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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, 1997
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
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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
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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. [_]
As of March 17, 1998, 51,636,086 shares of the Registrant's Common Stock
were outstanding, and the aggregate market value of the Common Stock held by
non-affiliates was approximately $683,917,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Annual Report to Stockholders for the fiscal
year ended December 31, 1997, 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 12, 1998, 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, 1997
TABLE OF CONTENTS
Page
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PART I
Items 1
and 2. Business and Properties........................................ 1
Item 3. Legal Proceedings.............................................. 26
Item 4. Submission of Matters to a Vote of
Security-Holders............................................... 27
Item 4A. Executive Officers of the Registrant........................... 27
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters................................ 30
Item 6. Selected Financial Data........................................ 30
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.................. 30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 30
Item 8. Financial Statements and Supplementary Data.................... 30
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......................... 30
PART III
Item 10. Directors and Executive Officers of the Registrant............. 30
Item 11. Executive Compensation......................................... 30
Item 12. Security Ownership of Certain Beneficial
Owners and Management.......................................... 30
Item 13. Certain Relationships and Related Transactions................. 31
PART IV
Item 14. Exhibits, Financial Statement Schedules
and Reports on Form 8-K........................................ 31
Signatures................................................................. 34
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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/o/ 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 FUTURE CAPITAL EXPENDITURES (INCLUDING THE AMOUNT AND NATURE
THEREOF), 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 1998 of
approximately $65 million represent 35 percent of the Company's 1998 capital
budget, excluding acquisitions.
At December 31, 1997, the Company owned and operated producing properties in
10 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 and the first half of 1997, the Company expanded its
Gulf Coast area through the acquisition of the Exxon Properties, the Conoco
Properties and the Burlington Properties. See "--Acquisition Activities." 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 in 1996 expanded
its South American operations into Bolivia through the acquisition of Vintage
Petroleum Boliviana Ltd. (formerly Shamrock Ventures (Boliviana) Ltd.) ("Vintage
Boliviana") which owns and operates three blocks covering approximately 570,000
acres in the Chaco Plains area of southern Bolivia. During 1997, the Company
enhanced its operations in Bolivia by obtaining the concession rights to the
Naranjillos concession located in the Santa Cruz Province.
As of December 31, 1997, the Company owned interests in 3,815 gross (2,778
net) producing wells in the United States, of which approximately 78 percent are
operated by the Company, 699 gross (686 net) producing wells in Argentina, of
which approximately 98 percent are operated by the Company, and 7 gross (6 net)
producing wells in Bolivia, 100 percent of which are operated by the Company.
As of December 31, 1997, the Company's properties had proved reserves of 279.8
MMBOE, comprised of 187.8 MMBbls of oil and 552.2 Bcf of gas, with a present
value of estimated future net revenues before income taxes (utilizing a 10
percent discount rate) of $1.2 billion and a standardized measure of discounted
future net cash flows of $1.0 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 1995 through the fourth quarter of 1997, the Company
increased its average net daily production from 17,000 Bbls of oil to 44,700
Bbls of oil and from 77,000 Mcf of gas to 129,700 Mcf of gas.
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 page 45 of the Company's 1997 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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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, 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, 1995, through
December 31, 1997, the Company acquired 164.4 MMBOE of proved oil and
gas reserves at an average acquisition cost of $2.67 per BOE, which is
significantly below the industry average. The Company replaced through
acquisitions approximately 3.1 times its production of 52.6 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, 1995, through December 31,
1997, the Company spent approximately $227.9 million on exploitation and
development activities. During this period, the Company's recompletion
and workover activities resulted in improved production or operating
efficiencies in approximately 75 percent of these operations, and the
result of all of its exploitation activities, including development and
infill drilling, succeeded in replacing approximately 81 percent of
production during this period. The Company has an extensive inventory of
exploitation and development opportunities including identified projects
which represent an inventory of over 10 years at current activity
levels. The Company anticipates spending approximately $45 million in
the United States and approximately $75 million in Argentina and Bolivia
during 1998 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, 1995, through December 31, 1997, the Company spent
approximately $64.6 million on exploration activities, including the
drilling of 50 gross (29.95 net) exploration wells, of which
approximately 56 percent gross (60 percent net) were productive. The
Company has increased its exploration budget to approximately $65
million in 1998, with spending planned in its core areas in the United
States and Argentina as well as 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
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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. The Company also successfully completed simultaneous
public debt and equity offerings in February 1997. These six offerings
provided the Company with aggregate net proceeds of approximately $416
million. In addition to accessing the public capital markets, the
Company currently has approximately $130 million of availability under
its revolving credit facility.
