VINTAGE PETROLEUM INC, 424B4, 1997-01-31

VINTAGE PETROLEUM INC
424B4, 1997-01-31
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>

Filed pursuant to Rule 424(b)(4)
SEC File No. 333-19569

1,500,000 SHARES

[LOGO OF VINTAGE VINTAGE PETROLEUM, INC.
PETROLEUM APPEARS
HERE] COMMON STOCK

The 1,500,000 shares of Common Stock, par value $.005 per share (the "Common
Stock"), offered hereby (this "Offering" or the "Common Stock Offering") are
being offered by Vintage Petroleum, Inc. (the "Company"). The Common Stock is
listed on the New York Stock Exchange under the symbol "VPI." On January 30,
1997, the last reported sales price of the Common Stock on the New York Stock
Exchange was $33 1/8 per share. See "Price Range of Common Stock and
Dividends."

Concurrent with this Offering, the Company is offering $100 million
aggregate principal amount of its 8 5/8% Senior Subordinated Notes Due 2009
(the "Notes") to the public (the "Note Offering"). See "Note Offering."
Consummation of this Offering is not contingent upon consummation of the Note
Offering, and there can be no assurance that the Note Offering will be
consummated.

FOR A DISCUSSION OF CERTAIN RISKS OF AN INVESTMENT IN THE SHARES OF COMMON
STOCK OFFERED HEREBY, SEE "RISK FACTORS" ON PAGES 11-14.

---------------

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.

---------------

<TABLE>
<CAPTION>
Underwriting
Price to Discounts and Proceeds to
Public Commissions* Company+
<S> <C> <C> <C>
Per Share................................. $33.125 $1.620 $31.505
Total ++.................................. $49,687,500 $2,430,000 $47,257,500
</TABLE>
- -------
* The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933. See
"Underwriting."

+ Before deducting expenses payable by the Company estimated to be $175,000.

++The Company has granted the Underwriters a 30-day option to purchase up to
225,000 additional shares of Common Stock on the same terms per share solely
to cover over-allotments, if any. If such option is exercised in full, the
total price to public will be $57,140,625, the total underwriting discounts
and commissions will be $2,794,500 and the total proceeds to the Company
will be $54,346,125. See "Underwriting."

---------------

The Common Stock is being offered by the Underwriters as set forth under
"Underwriting" herein. It is expected that delivery of the certificates
therefor will be made at the offices of Dillon, Read & Co. Inc., New York, New
York, on or about February 5, 1997, against payment therefor. The Underwriters
include:

DILLON, READ & CO. INC.
SALOMON BROTHERS INC
SMITH BARNEY INC.
JOHNSON RICE & COMPANY L.L.C.

The date of this Prospectus is January 31, 1997
<PAGE>

CERTAIN DEFINITIONS

Unless the context requires otherwise, all references in this Prospectus to
"Vintage" or the "Company" include Vintage Petroleum, Inc., its consolidated
subsidiaries and its proportionately consolidated general partner interests in
various limited partnerships and joint ventures.

As used in this Prospectus, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel,
"MBbls" means thousand barrels, "MMBbls" means million barrels, "BOE" means
equivalent barrels of oil, "MBOE" means thousand equivalent barrels of oil and
"MMBOE" means million equivalent barrels of oil. Unless otherwise indicated in
this Prospectus, gas volumes are stated at the legal pressure base of the
state or area in which the reserves are located and at 60(degrees) Fahrenheit.
Equivalent barrels of oil are determined using the ratio of six Mcf of gas to
one Bbl of oil. The term "gross" refers to the total acres or wells in which
the Company has a working interest, and "net" refers to gross acres or wells
multiplied by the percentage working interest owned by the Company. "Net
production" means production that is owned by the Company less royalties and
production due others. The terms "net" and "net production" include 100
percent of the Company's subsidiary Cadipsa S.A. ("Cadipsa") and do not
reflect reductions for minority interest ownership. The term "oil" includes
crude oil, condensate and natural gas liquids. "Finding cost" means an amount
per BOE equal to the sum of all costs incurred relating to oil and gas
property acquisition, exploration and development activities divided by the
sum of all additions and revisions to estimated proved reserves, including
reserve purchases.

INCORPORATION OF DOCUMENTS BY REFERENCE

The following documents heretofore filed by the Company with the Securities
and Exchange Commission (the "Commission") (File No. 1-10578) are hereby
incorporated by reference in this Prospectus: (a) the Company's Annual Report
on Form 10-K for the fiscal year ended December 31, 1995; (b) the Company's
Quarterly Reports on Form 10-Q for the quarters ended March 31, 1996, June 30,
1996, and September 30, 1996; (c) the Company's Current Report on Form 8-K
dated July 5, 1995, and Amendment No. 1 thereto dated September 18, 1995; (d)
the Company's Current Report on Form 8-K dated December 28, 1995; (e) the
Company's Current Report on Form 8-K dated January 10, 1997; and (f) the
description of the Common Stock contained in the Company's registration
statement on Form 8-A, dated July 18, 1990, including any amendment or report
heretofore or hereafter filed for the purpose of updating the description of
the Common Stock contained therein.

Each document filed by the Company pursuant to Sections 13(a), 13(c), 14 and
15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"),
subsequent to the date of this Prospectus and prior to the termination of this
Offering shall be deemed to be incorporated by reference in this Prospectus
and to be a part hereof from the date of filing of such document. Any
statement contained in a document incorporated or deemed to be incorporated by
reference herein shall be deemed to be modified or superseded for purposes of
this Prospectus to the extent that a statement contained in this Prospectus or
in any other subsequently filed document which also is or deemed to be
incorporated by reference herein modifies or supersedes such statement. Any
such statement so modified or superseded shall not be deemed, except as so
modified or superseded, to constitute a part of this Prospectus.

The Company will provide without charge to each person to whom this
Prospectus has been delivered, on written or oral request of such person, a
copy (without exhibits, unless such exhibits are specifically incorporated by
reference into such documents) of any or all documents incorporated by
reference in this Prospectus. Requests for such copies should be directed to
William C. Barnes, Secretary, at the Company's principal executive offices,
4200 One Williams Center, Tulsa, Oklahoma 74172, telephone number (918) 592-
0101.

----------------

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK
AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE OR OTHERWISE. SUCH
STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.

2
<PAGE>

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the more detailed
information and financial statements (including the notes thereto) included
elsewhere in this Prospectus or incorporated by reference herein. Unless
otherwise indicated, all data in this Prospectus assumes no exercise of the
Underwriters' over-allotment option. Certain terms used herein are defined
under "Certain Definitions."

THE COMPANY

Vintage Petroleum, Inc. ("Vintage" or the "Company") is an independent oil
and gas company focused on the acquisition of producing oil and gas properties
which contain the potential for increased value through exploitation and
development. The Company, through its experienced management and engineering
staff, has been successful in realizing such potential on prior acquisitions
through workovers, recompletions, secondary recovery operations, operating cost
reductions, and the drilling of development or infill wells. The Company
believes that its primary strengths are its ability to add reserves at
attractive prices through property acquisitions and subsequent exploitation,
and its low cost operating structure. These strengths have allowed the Company
to substantially increase reserves, production and cash flow during the last
five years. As the Company has grown its cash flow and added to its technical
staff, exploration has become a larger focus for its future growth. Planned
exploration expenditures for 1997 of approximately $43 million represent 37
percent of the Company's capital budget, excluding acquisitions.

At September 30, 1996, the Company owned and operated producing properties in
11 states, with its domestic proved reserves located primarily in four core
areas: the West Coast, Gulf Coast, East Texas and Mid-Continent areas of the
United States. During 1996, the Company expanded its Gulf Coast area through
the acquisitions of certain oil and gas properties from Exxon Company, U.S.A.
and Conoco Inc. In addition, the Company established a new core area in 1995 by
acquiring 12 oil concessions, 11 of which are producing and operated by the
Company, in the south flank of the San Jorge Basin in southern Argentina. The
Company recently expanded its South American operations into Bolivia through
the acquisition of Shamrock Ventures Boliviana Ltd. which owns and operates
three blocks covering approximately 570,000 net acres in the Chaco Plains area
of southern Bolivia. See "Recent Acquisitions."

Vintage owned interests in 3,053 gross (1,934 net) producing wells in the
United States as of September 30, 1996, of which approximately 81 percent are
operated by the Company. Vintage owned interests in 610 gross (597 net)
producing wells in Argentina as of September 30, 1996, of which approximately
97 percent are operated by the Company. As of December 31, 1995, the Company's
properties had proved reserves of 199.7 MMBOE, comprised of 147.9 MMBbls of oil
and 310.8 Bcf of gas, with a present value of estimated future net revenues
before income taxes (utilizing a 10 percent discount rate) of $894 million and
a standardized measure of discounted future net cash flows of $737 million.
Since that date, acquisitions have added 28.4 MMBOE of proved reserves, as
estimated by the Company as of the date of each acquisition.

BUSINESS STRATEGY

Vintage's overall goal is to maximize its value through profitable growth in
its oil and gas reserves and production. The Company has been successful at
achieving this goal through its ongoing strategy of (a) acquiring producing oil
and gas properties, at favorable prices, with significant exploitation
potential,

3
<PAGE>

(b) focusing on low risk exploitation and development activities to maximize
production and ultimate reserve recovery, (c) exploring non-producing
properties, (d) maintaining a low cost operating structure, and (e) maintaining
financial flexibility.

Key elements of the Company's strategy include:

. Acquisitions of Producing Properties. The Company has an experienced
management and engineering team which focuses on acquisitions of
operated producing properties that meet its selection criteria which
include (a) significant potential for increasing reserves and production
through low risk exploitation and development, (b) attractive purchase
price, and (c) opportunities for improved operating efficiency. The
Company's emphasis on property acquisitions reflects its belief that
continuing consolidation and restructuring activities on the part of
major integrated and large independent oil companies has afforded in
recent years, and should afford in the future, attractive opportunities
to purchase domestic and international producing properties. This
acquisition strategy has allowed the Company to rapidly grow its
reserves at favorable acquisition prices. From January 1, 1993, through
September 30, 1996, the Company acquired 140.1 MMBOE of proved oil and
gas reserves at an average acquisition cost of $2.78 per BOE, which is
significantly below the industry average. The Company replaced through
acquisitions approximately 3.1 times its production of 45.5 MMBOE during
the same period.

. Exploitation and Development. The Company pursues workovers,
recompletions, secondary recovery operations and other production
optimization techniques on its properties, as well as development and
infill drilling, to offset normal production declines and replace the
Company's annual production. From January 1, 1993, through December 31,
1995, the Company spent approximately $83.9 million on exploitation and
development activities. During this period, the Company's recompletion
and workover activities resulted in improved production or operating
efficiencies in approximately 75 percent of these operations, and the
result of all of its exploitation activities, including development and
infill drilling, succeeded in replacing more than 78 percent of
production during this period. The Company has an extensive inventory of
exploitation and development opportunities including identified projects
which represent approximately a 10 year inventory at current activity
levels. The Company anticipates spending approximately $33 million in
the United States and approximately $40 million in Argentina during 1997
on exploitation and development projects.

. Exploration. The Company's overall exploration strategy balances high
potential international prospects with lower risk drilling in known
formations in the United States and Argentina. This prospect mix and the
Company's practice of risk-sharing with industry partners is intended to
lower the incidence and costs of dry holes. The Company makes extensive
use of geophysical studies, including 3-D seismic, which further reduce
the cost and increase the success of its exploration program. From
January 1, 1993, through September 30, 1996, the Company spent
approximately $39.8 million on exploration activities including the
drilling of 75 gross (32.65 net) exploration wells, of which
approximately 69 percent gross (58 percent net) were productive. The
Company has increased its 1997 exploration budget by 79 percent over
1996 to approximately $43 million with spending planned in its core
areas in the United States and Argentina as well as in Block 19 of
Ecuador and the Chaco Block in Bolivia.

. Low Cost Structure. The Company is an efficient operator and capitalizes
on its low cost structure in evaluating acquisition opportunities. The
Company generally achieves substantial reductions in labor and other
field level costs from those experienced by the previous operators. In
addition, the Company targets acquisition candidates which are located
in its core areas and provide opportunities for cost efficiencies
through consolidation with other Vintage operations. The lower cost
structure has generally allowed the Company to substantially improve the
cash flow of newly acquired properties.

4
<PAGE>

. Financial Flexibility. The Company is committed to maintaining
substantial financial flexibility, which management believes is
important for the successful execution of its acquisition, exploitation
and exploration strategy. In conjunction with the purchase of
substantial oil and gas assets in 1990, 1992 and 1995, the Company
completed three public equity offerings, as well as a public debt
offering in 1995, which provided the Company with aggregate net proceeds
of approximately $272 million. Upon consummation of the Common Stock
Offering and the Note Offering and the application of the net proceeds
therefrom, and after giving effect to the related borrowing base
reduction, the unused portion of the Company's revolving credit facility
as of January 30, 1997, would have been approximately $167.8 million
($106.4 million if only the Common Stock Offering is consummated).

RECENT ACQUISITIONS

Since December 31, 1995, the Company has acquired, through several
transactions, oil and gas properties for an aggregate purchase price of
approximately $89.7 million. Most of these properties were acquired subsequent
to September 30, 1996. Based on estimates prepared by the Company, proved
reserves as of the dates of the various acquisitions aggregated 16.0 MMBbls of
oil and 74.0 Bcf of gas, or a total of 28.4 MMBOE. These reserves were acquired
at an average cost of $3.16 per BOE.

The two most significant acquisitions made subsequent to September 30, 1996,
are described below. If these properties had been acquired on January 1, 1996,
these properties would have increased the Company's revenues by approximately
$13.5 million, EBITDA by approximately $8.5 million and production by
approximately 302 MBbls of oil and 4.0 Bcf of gas for the nine months ended
September 30, 1996.

On November 20, 1996, the Company purchased certain producing oil and gas
properties and facilities from Exxon Company, U.S.A. located in south Alabama
for approximately $28.2 million in cash (the "Exxon Properties"). Funds were
provided by advances under the Company's revolving credit facility. The Exxon
Properties include an interest in two fields totaling approximately 5,000 net
acres with a total of 17 gross (9.9 net) productive wells with current net
daily production of approximately 1,450 Bbls of oil and liquids and 2,800 Mcf
of gas. All of the wells are now operated by the Company.

Also during November 1996, the Company agreed to purchase 100 percent of the
outstanding common stock of Shamrock Ventures Boliviana Ltd. ("Shamrock") from
affiliates of Ultramar Diamond Shamrock Corporation for approximately $29.0
million in cash. In addition, at closing on January 7, 1997, the Company repaid
all of Shamrock's existing bank debt (approximately $9.2 million). Funds for
the purchase of the stock and the repayment of debt were provided by advances
under the Company's revolving credit facility. Shamrock's assets include (a)
oil and gas properties valued at $35.5 million (including the effect of
approximately $6.6 million of deferred income taxes recorded under the purchase
method of accounting), and (b) inventory, receivables, cash and other assets
net of liabilities (other than bank debt repaid at
closing) of approximately $9.3 million. The oil and gas properties of Shamrock
consist of three blocks, totaling approximately 570,000 net acres, in the Chaco
Plains area of southern Bolivia. The properties consist of a 100 percent
interest in the Chaco and Porvenir blocks, and a 50 percent interest in the
Nupuco block. Proved reserves at the time of acquisition, as estimated by the
Company, were 53.2 Bcf of gas and 5.1 MMBbls of oil. Current net daily
production is approximately 14,500 Mcf of gas and 230 Bbls of condensate.
Recent realized prices on the properties were $1.23 per Mcf of gas and $21.00
per Bbl of condensate. The purchase also included a 29 mile gas pipeline and an
interest in a gas processing plant with a capacity of 110 MMcf per day. The
Company believes that the Shamrock properties contain substantial upside
potential which may be realized through exploitation and future exploration.
See "Recent Acquisitions."

5
<PAGE>

THE OFFERING

Common Stock offered........ 1,500,000 shares

Common Stock to be
outstanding after this
Offering.................... 25,600,502 shares(1)

Use of proceeds............. The net proceeds to the Company from the sale of
the Common Stock offered hereby are estimated to
be approximately $47.1 million. Such net proceeds
will be used to repay a portion of existing
indebtedness under the Company's revolving credit
facility (the "Bank Facility"). See "Use of
Proceeds."

New York Stock Exchange
Symbol...................... VPI

Note Offering............... Concurrent with this Offering, the Company is
offering $100 million aggregate principal amount
of Notes to the public. This Offering is not
contingent upon consummation of the Note
Offering, and there can be no assurance that the
Note Offering will be consummated. See "Note
Offering."
- --------
(1) Does not include (a) 225,000 shares of Common Stock that may be sold by the
Company upon exercise of the Underwriters' over-allotment option and (b)
1,304,102 shares of Common Stock reserved for issuance pursuant to
outstanding stock options.

6
<PAGE>

SUMMARY FINANCIAL DATA
The following table presents summary financial information for the periods
indicated and should be read in conjunction with the Company's consolidated
financial statements and the notes thereto included elsewhere in this
Prospectus and "Management's Discussion and Analysis of Financial Condition and
Results of Operations." Significant acquisitions of producing oil and gas
properties affect the comparability of the financial data for the periods
presented below.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEARS ENDED DECEMBER 31,
---------------------- ----------------------------------
1996 1995 1995 1994 1993
---------- ---------- ---------- ---------- ----------
(UNAUDITED)
(IN THOUSANDS, EXCEPT RATIOS AND PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales...... $ 185,847 $ 112,809 $ 160,254 $ 141,357 $ 113,259
Oil and gas gathering.. 15,310 8,472 12,380 14,635 7,861
Gas marketing.......... 21,519 13,631 20,912 27,285 36,175
Other income........... 659 1,461 1,251 2,375 2,732
---------- ---------- ---------- ---------- ----------
223,335 136,373 194,797 185,652 160,027
---------- ---------- ---------- ---------- ----------
Costs and expenses:
Lease operating,
including production
taxes................. 67,606 47,520 66,771 59,292 44,930
Oil and gas gathering.. 12,838 6,636 9,511 12,294 5,869
Gas marketing.......... 19,885 12,210 18,839 24,963 34,406
General and
administrative........ 12,026 8,258 11,601 8,889 6,066
Depreciation, depletion
and amortization...... 51,313 36,875 52,257 45,774 33,335
Interest............... 22,467 13,379 20,178 12,002 6,943
---------- ---------- ---------- ---------- ----------
186,135 124,878 179,157 163,214 131,549
---------- ---------- ---------- ---------- ----------
Income before income
taxes, minority
interest and cumulative
effect of accounting
change................. 37,200 11,495 15,640 22,438 28,478
Provision (benefit) for
income taxes:
Current................ 2,061 687 (955) 1,576 3,962
Deferred............... 7,982 3,895 6,034 6,933 7,727
Minority interest in
(income) loss of
subsidiary(a).......... (361) 662 800 -- --
---------- ---------- ---------- ---------- ----------
Income before cumulative
effect of accounting
change................. 26,796 7,575 11,361 13,929 16,789
Cumulative effect of
accounting change(b)... -- -- -- -- 1,725
---------- ---------- ---------- ---------- ----------
Net income.............. $ 26,796 $ 7,575 $ 11,361 $ 13,929 $ 18,514
========== ========== ========== ========== ==========
Weighted average common
shares outstanding..... 24,454 21,322 21,276 21,174 20,830
EARNINGS PER SHARE:
Income before cumulative
effect of accounting
change................. $ 1.10 $ .36 $ .53 $ .66 $ .81
Net income.............. 1.10 .36 .53 .66 .89
CASH FLOW DATA:
Cash provided (used) by:
Operating activities... $ 82,947 $ 48,904 $ 54,199 $ 58,670 $ 52,219
Investing activities... (100,699) (120,925) (187,251) (70,668) (146,126)
Financing activities... 20,546 73,134 135,166 11,867 93,900
BALANCE SHEET DATA (end
of period):
Property, plant and
equipment, net......... $ 623,092 $ 521,751 $ 577,746 $ 366,665 $ 346,034
Total assets............ 701,358 572,143 647,539 407,752 384,461
Total debt.............. 344,309 309,140 323,776 193,864 181,480
Minority interest(a).... 2,286 11,618 3,922 -- --
Stockholders' equity.... 251,232 169,702 223,960 155,993 143,392
OTHER FINANCIAL DATA:
Dividends declared per
share.................. $ .08 $ .07 $ .09 $ .07 $ .05
EBITDA(c)............... 110,980 61,749 88,075 80,214 68,756
Ratio of EBITDA to
interest expense....... 4.9x 4.6x 4.4x 6.7x 9.9x
Ratio of earnings to
fixed charges(d)....... 2.7x 1.9x 1.8x 2.9x 5.0x
</TABLE>
(see notes on following page)

7
<PAGE>

- --------
(a) Reflects the minority interest in Cadipsa S.A. See consolidated financial
statements and the notes thereto of the Company included elsewhere in this
Prospectus.
(b) Represents the cumulative effect on prior years of adopting Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes."
(c) EBITDA as presented herein is generally defined as income before cumulative
effect of accounting change, provision for income taxes, interest,
depreciation, depletion, amortization and certain other non-cash charges.
EBITDA is included as a supplemental disclosure because it is commonly
accepted as providing useful information regarding a company's ability to
service and incur debt. EBITDA, however, should not be considered in
isolation or as a substitute for net income, cash flow provided by
operating activities or other income or cash flow data prepared in
accordance with generally accepted accounting principles or as a measure of
a company's profitability or liquidity. If the Exxon Properties and
Shamrock had been acquired on January 1, 1996, these properties would have
increased the Company's EBITDA by approximately $8.5 million for the nine
months ended September 30, 1996. See "Recent Acquisitions."
(d) For purposes of calculating the ratio of earnings to fixed charges,
earnings are defined as income of the Company and its subsidiaries before
income taxes and fixed charges. Fixed charges consist of interest expense,
including amortization of financing costs and any discount or premium
related to any indebtedness.

8
<PAGE>

SUMMARY OPERATING AND RESERVE DATA (A)
(Unaudited)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEARS ENDED DECEMBER 31,
-------------------- ----------------------------
1996 1995 1995 1994 1993
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Production:
Oil (MBbls)................ 8,649 5,310 7,608 6,657 4,785
Gas (MMcf)................. 24,535 22,489 30,610 28,884 22,504
Oil equivalent (MBOE)...... 12,738 9,058 12,710 11,471 8,536
Average sales prices:
Oil (per Bbl).............. $ 16.66(b) $ 15.33 $15.26 $13.53 $14.14
Gas (per Mcf).............. 1.70 1.42 1.46 1.78 2.03
Production costs (per
BOE)(c).................... 5.31 5.25 5.25 5.17 5.26
Three-year average finding
cost (per BOE)(d).......... N/A N/A 2.98 3.23 3.34
Proved reserves (end of
period):
Oil (MBbls)................ N/A N/A 147,871 70,789 63,277
Gas (MMcf)................. N/A N/A 310,762 281,638 273,142
Total proved reserves
(MBOE).................... N/A N/A 199,665 117,729 108,801
Proved developed reserves
(MBOE).................... N/A N/A 145,790 91,722 88,976
Annual reserve replacement
ratio(e)................... N/A N/A 747% 179% 504%
Estimated reserve life (in
years)(f).................. N/A N/A 15.7 10.3 12.7
Present value of estimated
future net revenues before
income taxes (discounted at
10%) (in thousands)........ N/A N/A $894,249 $446,987 $359,978
Standardized measure of
discounted future net cash
flows (in thousands)....... N/A N/A 736,546 385,721 339,701
</TABLE>
- --------
(a) Significant acquisitions of producing oil and gas properties affect the
comparability of the operating data for the periods presented.
(b) During the first nine months of 1996, the impact of oil hedges reduced the
Company's overall average oil price $1.17 to $16.66 per Bbl.
(c) Includes lease operating costs and production and ad valorem taxes.
(d) Represents the average finding cost per BOE during the three years ended
December 31 of the year shown in the column. See "Certain Definitions."
(e) The annual reserve replacement ratio is a percentage determined on a BOE
basis by dividing the estimated reserves added during a year from
exploitation, development and exploration activities, acquisitions of
proved reserves and revisions of previous estimates, excluding property
sales, by the oil and gas volumes produced during that year.
(f) Estimated reserve life is calculated on a BOE basis by dividing the total
estimated proved reserves at year-end by the total production during the
year. This calculation can be affected by the timing of major acquisitions.
For example, major acquisitions were made during the second half of 1995
which resulted in an estimated reserve life of 15.7 years for 1995. This
compares to an estimated reserve life of 12.0 years for 1995 based on
annualized first quarter 1996 production.

9
<PAGE>

SUMMARY OIL AND GAS RESERVE DATA

The following table sets forth summary information with respect to the
estimates of the Company's proved oil and gas reserves at December 31, 1995, as
evaluated by Netherland, Sewell & Associates, Inc. For additional information
relating to the Company's oil and gas reserves, see "Business--Reserves,"
"Recent Acquisitions" and Note 9 "Supplementary Financial Information for Oil
and Gas Producing Activities" to the Company's consolidated financial
statements included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
PROVED RESERVES AT
DECEMBER 31, 1995
-----------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
<S> <C> <C> <C>
United States:
Oil (MBbls)..................................... 63,791 16,436 80,227
Gas (MMcf)...................................... 270,427 40,335 310,762
MBOE............................................ 108,862 23,159 132,021
Argentina:
Oil (MBbls)..................................... 36,928 30,716 67,644
Total:
Oil (MBbls)..................................... 100,719 47,152 147,871
Gas (MMcf)...................................... 270,427 40,335 310,762
MBOE............................................ 145,790 53,875 199,665
</TABLE>

10
<PAGE>

RISK FACTORS

Prospective purchasers of the Common Stock offered hereby should carefully
consider the following risk factors, as well as the other information set
forth in this Prospectus.

INDUSTRY CONDITIONS; IMPACT ON COMPANY'S OPERATING RESULTS

The Company's revenues, operating results and future rate of growth are
substantially dependent upon prevailing prices for oil and gas. Historically,
oil and gas prices and markets have been volatile, and they are likely to
continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuations in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include political
conditions in oil producing regions, including the Middle East, the domestic
and foreign supply of oil and gas, the level of consumer demand, weather
conditions, domestic and foreign government regulations, the price and
availability of alternative fuels and overall economic conditions. In
addition, various factors, including the capacity and availability of oil and
gas gathering systems and pipelines, the effect of federal and state
regulation of production and transportation, general economic conditions,
changes in supply due to drilling by other producers and changes in demand,
may adversely affect the Company's ability to market its oil and gas
production.

SUBSTANTIAL LEVERAGE

At September 30, 1996, on an as adjusted combined basis, the Company would
have had long-term debt of $358.4 million as compared to stockholders' equity
of $298.3 million ($355.7 million and $298.3 million, respectively, if the
Note Offering is not consummated) resulting in a long-term debt to total
capitalization ratio of 54 percent (54 percent if the Note Offering is not
consummated). See "Capitalization." Following the completion of the Note
Offering, the Company will have the ability to incur additional indebtedness
under the indenture governing the Notes and the indenture governing the
Company's 9% Senior Subordinated Notes Due 2005 (the "9% Notes") and will have
significant borrowing capacity under its revolving credit facility (the "Bank
Facility"). The Company's ability to meet its debt service obligations and
reduce total indebtedness will be dependent not only upon its future drilling
and production performance, but also on oil and gas prices, general economic
conditions and financial, business and other factors affecting its operations,
many of which are beyond its control. The Company's historical focus has been
and is expected to continue to be the acquisition, exploitation, development
and exploration of producing oil and gas properties. Each of these activities
requires substantial capital. The Company may finance such capital
expenditures in the future through the incurrence of additional indebtedness.
The degree to which the Company is leveraged could have important consequences
to the holders of Common Stock including (a) the ability of the Company to
obtain any necessary financing in the future for working capital, capital
expenditures, acquisitions, debt service requirements or other purposes may be
limited; (b) a portion of the Company's cash flow from operations must be
dedicated to the payment of interest on its indebtedness and will not be
available for other purposes; (c) the Company's level of indebtedness could
limit its flexibility in planning for, or reacting to changes in, its
business; (d) the Company is more highly leveraged than some of its
competitors, which may place it at a competitive disadvantage; (e) the
Company's level of indebtedness may make it more vulnerable in the event of a
downturn in its business; and (f) the terms of certain of the Company's
indebtedness permit its creditors to accelerate payments upon certain events
of default or a change of control of the Company. Currently, an instrument of
indebtedness of one of the Company's foreign subsidiaries restricts its
ability to pay dividends and other distributions to the Company, and the
respective indentures governing the Notes and the 9% Notes permit foreign
subsidiaries of the Company to agree to similar restrictions in the future.

RELIANCE ON DEVELOPMENT OF ADDITIONAL RESERVES; ACQUISITION RISKS

The Company's future performance is dependent upon its ability to find or
acquire additional oil and gas reserves that are economically recoverable.
Unless the Company successfully replaces the reserves that

11
<PAGE>

it produces, the Company's reserves will decline, resulting eventually in a
decrease in oil and gas production and lower revenues and cash flow from
operations.

The Company in the past has focused, and expects to continue to focus, on
acquiring producing oil and gas properties to replace reserves. Although the
Company performs a review of the acquired properties that it believes is
consistent with industry practice, such reviews are inherently incomplete. In
general, it is not feasible to review in-depth each individual property being
acquired. Ordinarily, the Company will focus its review efforts on the higher-
valued properties and will sample the remainder. However, even an in-depth
review of all properties and records may not necessarily reveal existing or
potential problems nor will it permit the Company to become sufficiently
familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not always be performed on each well included in
an acquisition, and environmental problems, such as ground water
contamination, are not necessarily observable even when an inspection is
performed. In addition, competition for producing oil and gas properties is
intense and many of the Company's competitors have financial and other
resources substantially in excess of those available to the Company.
Therefore, no assurance can be given that the Company will be able to acquire
producing oil and gas properties that contain economically recoverable
reserves or that it will make such acquisitions at acceptable prices.

