELIVERIES AND HYDRO SPILL CONDITIONS

      (a)   PGandE shall not be obligated to accept or pay for and may require
Seller to interrupt or reduce deliveries of energy (1) when necessary in order
to construct, install, maintain, repair, replace, remove, investigate, or
inspect any of its equipment or any part of its system, or (2) if it
determines that interruption or reduction is necessary because of emergencies,
forced outages, force majeure, or compliance with prudent electrical
practices.  PGandE shall make reasonable efforts to coordinate any
interruptions or reduced deliveries for reasons specified in (1) above to
periods of scheduled outages for which Seller has provided proper notice.

     (b)    In anticipation of a period of hydro spill conditions, as defined
by the CPUC, PGandE may notify Seller that any purchases of energy from Seller
during such period shall be at hydro savings prices quoted by PGandE.  If
Seller delivers energy to PGandE during any such period, Seller shall be paid
hydro savings prices for those deliveries in lieu of prices which would
otherwise be applicable.  The hydro savings prices shall be calculated by
PGandE using the following formula:

                                    AQF - S x PP
                                      AQF   
    






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                                                                 May 7, 1984

                                     A-18



where:
AQF = Energy, in kWh, projected to be available during hydro spill conditions  
      from all qualifying facilities under agreements containing hydro savings  
      price provisions.
S   = Potential energy, in kWh, from PGandE hydro facilities which will be     
      spilled if all AQF is delivered to PGandE.
PP  = Prices published by PGandE for purchases during other than hydro spill   
      conditions.

      (c)   PGandE shall not be obligated to accept or pay for and may require
Seller with a Facility with a nameplate rating of one megawatt or greater to
interrupt or reduce deliveries of energy during periods when purchases under
this Agreement would result in costs greater than those which PGandE would
incur if it did not make such purchases but instead generated an equivalent
amount of energy itself.

      (d)   Whenever possible, PGandE shall give Seller reasonable notice of
the possibility that interruption or reduction of deliveries under subsections
(a) or (c), above, may be required.  PGandE shall give Seller notice of
general periods when hydro spill conditions are anticipated, and shall give
Seller as much advance notice as practical of any specific hydro spill period
and the hydro savings price which will be applicable during such period. 
Before interrupting or reducing deliveries under subsection (c), above, and





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                                                                 May 7, 1984

                                     A-19



before invoking hydro savings prices under subsection (b), above, PGandE shall
take reasonable steps to make economy sales of the surplus energy giving rise
to the condition.  If such economy sales are made, while the surplus energy
conditions exists Seller shall be paid at the economy sales price obtained by
PGandE in lieu of the otherwise applicable prices.

      (e)   If Seller is selling net energy output to PGandE and
simultaneously purchasing its electrical needs from PGandE, energy curtailed
pursuant to subsections (b) or (c) above shall not be used by Seller to meet
its electrical needs.  When Seller elects not to sell energy to PGandE at the
hydro savings price pursuant to subsection (b) or when PGandE curtails
deliveries of energy pursuant to subsection (c), Seller shall continue to
purchase all its electrical needs from PGandE.  If Seller is selling surplus
energy output to PGandE, subsections (b) or (c) shall only apply to the
surplus energy output being delivered to PGandE, and Seller can continue to
internally use that generation it has retained for its own use.

      (f)   PGandE and Seller desire to and will continue to explore
alternatives to Subsections (b), (c), (d), and (e) above that would compensate
Seller for granting to PGandE increased flexibility to interrupt or reduce
energy deliveries.  The parties agree to amend this Section A-8 accordingly if
they reach agreement on such an alternative.






                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-20



A-9   FORCE MAJEURE

      (a)   The term force majeure as used herein means unforeseeable causes,
other than forced outages, beyond the reasonable control of and without the
fault or negligence of the Party claiming force majeure including, but not
limited to, acts of God, labor disputes, sudden actions of the elements,
actions by federal, state, and municipal agencies, and actions of legislative,
judicial, or regulatory agencies which conflict with the terms of this
Agreement.

      (b)   If either Party because of force majeure is rendered wholly or
partly unable to perform its obligations under this Agreement, that Party
shall be excused from whatever performance is affected by the force majeure to
the extent so affected provided that:

            (1)   the non-performing Party, within two weeks after the
occurrence of the force majeure, gives the other Party written notice
describing the particulars of the occurrence,
            (2)   the suspension of performance is of no greater scope and of
no longer duration than is required by the force majeure,
            (3)   the non-performing Party uses its best efforts to remedy its
inability to perform (this subsection shall not require the settlement   
of any strike, walkout, lockout or other labor dispute on terms which,





                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-21



in the sole judgment of the Party involved in the dispute, are contrary to its 
interest.  It is understood and agreed that the settlement of strikes,
walkouts, lockouts or other labor disputes shall be at the sole discretion of
the Party having the difficulty),
            (4)   when the non-performing Party is able to resume performance  
of its obligations under this Agreement, that Party shall give the other  
Party written notice to that effect, and
            (5)   capacity payments during such periods of force majeure on    
Seller's part shall be governed by Section C-2(c) of Appendix C.

      (c)   In the event a Party is unable to perform due to legislative,
judicial, or regulatory agency action, this Agreement shall be renegotiated to
comply with the legal change which caused the non-performance.

A-10 INDEMNITY

      Each Party as indemnitor shall save harmless and indemnify the other
Party and the directors, officers, and employees of such other Party against
and from any and all loss and liability for injuries to persons including
employees of either Party, and property damages including property of either
Party resulting from or arising out of (1) the engineering, design,
construction, maintenance, or operation of, or (2) the making of replacements,






                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-22



additions, or betterments to, the indemnitor's facilities.  This indemnity and
save harmless provision shall apply notwithstanding the active or passive
negligence of the indemnitee.  Neither Party shall be indemnified hereunder
for its liability or loss resulting from its sole negligence or willful
misconduct.  The indemnitor shall, on the other Party's request, defend any
suit asserting a claim covered by this indemnity and shall pay all costs,
including reasonable attorney fees, that may be incurred by the other Party in
enforcing this indemnity.

A-11  LIABILITY; DEDICATION
      (a)   Nothing in this Agreement shall create any duty to, any standard
of care with reference to, or any liability to any person not a Party to it. 
Neither Party shall be liable to the other Party for consequential damages.

      (b)   Each Party shall be responsible for protecting its facilities from
possible damage by reason of electrical disturbances or faults caused by the
operation, faulty operation, or nonoperation of the other Party's facilities,
and such other Party shall not be liable for any such damages so caused.

      (c)   No undertaking by one Party to the other under any provision of
this Agreement shall constitute the dedication of that Party's system or any







                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-23



portion thereof to the other Party or to the public or affect the status of
PGandE as an independent public utility corporation or Seller as an
independent individual or entity and not a public utility.

A-12 SEVERAL OBLIGATIONS

      Except where specifically stated in this Agreement to be otherwise, the
duties, obligations, and liabilities of the Parties are intended to be several
and not joint or collective.  Nothing contained in this Agreement shall ever
be construed to create an association, trust, partnership, or joint venture or
impose a trust or partnership duty, obligation, or liability on or with regard
to either Party.  Each Party shall be liable individually and severally for
its own obligations under this Agreement.

A-13 NON-WAIVER

      Failure to enforce any right or obligation by either Party with respect
to any matter arising in connection with this Agreement shall not constitute a
waiver as to that matter or any other matter.









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                                                                 May 7, 1984

                                     A-24



A-14 ASSIGNMENT

      Neither Party shall voluntarily assign its rights nor delegate its
duties under this Agreement, or any part of such rights or duties, without the
written consent of the other Party, except in connection with the sale or
merger of a substantial portion of its properties.  Any such assignment or
delegation made without such written consent shall be null and void.  Consent
for assignment shall not be withheld unreasonably.  Such assignment shall
include, unless otherwise specified therein, all of Seller's rights to any
refunds which might become due under this Agreement.

A-15 CAPTIONS

      All indexes, titles, subject headings, section titles, and similar items
are provided for the purpose of reference and convenience and are not intended
to affect the meaning of the contents or scope of this Agreement.

A-16 CHOICE OF LAWS

      This Agreement shall be interpreted in accordance with the laws of the
State of California, excluding any choice of law rules which may direct the
application of the laws of another jurisdiction.






                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-25


A-17 GOVERNMENTAL JURISDICTION AND AUTHORIZATION

      Seller shall obtain any governmental authorizations and permits required
for the construction and operation of the Facility.  Seller shall reimburse
PGandE for any and all losses, damages, claims, penalties, or liability it
incurs as a result of Seller's failure to obtain or maintain such
authorizations and permits.

A-18 NOTICES

      Any notice, demand, or request required or permitted to be given by
either Party to the other, and any instrument required or permitted to be
tendered or delivered by either Party to the other, shall be in writing
(except as provided in Section C-3) and so given, tendered, or delivered, as
the case may be, by depositing the same in any United States Post Office with
postage prepaid for transmission by certified mail, return receipt requested,
addressed to the Party, or personally delivered to the Party, at the address
in Article 4 of this Agreement.  Changes in such designation may be made by
notice similarly given.