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 afforded in recent years, and should afford
in the future, 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. In late 1996, that core area was expanded into Bolivia.
From January 1, 1995, through December 31, 1997, the Company made oil and
gas property acquisitions involving total costs of approximately $439 million.
As a result of these acquisitions, the Company acquired approximately 164.4
MMBOE of proved oil and gas reserves. The following table summarizes the
Company's acquisition experience during the periods indicated:
Proved Reserves When Acquired Acquisition
------------------------------- Cost Per
Acquisition Oil Gas BOE When
Costs (MBbls) (MMcf) MBOE Acquired
-------------- ---------- --------- -------- -----------
(In thousands)
U.S. Acquisitions
1995.................................. $ 38,896 8,840 39,486 15,421 $2.52
1996.................................. 50,480 8,095 20,787 11,560 4.37
1997.................................. 133,548 24,653 62,253 35,029 3.81
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Total U.S. Acquisitions............ 222,924 41,588 122,526 62,010 3.60
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Argentina Acquisitions
1995.................................. 168,762 65,653 -- 65,653 2.57
1996.................................. 3,754 2,849 -- 2,849 1.32
1997.................................. -- -- -- -- --
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Total Argentina Acquisitions....... 172,516 68,502 -- 68,502 2.52
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Bolivia Acquisitions
1996.................................. 37,048 4,953 57,758 14,579 2.54
1997.................................. 6,201 758 111,212 19,293 0.32
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Total Bolivia Acquisitions......... 43,249 5,711 168,970 33,872 1.28
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Total U.S. and International
Acquisitions.................. $438,689 115,801 291,496 164,384 $2.67
======== ======= ======= =======
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The following is a brief discussion of significant acquisitions in recent
years:
1995 Acquisitions.
United States. In May 1995, the Company purchased all of Texaco's
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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 identified
numerous exploitation opportunities in these properties including development
drilling, recompletions, steam flood expansions as well as lease operating
expense efficiencies.
International. In the third quarter of 1995, the Company closed two
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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 605,616 shares (after
giving effect to the Company's two-for-one common stock split effected on
October 7, 1997) of the Company's common stock (then valued at $5.7 million) and
$7.4 million in cash. Cadipsa's major assets included a 100 percent working
interest in two concessions and a 50 percent working interest in three
additional concessions, all five of which were 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 percent of Cadipsa which
increased its total ownership to approximately 97 percent at December 31, 1997.
Effective July 1, 1997, the operations of Cadipsa were merged into Vintage
Argentina, a wholly owned subsidiary of the Company, and Cadipsa is currently
awaiting governmental approval of formal dissolution.
On September 29, 1995, the Company purchased 100 percent of the outstanding
common stock of BG Argentina, S.A. (subsequently renamed Vintage Oil Argentina,
Inc.) ("Vintage Argentina") from British Gas plc, for $37 million in cash.
Vintage Argentina's major assets consist of a 50 percent working interest in
three of the producing concessions previously operated by Cadipsa now operated
by Vintage Argentina.
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.
United States. On January 31, 1996, the Company purchased interests in
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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 daily net production at the time of acquisition 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
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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. Exploitation activities include
workovers, recompletions and development drilling.
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 $29.4 million in cash (the "Exxon Properties"). Funds were
provided by advances under the Company's revolving credit facility. The Exxon
Properties include an interest in two fields totaling approximately 5,000 net
acres with a total of 17 gross (9.9 net) productive wells with net daily
production at the time of acquisition 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. Exploitation activities include operating cost
reductions, treating plant efficiencies, workovers and infill drilling.
