Annual Report — [x] Reg. S-K Item 405 — Form 10-K
Filing Table of Contents
Document/Exhibit Description Pages Size
1: 10-K405 Annual Report -- [x] Reg. S-K Item 405 42 244K
2: EX-4.3 Indenture Between Chase Manhattan and the Company 116 486K
3: EX-13 Portions of the Annual Report to Stockholders 26 188K
4: EX-21 Subsidiaries of the Company 1 6K
5: EX-23.1 Consent of Arthur Andersen LLP 1 6K
6: EX-23.2 Consent of Netherland, Sewell & Associates, Inc. 1 7K
7: EX-27 Financial Data Schedule 2 9K
8: EX-99.1 Letter Regarding U.S. Oil and Gas Reserve 4 19K
9: EX-99.2 Letter Regarding South America Oil and Gas Reserve 3 15K
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
COMMISSION FILE NUMBER 1-10578
VINTAGE PETROLEUM, INC.
(Exact name of registrant as specified in its charter
DELAWARE 73-1182669
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
4200 ONE WILLIAMS CENTER
TULSA, OKLAHOMA 74172
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (918) 592-0101
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -----------------------
Common Stock, $.005 Par Value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
As of March 17, 1997, 25,714,443 shares of the Registrant's Common Stock
were outstanding, and the aggregate market value of the Common Stock held by
non-affiliates was approximately $471,734,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Annual Report to Stockholders for the fiscal
year ended December 31, 1996, are incorporated by reference into Parts I and II
of this Form 10-K.
Portions of the Registrant's Proxy Statement for the Annual Meeting of
Stockholders to be held May 13, 1997, are incorporated by reference into Part
III of this Form 10-K.
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VINTAGE PETROLEUM, INC.
FORM 10-K
YEAR ENDED DECEMBER 31, 1996
TABLE OF CONTENTS
Page
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PART I
Items 1
and 2. Business and Properties....................................... 1
Item 3. Legal Proceedings............................................. 27
Item 4. Submission of Matters to a Vote of
Security-Holders.............................................. 28
Item 4A. Executive Officers of the Registrant.......................... 28
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................... 31
Item 6. Selected Financial Data....................................... 31
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations................. 31
Item 8. Financial Statements and Supplementary Data................... 31
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........................ 31
PART III
Item 10. Directors and Executive Officers of the Registrant............ 31
Item 11. Executive Compensation........................................ 31
Item 12. Security Ownership of Certain Beneficial
Owners and Management......................................... 31
Item 13. Certain Relationships and Related Transactions................ 31
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K................................................... 32
Signatures .............................................................. 36
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CERTAIN DEFINITIONS
AS USED IN THIS FORM 10-K:
Unless the context requires otherwise, all references to the "Company"
include Vintage Petroleum, Inc., its consolidated subsidiaries and its
proportionately consolidated general partner interests in various limited
partnerships and joint ventures.
"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 Form 10-K, 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. and do not reflect reductions for minority
interest ownership. The term "oil" includes crude oil, condensate and natural
gas liquids.
"Proved reserves" are estimated quantities of oil and gas which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. "Proved developed reserves" are those reserves which are expected
to be recovered through existing wells with existing equipment and operating
methods. "Proved undeveloped reserves" are those reserves which are expected to
be recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required.
FORWARD-LOOKING STATEMENTS
THIS FORM 10-K INCLUDES CERTAIN STATEMENTS THAT MAY BE DEEMED TO BE
"FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995. ALL STATEMENTS IN THIS FORM 10-K, OTHER THAN
STATEMENTS OF HISTORICAL FACTS, THAT ADDRESS ACTIVITIES, EVENTS OR DEVELOPMENTS
THAT THE COMPANY EXPECTS, BELIEVES OR ANTICIPATES WILL OR MAY OCCUR IN THE
FUTURE, INCLUDING THE DRILLING OF WELLS, RESERVE ESTIMATES, FUTURE PRODUCTION OF
OIL AND GAS, FUTURE CASH FLOWS, FUTURE RESERVE ACTIVITY AND OTHER SUCH MATTERS
ARE FORWARD-LOOKING STATEMENTS. ALTHOUGH THE COMPANY BELIEVES THE EXPECTATIONS
EXPRESSED IN SUCH FORWARD-LOOKING STATEMENTS ARE BASED ON REASONABLE ASSUMPTIONS
WITHIN THE BOUNDS OF ITS KNOWLEDGE OF ITS BUSINESS, SUCH STATEMENTS ARE NOT
GUARANTEES OF FUTURE PERFORMANCE AND ACTUAL RESULTS OR DEVELOPMENTS MAY DIFFER
MATERIALLY FROM THOSE IN THE FORWARD-LOOKING STATEMENTS.
FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE IN
FORWARD-LOOKING STATEMENTS INCLUDE: OIL AND GAS PRICES; EXPLOITATION AND
EXPLORATION SUCCESSES; CONTINUED AVAILABILITY OF CAPITAL AND FINANCING; GENERAL
ECONOMIC, MARKET OR BUSINESS CONDITIONS; ACQUISITION OPPORTUNITIES (OR LACK
THEREOF); CHANGES IN LAWS OR REGULATIONS; RISK FACTORS LISTED FROM TIME TO TIME
IN THE COMPANY'S REPORTS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION; AND
OTHER FACTORS. THE COMPANY ASSUMES NO OBLIGATION TO UPDATE PUBLICLY ANY
FORWARD-LOOKING STATEMENTS, WHETHER AS A RESULT OF NEW INFORMATION, FUTURE
EVENTS OR OTHERWISE.
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
GENERAL
Vintage Petroleum, Inc. (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 December 31, 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 gross acres in the Chaco Plains area of
southern Bolivia.
The Company owned interests in 3,032 gross (2,004 net) producing wells in
the United States as of December 31, 1996, of which approximately 81 percent are
operated by the Company. The Company owned interests in 642 gross (629 net)
producing wells in Argentina as of December 31, 1996, of which approximately 97
percent are operated by the Company. As of December 31, 1996, the Company's
properties had proved reserves of 242.1 MMBOE, comprised of 178.3 MMBbls of oil
and 382.8 Bcf of gas, with a present value of estimated future net revenues
before income taxes (utilizing a 10 percent discount rate) of $1.8 billion and a
standardized measure of discounted future net cash flows of $1.4 billion.
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 1994 through the fourth quarter of 1996, the Company
increased its average net daily production from 18,000 Bbls of oil to 35,800
Bbls of oil and from 78,500 Mcf of gas to 85,100 Mcf of gas. For the year ended
December 31, 1996, the Company generated revenues of $311.7 million and net
income of $41.2 million.
Financial information relating to the Company's industry segments is set
forth in "Note 8 to Consolidated Financial Statements - Segment Information"
which is incorporated by reference from pages 42 and 43 of the Company's 1996
Annual Report to Stockholders.
The Company was incorporated in Delaware on May 31, 1983. The Company's
principal office is located at 4200 One Williams Center, Tulsa, Oklahoma 74172,
and its telephone number is (918) 592-0101.
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RECENT DEVELOPMENTS
On February 5, 1997, the Company completed a public offering of 1,500,000
shares of its Common Stock, all of which were sold by the Company. The net
proceeds to the Company of approximately $47.1 million were used to repay a
portion of the existing indebtedness under the Company's revolving credit
facility.
Also on February 5, 1997, the Company issued $100 million of its 8 5/8%
Senior Subordinated Notes Due 2009 (the "8 5/8% Notes"). The 8 5/8% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after February 1, 2002. Upon a change in control (as defined) of the Company,
holders of the 8 5/8% Notes may require the Company to repurchase all or a
portion of the 8 5/8% Notes at a purchase price equal to 101 percent of the
principal amount thereof; plus accrued and unpaid interest. The 8 5/8% Notes
mature on February 1, 2009, with interest payable semiannually on February 1 and
August 1 of each year.