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                                                                 May 7, 1984

                                     A-26



A-19 INSURANCE

A-19.1  General Liability Coverage

      (a)   Seller shall maintain during the performance hereof, General
Liability Insurance ((1)) of not less than $1,000,000 if the Facility is over
100 kW, $500,000 if the Facility is over 20 kW to 100 kW, and $100,000 if the
Facility is 20 kW or below of combined single limit or equivalent for bodily
injury, personal injury, and property damage as the result of any one
occurrence.

      (b)   General Liability Insurance shall include coverage for Premises-
Operations, Owners and Contractors Protective, Products/Completed Operations
Hazard, Explosion, Collapse, Underground, Contractual Liability, and Broad
Form Property Damage including Completed Operations.

      (c)   Such insurance, by endorsement to the policy(ies), shall include
PGandE as an additional insured if the Facility is over 100 kW insofar as work
performed by Seller for PGandE is concerned, shall contain a severability of
interest clause, shall provide that PGandE shall not by reason of its
inclusion as an additional insured incur





                                                          
((1)) Governmental agencies which have an established record of self-insurance 
      may provide the required coverage through self-insurance.


                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-27



liability to the insurance carrier for payment of premium for such insurance,
and shall provide for 30-days' written notice to PGandE prior to cancellation,
termination, alteration, or material change of such insurance.

A-19.2   Additional Insurance Provisions

      (a)   Evidence of coverage described above in Section A-19.1 shall state
that coverage provided is primary and is not excess to or contributing with
any insurance or self-insurance maintained by PGandE.

      (b)   PGandE shall have the right to inspect or obtain a copy of the
original policy(ies) of insurance.

      (c)   Seller shall furnish the required certificates ((1)) and
endorsements to PGandE prior to commencing operation.

      (d)   All insurance certificates 1, endorsements, cancellations,
terminations, alterations, and material changes of such insurance shall be
issued and submitted to the following:

     PACIFIC GAS AND ELECTRIC COMPANY
     Attention: Manager - Insurance Department
     77 Beale Street, Room E280
     San Francisco, CA 94106



                                                          
((1)) A governmental agency qualifying to maintain self-insurance should       
provide a statement of self-insurance.


                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-28



A-20 REASONABLE ACTION BY EACH PARTY

      Any action required of either Party pursuant to this agreement,
including those in the sole discretion of one Party, shall be undertaken in a
reasonable manner and in a manner least likely to cause harm to the other
party.  This paragraph is not in any way intended to require special treatment
of Seller as compared to other QFs.



















                                                                 S.O. #2
                                                                 May 7, 1984

                                     A-29





                                  APPENDIX B
                                 ENERGY PRICES

                                    TABLE A

              Energy Prices Effective February 1 - April 30, 1985

      The energy purchase price calculations which will apply to energy
deliveries determined from meter readings taken during February, March and
April 1985 are as follows:

                  (a)           (b)              (c)                 (d)
                                         Revenue Requirement  Energy Purchase
             Incremental                      for Cash              Price
Time Period  Energy Rate  Cost of Energy   Working Capital   (d)={(a)x(b)}+(c)
                ((1))         ((2))              ((3))             ((4)) 
              (Btu/kWh)    ($/10-6 Btu)         ($/kWh)           ($/kWh)

February 1-
 April 30
(Period B)


Time of
Delivery
Basis:

On-Peak        16,320         5.2394           0.00053            0.08604
Partial-Peak   15,689         5.2394           0.00051            0.08271
Off-Peak       11,625         5.2394           0.00038            0.06129

Seasonal
Average
(Period B)     13,692         5.2394           0.00045            0.07219


____________________________________

((1)) Incremental energy rates (Btu/kWh) for Seasonal Period A and Seasonal    
      Period B are derived from the marginal energy costs (including variable
      operating and maintenance expense) adopted by the CPUC in Decision No.
      83-12-068 (page 339).  They are based upon natural gas as the            
      incremental fuel and weighted average hydroelectric power conditions.

((2)) Cost of natural gas under PGandE Gas Schedule No. G-55 effective         
      February 1, 1985 per Advice No. 1304-G.

((3)) Revenue Requirement for Cash Working Capital as prescribed by the CPUC   
      in Decision No. 83-12-068.

((4)) Energy Purchase Price = (Incremental Energy Rate x Cost of Energy) +     
      Revenue Requirement for Cash Working Capital.  The energy purchase price 
      excludes the applicable energy line loss adjustment factors.  However,   
      as ordered by Ordering Paragraph No. 12(j) of CPUC Decision No. 82-12-   
      120, this figure is currently 1.0 for transmission and primary           
      distribution loss adjustments and is equal to marginal cost line loss    
      adjustment factors for the secondary distribution voltage level.  These  
      factors may be changed by the CPUC in the future.  The currently    
      applicable energy loss adjustment factors are shown in Table C.


                                                               S.O. #2
                                                               May 7, 1984
                                      B-1

                                   TABLE B((1))
                                 Time Periods

                                     Monday
                                     through                       Sundays
                                     Friday        Saturdays    and Holidays
                                      ((2))          ((2))

Seasonal Period A
(May 1 through September 30)

      On-Peak                        12:30 p.m.
                                         to
                                      6:30 p.m.

      Partial-Peak                    8:30 a.m.      8:30 a.m.
                                         to             to
                                     12:30 p.m.     10:30 p.m.

                                      6:30 p.m.
                                         to
                                     10:30 p.m.

      Off-Peak                       10:30 p.m.      10:30 p.m.      All Day
                                         to              to
                                      8:30 a.m.       8:30 a.m.

Seasonal Period B
(October 1 through April 30)

      On-Peak                         4:30 p.m.
                                         to
                                      8:30 p.m.

      Partial-Peak                    8:30 p.m.       8:30 a.m.
                                         to              to
                                     10:30 p.m.      10:30 p.m.

                                      8:30 a.m.
                                         to
                                      4:30 p.m.

      Off-Peak                       10:30 p.m.      10:30 p.m.      All Day
                                         to              to
                                      8:30 a.m.       8:30 a.m.




____________________________________

((1)) This table is subject to change to accord with the on-peak, partial-     
      peak, and off-peak periods as defined in PGandE's own rate schedules for 
      the sale of electricity to its large industrial customers.

((2)) Except the following holidays: New Year's Day, Washington's Birthday,    
      Memorial Day, Independence Day, Labor Day, Veteran's Day, Thanksgiving   
      Day, and Christmas Day, as specified in Public Law 90-363 (5 U.S.C.A.    
      Section 6103(a)).

                                                                 S.O. #2
                                                                 May 7, 1984

                                      B-2

                                    TABLE C

                        Energy Loss Adjustment Factors ((1))



                                                 Primary           Secondary
                             Transmission      Distribution       Distribution


Seasonal Period A
(May 1 through September 30)

   On-Peak                        1.0               1.0               1.0148
   Partial-Peak                   1.0               1.0               1.0131
   Off-Peak                       1.0               1.0               1.0093

Seasonal Period B
(October 1 through April 30)

   On-Peak                        1.0               1.0               1.0128
   Partial-Peak                   1.0               1.0               1.0119
   Off-Peak                       1.0               1.0               1.0087




























____________________________________

((1)) The applicable energy loss adjustment factors may be revised pursuant to 
      orders of the CPUC.


                                                                 S.O. #2
                                                                 May 7, 1984

                                      B-3




                                   APPENDIX C

                         FIRM CAPACITY PRICE SCHEDULE


                                   CONTENTS


     Section                                                            Page

       C-1        GENERAL                                                 C-2

       C-2        PERFORMANCE REQUIREMENTS                                C-2

       C-3        SCHEDULED MAINTENANCE                                   C-5  
                                                             
       C-4        ADJUSTMENTS TO CONTRACT CAPACITY                        C-6

       C-5        PAYMENT OPTIONS                                         C-7

       C-6        DETERMINATION OF NATURAL FLOW DATA                      C-15

       C-7        THEORETICAL OPERATION STUDY                             C-16

       C-8        DETERMINATION OF AVERAGE DRY YEAR CAPACITY RATINGS      C-17

       C-9        INFORMATION REQUIREMENTS                                C-18

       C-10       ILLUSTRATIVE EXAMPLE                                    C-19





























                                                                 S.O. #2
                                                                 May 7, 1984

                                      C-1



                                  APPENDIX C

                         FIRM CAPACITY PRICE SCHEDULE


C-1   GENERAL

 

      This Appendix C establishes conditions and prices under which PGandE
shall pay for firm capacity.

C-2   PERFORMANCE REQUIREMENTS

      (a)   To receive full capacity payments the Facility must meet the
following requirements:
            (1)   The contract capacity shall be available ((1)) for all of    
      the on-peak hours 2 in the peak months on the PGandE system, which are   
      presently the months of June, July and August, subject to a 20 percent   
      allowance for forced outages in any month.  Compliance with this         
      provision shall be based on the Facility's total on-peak availability    
      ((1)) for each of the peak months and shall exclude any energy           
      associated with generation levels greater than the contract capacity.






____________________________________
((1)) For purposes of Option 1, available means either dispatchable by         
      PGandE or actually delivered to PGandE.  For purposes of Option 2,       
      available means actually delivered to PGandE.