International. In November 1996, the Company agreed to purchase 100
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percent of the outstanding common stock of Vintage Boliviana 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 Vintage
Boliviana'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. Vintage Boliviana's assets included (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. The acquisition of Vintage Boliviana represented 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 Vintage Boliviana consist of three blocks,
totaling approximately 570,000 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. Net daily production at the
time of acquisition was approximately 14,500 Mcf of gas and 230 Bbls of
condensate. The average 1997 realized price for natural gas on the properties
was approximately $1.10 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 Vintage Boliviana properties contain
substantial upside potential which may be realized through exploitation and
future exploration. Bolivia occupies a strategic 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 parties are constructing a gas pipeline from Santa
Cruz, Bolivia to Sao Paulo, Brazil with completion scheduled for early 1999.
The Company has begun work 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 when the pipeline to Brazil is completed.
1997 Acquisitions.
United States. During 1997, the Company acquired, through several
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transactions, oil and gas properties for an aggregate purchase price of
approximately $133.5 million. Based on estimates prepared by the Company,
except with respect to the Burlington Properties described below which estimates
were prepared by Netherland, Sewell, proved reserves as of the dates of the
various acquisitions aggregated
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24.7 MMBbls of oil and 62.3 Bcf of gas, or a total of 35.0 MMBOE. These reserves
were acquired at an average cost of $3.81 per BOE.
On April 1, 1997, the Company purchased certain producing oil and gas
properties and facilities located in the gulf coast of Texas and Louisiana from
subsidiaries of Burlington Resources Inc. (the "Burlington Properties") for
approximately $102.7 million in cash. Funds were provided by advances under the
revolving credit facility. The Burlington Properties consist of several key
onshore fields, five offshore fields and a number of smaller fields covering a
total of 74,547 gross (67,970 net) acres. Approximately 47 percent of this
acreage is associated with offshore fields. The Company now operates the
Burlington Properties with current net daily production of approximately 5,600
Bbls of crude oil and 17,000 Mcf of gas. At April 1, 1997, the Burlington
Properties totaled 24.3 MMBbls of oil and 25.2 Bcf of gas for a total of 28.5
MMBOE of proved reserves as estimated by Netherland, Sewell. The two largest
fields obtained in the purchase of the Burlington Properties are Luling Branyon
and West Ranch. For a brief description of these fields, see "--Oil and Gas
Properties--Gulf Coast Area."
International. On December 10, 1997, the Company entered into a
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contract with the Bolivian government for the concession rights to the
Naranjillos concession located in the Santa Cruz Province of Bolivia. The
Company's contract required a $1.0 million cash payment and a commitment to
perform 17,728 work units within the next three years. The work unit commitment
is guaranteed by the Company through the issuance of an $88.6 million letter of
credit; however, the Company anticipates that it will fulfill its three-year
work unit commitment through approximately $45 to $50 million of various seismic
and drilling capital expenditures.
The Naranjillos concession is located approximately 25 miles west of the
city of Santa Cruz, Bolivia, and contained proved reserves of 116 Bcf of gas
equivalent at the time of acquisition based on estimates prepared by the
Company. The Company believes that this concession contains significant
exploratory prospects and has initiated a 3-D seismic program covering nearly 39
square miles to be followed by drilling a minimum of two wells of varying depths
later in 1998. In addition, the Company plans to begin exploitation work aimed
at producing existing proved reserves under its existing market allocation. The
Company estimates capital expenditures for exploration and development of $17
million during the initial phase of the three-year program.
The Bolivia-to-Brazil gas pipeline is a major project with targeted
deliverability in excess of one Bcf of Bolivian gas per day to meet the growing
gas demand in Brazil. The Company believes that the exploitation potential of
the Naranjillos concession, combined with the exploration prospects it acquired
last year in the Chaco Basin of Bolivia, position the Company to be a
potentially significant beneficiary of the Bolivia-to-Brazil gas pipeline
project.
The Company intends to continue its growth strategy emphasizing reserve
additions through its acquisition efforts. The Company may utilize any one or a
combination of its line of credit with banks, institutional financing, issuance
of debt securities or additional equity securities and internally generated cash
flow to finance its acquisition efforts. No assurance can be given that
sufficient external funds will be available to fund the Company's desired
acquisitions.