The Company historically has succeeded in replacing reserves through
exploitation, development and exploration. The Company has conducted such
activities on its existing oil and gas properties as well as on newly acquired
properties. However, no assurance can be given that the Company will continue
to replace reserves from such activities at acceptable costs. In addition,
exploitation, development and exploration involve numerous risks, including
depositional or trapping uncertainties or other conditions that may result in
dry holes, the failure to produce oil and gas in commercial quantities and the
inability to fully produce discovered reserves.

UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET REVENUES; IMPAIRMENT OF
OIL AND GAS ASSETS

There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of
developmental expenditures, including many factors beyond the control of the
producer. The reserve data set forth in this Prospectus or incorporated by
reference herein represent only estimates. In addition, the estimates of
future net revenues from proved reserves of the Company and the present value
thereof are based upon certain assumptions about future production levels,
prices and costs that may not prove to be correct over time. The level of
future oil and gas production is subject to a number of uncertainties
including the degree to which the Company is successful in acquiring or
developing additional reserves. See "--Reliance on Development of Additional
Reserves; Acquisition Risks."

The Company accounts for its oil and gas producing activities under the full
cost method. This method imposes certain limitations on the carrying (book)
value of proved oil and gas properties and requires a writedown of such assets
for accounting purposes if such limits are exceeded. The risk that the Company
will be required to write down the carrying value of its oil and gas
properties increases as oil and gas prices decline or remain depressed. If a
writedown is required, it would result in a non-cash charge to earnings. If
declines in oil and gas prices are severe, the Company's borrowing base under
the Bank Facility may be reduced. In the event debt outstanding under the Bank
Facility exceeds the amount of the revised borrowing base, the Company would
be required to make a principal repayment to bring the total amount of debt
outstanding in compliance with the revised borrowing base. In the past, the
Company has not been required to writedown its oil and gas properties or make
a mandatory prepayment under the Bank Facility. However, no assurance can be
given that the Company will not be required to make such a writedown or make
such a mandatory prepayment in the future.

12
<PAGE>

RISKS OF INTERNATIONAL OPERATIONS

International investments represent approximately 34 percent of the
Company's total proved reserves at December 31, 1995, and are expected to
represent a significant portion of the Company's total assets in the future.
The Company continues to evaluate international investment opportunities but
currently has no binding agreements or commitments to make any material
international acquisitions.

The Company's foreign properties, operations or investments may be adversely
affected by local political and economic developments, exchange controls,
currency fluctuations, royalty and tax increases, retroactive tax claims,
expropriation, import and export regulations and other foreign laws or
policies as well as by laws and policies of the United States affecting
foreign trade, taxation and investment. In addition, in the event of a dispute
arising from foreign operations, the Company may be subject to the exclusive
jurisdiction of foreign courts or may not be successful in subjecting foreign
persons to the jurisdiction of the courts in the United States. The Company
may also be hindered or prevented from enforcing its rights with respect to a
governmental instrumentality because of the doctrine of sovereign immunity.

RISKS OF HEDGING TRANSACTIONS

The Company has previously engaged in oil and gas hedging activities and
intends to continue to consider various hedging arrangements to realize
commodity prices which it considers favorable. Currently, oil hedges for the
calendar year 1997 cover 2.738 MMBbls at an average NYMEX reference price of
$19.26. The impact of changes in the market prices for oil and gas on the
Company's average realized prices may be reduced from time to time based on
the level of the Company's hedging activities. These hedging arrangements may
limit potential gains by the Company if the market prices for oil and gas were
to rise substantially over the price established by the hedge. In addition,
the Company's hedging arrangements expose the Company to the risk of financial
loss in certain circumstances, including instances in which (a) production is
less than expected, (b) there is a widening of price differentials between
delivery points for the Company's production and the NYMEX reference price, or
(c) the counterparties to the Company's hedging arrangements fail to honor
their financial commitments. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Results of Operations."

RISKS RELATING TO A CHANGE OF CONTROL

In the event of a Change of Control (as defined in the respective indentures
governing the Notes and the 9% Notes), holders of the Notes, the 9% Notes and
all then outstanding indebtedness pari passu with the Notes that contains
similar change of control provisions will have the right to require the
Company, subject to certain conditions, to repurchase all or any part of such
holders' notes at a price equal to 101 percent of the principal amount
thereof, plus accrued and unpaid interest, if any, to the date of repurchase.
Existing senior indebtedness and existing senior subordinated indebtedness
includes, and future indebtedness may include, change of control provisions
pursuant to which the Company would be required to repurchase, or the lender
could demand repayment of, upon a change of control (as defined thereunder),
the indebtedness due thereunder. Upon such an occurrence, the Company would be
required to redeem or repay such senior indebtedness before repurchasing the
Notes, the 9% Notes and all then outstanding indebtedness pari passu with the
Notes that contains similar change of control provisions. Furthermore, no
assurance can be given that the Company would have sufficient funds available
or could obtain the financing required to repurchase the Notes, the 9% Notes
and such other outstanding indebtedness that is pari passu with the Notes
tendered by holders following a Change of Control. If a Change of Control
occurred and the Company had inadequate funds or financing available to pay
for Notes, 9% Notes and such other outstanding indebtedness that is pari passu
with the Notes tendered for repurchase, an event of default would be triggered
under the indenture governing the Notes and under the indentures governing the
9% Notes and such other outstanding indebtedness that is pari passu with the
Notes, each of which could have adverse consequences for the Company.

13
<PAGE>

OPERATING HAZARDS; UNINSURED RISKS

The Company's operations are subject to all of the risks and hazards
typically associated with the exploitation, development and exploration for,
the production of, and the transportation of oil and gas. Operating risks
include but are not limited to fires, explosions, formations with abnormal
pressures, blowouts, cratering and oil spills and other natural disasters, any
of which could result in loss to human life, significant damage to property,
environmental pollution, impairment of the Company's operations and
substantial losses to the Company. In accordance with customary industry
practice, the Company maintains insurance against some, but not all, of such
risks and some, but not all, of such losses. The occurrence of such an event
not fully covered by insurance could have a material adverse effect on the
financial position and operations of the Company.

GOVERNMENTAL AND ENVIRONMENTAL REGULATION

The Company's business is subject to certain foreign, federal, state and
local laws and regulations relating to the exploration for and development,
production and marketing of oil and gas, including environmental and safety
matters. Such laws and regulations have generally become more stringent in
recent years, often imposing greater liability on a larger number of
potentially responsible parties. Such laws and regulations have increased the
costs of planning, designing, drilling, installing, operating and abandoning
the Company's oil and gas wells and other facilities.

The Company has expended significant resources to comply with certain laws
and environmental regulations and anticipates that it will continue to do so
in the future. Because the requirements imposed by such laws and regulations
are frequently changed, the Company is unable to predict the ultimate cost of
compliance with such requirements. There can be no assurance given that laws
and regulations enacted in the future, including changes to existing laws and
regulations, will not adversely affect the Company's business.

COMPETITION

The oil and gas industry is highly competitive. The Company competes in the
areas of property acquisitions and the development, production and marketing
of oil and natural gas with major oil companies, other independent oil and
natural gas concerns and individual producers and operators. The Company also
competes with major and independent oil and natural gas concerns in recruiting
and retaining qualified employees. Many of these competitors have
substantially greater financial and other resources than the Company.

CONTROL BY CERTAIN STOCKHOLDERS

Upon the completion of this Offering, the current officers and directors of
the Company as a group will own at least 32 percent of the outstanding Common
Stock. Consequently, these stockholders may be in a position to effectively
control the affairs of the Company, including the election of all of the
Company's directors and the approval or prevention of certain corporate
transactions which require majority stockholder approval.

CERTAIN ANTI-TAKEOVER PROVISIONS

The Company's Restated Certificate of Incorporation and Restated By-laws and
the Delaware General Corporation Law contain provisions that may have the
effect of discouraging unsolicited takeover proposals for the Company that a
stockholder might consider to be in that stockholder's best interest. These
provisions, among other things, provide for a classified board of directors,
restrict the ability of stockholders to take action by written consent,
authorize the board of directors to designate the terms of and issue new
series of preferred stock, limit the personal liability of directors, require
the Company to indemnify directors and officers to the fullest extent
permitted by applicable law and impose restrictions on business combinations
with certain interested parties. See "Description of Capital Stock--Possible
Anti-takeover Provisions." In addition, certain provisions included in the
Bank Facility, the Notes and the 9% Notes will require the Company to prepay
indebtedness outstanding thereunder upon a change of control (as defined
therein) of the Company.

14
<PAGE>

FORWARD-LOOKING STATEMENTS

This Prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included or incorporated by reference in this
Prospectus which address activities, events or developments which the Company
expects or anticipates will or may occur in the future, including such things
as future capital expenditures (including the amount and nature thereof),
wells to be drilled or reworked, oil and gas prices and demand, exploitation
and exploration prospects, development and infill potential, drilling
prospects, expansion and other development trends of the oil and gas industry,
business strategy, production of oil and gas reserves, expansion and growth of
the Company's business and operations, and other such matters are forward-
looking statements. These statements are based on certain assumptions and
analyses made by the Company in light of its experience and its perception of
historical trends, current conditions and expected future developments as well
as other factors it believes are appropriate in the circumstances. However,
whether actual results and developments will conform with the Company's
expectations and predictions is subject to a number of risks and
uncertainties, including the risk factors discussed in this Prospectus;
general economic, market or business conditions; the business opportunities
(or lack thereof) that may be presented to and pursued by the Company; changes
in laws or regulations; and other factors, most of which are beyond the
control of the Company. Consequently, all of the forward-looking statements
made in this Prospectus are qualified by these cautionary statements and there
can be no assurance that the actual results or developments anticipated by the
Company will be realized or, even if substantially realized, that they will
have the expected consequences to or effects on the Company or its business or
operations. The Company assumes no obligation to update any such forward-
looking statements.

NOTE OFFERING

Concurrent with this Offering, the Company is offering $100 million
aggregate principal amount of its Senior Subordinated Notes Due 2009 (the
"Notes"). This Offering and the Note Offering are not contingent upon each
other and there can be no assurance that the Note Offering will be
consummated.

The Indenture for the Notes contains limitations on, among other things, (a)
the ability of the Company to incur additional indebtedness, (b) the payment
of dividends and other distributions with respect to the capital stock of the
Company and the purchase, redemption or retirement of capital stock of the
Company, (c) the making of certain investments, (d) the incurrence of certain
liens, (e) asset sales, (f) the issuance and sale of capital stock of
restricted subsidiaries, (g) transactions with affiliates, (h) payment
restrictions affecting restricted subsidiaries, and (i) certain
consolidations, mergers and transfers of assets.

USE OF PROCEEDS

The net proceeds to the Company from the sale of the Common Stock offered
hereby are estimated to be approximately $47.1 million. Such net proceeds will
be used to reduce a portion of existing indebtedness under the Company's Bank
Facility. At January 30, 1997, the outstanding balance under the Bank Facility
totaled approximately $238.0 million, with an average interest rate of
approximately 6.6 percent. The Company's indebtedness under the Bank Facility
was incurred, in part, to finance the Company's acquisitions of oil and gas
reserves, including the acquisitions of Shamrock and the Exxon Properties. For
additional information regarding the term and the interest rate of the
indebtedness under the Bank Facility, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity."

If the concurrent Note Offering is consummated, the net proceeds from that
offering to the Company are estimated to be approximately $96.4 million. Such
net proceeds will also be used to reduce a portion of existing indebtedness
under the Bank Facility.

15
<PAGE>

CAPITALIZATION

The following table sets forth at September 30, 1996: (a) the historical
capitalization of the Company, (b) the as adjusted capitalization of the
Company after giving effect to the debt incurred to purchase the Exxon
Properties and the acquisition of Shamrock (see "Recent Acquisitions"), and
the Common Stock Offering and the application of the estimated net proceeds
therefrom as set forth in "Use of Proceeds," and (c) the as adjusted combined
capitalization of the Company after giving effect to (b) above and the Note
Offering and the application of the estimated net proceeds therefrom as set
forth in "Use of Proceeds." This table should be read in conjunction with the
Company's consolidated financial statements and the notes thereto included
elsewhere in this Prospectus.

<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
----------------------------------------
AS ADJUSTED
COMMON STOCK
OFFERING AND AS ADJUSTED
HISTORICAL ACQUISITIONS COMBINED
---------- ------------ -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Current portion of long-term debt.... $ 7,929 $ 7,929 $ 7,929
========= ========= =========
Long-term debt:
Bank Revolving Loan Facility....... $ 164,800 $ 184,118(a)(b) $ 87,710(c)
9% Senior Subordinated Notes Due
2005, net of discount............. 149,623 149,623 149,623
Note Offering Notes, net of
discount.......................... -- -- 99,158
International Finance Corporation
Note.............................. 21,957 21,957 21,957
--------- --------- ---------
Total long-term debt............. 336,380 355,698 358,448
--------- --------- ---------
Minority interest.................... 2,286 2,286 2,286
--------- --------- ---------
Stockholders' equity:
Common stock(d).................... 120 128(b) 128
Capital in excess of par value..... 152,121 199,196(b) 199,196
Retained earnings.................. 98,991 98,991 98,991
--------- --------- ---------
Total stockholders' equity....... 251,232 298,315 298,315
--------- --------- ---------
Total capitalization................. $ 589,898 $ 656,299 $ 659,049
========= ========= =========
</TABLE>
- --------
(a) Reflects additional borrowings of $66.4 million to fund the acquisitions
of the Exxon Properties and Shamrock.
(b) Reflects the issuance of 1,500,000 shares of Common Stock by the Company
at the public offering price of $33.125 per share, resulting in estimated
net proceeds of $47.1 million, of which $7,500 (equal to the par value of
the shares issued) is reflected in Common stock and $47.1 million is
reflected in Capital in excess of par value. Net proceeds from the Common
Stock Offering are applied to reduce borrowings under the Bank Facility.
See "Use of Proceeds."
(c) Reflects the reduction in borrowings resulting from the application of the
estimated $96.4 million net proceeds from the Note Offering.
(d) There were 24,100,502 shares of Common Stock issued and outstanding prior
to the Common Stock Offering, and 25,600,502 shares outstanding after
giving effect to the Common Stock Offering. The number of shares of Common
Stock outstanding excludes (a) 225,000 shares of Common Stock that may be
sold by the Company upon exercise of the Underwriters' over-allotment
option, and (b) 1,304,102 shares of Common Stock reserved for issuance
upon exercise of outstanding options granted under the Company's 1983
Stock Option Plan, 1990 Stock Plan and Non-Management Director Stock
Option Plan, at an average exercise price of $16.45 per share. In
addition, an aggregate of 792,000 shares are available to be granted under
these Plans.

16
<PAGE>

PRICE RANGE OF COMMON STOCK AND DIVIDENDS

The Common Stock commenced trading on the New York Stock Exchange on August
3, 1990, under the symbol "VPI." The following table sets forth the high and
low sale prices per share of Common Stock, as reported in the New York Stock
Exchange composite transactions, and the cash dividends paid per share of
Common Stock, for the periods indicated:

<TABLE>
<CAPTION>
DIVIDENDS
HIGH LOW PAID
---- --- ---------
<S> <C> <C> <C>
1995:
First quarter........................................ $20 $16 $.02
Second quarter....................................... 21 5/8 18 1/4 .02
Third quarter........................................ 21 3/4 17 .02
Fourth quarter....................................... 22 1/2 19 1/8 .025
1996:
First quarter........................................ 22 1/2 19 1/8 .025
Second quarter....................................... 26 3/4 19 .025
Third quarter........................................ 29 7/8 22 3/8 .025
Fourth quarter....................................... 34 3/4 28 3/4 .03
1997:
First quarter (through January 30)................... 37 3/8 32 3/8 .03
</TABLE>

On January 30, 1997, the last reported sales price of the Common Stock on
the New York Stock Exchange was $33 1/8 per share. Substantially all of the
Company's stockholders maintain their shares in "street name" accounts and are
not, individually, stockholders of record. As of December 31, 1996, the Common
Stock was held by approximately 82 holders of record and approximately 2,500
beneficial owners.

The Company began paying a quarterly dividend in the fourth quarter of 1992
and expects to continue paying a regular quarterly cash dividend. The
determination of the amount of future cash dividends, if any, to be declared
and paid, however, will depend upon, among other things, the Company's
financial condition, funds from operations, the level of its capital
expenditures and its future business prospects. The Company's credit
arrangements (including the Notes in the event the Note Offering is
consummated and the 9% Notes), contain certain restrictions on the payment of
dividends, the most restrictive of which prohibit the payment of dividends if
such payments would reduce Net Worth, as defined in the Bank Facility, below
the sum of $200 million plus 75 percent of net proceeds of any future equity
offerings ($235.3 million based on estimated net proceeds from this Offering).
Net Worth was approximately $251.2 million at September 30, 1996 ($298.3
million as adjusted for the estimated net proceeds from this Offering).

17
<PAGE>

SELECTED FINANCIAL AND OPERATING DATA

The financial data presented in the table below for and at the end of each
of the years in the five-year period ended December 31, 1995, are derived from
the consolidated financial statements of the Company audited by Arthur
Andersen LLP, independent public accountants. The financial data presented in
the table below for and at the end of each of the nine-month periods ended
September 30, 1996 and 1995, are derived from the unaudited consolidated
financial statements of the Company. In the opinion of management of the
Company, such unaudited consolidated financial statements include all
adjustments (consisting only of normal recurring adjustments) necessary for a
fair presentation of the financial data for such periods. The results for the
nine months ended September 30, 1996, are not necessarily indicative of the
results to be achieved for the full year.

The data presented below should be read in conjunction with the Company's
consolidated financial statements and the notes thereto included elsewhere in
this Prospectus and "Management's Discussion and Analysis of Financial
Condition and Results of Operations." Significant acquisitions of producing
oil and gas properties affect the comparability of the financial and operating
data for the periods presented below.

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEARS ENDED DECEMBER 31,
-------------------- -------------------------------------------------
1996 1995 1995 1994 1993 1992 1991
--------- --------- --------- --------- --------- ------------------
(UNAUDITED)
(IN THOUSANDS, EXCEPT RATIOS, OPERATING DATA AND PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales...... $ 185,847 $ 112,809 $ 160,254 $ 141,357 $ 113,259 $ 61,194 $ 43,392
Oil and gas gathering.. 15,310 8,472 12,380 14,635 7,861 7,775 9,013
Gas marketing.......... 21,519 13,631 20,912 27,285 36,175 31,097 17,221
Other income........... 659 1,461 1,251 2,375 2,732 1,384 4,353
--------- --------- --------- --------- --------- -------- --------
223,335 136,373 194,797 185,652 160,027 101,450 73,979
--------- --------- --------- --------- --------- -------- --------
Costs and expenses:
Lease operating,
including production
taxes................. 67,606 47,520 66,771 59,292 44,930 26,334 19,146
Oil and gas gathering.. 12,838 6,636 9,511 12,294 5,869 5,901 6,894
Gas marketing.......... 19,885 12,210 18,839 24,963 34,406 29,536 16,652
General and
administrative........ 12,026 8,258 11,601 8,889 6,066 4,064 3,168
Depreciation, depletion
and amortization...... 51,313 36,875 52,257 45,774 33,335 17,374 12,927
Interest............... 22,467 13,379 20,178 12,002 6,943 4,497 4,244
--------- --------- --------- --------- --------- -------- --------
186,135 124,878 179,157 163,214 131,549 87,706 63,031
--------- --------- --------- --------- --------- -------- --------
Income before income
taxes, minority
interest and cumulative
effect of accounting
change................. 37,200 11,495 15,640 22,438 28,478 13,744 10,948
Provision (benefit) for
income taxes:
Current................ 2,061 687 (955) 1,576 3,962 1,650 2,367
Deferred............... 7,982 3,895 6,034 6,933 7,727 3,441 1,793
Minority interest in
(income) loss of
subsidiary(a).......... (361) 662 800 -- -- -- --
--------- --------- --------- --------- --------- -------- --------
Income before cumulative
effect of accounting
change................. 26,796 7,575 11,361 13,929 16,789 8,653 6,788
Cumulative effect of
accounting change(b)... -- -- -- -- 1,725 -- --
--------- --------- --------- --------- --------- -------- --------
Net income.............. $ 26,796 $ 7,575 $ 11,361 $ 13,929 $ 18,514 $ 8,653 $ 6,788
========= ========= ========= ========= ========= ======== ========
Weighted average common
shares outstanding..... 24,454 21,322 21,276 21,174 20,830 16,861 16,720
</TABLE>

18
<PAGE>

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEARS ENDED DECEMBER 31,
---------------------- -----------------------------------------------------
1996 1995 1995 1994 1993 1992 1991
--------- --------- --------- --------- --------- --------- ---------
(UNAUDITED)
(IN THOUSANDS, EXCEPT RATIOS, OPERATING DATA AND PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
EARNINGS PER SHARE:
Income before cumulative
effect of accounting
change................. $ 1.10 $ .36 $ .53 $ .66 $ .81 $ .51 $ .41
Net income.............. 1.10 .36 .53 .66 .89 .51 .41
CASH FLOW DATA:
Cash provided (used) by:
Operating activities... $ 82,947 $ 48,904 $ 54,199 $ 58,670 $ 52,219 $ 28,949 $ 19,393
Investing activities... (100,699) (120,925) (187,251) (70,668) (146,126) (122,637) (30,882)
Financing activities... 20,546 73,134 135,166 11,867 93,900 93,923 11,345
BALANCE SHEET DATA (end
of period):
Property, plant and
equipment, net......... $ 623,092 $ 521,751 $ 577,746 $ 366,665 $ 346,034 $ 228,778 $ 126,286
Total assets............ 701,358 572,143 647,539 407,752 384,461 259,887 143,897
Total debt.............. 344,309 309,140 323,776 193,864 181,480 133,375 41,957
Minority interest(a).... 2,286 11,618 3,922 -- -- -- --
Stockholders' equity.... 251,232 169,702 223,960 155,993 143,392 78,696 69,828
OTHER FINANCIAL DATA:
Dividends declared per
share.................. $ .08 $ .07 $ .09 $ .07 $ .05 $ .02 $ --
EBITDA(c)............... 110,980 61,749 88,075 80,214 68,756 35,615 28,119
Ratio of EBITDA to
interest expense....... 4.9x 4.6x 4.4x 6.7x 9.9x 7.9x 6.6x
Ratio of earnings to
fixed charges(d)....... 2.7x 1.9x 1.8x 2.9x 5.0x 4.0x 3.6x
SELECTED OPERATING DATA
(Unaudited):
Production:
Oil (MBbls)............ 8,649 5,310 7,608 6,657 4,785 1,978 1,388
Gas (MMcf)............. 24,535 22,489 30,610 28,884 22,504 14,592 11,411
Oil equivalent (MBOE).. 12,738 9,058 12,710 11,471 8,536 4,410 3,290
Average sales prices:
Oil (per Bbl).......... $ 16.66(e) $ 15.33 $ 15.26 $ 13.53 $ 14.14 $ 17.88 $ 19.39
Gas (per Mcf).......... 1.70 1.42 1.46 1.78 2.03 1.77 1.44
Production costs (per
BOE)(f)................ 5.31 5.25 5.25 5.17 5.26 5.97 5.82
Three-year average
finding cost
(per BOE)(g)........... N/A N/A 2.98 3.23 3.34 3.39 4.06
Proved reserves (end of
period):
Oil (MBbls)............ N/A N/A 147,871 70,789 63,277 40,209 17,061
Gas (MMcf)............. N/A N/A 310,762 281,638 273,142 206,582 137,712
Total proved reserves
(MBOE)................ N/A N/A 199,665 117,729 108,801 74,639 40,013
Proved developed
reserves (MBOE)....... N/A N/A 145,790 91,722 88,976 61,581 31,620
Annual reserve
replacement ratio(h)... N/A N/A 747% 179% 504% 891% 215%
Estimated reserve life
(in years)(i).......... N/A N/A 15.7 10.3 12.7 11.5 12.2
Present value of
estimated future net
revenues before income
taxes (discounted at
10%)
(in thousands)......... N/A N/A $ 894,249 $ 446,987 $ 359,978 $ 335,941 $ 160,021
Standardized measure of
discounted future net
cash flows
(in thousands)......... N/A N/A 736,546 385,721 339,701 274,443 131,533
</TABLE>
- --------
(a) Reflects the minority interest in Cadipsa. See the consolidated financial
statements and the notes thereto of the Company included elsewhere in this
Prospectus.
(b) Represents the cumulative effect on prior years of adopting Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes."
(c) EBITDA as presented herein is generally defined as income before
cumulative effect of accounting change, provision for income taxes,
interest, depreciation, depletion, amortization and certain other non-cash
charges. EBITDA is included as a supplemental disclosure because it is
commonly accepted as providing useful information regarding a company's
ability to service and incur debt. EBITDA, however, should not be
considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data
prepared in accordance with generally

19
<PAGE>

accepted accounting principles or as a measure of a company's profitability
or liquidity. If the Exxon Properties and Shamrock had been acquired on
January 1, 1996, these properties would have increased the Company's EBITDA
by approximately $8.5 million for the nine months ended September 30, 1996.
See "Recent Acquisitions."
(d) For purposes of calculating the ratio of earnings to fixed charges,
earnings are defined as income of the Company and its subsidiaries before
income taxes and fixed charges. Fixed charges consist of interest expense,
including amortization of financing costs and any discount or premium
related to any indebtedness.
(e) During the first nine months of 1996, the impact of oil hedges reduced the
Company's overall average oil price $1.17 to $16.66 per Bbl.
(f) Includes lease operating costs and production and ad valorem taxes.
(g) Represents the average finding cost per BOE during the three years ended
December 31 of the year shown in the column. See "Certain Definitions."
(h) The annual reserve replacement ratio is a percentage determined on a BOE
basis by dividing the estimated reserves added during a year from
exploitation, development and exploration activities, acquisitions of
proved reserves and revisions of previous estimates, excluding property
sales, by the oil and gas volumes produced during that year.
(i) Estimated reserve life is calculated on a BOE basis by dividing the total
estimated proved reserves at year-end by the total production during the
year. This calculation can be affected by the timing of major
acquisitions. For example, major acquisitions were made during the second
half of 1995 which resulted in an estimated reserve life of 15.7 years for
1995. This compares to an estimated reserve life of 12.0 years for 1995
based on annualized first quarter 1996 production.

20
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

The Company's results of operations have been significantly affected by its
success in acquiring oil and gas properties and its ability to maintain or
increase production through its exploitation and exploration activities.
Fluctuations in oil and gas prices have also significantly affected the
Company's results. Principally through acquisitions, the Company has achieved
significant increases in its oil and gas production. The following table
reflects the Company's average oil and gas prices and its oil and gas
production for the periods presented:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEARS ENDED DECEMBER 31,
----------------- --------------------------
1996 1995 1995 1994 1993
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Average prices:
Oil (per Bbl)--
U.S.............................. $ 17.08 $ 15.42 $ 15.44 $ 13.53 $ 14.14
Argentina........................ 15.87 14.20 13.98 -- --
Total............................ 16.66 15.33 15.26 13.53 14.14
Gas, all U.S. (per Mcf)........... $ 1.70 $ 1.42 $ 1.46 $ 1.78 $ 2.03
Production:
Oil (MBbls)--
U.S.............................. 5,683 4,933 6,647 6,657 4,785
Argentina........................ 2,966 377 961 -- --
Total............................ 8,649 5,310 7,608 6,657 4,785
Gas, all U.S. (MMcf).............. 24,535 22,489 30,610 28,884 22,504
</TABLE>

Average U.S. oil prices received by the Company fluctuate generally with
changes in the West Texas Intermediate ("WTI") posted prices for oil. The
Company's Argentina oil production is sold at WTI spot prices less a specified
differential. The Company experienced a nine percent increase in its average
oil price in the first nine months of 1996 compared to the same period in
1995. During the first nine months of 1996, the impact of oil hedges reduced
the Company's overall average oil price $1.17 to $16.66 per Bbl. The Company's
average U.S. oil price was reduced 79 cents to $17.08 per Bbl while its
average Argentina oil price was reduced $1.89 to $15.87 per Bbl. Approximately
58 percent of the Company's Argentina oil production and 32 percent of its
U.S. oil production (a combined 3.561 MMBbls) were covered by oil hedges in
the first nine months of 1996.

The Company experienced a 13 percent increase in its average oil price in
1995 compared to 1994. Higher prices relative to WTI posted prices for the
Company's California oil production and the impact of one hedge (swap
agreement) which expired December 31, 1995, combined with higher WTI posted
prices to account for the increase. The Company's average realized oil price
declined four percent in 1994 compared to 1993. The Company's average realized
oil price has increased from 84 percent of WTI posted prices in 1993 to 91
percent for the first nine months of 1996.

Average gas prices received by the Company fluctuate generally with changes
in spot market prices for gas, which may vary significantly by region. The
Company's average gas price for the first nine months of 1996, including the
impact of hedging, was 20 percent higher than the same period of 1995. For the
first nine months of 1996, the average gas price was negatively impacted by
six cents per Mcf as a result of certain gas hedges that were in place for
40,000 Mcf of gas per day for the period January through March 1996. The
Company experienced an 18 percent decline in average gas prices in 1995
compared to 1994 and a 12 percent decline in 1994 compared to 1993.

21
<PAGE>

The Company has previously engaged in oil and gas hedging activities and
intends to continue to consider various hedging arrangements to realize
commodity prices which it considers favorable. The Company had oil hedges
(swap agreements) in place for the fourth quarter of 1996 covering 2.204
MMBbls at an average NYMEX reference price of $18.27 per Bbl. Before the
impact of oil hedges, the Company's average realized oil price for the first
nine months of 1996 was $17.83 per Bbl, or approximately 84 percent of the
average NYMEX reference price. The actual NYMEX reference price in the fourth
quarter of 1996 was $24.52 per Bbl. Currently, oil hedges for the calendar
year 1997 cover 2.738 MMBbls at an average NYMEX reference price of $19.26.