((2)) On-peak, partial-peak, and off-peak hours are defined in Table B,        
      Appendix B.
                                                                 S.O. #2
                                                                 May 7, 1984

                                      C-2




            (2)   If Seller selects Option 1, the contract capacity shall be   
dispatchable throughout the year, subject to (i) a monthly allowance for forced
outages of 20% of the hours Seller is called upon to deliver power to PGandE
and (ii) the allowances for scheduled maintenance outages.  Except during the
peak months on the PGandE system, Seller may accumulate and apply the 20
percent allowance for forced outages for any consecutive three month period.
Seller shall demonstrate that the Facility is fueled by a reliable fuel supply
and adequate fuel storage is available to deliver power as requested by
PGandE's system dispatcher.  Such demonstration could reasonably include
documentation of the current availability of the fuel, identification of the
source, and production of contracts for its purchase and supply.

      (b)   If Seller is prevented from meeting the performance requirements
because of a forced outage on the PGandE system or a condition set forth       
in Section A-8, PGandE shall continue capacity payments.  Under Option 2,      
capacity payments will be calculated in the same manner used for       
scheduled maintenance outages.

      (c)   If Seller is prevents from meeting the performance requirements
because of force majeure, PGandE shall continue capacity payments for ninety
days from the occurrence of the force majeure.  Thereafter, Seller shall be






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                                                                 May 7, 1984

                                      C-3



deemed to have failed to have met the performance requirements.  Under Option
2, capacity payments will be calculated in the same manner used for scheduled
maintenance outages.

      (d)   If Seller is prevented from meeting the performance requirements
because of extreme dry year conditions, PGandE shall continue capacity
payments.  Extreme dry year conditions are drier than those used to establish
contract capacity pursuant to Section C-8.  Seller shall warrant to PGandE
that the Facility is a hydroelectric facility and that such conditions are the
sole cause of Seller's inability to meet its contract capacity obligations. 
Under Option 1, starting with the month in which Seller cannot provide its
contract capacity, payments shall be made under Option 2 for a one-year
period, and if at the end of this one-year period Seller is not able to resume
the contract capacity due solely to continued extreme dry year conditions,
Seller shall continue to receive payments under Option 2 for additional
one-year periods as long as such conditions continue to exist.

      (e)   If Seller is prevents from meeting the performance requirements
for reasons other than those described above in Sections C-2(b), (c) or (d):
            (1)   Seller shall receive the reduced capacity payments as        
provided in Section C-5 for a probationary period not to exceed 15        
months, or as otherwise agreed to by the Parties.






                                                                 S.O. #2
                                                                 May 7, 1984

                                      C-4



            (2)   If, at the end of the probationary period Seller has not     
demonstrated that the Facility can meet the performance requirements, PGandE 
may derate the contract capacity pursuant to Section C-4(b).

C-3   SCHEDULED MAINTENANCE

      Outage periods for scheduled maintenance shall not exceed 840 hours (35
days) in any 12-month period.  This allowance may be used in increments of an
hour or longer on a consecutive or nonconsecutive basis.  Seller may
accumulate unused maintenance hours from one 12-month period to another up to
a maximum of 1,080 hours (45 days).  This accrued time must be used
consecutively and only for major overhauls.  Seller shall provide PGandE with
the following advance notices: 24 hours for scheduled outages less than one
day, one week for a scheduled outage of one day or more (except for major
overhauls), and six months for a major overhaul.  Seller shall not schedule
major overhauls during the peak months (presently June, July and August). 
Seller shall make reasonable efforts to schedule or reschedule routine
maintenance outside the peak months, and in no event shall outages for
scheduled maintenance exceed 30 peak hours during the peak months.  Seller
shall confirm in writing to PGandE pursuant to Article 4, within 24 hours of








                                                                 S.O. #2
                                                                 May 7, 1984

                                      C-5



the original notice, all notices Seller gives personally or by telephone for
schedule maintenance.

C-4   ADJUSTMENTS TO CONTRACT CAPACITY

      (a)   Seller may increase the contract capacity with the approval of
PGandE and receive payment for the additional capacity thereafter in
accordance with the applicable capacity purchase price published by PGandE at
the time the increase is first delivered to PGandE.

      (b)   Seller may reduce the contract capacity at any time by giving
notice thereof to PGandE, subject to the provisions of Appendix D if the
reduction occurs after the actual operation date.  PGandE may reduce the
contract capacity in accordance with Section C-2(e) as a result of appropriate
data showing Seller has failed to meet the performance requirements of Section
C-2.  The amount by which the contract capacity is reduced by PGandE shall be
deemed a capacity sale reduction without notice as provided in Section D-3 of
Appendix D.

      (c)   Either Party may request, when it reasonably appears that the
capacity of the Facility may have changed for any reason, that a new contract
capacity be determined.






                                                                 S.O. #2
                                                                 May 7, 1984

                                      C-6



C-5   PAYMENT OPTIONS

      Seller has two options for calculation of capacity payments and Seller
has made its selection in Article 3(a).  As used below in this section, month
refers to a calendar month.  The two options are as follows:

                                   Option 1

      When Seller meets the requirements of Section C-2 the monthly payment
for capacity will be one-twelfth of the product of the contract capacity
price, the contract capacity, the appropriate capacity loss adjustment factor
from Table A based on the Facility's interconnection voltage, and the
appropriate performance bonus factor, if any, from Table C.  Capacity payments
will continue during scheduled maintenance outages provided that the
provisions of Section C-3 are met.

      During a probationary period Seller's monthly payment for capacity shall
be determined by substituting for the contract capacity, the capacity at which
Seller would have met the performance requirements.  In any month during the
probationary period that Seller does not meet the performance requirements at
whatever capacity was determined for the previous month, Seller's monthly
payment for capacity shall be determined by substituting the capacity at which
Seller would have met the performance requirements.





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                                                                 May 7, 1984

                                      C-7



The performance bonus factor shall not be applied during a probationary
period.

                                   Option 2

      The monthly payment for capacity will be the product of the Period Price
Factor (PPF), the Monthly Delivered Capacity (MDC), the appropriate capacity
loss adjustment factor from Table A based on the Facility's interconnection
voltage, and the appropriate performance bonus factor, if any, from Table C,
plus any allowable payment for outages due to scheduled maintenance.  Firm
capacity prices shall be applied to meter readings taken during the separate
times and periods as illustrated in Table B, Appendix B.

      The PPF is determined by multiplying the contract capacity price by the
following Option 2 Allocation Factors ((1)):
                   Option 2              Contract                  PPF
               Allocation Factor   x   Capacity Price     =   ($/kW-month)

Seasonal
Period A             .18540            ______________          __________

Seasonal
Period B             .01043            ______________          __________












____________________________________

((1)) These allocation factors were prescribed by the CPUC in Decision No. 
      83-12-068.  All allocation factors are subject to change by PGandE
      marginal capacity cost allocation, as determined in general rate case
      proceedings before the CPUC.  Seasonal Periods A and B are defined in
      Table B, Appendix B.

                                                                 S.O. #2 
                                                                 May 7, 1984

                                      C-8



The MDC is determined in the following manner:
      (1)   Determine the Performance Factor (P), which is defined as the
lesser of 1.0 or the following quantity:
                P = ___________A___________          (<= 1.0)
                      C x (B-S) x (0.8*)


Where:
A =   Total kilowatt-hours delivered during all on-peak and partial-peak hours
      excluding any energy associated with generation levels greater than the  
     contract capacity.
C =   Contract capacity in kilowatts.
B =   Total on-peak and partial-peak hours during the month.
S =   Total on-peak and partial-peak hours during the month Facility is out of 
      service on scheduled maintenance.

      (2)   Determine the Monthly Capacity Factor (MCF), which is computed
using the following expression:
                                             M 
                            MCF = P x (1.0 - - ) 
                                             D

Where:

M =   The number of hours during the month Facility is out of service on       
      scheduled maintenance.
D =   The number of hours in the month.





____________________________________

* 0.8 reflects a 20% allowance for forced outage.


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                                                                 May 7, 1984

                                      C-9



      (3)   Determine the MDC by multiplying the MCF by C:

                    MDC (kilowatts) = MCF x C

            The monthly payment for capacity is then determined by multiplying
the PPF by the MDC, by the appropriate capacity loss adjustment factor
presented from Table A, and by the appropriate performance bonus factor, if
any, from Table C.

monthly payment                          capacity loss       performance
 for capacity      =   PPF  x  MDC  x  adjustment factor  x  bonus factor

            
            Furthermore, the payment for a month in which there is an outage
for scheduled maintenance shall also include an amount equal to the produce of
the average hourly capacity payment ((1)) for the most recent month in the
same type of Seasonal Period (i.e., Seasonal Period A or Seasonal Period B)
during which deliveries were made times the number of hours of outage for
scheduled maintenance in the current month.  Capacity payments will continue
during the outage periods for scheduled maintenance provided that the
provisions of Section C-3 are met.

            During a probationary period, Seller's monthly payment for
capacity shall be determined by substituting for the contract capacity, the
capacity at which Seller would have met the performance requirements.  In




____________________________________

((1)) Total monthly payment divided by the total number of hours in the       
monthly billing period.


                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-10




the event that during the probationary period Seller does not meet the
performance requirements at whatever capacity was established for the previous
month, Seller's monthly payment for capacity shall be determined by
substituting the capacity at which Seller would have met the performance
requirements.  The performance bonus factor shall not be applied during
probationary periods.