The 8 5/8% Notes are unsecured senior subordinated obligations of the
Company, rank subordinate in right of payment to all senior indebtedness (as
defined) and rank pari passu with the Company's 9% Senior Subordinated Notes Due
2005 (the "9% Notes"). The indenture for the 8 5/8% Notes contains limitations
similar to those contained in the indenture for the 9% Notes. The net proceeds
to the Company of approximately $96.4 million from the sale of the 8 5/8% Notes
were used to repay a portion of the existing indebtedness under the Company's
revolving credit facility.
In February 1997, the Company reached an agreement with subsidiaries of
Burlington Resources Inc. to purchase certain producing oil and gas properties
and facilities located in the Gulf Coast of Texas and Louisiana for $114.1
million in cash, subject to closing adjustments. The effective date of the
transaction is January 1, 1997, with closing scheduled for April 1, 1997,
subject to board approvals by the Company and Burlington Resources Inc. and
satisfaction of other normal conditions to closing.
The properties to be acquired consist of several onshore fields, 5 offshore
fields and a number of smaller fields covering over 74,000 net acres, about 46
percent of which are associated with offshore fields. The Company will operate
the properties which have current net daily production averaging approximately
5,200 Bbls of oil and 17,000 Mcf of gas. Key producing areas are the West
Ranch, Luling/Darst Creek and Terryville fields. West Ranch, located along the
Texas Gulf Coast, produces primarily oil from the Greta sandstone formation at
depths of 5,000 feet to 6,000 feet. Oil is also produced in the Luling/Darst
Creek fields in south central Texas from the Edwards limestone formation at
depths of less than 3,000 feet. Terryville, in north Louisiana, produces
principally gas from the Cotton Valley and Gray formations between 9,000 feet
and 13,000 feet.
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 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:
. 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,
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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, 1994, through
December 31, 1996, the Company acquired 120.7 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 2.9 times its production of 41.5 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, 1994, through December 31,
1996, the Company spent approximately $154.8 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 77 percent of these operations, and the
result of all of its exploitation activities, including development and
infill drilling, succeeded in replacing more than 125 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.
. 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, 1994, through December 31, 1996, the Company spent
approximately $38.6 million on exploration activities including the
drilling of 52 gross (29.51 net) exploration wells, of which
approximately 63 percent gross (60 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 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, 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. Additionally, the
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Company closed February 5, 1997, on its fourth public equity offering
and its second public debt offering. Net proceeds from these offerings
totaled approximately $143.5 million and were used to repay a portion of
existing indebtedness under the Company's revolving credit facility
thereby providing increased financial flexibility for future
acquisitions.
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, 1994, through December 31, 1996, the Company made oil and
gas property acquisitions involving total costs of approximately $335.5 million.
As a result of these acquisitions, the Company acquired approximately 120.7
MMBOE of proved oil and gas reserves. The following table summarizes the
Company's acquisition experience during the periods indicated:
[Enlarge/Download Table]
PROVED RESERVES WHEN ACQUIRED ACQUISITION
----------------------------- COST PER
ACQUISITION OIL GAS BOE WHEN
COSTS (MBbls) (MMcf) MBOE ACQUIRED
----------- ------- ------- ------ ----------
(In thousands)
U.S. Acquisitions
1994............................................. $ 36,544 5,645 29,655 10,588 $3.45
1995............................................. 38,896 8,840 39,486 15,421 2.52
1996............................................. 50,480 8,095 20,787 11,560 4.37
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Total U.S. Acquisitions....... 125,920 22,580 89,928 37,569 3.35
-------- ------ ------- ------- -----
Argentina Acquisitions
1995............................................. 168,762 65,653 - 65,653 2.57
1996............................................. 3,754 2,849 - 2,849 1.32
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Total Argentina Acquisitions.. 172,516 68,502 - 68,502 2.52
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Bolivia Acquisition
1996............................................. 37,048 4,953 57,758 14,579 2.54
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Total U.S. and International Acquisitions..... $335,484 96,035 147,686 120,650 $2.78
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The following is a brief discussion of significant acquisitions in recent
years:
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
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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
(the "Texaco Properties"). 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 S.A. ("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 Oil Argentina, Inc., formerly BG Argentina, S.A.
("Vintage Argentina") from British Gas plc, for $37.0 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 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 Company's
revolving credit 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.
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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 $28.5 million in cash, subject to post-closing adjustments
(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. 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.
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 revolving credit facility. Shamrock's assets include (a) oil and
gas properties valued at $37.0 million (including the effect of approximately
$7.0 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 $8.2
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 gross 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 Netherland,
Sewell, were 57.8 Bcf of gas and 5.0 MMBbls of oil. Current net daily production
is approximately 14,500 Mcf of gas and 230 Bbls of condensate. The recent
realized price on the properties for natural gas was approximately $1.39 per
Mcf. 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.
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.
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
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will be available to fund the Company's desired acquisitions. For additional
discussion of the Company's liquidity, see pages 29 and 30 of the Company's 1996
Annual Report to Stockholders.
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 other than the agreement with Burlington Resources Inc.
(see "--Recent Developments").
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 125 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 1996 totaled 29.5 MMBOE, or 171 percent
of the Company's production of 17.3 MMBOE.
From January 1, 1994, through December 31, 1996, the Company spent
approximately $65.8 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.
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, 1994, through December 31, 1996, the Company participated in
the drilling of 142 gross (99.15 net) development wells, of which approximately
90 percent gross (90 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 1996, the Company participated in the drilling of 68 gross (56.61
net) development wells. At December 31, 1996, the Company's proved reserves
included approximately 88 development or infill drilling locations on its U.S.
acreage and 160 locations on its Argentine acreage. In addition, the
-7-
Company has an extensive inventory of development and infill drilling locations
on its existing properties which are not included in proved reserves. The
Company spent approximately $43.3 million on development/infill drilling during
1996 and expects to spend approximately $45 million on its 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
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 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 Bbls of oil per day to a current
rate of approximately 2,750 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 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.
-8-
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. 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, 1994, through
December 31, 1996, the Company spent $38.6 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:
-9-
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 extensional 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 the
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 extensional 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 extensional 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 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
-10-
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 December 31, 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 December 31, 1996, the Company operated approximately 3,101
productive wells and also owned non-operating interests in 579 productive wells.
Oil and gas sales from the Company's producing properties accounted for
approximately 83 percent, 82 percent and 76 percent of the Company's revenues
for the years ended December 31, 1996, 1995 and 1994, respectively. 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.
The following table summarizes the Company's proved reserves in its 30
largest fields in the U.S., its five largest concessions in Argentina and its
largest concession in Bolivia at December 31, 1996, as estimated by Netherland,
Sewell. These fields and concessions represent approximately 76 percent of the
Company's proved reserves on such date.