The Company does not have a specific acquisition budget since the timing and
size of acquisitions are difficult to forecast. The Company is constantly
reviewing acquisition possibilities. The Company may expand into new domestic
core areas. The Company is also evaluating additional acquisition opportunities
in other countries which the Company believes are politically stable. At the
present time the Company has no binding agreements with respect to any
significant acquisitions.
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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, recompletion and development drilling
program on the properties it has acquired and intends to continue these
activities 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 81 percent of the Company's production
during the last three years. The results of their efforts are reflected in
revisions to reserves. Net revisions to reserves for 1997 (before the impact of
lower oil and gas prices) totaled 29.9 MMBOE, or 132 percent of the Company's
production of 22.6 MMBOE. However, the replacement of these reserves was
entirely offset by a 30 MMBOE downward revision of reserves resulting from
sharply lower realized oil and gas prices at year-end 1997 used in the
calculation of proved reserves.
From January 1, 1995, through December 31, 1997, the Company spent
approximately $102.3 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 75 percent of such operations. However, there can be no assurance
that such results will continue. The Company anticipates spending $22 million on
workover and recompletion operations during 1998. 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, 1995, through December 31, 1997, the Company participated in
the drilling of 199 gross (152.90 net) development wells, of which approximately
91 percent gross (93 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 1997, the Company participated in the drilling of 90 gross (73.54
net) development wells. At December 31, 1997, the Company's proved reserves
included approximately 138 development or infill drilling locations on its U.S.
acreage and 131 locations on its Argentine acreage. In addition, the Company has
an extensive inventory of development and infill drilling locations on its
existing properties which are not included in proved reserves. The Company
spent approximately $47.7 million on development/infill drilling during 1997.
The Company expects to spend approximately $98 million on development/infill
drilling activities during 1998.
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
-7-
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 a focus area of the Company's
West Coast exploitation efforts. Consolidation of the three acquisition areas
into a single operating unit has significantly reduced operating costs.
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 the
three prior years. During 1997, one well was successfully sidetracked to the
Fourth Grubb zone with resulting gross daily production of 175 Bbls of oil. Six
more sidetracks are planned for 1998. The Company has been able to increase
proved reserves each year in this field area, and believes ongoing reservoir
studies will continue to identify additional exploitation projects in addition
to the 50 projects currently identified.
In addition to the San Miguelito/Rincon field area, exploitation efforts
have been successful in other areas of California. A horizontal well drilled in
the Zaca field has produced at rates in excess of 75 Bbls of oil per day since
its completion in February 1997. This successful well sets up additional
horizontal wells, both extensional and exploratory. Two infill wells were
drilled in the Buena Vista Hills field during the first half of 1997. Electric
submersible pumps are currently being designed for both wells. Test data
indicates that once the wells are equipped, production for each well should be
approximately 200 Bbls of oil per day. The Company has identified several more
infill wells and recompletions in this field. An expansion of the current
three-pattern steamflood pilot on the Carlton Investment property in the North
Antelope Hills field is planned for 1998. Six additional steam injection wells
are planned to be drilled and total steam injection into the heavy-oil Packwood
formation will increase from the current rate of 1,000 Bbls of steam (cold-water
equivalent) per day to over 3,000 Bbls of steam per day. Incremental oil
production from the steamflood expansion is expected to peak at 385 Bbls of oil
per day in approximately two years. Current field production is 320 Bbls of oil
per day. The expansion project is expected to recover net proved oil reserves
of one MMBbls, with an ultimate recovery of 70 percent of the original oil in
place.
Gulf Coast Area. Exploitation of the Burlington Properties had an
aggressive start in 1997, and plans call for the pace to continue into 1998 and
beyond. Activity in 1997 included the recompletion of 28 wells, artificial lift
upgrades in 20 wells and, most recently, the initiation and completion of four
horizontal wells. These activities were successful at replacing oil production
and offsetting the natural decline curve. For 1998, exploitation activities are
expected to increase with the aim of growing oil production. Plans for 1998
include the drilling of several horizontal wells and numerous recompletions and
artificial lift upgrades. In addition to these activities, total operating
costs for properties in the three main fields, Luling Branyon, Darst Creek and
West Ranch, have been reduced by 16 percent, or $2.7 million annually, from the
time the properties were purchased in April 1997. Additional improvements
planned for 1998 should lower these costs an additional five percent. The
inventory of identified exploitation projects provides additional opportunities
for 1999 and beyond.