                                    TABLE A

If the Facility is non-remote 1 the capacity loss adjustment factors are as
follows:

                                                           Capacity Loss
Interconnection Voltage                                   Adjustment Factor

Transmission                                                      .989

Primary Distribution                                              .991

Secondary Distribution                                            .991


If the Facility is remote the capacity loss adjustment factor is
___________((1)).



____________________________________

((1)) The Seller acknowledges that this blank cannot be filled in at the time  
      of executing this Agreement because the information is not yet available 
      to make a definitive determination of whether the Facility is remote or  
      non-remote and, if remote, the number to be inserted in this blank.
      Seller shall request PGandE to perform a capacity loss adjustment factor 
      study to be done in its accustomed manner of making such studies to      
      determine whether the Facility is remote or non-remote and, if remote the
      number to be inserted.  If the Facility is determined to be non-remote,
      N/A shall be inserted.



                                                                 S.O. #2
                                                                 May 7, 1984
                                     C-11



                                    TABLE B

                         Firm Capacity Price Schedule
                             (Levelized $/kW-year)

  Actual
Operation
   Date                        Term of Agreement

  (Year)       1     2    3     4     5     6     7     8     9     10

   1983       72   111   96    88    84    85    88    91    93     96
   1984      156   111   95    88    89    92    95    98   100    103
   1985       60    58   59    66    73    79    84    88    92     95
   1986       56    58   69    78    85    90    95    99   103    106
   1987       61    77   88    95   101   105   109   113   117    120
   1988       96   104  110   115*  119   122   126   129   133    136




  (Year)      11    12   13    14    15    20    25    30 
    
   1983       98   100  102   104   106   115   122   128
   1984      105   108  110   112   114   124   131   137
   1985       99   102  104   107   110   121*  127*  135
   1986      110   113  116   118   121   132   141   148
   1987      124   127  130   132   135   147   156   163
   1988      139   142  145   148   151   163   173   180












____________________________________

*  In its Application for Rehearing and/or Petition for Modification of CPUC   
   Decision 83-12-068 (dated December 22, 1983) filed on February 6, 1984,     
   PGandE requests correction of three numbers which were incorrectly          
   presented in the Firm Capacity Price Schedule included in that decision (p. 
   349, Table VI-4).  The correct number for 1985 for a 20-year contract life  
   should be $120/kW-yr, and for a 25-year contract life should be $129/kW-yr. 
   The correct number for 1988 for a 4-year contract life should be $115/kW-   
   yr.  When the CPUC issues an order correcting these numbers, PGandE shall   
   correct the Firm Capacity Price Schedule accordingly.


                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-12




                                    TABLE C


                           Performance Bonus Factor

      The following shall be the performance bonus factors applicable to the
calculation of the monthly payments for capacity delivered by the Facility
after it has demonstrated a capacity factor in excess of 85%.

                 DEMONSTRATED
               CAPACITY FACTOR                    PERFORMANCE
                      %                           BONUS FACTOR

                 
                      85                              1.000
                      90                              1.059
                      95                              1.118
                     100                              1.176


      After the Facility has delivered power during the span of all of the
peak months on the PGandE system (presently June, July and August) in any hear
(span),

      (i)   the capacity factor for each such month shall be calculated in the
following manner:

               CAPACITY FACTOR (%) =        F      x 100
                                       (N-W) x Q  

Where:

                                 For Option 1

      F =   Total kilowatt-hours delivered by Seller in any peak month during  
            all on-peak hours that Sellers is asked to deliver power to PGandE

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                                                                 May 7, 1984

                                     C-13



            excluding any energy associated with generatin levels greater   
            than the contract capacity.
      N =   Total on-peak hours that Seller is asked to deliver power to       
            PGandE during the month.
      W =   Total on-peak hours during the peak month that the Facility is
            out of service on scheduled maintenance during the on-peak hours
            that Seller is asked to deliver power to PGandE.
      Q =   Contract capacity in kilowatts.

                                 For Option 2

      F =   Total kilowatt-hours delivered by Seller in any peak month during
            all on-peak hours excluding any energy associated with generation
            levels greater than the contract capacity.
      N =   Total on-peak hours during the month.
      W =   Total on-peak hours during the peak month that the Facility is out
            of service on scheduled maintenance.
      Q =   Contract capacity in kilowatts.

      (ii) the arithmetic average of the above capacity factors shall be
determined for that span,

      (iii) the average of the above arithmetic average capacity factors for
the most recent span(s), not to exceed 5, shall be calculated and shall become
the Demonstrated Capacity Factor.



                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-14



            To calculate the performance bonus factor for a Demonstrated
Capacity Factor not shown in Table D use the following formula:

Performance Bonus Factor = Demonstrated Capacity Factor (%)
                                        85%



THE FOLLOWING SECTIONS SHALL APPLY ONLY TO HYDROELECTRIC PROJECTS

C-6   DETERMINATION OF NATURAL FLOW DATA

      Natural flow data shall be based on a period of record of at least 50
years and which includes historic critically dry periods.  In the event Seller
demonstrates that a natural flow data base of at least 50 years would be
unreasonably burdensome, PGandE shall accept a shorter period of record with a
corresponding reduction in the averaging basis set forth in Section C-8. 
Seller shall determine the natural flow data by month by using one of the
following methods:
                                   Method 1
      If stream flow records are available from a recognized gauging station
on the water course being developed in the general vicinity of the project,
Seller may use the data from them directly.







                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-15




                                   Method 2

      If directly applicable flow records are not available, Seller may
develop theoretical natural flows based on correlation with available flow
data for the closest adjacent and similar area which has a recognized gauging
station using generally accepted hydrologic estimating methods.

C-7   THEORETICAL OPERATION STUDY

      Based on the monthly natural flow data developed under Section C-6 a
theoretical operation study shall be prepared by Seller.  Such a study shall
identify the monthly capacity rating in kW and the monthly energy production
in kWh for each month of each year.  The study shall take into account all
relevant operating constraints, limitations, and requirements including but
not limited to --
      (1)   Release requirements for support of fish life and any other
operating constraints imposed on the project;
      (2)   Operating characteristics of the proposed equipment of the
Facility such as efficiencies, minimum and maximum operating levels, project
control procedures, etc.;









                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-16



      (3)   The design characteristics of project facilities such as head
losses in penstocks, valves, tailwater elevation levels, etc.; and
      (4)   Release requirements for purposes other than power generation such
as irrigation, domestic water supply, etc.
      The theoretical operation study for each month shall assume an even
distribution of generation throughout the month unless Seller can demonstrate
that the Facility has water storage characteristics.  For the study to show
monthly capacity ratings, the Facility shall be capable of operating during
all on-peak hours in the peak months on PGandE system, which are presently the
months of June, July and August.  If the project does not have this capability
throughout each such month, the capacity rating in that month of that year
shall be set at zero for purposes of this theoretical operation study.

C-8   DETERMINATION OF AVERAGE DRY YEAR CAPACITY RATINGS
      
      Based on the results of the theoretical operation study developed under
Section C-7, the average dry year capacity rating shall be established for
each month.  The average dry year shall be based on the average of the five
years of the lowest annual generation as shown in the theoretical operation
study.  Once such years of lowest annual generation are identified, the
monthly capacity rating is determined for each month by averaging the capacity







                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-17



ratings from each month of those years.  The contract capacity shown in
Article 2(a) shall not exceed the lowest average dry year monthly capacity
ratings for the peak months on the PGandE system, which are presently the
months of June, July and August.

C-9   INFORMATION REQUIREMENTS

      Seller shall provide the following information to PGandE for its review:
      (1)   A summary of the average dry year capacity ratings based on the
theoretical operation study as provided in Table D;
      (2)   A topographic project map which shows the location of all aspects
of the Facility and locations of stream gauging stations used to determine
natural flow data;
      (3)   A discussion of all major factors relevant to project operation;
      (4)   A discussion of the methods and procedures used to establish the
natural flow data.  This discussion shall be in sufficient detail for PGandE
to determine that the methods are consistent with those outlined in Section 
C-6 and are consistent with generally accepted engineering practices; and
      (5)   Upon specific written request by PGandE, Seller's theoretical
operation study.








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                                                                 May 7, 1984

                                     C-18



C-10  ILLUSTRATIVE EXAMPLE

      (1)   Determine natural flows - These flows are developed based on
historic stream gauging records and are compiled by month, for a long-term
period (normally at least 50 years or more) which covers dry periods which
historically occurred in the 1920's and 30's and more recently in 1976 and 77. 
In all but unusual situations this will require application of hydrological
engineering methods to records that are available, primarily from the USGS
publication Water Resources Data for California.

      (2)   Perform theoretical operation study - Using the natural flow data
compiled under (1) above a theoretical operation study is prepared which
determines, for each month of each year, energy generation (kWh) and capacity
rating (kW).  This study is performed based on the Facility's design,
operating capabilities, constraints, etc., and should take into account all
factors relevant to project operation.  Generally such a study is done by
computer which routes the natural flows through project features, considering
additions and withdrawals from storage, spill past the project, releases for
support of fish life, etc., to determine flow available for generation.  Then
the generation and capacity amounts are computed based on equipment
performance, efficiencies, etc.