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[Enlarge/Download Table]
LOCATION NET OIL NET GAS
AREA FIELD/CONCESSION NAME (COUNTY, STATE OR PROVINCE) (MBBLS) (MMCF) MBOE
-------------------------- ----------------------------- --------------------------- ------- ------- ------
West Coast San Miguelito Ventura, CA 17,753 4,580 18,516
South Mountain Ventura, CA 6,130 6,308 7,182
Rincon Ventura, CA 4,734 3,823 5,372
Ojai-Silverthread Ventura, CA 2,915 13,567 5,176
Santa Maria Valley/Cat Canyon Santa Barbara, CA 4,089 - 4,089
Buena Vista Hills Kern, CA 2,522 5,264 3,399
Pleito Ranch Kern, CA 2,993 1,212 3,195
North Tejon Kern, CA 1,701 8,440 3,108
Sespe Ventura, CA 2,690 2,433 3,096
Canfield Ranch Kern, CA 2,552 443 2,626
Zaca Santa Barbara, CA 2,101 - 2,101
Lathrop San Joaquin, CA - 11,475 1,913
Wheeler Ridge Kern, CA 1,352 2,029 1,690
North Antelope Hills Kern, CA 1,661 - 1,661
Tejon Kern, CA 1,532 143 1,556
Gulf Coast South Pass 24 Plaquemines, LA 2,500 10,009 4,168
Flomaton Escambia, AL 2,002 7,574 3,264
Tepetate Acadia, LA 2,305 1,017 2,475
Waveland Hancock, MS 249 10,827 2,053
Ville Platte Evangeline, LA 1,147 4,043 1,821
Pachuta Creek Clarke, MS 1,607 317 1,660
Fanny Church Escambia, AL 1,126 2,185 1,490
Trinity Bay Chambers, TX 1,310 1,022 1,481
East Texas South Gilmer Upshur, TX 762 26,147 5,120
Colgrade Winn, LA 3,960 - 3,960
Southern Pine Cherokee, TX - 22,132 3,689
Fruitvale Van Zandt, TX 21 20,308 3,405
Mid-Continent Shawnee Pottawatomie, OK 2,209 61 2,220
Booker Ochiltree, TX 1,775 92 1,791
Strong City Roger Mills, OK 53 10,149 1,745
San Jorge Basin, Argentina Canadon Minerales Santa Cruz Province 25,816 - 25,816
Las Heras/Piedra Clavada Santa Cruz Province 15,489 - 15,489
Canadon Seco Santa Cruz Province 11,547 - 11,547
Cerro Wenceslao Santa Cruz Province 9,205 - 9,205
Meseta Espinosa Santa Cruz Province 8,043 - 8,043
Chaco Plains, Bolivia Nupuco Tarija Department 860 45,236 8,399
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, 1996, the area comprised 32 percent of the
Company's total proved reserves and 53 percent of the Company's U.S. proved
reserves. The Company currently operates 1,171 productive wells with current
daily gross production of approximately 12,300 Bbls of mid-gravity oil, 2,050
Bbls of heavy oil and 27,100 Mcf of gas. In addition, the Company owns an
interest in 71 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
-12-
underway in three of the producing zones. With the field still producing in
excess of 3,300 gross Bbls of oil per day, the Company believes additional
waterflood potential exists in lower sands currently producing on primary
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. Current gross daily production of 1,100 Bbls of oil and 2,175
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 1,000 Bbls of oil and 900 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 current daily gross production exceeds 750 Bbls of oil and 3,200
Mcf of gas.
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 currently is in excess of 1,500 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.
Buena Vista Hills. The Buena Vista Hills field is located
-----------------
approximately 25 miles east of Bakersfield, California. Production is from the
Upper Channel, Main Massive and Interbed zones at a depth of 5,000 feet to 5,500
feet. The Company operates 24 productive wells in the field with a 100 percent
working interest. Daily gross production is 650 Bbls of oil and 400 Mcf of gas.
The Company
-13-
has an ongoing annual workover program in the field. Future projects include
continued recompletions, infill drilling and potential waterflooding.
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. 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 current gross production of approximately 600 Bbls of oil per day.
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. Current 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.
Gulf Coast Area. The Gulf Coast Area comprised approximately 14 percent
of the Company's December 31, 1996, 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 288 productive wells and owns
interests in an additional 166 productive wells in this area. Daily gross
production from the operated wells currently averages 7,000 Bbls of oil and
49,800 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.
South Pass 24. The South Pass 24 field is located in state waters
-------------
of Plaquemines Parish, Louisiana, at shallow water depths averaging 10 feet 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.
Flomaton. This field, purchased from Exxon in 1996, is located in
--------
Escambia County, Alabama, and produces from the Norphlet sand at 15,000 feet.
Company operated gross daily production is 600 Bbls of oil and 10,000 Mcf of gas
from nine wells. The Company anticipates significant reduction in operating
costs due to planned treating plant efficiency improvements. The Company is
also examining the feasibility of accelerating recovery through infill drilling.
Tepetate. The Tepetate field is located in Acadia Parish, Louisiana.
--------
The major producing sand is the Ortega A. The Company is the operator and owns a
100 percent working interest in the field. Over 20 productive sands are found in
the field, primarily in the Frio and Anahuac formations. The depths of the
producing sands range from 7,500 feet to 10,000 feet. The field currently
produces 1,000 Bbls of oil per day and 12,500 Bbls of water per day from 11
producing wells. The water is reinjected through four injection wells and one
disposal well. Several workovers and equipment changes have increased the
production from 500 Bbls of oil per day to the current level since acquisition
in February 1996.
Waveland. 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 3,500 Mcf of gas. This
-14-
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.
Ville Platte. The Ville Platte field is located in east-central
------------
Evangeline Parish, Louisiana. The field has 26 productive sands with six sands
currently producing. The Company acquired operating interest in the field in
February 1996. The Haas, Tate, and Wilcox 1 through 6 were unitized in 1951
into the Ville Platte Unit. The Company operates the Ville Platte Unit with a
77.8 percent working interest. Other current producing sands are the Middle and
Basal Cockfield reservoirs. The Company owns a 100 percent working interest in
most of the wells completed in the non-unitized sands. The depths of the
producing sands range from 8,000 feet to 12,000 feet. The field currently
produces 225 Bbls of oil per day from 15 wells.
East Texas Area. The East Texas Area comprised approximately eight percent
of the Company's December 31, 1996, 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 1,250 Bbls of oil and 27,600 Mcf of gas from 673 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.
Colgrade. The Colgrade field is located in Winn Parish, Louisiana
--------
and currently produces 750 Bbls of oil per day from the Wilcox formation at a
depth of 1,400 feet. The Company operates 437 active wells in this field. During
1996, a pilot project was initiated to increase fluid withdrawal rates from
these wells using submersible pumps. To date, 38 wells tested using such pumps
have indicated increased cumulative oil production of 144 Bbls per day.
Projecting this success to an additional 257 candidate wells should result in a
peak field rate in 1998 of 1,650 Bbls of oil per day, or an increase in excess
of 100 percent over the current rate. These submersible pumps are low cost and
replace conventional rod pump installations. Surface facilities are being
modified to handle the increased rates. The Company generally has a 100 percent
working interest and an 88 percent net revenue interest in this field.
Southern Pine. The Southern Pine field is located in Cherokee
-------------
County, Texas, and produces from the Travis Peak formation. 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 6,700 Mcf of gas.
-15-
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 six percent of the Company's total proved reserves as of December
31, 1996. The Company currently operates daily gross production of 4,200 Bbls of
oil and 28,400 Mcf of gas from 328 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 33 percent of the Company's December
31, 1996, total proved reserves. The Company currently operates 625 productive
wells (100 percent working interest) with daily gross production of 16,450 Bbls
of oil. In addition, the Company owns an interest in 17 productive wells
operated by others. At December 31, 1996, the Company's proved reserves included
approximately 160 development or infill drilling locations and 281 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 6,000 feet. This concession currently has 184 producing wells and
32 water injection wells with daily gross production of approximately 7,050 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 evelopment 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 feet 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 88
producing wells and five water injection wells with daily gross production of
approximately 1,200 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
-16-
have been tested. The proved undeveloped locations are generally infill
development locations in areas offsetting existing production.
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 79 producing wells and eight water injection wells with a daily
gross production of approximately 3,300 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 9 water injection wells with daily gross production of approximately
1,550 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 103
producing wells and 10 water injection wells with a daily gross production of
approximately 2,550 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.
Bolivia Concessions. The Bolivia properties consist of two producing
concessions and one exploration concession located in the Chaco Plains area of
southern Bolivia. The Company has a 100 percent working interest in the Chaco
exploration concession and the Porvenir producing concession. In the other
concession, Nupuco, the Company has a 50 percent working interest. The Company
operates all three concessions. These concessions comprise approximately six
percent of the Company's total proved reserves and include 6 gross (5.00 net)
active producing wells, all of which are operated by the Company. The current
daily gross production is approximately 35,000 Mcf of gas and 685 Bbls of
condensate.