Relatively modest changes in either oil or gas prices significantly impact
the Company's results of operations and cash flow. However, the impact of
changes in the market prices for oil and gas on the Company's average realized
prices may be reduced from time to time based on the level of the Company's
hedging activities. Based on 1996 first nine months oil and gas production, a
change in the average oil price realized by the Company of $1.00 per Bbl would
result in a change in net income and cash flow before income taxes on a nine
month basis of approximately $6.3 million and $8.5 million, respectively. A 10
cent per Mcf change in the average price realized by the Company for gas would
result in a change in net income and cash flow before income taxes on a nine
month basis of approximately $1.4 million and $2.4 million, respectively.

PERIOD TO PERIOD COMPARISONS

During 1995, the Company made various acquisitions which significantly
impacted the period to period comparison for the first nine months of 1996.
These acquisitions (the "1995 Acquisitions") include the purchase of certain
oil and gas properties from Texaco Exploration and Production, Inc. ("Texaco")
(the "Texaco Properties") in May 1995, the acquisition of a controlling
interest in Cadipsa in July 1995, the acquisition of Vintage Oil Argentina,
Inc., formerly BG Argentina, S.A. ("Vintage Argentina"), in September 1995,
and the acquisition of certain Argentina oil and gas properties from Astra
Compania Argentina de Petroleo S.A. and Shell Compania Argentina de Petroleo
S.A. (collectively, the "Astra/Shell Properties") in November 1995 and
December 1995, respectively.

The Company's consolidated revenues and expenses for 1996 and 1995 include
the consolidation of 100 percent of Cadipsa from the date of acquisition under
the purchase method of accounting. The minority interest in income/(loss) of
subsidiary reflects the portion of Cadipsa's income/(loss) attributable to the
minority ownership during the nine months ended September 30, 1996 and 1995,
and the year ended December 31, 1995. At September 30, 1996, the Company owned
95.7 percent of Cadipsa.

Nine Months Ended September 30, 1996, Compared to Nine Months Ended September
30, 1995

Net income was $26.8 million for the first nine months of 1996, up 253
percent from $7.6 million for the same period in 1995. Increases in the
Company's oil and gas production of 41 percent on an equivalent barrel basis,
an increase of 20 percent in natural gas prices, and an increase of nine
percent in oil prices are primarily responsible for the increase in net
income. The production increases primarily relate to the 1995 Acquisitions.

Oil and gas sales increased $73.0 million (65 percent), to $185.8 million
for the first nine months of 1996 from $112.8 million for the first nine
months of 1995. A 63 percent increase in oil production and a nine percent
increase in average oil prices combined to account for $62.7 million of the
increase. A nine percent increase in gas production and a 20 percent increase
in average gas prices contributed to an additional $10.3 million increase.

Oil and gas gathering net margins (revenue less expenses) increased $700,000
(39 percent), to $2.5 million for the first nine months of 1996 from $1.8
million for the first nine months of 1995, due primarily to improved
profitability on a gathering system located in Texas, additional net margins
from a gathering system located in California acquired from Texaco in May 1995
and increased gas prices.

22
<PAGE>

Gas marketing net margins (revenue less expenses) increased $200,000 (14
percent), to $1.6 million for the first nine months of 1996 from $1.4 million
for the first nine months of 1995, due primarily to an increase in the reserve
for doubtful accounts associated with gas sales in the first nine months of
1995 with no similar increase in 1996.

Lease operating expenses, including production taxes, increased $20.1
million (42 percent), to $67.6 million for the first nine months of 1996 from
$47.5 million for the first nine months of 1995. The increase in lease
operating expenses is due primarily to the 1995 Acquisitions. Lease operating
expenses per equivalent barrel produced increased one percent to $5.31 in the
first nine months of 1996 from $5.25 for the same period in 1995.

General and administrative expenses increased $3.7 million (45 percent), to
$12.0 million for the first nine months of 1996 from $8.3 million for the
first nine months of 1995, due primarily to the acquisitions of Cadipsa and
Vintage Argentina in the last half of 1995.

Depreciation, depletion and amortization increased $14.4 million (39
percent), to $51.3 million for the first nine months of 1996 from $36.9
million for the first nine months of 1995, due primarily to the 41 percent
increase in production on an equivalent barrel basis. Amortization per
equivalent barrel of the Company's U.S. oil and gas properties declined to
$3.76 in the first nine months of 1996 from $3.87 in 1995. Amortization per
equivalent barrel of the Company's Argentina oil and gas properties for the
first nine months of 1996 was $4.18 as compared to $4.29 in the same period
for 1995.

Interest expense increased $9.1 million (68 percent), to $22.5 million for
the first nine months of 1996 from $13.4 million for the first nine months of
1995, due primarily to a 46 percent increase in the Company's total average
outstanding debt related primarily to the 1995 Acquisitions.

Year Ended December 31, 1995, Compared to Year Ended December 31, 1994

Net income was $11.4 million for the year ended December 31, 1995, down 18
percent from $13.9 million in 1994. A decrease of 18 percent in natural gas
prices and a 68 percent increase in interest expense offset a 13 percent
increase in average oil prices and an 11 percent increase in production on an
equivalent barrel basis. In addition, certain oil and gas properties were
shut-in for a portion of the first six months of 1995 due to storm damage
caused by heavy rains in California and the resulting mudslides, reducing the
Company's overall production in the first half by approximately 70,000 Bbls of
oil and 350,000 Mcf of gas.

During the last half of 1995, the Company purchased a 71.6 percent
controlling interest in Cadipsa, a publicly-traded Argentine oil and gas
exploration and production company. The Company's consolidated revenues and
expenses for the year ended December 31, 1995, include the consolidation of
100 percent of Cadipsa for the last half of 1995 under the purchase method of
accounting. The minority interest in loss of subsidiary of $0.8 million
reflects the portion of Cadipsa's loss attributable to the minority ownership
during the last half of 1995.

Oil and gas sales increased $18.9 million (13 percent), to $160.3 million
for 1995 from $141.4 million for 1994, due primarily to a 13 percent increase
in average oil prices and an 11 percent increase in production on an
equivalent barrel basis, partially offset by an 18 percent decline in average
natural gas prices. The production increases primarily related to the Texaco
Properties purchased in May 1995, the acquisition of a controlling interest in
Cadipsa in July 1995, and the acquisition of Vintage Argentina in September
1995. However, these production increases were partially offset by lower
production from the Company's properties affected by the California storms. In
addition, oil and gas sales for 1995 were reduced by $0.5 million reflecting
the total settlement of a class action lawsuit filed on June 8, 1990, on
behalf of certain royalty and mineral interest owners.

23
<PAGE>

Oil and gas gathering net margins (revenues less expenses) increased
$600,000 (26 percent), to $2.9 million in 1995 from $2.3 million in 1994, due
primarily to net margins from a gathering system located in California
acquired from Texaco in May 1995 and additional third party volumes
transported on an existing system located in Texas.

Gas marketing net margins (revenues less expenses) decreased $200,000 (9
percent), to $2.1 million in 1995 from $2.3 million in 1994, due primarily to
an increase in the reserve for doubtful accounts associated with gas sales and
the decline in average natural gas prices.

Other income decreased $1.1 million (46 percent) to $1.3 million in 1995
from $2.4 million in 1994, due primarily to the recognition of a $0.9 million
loss from 1996 natural gas price hedges (swap agreements) which no longer
qualify as hedges.

Lease operating expenses, including production taxes, increased $7.5 million
(13 percent), to $66.8 million in 1995 from $59.3 million in 1994. The
increase in lease operating expenses is due primarily to the acquisitions of
Cadipsa and Vintage Argentina and the Texaco Properties. Lease operating
expenses per equivalent barrel produced increased 2 percent to $5.25 in 1995
from $5.17 in 1994, due to the impact of the California storms on production
and costs incurred.

General and administrative expenses increased $2.7 million (30 percent), to
$11.6 million in 1995 from $8.9 million in 1994, due primarily to the
acquisition of Cadipsa and the addition of new personnel throughout 1994 and
1995 as a result of 1994 acquisitions and an increase in the Company's
exploitation efforts.

Depreciation, depletion and amortization increased $6.5 million (14
percent), to $52.3 million in 1995 from $45.8 million in 1994, due primarily
to the 11 percent increase in production on an equivalent barrel basis.
Amortization per equivalent barrel increased 2 percent to $3.89 in 1995 from
$3.82 in 1994 on the Company's U.S. oil and gas properties. Amortization per
equivalent barrel of the Company's Argentina oil and gas properties for 1995
was $4.28. The Company had no Argentina operations prior to 1995.

Interest expense increased $8.2 million (68 percent), to $20.2 million in
1995 from $12.0 million in 1994, due primarily to a 28 percent increase in the
average interest rate on the Company's floating-rate debt with banks to 7.4
percent per annum in 1995 from 5.8 percent per annum in 1994, an increase in
average outstanding advances under the Company's bank revolving credit
facility and bank term loan, and interest expense on third-party debt of the
Company's foreign subsidiaries.

Year Ended December 31, 1994, Compared to Year Ended December 31, 1993

Income before the cumulative effect of the change in accounting for income
taxes was $13.9 million for the year ended December 31, 1994, down 17 percent
from $16.8 million in 1993. Significantly lower gas prices combined with lower
oil prices more than offset the impact on net income of a 34 percent increase
in oil and gas production on an equivalent barrel basis. The production
increases related primarily to production from certain oil and gas properties
acquired through various acquisitions in 1993 and 1994. Net income for the
year ended December 31, 1993, of $18.5 million included $1.7 million related
to the cumulative effect on prior years of adopting Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes ("SFAS 109").

Oil and gas sales increased $28.1 million (25 percent), to $141.4 million in
1994 from $113.3 million in 1993 due primarily to a 39 percent increase in oil
production and a 28 percent increase in gas production. The production
increases related primarily to production from certain oil and gas properties
acquired from Conoco Inc. ("Conoco") in June 1993, Santa Fe Energy Resources,
Inc. ("Santa Fe") in November 1993 and various smaller acquisitions made
throughout 1994. The production increases were partially offset by a 4 percent
decrease in the Company's average oil price and a 12 percent decrease in the
Company's average gas price for the period.

24
<PAGE>

Oil and gas gathering net margins (revenues less expenses) increased
$300,000 (15 percent) to $2.3 million in 1994 from $2.0 million in 1993 due
primarily to the acquisition of the remaining interests in certain gathering
systems located in Oklahoma and Kansas by acquiring the Vintage/P Acquisition
Limited Partnership in November 1993 and the acquisition and construction of
certain smaller gathering systems located in Texas in 1994.

Gas marketing net margins (revenues less expenses) increased $500,000 (28
percent) to $2.3 million in 1994 from $1.8 million in 1993 due primarily to a
3 percent increase in gas volumes marketed and a $300,000 nonrecurring charge
in 1993 with no similar charge in 1994.

Other income decreased $300,000 (11 percent) to $2.4 million in 1994 from
$2.7 million in 1993 due primarily to the receipt in 1993 of $865,000 related
to gas contract settlements with no similar settlements in 1994 partially
offset by an increase in rental income from Company owned equipment.

Lease operating expenses, including production taxes, increased $14.4
million (32 percent) to $59.3 million in 1994 from $44.9 million in 1993 due
primarily to the 34 percent increase in oil and gas production (on an
equivalent barrel basis) resulting from the acquisitions discussed above.
Lease operating expenses per equivalent barrel produced decreased 2 percent to
$5.17 in 1994 from $5.26 in 1993.

General and administrative expenses increased $2.8 million (46 percent) to
$8.9 million in 1994 from $6.1 million in 1993 due primarily to the addition
of personnel in 1994 associated with the Company's significant acquisitions in
late 1993.

Depreciation, depletion and amortization increased $12.5 million (38
percent) to $45.8 million in 1994 from $33.3 million in 1993 due primarily to
the 34 percent increase in oil and gas production on an equivalent barrel
basis. Amortization per equivalent barrel produced increased only 3 percent to
$3.82 in 1994 from $3.71 in 1993.

Interest expense increased $5.1 million (74 percent) to $12.0 million in
1994 from $6.9 million in 1993 due primarily to an increase in the average
outstanding advances under the Company's revolving credit facility and an
increase in the average annual interest rate paid under this facility to 5.8
percent in 1994 from 4.5 percent in 1993.

CAPITAL EXPENDITURES

During the first nine months of 1996, the Company's domestic capital
expenditures totaled $58.6 million of which $18.0 million were for
acquisitions of domestic producing oil and gas properties. The largest of
these acquisitions was approximately $13.9 million for certain oil and gas
properties from Conoco. Subsequent to September 30, 1996, the Company
purchased the Exxon Properties for approximately $28.2 million. Funds for
these acquisitions were provided by advances under the Bank Facility. See
"Recent Acquisitions."

During the nine months ended September 30, 1996, the Company's international
capital expenditures of $38.9 million included $35.1 million in Argentina. In
November 1996, the Company agreed to purchase all the outstanding stock of
Shamrock for approximately $29.0 million in cash. In addition, at closing on
January 7, 1997, the Company repaid all of Shamrock's existing bank debt
(approximately $9.2 million). Funds for the purchase of the stock and the
repayment of debt were provided by advances under the Company's Bank Facility.
Shamrock's assets include (a) oil and gas properties valued at $35.5 million
(including the effect of approximately $6.6 million of deferred income taxes
recorded under the purchase method of accounting), and (b) inventory,
receivables, cash and other assets net of liabilities (other than bank debt
repaid at closing) of approximately $9.3 million. See "Recent Acquisitions."

25
<PAGE>

The timing of most of the Company's capital expenditures is discretionary
with no material long-term capital expenditure commitments. Consequently, the
Company has a significant degree of flexibility to adjust the level of such
expenditures as circumstances warrant. The Company primarily uses internally
generated cash flow to fund capital expenditures other than significant
acquisitions and anticipates that its cash flow, net of debt service
obligations, will be sufficient to fund its planned $117 million of non-
acquisition capital expenditures during 1997. Approximately $74 million of the
Company's planned 1997 non-acquisition capital expenditure budget is devoted
to reserve exploitation activities, including development and infill drilling,
and approximately $43 million is devoted to exploration activities. The
Company does not have a specific acquisition budget since the timing and size
of acquisitions are difficult to forecast. The Company is actively pursuing
additional acquisitions of oil and gas properties. In addition to internally
generated cash flow and advances under the Bank Facility, the Company may seek
additional sources of capital to fund any future significant acquisitions (see
"--Liquidity").

The Company's recent capital expenditure history is as follows (in
thousands):

<TABLE>
<CAPTION>
NINE MONTHS
ENDED YEARS ENDED DECEMBER 31,
SEPTEMBER 30, -------------------------
1996 1995 1994 1993
------------- -------- ------- --------
<S> <C> <C> <C> <C>
Acquisition of oil and gas reserves.... $21,712 $207,658 $36,544 $123,906
Workovers and recompletions............ 24,949 18,313 13,984 12,915
Drilling............................... 29,223 21,343 9,593 6,750
Acquisition and construction of gather-
ing systems........................... 107 234 632 3,319
Acquisition of undeveloped acreage and
seismic............................... 12,611 7,684 1,869 610
Other.................................. 8,876 5,367 3,146 3,071
------- -------- ------- --------
Total................................ $97,478 $260,599 $65,768 $150,571
======= ======== ======= ========
</TABLE>

LIQUIDITY

The $96.4 million of estimated net proceeds from the sale of the Notes under
the Note Offering will be used to repay a portion of existing indebtedness
outstanding under the Company's Bank Facility. In addition, the estimated
proceeds of $47.1 million from the Common Stock Offering will be used to repay
a portion of existing indebtedness outstanding under the Company's Bank
Facility. The Company may issue additional equity and debt securities in the
future in connection with any future major acquisitions and to maintain its
financial flexibility.

During 1990, early 1993 and late 1995, the Company completed public
offerings of Common Stock to finance certain acquisitions and provide
liquidity for its future activities. Simultaneous with the 1995 common stock
offering, the Company completed a public debt offering to provide liquidity
for its future activities.

In August 1990, the Company sold 3.4 million shares of its Common Stock for
net proceeds of approximately $32.8 million which were used to fund an
acquisition of oil and gas properties and reduce indebtedness under the
Company's revolving credit facility. In January 1993, the Company sold 3.9
million shares of its Common Stock for net proceeds of approximately $44.8
million which were used to reduce indebtedness under the Company's revolving
credit facility.

On December 20, 1995, the Company completed a public offering of 2,793,700
shares of Common Stock of which 2,500,000 shares were sold by the Company and
293,700 shares were sold by a stockholder. Net proceeds to the Company, after
underwriting commission and other expenses, were approximately $49.5 million
and were used to fund a substantial portion of the purchase of the Astra/Shell
Properties.

26
<PAGE>

Also on December 20, 1995, the Company issued $150 million of its 9% Senior
Subordinated Notes Due 2005 (the "9% Notes"). The net proceeds to the Company
from the sale of the 9% Notes of approximately $145.1 million were used
principally to reduce a portion of the outstanding balance under the Company's
revolving credit facility. The 9% Notes are redeemable at the option of the
Company, in whole or in part, at any time on or after December 15, 2000. Upon
a change in control of the Company, holders of the 9% Notes may require the
Company to repurchase all or a portion of the 9% Notes at a purchase price
equal to 101 percent of the principal amount thereof, plus accrued and unpaid
interest. The 9% Notes will mature on December 15, 2005, with interest payable
semiannually on June 15 and December 15 of each year.

Internally generated cash flow and the borrowing capacity under the Bank
Facility are the Company's major sources of liquidity. In addition, the
Company may use other sources of capital, including the issuance of additional
debt securities or equity securities, to fund any major acquisitions it might
secure in the future and to maintain its financial flexibility. The Company
funds its capital expenditures (excluding acquisitions) and debt service
requirements through internally generated cash flows from operations. Any
excess cash flow is used to reduce outstanding advances under the Bank
Facility and other indebtedness.

Under its Credit Agreement dated August 29, 1996, as amended, certain banks
have provided to the Company an unsecured Bank Facility. The Bank Facility
establishes a borrowing base (currently $305 million) determined by the banks'
evaluation of the Company's U.S. and certain Argentina oil and gas reserves.

Outstanding advances under the Bank Facility bear interest payable quarterly
at a floating rate based on Bank of Montreal's alternate base rate (as
defined) or, at the Company's option, at a fixed rate for up to six months
based on the eurodollar market rate ("LIBOR"). The Company's interest rate
increments above the alternate base rate and LIBOR vary based on the level of
outstanding senior debt and the portion of the borrowing base attributable to
U.S. reserves at the time. As of January 30, 1997, the Company had elected a
fixed rate based on LIBOR for a substantial portion of its outstanding
advances, which resulted in an average interest rate of approximately 6.6
percent. In addition, the Company must pay a commitment fee ranging from 0.25
to 0.375 percent per annum on the unused portion of the banks' commitment.

On a semiannual basis, the Company's borrowing base is redetermined by the
banks based upon their review of the Company's U.S. and certain Argentina oil
and gas reserves. If the sum of outstanding senior debt (excluding debt of the
Company's foreign subsidiaries) exceeds the borrowing base, as redetermined,
the Company must repay such excess. Any principal advances outstanding under
the Bank Facility at October 1, 1999, will be payable in 12 equal consecutive
quarterly installments commencing January 1, 2000, with maturity at October 1,
2002.

The unused portion of the Bank Facility was approximately $59.3 million at
January 30, 1997. The Company has entered into an amendment to its Bank
Facility in connection with the proposed Note Offering which provides that the
borrowing base will be reduced to approximately $270 million if such offering
is consummated. After giving effect to the application of the net proceeds
from the Note Offering and the Common Stock Offering as set forth in "Use of
Proceeds" and the related reduction in the borrowing base, the unused portion
of the Bank Facility would be approximately $167.8 million ($120.7 million if
only the Note Offering is consummated or $106.4 million if only the Common
Stock Offering is consummated). The unused portion of the Bank Facility and
the Company's internally generated cash flow provide liquidity which may be
used to finance future capital expenditures, including acquisitions. As
additional U.S. and Argentina acquisitions are made and properties are added
to the borrowing base, the banks' determination of the borrowing base and
their commitments may be increased.

INFLATION

In recent years inflation has not had a significant impact on the Company's
operations or financial condition.

27
<PAGE>

INCOME TAXES

In February 1992, the Financial Accounting Standards Board issued SFAS 109.
The Company adopted SFAS 109 in 1993. An analysis of income taxes and a
discussion of the impact on the Company of adopting SFAS 109 is presented in
Notes 1 and 5 to the Company's December 31, 1995, consolidated financial
statements included elsewhere in this Prospectus.

The total provision for U.S. income taxes is based on the Federal corporate
statutory income tax rate plus an estimated average rate for state income
taxes. The Company incurred a current benefit for income taxes of
approximately $1.0 million during 1995, and a current provision for income
taxes of $1.6 million and $4.0 million for 1994 and 1993, respectively. During
the first nine months of 1996 and 1995, the Company incurred a current
provision for income taxes of approximately $2.1 million and $0.7 million,
respectively.

The Company has a $5.4 million U.S. Alternative Minimum Tax ("AMT") credit
carryforward which does not expire and is available to offset U.S. regular
income taxes in future years, but only to the extent that U.S. regular income
taxes exceed the U.S. AMT in such years.

Earnings of the Company's subsidiaries, Cadipsa and Vintage Argentina, are
subject to Argentina income taxes. Due to significant Argentina net operating
loss carryforwards for both companies, the Company does not expect to pay any
foreign income taxes related to these subsidiaries in 1996. Earnings of the
Company's subsidiary, Shamrock, are subject to Bolivia income taxes. No U.S.
deferred tax liability will be recognized related to the unremitted earnings
of these foreign subsidiaries as it is the Company's intention, generally, to
reinvest such earnings permanently.

FOREIGN OPERATIONS

A majority of the Company's foreign operations are located in Argentina. The
Company believes Argentina offers a politically stable environment and does
not anticipate any significant change in the near future. The current
democratic form of government has been in place since 1983 and, since 1989,
has pursued a steady process of privatization, deregulation and economic
stabilization and reforms involving the reduction of inflation and public
spending. Argentina's 12-month trailing inflation rate measured by the
Argentine Consumer Price Index declined from 200.7 percent as of June 1991 to
0.4 percent as of November 1996.

The Company believes that its Argentine operations present minimal currency
risk. All of the Company's Argentine revenues are U.S. dollar based, while a
large portion of its costs are Argentine peso-denominated. The Argentina
Central Bank is obligated by law to sell dollars at a rate of one Argentine
peso to one U.S. dollar and has sought to prevent appreciation of the peso by
buying dollars at rates of not less than 0.998 peso to one U.S. dollar. As a
result, the Company believes that should any devaluation of the Argentine peso
occur, its revenues would be unaffected and its operating costs would not be
significantly increased. At the present time, there are no foreign exchange
controls preventing or restricting the conversion of pesos into dollars.

28
<PAGE>

RECENT ACQUISITIONS

EXXON PROPERTIES (GULF COAST)

On November 20, 1996, the Company purchased certain producing oil and gas
properties and facilities from Exxon Company, U.S.A. located in south Alabama
for approximately $28.2 million in cash, subject to post-closing adjustments
(the "Exxon Properties"). Funds were provided by advances under the Company's
Bank Facility. The Exxon Properties include an interest in two fields totaling
approximately 5,000 net acres with a total of 17 gross (9.9 net) productive
wells with current net daily production of approximately 1,450 Bbls of oil and
liquids and 2,800 Mcf of gas. All of the wells are now operated by the
Company. The primary producing sands are the Smackover and Norphlet at depths
of approximately 15,000 feet. Future exploitation activities will include
operating cost reductions, treating plant efficiencies, workovers and infill
drilling.

SHAMROCK (BOLIVIA)

In November 1996, the Company agreed to purchase 100 percent of the
outstanding common stock of Shamrock Ventures Boliviana Ltd. ("Shamrock") from
affiliates of Ultramar Diamond Shamrock Corporation for approximately $29.0
million in cash. In addition, at closing on January 7, 1997, the Company
repaid all of Shamrock's existing bank debt (approximately $9.2 million).
Funds for the purchase of the stock and the repayment of debt were provided by
advances under the Company's Bank Facility. Shamrock's assets include (a) oil
and gas properties valued at $35.5 million (including the effect of
approximately $6.6 million of deferred income taxes recorded under the
purchase method of accounting), and (b) inventory, receivables, cash and other
assets net of liabilities (other than bank debt repaid at closing) of
approximately $9.3 million. This transaction is subject to government
approvals. The acquisition of Shamrock represents an extension of the
Company's South American operating area that was initially established through
a series of acquisitions in Argentina during 1995.

The oil and gas properties of Shamrock consist of three blocks, totaling
approximately 570,000 net acres, in the Chaco Plains area of southern Bolivia.
This region has experienced the greatest amount of exploration and currently
accounts for the majority of the country's production. The properties consist
of a 100 percent interest in the Chaco and Porvenir blocks, and a 50 percent
interest in the Nupuco block.

Proved reserves at the time of acquisition, as estimated by the Company,
were 53.2 Bcf of gas and 5.1 MMBbls of oil. Current net daily production is
approximately 14,500 Mcf of gas and 230 Bbls of condensate. Recent realized
prices on the properties were $1.23 per Mcf of gas and $21.00 per Bbl of
condensate. The purchase also included a 29 mile gas pipeline and an interest
in a gas processing plant with a capacity of 110 MMcf per day. Liquids are
transferred through the pipeline to the processing plant. The current market
for the gas is Argentina.

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<PAGE>

The Company believes that the Shamrock properties contain substantial upside
potential which may be realized through exploitation and future exploration.
There can be no assurance, however, that such potential will be realized.
Bolivia occupies the strategic pivotal position in the area known as the
"Southern Cone" of South America. The Company expects that gas will be the key
energy source for the developing regional economies. The development of the
sizable gas reserves in southern Bolivia will play an important role as a
source of energy for the net importing countries of this region, the most
significant of which is Brazil. Third party plans call for construction of a
gas pipeline from Santa Cruz, Bolivia to Sao Paulo, Brazil which is
anticipated to be completed by 1999. The Company plans to begin work during
1997 to evaluate the exploration prospects on the Bolivian properties in order
to be ready to take advantage of the increased market for Bolivian gas that
should occur if the pipeline to Brazil is completed. There can be no
assurance, however, that this Brazilian market will be developed.

30
<PAGE>

BUSINESS

GENERAL

The Company is an independent oil and gas company focused on the acquisition
of producing oil and gas properties which contain the potential for increased
value through exploitation and development. The Company, through its
experienced management and engineering staff, has been successful in realizing
such potential on prior acquisitions through workovers, recompletions,
secondary recovery operations, operating cost reductions, and the drilling of
development or infill wells. The Company believes that its primary strengths
are its ability to add reserves at attractive prices through property
acquisitions and subsequent exploitation, and its low cost operating
structure. These strengths have allowed the Company to substantially increase
reserves, production and cash flow during the last five years. As the Company
has grown its cash flow and added to its technical staff, exploration has
become a larger focus for its future growth. Planned exploration expenditures
for 1997 of approximately $43 million represent 37 percent of the Company's
capital budget, excluding acquisitions.

At September 30, 1996, the Company owned and operated producing properties
in 11 states, with its domestic proved reserves located primarily in four core
areas: the West Coast, Gulf Coast, East Texas and Mid-Continent areas of the
United States. During 1996, the Company expanded its Gulf Coast area through
the acquisitions of the Exxon Properties and the Conoco Properties. In
addition, the Company established a new core area in 1995 by acquiring 12 oil
concessions, 11 of which are producing and operated by the Company, in the
south flank of the San Jorge Basin in southern Argentina. The Company recently
expanded its South American operations into Bolivia through the acquisition of
Shamrock which owns and operates three blocks covering approximately 570,000
net acres in the Chaco Plains area of southern Bolivia. See "Recent
Acquisitions."

The Company owned interests in 3,053 gross (1,934 net) producing wells in
the United States as of September 30, 1996, of which approximately 81 percent
are operated by the Company. The Company owned interests in 610 gross (597
net) producing wells in Argentina as of September 30, 1996, of which
approximately 97 percent are operated by the Company. As of December 31, 1995,
the Company's properties had proved reserves of 199.7 MMBOE, comprised of
147.9 MMBbls of oil and 310.8 Bcf of gas, with a present value of estimated
future net revenues before income taxes (utilizing a 10 percent discount rate)
of $894 million and a standardized measure of discounted future net cash flows
of $737 million. Since that date, acquisitions have added 28.4 MMBOE of proved
reserves, as estimated by the Company as of the date of each acquisition.

The Company has consistently achieved growth in proved reserves, production
and revenues and has been profitable every full year since its founding in
1983. From the first quarter of 1993 through the third quarter of 1996, the
Company increased its average net daily production from 11,200 Bbls of oil to
32,900 Bbls of oil and from 60,000 Mcf of gas to 86,300 Mcf of gas. For the
year ended December 31, 1995, the Company generated revenues of $195 million
and EBITDA (as defined herein) of $88 million. For the nine months ended
September 30, 1996, the Company generated revenues of $223 million and EBITDA
of $111 million. (EBITDA as presented herein is generally defined as income
before cumulative effect of accounting change, provision for income taxes,
interest, depreciation, depletion, amortization and certain other non-cash
charges. EBITDA is included as a supplemental disclosure because it is
commonly accepted as providing useful information regarding a company's
ability to service and incur debt. EBITDA, however, should not be considered
in isolation or as a substitute for net income, cash flow provided by
operating activities or other income or cash flow data prepared in accordance
with generally accepted accounting principles or as a measure of a company's
profitability or liquidity.)