In the Galveston Bay area of Texas, the Company performed three workovers
during 1997 in the Red Fish Reef field which is 100 percent owned by the Company
and which historically has had good exploitation potential. This work consisted
of workovers and recompletions in the multi-pay Frio zones productive in the
area which resulted in a total gross daily production increase of 68 Bbls of oil
and 2,840 Mcf of gas. During 1997, the Company also performed three
recompletions in the Four Sevens field, owned 90 percent by the Company, which
resulted in gross daily production increases of 63 Bbls of oil and 2,500 Mcf of
gas. The Company also recompleted three wells in the South Pass 24 field
increasing daily gross field production by 225 Bbls of oil and 3,810 Mcf of gas.
In the Fanny Church field in Alabama, oil production was increased by 770 Bbls
per day by removing surface piping restrictions in one well.
-8-
Mid-Continent Area. Infill drilling in gas fields and waterflooding oil
fields continue to be the major activities of the Company in this area. The
Company participates in a large number of Company-generated and partner-
generated low risk infill projects each year in the many gas fields in this
area. The Company also has ongoing and planned waterfloods in Texas and Kansas.
The four Booker Upper Morrow waterfloods in the panhandle of Texas are expected
to respond to injection during 1998. For additional information regarding
activities in this area, see "--Oil and Gas Properties."
Argentina Concessions. Development and extensional drilling along with the
implementation and optimization of secondary recovery projects have been the
focus of the Company's exploitation efforts in its Argentina properties. The
Company's successful exploitation program has resulted in a gross daily
production increase from 10,200 Bbls of oil in January 1996 to over 18,500 Bbls
of oil currently. Drilling activity commenced during February 1996 and continued
through the end of 1997 with 102 wells having been completed. The three focus
areas for drilling activity to date have been Canadon Minerales with 52 wells,
Canadon Seco with 26 wells, and Meseta Espinosa with 20 wells. Largely due to
the results of this drilling activity, average gross daily oil production on
these three concessions has increased from a total of 6,800 Bbls to 14,400 Bbls.
Drilling activity continues with two drilling rigs currently operating.
During 1996, the Company acquired 48 square miles (124 square kilometers) of
3-D seismic to aid in the optimum placement of drilling locations. Based on the
successful results obtained from the utilization of the 1996 3-D data, the
Company has acquired an additional 99 square miles (256 square kilometers) of 3-
D data during 1997. The Company believes that substantial upside potential that
has historically been overlooked can be economically exploited with the aid of
3-D seismic.
The Company has also continued its endeavor to optimize existing secondary
recovery projects and to initiate new waterfloods. The waterflood work in 1996
and 1997 on Canadon Minerales Block 123A, Canadon Minerales Block 123E, Cerro
Wenceslao Flanco Oriental and Clavada Block 24 has exhibited incremental gross
daily production responses of 970 Bbls of oil. Only a small portion of the
producing areas of the concessions controlled by the Company have been subject
to secondary recovery operations. There are ten new waterflood project areas
that are currently in various stages of development. The Company believes that
numerous other areas presently under primary recovery are amenable to
waterflooding. The Company also believes that the utilization of 3-D seismic
will enhance the ultimate recovery derived from these new waterflood projects
and be a valuable tool in identifying new secondary recovery project areas that
previously would have gone undeveloped.
Bolivia Concessions. The Company initiated its exploitation program in
Bolivia during 1997 with the rework of two wells. Incremental gross daily
production from this work was approximately 7,500 Mcf of gas and 200 Bbls of
condensate. The activity in 1998 will see a dramatic increase as the Bolivia-
to-Brazil pipeline is completed and gas begins to flow into the Brazilian market
in early 1999. In preparation for the opening of the Brazilian market, the
Company has initiated work to upgrade the existing facilities and compression in
Nupuco and Naranjillos. These facility improvements along with planned
additional development drilling should position the Company to take advantage of
this increased gas market opportunity.