Nupuco. The Nupuco field is located in the southern part of Bolivia
------
approximately 230 miles south of the city of Santa Cruz and approximately 60
miles north of the border with Argentina. The primary gas producing reservoirs
are the Triassic age Cangapi and the Carboniferious age San Telmo and
Escarpment. This field currently has 2 gross (1.00 net) active producing wells
with daily gross production of approximately 30 MMcf of gas and 600 Bbls of
condensate.
-17-
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. Gas marketing accounted for approximately 10
percent, 11 percent and 15 percent of the Company's revenues for the years ended
December 31, 1996, 1995 and 1994, respectively.
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 1996 was Texaco
Trading and Transportation, Inc. Such oil purchases amounted to approximately 15
percent of the Company's total revenues for 1996. No other purchaser of the
Company's oil or gas during 1996 exceeded 10 percent of the Company's total
revenues.
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 December 31, 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. Oil and gas gathering accounted for approximately 7 percent, 6
percent and 8 percent of the Company's revenues for the years ended December 31,
1996, 1995 and 1994, respectively.
-18-
RESERVES
At December 31, 1996, the Company had proved reserves, as estimated by
Netherland, Sewell, of 242.1 MMBOE, comprised of 178.3 MMBbls of oil and 382.8
Bcf of gas. The following table sets forth, at December 31, 1996, 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):
[Download Table]
Proved Reserves:
Future net revenues........................................ $3,140,212
Present value of future net revenues before income taxes,
discounted at 10 percent.................................. 1,807,137
Standardized measure of discounted future net cash flows... 1,392,841
Proved Developed Reserves:
Future net revenues........................................ 2,309,759
Present value of future net revenues before income taxes,
discounted at 10 percent.................................. 1,386,361
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, 1996, economic
conditions. The estimated future production is priced at prices prevailing at
December 31, 1996, 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, 1996, 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 10 to
Consolidated Financial Statements -Supplementary Financial Information for Oil
and Gas Producing Activities" which is incorporated by reference from pages 44
through 48 of the Company's 1996 Annual Report to Stockholders.
The following table sets forth estimates of the proved oil and gas reserves
of the Company at December 31, 1996, as evaluated by Netherland, Sewell:
[Enlarge/Download Table]
OIL (MBbls) GAS(MMcf)
------------------------------- --------------------------------- MBOE
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL TOTAL
--------- ----------- ------- --------- ----------- -------- -------
West Coast (a).... 51,240 11,081 62,321 87,952 6,149 94,101 78,005
Gulf Coast........ 16,434 2,022 18,456 86,074 12,833 98,907 34,941
East Texas........ 5,382 424 5,806 72,438 15,743 88,181 20,502
Mid-Continent..... 5,880 1,281 7,161 42,974 899 43,873 14,473
Other U.S......... 314 280 594 26 - 26 598
--------- ---------- ------- -------- --------- -------- -------
Total U.S...... 79,250 15,088 94,338 289,464 35,624 325,088 148,519
Argentina......... 46,582 32,423 79,005 - - - 79,005
Bolivia........... 1,007 3,946 4,953 51,276 6,482 57,758 14,580
--------- ---------- ------- -------- --------- -------- -------
Total Company.. 126,839 51,457 178,296 340,740 42,106 382,846 242,104
========= ========== ======= ======== ========= ======== =======
--------------
(a) Total proved oil reserves include 6.8 MMBbls of heavy oil located in the
Company's Santa Maria Valley/Cat Canyon, North Antelope Hills and Zaca
fields in California.
-19-
Estimates of the Company's 1996 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 74 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 Form 10-K 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 10 to
Consolidated Financial Statements -Supplementary Financial Information for Oil
and Gas Producing Activities" which is incorporated by reference from pages 44
through 48 of the Company's 1996 Annual Report to Stockholders.
PRODUCTIVE WELLS; DEVELOPED ACREAGE
The following table sets forth the Company's domestic and international
productive wells and developed acreage assignable to such wells at December 31,
1996:
[Download Table]
PRODUCTIVE WELLS
--------------------------------------
DEVELOPED ACREAGE OIL GAS TOTAL
-------------------- ------------ ---------- ------------
GROSS NET GROSS NET GROSS NET GROSS NET
--------- --------- ----- ----- ----- ---- ----- -----
U.S........ 574,163 317,674 2,107 1,631 925 373 3,032 2,004
Argentina.. 1,008,339 844,372 642 629 - - 642 629
Bolivia.... 84,014 72,895 - - 6 5 6 5
--------- --------- ----- ----- ----- ---- ----- -----
Total..... 1,666,516 1,234,941 2,749 2,260 931 378 3,680 2,638
========= ========= ===== ===== ===== ==== ===== =====
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, five 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:
-20-
[Download Table]
YEARS ENDED DECEMBER 31,
------------------------------
1996 1995 1994
--------- -------- ------
Production:
Oil (MBbls) -
U.S....................... 7,694 6,647 6,657
Argentina................. 4,245 961 -
Total..................... 11,939 7,608 6,657
Gas, all U.S. (MMcf)....... 32,366 30,610 28,884
Average sales prices:
Oil (per Bbl) -
U.S....................... $ 17.19 (a) $ 15.44 $ 13.53
Argentina................. 15.91 (a) 13.98 -
Total..................... 16.73 (a) 15.26 13.53
Gas, all U.S. (per Mcf).... 1.81 1.46 1.78
Production costs (per BOE):
U.S........................ 5.42 5.24 5.17
Argentina.................. 4.93 5.42 -
Total...................... 5.30 5.25 5.17
-----------
(a) The impact of oil hedges reduced the Company's 1996 U.S., Argentina and
total average oil prices per Bbl by $1.47, $2.96 and $2.00, 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.
UNDEVELOPED ACREAGE
At December 31, 1996, the Company held the following undeveloped acres
located in the United States, Ecuador and Bolivia. With respect to such United
States acreage held under leases, 96,950 gross (34,535 net) acres are held under
leases with primary terms that expire at varying dates through December 31,
2000, unless commercial production is commenced. The Ecuador and Bolivia
acreage are held under concessions with primary terms that expire at varying
dates in 1999. 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.
-21-
[Download Table]
GROSS NET
STATE/COUNTRY ACRES ACRES
----------------------------------- --------- -------
California.......................... 6,698 6,090
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............................... 52,506 13,985
--------- -------
Total U.S.......................... 102,559 39,378
Ecuador............................. 494,226 148,268
Bolivia............................. 485,552 485,552
--------- -------
Total Company...................... 1,082,337 673,198
========= =======
DRILLING ACTIVITY
During the periods indicated, the Company drilled or participated in
the drilling of the following exploratory and development wells:
[Download Table]
YEARS ENDED DECEMBER 31,
----------------------------------------
1996 1995 1994
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Development:
United States -
Productive............ 22 12.67 36 19.26 31 18.75
Non-Productive........ 5 2.94 5 3.49 2 1.04
Argentina -
Productive............ 39 39.00 - - - -
Non-Productive........ 2 2.00 - - - -
----- ----- ----- ----- ----- -----
Total................ 68 56.61 41 22.75 33 19.79
===== ===== ===== ===== ===== =====
Exploratory:
United States -
Productive............ 6 3.00 13 9.84 12 2.82
Non-Productive........ 7 3.12 5 2.69 5 4.04
Argentina -
Productive............ 2 2.00 - - - -
Non-Productive........ 1 1.00 - - - -
Other International -
Productive............ - - - - - -
Non-Productive........ 1 1.00 - - - -
----- ----- ----- ----- ----- -----
Total................ 17 10.12 18 12.53 17 6.86
===== ===== ===== ===== ===== =====
Total:
Productive............. 69 56.67 49 29.10 43 21.58
Non-Productive......... 16 10.06 10 6.18 7 5.07
----- ----- ----- ----- ----- -----
Total................. 85 66.73 59 35.28 50 26.65
===== ===== ===== ===== ===== =====
The above well information excludes wells in which the Company has only a
royalty interest.
-22-
At December 31, 1996, the Company was a participant in the drilling or
completion of 23 gross (19.63 net) wells. All of the Company's drilling
activities are conducted with independent contractors. The Company owns no
drilling equipment.