BUSINESS STRATEGY

The Company's overall goal is to maximize its value through profitable
growth in its oil and gas reserves and production. The Company has been
successful at achieving this goal through its ongoing

31
<PAGE>

strategy of (a) acquiring producing oil and gas properties, at favorable
prices, with significant exploitation potential, (b) focusing on low risk
exploitation and development activities to maximize production and ultimate
reserve recovery, (c) exploring non-producing properties, (d) maintaining a
low cost operating structure, and (e) maintaining financial flexibility. Key
elements of the Company's strategy include:

. Exploitation and Development. The Company pursues workovers,
recompletions, secondary recovery operations and other production
optimization techniques on its properties, as well as development and
infill drilling, to offset normal production declines and replace the
Company's annual production. From January 1, 1993, through December 31,
1995, the Company spent approximately $83.9 million on exploitation and
development activities. During this period, the Company's recompletion
and workover activities resulted in improved production or operating
efficiencies in approximately 75 percent of these operations, and the
result of all of its exploitation activities, including development and
infill drilling, succeeded in replacing more than 78 percent of
production during this period. The Company has an extensive inventory of
exploitation and development opportunities including identified projects
which represent approximately a ten year inventory at current activity
levels. The Company anticipates spending approximately $33 million in
the United States and approximately $40 million in Argentina during 1997
on exploitation and development projects.

. Low Cost Structure. The Company is an efficient operator and capitalizes
on its low cost structure in evaluating acquisition opportunities. The
Company generally achieves substantial reductions in labor and other
field level costs from those experienced by the previous operators. In
addition, the Company targets acquisition candidates which are located
in its core areas and provide opportunities for cost efficiencies
through consolidation with other Company operations. The lower cost
structure has generally allowed the Company to substantially improve the
cash flow of newly acquired properties.

. Financial Flexibility. The Company is committed to maintaining
substantial financial flexibility, which management believes is
important for the successful execution of its acquisition,

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<PAGE>

exploitation and exploration strategy. In conjunction with the purchase
of substantial oil and gas assets in 1990, 1992 and 1995, the Company
completed three public equity offerings, as well as a public debt
offering in 1995, which provided the Company with aggregate net proceeds
of approximately $272 million. Upon consummation of the Common Stock
Offering and the Note Offering and the application of the net proceeds
therefrom, and after giving effect to the related borrowing base
reduction, the unused portion of the Bank Facility as of January 30,
1997, would have been approximately $167.8 milllion ($106.4 million if
only the Common Stock Offering is consummated).

ACQUISITION ACTIVITIES

Historically, the Company has allocated a substantial portion of its capital
expenditures to the acquisition of producing oil and gas properties. The
Company's emphasis on property acquisitions reflects its belief that
continuing consolidation and restructuring activities on the part of major
integrated and large independent oil companies has in recent years and should
in the future afford attractive opportunities to purchase domestic and
international producing properties. The Company's ability to quickly evaluate
and complete acquisitions as well as its financial flexibility allow it to
take advantage of these opportunities as they materialize.

Since the Company's incorporation in May 1983, it has been actively engaged
in the acquisition of producing oil and gas properties primarily in the Gulf
Coast, East Texas and Mid-Continent areas of the United States, and in
California since April 1992. In 1995, a series of acquisitions made by the
Company established a new core area in the San Jorge Basin in southern
Argentina.

From January 1, 1993, through September 30, 1996, the Company made oil and
gas property acquisitions involving total costs of approximately $390 million.
As a result of these acquisitions, the Company acquired approximately 140.1
MMBOE of proved oil and gas reserves. The following table summarizes the
Company's acquisition experience during the periods indicated:

<TABLE>
<CAPTION>
PROVED RESERVES WHEN ACQUIRED ACQUISITION
----------------------------- COST PER
ACQUISITION OIL GAS BOE WHEN
COSTS (MBBLS) (MMCF) MBOE ACQUIRED
-------------- ----------------------------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
U.S. Acquisitions
1993.................... $123,906 27,898 68,000 39,231 $3.16
1994.................... 36,544 5,645 29,655 10,588 3.45
1995.................... 38,896 8,840 39,486 15,421 2.52
1996 (through September
30, 1996).............. 17,958 4,650 10,112 6,335 2.83
-------- --------- --------- ---------
Total U.S. Acquisi-
tions................ 217,304 47,033 147,253 71,575 3.04
-------- --------- --------- ---------
Argentina Acquisitions
1995.................... 168,762 65,653 -- 65,653 2.57
1996 (through September
30, 1996).............. 3,754 2,849 -- 2,849 1.32
-------- --------- --------- ---------
Total Argentina Acqui-
sitions.............. 172,516 68,502 -- 68,502 2.52
-------- --------- --------- ---------
Total U.S. and Argen-
tina Acquisitions.... $389,820 115,535 147,253 140,077 $2.78
======== ========= ========= =========
</TABLE>

The following is a brief discussion of significant acquisitions in recent
years:

1993 Acquisitions. In June 1993, the Company acquired the interest of Conoco
in certain oil and gas properties for approximately $38.1 million. The
properties, now operated by the Company, are located in the San Miguelito,
Rincon and Ventura fields in Ventura County, California. Proved reserves
totaled approximately 11.7 MMBbls of oil and 5.8 Bcf of gas at the time of
acquisition. Exploitation potential identified at the time of acquisition
included the adding of additional productive intervals in existing producing
wells, recompletion of inactive wells and expansion of an existing waterflood
operation to include an additional zone.

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<PAGE>

In November 1993, the Company acquired certain oil and gas properties from
Santa Fe and its affiliates for approximately $43.4 million. The properties
are located primarily in the Ventura Basin of California and the Gulf Coast
areas of Texas, Louisiana and Mississippi. Substantially all of the properties
acquired are now operated by the Company and are adjacent or in close
proximity to Company-operated fields or increased the Company's ownership in
its existing fields. Proved reserves totaled approximately 11.6 MMBbls of oil
and 22.4 Bcf of gas at the time of acquisition. The major fields acquired
included the Sespe, Rincon, Santa Fe Springs, San Miguelito and Ojai-
Silverthread fields in California and the Gwinville field in Mississippi.
Included in this acquisition was an additional interest in the properties
acquired from Conoco in June 1993. In addition to cost efficiencies resulting
from consolidation with other Company operations, exploitation potential
identified in the properties at the time of acquisition included adding
productive intervals and stimulations of existing producing wells,
recompletions of inactive wells and development drilling.

The Company spent a total of approximately $27.7 million in several other
transactions throughout 1993 to increase its ownership in Company-owned
properties located primarily in the Mid-Continent and California areas.
Purchases of additional interests in currently owned properties enable the
Company to increase reserves, production and cash flow with little or no
incremental administrative costs.

1994 Acquisitions. The Company acquired approximately 5.6 MMBbls of oil and
29.7 Bcf of gas through a series of small transactions in 1994 for a total of
approximately $36.5 million. The oil reserves are located primarily in the
Colgrade field in Louisiana and the Rincon field in Southern California. The
gas reserves are located primarily in California's Sacramento Basin,
Louisiana's Gulf Coast area and the Mid-Continent area in Oklahoma. The
Company has identified numerous exploitation opportunities in these
properties, including infill development drilling, adding productive intervals
in existing producing wells and recompleting inactive wells.

1995 Acquisitions. In May 1995, the Company purchased all of Texaco
Exploration and Production, Inc.'s interests in nine oil fields and seven gas
fields in California located primarily in Kern, Ventura, Los Angeles, Orange
and Santa Barbara Counties and the Sacramento Basin area for $26.7 million in
cash. Netherland, Sewell & Associates, Inc. ("Netherland, Sewell") estimated
that proved reserves attributable to these properties at the date of
acquisition were approximately 7.5 MMBbls of oil and 16.4 Bcf of gas. The
Company has identified numerous exploitation opportunities in these properties
including development drilling, recompletions, steam flood expansions as well
as lease operating expense efficiencies.

In the third quarter of 1995, the Company closed two acquisitions of related
properties located in the south flank of the San Jorge Basin in southern
Argentina, establishing a new core area for the Company. On July 5, 1995, the
Company purchased approximately 51.8 percent of the outstanding common stock
of Cadipsa for 302,808 shares of the Company's Common Stock (then valued at
$5.7 million) and $7.4 million in cash. Cadipsa's major assets include a 100
percent working interest in two concessions and a 50 percent working interest
in three additional concessions, all five of which are mature, producing and
operated by Cadipsa, covering approximately 322,000 gross acres. Cadipsa's net
daily production at the date of acquisition was approximately 3,700 Bbls of
mid-gravity oil from multiple zones at depths between 2,500 feet and 5,500
feet. The Company has subsequently purchased an additional 45.0 percent of
Cadipsa which increases its total ownership to approximately 96.8 percent.

On September 29, 1995, the Company purchased 100 percent of the outstanding
common stock of Vintage Argentina from British Gas plc, for $37 million in
cash. Vintage Argentina's major assets consist of a 50 percent working
interest in three of the producing concessions operated by Cadipsa.

In November 1995, the Company entered into separate agreements with Astra
Compania Argentina de Petroleo S.A. ("Astra") and Shell Compania Argentina de
Petroleo S.A. ("Shell") to acquire certain producing oil and gas properties in
Argentina (the "Astra/Shell Properties"). On November 30, 1995, the

34
<PAGE>

Company completed the purchase of the Astra portion of the Astra/Shell
Properties by paying $17.9 million in cash for Astra's 35 percent working
interest in the Astra/Shell Properties. On December 27, 1995, the Company
completed the purchase of the remaining 65 percent working interest from Shell
for $32.8 million cash and deferred payments valued at $5.1 million.

The acquisition of the Astra/Shell Properties resulted in the Company
acquiring 100 percent working interests in seven concessions, six of which are
currently producing and all of which are located on the south flank of the San
Jorge Basin in southern Argentina. The concessions cover approximately 450,000
acres and are located in close proximity to the Company's other Argentina
properties.

1996 Acquisitions. On January 31, 1996, the Company purchased interests in
two fields located in south-central Louisiana from Conoco Inc. for $13.9
million (the "Conoco Properties"). Funds were provided by advances under the
Bank Facility. The Conoco Properties included 26 gross (21 net) productive
wells with net daily production of approximately 1,000 Bbls of oil and 550 Mcf
of gas. All of the wells are now operated by the Company. The primary
producing sands include the Ortego A, Haas, Tate, Wilcox 1 through 6 and the
Middle and Basal Cockfield at depths ranging from 7,500 feet to 12,000 feet.
Planned exploitation activities include workovers, recompletions and
developmental drilling.

For additional 1996 acquisitions, see "Recent Acquisitions."

The Company intends to continue its growth strategy emphasizing reserve
additions through its acquisition efforts. The Company may utilize any one or
a combination of its line of credit with banks, institutional financing,
issuance of debt securities or additional equity securities and internally
generated cash flow to finance its acquisition efforts. No assurance can be
given that sufficient external funds will be available to fund the Company's
desired acquisitions.

The Company does not have a specific acquisition budget since the timing and
size of acquisitions are difficult to forecast. The Company is constantly
reviewing acquisition possibilities. The Company may expand into new domestic
core areas. The Company is also evaluating additional acquisition
opportunities in other countries which the Company believes are politically
stable. At the present time the Company has no binding agreements with respect
to any significant acquisitions.

EXPLOITATION AND DEVELOPMENT ACTIVITIES

The Company concentrates its acquisition efforts on proved producing
properties which demonstrate a potential for significant additional
development through workovers, behind-pipe recompletions, secondary recovery
operations, the drilling of development or infill wells, and other
exploitation techniques. The Company has pursued an active workover and
recompletion program on the properties it has acquired and intends to continue
its workover and recompletion program in the future.

The Company's exploitation staff focuses on maximizing the value of the
properties within its reserve base. The Company's exploitation engineers, who
strive to offset normal production declines and replace the Company's annual
production, have replaced more than 78 percent of its production during the
last three years. The results of their efforts are reflected in revisions to
reserves. Net revisions to reserves for 1995 totaled 13.2 MMBOE, or 104
percent of the Company's production of 12.7 MMBOE.

From January 1, 1993, through September 30, 1996, the Company spent
approximately $70.2 million on recompletion and workover operations. A measure
of the overall success of the Company's recompletion and workover operations
during this period (excluding minor equipment repair and replacement) has been
that improved production or operating efficiencies have been achieved from
approximately 77 percent of such operations. However, there can be no
assurance that such results will continue. The Company anticipates spending in
excess of $29 million on workover and recompletion operations during 1997. The
expenditures required for this program have historically been, and are
expected to continue to be, financed by internally generated funds.

35
<PAGE>

Development drilling activity is generated both through the Company's
exploration efforts and as a result of the Company's obtaining undeveloped
acreage in connection with producing property acquisitions. In addition, there
are many opportunities for infill drilling on Company leases currently
producing oil and gas. The Company intends to continue to pursue development
drilling opportunities which offer potentially significant returns to the
Company.

From January 1, 1993, through September 30, 1996, the Company participated
in the drilling of 122 gross (69.36 net) development wells, of which
approximately 90 percent gross (89 percent net) were productive. However,
there can be no assurance that this past rate of drilling success will
continue in the future. The Company is pursuing development drilling in the
West Coast, Gulf Coast, Mid-Continent and East Texas areas as well as its
Argentina concessions and anticipates continued growth in its drilling
activities. Additionally, the Company has numerous infill drilling locations
in several East Texas area fields, specifically South Gilmer (Cotton Valley
formation), Southern Pine (Travis Peak formation), Bethany Longstreet (Hosston
formation) and Rosewood (Cotton Valley formation) fields.

During 1995, the Company participated in the drilling of 41 gross (22.75
net) development wells. At December 31, 1995, the Company's proved reserves
included approximately 135 development or infill drilling locations on its
U.S. acreage and 181 locations on its Argentine acreage. In addition, the
Company has an extensive inventory of development and infill drilling
locations on its existing properties which are not included in proved
reserves. During the nine-month period ended September 30, 1996, the Company
participated in the drilling of 31 gross (24.26 net) development wells. The
Company spent approximately $22.2 million on development/infill drilling
during the first nine months of 1996. The Company expects to spend
approximately $45 million on development/infill drilling activities during
1997.

In connection with its exploitation focus, the Company actively pursues
operating cost reductions on the properties it acquires. The Company believes
that its cost structure and operating practices generally result in improved
operating economics. Although each situation is unique, the Company generally
has achieved reductions in labor and other field level costs from those
experienced by the previous operators, particularly in its acquisitions from
major oil companies.

The following is a brief discussion of significant developments in the
Company's recent exploitation and development activities:

West Coast Area. The San Miguelito/Rincon field area, acquired from Conoco,
Santa Fe Energy and Mobil, continues to be the primary focus of the Company's
West Coast exploitation efforts. Consolidation of the three acquisition areas
into a single operating unit has significantly reduced operating costs. At the
time of the initial acquisition in July 1993, the Company identified 18
exploitation projects; however, since that time, the Company has completed 90
projects. Exploitation efforts including artificial lift enhancements,
waterflood optimization, recompletions and sidetracking junked producers have
resulted in sustaining the average field production at levels comparable to
that of three years prior. As a result, the Company has been able to increase
proved reserves each year since the properties were acquired. Also during
1996, the Company initiated pilot waterflooding operations on the Fourth Grubb
producing interval. Based on this successful pilot injection test, full scale
waterflooding operations will be initiated during 1997. Ongoing reservoir
studies continue to identify significant upside to the Company's existing
inventory of exploitation projects.

Gulf Coast Area. In the Galveston Bay area of Texas, the Company performed
during 1996 12 workovers in the Red Fish Reef, Trinity Bay and Fishers Reef
fields which are 100 percent owned by the Company and which historically have
had good exploitation potential. This work consisted of recompletions and
repair jobs in the multi-pay Frio zones productive in the area which resulted
in a total gross production increase of 250 Bbls of oil per day and 4,200 Mcf
of gas per day. During 1996, the Company also performed recompletions and
workovers on seven wells in the Tepetate field, a 100 percent

36
<PAGE>

owned field acquired from Conoco in January 1996, which resulted in gross
production increases of 850 Bbls of oil per day and 400 Mcf of gas per day.
The Company also experienced a successful 1996 exploitation program in the
South Pass 24 field where three recompletions and one development well
resulted in increased gross daily production from the field of 140 Bbls of oil
and 4,370 Mcf of gas.

Mid-Continent Area. Water injection began in October 1993 in the Shawnee
Townsite Unit waterflood project and oil response began in November 1994.
Gross unit production has increased from a low of 250 barrels of oil per day
to a current rate of approximately 2,300 Bbls of oil per day. Oil rates are
forecasted to peak at approximately 3,500 Bbls of oil per day in 1997. An
engineering and geological study performed in 1996 has refined the reservoir
characterization and established the viability of drilling several infill
development wells within the unit boundary to recover oil that would otherwise
be undrained. In addition to the Shawnee waterflood, the Company is actively
pursuing four other secondary recovery projects located in the Texas
Panhandle. Each of these waterflood projects is targeting the Upper Morrow
sand at depths of approximately 8,000 feet. Three of these units have been
approved and water injection has been initiated. Installation of the final
unit, pending Texas Railroad Commission approval, is expected to commence in
the first quarter of 1997. Two analogous Upper Morrow fields producing in the
immediate area have already responded favorably to waterflood operations. The
Company owns working interests ranging from 82 percent to 100 percent in each
of the four projects. The Company anticipates additional proved reserves will
be added based on the level of success of these secondary recovery projects.

East Texas Area. Gas development projects remain the focus of the Company's
exploitation efforts in East Texas. In the South Gilmer field, Upshur County,
Texas, a Company engineering study performed in 1993 established the potential
viability of 10 infill drilling locations along with workover opportunities in
eight existing wells. This exploitation work was initiated in 1994 and
successful workovers were conducted on five wells. Seven of the infill
locations have now been drilled and completed. As a result of this work, gross
field production has increased to over 9,000 Mcf per day. The Company's
working interests in these wells range from 73 percent to 99 percent.

Argentina Concessions. Development and extensional drilling along with
development of secondary recovery projects have been the focus of the
Company's exploitation efforts in its Argentina properties. During 1996, the
Company continued the expansion of the Canadon Minerales Block 123A waterflood
by adding additional sands to the flood and completing additional patterns.
Water injection began in February 1992 and first oil response was seen
approximately 12 months later. Since the initiation of this project, gross
production has increased from 150 Bbls of oil per day to 1,300 Bbls of oil per
day. During 1996, the Company installed two new waterflood projects in areas
immediately adjacent to the Block 123A waterflood. There are two additional
areas in Canadon Minerales for which new waterflood projects are planned for
1997. Numerous other areas within the other concessions are being evaluated as
future waterflood candidates. Drilling activity commenced during February 1996
and reached its peak with three rigs running during the fourth quarter of
1996. Forty-one wells were drilled in 1996 and an additional 10 were in
process at year end 1996. The two main areas where this activity was
concentrated were Canadon Minerales with 25 wells drilled and Canadon Seco
with 12 wells drilled. Largely due to the results of this drilling activity,
gross production during 1996 increased from 3,500 Bbls of oil per day to 6,900
Bbls of oil per day in Canadon Minerales and from 1,300 Bbls of oil per day to
3,200 Bbls of oil per day in Canadon Seco. During 1996, the Company acquired
124 square kilometers (48 square miles) of 3-D seismic to aid in the optimum
placement of future drilling locations. This data was acquired in an attempt
to aid in the evaluation of the extremely complex stratigraphy that has
historically caused problems in geologic interpretation in this basin. The
first three wells that were drilled from the evaluation of the 3-D seismic
data have proven successful. If future wells verify these initial results, the
Company believes that substantial upside potential that has historically been
overlooked can be economically exploited.

EXPLORATION

The Company's exploration program is designed to contribute significantly to
its growth. Management divides the strategic objectives of its exploration
program into two parts. First, in the U.S.

37
<PAGE>

and in Argentina, the Company's exploration focus is in its core areas where
its geological and engineering expertise and experience are greatest. State-
of-the-art technology, including 3-D seismic, is employed to identify
prospects. Exploration in the U.S. and Argentina is designed to generate
reserve growth in the Company's core areas in combination with its
exploitation activities. The Company's longer-term plans are to increase the
magnitude of this program with a goal of achieving production replacement
through core area exploration. Such exploration is characterized by numerous
individual projects with medium to low risk. Secondly, international
exploration targets significant long-term reserve growth and value creation.
International exploration projects in Ecuador and Bolivia are characterized by
higher potential and higher risk. From January 1, 1993, through September 30,
1996, the Company spent $39.8 million on exploration activities. The Company
plans to spend approximately $43 million on exploration activities during
1997, approximately $31 million in the U.S. and Argentina and approximately
$12 million in other international areas.

The following is a brief discussion of the primary areas of exploration
activity for the Company:

United States.

Gulf Coast Area. In the Galveston Bay area of Texas, the Company has
---------------
acquired over 180 square miles of new 3-D seismic data and controls over
30,000 net acres in shallow state waters. The Company uses 3-D seismic data to
identify new exploration and extentional opportunities in new reservoirs as
well as in existing fields. The Company has identified several new prospects
in Galveston Bay. The Texas State Tract-75, an exploratory well which utilized
3-D seismic data, was drilled in the Umbrella Point area and was successfully
completed as a producer. One or more offset wells are planned to be drilled at
Umbrella Point in 1997. The Texas State Tract No. 2-3A well in the area of
Fishers Reef West is scheduled to spud during the second quarter of 1997. A
third exploratory prospect, White Heron, is also scheduled to spud during
second quarter of 1997. The Galveston Bay prospects, if successful, may
require multiple development wells to drain target reservoirs. Working
interests net to the Company range between 33 percent and 100 percent in
Galveston Bay. At the Company's Deweyville prospect, a new 10 square mile 3-D
seismic survey is being used to aid in the identification of an expanded Yegua
Trend on the Texas and Louisiana border. The Company has a 90 percent working
interest in this prospect and is in the process of acquiring additional
acreage.

Mid-Continent Area. The focus of the Company's Mid-Continent drilling
------------------
program continues to be the Anadarko and Ardmore Basins. In the Fort-X
prospect, four exploratory wells were drilled in 1996 utilizing 3-D seismic.
All four wells found sands targeted to be developed. Two were completed as
producers and are producing at 1,250 to 2,500 Mcf of gas per day. A fifth well
is currently drilling. With the information obtained from these four wells,
the Company has entered into two large 3-D seismic joint ventures in the
Anadarko Basin aimed at increasing its inventory of exploratory prospects,
drilling activity and reserves in selected multi-pay areas over the next
several years. The Wheeler project, in which the Company has a 25 percent
working interest, is a 150 square mile 3-D seismic survey in the Texas
Panhandle targeting the productive Granite Wash, Morrow, Hunton and Arbuckle
formations which are known to exist regionally. An exploratory well is planned
for the first half of 1997. The second project is a 500 square mile 3-D
seismic joint venture in which the Company has a 31.25 percent working
interest. Eight areas of interest have been selected for geologic imaging,
targeting the Granite Wash, Red Fork, Morrow, Springer, Hunton and Arbuckle
formations. In the Stagecoach evaluation area of southern Oklahoma, the
Company has initiated an extentional drilling program utilizing a new frac
technology aimed at developing a large 6,000 net acre lease block. Drilling of
the first well has begun with evaluation expected in early 1997. If
successful, the play could open up additional extentional projects in this gas
rich sub-basin. The Company's working interests in these prospects range
between 70 percent and 100 percent.

West Coast Area. Based on a discovery made by the Company in 1995, 3-D
---------------
seismic data is being used to generate additional prospects in the Buttes
Slough area of Northern California. Three to five wells

38
<PAGE>

are planned in the Grimes area during 1997. In the Zaca field located in Santa
Barbara County, an exploratory horizontal well is targeted to be drilled in
1997 to access potential reserves in new fault blocks. The Company owns a 100
percent working interest in this field and has eight additional exploratory
prospects.

International.

South America. The Company is currently pursuing several international
-------------
exploratory projects which, if successful, have the potential to increase the
growth of the Company. The Company believes that its existing projects in
Ecuador and Bolivia have the potential to significantly increase reserves. The
exploration play with the largest potential for reserve additions, as
estimated by the Company, is Block 19 in the Oriente Basin in Ecuador. The
Company has a 30 percent working interest in a project to explore Block 19.
Numerous commercially productive fields have been discovered in this basin.
Primary targets are the Hollin, Napo "U" and "T" sands which are productive in
other significant fields in this basin. Two wells are planned for 1997. In
Bolivia, geological studies are underway to confirm a prospect which has been
identified on the Company's recently acquired acreage. Pending the results of
these studies, the Company plans to drill a well during 1997 that would test
independent oil and gas concepts in this area. Additionally, the Company has
identified several exploratory leads on the 570,000 acres it controls which,
if successfully developed into prospects, could require several years to test.
The Company's working interest in the area is 100 percent. In Argentina, in
the Cerro Wenceslao concession in the western portion of the San Jorge Basin,
an exploratory project is currently underway to test an area structurally high
on an anticline feature to a prior well with oil shows. A similar structural
feature located in the northeast portion of the same concession produces from
numerous sands in the Bajo Barreal formation. This field is currently
producing at a rate of 1,520 Bbls of oil per day with a cumulative recovery to
date of 17 MMBbls of oil. The Company has a 100 percent working interest in
the Cerro Wenceslao concession.

OIL AND GAS PROPERTIES

At September 30, 1996, the Company owned and operated producing properties
in 11 states, with its U.S. proved reserves located primarily in four core
areas: the West Coast, Gulf Coast, East Texas and Mid-Continent areas. In
addition, during 1995 the Company established a new core area in the San Jorge
Basin of Argentina. As of September 30, 1996, the Company operated
approximately 3,076 productive wells and also owned non-operating interests in
587 productive wells. The Company continuously evaluates the profitability of
its oil, gas and related activities and has a policy of divesting itself of
unprofitable leases or areas of operations that are not consistent with its
operating philosophy.

39
<PAGE>

The following table summarizes the Company's proved reserves in its 30
largest fields in the U.S. and its five largest concessions in Argentina at
December 31, 1995, as estimated by Netherland, Sewell. These fields and
concessions represent approximately 80 percent of the Company's proved
reserves on such date.

<TABLE>
<CAPTION>
LOCATION (COUNTY NET NET
OR PARISH, STATE OIL GAS
AREA FIELD/CONCESSION NAME OR PROVINCE) (MBBLS) (MMCF) MBOE
---- ----------------------------- ------------------- ------- ------ ------
<S> <C> <C> <C> <C> <C>
West Coast.............. San Miguelito Ventura, CA 15,432 3,491 16,013
South Mountain Ventura, CA 5,498 6,975 6,660
Rincon Ventura, CA 4,371 4,094 5,053
Ojai-Silverthread Ventura, CA 2,961 12,230 5,000
North Tejon Kern, CA 1,746 9,540 3,336
Santa Maria Valley/Cat Canyon Santa Barbara, CA 3,294 0 3,294
Pleito Ranch Kern, CA 2,905 692 3,021
Canfield Ranch Kern, CA 2,700 508 2,784
Sespe Ventura, CA 2,311 1,915 2,630
Buena Vista Hills Kern, CA 2,065 3,348 2,623
Lathrop San Joaquin, CA 0 12,135 2,022
Antelope Hills Kern, CA 1,797 0 1,797
Zaca Santa Barbara, CA 1,693 0 1,693
Wheeler Ridge Kern, CA 1,235 2,497 1,651
Tejon Kern, CA 1,618 181 1,649
Landslide Kern, CA 1,251 182 1,282
Timber Canyon Ventura, CA 769 2,410 1,171
Gulf Coast.............. Waveland Hancock, MS 323 14,930 2,811
South Pass 24 Plaquemines, LA 1,200 3,142 1,724
Little Lake/Temple Jefferson, LA 1,190 2,740 1,647
Panther Reef Calhoun, TX 298 6,122 1,319
Trinity Bay Chambers, TX 1,114 804 1,248
Vacherie St. James, LA 39 7,016 1,209
East Texas.............. South Gilmer Upshur, TX 523 31,088 5,704
Southern Pine Cherokee, TX 0 25,128 4,188
Fruitvale Van Zandt, TX 0 23,384 3,897
Colgrade Winn, LA 3,393 0 3,393
Mid-Continent........... Shawnee Pottawatomie, OK 2,820 230 2,858
Booker Ochiltree, TX 1,848 171 1,877
Strong City Roger Mills, OK 59 9,867 1,703
San Jorge Basin,
Argentina.............. Canadon Minerales Santa Cruz Province 18,768 0 18,768
Las Heras/Piedra Clavada Santa Cruz Province 14,958 0 14,958
Canadon Seco Santa Cruz Province 11,103 0 11,103
Cerro Wenceslao Santa Cruz Province 9,477 0 9,477
Meseta Espinosa Santa Cruz Province 7,749 0 7,749
</TABLE>

West Coast Area. The Company expanded its operations to the West Coast in
1992 through two separate acquisitions of properties located in Kern, Ventura,
and Santa Barbara Counties in California. Since 1992, the Company has
continued to expand its operations in the West Coast area through additional
property acquisitions. As of December 31, 1995, the area comprised 35 percent
of the Company's total proved reserves and 54 percent of the Company's U.S.
proved reserves. The Company currently operates 1,158 productive wells with
daily gross production of approximately 11,700 Bbls of mid-gravity oil, 2,600
Bbls of heavy oil and 30,300 Mcf of gas. In addition, the Company owns an
interest in 72 productive wells operated by others.

San Miguelito. The San Miguelito field is located in the west central
-------------
portion of the greater Ventura Avenue field just north of the City of Ventura,
California. Production is from multiple pay intervals in Pliocene-age sands
which span 7,000 vertical feet. Well depths generally range from 7,000 feet to
just over 16,000 feet in the deepest wells. Currently, active waterflood
operations are underway in three of the producing zones. With the field still
producing in excess of 3,400 gross Bbls of oil per day, the Company believes
additional waterflood potential exists in lower sands currently producing on
primary

40
<PAGE>

depletion. The Company operates this single lease property with a 100 percent
working and 87.5 percent net revenue interest. For additional information
regarding this field, see "--Exploitation and Development Activities--West
Coast Area."