                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-19



      (3)   Determine average dry year capacity ratings - After the
theoretical project operation study is complete the five years in which the
annual generation (kWh) would have been the lowest are identified.  Then for
each month, the capacity rating (kW) is averaged for the five years to arrive
at a monthly average capacity rating.  The contract capacity is then set by
the Seller based on the monthly average dry year capacity ratings and the
performance requirements of Appendix C.  An example project is shown in the
attached completed Table D.




















                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-20



                                    EXAMPLE


                                    TABLE D

                    Summary of Theoretical Operation Study


Project:   New Creek 1                    Dispatchable:   Yes ___ No __X__
Water Source:   West Fork New Creek
Mode of Operation: Run of the river
Type of Turbine: Francis     Design Flow:   100 cfs   Design Head: 150 feet
Operating Characteristics ((1)):
                       Flow      Head (feet)    Output      Efficiency (%)
                       (cfs)     Gross   Net     (kW)     Turbine   Generator

Normal Operation        100       160    150    1,120        90         98
Maximum Operation       110       160    148    1,150        85         98
Minimum Operation        30       160    155      290        75         98


Average Dry Year Operation - Based on the average of the following lowest
generation years: 1930, 1932, 1934, 1949, 1977.


          Energy Generation       Capacity Output      Percent of Total
Month         (kWh)                    (kW)           Hours Operated ((2))

January        855,000                 1,150                  100
February       753,000                 1,120                  100
March          818,000                 1,100                  100
April          727,000                 1,010                  100
May            699,000                   940                  100
June           612,000                   850                  100
July           484,000                   650                  100
August         305,000                   410                  100
September      245,000                   340                  100
October        148,800                   200                  100
November       468,000                   650                  100
December       595,000                   800                  100

Maximum Contract Capacity: 410 kW





____________________________________

((1)) If Facility has a variable head, operating curves should be provided.

((2)) For this to be less than 100%, Facility must be dispatchable.

                                                                 S.O. #2
                                                                 May 7, 1984

                                     C-21


                                  APPENDIX D

                        ADJUSTMENT OF CAPACITY PAYMENTS
                    IN THE EVENT OF TERMINATION OR REDUCTION                   
                    
                                   CONTENTS

Section                                                                  Page
  D-1       GENERAL PROVISIONS                                            D-2
  D-2       TERMINATION WITH PRESCRIBED NOTICE                            D-4  
  D-3       TERMINATION WITHOUT PRESCRIBED NOTICE                         D-5
  D-4       TERMINATION EXAMPLES                                          D-6

















                                                                 S.O. #2
                                                                 May 7, 1984

                                      D-1




                                  APPENDIX D
                        ADJUSTMENT OF CAPACITY PAYMENTS
                   IN THE EVENT OF TERMINATION OR REDUCTION

D-1   GENERAL PROVISIONS
  
      (a)   This Appendix shall be applicable in the event there is a contract
termination or a capacity sale reduction (each sometimes referred to as
termination in this Appendix D).

      (b)   The Parties agree that the amount which PGandE pays Seller for the
capacity which Seller makes available to PGandE is based on the agreed value
to PGandE of Seller's performance of capacity obligations during the full
period of the term of agreement.  The Parties further agree that in the event
PGandE does not receive such full performance by reason of a termination:
            (1)   PGandE shall be deemed damaged by reason thereof,
            (2)   it would be impracticable or extremely difficult to fix the
      actual damages to PGandE resulting therefrom,
            (3)   the refunds and payments as provided in Sections D-2 and 
      D-3, as applicable, are in the nature of adjustments in capacity prices  
      and liquidated damages, and not a penalty, and are fair and reasonable,
      and 






                                                                 S.O. #2
                                                                 May 7, 1984

                                      D-2



            (4)  such refunds and payments represent a reasonable endeavor by  
the Parties to estimate a fair compensation for the reasonable losses that
would result from such termination or reduction.

      (c)   In the event of a capacity sale reduction, the quantity by which
the contract capacity is reduced shall be used to calculate the payments due
PGandE in accordance with Sections D-2 and D-3, as applicable.

      (d)   Seller shall be invoiced by PGandE for all refunds and payments
due under this Appendix D and the special facilities agreement.  From the date
of the notice of termination or the date of termination, whichever is earlier,
Seller shall pay interest, compounded monthly, on all overdue amounts, at the
published Federal Reserve Board three months' Prime Commercial Paper rate.

      (e)   If Seller does not make payments pursuant to Section D-1(d),
PGandE shall have the right to offset any amounts due it against any present
or future payments due Seller.

      (f)   Notices of termination shall be made in accordance with Section 
A-18 of Appendix A.








                                                                 S.O. #2
                                                                 May 7, 1984

                                      D-3



D-2   TERMINATION WITH PRESCRIBED NOTICE

      In the event Seller terminates this entire Agreement, or all or part of
the contract capacity thereof, with the following prescribed written notice:

        Amount of Contract Capacity                          Length of
                Terminated                                Notice Required

        1,000 kW or under                                       3 months
        over 1,000  kW through  10,000 kW                       9 months
        over 10,000 kW through  25,000 kW                      12 months
        over 25,000 kW through  50,000 kW                      36 months
        over 50,000 kW through 100,000 kW                      48 months
        over 100,000 kW                                        60 months


Then the following provisions shall apply:
      (1)   With respect to the amount by which the contract capacity is
reduced, Seller shall refund to PGandE an amount equal to the difference
between (a) the capacity payments already paid by PGandE, based on the
original term of agreement and (b) the total capacity payments which PGandE
would have paid based on the period of Seller's actual performance using the
adjusted capacity price.  Additionally, Seller shall pay interest, compounded
monthly, on all overpayments, at the published Federal Reserve Board three
months' Prime Commercial Paper rate.
      (2)   From the date PGandE receives the termination notice to the date
of actual termination, PGandE shall make capacity payments based on the
adjusted capacity price for the amount of contract capacity being terminated.





                                                                 S.O. #2
                                                                 May 7, 1984

                                      D-4




      (3)   From the date PGandE receives the termination notice, PGandE shall
continue to pay for the amount of contract capacity not being terminated, if
any, at the original contract capacity price.

D-3   TERMINATION WITHOUT PRESCRIBED NOTICE

      (a)   If Seller terminates this Agreement, or all or a part of the
contract capacity thereof, without the notice prescribed in Section D-2, the
provisions prescribed in Section D-2 will all apply.  Additionally:

      (b)   Seller shall pay PGandE a sum equal to the amount by which the
contract capacity is being terminated times the difference between the current
firm capacity price on the date of termination for a term equal to the balance
of the term of agreement and the contract capacity price, pro-rated for the
length of notice given by multiplying by the difference between the prescribed
length of notice and the actual notice given, with the difference divided by
12.  In the event that the current firm capacity price is less than the
contract capacity price, no payment under this Section D-3 shall be due either
Party.
      This additional payment shall be computed using the following formula:

                          G = CC x (T - CCP) x J - H
                                                 12




                             





                                                                 S.O. #2
                                                                 May 7, 1984

                                      D-5



Where G >= O

and where:

G   = additional payment.
CC  = the amount by which the contract capacity is being terminated.
T   = the current firm capacity price.
CCP = the contract capacity price.
H   = the actual number of months notice given.
J   = the prescribed length of notice.

D-4   TERMINATION EXAMPLES

      These examples demonstrate how to calculate capacity payment adjustments
when capacity sales are terminated.

(a)   Termination with Prescribed Notice
      (1) Example Based on Option 1
          Assumptions:
           i.  Term of Agreement is 15 years;
          ii.  Actual operation date is July 1, 1985;
         iii.  Prescribed notice is given on July 1, 1986;








                                                                 S.O. #2
                                                                 May 7, 1984

                                      D-6



          iv.  Contract capacity to be reduced by 10,000 kW on July 1 1987;    
               actual performance to be from July 1, 1985 through July 1, 1987 
              ((1));
           v.  The applicable capacity loss adjustment factor is .989; and
          vi.  No performance bonus for capacity has been earned.

          The amount of overpayment (E) made by PGandE to Seller during each   
    monthly billing period is calculated as follows:
                        E = (A-B) x C x L x U
      Where:
      A =   contract capacity price per month for the actual operation date
            (July 1, 1985) and the term of agreement which is 15 years =
            $110/kW-yr / 12 mo/yr = $9.17/kW-mo.
      B =   adjusted capacity price per month for the actual operation date
            (July 1, 1984) and a two-year agreement term = 
            $58/kW-hr / 12 mo/yr = $4.83/kW-mo.









____________________________________

((1)) The capacity payment is adjusted upon receiving notice, so no refund is  
      necessary for the last month of the first twelve months of operation and 
      all of the second twelve months (June 1, 1986 to July 1, 1987).  Seller  
      performed for eleven month prior to payment adjustment.  (Note that due  
      to the 30-day interval between delivery and payment, performance in the  
      twelfth month (June 1986) can be paid for at the adjusted capacity price.



                                                                 S.O. #2
                                                                 May 7, 1984
                                      D-7

      C =   amount by which the contract capacity is being reduced = 
            10,000 kW.
      L =   capacity loss adjustment factor = .989.
      U =   performance bonus factor; when Seller does not qualify for a       
            performance bonus factor, as in this example, U is removed from    
            the above calculation of E.
      Therefore:
      E =   ($9.17/kW-mo - $4.83/kW-mo) x 10,000 kW x .989 = $42,923 per       
            month.