SEASONALITY
The results of operations of the Company are somewhat seasonal due to
seasonal fluctuations in the price for gas. Gas prices have been generally
higher in the fourth and first quarters. Due to these seasonal fluctuations,
results of operations for individual quarterly periods may not be indicative of
results which may be realized on an annual basis.
COMPETITION
Competition in the oil and gas industry is intense. Both in seeking to
obtain and acquire desirable producing properties, new leases and exploration
prospects, and in marketing oil and gas, the Company faces competition from both
major and independent oil and gas companies, as well as from numerous
individuals and drilling programs. Many of these competitors have financial and
other resources substantially in excess of those available to the Company.
Increases in worldwide energy production capability have brought about
substantial surpluses in energy supplies in recent years. This, in turn, has
resulted in substantial competition for markets historically served by domestic
gas resources from alternative sources of energy, such as residual fuel oil, and
among domestic gas suppliers. Changes in government regulations relating to the
production, transportation and marketing of gas have also resulted in
significant changes in the historical marketing patterns of the industry.
Generally, these changes have resulted in the abandonment by many pipelines of
long-term contracts for the purchase of gas, the development by gas producers of
their own marketing programs to take advantage of new regulations requiring
pipelines to transport gas for regulated fees, and the emergence of various
types of marketing companies and other aggregators of gas supplies. As a
consequence, gas prices, which were once effectively determined by government
regulations, are now largely established by competition. Competitors of the
Company in this market include other producers, gas pipelines and their
affiliated marketing companies, independent marketers, and providers of
alternate energy supplies, such as residual fuel oil.
Exploration for and production of oil and gas are affected by the
availability of pipe, casing and other tubular goods and certain other oil field
equipment, including drilling rigs and tools. The Company is dependent upon
independent drilling contractors to furnish rigs, equipment and tools to drill
the wells it operates. The Company has not experienced and does not anticipate
difficulty in obtaining supplies, materials, drilling rigs, equipment or tools.
Higher prices for oil and gas production, however, may cause competition for
these items to increase and may result in increased costs of operations.
RISKS OF INTERNATIONAL OPERATIONS
International investments represent approximately 39 percent of the
Company's total proved reserves at December 31, 1996, 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
-23-
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.
REGULATION
The oil and gas industry is extensively regulated by federal, state and
local authorities. Legislation affecting the oil and gas industry is under
constant review for amendment or expansion. Numerous departments and agencies,
both federal and state, have issued rules and regulations affecting the oil and
gas industry and its individual members, some of which carry substantial
penalties for the failure to comply. The regulatory burden on the oil and gas
industry increases its cost of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.
Exploration and Production. Exploration and production operations of the
Company are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells, and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled and the
plugging and abandoning of wells. The Company's operations are also subject to
various conservation regulations, including regulation of the size of drilling
and spacing units or proration units, the density of wells which may be drilled
and the unitization or pooling of oil and gas properties. In this regard, some
states allow the forced pooling or integration of lands and leases to facilitate
exploration, while other states rely on voluntary pooling of lands and leases.
In addition, state conservation laws establish maximum rates of production from
oil and gas wells, generally prohibit the venting or flaring of gas and impose
certain requirements regarding the ratability of production. The effect of
these regulations is to limit the amounts of oil and gas the Company can produce
from its wells and the number of wells or the locations at which the Company can
drill.
In March 1992, Oklahoma enacted legislation which further limits the daily
allowable of gas production during periods of low demand for gas. The Oklahoma
Corporation Commission sets production levels quarterly. The production of gas
from a single well is limited to the greater of a specified Mcf per day or a
percentage of the total daily production capacity of the well. Since March
1992, the daily Mcf has been between 750 and 1,000 Mcf and the total daily
production has ranged from 25 percent to 50 percent. Effective July 1, 1992,
the Texas Railroad Commission, which is the state agency that regulates oil and
gas production in Texas (the "TRC"), enacted new regulations that may limit the
rate at which oil and gas may be produced from the Company's Texas properties.
Under the new Texas rules, the TRC relies upon certain information filed monthly
by well operators, in addition to using historical production data for each well
during comparable past periods, to arrive at a production allowable. These
Texas and Oklahoma regulations and legislation have not had a significant impact
on the Company's operations. The Company cannot predict whether other states
will adopt similar regulations or legislation. The effect of such future
legislation and regulations may be to decrease the allowable daily production
and the revenues from gas properties, including properties that produce both oil
and gas. It is also possible that such future legislation and regulations may
result in a decrease in gas production in such states, which could exert upward
pressure on the price of gas.
-24-
Various federal, state and local laws and regulations covering the discharge
of materials into the environment, or otherwise relating to the protection of
the environment, may affect exploration, development and production operations
of the Company. For example, the discharge or substantial threat of a discharge
of oil by the Company into United States waters or onto an adjoining shoreline
may subject the Company to liability under the Oil Pollution Act of 1990 and
similar state laws. While liability under the Oil Pollution Act of 1990 is
limited under certain circumstances, such limits are so high that the maximum
liability would likely have a significant adverse effect on the Company. The
Company's operations generally will be covered by insurance which the Company
believes is adequate for these purposes. However, there can be no assurance
that such insurance coverage will always be in force or that, if in force, it
will adequately cover any losses or liability the Company may incur. The
Company is also subject to laws and regulations concerning occupational safety
and health. It is not anticipated that the Company will be required in the near
future to expend amounts that are material in the aggregate to the Company's
overall operations by reason of environmental or occupational safety and health
laws and regulations, but because such laws and regulations are frequently
changed, the Company is unable to predict the ultimate cost of compliance.
Certain of the Company's oil and gas leases are granted by the federal
government and administered by various federal agencies. Such leases require
compliance with detailed federal regulations and orders which regulate, among
other matters, drilling and operations on these leases and calculation of
royalty payments to the federal government. The Mineral Lands Leasing Act of
1920 places limitations on the number of acres under federal leases that may be
owned in any one state. While subject to this law, the Company does not have a
substantial federal lease acreage position in any state or in the aggregate.
The Mineral Lands Leasing Act of 1920 and related regulations also may restrict
a corporation from the holding of a federal onshore oil and gas lease if stock
of such corporation is owned by citizens of foreign countries which are not
deemed reciprocal under such Act. Reciprocity depends, in large part, on whether
the laws of the foreign jurisdiction discriminate against a United States
person's ownership of rights to minerals in such jurisdiction. The purchase of
shares in the Company by citizens of foreign countries who are not deemed to be
reciprocal under such Act could have an impact on the Company's ownership of
federal leases.
Marketing, Gathering and Transportation. Federal legislation and regulatory
controls have historically affected the price of the gas produced and sold by
the Company and the manner in which such production is marketed. Historically,
the transportation and sale for resale of gas in interstate commerce have been
regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural Gas
Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by
the Federal Energy Regulatory Commission ("FERC"). Since 1978, maximum selling
prices of certain categories of gas, whether sold in interstate or intrastate
commerce, were regulated pursuant to the NGPA. The NGPA established various
categories of gas and provided for graduated deregulation of price controls of
several categories of gas and the deregulation of sales of certain categories of
gas. All price deregulation contemplated under the NGPA has already taken
place. On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the
"Decontrol Act") was enacted. The Decontrol Act amended the NGPA to remove, as
of July 27, 1989, both price and nonprice controls from gas not subject to a
contract in effect on July 26, 1989. Gas under contract on July 26, 1989, was
decontrolled on the earlier of the termination of the contract or January 1,
1993. Gas from wells spudded after July 26, 1989, was decontrolled on May 15,
1991, even if those wells were still covered by an existing contract. In
December 1992, the FERC issued Order 547, which, effective January 7, 1993,
constitutes a blanket certificate of public convenience and necessity pursuant
to Section 7 of the NGA authorizing any company which is not an interstate
natural gas pipeline or an affiliate thereof to make sales for resale at
negotiated rates in interstate commerce of any category of gas that is subject
to the FERC's NGA jurisdiction.