South Mountain. The South Mountain field, located just south of Santa
--------------
Paula, California, has become one of the Company's major producing areas. As a
result of the acquisition of the Texaco Properties, which included certain
properties in this field, the Company now operates 226 active wells in the
South Mountain field. Gross daily production of 1,150 Bbls of oil and 2,000
Mcf of gas comes from Eocene and Pliocene sand intervals at depths of 3,000
feet to 10,000 feet. The solution gas and gravity drainage producing
mechanisms are responsible for low decline rates which result in long-life
reserves. In addition to the producing wells, the Company also operates the
South Mountain Gas Gathering System which transports approximately 3,500 Mcf
per day of Company and third party gas. The Company's working interests in the
South Mountain field range from 50 percent to 100 percent with net revenue
interests from 42 percent to 100 percent; however, the properties are
predominantly owned 100 percent.

Rincon. The Rincon field is located on the western updip end of the greater
------
Ventura Avenue field just north of the City of Ventura, California, and
adjacent to the Company's San Miguelito field properties. Like the San
Miguelito field, production is from multiple pay intervals of Pliocene-age
sands. These intervals span several thousand feet with three waterfloods
currently in operation. Producing intervals range in depth from approximately
3,500 feet to 14,000 feet. The Company operates this field with a 100 percent
working and 80 percent net revenue interest. Current daily gross production
from this field is approximately 1,030 Bbls of oil and 1,100 Mcf of gas.
During 1996, the Company was able to increase total field production through
development of uphole producing intervals and re-vitalization of existing
waterfloods. The Company believes that significant upside reserve potential
remains in the development of these shallow producing horizons as well as
workover and stimulation activity in the presently producing intervals. For
additional information regarding this field, see "--Exploitation and
Development Activities--West Coast Area."

Ojai-Silverthread and Timber Canyon. The Ojai field, which extends to the
-----------------------------------
Silverthread and Timber Canyon areas, is located in the western central
portion of Ventura County, California. All production in this area is from the
fractured Monterey Shale formation which is encountered at depths ranging from
2,000 feet to 6,000 feet. The Company operates 118 productive wells in this
field with a 100 percent working interest and net revenue interests ranging
from 83 percent to 100 percent. The properties are mature, characterized by
pressure depletion and gravity drainage, with highly predictable production
decline rates. Combined daily gross production exceeds 800 Bbls of oil and
3,500 Mcf of gas.

North Tejon. The North Tejon field is located near the southern end of the
-----------
San Joaquin Basin. This field is divided into a series of fault blocks with
productive reservoirs in the lower Miocene, Oligocene, Zemorrian and Eocene
sands. These producing zones range in depth from 5,400 feet to 11,300 feet.
All productive wells are operated by the Company with a 100 percent working
and net revenue interest. Gross production rates average in excess of 200 Bbls
of oil per day and 2,200 Mcf of gas per day. The Company believes that future
projects in this field may increase production and reserves.

Santa Maria Valley/Cat Canyon. The Company operates these two heavy (low
-----------------------------
gravity) oil fields near Santa Maria, California. At the end of 1992, the
Company built and commenced operation of two non-conventional fuel facilities.
Those facilities are located in the Santa Maria Valley and Cat Canyon fields
and now produce oil from tar sands. Since December 1992, the Company has
produced over 800 MBbls of tar sand oil through these facilities. In addition,
the Company operates one waterflood. Total produced volume from the fields is
in excess of 1,400 gross Bbls of oil per day. The Company's working interests
in the fields are 100 percent with net revenue interests ranging from 74.5
percent to 100 percent.

Pleito Ranch. The Pleito Ranch field is located on the southern end of the
------------
San Joaquin Basin. Production is from Miocene-age Chanac and Santa Margarita
sands below the Wheeler Ridge thrust fault.

41
<PAGE>

Well depths range from 11,000 feet to 14,000 feet. All productive wells are
operated by the Company with a 100 percent working and net revenue interest.
The recovery mechanism is predominantly gravity drainage and is characterized
by low decline, long-life reserves with gross production of approximately 600
Bbls of oil per day.

Gulf Coast Area. The Gulf Coast Area comprised approximately 12 percent of
the Company's December 31, 1995, total proved reserves. Production in this
area is predominantly from structural accumulations in reservoirs of Miocene
Age. The depths of the producing reservoirs in this area range from 1,200 feet
to 14,500 feet. The Company currently operates 232 productive wells and owns
interests in an additional 166 productive wells in this area. Daily gross
production from the operated wells averages 7,600 Bbls of oil and 52,400 Mcf
of gas. Additional development potential exists in this area from
recompletions in existing wellbores particularly in the South Pass 24 (70
percent working interest), Red Fish Reef (100 percent working interest), and
Panther Reef (96 percent average working interest) fields.

Waveland. The Company's largest field in the Gulf Coast Area is the
--------
Waveland field. The Waveland field is located in Hancock County, Mississippi,
and produces from the Washita-Fredricksburg, Paluxy and Mooringsport
formations at depths ranging from 11,800 feet to 13,340 feet. The Company
currently operates gross daily production of 3,250 Mcf of gas. This field
contains a significant amount of reserves that are behind-pipe in existing
well bores. The Company intends to further develop this field through a series
of workovers and recompletions with two to four such projects scheduled for
1997.

South Pass 24. The South Pass 24 field is located in state waters of
-------------
Plaquemines Parish, Louisiana, at shallow water depths averaging 10 to 20
feet. The 33 productive oil wells and seven productive gas wells in this field
are operated by the Company and one other operator. The South Pass 24 field
produces hydrocarbons from various members of the Miocene sand series at an
average depth of approximately 7,000 feet. Future value enhancements in this
field are expected to come from exploitation opportunities.

East Texas Area. The East Texas Area comprised approximately 11 percent of
the Company's December 31, 1995, total proved reserves. The Cotton Valley,
Smackover and Travis Peak formations are the dominant producing reservoirs on
the Company's acreage in this area. The Company currently operates daily gross
production of 1,150 Bbls of oil and 30,500 Mcf of gas from 594 operated
productive wells in this area. The Company owns an interest in an additional
71 productive wells in this area. Significant infill drilling potential exists
on the Company's acreage in the South Gilmer, Colgrade, Southern Pine,
Rosewood, Bethany Longstreet and Bear Grass fields. The Company plans to
continue infill drilling programs in Southern Pine, Colgrade and South Gilmer
fields. During 1996, these infill drilling programs have resulted in the
addition of five wells, all of which were successful. For additional
information regarding these producing operations, see "--Exploitation and
Development Activities--East Texas Area."

South Gilmer. The South Gilmer field, the Company's largest field in the
------------
East Texas area, is located in Upshur County and produces from the Cotton
Valley Lime formation at average depths of 11,300 feet to 11,800 feet. The
Company currently operates 18 productive wells and owns interests in three
additional productive wells in this field. A workover program implemented in
1994 increased production substantially in five wells. The Company began the
drilling of an infill well in December 1994, with two additional wells drilled
in 1995 and four wells in 1996. All seven wells resulted in successful
completions. Significant behind-pipe reserves are booked for the Company's
6,727 gross acres in the Cotton Valley sand formation.

Southern Pine. The Southern Pine field is located in Cherokee County,
-------------
Texas, and produces from the Travis Peak formation with gross daily production
of 7,900 Mcf of gas. The Company currently operates 26 productive wells in
this field. The Company completed the drilling of eight development wells in
1995. These wells, combined with the ten wells acquired from Herd Producing
Company in March 1995, increased gross daily production from 1,200 Mcf of gas
to a peak rate of 10,000 Mcf of gas. The installations of plunger lift and
central compression during 1996 have helped maintain the current gross daily
production of 7,900 Mcf of gas.

42
<PAGE>

Mid-Continent Area. The Mid-Continent Area extends from the Arkoma Basin of
Eastern Oklahoma to the Texas Panhandle and north to include Kansas. This area
comprises seven percent of the Company's total proved reserves as of December
31, 1995. The Company currently operates daily gross production of 3,500 Bbls
of oil and 29,500 Mcf of gas from 373 operated productive wells in this area.
The Company owns an interest in an additional 249 productive wells in this
area.

The Company's largest field in the Mid-Continent Area is the Shawnee
Townsite field, which the Company operates. On March 1, 1993, a unit was
formed for secondary recovery operations with water injection initiated in
October 1993. For additional information regarding this field, see "--
Exploitation and Development Activities--Mid-Continent Area."

Argentina Concessions. The Argentina properties consist primarily of 12
mature producing concessions located on the south flank of the San Jorge
Basin. These concessions comprised approximately 34 percent of the Company's
December 31, 1995, total proved reserves. The Company currently operates 600
productive wells (100 percent working interest) with daily gross production of
16,200 Bbls of oil. In addition, the Company owns an interest in 17 productive
wells operated by others. At December 31, 1995, the Company's proved reserves
included approximately 181 development or infill drilling locations and 253
workovers on its Argentina acreage. In addition, the Company has an extensive
inventory of workovers and development or infill drilling locations on its
Argentina properties which are not included in proved reserves.

Canadon Minerales. The primary oil producing reservoirs of the Canadon
-----------------
Minerales oil concession are the Mina del Carmen and Canadon Seco formations
which are both fluvial channel sand bodies at depths ranging from 3,000 feet
to 4,000 feet. This concession currently has 169 producing wells and 31 water
injection wells with daily gross production of approximately 6,850 Bbls of
oil. Approximately 20 percent of the concession's daily production is produced
from the Block 123A waterflood, which contains 22 producing wells and 17 water
injection wells. The Block 123A waterflood was expanded during 1996 to include
additional sands. Also during 1996, two additional waterflood projects were
initiated in areas adjacent to Block 123A. At this time there are two
additional waterflood projects scheduled for development.

Future development plans at Canadon Minerales include numerous workovers and
development drilling locations. Many of the workovers are expected to return
idle wells back to production by perforating zones not produced by the former
owner. Log cross sections reveal many zones which do not appear to have been
previously tested.

The proved undeveloped locations are generally infill development locations
in areas offsetting existing production. Well depths vary from 3,000 to 6,000
feet. The first well was drilled in the first quarter of 1996 and 25 wells
were drilled on this concession during 1996. See "--Exploitation and
Development Activities--Argentina Concessions."

Las Heras/Piedra Clavada. The primary oil producing reservoirs of the Las
------------------------
Heras/Piedra Clavada oil concession are the Castillo and Bajo Barreal
formations which are both fluvial channel sand bodies with good to moderate
sand quality at depths ranging from 3,500 feet to 7,000 feet. Currently, there
are 82 producing wells and three water injection wells with daily gross
production of approximately 1,160 Bbls of oil. There is one active waterflood
in Block 24, which contains 13 producing wells and five water injection wells.
In addition to the activities in Block 24, there are three other waterflood
projects scheduled for development at Las Heras/Piedra Clavada.

Future development plans at Las Heras/Piedra Clavada include numerous
workovers and development drilling locations. Many of these workovers are
expected to return idle wells back to production by perforating additional
zones. Cross sections reveal many zones which do not appear to have been
tested. The proved undeveloped locations are generally infill development
locations in areas offsetting existing production.

43
<PAGE>

Canadon Seco. The primary oil producing reservoirs of the Canadon Seco oil
------------
concession are the Canadon Seco and Mina del Carmen which are fluvial channel
sand bodies at depths ranging from 4,000 feet to 7,000 feet. This field
currently has 74 producing wells and eight water injection wells with a daily
gross production of approximately 3,200 Bbls of oil.

There are three active waterfloods at Canadon Seco which contain a total of
10 producing wells and eight water injection wells. The Block VIIIAo
waterflood has additional drilling and water injection conversions scheduled
for additional development of the concession.

Additional development plans at Canadon Seco include numerous workovers and
development drilling locations. Many of the workovers are expected to return
idle wells back to production by perforating additional zones. See "--
Exploitation and Development Activities--Argentina Concessions."

Cerro Wenceslao. The primary oil producing reservoir of the Cerro Wenceslao
---------------
oil concession is the Bajo Barreal which contains sands at depths ranging from
1,000 feet to 3,000 feet. Currently, there are 122 producing oil wells and 10
water injection wells with daily gross production of approximately 1,520 Bbls
of oil.

Future development plans at Cerro Wenceslao include workovers, fracture
stimulations, and development drilling on several drilling locations. In
addition, the Company plans to further develop the significant waterflood
potential in Block 2, Block 5 and the East Flank Block.

Meseta Espinosa. The primary oil producing reservoirs of the Meseta
---------------
Espinosa oil concession are the Canadon Seco and Mina del Carmen which are
fluvial channel sand bodies with good to moderate sand quality at depths
ranging from 4,000 feet to 7,000 feet. This concession currently has 101
producing wells and 10 water injection wells with a daily gross production of
approximately 2,250 Bbls of oil.

There are seven active waterfloods at Meseta Espinosa which contain a total
of 17 producing wells and 10 water injection wells. One new proven waterflood
project was installed during 1996. It will be followed by the implementation
of a second new proven waterflood project. Additional development plans at
Meseta Espinosa include several workovers and the drilling of development
wells.

MARKETING

The Company's gas production and gathered gas are sold primarily on the spot
market or under market-sensitive, long-term agreements with a variety of
purchasers, including intrastate and interstate pipelines, their marketing
affiliates, independent marketing companies and other purchasers who have the
ability to move the gas under firm transportation agreements. Because an
insignificant amount of the Company's gas is committed to long-term fixed-
price contracts, the Company is positioned to take advantage of rising prices
for gas but it is also subject to gas price declines.

In order to more efficiently handle spot market transactions, the Company's
gas marketing activities are handled by Vintage Gas, Inc., its wholly owned
gas marketing affiliate, which commenced operation on May 1, 1991. This
marketing affiliate purchases gas on the spot market from the Company and
third parties. Generally, the marketing affiliate purchases this gas on a
month-to-month basis at a percentage of resale prices.

Generally, the Company's domestic oil production is sold under short-term
contracts at posted prices plus a premium in some cases. The Company's
Argentina oil production is currently sold at port to ESSO SAPA and Petrobras
at West Texas Intermediate spot prices less a specified differential.

The most significant purchaser of the Company's oil during 1995 was Texaco
Trading and Transportation, Inc. Such oil purchases amounted to approximately
17 percent of the Company's total revenues for 1995. No other purchaser of the
Company's oil or gas during 1995 exceeded 10 percent of the Company's total
revenues.

44
<PAGE>

The Company has previously engaged in oil and gas hedging activities and
intends to continue to consider various hedging arrangements to realize
commodity prices which it considers favorable. Three hedges (swap agreements)
are currently in place for a total of 7,500 Bbls of oil per day at a weighted
average price of $19.26 per Bbl (NYMEX reference price) for the period January
1997 through December 1997.

GATHERING SYSTEMS

The Company owns 100 percent interests in two oil and gas gathering systems
located in Pottawatomie County, Oklahoma and Harris and Chambers Counties,
Texas. In addition, the Company owns 100 percent interests in 22 gas gathering
systems located in active producing areas of California, Kansas, Texas and
Oklahoma. All of these gathering systems are operated by the Company.
Together, these systems comprise approximately 300 miles of varying diameter
pipe with a combined capacity in excess of 175 MMcf of gas per day. At
September 30, 1996, there were 432 wells (most of which are operated by the
Company) connected to these systems. Generally, the gathering systems buy gas
at the wellhead on the basis of a percentage of the resale price under
contracts containing terms of one to 10 years.

RESERVES

At December 31, 1995, the Company had proved reserves, as estimated by
Netherland, Sewell, of 199.7 MMBOE, comprised of 147.9 MMBbls of oil and 310.8
Bcf of gas. The following table sets forth, at December 31, 1995, the present
value of future net revenues (revenues less production and development costs)
before income taxes attributable to the Company's proved reserves at such date
(in thousands):

<TABLE>
<S> <C>
Proved Reserves:
Future net revenues............................................ $1,470,350
Present value of future net revenues before income taxes, dis-
counted at 10 percent......................................... 894,249
Standardized measure of discounted future net cash flows....... 736,546
Proved Developed Reserves:
Future net revenues............................................ 1,032,798
Present value of future net revenues before income taxes, dis-
counted at 10 percent......................................... 675,318
</TABLE>

In computing this data, assumptions and estimates have been utilized, and
the Company cautions against viewing this information as a forecast of future
economic conditions. The historical future net revenues are determined by
using estimated quantities of proved reserves and the periods in which they
are expected to be developed and produced based on December 31, 1995, economic
conditions. The estimated future production is priced at prices prevailing at
December 31, 1995, except where fixed and determinable price escalations are
provided by contract. The resulting estimated future gross revenues are
reduced by estimated future costs to develop and produce the proved reserves,
based on December 31, 1995, cost levels, but such costs do not include debt
service, general and administrative expenses and income taxes. For additional
information concerning the historical discounted future net revenues to be
derived from these reserves and the disclosure of the Standardized Measure
information in accordance with the provisions of Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities," see Note 9 "Supplementary Financial Information for Oil and Gas
Producing Activities" to the Company's consolidated financial statements
included elsewhere in this Prospectus.

45
<PAGE>

The following table sets forth estimates of the proved oil and gas reserves
of the Company at December 31, 1995, as evaluated by Netherland, Sewell:

<TABLE>
<CAPTION>
OIL (MBBLS) GAS (MMCF) MBOE
----------------------------- ----------------------------- -------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL TOTAL
--------- ----------- ------- --------- ----------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
West Coast(a)........... 45,947 10,204 56,151 79,514 7,388 86,902 70,635
Gulf Coast.............. 9,159 1,936 11,095 73,772 7,777 81,549 24,687
East Texas.............. 3,723 1,167 4,890 75,934 23,483 99,417 21,459
Mid-Continent........... 4,619 2,854 7,473 41,180 1,687 42,867 14,618
Other U.S............... 343 275 618 27 -- 27 622
------- ------ ------- ------- ------ ------- -------
Total U.S............. 63,791 16,436 80,227 270,427 40,335 310,762 132,021
Argentina............... 36,928 30,716 67,644 -- -- -- 67,644
------- ------ ------- ------- ------ ------- -------
Total Company(b)...... 100,719 47,152 147,871 270,427 40,335 310,762 199,665
======= ====== ======= ======= ====== ======= =======
</TABLE>
- --------
(a) Total proved oil reserves include 5.1 MMBbls of heavy oil located in the
Company's Santa Maria Valley/Cat Canyon and Antelope Hills fields in
California.
(b) Does not include acquisitions since December 31, 1995. See "Recent
Acquisitions."

Estimates of the Company's 1995 proved reserves set forth above have not
been filed with, or included in reports to, any Federal authority or agency,
other than the Securities and Exchange Commission.

The Company's non-producing proved reserves are largely behind-pipe in
fields which it operates. Undeveloped proved reserves are predominantly infill
drilling locations and secondary recovery projects. Approximately 67 percent
of the U.S. proved reserves associated with infill drilling locations are
located in the Company's 30 largest U.S. fields.

The reserve data set forth in this Prospectus or incorporated by reference
herein represent only estimates. Reserve engineering is a subjective process
of estimating underground accumulations of oil and gas that cannot be measured
in an exact manner. The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. As a result, estimates of different engineers often vary. In
addition, results of drilling, testing and production subsequent to the date
of an estimate may justify revision of such estimate. Accordingly, reserve
estimates often differ from the quantities of oil and gas that are ultimately
recovered. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based.

For further information on reserves, costs relating to oil and gas
activities and results of operations from producing activities, see Note 9
"Supplementary Financial Information for Oil and Gas Producing Activities" to
the Company's consolidated financial statements included elsewhere in this
Prospectus.

PRODUCTIVE WELLS; DEVELOPED ACREAGE

The following table sets forth the Company's domestic and Argentina
productive wells and developed acreage assignable to such wells at September
30, 1996:

<TABLE>
<CAPTION>
PRODUCTIVE WELLS
---------------------------------
DEVELOPED ACREAGE OIL GAS TOTAL
------------------- ----------- --------- -----------
GROSS NET GROSS NET GROSS NET GROSS NET
--------- --------- ----- ----- ----- --- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
U.S....................... 585,106 309,322 2,108 1,583 945 358 3,053 1,941
Argentina................. 1,008,339 844,372 610 597 -- -- 610 597
--------- --------- ----- ----- --- --- ----- -----
Total................... 1,593,445 1,153,694 2,718 2,180 945 358 3,663 2,538
========= ========= ===== ===== === === ===== =====
</TABLE>

46
<PAGE>

Productive wells consist of producing wells and wells capable of production,
including gas wells awaiting pipeline connections to commence deliveries and
oil wells awaiting connection to production facilities. Wells which are
completed in more than one producing horizon are counted as one well. Of the
gross wells reported above, two had multiple completions.

PRODUCTION; UNIT PRICES; COSTS

The following table sets forth information with respect to production and
average unit prices and costs for the periods indicated:

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEARS ENDED DECEMBER 31,
-------------------- --------------------------
1996 1995 1995 1994 1993
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Production:
Oil (MBbls)--
U.S......................... 5,683 4,933 6,647 6,657 4,785
Argentina................... 2,966 377 961 -- --
Total....................... 8,649 5,310 7,608 6,657 4,785
Gas, all U.S. (MMcf).......... 24,535 22,489 30,610 28,884 22,504
Average sales prices:
Oil (per Bbl)--
U.S. ....................... $ 17.08(a) $ 15.42 $ 15.44 $ 13.53 $ 14.14
Argentina................... 15.87(a) 14.20 13.98 -- --
Total....................... 16.66(a) 15.33 15.26 13.53 14.14
Gas, all U.S. (per Mcf)....... 1.70 1.42 1.46 1.78 2.03
Production costs (per BOE):
U.S........................... 5.38 5.27 5.24 5.17 5.26
Argentina..................... 5.07 4.62 5.42 -- --
Total......................... 5.31 5.25 5.25 5.17 5.26
</TABLE>
- --------
(a) The impact of oil hedges reduced the Company's 1996 U.S., Argentina and
total average oil prices per Bbl by $0.79, $1.89 and $1.17, respectively.

The components of production costs may vary substantially among wells
depending on the methods of recovery employed and other factors, but generally
include production taxes, maintenance and repairs, labor and utilities.

47
<PAGE>

UNDEVELOPED ACREAGE

At September 30, 1996, the Company held the following undeveloped acres
located in the United States and Ecuador. With respect to such United States
acreage held under leases, 101,132 gross (38,363 net) acres are held under
leases with primary terms that expire at varying dates through December 31,
2000, unless commercial production is commenced. The following table sets
forth the location of the Company's undeveloped acreage and the number of
gross and net acres in each. Although substantial undeveloped acreage exists
in the Company's concessions in Argentina, the concessions in their entirety
are held by production.

<TABLE>
<CAPTION>
STATE/COUNTRY GROSS ACRES NET ACRES
------------- ----------- ---------
<S> <C> <C>
California............................................. 6,698 5,910
Colorado............................................... 2,720 972
Kansas................................................. 1,420 1,420
Louisiana.............................................. 1,182 430
Mississippi............................................ 204 65
Montana................................................ 12,382 6,250
New Mexico............................................. 11,469 1,656
Oklahoma............................................... 13,978 8,510
Texas.................................................. 52,826 14,097
------- -------
Total U.S............................................ 102,879 39,310
Ecuador................................................ 494,226 148,268
------- -------
Total Company........................................ 597,105 187,578
======= =======
</TABLE>

DRILLING ACTIVITY

During the periods indicated, the Company drilled or participated in the
drilling of the following exploratory and development wells:

<TABLE>
<CAPTION>
NINE MONTHS ENDED YEARS ENDED DECEMBER 31,
SEPTEMBER 30, -----------------------------------
1996 1995 1994 1993
------------------ ----------- ----------- -----------
GROSS NET GROSS NET GROSS NET GROSS NET
------------------ ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Development:
United States--
Productive........... 11 5.69 36 19.26 31 18.75 16 2.12
Non-Productive....... 3 1.57 5 3.49 2 1.04 1 0.44
Argentina--
Productive........... 16 16.00 -- -- -- -- -- --
Non-Productive....... 1 1.00 -- -- -- -- -- --
------- --------- --- ----- --- ----- --- -----
Total.............. 31 24.26 41 22.75 33 19.79 17 2.56
======= ========= === ===== === ===== === =====
Exploratory:
United States--
Productive........... 4 2.25 13 9.84 12 2.82 21 2.01
Non-Productive....... 3 1.50 5 2.69 5 4.04 10 5.70
Argentina--
Productive........... 2 2.00 -- -- -- -- -- --
Non-Productive....... -- -- -- -- -- -- -- --
------- --------- --- ----- --- ----- --- -----
Total.............. 9 5.75 18 12.33 17 6.86 31 7.71
======= ========= === ===== === ===== === =====
Total:
Productive........... 33 25.94 49 29.10 43 21.58 37 4.13
Non-Productive....... 7 4.07 10 6.18 7 5.07 11 6.14
------- --------- --- ----- --- ----- --- -----
Total.............. 40 30.01 59 35.28 50 26.65 48 10.27
======= ========= === ===== === ===== === =====
</TABLE>

The above well information excludes wells in which the Company has only a
royalty interest.

48
<PAGE>

At September 30, 1996, the Company was a participant in the drilling or
completion of 18 gross (13.59 net) wells. All of the Company's drilling
activities are conducted with independent contractors. The Company owns no
drilling equipment.

LEGAL PROCEEDINGS

On November 5, 1996, the Province of Santa Cruz, Argentina brought suit
against Cadipsa in the Corte Suprema de Justicia de la Nacion (the Supreme
Court of Justice of the Argentine Republic, Buenos Aires, Argentina), Dossier
No. s-1451, seeking to recover approximately $10.6 million (which sum includes
interest) allegedly due as additional royalties on four concessions granted in
1990 in which the Company currently owns a 100 percent working interest. The
Company and its predecessors in title have been paying royalties at an eight
percent rate; the Province of Santa Cruz claims the rate should be 12 percent.
The amount of such claim will increase at the differential of these royalty
rates until this claim is resolved. With respect to the 50 percent interest in
the two concessions that the Company acquired from British Gas, plc, the
Company believes that it is entitled to indemnification by British Gas, plc
for any loss sustained by the Company as a result of this claim. Such
indemnification equals approximately $4.0 million of the $10.6 million claim.
The Company has no indemnification from its predecessors in title with respect
to the payment of royalties on the other two concessions. Although the Company
cannot predict the outcome of this litigation, based upon the advice of
counsel, the Company does not expect this claim to have a material adverse
impact on the Company's financial position or results of operations.

The Company is also a named defendant in other lawsuits and is a party in
governmental proceedings from time to time arising in the ordinary course of
business. While the outcome of such other lawsuits or proceedings against the
Company cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the Company's financial position
or results of operations.

49
<PAGE>

MANAGEMENT

The following table sets forth certain information regarding the directors
and executive officers of the Company. Officers are elected annually by the
Board of Directors and serve at its discretion.

<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Charles C. Stephenson,
Jr. ................... 60 Director and Chairman of the Board of Directors
Jo Bob Hille............ 55 Director, Vice Chairman of the Board of Directors
and Chief Executive Officer
S. Craig George......... 44 Director, President and Chief Operating Officer
William C. Barnes....... 42 Director, Executive Vice President, Chief Financial
Officer, Secretary and Treasurer
William L. Abernathy.... 45 Senior Vice President--Acquisitions
Robert W. Cox........... 51 Vice President--General Counsel
William E. Dozier....... 44 Vice President--Operations
Michael F. Meimerstorf.. 40 Vice President and Controller
Robert E. Phaneuf....... 50 Vice President--Corporate Development
Barry D. Quackenbush.... 54 Vice President--Production
Larry W. Sheppard....... 42 Vice President--International
Bryan H. Lawrence....... 54 Director
John T. McNabb, II...... 52 Director
</TABLE>

Mr. Stephenson, a co-founder of the Company, has been a Director since June
1983 and Chairman of the Board of Directors of the Company since April 1987.
He was also Chief Executive Officer of the Company from April 1987 to March
1994 and President of the Company from June 1983 to May 1990. From October
1974 to March 1983, he was President of Santa Fe-Andover Oil Company (formerly
Andover Oil Company), an independent oil and gas company ("Andover"), and from
January 1973 to October 1974, he was Vice President of Andover. Mr. Stephenson
has a B.S. Degree in Petroleum Engineering from the University of Oklahoma,
and has approximately 37 years of oil and gas experience.

Mr. Hille, the other co-founder of the Company, has been a Director of the
Company since June 1983, Chief Executive Officer of the Company since March
1994 and Vice Chairman of the Company since September 1995. He was also
President of the Company from May 1990 to September 1995, Chief Operating
Officer of the Company from April 1987 to March 1994, Executive Vice President
of the Company from June 1983 to May 1990 and Treasurer and Secretary of the
Company from June 1983 to April 1987. From August 1972 to March 1983, Mr.
Hille was employed by Andover where he served at various times primarily as
Executive Vice President and Vice President--Operations. Mr. Hille has a B.S.
Degree in Petroleum Engineering from the University of Tulsa, and has
approximately 31 years of oil and gas experience.

Mr. George has been a Director since October 1991, President of the Company
since September 1995 and Chief Operating Officer of the Company since March
1994. He was also an Executive Vice President of the Company from March 1994
to September 1995 and a Senior Vice President of the Company from October 1991
to March 1994. From April 1991 to October 1991, Mr. George was Vice President
of Operations and International with Santa Fe Minerals, Inc., an independent
oil and gas company ("Santa Fe Minerals"). From May 1981 to March 1991, he
served in various other management and executive capacities with Santa Fe
Minerals and its subsidiary, Andover. From December 1974 to April 1981, Mr.
George held various management and engineering positions with Amoco Production
Company. He has a B.S. Degree in Mechanical Engineering from the University of
Missouri-Rolla.

50
<PAGE>

Mr. Barnes, a certified public accountant, has been a Director, Treasurer
and Secretary of the Company since April 1987, an Executive Vice President of
the Company since March 1994 and Chief Financial Officer of the Company since
May 1990. He was also a Senior Vice President of the Company from May 1990 to
March 1994 and Vice President--Finance of the Company from January 1984 to May
1990. From November 1982 to December 1983, Mr. Barnes was an audit manager for
Arthur Andersen & Co., an independent public accounting firm, where he dealt
primarily with clients in the oil and gas industry. He was Assistant
Controller--Finance of Andover from December 1980 to November 1982. From June
1976 to December 1980, he was an auditor with Arthur Andersen & Co., where he
dealt primarily with clients in the oil and gas industry. Mr. Barnes has a
B.S. Degree in Business Administration from Oklahoma State University.