            Table A shows a step-by-step derivation of the refund Seller owes  
PGandE for the early termination outlined above.  The $497,342 that Seller owes
PGandE appears at the lower right-hand corner of the table.  All other figures  
of this table represent intermediate calculation steps.














                                                                 S.O. #2
                                                                 May 7, 1984

                                      D-8



                                    TABLE A

  (a)       (b)        (c)       (d)        (e)          (f)           (g)
 
                                                     Interest
                     Amount     Accumu-              Charge on
Monthly                of       lated                Accumulated    Balance
Billing   Date of     Over-     Over-      Interest  Overpayment      (g) =
Period    Payment    Payment   Payment       Rate    (f)=(d)x(e)   (c)+(d)+(f)
((1))      ((2))      ((3))     ((4))       ((5))       ((6))         ((7))
                        $         $           %           $              $

 7/85      8/30/85   42,923           0      1.2             0        42,923
 8/85      9/30/85   42,923      42,923      1.0           429        86,275
 9/85     10/30/85   42,923      86,275      0.9           776       129,974
10/85     11/30/85   42,923     129,974      0.8         1,040       173,937
11/85     12/30/85   42,923     173,937      0.7         1,218       218,078
12/85      1/30/86   42,923     218,078      0.8         1,745       262,746
 1/86      3/ 2/86   42,923     262,746      0.9         2,365       308,034
 2/86      3/30/86   42,923     308,034      1.0         3,080       354,037
 3/86      4/30/86   42,923     354,037      1.1         3,894       400,854
 4/86      5/30/86   42,923     400,854      1.2         4,810       448,587
 5/86      6/30/86   42,923     448,587      1.3         5,832       497,342





____________________________________

((1)) The month in which power deliveries were made.  For purposes of          
      simplification, the monthly billing period will coincide exactly with    
      each calendar month.

((2)) The date on which payment for the monthly billing period state in column 
      (a) is made.

((3)) The amount of overpayment made by PGandE to Seller during each monthly   
      billing period.

((4)) The amount of overpayment accumulated up through last month's date of    
      payment.

((5)) The interest rate for the period between the date of payment for the
      previous monthly billing period and the date of payment for this monthly
      billing period.  These interest rates are arbitrarily chosen for use in
      this example.

((6)) The amount of interest charge accrued between the date of payment for the
      previous monthly billing period and the date of payment for this monthly
      billing period on the accumulated overpayment balance existing as of the
      previous monthly billing period's date of payment.

((7)) The amount Seller owes PGandE at this stage of the calculation.  The     
      balance (g) for a given monthly billing period equals the accumulated
      overpayment (d) for the monthly billing period immediately following.

                                                                 S.O. #2
                                                                 May 7, 1984

                                      D-9



      (2)   Example Based on Option 2

            Assumptions:

             i.   Term of agreement is 15 years;
            ii.   Actual operation date is April 1, 1985;
           iii.   Prescribed notice is given on April 1, 1987;
            iv.   Contract capacity is reduced by 10,000 kW on April 1,
                  1988; actual performance is from April 1, 1985 through
                  April 1, 1988((1));
             v.   Scheduled outage for maintenance: 18 days = 432 hours
                  in both November 1985 and November 1986;
            vi.   The applicable capacity loss adjustment factor is .989;
                  and
           vii.   Listed below is Seller's Performance Factor (P), the 
                  Demonstrated Capacity Factor (Y) in % (when measured),
                  and where applicable, the performance bonus factor (U)
                  earned for each of the monthly billing periods((2)) prior
                  to the time capacity payment is adjusted.  Also listed
                  below are the number of hours the Facility was out of
                  service for schedule maintenance (M) and the number of
                  hours in the month (D) for each of these months.

____________________________________

((1)) The capacity payment is adjusted upon receiving notice, so no refund is  
      necessary for the last month of the first twenty-four months of operation 
      and all of the last twelve months (March 1, 1987 to April 1, 1988).  
      Seller performed for twenty-three months prior to payment adjustment.  
      (Note that due to the 30-day interval between delivery and payment, 
      performance in the twenty-fourth month (March 1987) can be paid for at
      the adjusted capacity price.)

((2)) For purposes of simplification, the monthly billing period will coincide
      exactly with each calendar month.




                                                                 S.O. #2
                                                                 May 7, 1984
                                     D-10



Monthly Billing Period        P        Y       U         M         D

April            1985        .85       -       -          0       720
May              1985        .95       -       -          0       744
June             1985        .90       80      -          0       720
July             1985       1.00       88      -          0       744
August           1985        .90       96      -          0       744
September        1985       1.00       -     1.035*       0       720
October          1985        .96       -     1.035        0       744
November         1985        .98       -     1.035      432       720
December         1985       1.00       -     1.035        0       744
January          1986       1.00       -     1.035        0       744
February         1986        .92       -     1.035        0       672
March            1986        .85       -     1.035        0       744
April            1986        .78       -     1.035        0       720
May              1986       1.00       -     1.035        0       744
June             1986        .94      100    1.035        0       720
July             1986        .95       95    1.035        0       744
August           1986       1.00       92    1.035        0       744
September        1986       1.00       -     1.080**      0       720
October          1986        .93       -     1.080        0       744
November         1986        .84       -     1.080      432       720
December         1986        .88       -     1.080        0       744
January          1987        .94       -     1.080        0       744
February         1987       1.00       -     1.080        0       672















____________________________________

*  This performance bonus factor was calculated by averaging the Demonstrated
   Capacity Factors for each of the months of June, July and August 1985, and
   then dividing that average by 85(%):

                         U = 80 + 88 + 96  / 85 = 1.035
                                  3

** This performance bonus factor was calculated by averaging the Demonstrated
   Capacity Factors for each of the months of June, July and August 1985, and
   June, July and August 1986, and then dividing that average by 85(%):

                         U = 80 + 88 + 96 + 100 + 95 + 92 / 85 = 1.080
                                       6



                                                                 S.O. #2
                                                                 May 7, 1984

                                     D-11



      The amount of overpayment (E) made by PGandE to Seller during each
monthly billing period is calculated as follows:

E = [P x (1 - M) x K x L x U x (A - B) x C] + [M x R]
              D                                D

Where:
P =   performance factor.
M =   number of hours of scheduled maintenance for that monthly billing        
      period.
D =   number of hours in that monthly billing period.
K =   allocation factor from Section C-5.
L =   capacity loss adjustment factor = .989.
U =   performance bonus factor; when Seller does not qualify for a performance
      bonus factor, U is removed from the above calculation of E.
A =   Contract capacity price for the actual operation date (April 1, 1985)    
      and term of agreement which is 15 years = $110/kW-yr.
B =   adjusted capacity price for the actual operation date and a three-year
      agreement term = $59/kW-yr.
C =   amount by which the contract capacity is being reduced = 10,000 kW.







                                                                 S.O. #2
                                                                 May 7, 1985




                                     D-12



R =   amount of overpayment for the most recent monthly billing period in
      the same Seasonal Period (i.e., Seasonal Period A or Seasonal Period
      B).

The results of the calculations are:
                                                 Amount of
Monthly Billing Period                          Overpayment (E)

April            1985                             $  4,472
May              1985                               88,838
June             1985                               84,163
July             1985                               93,514
August           1985                               84,163
September        1985                               96,787
October          1985                                5,227
November         1985                                5,271
December         1985                                5,445
January          1986                                5,445
February         1986                                5,009
March            1986                                4,628
April            1986                                4,247
May              1986                               96,787
June             1986                               90,980
July             1986                               91,948
August           1986                               96,787
September        1986                              100,995
October          1986                                5,284
November         1986                                5,079
December         1986                                5,000
January          1987                                5,341
February         1987                                5,682

      Table B shows a step-by-step derivation of the refund Seller owes PGandE
for the early termination outlined above.  The $1,136,015 that Seller owes
PGandE appears at the lower right-hand corner of the table.  All other figures
of this table represent intermediate calculation steps.