As a result of such deregulation provisions, virtually all of the Company's
gas production is no longer subject to price regulation. Gas which has been
removed from price regulation is subject only
-25-
to that price contractually agreed upon between the producer and purchaser.
Under current market conditions, deregulated gas prices under recently
negotiated contracts tend to be substantially lower than most regulated price
ceilings that were previously prescribed by the NGPA.
In February 1988, the FERC issued Order No. 490, which promulgated new
abandonment regulations for expired, canceled or modified contracts involving
the sale of certain gas committed or dedicated to interstate commerce prior to
the enactment of the NGPA. The new rules largely eliminate delays and
regulatory burdens associated with securing approval to abandon gas service upon
termination or expiration of a contract for the sale of such gas. The new rules
also significantly facilitate certain pipelines' ability to discontinue
purchasing such gas under terms unfavorable to the pipeline in situations in
which the contract has expired or terminated, but abandonment authorization is
required to terminate the service. The Company has gas purchase agreements with
purchasers that have been abandoned pursuant to Order No. 490. Order No. 490 is
currently being challenged in the courts. The Company is unable to predict the
outcome of these proceedings, and is also unable to predict the consequences to
it of any possible future vacation of Order No. 490.
Commencing in 1985, the FERC promulgated a series of orders and regulations
adopting changes that significantly affect the transportation and marketing of
gas. These changes have been intended to foster competition in the gas industry
by, among other things, inducing or mandating that interstate pipeline companies
provide nondiscriminatory transportation services to producers, distributors and
other shippers (so-called "open access" requirements). The FERC has also sought
to expedite the certification process for new services, facilities, and
operations of those pipeline companies providing "open access" services. The
FERC's actions in these areas have been subject to extensive judicial review and
have generated significant industry comment and proposals for modifications to
existing regulations.
In April 1992 (and clarified in August 1992 and finalized in November 1992),
the FERC issued Order 636, a complex regulation which changed gas pipeline
operations, services and rates. Among other things, Order 636 required each
interstate pipeline company to "unbundle" its traditional wholesale services and
create and make available on an open and nondiscriminatory basis numerous
constituent services (such as gathering services, storage services, firm and
interruptible transportation services, and stand-by sales services) and to adopt
a new rate making methodology to determine appropriate rates for those services.
To the extent the pipeline company or its sales affiliate makes gas sales as a
merchant in the future, it will do so in direct competition with all other
sellers pursuant to private contracts; however, pipeline companies are not
required to remain "merchants" of gas, and many of the interstate pipeline
companies have or will become "transporters only." Each pipeline company had to
develop the specific terms of service in individual proceedings. The new rules
and various pipeline compliance filings are the subject of appeals and resulting
remand proceedings concerning certain issues. The Company cannot predict
whether and to what extent further FERC remand proceedings and judicial review
will affect these matters. Although the new regulations do not directly
regulate gas producers such as the Company, the availability of non-
discriminatory transportation services and the ability of pipeline customers to
modify or terminate their existing purchase obligations under these regulations
have greatly enhanced the ability of producers to market their gas directly to
end users and local distribution companies. In this regard, access to markets
through interstate gas pipelines is critical to the marketing activities of the
Company.
Under the NGA, gas gathering facilities are generally exempt from FERC
jurisdiction. Interstate transmission facilities are, on the other hand,
subject to FERC jurisdiction. The FERC has historically distinguished between
these types of activities on a very fact-specific basis which makes it difficult
to predict with certainty the status of the Company's gathering facilities.
While the FERC has not issued any order or opinion declaring the Company's
facilities as gathering rather than transmission facilities, the Company
believes that these systems meet the traditional tests that the FERC has used to
establish a pipeline status as a gatherer. Further, while some states provide
for the rate regulation
-26-
of pipelines engaged in the intrastate transportation of gas, such regulation
has not generally been applied against gatherers of gas. The Company's
gathering systems could be adversely affected should they be subjected in the
future to the application of such state or federal regulation.
As a result of Order 636 a number of interstate pipeline companies have (i)
"spun down" their gathering systems from regulated pipeline transportation
companies to unregulated affiliates, (ii) "spun-off" gathering systems to non-
related entities, and/or (iii) "refunctionalized" portions of their pipeline
facilities from transmission to gathering. In May 1994 (and clarified in
December 1994) FERC ruled that it generally does not have jurisdiction over
gathering facilities absent abuse involving the pipeline-affiliate relationship.
However, FERC directed pipelines spinning down or off their gathering systems to
include certain Order No. 497 standards of conduct in their tariffs and to enter
into continuity of service agreements with existing users or to execute a
"default contract" with users with whom they cannot reach agreement, with the
default contract to contain a minimum two-year term, use the pipeline gatherer's
then current rate (with an appropriate escalator clause) for existing customers
for similar service, and contain terms and conditions consistent with those
applicable to the pipeline's gathering service. In addition, the interstate
pipeline must seek authority under Section 7(b) of the NGA to abandon certified
gathering facilities and must file for authority under Section 4 of the NGA to
terminate gathering service from both certified and uncertified facilities. On
appeal, FERC's decisions were generally upheld, except the court held that FERC
did not have the authority to require an unregulated entity to implement
"default contracts" and therefore remanded this aspect back to FERC. A
consequence of this divestiture of gathering facilities could be separate, and
higher, gathering fees.
With respect to oil pipeline rates subject to the FERC's jurisdiction, in
October 1993 the FERC issued Order 561 to fulfill the requirements of Title
XVIII of the Energy Policy Act of 1992. Order 561 established an indexing
system, effective January 1, 1995, under which oil pipelines will be able to
readily change their rates to track changes in the Producer Price Index for
Finished Goods (PPI-FG), minus one percent. This index established ceiling
levels for rates. Order 561 also permits cost-of-service proceedings to
establish just and reasonable rates. The order does not alter the right of a
pipeline to seek FERC authorization to charge market-based rates. However,
until the FERC makes the finding that the pipeline does not exercise significant
market power, the pipeline's rates cannot exceed the applicable index ceiling
level or a level justified by the pipeline's cost of service.
EMPLOYEES
The Company employs approximately 193 people in its Tulsa office whose
functions are associated with management, engineering, geology, land and legal,
accounting, financial planning, and administration. In addition, approximately
171 full time employees are responsible for the supervision and operation of its
U.S. field activities. The Company also has approximately 136 employees located
in South America for the management and operation of its properties in Argentina
and Bolivia. The Company believes its relations with its employees are
excellent.
ITEM 3. 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
-27-
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 various 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.
There were no matters submitted to the Company's stockholders during the
fourth quarter of the fiscal year ended December 31, 1996.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT.
The following table sets forth certain information regarding the executive
officers of the Company. Officers are elected annually by the Board of Directors
and serve at its discretion.
[Enlarge/Download Table]
NAME AGE POSITION
--------------------------- --- -----------------------------------------------------
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 Treasurer and Secretary
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....... 55 Vice President--Production
Larry W. Sheppard.......... 42 Vice President--International
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 also
serves as a Director of AAON, Inc. 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
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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.
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-
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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 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.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The information required by this Item is incorporated by reference from the
sections on page 51 of the Company's 1996 Annual Report to Stockholders entitled
"Stock Price Information," "Dividend Policy" and "Number of Stockholders."
ITEM 6. SELECTED FINANCIAL DATA.
The information required by this Item is incorporated by reference from page
25 of the Company's 1996 Annual Report to Stockholders.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The information required by this Item is incorporated by reference from
pages 26 through 30 of the Company's 1996 Annual Report to Stockholders.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this Item is incorporated by reference from
pages 31 through 49 of the Company's 1996 Annual Report to Stockholders.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this Item with respect to the Company's
directors is incorporated by reference from the sections of the Company's
definitive Proxy Statement for its 1997 Annual Meeting of Stockholders (the
"Proxy Statement") entitled "Election of Directors" and "Section 16(a)
Beneficial Ownership Reporting Compliance." The information required by this
Item with respect to the Company's executive officers appears at Item 4A of Part
I of this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item is incorporated by reference from the
section of the Proxy Statement entitled "Executive Compensation."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item is incorporated by reference from the
section of the Proxy Statement entitled "Principal Stockholders and Security
Ownership of Management."