Mr. Abernathy has been Senior Vice President--Acquisitions of the Company
since March 1994. He was Vice President--Acquisitions of the Company from May
1990 to March 1994 and Manager--Acquisitions of the Company from June 1987 to
May 1990. From June 1976 to June 1987, Mr. Abernathy was employed by Exxon
Company USA, where he served at various times as Senior Staff Engineer, Senior
Supervising Engineer and in other engineering capacities, with assignments in
drilling, production and reservoir engineering in the Gulf Coast and offshore.
He has B.S. and M.S. Degrees in Mechanical Engineering from Auburn University.

Mr. Cox has been Vice President--General Counsel of the Company since March
1988. From August 1982 to March 1988, he was employed by Santa Fe Minerals and
its subsidiary, Andover, where he served at various times as Vice President--
Law and Regional Attorney. From April 1982 to August 1982, he was employed as
Corporate Attorney by Andover. Prior to that time, Mr. Cox was employed by
Amerada Hess Corporation, a major oil company, served as General Counsel and
Secretary of Kissinger Petroleum Corporation, an independent oil and gas
company, and served on the legal staff of Champlin Petroleum Company, an
independent oil and gas company. He has a B.S. Degree in Business
Administration with a major in Petroleum Marketing from the University of
Tulsa, and a Juris Doctor from the University of Michigan Law School.

Mr. Dozier has been Vice President--Operations of the Company since May
1992. From June 1983 to April 1992, he was employed by Santa Fe Minerals where
he held various engineering and management positions serving most recently as
Manager of Operations Engineering. From January 1975 to May 1983, he was
employed by Amoco Production Company serving in various positions where he
worked all phases of production, reservoir evaluations, drilling and
completions in the Mid-Continent and Gulf Coast areas. He has a B.S. Degree in
Petroleum Engineering from the University of Texas.

Mr. Meimerstorf, a certified public accountant, has been Controller of the
Company since January 1988 and a Vice President of the Company since May 1990.
He was Accounting Manager of the Company from February 1984 to January 1988.
From April 1981 to February 1984, he was the Financial Reporting Supervisor
for Andover. From June 1979 to April 1981, he was an auditor with Arthur
Andersen & Co. He has a B.S. Degree in Accounting from Arkansas Tech
University and an M.B.A. Degree from the University of Arkansas.

Mr. Phaneuf joined the Company as Vice President--Corporate Development in
October 1995. From June 1995 to October 1995, he was employed in the Corporate
Finance Group of Arthur Andersen LLP, specializing in energy industry
corporate finance activities. From April 1993 to August 1994, he was Senior
Vice President and head of the Energy Research Group at Kemper Securities, an
investment banking firm. From 1988 until April 1993, he was employed by
Rauscher, Pierce Refsnes, Inc., an investment banking firm, as a Senior Vice
President, serving as an energy analyst involved in equity research. From 1978
to 1988, Mr. Phaneuf was Vice President of Kidder, Peabody, & Co., an
investment banking firm, serving as an energy analyst in the Research
Department. From 1976 to 1978, he was employed by Schneider, Bernet, and
Hickman, serving as an energy analyst in the Research Department. From 1972 to
1976, he held the

51
<PAGE>

position of Investment Advisor for First International Investment Management,
a subsidiary of NationsBank. He holds a B.A. Degree in Psychology and an
M.B.A. Degree from the University of Texas.

Mr. Quackenbush has been Vice President--Production of the Company since May
1990. He was Manager--Production of the Company from November 1989 to May
1990. From May 1970 to July 1989, Mr. Quackenbush was employed by Tenneco Oil
Co., an oil and gas company, where he served as Acquisition Manager and in
various engineering positions. He has a B.S. Degree in Petroleum Engineering
from the Colorado School of Mines.

Mr. Sheppard has been Vice President--International of the Company since
November 1994. From June 1984 to August 1994, he was employed by Santa Fe
Minerals serving as Manager--Acquisitions & Special Projects, Manager--
International Operations, and in various other management and supervisory
capacities. From August 1977 to June 1984, he was employed by Amoco Production
Company serving in various engineering and supervisory capacities. He has a
B.S. Degree in Petroleum Engineering from Texas Tech University.

Mr. Lawrence has been a Director of the Company since January 1987. He has
been employed by Dillon, Read & Co. Inc., an investment banking firm ("Dillon
Read"), since January 1966 and is currently a Managing Director. Mr. Lawrence
also serves as a Director of D & K Wholesale Drug, Inc., Hallador Petroleum
Company, TransMontaigne Oil Company and Willbros Group, Inc. (each a United
States public company), Benson Petroleum Ltd. and Cavell Energy Corp. (each a
Canadian public company) and certain non-public companies in which affiliates
of Dillon Read hold equity interests including Meenan Oil Co., Inc., Fintube
Limited Partnership, Interenergy Corporation, PetroSantander Inc., Strega
Energy, Inc. and Savoy Energy, L.P. Mr. Lawrence is a graduate of Hamilton
College and also has an M.B.A. from Columbia University.

Mr. McNabb has been a Director of the Company since October 1990. He has
been Chief Executive Officer of Growth Capital Partners, Inc., an investment
and advisory firm in Houston, Texas serving privately held and public middle
market companies based in the Southwest, since March 1992. From June 1990 to
January 1992, he was a Managing Director of Bankers Trust Company, managing
commercial banking, investment banking and financial advisory activities in
the Southwest for Bankers Trust Company, and head of BT Southwest, Inc., an
affiliate of Bankers Trust New York Corporation. From September 1984 to June
1990, Mr. McNabb was employed by investment affiliates of The Prudential
Insurance Company of America where he provided a wide range of investment
banking services and corporate finance expertise to corporate clients. Mr.
McNabb also serves as a Director of Hugoton Energy Corporation and several
non-public companies. He holds undergraduate and graduate (M.B.A.) degrees
from Duke University.

52
<PAGE>

DESCRIPTION OF CAPITAL STOCK

The Company has 45,000,000 authorized shares of stock, consisting of (a)
40,000,000 shares of Common Stock, having a par value of $.005 per share, and
(b) 5,000,000 shares of Preferred Stock, having a par value of $.01 per share.

COMMON STOCK

As of the date of this Prospectus, there were 24,100,502 shares of Common
Stock outstanding. All of such outstanding shares of Common Stock are fully
paid and nonassessable. Each share of Common Stock has an equal and ratable
right to receive dividends when, as and if declared by the Board of Directors
of the Company out of assets legally available therefor and subject to the
dividend obligations of the Company to the holders of any Preferred Stock then
outstanding. The Company is subject to certain restrictions on the payment of
dividends under the provisions of its credit arrangements. See "Price Range of
Common Stock and Dividends."

In the event of a liquidation, dissolution or winding up of the Company, the
holders of Common Stock are entitled to share equally and ratably in the
assets available for distribution after payment of all liabilities, and
subject to any prior rights of any holders of Preferred Stock that at the time
may be outstanding.

The holders of Common Stock have no preemptive, subscription, conversion or
redemption rights, and are not subject to further calls or assessments of the
Company. There are no sinking fund provisions applicable to the Common Stock.
Each share of Common Stock is entitled to one vote in the election of
directors and on all other matters submitted to a vote of stockholders.
Holders of Common Stock have no right to cumulate their votes in the election
of directors.

PREFERRED STOCK

As of the date of this Prospectus, there were no shares of Preferred Stock
outstanding. Preferred Stock may be issued from time to time in one or more
series, and the Board of Directors, without further approval of the
stockholders, is authorized to fix the dividend rates and terms, conversion
rights, voting rights, redemption rights and terms, liquidation preferences,
sinking fund and any other rights, preferences, privileges and restrictions
applicable to each series of Preferred Stock. The purpose of authorizing the
Board of Directors to determine such rights, preferences, privileges and
restrictions is to eliminate delays associated with a stockholder vote on
specific issuances. The issuance of Preferred Stock, while providing
flexibility in connection with possible acquisitions and other corporate
purposes, could, among other things, adversely affect the voting power of the
holders of Common Stock and, under certain circumstances, make it more
difficult for a third party to gain control of the Company.

POSSIBLE ANTI-TAKEOVER PROVISIONS

The Company's Restated Certificate of Incorporation (the "Company's
Charter") contains certain provisions that might be characterized as anti-
takeover provisions. Such provisions may render more difficult certain
possible takeover proposals to acquire control of the Company and make removal
of management of the Company more difficult.

The Company's Charter provides for the Board of Directors to be divided into
three classes of directors serving staggered three-year terms, with the number
of directors in each class to be as nearly equal as possible. Any director of
the Company may be removed from office, but only for cause and only by the
affirmative vote of a majority of the then outstanding shares of stock
entitled to vote on the matter. Any stockholder wishing to submit a nomination
to the Board of Directors must follow certain procedures outlined in the
Company's Charter.

53
<PAGE>

The Company's Charter also provides that stockholder action may be taken
only at an annual or special meeting of stockholders, and may not be taken by
written consent of the stockholders.

As described above, the Company's Charter authorizes a class of undesignated
Preferred Stock consisting of 5,000,000 shares. Preferred Stock may be issued
from time to time in one or more series, and the Board of Directors, without
further approval of the stockholders, is authorized to fix the rights,
preferences, privileges and restrictions applicable to each series of
Preferred Stock. The purpose of authorizing the Board of Directors to
determine such rights, preferences, privileges and restrictions is to
eliminate delays associated with a stockholder vote on specific issuances. The
issuance of Preferred Stock, while providing flexibility in connection with
possible acquisitions and other corporate purposes, could, among other things,
adversely affect the voting power of the holders of Common Stock and, under
certain circumstances, make it more difficult for a third party to gain
control of the Company.

The Company's Charter also contains certain "fair price provisions" designed
to provide safeguards for stockholders when an "interested stockholder"
(defined as a stockholder owning 10 percent or more of the Company's voting
stock) attempts to effect a "business combination" with the Company. The term
"business combination" includes any merger or consolidation of the Company
involving the interested stockholder, certain dispositions of assets of the
Company, any issuance of securities of the Company, meeting certain threshold
amounts, to the interested stockholder, adoption of any plan of liquidation or
dissolution of the Company proposed by the interested stockholder and any
reclassification of securities of the Company having the effect of increasing
the proportionate share of ownership of the interested stockholder. In
general, a business combination between the Company and the interested
stockholder must be approved by the affirmative vote of two-thirds of the
outstanding voting stock, excluding voting stock owned by such interested
stockholder, unless the transaction is approved by a majority of the members
of the Board of Directors who are not affiliated with the interested
stockholder or certain minimum price and form of consideration requirements
are satisfied.

The Company is incorporated under the laws of the State of Delaware. Section
203 of the Delaware General Corporation Law prevents an "interested
stockholder" (defined as a stockholder owning 15 percent or more of a
corporation's voting stock) from engaging in a business combination with such
corporation for a period of three years from the date such stockholder became
an interested stockholder unless (a) the corporation's board of directors had
earlier approved either the business combination or the transaction by which
the stockholder became an interested stockholder, or (b) upon attaining that
status, the interested stockholder had acquired at least 85 percent of the
corporation's voting stock (not counting shares owned by persons who are
directors and also officers), or (c) the business combination is later
approved by the board of directors and authorized by a vote of two-thirds of
the stockholders (not including the shares held by the interested
stockholder). Since the Company has not amended its Charter or Restated By-
laws to exclude the application of Section 203, such section does apply to the
Company and thus may inhibit an interested stockholder's ability to acquire
additional shares of Common Stock or otherwise engage in a business
combination with the Company.

TRANSFER AGENT AND REGISTRAR

The Transfer Agent and Registrar for the Common Stock is ChaseMellon
Shareholder Services, L.L.C.

54
<PAGE>

CERTAIN U.S. TAX CONSEQUENCES TO NON-U.S. HOLDERS OF COMMON STOCK

GENERAL

The following is a general discussion of United States Federal income and
estate tax consequences of the ownership and disposition of Common Stock by a
holder who is not a United States person (a "Non-U.S. Holder"). This
discussion does not address all aspects of United States Federal income and
estate taxes and does not address any foreign, state or local tax
consequences. Furthermore, this discussion is based on provisions of the
Internal Revenue Code of 1986, as amended (the "Code"), existing, temporary
and proposed regulations promulgated thereunder and administrative and
judicial interpretations thereof, all as in effect or proposed on the date
hereof and all of which are subject to change, possibly with retroactive
effect, or different interpretations. Each prospective purchaser of Common
Stock is advised to consult a tax advisor with respect to current and possible
future United States Federal income and estate tax consequences of holding and
disposing of Common Stock as well as any tax consequences that may arise under
the laws of any state, local, foreign or other taxing jurisdiction. For
purposes of this summary, a "U.S. Holder" with respect to the Common Stock is
(a) an individual who is a citizen or resident of the United States, (b) a
corporation or other entity taxable as a corporation created or organized in
the United States or under the laws of the United States or of any state
thereof (including the District of Columbia), (c) an estate or trust the
income of which is includable in gross income for United States Federal income
tax purposes regardless of its source, or (d) a person otherwise subject to
United States Federal income taxation with respect to income from the Common
Stock on a net income basis.

DISTRIBUTIONS

Distributions on the shares of Common Stock (other than distributions
subject to Sections 302(b) or 355 of the Code) will constitute dividends for
Federal income tax purposes to the extent paid from current or accumulated
earnings and profits of the Company (as determined under Federal income tax
principles). Dividends paid to a Non-U.S. Holder of Common Stock that are not
effectively connected with a U.S. trade or business of the Non-U.S. Holder
will be subject to withholding of United States Federal income tax at a 30
percent rate or such lower rate as may be specified by an applicable income
tax treaty. Under the terms of the tax treaty between Canada and the United
States (the "Treaty"), dividends paid to a Non-U.S. Holder owning less than 10
percent of the Common Stock is subject to such withholding at the reduced rate
of 15 percent, provided that such Non-U.S. Holder is entitled to the benefits
of the Treaty. Moreover, under United States Treasury regulations which are
currently in effect, withholding is generally imposed on the gross amount of
the distribution, without regard to whether the corporation has sufficient
earnings and profits to cause the distribution to be a dividend for Federal
income tax purposes. Dividends that are effectively connected with the conduct
of a trade or business within the United States or, if a tax treaty applies,
are attributable to a U.S. permanent establishment of the Non-U.S. Holder, are
exempt from withholding of United States Federal income tax but are subject to
United States Federal income tax on a net income basis at applicable graduated
individual or corporate rates. Any such dividends effectively connected with
the conduct of a trade or business within the U.S. or attributable to a U.S.
permanent establishment received by a foreign corporation may, under certain
circumstances, be subject to an additional "branch profits tax" at a 30
percent rate or such lower rate as may be specified by an applicable income
tax treaty. Certain certification and disclosure requirements must be met in
order to qualify for exemption from withholding under the effectively
connected income or permanent establishment exemptions.

Under current United States Treasury regulations, dividends paid to an
address outside the United States are presumed to be paid to a resident of
such country for purposes of the withholding discussed above, and, under the
current interpretation of United States Treasury regulations, for purposes of
determining the applicability of a tax treaty rate. Under proposed United
States Treasury regulations (the "Proposed Regulations") not currently in
effect, however, a Non-U.S. Holder would be required to satisfy applicable
certification and other requirements to qualify for withholding at an
applicable treaty rate. The

55
<PAGE>

Proposed Regulations would require a Non-U.S. Holder to file a beneficial
owner withholding certificate, for example, a Form W-8, to obtain the lower
treaty rate. If the Proposed Regulations become effective, they will apply to
dividends paid after December 31, 1997, subject to certain transitional rules.

A Non-U.S. Holder may obtain a refund of any excess amounts withheld by
filing an appropriate claim for refund with the Internal Revenue Service (the
"IRS").

GAIN ON DISPOSITION OF COMMON STOCK

A Non-U.S. Holder will generally not be subject to United States Federal
income tax with respect to gain recognized on a sale or other disposition of
Common Stock unless (a) the gain is effectively connected with a trade or
business of the Non-U.S. Holder in the United States, (b) in the case of an
individual who holds the Common Stock as a capital asset, such Non-U.S. Holder
is present in the United States for 183 or more days in the taxable year of
the sale or other disposition and certain other conditions are met, or (c) the
Company is or has been a "U.S. real property holding corporation" for United
States Federal income tax purposes. The Company believes that it is currently
a "U.S. real property holding corporation" for Federal income tax purposes.
Under the "U.S. real property holding corporation" rules, so long as the
Common Stock continues to be regularly traded on an established securities
market (such as the New York Stock Exchange) and the Company is a "U.S. real
property holding corporation," a Non-U.S. Holder who holds or held (at any
time during the shorter of the five-year period preceding the date of
disposition or the Non-U.S. Holder's holding period) more than five percent of
the Common Stock will be subject to U.S. Federal income tax on the disposition
of the Common Stock. Such Non-U.S. Holders should consult their tax advisors
concerning this and other tax effects of the ownership and disposition of
Common Stock.

FEDERAL ESTATE TAX

Common Stock held by an individual Non-U.S. Holder at the time of death will
be included in such Non-U.S. Holder's gross estate for United States Federal
estate tax purposes, unless an applicable estate tax treaty provides
otherwise.

INFORMATION REPORTING AND BACKUP WITHHOLDING TAX

Under United States Treasury regulations, the Company must report annually
to the IRS and to each Non-U.S. Holder the amount of dividends paid to such
Non-U.S. Holder and the tax withheld with respect to such dividends. These
information reporting requirements apply even if withholding was not required
or withholding was reduced or eliminated by an applicable income tax treaty.
Copies of the information returns reporting such dividends and withholding may
also be made available to the tax authorities in the country in which the Non-
U.S. Holder resides under the provisions of an applicable income tax treaty.

Backup withholding of United States Federal income tax (which generally is
imposed at the rate of 31 percent on certain payments to persons that fail to
furnish certain information under the United States information reporting
requirements) will generally not apply to dividends paid to Non-U.S. Holders
that either are subject to the U.S. withholding of income tax, whether at 30
percent or a reduced treaty rate, or that are exempt from such withholding. As
a general matter, information reporting and backup withholding will not apply
to a payment by or through a foreign office of a foreign broker of the
proceeds of a sale of Common Stock effected outside the United States.
However, information reporting requirements (but not backup withholding) will
apply to a payment by or through a foreign office of a broker of the proceeds
of a sale of Common Stock effected outside the United States if that broker
(a) is a United States person, (b) is a foreign person that derives 50 percent
or more of its gross income for certain periods from the conduct of a trade or
business in the United States or (c) is a "controlled foreign corporation" as
defined in the Code (generally, a foreign corporation controlled by certain
United States stockholders), unless the broker has documentary evidence in its
records that the holder is a Non-U.S. Holder and certain conditions are met or
the holder otherwise establishes an exemption. Payment by a

56
<PAGE>

United States office of a broker of the proceeds of a sale of Common Stock is
subject to both backup withholding and information reporting unless the holder
certifies to the payor in the manner required as to its Non-U.S. Holder status
under penalties of perjury, or otherwise establishes an exemption.

Amounts withheld under the backup withholding rules do not constitute a
separate United States Federal income tax. Rather, any amounts withheld under
the backup withholding rules will be refunded or allowed as a credit against
the holder's United States Federal income tax liability, if any, provided the
required information or appropriate claim for refund is filed with the IRS.

THE FOREGOING DISCUSSION IS A SUMMARY OF THE PRINCIPAL UNITED STATES FEDERAL
INCOME AND ESTATE TAX CONSEQUENCES OF THE OWNERSHIP, SALE OR OTHER DISPOSITION
OF THE COMMON STOCK BY NON-U.S. HOLDERS. ACCORDINGLY, INVESTORS ARE URGED TO
CONSULT WITH THEIR TAX ADVISORS WITH RESPECT TO THE UNITED STATES FEDERAL
INCOME TAX CONSEQUENCES OF THE OWNERSHIP AND DISPOSITION OF THE COMMON STOCK
INCLUDING THE APPLICATION AND EFFECT OF THE LAWS OF ANY STATE, LOCAL, FOREIGN
OR OTHER TAXING JURISDICTION.

57
<PAGE>

UNDERWRITING

The names of the underwriters of the shares of Common Stock offered hereby
(the "Underwriters") and the aggregate number of shares which each has
severally agreed to purchase from the Company (subject to the terms and
conditions specified in the Underwriting Agreement) are as follows:

<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITERS SHARES
------------ ---------
<S> <C>
Dillon, Read & Co. Inc.......................................... 210,000
Salomon Brothers Inc............................................ 210,000
Smith Barney Inc................................................ 210,000
Johnson Rice & Company L.L.C.................................... 210,000
A.G. Edwards & Sons, Inc........................................ 40,000
Donaldson, Lufkin & Jenrette Securities Corporation............. 40,000
Goldman, Sachs & Co............................................. 40,000
Hanifen, Imhoff Inc............................................. 20,000
Hoak Breedlove Wesneski & Co.................................... 15,000
Jefferies & Company............................................. 20,000
Lazard Freres & Co. LLC......................................... 40,000
Lehman Brothers Inc. ........................................... 40,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated.............. 40,000
Morgan Stanley & Co. Incorporated............................... 40,000
Nesbitt Burns Securities Inc.................................... 40,000
David A. Noyes & Company........................................ 15,000
PaineWebber Incorporated........................................ 40,000
Pennsylvania Merchant Group Ltd................................. 15,000
Petrie Parkman & Co............................................. 20,000
Principal Financial Securities, Inc............................. 20,000
Prudential Securities Incorporated.............................. 40,000
Rauscher Pierce Refsnes, Inc.................................... 20,000
Raymond James & Associates, Inc................................. 20,000
Rodman & Renshaw, Inc........................................... 20,000
Southcoast Capital Corp......................................... 20,000
Wasserstein Perella Securities, Inc............................. 40,000
H.G. Wellington & Co. Inc....................................... 15,000
---------
Total......................................................... 1,500,000
=========
</TABLE>

The Managing Underwriters are Dillon, Read & Co. Inc., Salomon Brothers Inc,
Smith Barney Inc. and Johnson Rice & Company L.L.C.

If any shares of Common Stock offered hereby are purchased by the
Underwriters, all such shares will be so purchased. The Underwriting Agreement
contains certain provisions whereby if any Underwriter defaults in its
obligation to purchase such shares and if the aggregate obligations of the
Underwriters so defaulting do not exceed 10 percent of the shares offered
hereby, the remaining Underwriters, or some of them, must assume such
obligations.

The shares of Common Stock offered hereby are being offered severally by the
Underwriters for sale at the price set forth on the cover page hereof, or at
such price less a concession not to exceed $0.96 per share on sales to certain
dealers. The Underwriters may allow, and such dealers may reallow, a
concession not to exceed $0.10 per share on sales to certain dealers. The
offering of the shares of Common Stock is made for delivery when, as, and if
accepted by the Underwriters and subject to prior sale and to withdrawal,
cancellation or modification of the offer without notice. The Underwriters
reserve the right to reject any order for the purchase of the shares. After
the shares are released for sale to the public, the public offering price, the
concession and the reallowance may be changed by the Managing Underwriters.

58
<PAGE>

The Company has granted to the Underwriters an option to purchase up to an
additional 225,000 shares of Common Stock on the same terms per share. If the
Underwriters exercise this option, each of the Underwriters will have a firm
commitment, subject to certain conditions, to purchase approximately the same
proportion of the aggregate shares so purchased as the number of shares to be
purchased by it shown in the above table bears to the total number of shares
in such table. The Underwriters may exercise such option on or before the
thirtieth day from the date of the public offering of the shares offered
hereby and only to cover the over-allotments made of the shares in connection
with this Offering.

For a period of 90 days after the date of this Prospectus, the Company and
each director and executive officer of the Company have agreed not to offer,
sell, contract to sell or otherwise dispose of any shares of Common Stock, any
other capital stock of the Company or any security convertible into or
exercisable or exchangeable for Common Stock or any such other capital stock
without the prior written consent of Dillon, Read & Co. Inc. ("Dillon Read"),
except (a) the Company may register the Common Stock and the Company may sell
the shares of Common Stock offered in this Offering, (b) the Company may
register and the Company may issue securities pursuant to the Company's stock
option or other benefit or incentive plans maintained for its officers,
directors or employees, and (c) officers of the Company may, without such
consent, sell up to 400,000 shares of Common Stock in the aggregate.

The Company has agreed in the Underwriting Agreement to indemnify the
Underwriters against certain civil liabilities, including liabilities under
the Securities Act of 1933, as amended (the "Securities Act"), or to payments
that the Underwriters may be required to make in respect thereof.

Each of Dillon Read and Salomon Brothers Inc has performed various
investment banking services for the Company from time to time, for which it
has received customary fees. As of the date of this Prospectus, certain
Managing Directors and Senior Vice Presidents of Dillon Read owned 120,248
shares of Common Stock of the Company in the aggregate. Bryan H. Lawrence, a
Managing Director of Dillon Read, has been a member of the Board of Directors
of the Company since January 1987.

LEGAL MATTERS

The validity of the Common Stock offered hereby will be passed upon for the
Company by Conner & Winters, A Professional Corporation, Tulsa, Oklahoma.
Certain legal matters related to this Offering will be passed upon for the
Underwriters by Cravath, Swaine & Moore, New York, New York.

EXPERTS

The audited financial statements of the Company included in this Prospectus
have been audited by Arthur Andersen LLP, independent public accountants, as
indicated in their reports with respect thereto, and are included herein in
reliance upon the authority of said firm as experts in giving said reports.

The audited financial statements of Cadipsa as of, and for the year ended
June 30, 1995, included in the Company's Current Report on Form 8-K dated July
5, 1995 (as amended), which is incorporated herein by reference, have been
audited by Pistrelli, Diaz y Asociados and Arthur Andersen LLP, independent
public accountants, as indicated in their report with respect thereto, and are
incorporated herein in reliance upon the authority of said firms as experts in
giving said reports. Pistrelli, Diaz y Asociados is a member firm of Andersen
Worldwide SC.

The audited financial statements of Cadipsa as of June 30, 1994, and for the
years ended June 30, 1994 and 1993, included in the Company's Current Report
on Form 8-K dated July 5, 1995 (as amended), which is incorporated herein by
reference, have been audited by Deloitte & Touche, independent public
accountants, as indicated in their report with respect thereto, and are
incorporated herein in reliance upon the authority of said firm as experts in
giving said reports.

59
<PAGE>

The estimated reserve evaluations and related calculations of Netherland,
Sewell set forth or incorporated by reference in this Prospectus have been
included or incorporated by reference herein in reliance upon the authority of
said firm as experts in petroleum engineering.

AVAILABLE INFORMATION

The Company is subject to the informational requirements of the Exchange
Act, and, in accordance therewith, files reports, proxy and information
statements and other information with the Commission. Copies of such material
can be obtained by mail from the Public Reference Section of the Commission,
at Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, at
prescribed rates. In addition, such reports, proxy and information statements
and other information can be inspected and copied at the public reference
facility referenced above and at the Commission's regional offices at
Northwestern Atrium Center, 500 West Madison Street, Suite 1400, Chicago,
Illinois 60661-2511 and Seven World Trade Center, Suite 1300, New York, New
York 10048. Such reports, proxy statements and other information concerning
the Company can also be inspected and copied at the New York Stock Exchange,
20 Broad Street, New York, New York 10005. In addition, the Commission
maintains a site on the World Wide Web that contains reports, proxy and
information statements and other information filed electronically by the
Company with the Commission which can be accessed over the Internet at
http://www.sec.gov.

The Company has filed with the Commission a registration statement on Form
S-3 (herein, together with all amendments, supplements and exhibits thereto,
referred to as the "Registration Statement") under the Securities Act with
respect to the shares of Common Stock offered hereby. This Prospectus, which
forms a part of the Registration Statement, does not contain all of the
information set forth in the Registration Statement, certain parts of which
are omitted in accordance with the rules and regulations of the Commission.
For further information, reference is hereby made to the Registration
Statement.

60
<PAGE>

INDEX TO FINANCIAL STATEMENTS

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
AUDITED FINANCIAL STATEMENTS OF VINTAGE PETROLEUM, INC. AND SUBSIDIARIES:
Report of Independent Public Accountants................................ F-2
Consolidated Balance Sheets as of December 31, 1995 and 1994............ F-3
Consolidated Statements of Income for the years ended December 31, 1995,
1994 and 1993.......................................................... F-4
Consolidated Statements of Changes in Stockholders' Equity for the years
ended December 31, 1995, 1994 and 1993................................. F-5
Consolidated Statements of Cash Flows for the years ended December 31,
1995, 1994 and 1993.................................................... F-6
Notes to Consolidated Financial Statements for the years ended December
31, 1995, 1994 and 1993................................................ F-7
INTERIM FINANCIAL STATEMENTS OF VINTAGE PETROLEUM, INC. AND SUBSIDIARIES:
Consolidated Balance Sheet as of September 30, 1996 (Unaudited)......... F-22
Consolidated Statements of Income for the nine months ended September
30, 1996 and 1995 (Unaudited).......................................... F-23
Consolidated Statement of Changes in Stockholders' Equity for the nine
months ended September 30, 1996 (Unaudited)............................ F-24
Consolidated Statements of Cash Flows for the nine months ended
September 30, 1996 and 1995 (Unaudited)................................ F-25
Notes to Consolidated Financial Statements for the nine months ended
September 30, 1996 and 1995 (Unaudited)................................ F-26
</TABLE>

F-1
<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of Vintage Petroleum, Inc.:

We have audited the accompanying consolidated balance sheets of Vintage
Petroleum, Inc. (a Delaware corporation) and subsidiaries as of December 31,
1995 and 1994, and the related consolidated statements of income, changes in
stockholders' 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 Vintage Petroleum, Inc.
and subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted accounting
principles.