                                                                 S.O. #2
                                                                 May 7, 1984

                                     D-13




                                    TABLE B



  (a)       (b)        (c)       (d)        (e)          (f)           (g)
 
                                                     Interest
                     Amount     Accumu-              Charge on
Monthly                of       lated                Accumulated    Balance
Billing   Date of     Over-     Over-      Interest  Overpayment      (g) =
Period    Payment   Payment    Payment      Rate     (f)=(d)x(e)   (c)+(d)+(f)
 ((1))     ((2))      ((3))     ((4))       ((5))       ((6))          ((7))
                        $         $           %           $              $

 4/85     5/30/85      4,472          0       1.3             0          4,472
 5/85     6/30/85     88,838      4,472       1.4            63         93,373
 6/85     7/30/85     84,163     93,373       1.3         1,214        178,750
 7/85     8/30/85     93,514    178,750       1.2         2,145        274,409
 8/85     9/30/85     84,163    274,409       1.0         2,744        361,316
 9/85    10/30/85     96,787    361,316       0.9         3,252        461,355
10/85    11/30/85      5,227    461,355       0.8         3,691        470,273
11/85    12/30/85      5,271    470,273       0.7         3,292        478,836
12/85     1/30/86      5,445    478,836       0.8         3,831        488,112
 1/86     3/ 2/86      5,445    488,112       0.9         4,393        497,950
 2/86     3/30/86      5,009    497,950       1.0         4,980        507,939
 3/86     4/30/86      4,628    507,939       1.1         5,587        518,154
 4/86     5/30/86      4,247    518,154       1.2         6,218        528,619
 5/86     6/30/86     96,787    528,619       1.3         6,872        632,278
 6/86     7/30/86     90,980    632,278       1.4         8,852        732,110
 7/86     8/30/86     91,948    732,110       1.4        10,250        834,308
 8/86     9/30/86     96,787    834,308       1.3        10,846        941,941
 9/86    10/30/86    100,995    941,941       1.2        11,303      1,054,239
10/86    11/30/86      5,284  1,054,239       1.0        10,542      1,070,065
11/86    12/30/86      5,079  1,070,065       1.1        11,771      1,086,915
12/86     1/30/87      5,000  1,086,915       1.1        11,956      1,103,871
 1/87     3/ 2/87      5,341  1,103,871       1.0        11,039      1,120,251
 2/87     3/30/87      5,682  1,120,251       0.9        10,082      1,136,015

____________________________________

((1)) The month in which power deliveries were made.  For purposes of          
      simplification, the monthly billing period will coincide exactly with    
      each calendar month.
((2)) The date on which payment for the monthly billing period stated in       
      column (a) is made.
((3)) The amount of overpayment made by PGandE to Seller during each monthly   
      billing period.
((4)) The amount of overpayment accumulated up through last month's date of    
      payment.
((5)) The interest rate for the period between the date of payment for the
      previous monthly billing period and the date of payment for this monthly
      billing period.  These interest rates are arbitrarily chosen for use in
      this example.
((6)) The amount of interest charge accrued between the date of payment for    
      the previous monthly billing period and the date of payment for this     
      monthly billing period on the accumulated overpayment balance existing   
      as of the previous monthly billing period's date of payment.
((7)) The amount Seller owes PGandE at this stage of the calculation.  The     
      balance (g) for a given monthly billing period equals the accumulated
      overpayment (d) for the monthly billing period immediately following.

                                                                 S.O. #2
                                                                 May 7, 1984
                                     D-14

(b)   Termination without Prescribed Notice

      If Seller terminates without prescribed notice, Seller will owe PGandE a
refund [the calculation of which is described in Sections D-4(a)(1) and D-4(a)
(2) of this example] and payment (G).  This example demonstrates how the
payment (G) is calculated.  Assumptions:
          i.  Term of agreement is 15 years;
         ii.  Actual operation date is July 1, 1985;
        iii.  Notice is given on January 1, 1990; and
         iv.  Contract capacity is to be reduced by 10,000 kW on July 1, 1990;
              actual performance is from July 1, 1985 through July 1, 1990.

      The payment (G) is calculated as follows:
          (G) = CC x (T-CCP) x J-H   G >= O
                                12

      Where:
      CC  = The amount of contract capacity being terminated = 10,000 kW.
      T   = the current firm capacity price $140/kW-yr is arbitrarily chosen
            for use in this example for a July 1, 1990 Operation Date and 
            10-year agreement term.
      CCP = the contract capacity price = $110/kW-yr.
      H   = the actual number of months notice given = six months.
      J   = the prescribed notice = twelve months.






                                                                 S.O. #2
                                                                 May 7, 1984

                                     D-15




      The sample calculation is:

      G = CC x (T - CCP) x (J-H)
                             12

      G = 10,000 kW x ($140/kW-yr - $110/kW-yr) x

                   (12 mos. - 6 mos.)
                      12 mos./yr

      G = $150,000












































                                                                 S.O. #2
                                                                 May 7, 1984

                                     D-16




                                  APPENDIX E

                                INTERCONNECTION

                                   CONTENTS


Section                                                                Page

  E-1       INTERCONNECTION TARIFFS                                     E-2

  E-2       POINT OF DELIVERY LOCATION SKETCH                           E-3

  E-3       INTERCONNECTION FACILITIES FOR WHICH SELLER IS RESPONSIBLE  E-4














































                                                                 S.O. #2
                                                                 May 7, 1984

                                      E-1

E-1   INTERCONNECTION TARIFFS

      (The applicable tariffs in effect at the time of execution of this       
Agreement shall be attached.)



























                                                                 S.O. #2
                                                                 May 7, 1984

                                      E-2

E-2   POINT OF DELIVERY LOCATION SKETCH


      The Seller requests, and PGandE consents, that the location sketch not
be made at the time of executing the Agreement, because the Seller,
recognizing that the information is not yet available to make a definitive
determination of the sketch to be inserted here, shall request PGandE to
perform an interconnection study to be done in its accustomed manner of making
such studies to determine the sketch to be inserted.






















                                                                 S.O. #2
                                                                 May 7, 1984

                                      E-3

E-3   INTERCONNECTION FACILITIES FOR WHICH SELLER IS RESPONSIBLE


      The Seller requests, and PGandE consents, that this listing of
facilities not be filled in at the time of executing the Agreement, because
the Seller, recognizing that the information is not yet available to make a
definitive determination of the listing of facilities to be inserted here,
shall request PGandE to perform an interconnection study to be done in its
accustomed manner of making such studies to determine the listing of
facilities to be inserted.





















                                                                 S.O. #2
                                                                 May 7, 1984

                                      E-4

                       FIRST AMENDMENT TO POWER PURCHASE
                    AGREEMENT FOR FIRM CAPACITY AND ENERGY
                  BETWEEN UNIVERSITY COGENERATION, INC., AND
                       PACIFIC GAS AND ELECTRIC COMPANY

This First Amendment is entered into as of the 17th day of October, 1985,
between University Cogeneration, Inc., a California corporation, ("Seller"), 
and Pacific Gas and Electric Company, a California corporation, ("PGandE"), with
reference to the following:

A.    Seller and PGandE are parties to that certain Power Purchase Agreement
      for Firm Capacity and Energy dated April 23, 1985 (the Power Purchase    
      Agreement);

B.    It has come to the attention of Seller and PGandE that Seller's corporate 
      name was incorrectly set forth in the Power Purchase Agreement as
      University Cogeneration Inc., 1985-1 when it should have been set forth as
      University Cogeneration, Inc.; and

C.    Seller and PGandE wish to amend the Power Purchase Agreement to correctly 
      set forth Seller's corporate name.

NOW, THEREFORE, in consideration of the mutual agreements contained in the
Power Purchase Agreement and herein, the parties agree as follows:

1.    Effective from the execution date of the Power Purchase Agreement, 
      such agreement is amended to the extent that all references to Seller
      as University Cogeneration Inc., 1985-1 shall be deemed to be references
      to Seller as University Cogeneration, Inc.


                                       1
IN WITNESS WHEREOF the parties have caused this Amendment to be signed.

                                       UNIVERSITY COGENERATION, INC.

Date Signed: October 16, 1985        By: /s/ John R. Zanot
                                     Name:  John R. Zanot
                                     Title: Vice President

                                       PACIFIC GAS AND ELECTRIC COMPANY

Date Signed: October 17, 1985        By: /s/ Nolan H. Daines
                                     Name:  Nolan H. Daines
                                     Title: Vice President
















                                          2



                       SECOND AMENDMENT TO
                     POWER PURCHASE AGREEMENT
                   FOR FIRM CAPACITY AND ENERGY
            BETWEEN UNIVERSITY COGENERATION, INC., AND
                 PACIFIC GAS AND ELECTRIC COMPANY
                       DATED APRIL 23, 1985

         On April 23, 1985 PACIFIC GAS AND ELECTRIC COMPANY ("PGandE") and
UNIVERSITY COGENERATION, INC. ("Seller") entered into a Standard offer No. 2
Power Purchase Agreement ("Agreement") for the 38,000 kW cogeneration project
located at Section 28, Township 12 north, Range 24 west, 1/2 miles south of
Taft, Kern County, California.

         PGandE and Seller in consideration of the mutual agreements herein, and
other good and valuable considerations, hereby amend said Agreement as
follows:
1.       ARTICLE 2 - PURCHASE OF POWER

         Paragraph (a) - The blank in the first sentence is replaced with 115 kV
         to reflect the energy delivery voltage level:

         "(a) Seller shall sell and deliver and PGandE shall
         purchase and accept delivery of firm capacity and energy at the
         voltage level of 115 kV as indicated below


                                       1

         





         Paragraph (d) - The blank in this paragraph is replaced with 46.7 MVA 
      to reflect the physical limitations of the project interconnection      
      facilities:
         "(d) To avoid exceeding the physical limitations of the            
        interconnection facilities., Seller shall limit the                    
        Facility's actual rate of delivery into the PGandE system to           
        46.7 MVA."
         Paragraph (g) - The blank in this paragraph is replaced with "not
      applicable" to reflect the fact that the meters have been placed on
      PGandE's side of the transformer:
        "(g) The transformer loss adjustment factor is not applicable."

2.       Appendix C - FIRM CAPACITY PRICE SCHEDULE

         Section C-5, Table A, page C-11 - The sentence following this table
         shall be replaced with the following:

         "The Facility is non-remote and the capacity loss adjustment factor
         is 0.989."