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this Item is incorporated by reference from the
section of the Proxy Statement entitled "Certain Transactions."
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) (1) Financial Statements:
The financial statements of the Company and its subsidiaries and report of
independent public accountants listed below are incorporated by reference from
the following pages of the Company's 1996 Annual Report to Stockholders:
Annual Report
Page
-------------
Consolidated Balance Sheets as of December 31, 1996 and 1995..... 31
Consolidated Statements of Income for the years ended
December 31, 1996, 1995 and 1994.............................. 32
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1996, 1995 and 1994.......... 33
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994.............................. 34
Notes to Consolidated Financial Statements for the years ended
December 31, 1996, 1995 and 1994.............................. 35 through 48
Report of Independent Public Accountants......................... 49
(2) Financial Statement Schedules:
All schedules are omitted as inapplicable or because the required
information is contained in the financial statements or included in the
footnotes thereto.
(3) Exhibits:
The following documents are included as exhibits to this Form 10-K. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, such exhibit is filed herewith.
3.1 Restated Certificate of Incorporation of the Company (Filed as
Exhibit 3.1 to the Company's Registration Statement on Form S-1,
Registration No. 33-35289 (the "S-1 Registration Statement")).
3.2 Restated By-laws of the Company (Filed as Exhibit 3.2 to the S-1
Registration Statement).
4.1 Form of stock certificate for Common Stock, par value $.005 per
share (Filed as Exhibit 4.1 to the S-1 Registration Statement).
4.2 Indenture dated as of December 20, 1995, between Chemical Bank, as
Trustee, and the Company (Filed as Exhibit 99.1 to the Company's
report on Form 8-K filed January 16, 1996).
4.3 Indenture dated as February 5, 1997, between The Chase Manhattan
Bank, as Trustee, and the Company.
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10.1* Employment and Noncompetition Agreement dated January 7, 1987,
between the Company and Charles C. Stephenson, Jr. (Filed as Exhibit
10.19 to the S-1 Registration Statement).
10.2* Employment and Noncompetition Agreement dated January 7, 1987,
between the Company and Jo Bob Hille (Filed as Exhibit 10.20 to the
S-1 Registration Statement).
10.3* Employment Agreement dated September 19, 1995, between the Company
and Robert E. Phaneuf (Filed as Exhibit 10.3 to the Company's report
on Form 10-K for the year ended December 31, 1995, filed April 1,
1996).
10.4* Form of Indemnification Agreement between the Company and certain of
its officers and directors (Filed as Exhibit 10.23 to the S-1
Registration Statement).
10.5* Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 4(d) to
the Company's Registration Statement on Form S-8, Registration No.
33-37505).
10.6* Amendment No. 1 to Vintage Petroleum, Inc. 1990 Stock Plan,
effective January 1, 1991 (Filed as Exhibit 10.15 to the Company's
report on Form 10-K for the year ended December 31, 1991, filed
March 30, 1992).
10.7* Amendment No. 2 to Vintage Petroleum, Inc. 1990 Stock Plan dated
February 24, 1994 (Filed as Exhibit 10.15 to the Company's report on
Form 10-K for the year ended December 31, 1993, filed March 29,
1994).
10.8* Amendment No. 3 to Vintage Petroleum, Inc. 1990 Stock Plan dated
March 15, 1996 (Filed as Exhibit A to the Company's Proxy Statement
for Annual Meeting of Stockholders dated April 1, 1996).
10.9* Vintage Petroleum, Inc. 401(k) Plan (Filed as Exhibit 4(c) to the
Company's Registration Statement on Form S-8, Registration No. 33-
55706).
10.10* Vintage Petroleum, Inc. Non-Management Director Stock Option Plan
(Filed as Exhibit 10.18 to the Company's report on Form 10-K for the
year ended December 31, 1992, filed March 31, 1993 (the "1992 Form
10-K")).
10.11* Form of Incentive Stock Option Agreement under the Vintage
Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the
Company's report on Form 10-K for the year ended December 31, 1990,
filed April 1, 1991).
10.12* Form of Non-Qualified Stock Option Agreement under the Vintage
Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the 1992
Form 10-K).
10.13 Credit Agreement dated August 29, 1996, among the Company, as
borrower, certain commercial lending institutions, as lenders, and
Bank of Montreal, as agent (Filed as Exhibit 10.1 to the Company's
report on Form 10-Q for the quarter ended September 30, 1996, filed
November 7, 1996).
10.14 First Amendment to Credit Agreement (Exhibit No. 10.13 above) dated
October 21, 1996, among the Company, as borrower, certain commercial
lending institutions, as lenders, and Bank of Montreal, as agent
(Filed as Exhibit 10.2 to the Company's report on Form 10-Q for the
quarter ended September 30, 1996, filed November 7, 1996).
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10.15 Second Amendment to Credit Agreement (Exhibit No. 10.13 above) dated
January 9, 1997, among the Company, as borrower, certain commercial
lending institutions, as lenders, and Bank of Montreal, as agent
(Filed as Exhibit 99 to the Company's Registration Statement on Form
S-3, Registration No. 333-19569).
10.16 Assignment Agreement dated November 3, 1995, between Shell Compania
Argentina de Petroleo S.A. and Vintage Petroleum Argentina, Inc.
(Filed as Exhibit 2.1 to the Company's Registration Statement on
Form S-3, Registration No. 33-97844 (the "S-3 Registration
Statement")).
10.17 Assignment Agreement dated November 3, 1995, between Astra Compania
Argentina de Petroleo S.A. and Vintage Petroleum Argentina, Inc.
(Filed as Exhibit 2.2 to the S-3 Registration Statement).
10.18 Cadipsa Main Purchase Agreement dated June 2, 1995, between certain
shareholders of Cadipsa S.A. listed in Annex 1 thereto and Vintage
Petroleum Argentina, Inc. (Filed as Exhibit 2.1 to the Company's
report on Form 8-K filed July 20, 1995).
10.19 Purchase Agreement dated June 2, 1995, between certain shareholders
of Cadipsa S.A. listed in Annex 1 thereto and Vintage Petroleum,
Argentina Inc. (Filed as Exhibit 2.2 to the Company's report on Form
8-K filed July 20, 1995).
10.20 Amended and Restated Investment Agreement dated April 28, 1994,
between Cadipsa S.A. and International Finance Corporation ("IFC")
(Filed as Exhibit 99.1 to the S-3 Registration Statement).
10.21 Rescheduling, Amendatory and Temporary Guarantee Agreement dated
September 28, 1995, between Cadipsa S.A. and the Company and IFC
(Filed as Exhibit 99.2 to the S-3 Registration Statement).
10.22 Purchase Agreement dated September 28, 1995, between IFC and Vintage
Petroleum Argentina, Inc. (Filed as Exhibit 99.3 to the S-3
Registration Statement).
10.23 British Gas BGA Purchase Agreement dated September 28, 1995, between
British Gas plc and Vintage Petroleum Argentina, Inc. (Filed as
Exhibit 2.1 to the Company's report on Form 8-K filed October 4,
1995).
13. Portions of the Company's 1996 Annual Report to Stockholders.
21. Subsidiaries of the Company.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Netherland, Sewell & Associates, Inc.
27. Financial Data Schedule.
99.1 Letter of Netherland, Sewell & Associates, Inc. dated March 17,
1997, regarding U.S. oil and gas reserve information.
99.2 Letter of Netherland, Sewell & Associates, Inc. dated March 24,
1997, regarding South American oil and gas reserve information.
-----------------------
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* Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the fourth quarter of the fiscal
year ended December 31, 1996.
-35-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
VINTAGE PETROLEUM, INC.
Date: March 27, 1997 By: /s/ C. C. Stephenson, Jr.