As discussed in Note 5 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 109, effective January
1, 1993.

Arthur Andersen LLP

Tulsa, Oklahoma
February 22, 1996

F-2
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)

A S S E T S

<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1995 1994
-------- --------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................... $ 2,545 $ 431
Accounts receivable--
Oil and gas sales.......................................... 40,256 26,278
Joint operations........................................... 4,616 4,205
Other...................................................... -- 4,300
Prepaids and other current assets........................... 11,665 4,036
-------- --------
Total current assets..................................... 59,082 39,250
-------- --------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, full cost method.................... 762,582 502,821
Oil and gas gathering systems............................... 12,765 12,531
Other....................................................... 7,733 4,711
-------- --------
783,080 520,063
Less accumulated depreciation, depletion and amortization... 205,334 153,398
-------- --------
577,746 366,665
-------- --------
OTHER ASSETS, net............................................ 10,711 1,837
-------- --------
$647,539 $407,752
======== ========

L I A B I L I T I E S A N D S T O C K H O L D E R S' E Q U I T Y

CURRENT LIABILITIES:
Revenue payable............................................. $ 16,855 $ 12,926
Accounts payable--trade..................................... 15,514 6,559
Other payables and accrued liabilities...................... 18,697 7,222
Current portion of long-term debt........................... 7,930 7,316
-------- --------
Total current liabilities................................ 58,996 34,023
-------- --------
LONG-TERM DEBT, less current portion above................... 315,846 186,548
-------- --------
DEFERRED INCOME TAXES........................................ 37,753 31,188
-------- --------
OTHER LONG-TERM LIABILITIES.................................. 3,922 --
-------- --------
MINORITY INTEREST IN SUBSIDIARY.............................. 7,062 --
-------- --------
COMMITMENTS AND CONTINGENCIES (Note 4)
STOCKHOLDERS' EQUITY, per accompanying statements:
Preferred stock, $.01 par, 5,000,000 shares authorized, zero
shares issued and outstanding.............................. -- --
Common stock, $.005 par, 40,000,000 shares authorized,
23,661,162 and 20,162,756 shares issued and outstanding.... 118 101
Capital in excess of par value.............................. 149,725 91,201
Retained earnings........................................... 74,117 64,691
-------- --------
223,960 155,993
-------- --------
$647,539 $407,752
======== ========
</TABLE>

The accompanying notes are an integral part of these statements.

F-3
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
---------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
REVENUES:
Oil and gas sales................................ $160,254 $141,357 $113,259
Oil and gas gathering............................ 12,380 14,635 7,861
Gas marketing.................................... 20,912 27,285 36,175
Other income..................................... 1,251 2,375 2,732
-------- -------- --------
194,797 185,652 160,027
-------- -------- --------
COSTS AND EXPENSES:
Lease operating, including production taxes...... 66,771 59,292 44,930
Oil and gas gathering............................ 9,511 12,294 5,869
Gas marketing.................................... 18,839 24,963 34,406
General and administrative....................... 11,601 8,889 6,066
Depreciation, depletion and amortization......... 52,257 45,774 33,335
Interest......................................... 20,178 12,002 6,943
-------- -------- --------
179,157 163,214 131,549
-------- -------- --------
Income before provision for income taxes,
minority interest and cumulative effect of
accounting change............................. 15,640 22,438 28,478
PROVISION FOR INCOME TAXES:
Current.......................................... (955) 1,576 3,962
Deferred......................................... 6,034 6,933 7,727
MINORITY INTEREST IN LOSS OF SUBSIDIARY............ 800 -- --
-------- -------- --------
Income before cumulative effect of accounting
change........................................ 11,361 13,929 16,789
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR
INCOME TAXES...................................... -- -- 1,725
-------- -------- --------
NET INCOME......................................... $ 11,361 $ 13,929 $ 18,514
======== ======== ========
EARNINGS PER SHARE:
Income before cumulative effect of accounting
change.......................................... $ .53 $ .66 $ .81
Cumulative effect of accounting change........... -- -- .08
-------- -------- --------
Net income....................................... $ .53 $ .66 $ .89
======== ======== ========
Weighted average common shares and common
equivalent shares outstanding................... 21,276 21,174 20,830
======== ======== ========
</TABLE>

The accompanying notes are an integral part of these statements.

F-4
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
CAPITAL
COMMON STOCK IN EXCESS
------------- OF PAR RETAINED
SHARES AMOUNT VALUE EARNINGS TOTAL
------ ------ --------- -------- --------
<S> <C> <C> <C> <C> <C>
BALANCE AT DECEMBER 31, 1992........ 16,392 $ 82 $ 43,955 $34,659 $ 78,696
Net income........................ -- -- -- 18,514 18,514
Issuance of common stock.......... 3,623 18 46,754 -- 46,772
Exercise of stock options and
resulting tax effects............ 138 1 409 -- 410
Cash dividends declared ($.05 per
share)........................... -- -- -- (1,000) (1,000)
------ ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1993........ 20,153 101 91,118 52,173 143,392
Net income........................ -- -- -- 13,929 13,929
Exercise of stock options and
resulting tax effects............ 10 -- 83 -- 83
Cash dividends declared ($.07 per
share)........................... -- -- -- (1,411) (1,411)
------ ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1994........ 20,163 101 91,201 64,691 155,993
Net income........................ -- -- -- 11,361 11,361
Issuance of common stock.......... 2,803 14 55,190 -- 55,204
Exercise of warrants.............. 294 1 1,467 -- 1,468
Exercise of stock options and
resulting tax effects............ 401 2 1,867 -- 1,869
Cash dividends declared ($.09 per
share)........................... -- -- -- (1,935) (1,935)
------ ---- -------- ------- --------
BALANCE AT DECEMBER 31, 1995........ 23,661 $118 $149,725 $74,117 $223,960
====== ==== ======== ======= ========
</TABLE>

The accompanying notes are an integral part of these statements.

F-5
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
------------------------------------
1995 1994 1993
----------- ---------- -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.............................. $ 11,361 $ 13,929 $ 18,514
Adjustments to reconcile net income to
cash provided by operating activities--
Cumulative effect of change in
accounting for income taxes........... -- -- (1,725)
Depreciation, depletion and
amortization.......................... 52,257 45,774 33,335
Minority interest in loss of
subsidiary............................ (800) -- --
Provision for deferred income taxes.... 6,034 6,933 7,727
----------- ---------- -----------
68,852 66,636 57,851
Decrease (increase) in receivables..... (11,836) 3,005 (9,056)
(Decrease) increase in payables and
accrued liabilities................... (1,012) (9,487) 3,879
Other.................................. (1,805) (1,484) (455)
----------- ---------- -----------
Cash provided by operating
activities.......................... 54,199 58,670 52,219
----------- ---------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and
equipment--
Oil and gas properties................. (141,490) (65,136) (140,864)
Gathering systems and other............ (3,256) (1,832) (4,162)
Proceeds from sale of oil and gas
properties............................. 604 711 1,006
Purchase of companies, net of cash
acquired............................... (45,886) -- --
Other................................... 2,777 (4,411) (2,106)
----------- ---------- -----------
Cash used by investing activities.... (187,251) (70,668) (146,126)
----------- ---------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock.................... 51,191 -- 44,772
Sale of 9% Senior Subordinated Notes Due
2005................................... 145,137 -- --
Advances on revolving credit facility
and other borrowings................... 178,264 51,134 220,878
Payments on revolving credit facility
and other borrowings................... (237,679) (37,959) (170,885)
Dividends paid.......................... (1,747) (1,308) (865)
----------- ---------- -----------
Cash provided by financing
activities.......................... 135,166 11,867 93,900
----------- ---------- -----------
NET INCREASE (DECREASE) IN CASH.......... 2,114 (131) (7)
CASH AND CASH EQUIVALENTS, beginning of
year.................................... 431 562 569
----------- ---------- -----------
CASH AND CASH EQUIVALENTS, end of year... $ 2,545 $ 431 $ 562
=========== ========== ===========
</TABLE>

The accompanying notes are an integral part of these statements.

F-6
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Consolidation

Vintage Petroleum, Inc. is an independent energy company with operations
primarily in the exploration and production, gas marketing and gathering
segments of the oil and gas industry. Approximately 90 percent of the
Company's operations are within the exploration and production segment based
on 1995 operating income. Its core areas of exploration and production
operations include California, the Gulf Coast, East Texas and Mid-Continent
areas of the United States, and the San Jorge Basin of Argentina. Argentina
exploration and production operations commenced in 1995 as a result of the
acquisitions discussed in Note 6.

The consolidated financial statements include the accounts of Vintage
Petroleum, Inc. and its wholly- and majority-owned subsidiaries,
(collectively, the "Company"). In addition, the Company's interests in various
partnerships and joint ventures have been proportionately consolidated,
whereby the Company's proportionate share of each partnership or joint
venture's assets, liabilities, revenues and expenses is included in the
appropriate accounts in the consolidated financial statements. All significant
intercompany accounts and transactions have been eliminated in consolidation.

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, if any, 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.

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method which
provides for the capitalization of all acquisition, exploration and
development costs incurred for the purpose of finding oil and gas reserves,
including salaries, benefits and other internal costs directly attributable to
these activities. The Company capitalized $4.4 million, $2.3 million and $2.1
million of internal costs in 1995, 1994 and 1993, respectively. The
unamortized capitalized costs of oil and gas properties, including estimated
future development and abandonment costs, are amortized using the units-of-
production method based on proved reserves on a country-by-country basis. The
Company's unamortized costs of oil and gas properties are limited, on a
country-by-country basis, to the sum of the future net revenues attributable
to proved oil and gas reserves discounted at 10 percent plus the cost of any
unproved properties. If the Company's unamortized costs in oil and gas
properties exceed this ceiling amount, a provision for additional
depreciation, depletion and amortization is required. At December 31, 1995,
1994 and 1993, the Company's cost of oil and gas properties by country did not
exceed such ceiling amounts. Amortization per equivalent barrel of the
Company's U.S. oil and gas properties was $3.89, $3.82 and $3.71 for the years
ended December 31, 1995, 1994 and 1993, respectively. Amortization per
equivalent barrel of the Company's Argentina oil and gas properties for the
year ended December 31, 1995, was $4.28. The Company had no Argentina
operations prior to 1995.

Revenue Recognition

Natural gas revenues are recorded using the sales method. Under this method,
the Company recognizes revenues based on actual volumes of gas sold to
purchasers. The Company and other joint interest owners may sell more or less
than their entitlement share of the natural gas volumes produced. A liability
is recorded and revenue is deferred if the Company's excess sales of natural
gas volumes exceed its estimated remaining recoverable reserves.

F-7
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Hedging Policy

The Company periodically uses hedges (swap agreements) to reduce the impact
of oil and natural gas price fluctuations. Gains and losses on swap agreements
are recognized as an adjustment to sales revenue when the related transactions
being hedged are finalized. Gains or losses from swap agreements that do not
qualify for accounting treatment as hedges are recognized currently as other
income or expense.

Depreciation

Depreciation of property, plant and equipment (other than oil and gas
properties) is provided using both straight-line and accelerated methods based
on estimated useful lives ranging from three to ten years.

Income Taxes

Statements of Cash Flows

During the years ended December 31, 1995, 1994 and 1993, the Company made
cash payments for interest totaling $21.6 million, $11.3 million and $6.0
million, respectively, and cash payments for U.S. income taxes of $0.5
million, $3.1 million and $4.1 million, respectively. No cash payments were
made during 1995 for foreign income taxes and the Company had no foreign
operations prior to 1995.

In late 1993, the Company increased its ownership in certain oil and gas
properties and gathering systems by acquiring 100 percent of its partners'
interests in the Vintage/P Acquisition Limited Partnership and a joint
venture. Total consideration included cash, common stock, a stock subscription
warrant and the assumption of certain net liabilities. The value of the non-
cash consideration was $6.4 million and is not reflected in the Company's 1993
Consolidated Statement of Cash Flows.

During 1995, the Company purchased a majority interest in Cadipsa S.A.
("Cadipsa"--see Note 6). The value of the non-cash consideration is not
reflected in the Company's 1995 Consolidated Statement of Cash Flows. Such
non-cash consideration consisted of $5.7 million of the Company's common
stock, $3.2 million cash payable in 1996, and approximately $58.1 million of
net liabilities and a $7.9 million minority interest added through
consolidation of Cadipsa.

In December 1995, the Company purchased certain oil and gas properties from
Shell (see Note 6) for $32.8 million cash and deferred payments valued at $5.1
million. The $5.1 million of deferred payments represent non-cash
consideration and are not reflected in the Company's 1995 Consolidated
Statement of Cash Flows.

Earnings Per Share

Earnings per share are based on the weighted average common shares and
common share equivalents outstanding, computed using the treasury stock method
assuming the exercise of all common stock options and warrants (except where
the effect is anti-dilutive).

General and Administrative Expense

The Company receives fees for operation of jointly-owned oil and gas
properties and records such reimbursements as reductions of general and
administrative expense. Such fees totaled approximately $2.9 million, $2.3
million and $2.9 million in 1995, 1994 and 1993, respectively.

F-8
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Revenue Payable

Amounts payable to royalty and working interest owners resulting from sales
of oil and gas from jointly-owned properties and from purchases of oil and gas
by the Company's marketing and gathering segments are classified as revenue
payable in the accompanying financial statements.

Accounts Receivable

The Company's oil and gas, gas marketing and gathering sales are to a
variety of purchasers, including intrastate and interstate pipelines or their
marketing affiliates, independent marketing companies and major oil companies.
The Company's joint operations accounts receivable are from a large number of
major and independent oil companies, partnerships, individuals and others who
own interests in the properties operated by the Company. The Company's other
accounts receivable at December 31, 1994, represents funds in escrow at year
end relating to a potential acquisition. These funds were returned to the
Company during 1995.

2. LONG-TERM DEBT

Long-term debt at December 31, 1995 and 1994, consists of the following:

<TABLE>
<CAPTION>
1995 1994
-------- --------
(IN THOUSANDS)
<S> <C> <C>
9% Senior Subordinated Notes Due 2005, net of discount.... $149,592 $ --
Revolving credit facility................................. 74,300 172,600
Bank term loan............................................ 36,736 --
5.92% Senior note......................................... 9,948 13,264
11% Subordinated note..................................... -- 8,000
Subsidiary debt--
International Finance Corporation notes................. 28,000 --
Bank of Boston senior note.............................. 20,000 --
Other subsidiary debt................................... 5,200 --
-------- --------
323,776 193,864
Less--Current portion of long-term debt................... 7,930 7,316
-------- --------
$315,846 $186,548
======== ========
</TABLE>

Subsidiary debt relates to borrowings of the Company's foreign subsidiaries,
the recourse of which is solely to such subsidiaries, except for $9.2 million
advanced by the International Finance Corporation which is guaranteed by the
Company.

Aggregate maturities of long-term debt for each of the years ending December
31, 1996, through December 31, 2000, are $7.9 million, $29.9 million, $25.9
million, $59.3 million and $22.6 million, with $178.2 million thereafter.

9% Senior Subordinated Notes

On December 20, 1995, the Company issued $150 million of its 9% Senior
Subordinated Notes Due 2005 (the "Notes"). The Notes are redeemable at the
option of the Company, in whole or in part, at any time on or after December
15, 2000. Upon a change in control (as defined) of the Company, holders of the
Notes may require the Company to purchase all or a portion of the Notes at a
purchase price equal to 101 percent of the principal amount thereof, plus
accrued and unpaid interest. The Notes mature on December 15, 2005, with
interest payable semiannually on June 15 and December 15 of each year.

F-9
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

The Notes are unsecured senior subordinated obligations of the Company and
rank subordinate in right of payment to all senior indebtedness (as defined).
The indenture for the Notes contains limitations on, among other things,
additional indebtedness and liens, the payment of dividends and other
distributions, certain investments and transfers or sales of assets. The net
proceeds to the Company from the sale of the Notes of approximately $145.1
million were used to reduce a portion of the outstanding balance under the
Company's revolving credit facility and to repay a short-term note payable
used to retire the 11% Subordinated Note.

Revolving Credit Facility

The Company has available an unsecured revolving credit facility under the
Credit Agreement dated November 3, 1993, as amended (the "Credit Agreement"),
among the Company, and certain banks. The Credit Agreement establishes a
borrowing base (currently $230 million) based on the banks' evaluation of the
Company's U.S. oil and gas reserves. On February 1, 1996, the Company elected
to set the banks' commitment at $180 million in order to reduce fees charged
by the banks.

Outstanding advances under the Company's revolving credit facility bear
interest payable quarterly at a floating rate based on Bank of Montreal's
alternate base rate (as defined) or, at the Company's option, at a fixed rate
for up to six months based on the eurodollar market rate ("LIBOR"). The
Company's interest rate increments above the alternate base rate and LIBOR
vary based on the level of outstanding senior debt and the borrowing base at
the time. In addition, the Company must pay a commitment fee of 0.375 percent
per annum on the unused portion of the banks' commitment. Total outstanding
advances at December 31, 1995, were $74.3 million at an average interest rate
of approximately 7.8 percent.

On a semiannual basis, the Company's borrowing base is redetermined by the
banks based upon their review of the Company's U.S. oil and gas reserves. If
the sum of outstanding senior debt exceeds the borrowing base, as
redetermined, the Company must repay such excess. Any principal advances
outstanding at October 31, 1997, will be payable in 16 equal consecutive
quarterly installments commencing January 31, 1998, with maturity at October
31, 2001.

The terms of the Credit Agreement impose certain restrictions on the Company
regarding the pledging of assets and limitations on, among other things,
additional indebtedness and the payment of dividends and other distributions.
In addition, the Credit Agreement requires the maintenance of a minimum
current ratio (as defined) and tangible net worth (as defined) of $164 million
plus 75 percent of the net proceeds of any future equity offerings.

Bank Term Loan

On January 12, 1995, the Company refinanced with certain banks $36.7 million
of outstanding advances under the revolving credit facility with an unsecured
term loan maturing November 30, 1999. The term loan bears interest at a
floating rate (plus a fixed increment) based on Bank of Montreal's alternate
base rate (as defined) or, at the Company's option, at a fixed rate for up to
six months based on LIBOR. The Company has currently elected a fixed rate
based on LIBOR, which on December 31, 1995, was 6.7 percent. The terms and
restrictions under the bank term loan are generally the same as those provided
in the Credit Agreement.

International Finance Corporation Notes

Under an Amended and Restated Investment Agreement dated April 28, 1994, as
amended (the "Investment Agreement"), between the International Finance
Corporation ("IFC") and Cadipsa, the Company's majority-owned subsidiary,
outstanding advances were $28.0 million at December 31, 1995.

F-10
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

These borrowings consist of three separate loans having principal payments
beginning on September 15, 1996, with maturity on March 15, 2003. The
Investment Agreement is recourse solely to Cadipsa except for a guarantee of
$9.2 million of principal, plus interest thereon, provided by the Company on
behalf of Cadipsa to the IFC. The guarantee can be released and dividends may
be paid out of profits of Cadipsa once certain conditions and financial ratios
are met by Cadipsa.

Bank of Boston Senior Note

In connection with the BG Acquisition (see Note 6), the Company, through its
wholly-owned subsidiary, Vintage Oil Argentina, Inc. (formerly BG Argentina,
S.A.), entered into a non-recourse $20 Million Credit Agreement dated
September 28, 1995, with the Buenos Aires Branch of The First National Bank of
Boston. This loan is secured by all of the common stock of Vintage Oil
Argentina, Inc. and, upon government approval of the fiduciary assignment
agreement, substantially all of its assets. The Company expects to receive
such government approval, however, a default occurs if such approval is not
received by May 25, 1996. The borrowing limit under the $20 Million Credit
Agreement (currently $20.0 million) is redetermined semiannually by the bank,
beginning September 30, 1996, based on a review of Vintage Oil Argentina,
Inc.'s oil and gas reserves. Such reviews may result in a required repayment
of the amount in excess of the borrowing limit prior to maturity of the loan
on September 29, 1997. Vintage Oil Argentina, Inc. dividends are permitted to
the extent its tangible net worth (as defined) exceeds $14.0 million.

Fair Value of Long-term Debt

Based on the estimated borrowing rates currently available to the Company
for the long-term loans with similar terms and average maturities, the
aggregate fair value at December 31, 1995, of the Company's long-term debt is
approximately $323.2 million compared to the aggregate carrying amount of
$323.8 million.

3. CAPITAL STOCK

Public Offerings and Other Issuances

In January 1993, the Company completed a public offering of 3,910,000 shares
of common stock of which 3,510,000 shares were sold by the Company and 400,000
shares were sold by a stockholder. Net proceeds to the Company were
approximately $44.8 million and were used to reduce a portion of the
indebtedness incurred under the Company's revolving credit facility to acquire
certain oil and gas properties on December 30, 1992.

In December 1993, the Company issued 112,756 shares of common stock valued
at $2.0 million as partial consideration to acquire the sole limited
partnership interest in the Vintage/P Acquisition Limited Partnership.

On July 5, 1995, the Company issued 302,808 shares of common stock valued at
$5.7 million as partial consideration to acquire a controlling interest in
Cadipsa (see Note 6).

On December 20, 1995, the Company completed a public offering of 2,793,700
shares of common stock of which 2,500,000 shares were sold by the Company and
293,700 shares were sold by a stockholder. Net proceeds to the Company were
approximately $49.5 million. The net proceeds were used to repay advances made
under the revolving credit facility to fund the acquisition of a portion of
the Astra/Shell Properties (see Note 6) and to finance a substantial portion
of the acquisition of the remaining portion of the Astra/Shell Properties.

A stock subscription warrant was exercised on December 20, 1995, for the
purchase of 293,700 shares of the Company's common stock at an exercise price
of $5.00 per share yielding net proceeds to the Company of approximately $1.5
million.

F-11
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Stock Plans and Warrants

Under the 1983 Stock Option Plan, as amended (the "1983 Plan"), incentive
stock options were granted to key employees of the Company. Generally, options
granted under the 1983 Plan are exercisable for a two to seven year period
beginning three years from the date granted. As of December 31, 1995, all
available options have been granted under the 1983 Plan.

Under the 1990 Stock Plan, as amended (the "1990 Plan"), a total of up to
1,500,000 shares of common stock are available for issuance to key employees
of the Company. The 1990 Plan permits the granting of any or all of the
following types of awards: (a) stock options, (b) stock appreciation rights,
and (c) restricted stock. As of December 31, 1995, awards for a total of
339,000 shares of common stock remain available for grant under the 1990 Plan.

The 1990 Plan is administered by the Compensation Committee appointed by the
Board of Directors of the Company (the "Committee"). Subject to the terms of
the 1990 Plan, the Committee has the authority to determine plan participants,
the types and amounts of awards to be granted and the terms, conditions and
provisions of awards. Options granted pursuant to the 1990 Plan may, at the
discretion of the Committee, be either incentive stock options or non-
qualified stock options. The exercise price of incentive stock options may not
be less than the fair market value of the common stock on the date of grant.
In the case of non-qualified stock options, the exercise price may not be less
than 85 percent of the fair market value of the common stock on the date of
grant. Any stock appreciation rights granted under the 1990 Plan will give the
holder the right to receive cash in an amount equal to the difference between
the fair market value of the share of common stock on the date of exercise and
the exercise price. Restricted stock under the 1990 Plan will generally
consist of shares which may not be disposed of by participants until certain
restrictions established by the Committee lapse.

In 1993, the Non-Management Director Stock Option Plan (the "Director Plan")
was approved by the Company's stockholders. Under the Director Plan, 30,000
shares of common stock are available for issuance to the outside directors of
the Company. Each outside director receives an initial option to purchase
5,000 shares of common stock during the director's first year of service to
the Company. Annually thereafter, options to purchase 1,000 shares of common
stock are to be granted to each outside director. Options granted pursuant to
the Director Plan are non-qualified stock options and the option exercise
price is equal to the fair market value of the common stock on the date of
grant.

The following is an analysis of all option activity under the 1983 Plan, the
1990 Plan and the Director Plan for 1995, 1994 and 1993:

<TABLE>
<CAPTION>
1995 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
Beginning stock options outstanding...... 1,457,000 1,193,000 988,000
Stock options granted.................. 98,000 274,000 343,000
Stock options cancelled................ (20,000) -- --
Stock options exercised................ (401,898) (10,000) (138,000)
---------- ---------- ----------
Ending stock options outstanding......... 1,133,102 1,457,000 1,193,000
========== ========== ==========
Ending stock options exercisable......... 336,701 338,018 224,832
========== ========== ==========
Weighted average exercise price of:
Options exercised during the year...... $ 4.47 $ 4.89 $ 2.02
Ending stock options outstanding....... 14.81 11.64 10.34
Ending stock options exercisable....... 11.04 4.74 4.09
</TABLE>

F-12
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

All of the outstanding options are exercisable at various times in years
1996 through 2005. All incentive stock options and non-qualified options were
granted at fair market value on the date of grant. As of December 31, 1995, no
awards other than incentive and non-qualified stock options have been granted
under the 1990 Plan.

At December 31, 1995, stock subscription warrants (the "Warrants") for the
purchase of 316,300 shares of the Company's common stock at an average
exercise price of $5.42 per share were outstanding. In January 1996, a Warrant
for 306,300 shares of the Company's common stock was exercised at a price of
$5.00 per share and the remaining Warrant for 10,000 shares was cancelled.

At December 31, 1995, a total of 1,804,402 shares of the Company's common
stock are reserved for issuance pursuant to the 1983 Plan, the 1990 Plan and
the Director Plan and upon the exercise of the Warrants.

Preferred Stock

Preferred stock at December 31, 1995, consists of 5,000,000 authorized but
unissued shares. Preferred stock may be issued from time to time in one or
more series, and the Board of Directors, without further approval of the
stockholders, is authorized to fix the dividend rates and terms, conversion
rights, voting rights, redemption rights and terms, liquidation preferences,
sinking fund and any other rights, preferences, privileges and restrictions
applicable to each series of preferred stock.

4. COMMITMENTS AND CONTINGENCIES

Rent expense was $0.8 million, $0.5 million and $0.4 million for 1995, 1994
and 1993, respectively. The future minimum commitments under long-term
noncancellable leases for office space are $0.9 million and $0.5 million for
1996 and 1997, respectively.

The Company has $10.1 million in letters of credit outstanding at December
31, 1995. These letters of credit relate primarily to bonding requirements of
various state regulatory agencies for oil and gas operations and various
obligations for acquisition and exploration activities in South America.

During 1995, the Company entered into an exploration contract on Block 19 in
Ecuador for a term of four years. Under the terms of the contract the Company
is required to spend approximately $2.0 million per year for the project.

The Company is a defendant in various lawsuits and is a party in
governmental proceedings from time to time arising in the ordinary course of
business. In the opinion of management, none of the various pending lawsuits
and proceedings should have a material adverse effect upon the consolidated
financial statements of the Company.

5. INCOME TAXES

Effective January 1, 1993, the Company adopted the provisions of Statement
of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS
109"). SFAS 109 generally requires that deferred taxes be provided using a
liability approach at currently enacted income tax rates rather than the
deferred approach at historical rates which had previously been required. The
cumulative effect on prior years of adopting the change was recorded in the
quarter ended March 31, 1993, as provided by SFAS 109, and increased net
income by $1.7 million.

F-13
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

The provision for income taxes for the years ended December 31, 1995, 1994
and 1993, consists of the following:

<TABLE>
<CAPTION>
1995 1994 1993
------ ------ -------
(IN THOUSANDS)
<S> <C> <C> <C>
Current............................................... $ (955) $1,576 $ 3,962
Deferred.............................................. 6,034 6,933 7,727
------ ------ -------
$5,079 $8,509 $11,689
====== ====== =======
</TABLE>

A reconciliation of the federal statutory income tax rate to the effective
rate is as follows:

<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Statutory income tax rate................................. 35.0% 35.0% 35.0%
State income tax, less federal benefit.................... 3.9 3.9 3.9
Federal income tax credits................................ (7.4) -- --
Effect on prior years of increase in corporate income tax
rate..................................................... -- -- 2.0
All other, net............................................ 1.0 (1.0) 0.1
---- ---- ----
32.5% 37.9% 41.0%
==== ==== ====
</TABLE>

The components of the Company's net deferred tax liability as of December
31, 1995 and 1994, are as follows:

<TABLE>
<CAPTION>
1995 1994
------- -------
(IN THOUSANDS)
<S> <C> <C>
Deferred Tax Liabilities:
Differences between book and tax basis of property........ $41,699 $34,670
Other..................................................... -- 21
------- -------
41,699 34,691
------- -------
Deferred Tax Assets:
Alternative minimum tax credit carryforward............... 3,538 3,165
Other..................................................... 408 338
------- -------
3,946 3,503
------- -------
$37,753 $31,188
======= =======
</TABLE>

Earnings of the Company's foreign subsidiaries, Cadipsa and Vintage Oil
Argentina, Inc., are subject to Argentina income taxes. Due to significant
Argentina net operating loss carryforwards for both companies, the Company
does not expect to pay any foreign income taxes related to these subsidiaries
in the near future. No U.S. deferred tax liability will be recognized related
to the unremitted earnings of these foreign subsidiaries, as it is the
Company's intention, generally, to reinvest such earnings permanently.

As of December 31, 1995, the Company has an alternative minimum tax ("AMT")
credit carryforward of approximately $3.5 million. The AMT credit carryforward
does not expire and is available to offset regular income taxes in future
years, but only to the extent that regular income taxes exceed the AMT in such
years.

F-14
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

6. SIGNIFICANT ACQUISITIONS

In May 1995, the Company acquired certain U.S. oil and gas properties from
Texaco Exploration and Production Inc. for approximately $26.7 million cash
(the "Texaco Acquisition").

Through a series of transactions during the last six months of 1995, the
Company purchased approximately 71.6 percent of the outstanding common stock
of Cadipsa S.A. ("Cadipsa"), a publicly-traded Argentine oil and gas
exploration and production company, for 302,808 shares of the Company's common
stock (valued at $5.7 million) and $12.3 million cash (the "Cadipsa
Acquisition"). Approximately $58.1 million of net liabilities and a $7.9
million minority interest result from the consolidation of Cadipsa as of the
acquisition date. Subsequent to December 31, 1995, the Company purchased an
additional 9.3 percent of Cadipsa for $2.3 million cash. The Company is
pursuing additional purchases of shares of Cadipsa.