                                   2



3.       Appendix E - INTERCONNECTION

         The entire appendix shall be replaced- by the following to include the
         Electric Rule No. 21 in effect at the time of execution of the 
         Agreement,the Point of Delivery Location sketch and the List of 
         Interconnection Facilities for which Seller is Responsible:








                                 













                                       3



                            APPENDIX E
                         INTERCONNECTION
                             CONTENTS

  Section                                                       Page

    E-1  INTERCONNECTION TARIFFS                                 E-2

    E-2  POINT OF DELIVERY LOCATION SKETCH                       E-3

    E-3  INTERCONNECTION FACILITIES FOR WHICH                    E-4
         SELLER IS RESPONSIBLE
    













                                      4




 E-1 INTERCONNECTION TARIFFS

         (The applicable tariffs in effect at the time of execution of this
         Agreement shall be attached.
























                                      5




                         THIRD AMENDMENT

                              TO THE
                     FIRM CAPACITY AND ENERGY
                     POWER PURCHASE AGREEMENT
                             BETWEEN
                  UNIVERSITY COGENERATION, INC.
                               AND
                 PACIFIC GAS AND ELECTRIC COMPANY

         THIS THIRD AMENDMENT is by and between UNIVERSITY COGENERATION INC.
("Seller"), and PACIFIC GAS AND ELECTRIC COMPANY ("PG&E"), a California
corporation.  It amends the Firm capacity and Energy Power Purchase Agreement
signed on April 23, 1985 by PG&E and on April 16, 1985 by University
Cogeneration, Inc. for the 38,000 kW cogeneration facility located at Section
28, Township 12N., Range 24W, 3-1/2 miles South of Taft, Kern County,
California (the "Agreement").  PG&E and Seller are sometimes referred to
herein collectively as the "Parties".

         WHEREAS, by letter dated June 2, 1988, Seller notified PG&E that it
elected to decrease the contract firm capacity to 32,000 kW, in accordance
with Section C-4(b), Appendix C, of the Agreement; and

         WHEREAS, the Parties desire to amend the Agreement to reflect the
foregoing.


                                

                                       1



         NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained herein, PG&E and Seller hereby agree as follows:

         1.   The term "34,000 kW" shall be deleted from page 4, line 6,
              Article 2(a), PURCHASE OF POWER, of the Agreement and replaced
              by the term "32,000 kW".

         2.   All other provisions of the Agreement remain unchanged.

         3.   All underlined terms used herein shall have the same meanings 
              as defined in the Agreement.

         4.   This Third Amendment shall be construed and interpreted in
              accordance with the laws of the State of California, excluding
              any choice of law rules that may direct the application of the
              laws of another jurisdiction.

         IN WITNESS WHEREOF, the Parties hereto have caused this Third
Amendment to be signed by their authorized representatives, and it is effective
as of the last date set written below.

       UNIVERSITY COGENERATION, INC. PACIFIC GAS AND ELECTRIC COMPANY
       BY: /s/ L.M. Gunderson                 By: /s/ Junona A. Jonas
       Name: L.M. Gunderson          Name: Junona A. Jonas
       Title: Vice President         Title: Manager, QF Contracts
       Date Signed: April 26, 1989   Date Signed: May 19, 1989


                                 


                                       2







                   CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

We consent to the incorporation by reference in the registration statements of
Berry Petroleum Company on Form S-8 (File No. 33-23326 and 33-61337) of our
report dated February 21, 1996 on our audits of the financial statements of
Berry Petroleum Company as of December 31, 1995 and 1994 and for the three
years in the period ended December 31, 1995, which report is included in this
Annual Report on Form 10-K.



/s/ Coopers & Lybrand L.L.P.
COOPERS & LYBRAND L.L.P.


Los Angeles, California
March 14, 1996





















                                 Exhibit 23.1











            CONSENT OF INDEPENDENT PETROLEUM ENGINEERING CONSULTANT


     The undersigned, an independent petroleum engineering consultant, hereby
consents to incorporation by reference in the Registration Statements
No. 33-23326 and No. 33-61337 on Form S-8 of Berry Petroleum Company and
the related Prospectus of our reserve report prepared pursuant to the
Securities Exchange Act of 1934 dated January 26, 1994, pertaining to
interests of Berry Petroleum Company and subsidiaries in certain oil and gas
properties located in California, and the use of the name Babson and Sheppard
Petroleum Engineers as the independent petroleum engineering firm that prepared
such report for the year ended December 31, 1993 which report is referenced
in the December 31, 1995 Annual Report on Form 10-K of Berry Petroleum Company.



Dated: March 4, 1996

                                       BABSON AND SHEPPARD PETROLEUM ENGINEERS



                                       By:     /s/ John F. Bergquist 
                                               John F. Bergquist, President
                                           















                                 Exhibit 23.2





                           DEGOLYER AND MACNAUGHTON
                              ONE ENERGY SQUARE
                             DALLAS, TEXAS 75206



                          March 1, 1996






Berry Petroleum Company
P.O. Bin X
Taft, CA 93268


Gentlemen:

      In connection with the Annual Report on Form 10-K for the fiscal year
ended December 31, 1995, (the Annual Report) of Berry Petroleum Company (the
Company), we hereby consent to (i) the use of and reference to our report
dated February 12, 1996, entitled "Appraisal Report as of December 31, 1995 on
Certain Property Interests owned by Berry Petroleum Company, "our report dated
February 23, 1995, entitled "Appraisal Report as of December 31, 1994 on
Certain Properties owned by Berry Petroleum Company," and our report dated
March 4, 1994, entitled "Appraisal Report as of December 31, 1993 on Certain
Properties owned by Berry Petroleum Company" (collectively referred to as the
"Reports "), all three of which pertain to interests of the Company in certain
oil and gas properties located in California, Louisiana, Nevada, and Texas,
under the caption "Oil and Gas Reserves - Reserve Reports" in items 1 and 2 of
the Annual Report, in item 6 of the Annual Report, and under the caption
"Supplemental Information About Oil and Gas Producing Activities (Unaudited)"
in item 8 of the Annual Report; and (ii) the use of and reference
 to the name
DeGolyer and MacNaughton as the independent petroleum engineering firm that
prepared the Reports under such items; provided, however, that since the
reserves estimates set forth in the report dated March 4, 1994, have been
combined with reserves estimates of other petroleum consultants and the
engineering staff of the Company, we are necessarily unable to verify the
accuracy of the reserves values, as of December 31, 1993, contained in the
Annual Report and, since the cash flow calculations in the Annual Report
include estimated income taxes not included in the Reports, we are unable to
verify the accuracy of the cash flow values in the Annual Report.

                                       Very truly yours,



                                       /s/ DeGolyer and MacNaughton
                                       DEGOLYER and MacNAUGHTON






                                 Exhibit 23.3




<TABLE> <S> <C>

<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
DECEMBER 31, 1995 FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000778438
<NAME> BERRY PETROLEUM COMPANY
<MULTIPLIER> 1,000
       
<S>                             <C>
<PERIOD-TYPE>                   YEAR
<FISCAL-YEAR-END>                          DEC-31-1995
<PERIOD-END>                               DEC-31-1995
<CASH>                                          18,759
<SECURITIES>                                    15,695
<RECEIVABLES>                                    8,414
<ALLOWANCES>                                         0
<INVENTORY>                                          0
<CURRENT-ASSETS>                                45,200
<PP&E>                                         138,745
<DEPRECIATION>                                  66,703
<TOTAL-ASSETS>                                 117,722
<CURRENT-LIABILITIES>                            8,694
<BONDS>                                              0
<PREFERRED-MANDATORY>                                0
<PREFERRED>                                          0
<COMMON>                                           219
<OTHER-SE>                                      91,841
<TOTAL-LIABILITY-AND-EQUITY>                   117,722
<SALES>                                         45,773
<TOTAL-REVENUES>                                51,190
<CGS>                                                0
<TOTAL-COSTS>                                   26,630
<OTHER-EXPENSES>                                 5,071
<LOSS-PROVISION>                                     0
<INTEREST-EXPENSE>                                   0
<INCOME-PRETAX>                                 19,489
<INCOME-TAX>                                     7,286
<INCOME-CONTINUING>                             12,203
<DISCONTINUED>                                       0
<EXTRAORDINARY>                                      0
<CHANGES>                                            0
<NET-INCOME>                                    12,203
<EPS-PRIMARY>                                      .56
<EPS-DILUTED>                                      .56
        

</TABLE>






                  UNDERTAKING FOR FORM S-8 REGISTRATION STATEMENT

     For purposes of complying with the amendments to the rules governing
Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the
Company hereby undertakes as follows, which undertaking shall be
incorporated by reference into the Company's Registration Statements on Form
S-8 (No. 33-23326 and No. 33-61337 filed on July 28, 1988 and July 27, 1995,
respectively):

     Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to director, officers and
controlling persons of the Company pursuant to the foregoing provisions, or
otherwise, the Company has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public
policy as expressed in the Securities Act of 1933 and is, therefore,
unenforceable.  In the event that a claim for indemnification against such
liabilities (other than the payment by the Company of expenses incurred or
paid by a director, officer or controlling person of the Company in the
successful defense of any action, suit or proceeding is asserted by such
director, officer or controlling person in connection with the securities
being registered,
 the Company will, unless in the opinion of its counsel
the matter has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such indemnification is
against public policy as expressed in the Act and will be governed by the
final adjudication of such issue.




















                                Exhibit 99.1