--------------------------------
C. C. Stephenson, Jr.
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated:
[Enlarge/Download Table]
SIGNATURE TITLE DATE
--------- ----- ----
/s/ C. C. Stephenson, Jr. Director and Chairman of the Board March 27, 1997
----------------------------
C. C. Stephenson, Jr.
/s/ Jo Bob Hille Director, Vice Chairman of the March 27, 1997
---------------------------- Board and Chief Executive Officer
Jo Bob Hille (Principal Executive Officer)
/s/ S. Craig George Director, President and March 27, 1997
---------------------------- Chief Operating Officer
S. Craig George
/s/ William C. Barnes Director, Executive Vice President, March 27, 1997
---------------------------- Chief Financial Officer and
William C. Barnes Treasurer (Principal Financial Officer)
/s/ Bryan H. Lawrence Director March 27, 1997
----------------------------
Bryan H. Lawrence
/s/ John T. McNabb, II Director March 27, 1997
----------------------------
John T. McNabb, II
/s/ Michael F. Meimerstorf Vice President and Controller March 27, 1997
---------------------------- (Principal Accounting Officer)
Michael F. Meimerstorf
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INDEX TO EXHIBITS
The following documents are included as exhibits to this Form 10-K. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, such exhibit is filed herewith.
EXHIBIT
NUMBER DESCRIPTION
------ -----------
3.1 Restated Certificate of Incorporation of the Company (Filed as
Exhibit 3.1 to the Company's Registration Statement on Form S-1,
Registration No. 33-35289 (the "S-1 Registration Statement")).
3.2 Restated By-laws of the Company (Filed as Exhibit 3.2 to the S-1
Registration Statement).
4.1 Form of stock certificate for Common Stock, par value $.005 per
share (Filed as Exhibit 4.1 to the S-1 Registration Statement).
4.2 Indenture dated as of December 20, 1995, between Chemical Bank,
as Trustee, and the Company (Filed as Exhibit 99.1 to the
Company's report on Form 8-K filed January 16, 1996).
4.3 Indenture dated as February 5, 1997, between The Chase Manhattan
Bank, as Trustee, and the Company.
10.1* Employment and Noncompetition Agreement dated January 7, 1987,
between the Company and Charles C. Stephenson, Jr. (Filed as
Exhibit 10.19 to the S-1 Registration Statement).
10.2* Employment and Noncompetition Agreement dated January 7, 1987,
between the Company and Jo Bob Hille (Filed as Exhibit 10.20 to
the S-1 Registration Statement).
10.3* Employment Agreement dated September 19, 1995, between the
Company and Robert E. Phaneuf (Filed as Exhibit 10.3 to the
Company's report on Form 10-K for the year ended December 31,
1995, filed April 1, 1996).
10.4* Form of Indemnification Agreement between the Company and
certain of its officers and directors (Filed as Exhibit 10.23 to
the S-1 Registration Statement).
10.5* Vintage Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 4(d)
to the Company's Registration Statement on Form S-8,
Registration No. 33-37505).
10.6* Amendment No. 1 to Vintage Petroleum, Inc. 1990 Stock Plan,
effective January 1, 1991 (Filed as Exhibit 10.15 to the
Company's report on Form 10-K for the year ended December 31,
1991, filed March 30, 1992).
10.7* Amendment No. 2 to Vintage Petroleum, Inc. 1990 Stock Plan dated
February 24, 1994 (Filed as Exhibit 10.15 to the Company's
report on Form 10-K for the year ended December 31, 1993, filed
March 29, 1994).
10.8* Amendment No. 3 to Vintage Petroleum, Inc. 1990 Stock Plan dated
March 15, 1996 (Filed as Exhibit A to the Company's Proxy
Statement for Annual Meeting of Stockholders dated April 1,
1996).
10.9* Vintage Petroleum, Inc. 401(k) Plan (Filed as Exhibit 4(c) to
the Company's Registration Statement on Form S-8, Registration
No. 33-55706).
10.10* Vintage Petroleum, Inc. Non-Management Director Stock Option
Plan (Filed as Exhibit 10.18 to the Company's report on Form 10-
K for the year ended December 31, 1992, filed March 31, 1993
(the "1992 Form 10-K")).
10.11* Form of Incentive Stock Option Agreement under the Vintage
Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the
Company's report on Form 10-K for the year ended December 31,
1990, filed April 1, 1991).
10.12* Form of Non-Qualified Stock Option Agreement under the Vintage
Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the
1992 Form 10-K).
10.13 Credit Agreement dated August 29, 1996, among the Company, as
borrower, certain commercial lending institutions, as lenders,
and Bank of Montreal, as agent (Filed as Exhibit 10.1 to the
Company's report on Form 10-Q for the quarter ended September
30, 1996, filed November 7, 1996).
10.14 First Amendment to Credit Agreement (Exhibit No. 10.13 above)
dated October 21, 1996, among the Company, as borrower, certain
commercial lending institutions, as lenders, and Bank of
Montreal, as agent (Filed as Exhibit 10.2 to the Company's
report on Form 10-Q for the quarter ended September 30, 1996,
filed November 7, 1996).
10.15 Second Amendment to Credit Agreement (Exhibit No. 10.13 above)
dated January 9, 1997, among the Company, as borrower, certain
commercial lending institutions, as lenders, and Bank of
Montreal, as agent (Filed as Exhibit 99 to the Company's
Registration Statement on Form S-3, Registration No. 333-19569).
10.16 Assignment Agreement dated November 3, 1995, between Shell
Compania Argentina de Petroleo S.A. and Vintage Petroleum
Argentina, Inc. (Filed as Exhibit 2.1 to the Company's
Registration Statement on Form S-3, Registration No. 33-97844
(the "S-3 Registration Statement")).
10.17 Assignment Agreement dated November 3, 1995, between Astra
Compania Argentina de Petroleo S.A. and Vintage Petroleum
Argentina, Inc. (Filed as Exhibit 2.2 to the S-3 Registration
Statement).
10.18 Cadipsa Main Purchase Agreement dated June 2, 1995, between
certain shareholders of Cadipsa S.A. listed in Annex 1 thereto
and Vintage Petroleum Argentina, Inc. (Filed as Exhibit 2.1 to
the Company's report on Form 8-K filed July 20, 1995).
10.19 Purchase Agreement dated June 2, 1995, between certain
shareholders of Cadipsa S.A. listed in Annex 1 thereto and
Vintage Petroleum, Argentina Inc. (Filed as Exhibit 2.2 to the
Company's report on Form 8-K filed July 20, 1995).
10.20 Amended and Restated Investment Agreement dated April 28, 1994,
between Cadipsa S.A. and International Finance Corporation
("IFC") (Filed as Exhibit 99.1 to the S-3 Registration
Statement).
10.21 Rescheduling, Amendatory and Temporary Guarantee Agreement dated
September 28, 1995, between Cadipsa S.A. and the Company and IFC
(Filed as Exhibit 99.2 to the S-3 Registration Statement).
10.22 Purchase Agreement dated September 28, 1995, between IFC and
Vintage Petroleum Argentina, Inc. (Filed as Exhibit 99.3 to the
S-3 Registration Statement).
10.23 British Gas BGA Purchase Agreement dated September 28, 1995,
between British Gas plc and Vintage Petroleum Argentina, Inc.
(Filed as Exhibit 2.1 to the Company's report on Form 8-K filed
October 4, 1995).
13. Portions of the Company's 1996 Annual Report to Stockholders.
21. Subsidiaries of the Company.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Netherland, Sewell & Associates, Inc.
27. Financial Data Schedule.
99.1 Letter of Netherland, Sewell & Associates, Inc. dated March 17,
1997, regarding U.S. oil and gas reserve information.
99.2 Letter of Netherland, Sewell & Associates, Inc. dated March 24,
1997, regarding South American oil and gas reserve information.
---------------------------
* Management contract or compensatory plan or arrangement.
Dates Referenced Herein and Documents Incorporated by Reference
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