On September 29, 1995, the Company purchased 100 percent of the outstanding
common stock of BG Argentina, S.A. ("BG Argentina") from British Gas plc, for
$37 million cash (the "BG Acquisition"). BG Argentina was subsequently renamed
Vintage Oil Argentina, Inc.

On November 3, 1995, the Company purchased a 35 percent interest in certain
Argentina oil and gas properties (the "Astra/Shell Properties") from Astra
Compania Argentina de Petroleo S.A. ("Astra") for $17.9 million cash. On
December 28, 1995, the Company purchased the remaining 65 percent interest in
the Astra/Shell Properties from Shell Compania Argentina de Petroleo S.A.
("Shell") for $32.8 million cash and deferred payments valued at $5.1 million.

The Company accounted for the Cadipsa Acquisition and the BG Acquisition
under the purchase method and has not completed its evaluations of the
purchased assets and assumed liabilities; therefore, it has not completed the
final purchase price allocations for these acquisitions. The consolidated
statements of income include the operating results of the above acquisitions
since their acquisition date.

The Company completed on December 20, 1995, a public offering of 2,793,700
shares of the Company's common stock (the "Common Stock Offering"), of which
2,500,000 shares were sold by the Company and 293,700 shares were sold by a
certain stockholder (see Note 3). The net proceeds to the Company of
approximately $49.5 million were used to fund a substantial portion of the
purchase of the Astra/Shell Properties.

The Company's unaudited pro forma revenues, net income and net income per
share for the years ended December 31, 1995 and 1994, presented below have
been prepared assuming the Common Stock Offering, the Texaco Acquisition, the
Cadipsa Acquisition, the BG Acquisition and the acquisition of the Astra/Shell
Properties had been consummated as of January 1, 1994. However, such pro forma
information is not necessarily indicative of what actually would have occurred
had the transactions occurred on such date.

<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Revenues (in thousands)................................... $244,921 $255,489
Net income (in thousands)................................. 18,712 9,059
Net income per share...................................... .78 .37
</TABLE>

F-15
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

7. SEGMENT INFORMATION

The Company operates in the oil and gas exploration and production industry
in the United States and South America. Operations in the gathering and gas
marketing industries are in the United States. The following is industry
segment data for the years ended December 31, 1995, 1994 and 1993:

<TABLE>
<CAPTION>
1995 1994 1993
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
REVENUES:
Exploration and production--
U.S.......................................... $146,819 $141,357 $113,259
Argentina.................................... 13,435 -- --
Gas marketing................................. 49,775 61,480 70,705
Gathering..................................... 22,289 17,630 9,445
Other income.................................. 1,251 2,375 2,732
Elimination of intersegment sales............. (38,772) (37,190) (36,114)
-------- -------- --------
$194,797 $185,652 $160,027
======== ======== ========
OPERATING INCOME:
Exploration and production--
U.S.......................................... $ 39,524 $ 38,234 $ 36,634
Argentina.................................... 4,114 -- --
Gas marketing................................. 2,073 2,322 1,769
Gathering..................................... 1,568 1,058 990
Other income.................................. 1,251 2,375 2,732
Corporate expenses............................ (12,712) (9,549) (6,704)
Interest expense.............................. (20,178) (12,002) (6,943)
-------- -------- --------
$ 15,640 $ 22,438 $ 28,478
======== ======== ========
IDENTIFIABLE ASSETS:
Exploration and production--
U.S.......................................... $431,391 $386,824 $363,456
Argentina.................................... 180,488 -- --
Other international.......................... 1,269 -- --
Gas marketing................................. 5,431 5,850 8,415
Gathering..................................... 11,084 8,918 8,728
Corporate..................................... 17,876 6,160 3,862
-------- -------- --------
$647,539 $407,752 $384,461
======== ======== ========
DEPRECIATION, DEPLETION AND AMORTIZATION:
Exploration and production--
U.S.......................................... $ 45,730 $ 43,831 $ 31,695
Argentina.................................... 4,115 -- --
Gathering..................................... 1,301 1,283 1,002
Corporate..................................... 1,111 660 638
-------- -------- --------
$ 52,257 $ 45,774 $ 33,335
======== ======== ========
CAPITAL ADDITIONS:
Exploration and production--
U.S.......................................... $ 88,149 $ 65,136 $147,252
Argentina.................................... 170,947 -- --
Other international.......................... 1,269 -- --
Gathering..................................... 234 632 3,319
Corporate..................................... 3,023 1,200 843
-------- -------- --------
$263,622 $ 66,968 $151,414
======== ======== ========
</TABLE>

F-16
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

During 1995, 1994 and 1993, sales to one crude oil purchaser represented
approximately 17%, 14% and 11%, respectively, of the Company's total revenues.

8. QUARTERLY RESULTS (UNAUDITED)

The following is a summary of the quarterly results of operations for the
years ended December 31, 1995 and 1994:

<TABLE>
<CAPTION>
QUARTER ENDED
---------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1995
Revenues....................... $ 41,042 $ 45,230 $ 50,101 $ 58,424
Operating income............... 8,999 11,778 13,041 14,713
Net income..................... 1,608 3,244 2,724 3,786
Net income per share........... .08 .15 .13 .17
1994
Revenues....................... $ 44,635 $ 48,088 $ 48,246 $ 44,683
Operating income............... 8,591 11,583 12,885 10,930
Net income..................... 2,468 3,937 4,403 3,121
Net income per share........... .12 .19 .21 .15
</TABLE>

9. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES

Results of Operations from Oil and Gas Producing Activities

The following sets forth certain information with respect to the Company's
results of operations from oil and gas producing activities for the years
ended December 31, 1995, 1994 and 1993. The Company began operations in
Argentina through various acquisitions in the last two quarters of 1995 (see
Note 6). Prior to 1995, all of the Company's oil and gas producing activities
were located in the United States.

<TABLE>
<CAPTION>
1995
---------------------------
U.S. ARGENTINA TOTAL 1994 1993
-------- --------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Revenues...................... $146,819 $13,435 $160,254 $141,357 $113,259
Production (lifting) costs.... 61,565 5,206 66,771 59,292 44,930
Depreciation, depletion and
amortization................. 45,730 4,115 49,845 43,831 31,695
-------- ------- -------- -------- --------
Results of operations before
income taxes................. 39,524 4,114 43,638 38,234 36,634
Income tax expense............ 12,332 -- 12,332 14,529 14,287
-------- ------- -------- -------- --------
Results of operations
(excluding corporate overhead
and interest costs).......... $ 27,192 $ 4,114 $ 31,306 $ 23,705 $ 22,347
======== ======= ======== ======== ========
</TABLE>

F-17
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Capitalized Costs and Costs Incurred Relating to Oil and Gas Producing
Activities

Prior to 1995, the Company had not incurred any significant costs outside of
the United States. The Company's net investment in oil and gas properties at
December 31, 1995 and 1994, was as follows:

<TABLE>
<CAPTION>
1995
----------------------------------
U.S. ARGENTINA OTHER TOTAL 1994
-------- --------- ------ -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Unproved properties not being
amortized...................... $ 8,505 $ -- $1,269 $ 9,774 $ 6,073
Proved properties being
amortized...................... 581,861 170,947 -- 752,808 496,748
-------- -------- ------ -------- --------
Total capitalized costs....... 590,366 170,947 1,269 762,582 502,821
Less accumulated depreciation,
depletion and amortization..... 190,593 4,115 -- 194,708 144,863
-------- -------- ------ -------- --------
Net capitalized costs......... $399,773 $166,832 $1,269 $567,874 $357,958
======== ======== ====== ======== ========
</TABLE>

The following sets forth certain information with respect to costs incurred
(exclusive of general support facilities) in the Company's oil and gas
activities during 1995, 1994 and 1993:

<TABLE>
<CAPTION>
1995
---------------------------------
U.S. ARGENTINA OTHER TOTAL 1994 1993
------- --------- ------ -------- ------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Acquisition:
Undeveloped properties. $ 6,415 $ -- $1,269 $ 7,684 $ 1,869 $ 610
Producing properties... 38,896 168,762 -- 207,658 36,544 123,906
Costs incurred:
Exploratory............ 2,037 -- -- 2,037 3,349 5,217
Development............ 40,801 2,185 -- 42,986 23,374 17,519
------- -------- ------ -------- ------- --------
Total costs incurred. $88,149 $170,947 $1,269 $260,365 $65,136 $147,252
======= ======== ====== ======== ======= ========
</TABLE>

F-18
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids 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 reserves
are those which are expected to be recovered through existing wells with
existing equipment and operating methods. The following is an analysis of the
Company's proved oil and gas reserves which are located in the United States
and Argentina (including its proportionate share of reserves of its limited
partnerships and joint venture) as estimated by the Company's independent
petroleum consultants, Netherland, Sewell & Associates, Inc.:

<TABLE>
<CAPTION>
U.S. ARGENTINA TOTAL
---------------- --------- ----------------
OIL GAS OIL OIL GAS
(MBBLS) (MMCF) (MBBLS) (MBBLS) (MMCF)
------- ------- --------- ------- -------
<S> <C> <C> <C> <C> <C>
Proved reserves at December 31,
1992............................. 40,209 206,582 -- 40,209 206,582
Revisions of previous estimates... (10) 18,381 -- (10) 18,381
Extensions, discoveries and other
additions........................ 35 4,183 -- 35 4,183
Production........................ (4,785) (22,504) -- (4,785) (22,504)
Purchase of reserves-in-place..... 27,898 68,000 -- 27,898 68,000
Sales of reserves-in-place........ (70) (1,500) -- (70) (1,500)
------ ------- ------ ------- -------
Proved reserves at December 31,
1993............................. 63,277 273,142 -- 63,277 273,142
Revisions of previous estimates... 8,577 4,131 -- 8,577 4,131
Extensions, discoveries and other
additions........................ 6 4,139 -- 6 4,139
Production........................ (6,657) (28,884) -- (6,657) (28,884)
Purchase of reserves-in-place..... 5,645 29,655 -- 5,645 29,655
Sales of reserves-in-place........ (59) (545) -- (59) (545)
------ ------- ------ ------- -------
Proved reserves at December 31,
1994............................. 70,789 281,638 -- 70,789 281,638
Revisions of previous estimates... 7,160 18,405 2,952 10,112 18,405
Extensions, discoveries and other
additions........................ 338 2,015 -- 338 2,015
Production........................ (6,647) (30,610) (961) (7,608) (30,610)
Purchase of reserves-in-place..... 8,840 39,486 65,653 74,493 39,486
Sales of reserves-in-place........ (253) (172) -- (253) (172)
------ ------- ------ ------- -------
Proved reserves at December 31,
1995............................. 80,227 310,762 67,644 147,871 310,762
====== ======= ====== ======= =======
Proved developed reserves at:
December 31, 1993............... 51,187 226,734 -- 51,187 226,734
====== ======= ====== ======= =======
December 31, 1994............... 55,037 220,112 -- 55,037 220,112
====== ======= ====== ======= =======
December 31, 1995............... 63,791 270,427 36,928 100,719 270,427
====== ======= ====== ======= =======
</TABLE>

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves (Unaudited)

The Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves ("Standardized Measure") is a disclosure
requirement under SFAS No. 69. The Standardized Measure does not purport to
present the fair market value of proved oil and gas reserves. This would
require consideration of expected future economic and operating conditions
which are not taken into account in calculating the Standardized Measure.

F-19
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Under the Standardized Measure, future cash inflows were estimated by
applying year-end prices, adjusted for fixed and determinable escalations, to
the estimated future production of year-end proved reserves. Future cash
inflows were reduced by estimated future production, development and
abandonment costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the Company's tax basis in the associated
proved oil and gas properties. Tax credits and permanent differences were also
considered in the future income tax calculation. Future net cash inflows after
income taxes were discounted using a 10 percent annual discount rate to arrive
at the Standardized Measure.

Prior to 1995, the Company did not have any oil and gas producing activities
outside the United States. Set forth below is the Standardized Measure
relating to proved oil and gas reserves at December 31, 1995 and 1994:

<TABLE>
<CAPTION>
1995
--------------------------------
U.S. ARGENTINA TOTAL 1994
---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Future cash inflows............. $1,786,545 $1,083,551 $2,870,096 $1,483,854
Future production costs......... 751,312 409,734 1,161,046 620,615
Future development and
abandonment costs.............. 118,784 119,916 238,700 112,877
---------- ---------- ---------- ----------
Future net cash inflows before
income tax expense............. 916,449 553,901 1,470,350 750,362
Future income tax expense....... 232,036 86,162 318,198 173,875
---------- ---------- ---------- ----------
Future net cash flows........... 684,413 467,739 1,152,152 576,487
10 percent annual discount for
estimated timing of cash flows. 224,078 191,528 415,606 190,766
---------- ---------- ---------- ----------
Standardized Measure of
discounted future net cash
flows.......................... $ 460,335 $ 276,211 $ 736,546 $ 385,721
========== ========== ========== ==========
</TABLE>

F-20
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves (Unaudited)

The following is an analysis of the changes in the Standardized Measure
during 1995, 1994 and 1993:

<TABLE>
<CAPTION>
1995 1994 1993
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized Measure--Beginning of year....... $385,721 $339,701 $274,443
Increases (decreases)--
Sales, net of production costs.............. (93,483) (82,065) (68,328)
Net change in sales price, net of production
costs...................................... 131,697 54,864 (101,453)
Discoveries and extensions, net of related
future development and production costs.... 4,585 4,724 6,495
Changes in estimated future development
costs...................................... (31,210) (17,276) (4,709)
Development costs incurred.................. 37,600 20,228 10,195
Revisions of previous quantity estimates.... 59,319 34,428 9,021
Accretion of discount....................... 44,699 35,078 33,594
Net change in income taxes.................. (86,296) (50,189) 50,421
Purchase of reserves-in-place............... 311,449 47,718 152,712
Sales of reserves-in-place.................. (661) (694) (1,838)
Timing of production of reserves and other.. (26,874) (796) (20,852)
-------- -------- --------
Standardized Measure--End of year............. $736,546 $385,721 $339,701
======== ======== ========
</TABLE>

F-21
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET
SEPTEMBER 30, 1996
(IN THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)
(UNAUDITED)

A S S E T S

<TABLE>
<S> <C>
CURRENT ASSETS:
Cash and cash equivalents............................................ $ 5,339
Accounts receivable--
Oil and gas sales................................................... 43,275
Joint operations.................................................... 5,360
Prepaids and other current assets.................................... 13,536
--------
Total current assets.............................................. 67,510
--------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, full cost method............................. 859,184
Oil and gas gathering systems........................................ 12,872
Other................................................................ 7,681
--------
879,737
Less accumulated depreciation, depletion and amortization............ 256,645
--------
623,092
--------
OTHER ASSETS, net..................................................... 10,756
--------
$701,358
========

L I A B I L I T I E S A N D S T O C K H O L D E R S' E Q U I T Y

CURRENT LIABILITIES:
Revenue payable...................................................... $ 18,910
Accounts payable--trade.............................................. 14,702
Other payables and accrued liabilities............................... 21,103
Current portion of long-term debt.................................... 7,929
--------
Total current liabilities......................................... 62,644
--------
LONG-TERM DEBT, less current portion above............................ 336,380
--------
DEFERRED INCOME TAXES................................................. 45,735
--------
OTHER LONG-TERM LIABILITIES........................................... 3,081
--------
MINORITY INTEREST IN SUBSIDIARY....................................... 2,286
--------
STOCKHOLDERS' EQUITY, per accompanying statement:
Preferred stock, $.01 par, 5,000,000 shares authorized, zero shares
issued and outstanding.............................................. --
Common stock, $.005 par, 40,000,000 shares authorized, 24,062,462 and
23,661,162 shares issued and outstanding............................ 120
Capital in excess of par value....................................... 152,121
Retained earnings.................................................... 98,991
--------
251,232
--------
$701,358
========
</TABLE>

See notes to unaudited consolidated financial statements.

F-22
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE
NINE MONTHS ENDED
SEPTEMBER 30,
------------------
1996 1995
-------- --------
<S> <C> <C>
REVENUES:
Oil and gas sales.......................................... $185,847 $112,809
Oil and gas gathering...................................... 15,310 8,472
Gas marketing.............................................. 21,519 13,631
Other income............................................... 659 1,461
-------- --------
223,335 136,373
-------- --------
COSTS AND EXPENSES:
Lease operating, including production taxes................ 67,606 47,520
Oil and gas gathering...................................... 12,838 6,636
Gas marketing.............................................. 19,885 12,210
General and administrative................................. 12,026 8,258
Depreciation, depletion, and amortization.................. 51,313 36,875
Interest................................................... 22,467 13,379
-------- --------
186,135 124,878
-------- --------
Income before provision for income taxes and minority
interest................................................ 37,200 11,495
PROVISION FOR INCOME TAXES:
Current.................................................... 2,061 687
Deferred................................................... 7,982 3,895
MINORITY INTEREST IN (INCOME) LOSS OF SUBSIDIARY............. (361) 662
-------- --------
NET INCOME................................................... $ 26,796 $ 7,575
======== ========
NET INCOME PER SHARE......................................... $ 1.10 $ .36
======== ========
Weighted average common shares and common equivalent shares
outstanding................................................. 24,454 21,322
</TABLE>

See notes to unaudited consolidated financial statements.

F-23
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1996
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)

<TABLE>
<CAPTION>
CAPITAL
COMMON STOCK IN EXCESS
------------- OF PAR RETAINED
SHARES AMOUNT VALUE EARNINGS TOTAL
------ ------ --------- -------- ---------
<S> <C> <C> <C> <C> <C>
BALANCE AT DECEMBER 31, 1995...... 23,661 $ 118 $ 149,725 $ 74,117 $ 223,960
Net income...................... -- -- -- 26,796 26,796
Exercise of warrants............ 306 2 1,530 -- 1,532
Exercise of stock options and
resulting tax effects.......... 96 -- 866 -- 866
Cash dividends declared
($.08 per share)............... -- -- -- (1,922) (1,922)
------ ----- --------- -------- ---------
BALANCE AT SEPTEMBER 30, 1996..... 24,063 $ 120 $ 152,121 $ 98,991 $ 251,232
====== ===== ========= ======== =========
</TABLE>

See notes to unaudited consolidated financial statements.

F-24
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
1996 1995
--------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.............................................. $ 26,796 $ 7,575
Adjustments to reconcile net income to cash provided by
operating activities--
Depreciation, depletion and amortization............... 51,313 36,875
Minority interest in income (loss) of subsidiary....... 361 (662)
Provision for deferred income taxes.................... 7,982 3,895
--------- ---------
86,452 47,683
Decrease (increase) in receivables..................... (3,763) 3,953
Increase (decrease) in payables and accrued
liabilities........................................... 4,340 (1,531)
Other.................................................. (4,082) (1,201)
--------- ---------
Cash provided by operating activities................ 82,947 48,904
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment--
Oil and gas properties................................. (92,441) (78,427)
Other property and equipment........................... (1,567) (775)
Purchase of additional interest in subsidiary........... (5,213) (41,594)
Other................................................... (1,478) (129)
--------- ---------
Cash used by investing activities.................... (100,699) (120,925)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock.................................... 1,753 129
Advances on revolving credit facility and other
borrowings............................................. 108,048 88,410
Payments on revolving credit facility and other
borrowings............................................. (87,614) (14,061)
Dividends paid.......................................... (2,514) (1,344)
Other................................................... 873 --
--------- ---------
Cash provided by financing activities................ 20,546 73,134
--------- ---------
Net increase in cash and cash equivalents................ 2,794 1,113
Cash and cash equivalents, beginning of period.......... 2,545 431
--------- ---------
Cash and cash equivalents, end of period................ $ 5,339 $ 1,544
========= =========
</TABLE>

See notes to unaudited consolidated financial statements.

F-25
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1995
(UNAUDITED)

1. GENERAL

The accompanying financial statements are unaudited. The consolidated
financial statements include the accounts of the Company and its wholly- and
majority-owned subsidiaries. Management believes that all material adjustments
(consisting of only normal recurring adjustments) necessary for a fair
presentation have been made. These financial statements and notes should be
read in conjunction with the 1995 audited financial statements and related
notes included elsewhere in this Prospectus. Certain reclassifications have
been made to the prior year financial statements to conform to the 1996
presentations. These reclassifications had no effect on previously reported
net income or cash flow.

2. SIGNIFICANT ACCOUNTING POLICIES

Statements of Cash Flows

During the nine months ended September 30, 1996 and 1995, cash payments for
interest totaled $19,141,953 and $14,161,441, respectively. During the nine
months ended September 30, 1996 and 1995, cash payments for U.S. Federal and
state income taxes totaled $700,000 and $545,453, respectively. Cash payments
for Argentina withholding taxes totaling $64,949 were made during the nine
months ended September 30, 1996. No cash payments were made for the nine
months ended September 30, 1995, for foreign income taxes.

Depreciation, Depletion, and Amortization

Amortization per equivalent barrel of the Company's U.S. oil and gas
properties for the nine months ended September 30, 1996 and 1995, was $3.76
and $3.87, respectively. Amortization per equivalent barrel of the Company's
Argentina oil and gas properties for the nine months ended September 30, 1996
and 1995, was $4.18 and $4.29, respectively. The Company had no Argentina
operations prior to July 1995.

Income Taxes

Deferred income taxes are provided on transactions which are recognized in
different periods for financial and tax reporting purposes. Such temporary
differences arise primarily from the deduction of certain oil and gas
exploration and development costs which are capitalized for financial
reporting purposes and differences in the methods of depreciation. The Company
follows the provisions of Statement of Financial Accounting Standards No. 109
when calculating the deferred income tax provision for financial purposes.

Earnings of the Company's foreign subsidiaries, Cadipsa S.A. and Vintage Oil
Argentina, Inc., are subject to Argentina income taxes. Due to significant
Argentina net operating loss carryforwards for both companies, the Company
does not expect to pay any foreign income taxes related to these subsidiaries
in 1996. No U.S. deferred tax liability has been recognized related to the
unremitted earnings of these foreign subsidiaries, as it is the Company's
intention, generally, to reinvest such earnings permanently.

F-26
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

3. LONG-TERM DEBT

Long-term debt at September 30, 1996, and December 31, 1995, consists of the
following:

<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1996 1995
------------- ------------
(IN THOUSANDS)
<S> <C> <C>
9% Senior Subordinated Notes Due 2005, net of
discount....................................... $ 149,623 $ 149,592
Bank revolving credit facility.................. 164,800 74,300
Bank term loan.................................. -- 36,736
5.92% Senior note............................... -- 9,948
Subsidiary debt (a)--
International Finance Corporation Notes....... 25,986 28,000
Bank of Boston Senior note.................... -- 20,000
Other subsidiary debt......................... 3,900 5,200
--------- ---------
344,309 323,776
Less--Current portion of long-term debt......... 7,929 7,930
--------- ---------
$ 336,380 $ 315,846
========= =========
</TABLE>
- --------
(a) Subsidiary debt relates to borrowings of the Company's international
subsidiaries and is non-recourse to the Company except for $9.2 million
advanced by the International Finance Corporation.

Bank Revolving Credit Facility

The Company has available an unsecured revolving credit facility under the
Credit Agreement dated August 29, 1996, as amended (the "Bank Facility"),
among the Company and certain banks. The Bank Facility establishes a borrowing
base (currently $305 million) based on the banks' evaluation of the Company's
U.S. and certain Argentina oil and gas reserves.

Outstanding advances under the Bank Facility bear interest payable quarterly
at a floating rate based on Bank of Montreal's alternate base rate (as
defined) or, at the Company's option, at a fixed rate for up to six months
based on the eurodollar market rate ("LIBOR"). The Company's interest rate
increments above the alternate base rate and LIBOR vary based on the level of
outstanding senior debt and the portion of the borrowing base attributable to
the U.S. reserves at the time. In addition, the Company must pay a commitment
fee ranging from 0.250 to 0.375 percent per annum on the unused portion of the
banks' commitment. Total outstanding advances at September 30, 1996, were
$164.8 million at an average interest rate of approximately 6.5 percent.

On a semiannual basis, the Company's borrowing base is redetermined by the
banks based upon their review of the Company's U.S. and certain Argentina oil
and gas reserves. If the sum of outstanding senior debt (excluding debt of the
Company's foreign subsidiaries) exceeds the borrowing base, as redetermined,
the Company must repay such excess. Any principal advances outstanding at
October 1, 1999, will be payable in 12 equal consecutive quarterly
installments commencing January 1, 2000, with maturity at October 1, 2002.

The terms of the Bank Facility impose certain restrictions on the Company
regarding the pledging of assets and limitations on, among other things,
additional indebtedness and the payment of dividends and other distributions.
In addition, the Bank Facility requires the maintenance of a minimum current
ratio (as defined) and tangible net worth (as defined) of $200 million plus 75
percent of net proceeds of any future equity offerings.

F-27
<PAGE>

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

4. SUBSEQUENT EVENTS

On November 5, 1996, the Province of Santa Cruz, Argentina brought suit
against Cadipsa S.A. in the Corte Suprema de Justicia de la Nacion (the
Supreme Court of Justice of the Argentine Republic, Buenos Aires, Argentina),
Dossier No. s-1451, seeking to recover approximately $10.6 million (which sum
includes interest) allegedly due as additional royalties on four concessions
granted in 1990 in which the Company currently owns a 100 percent working
interest. The Company and its predecessors in title have been paying royalties
at an eight percent rate; the Province of Santa Cruz claims the rate should be
12 percent. The amount of such claim will increase at the differential of
these royalty rates until this claim is resolved. With respect to the 50
percent interest in the two concessions that the Company acquired from British
Gas, plc, the Company believes that it is entitled to indemnification by
British Gas, plc for any loss sustained by the Company as a result of this
claim. Such indemnification equals approximately $4.0 million of the $10.6
million claim. The Company has no indemnification from its predecessors in
title with respect to the payment of royalties on the other two concessions.
Although the Company cannot predict the outcome of this litigation, based upon
the advice of counsel, the Company does not expect this claim to have a
material adverse impact on the Company's financial position or results of
operations.

On November 20, 1996, the Company purchased from Exxon Company, U.S.A.
certain producing oil and gas properties and facilities located in south
Alabama for approximately $28.2 million in cash, subject to post-closing
adjustments. Funds for this acquisition were provided by advances under the
Company's Bank Facility. The properties consist of all of Exxon's interests in
two fields totaling approximately 5,000 net acres located in Escambia County
in south Alabama and are now operated by the Company. Current net daily
production from the properties averages approximately 1,450 barrels of oil and
liquids and 2,800 Mcf of gas.

Also during November 1996, the Company agreed to purchase 100% of the
outstanding common stock of Shamrock Ventures Boliviana Ltd. ("Shamrock") from
affiliates of Ultramar Diamond Shamrock Corporation for $29.0 million in cash.
In addition, at closing on January 7, 1997, the Company repaid all of
Shamrock's existing bank debt (approximately $9.2 million). Funds for the
purchase of the stock and the repayment of debt were provided by advances
under the Company's Bank Facility. Shamrock's assets include (i) oil and gas
properties valued at $35.5 million (including the effect of approximately $6.6
million of deferred income taxes recorded under the purchase method of
accounting), and (ii) inventory, receivables, cash and other assets net of
liabilities (other than bank debt repaid at closing) of approximately $9.3
million. The Company has not completed its evaluations of the purchased assets
and assumed liabilities; therefore, it has not completed the final purchase
price allocation. The transaction is subject to government approval. The oil
and gas properties of Shamrock consist of three blocks in the Chaco Plains
area of southern Bolivia. The acquisition of Shamrock represents an extension
to the Company's South American operating area that was initially established
through a series of acquisitions in Argentina during 1995.

F-28
<PAGE>

- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------

NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY IN-
FORMATION OR TO MAKE ANY REPRESENTATION OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS IN CONNECTION WITH THE OFFER CONTAINED HEREIN, AND IF GIVEN OR
MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING
BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES NOT
CONSTITUTE AN OFFER TO SELL, OR A SOLICITATION OF AN OFFER TO BUY, SHARES OF
COMMON STOCK IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS NOT LAWFUL TO
MAKE ANY SUCH OFFER OR SOLICITATION IN SUCH JURISDICTION OR IN WHICH THE PER-
SON MAKING SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO. NEITHER THE
DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIR-
CUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS
OF THE COMPANY SINCE THE DATE HEREOF.

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TABLE OF CONTENTS

<TABLE>
<CAPTION>
Page
----
<S> <C>
Certain Definitions....................................................... 2
Incorporation of Documents by Reference................................... 2
Prospectus Summary........................................................ 3
Risk Factors.............................................................. 11
Forward-Looking Statements................................................ 15
Note Offering............................................................. 15
Use of Proceeds........................................................... 15
Capitalization............................................................ 16
Price Range of Common Stock and Dividends................................. 17
Selected Financial and Operating Data..................................... 18
Management's Discussion and Analysis of Financial Condition and Results of
Operations............................................................... 21
Recent Acquisitions....................................................... 29
Business.................................................................. 31
Management................................................................ 50
Description of Capital Stock.............................................. 53
Certain U.S. Tax Consequences to Non-U.S. Holders of Common Stock......... 55
Underwriting.............................................................. 58
Legal Matters............................................................. 59
Experts................................................................... 59
Available Information..................................................... 60
Index to Financial Statements............................................. F-1
</TABLE>

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[LOGO OF VINTAGE PETROLEUM, INC. APPEARS HERE]

VINTAGE PETROLEUM, INC.

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1,500,000 SHARES

COMMON STOCK

PROSPECTUS

JANUARY 31, 1997

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DILLON, READ & CO. INC.

SALOMON BROTHERS INC

SMITH BARNEY INC.

JOHNSON RICE & COMPANY L.L.C.

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