A rig has been contracted and drilling is currently underway to test a
Devonian Iquiri sand oil accumulation that was identified by a well drilled in
the early 1960's. More development drilling locations may be identified as a
result of a 3-D seismic survey that is to be completed and interpreted in the
first quarter of 1998.
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
-9-
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, Bolivia and Yemen are
characterized by higher potential and higher risk. From January 1, 1995, through
December 31, 1997, the Company spent $64.6 million on exploration activities.
The Company plans to spend approximately $65 million on exploration activities
during 1998, approximately $39 million in the U.S. and Argentina and
approximately $26 million in other international areas.
The following is a brief discussion of the primary areas of exploration
activity for the Company:
United States.
Gulf Coast Area. In 1997, the Company successfully drilled and
---------------
completed three wildcat discoveries and one field extension in the geopressured
pay horizons of Galveston Bay in south Texas. All the locations were based on
interpretations derived from the Company's 180 square mile 3-D seismic survey.
The State Tract 75-2 well was a successful extension to the Company's 1996
discovery well, the State Tract 75-1. Wildcats drilled at the Umbrella Point
West, White Heron and White Heron North prospects in the Umbrella Point field
were successful and are currently producing at gross daily rates ranging from 5
MMcf of gas to 15 MMcf of gas along with condensate of up to 600 Bbls per well.
Plans for 1998 include the drilling of five additional wildcats where the
Company's working interests range between 50 percent to 100 percent. In an
attempt to extend the play, the Company is planning to shoot an additional 30
square miles of proprietary 3-D seismic in an adjacent onshore area where lease
options have been secured. For additional information, see "--Oil and Gas
Properties--Gulf Coast Area."
Three potentially significant south Louisiana prospects will be evaluated in
1998. 3-D seismic surveys have been shot and geophysical processing is nearing
completion on both the Lake Washington and Little Lake Deep prospects.
Geological and 2-D seismic leads will be evaluated with potential drilling
planned sometime in 1998. The Company will have working interests ranging from
50 percent to 100 percent. In the Deweyville prospect of south Texas, initial
drilling is expected to commence in the summer of 1998 to evaluate 3-D and
geochemically defined locations in the expanded Yegua trend.
Mid-Continent Area. The Company is participating in a regional 3-D
------------------
Seismic Alliance in which over 625 square miles of non-contiguous, high-quality
3-D seismic has been shot. Several different play concepts are being pursued.
Main objectives include the Hunton, Springer, Morrow and Granite Wash
formations. A potentially significant discovery in the Company's Jayhawk
prospect, the #1 Weise, was recently completed with gross daily production of
4.5 MMcf of gas and 255 Bbls of oil from the Hunton formation. A delineation
well is planned in the first quarter of 1998. Additional 3-D seismic data has
been acquired and is currently being processed. An aggressive drilling program
is anticipated in 1998 on prospects identified in this Alliance.
In the Stagecoach prospect in southern Oklahoma, the Company is pursuing a
multipay gas project in which the Granite Wash as well as multiple shallower
horizons in the Hoxbar and Deese formations are of primary interest.
Preliminary results from the first well are encouraging and two additional
wells, the Ithaca #1 and Travis #1, have been drilled and are being tested. A
100 square mile 3-D seismic survey will be shot in 1998 and is expected to help
evaluate the deeper drilling potential.
West Coast Area. Horizontal drilling will evaluate two potentially
---------------
undrained fault blocks adjacent to the Company's Zaca oil field in 1998. Two
prospects target the Monterrey formation and will attempt to extend production
beyond the limits of the existing field.
-10-
A 30 square mile 3-D seismic survey covering the Company's Rio Vista field
is currently being evaluated. Multiple pay horizons are potential in this
structurally and stratigraphically complex field that is one of California's
largest gas fields. The Company believes that a detailed geologic and
geophysical evaluation will uncover previously untapped gas reserves in fault
and stratigraphic traps that 2-D seismic could not identify.
International.
South America. The Company is currently pursuing several international
-------------
exploratory projects. The Company believes that its existing projects in Ecuador
and Bolivia have the potential to significantly increase reserves. The Company
has a 30 percent working interest in a project to explore Block 19 in the
Oriente Basin in Ecuador. 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. The first of two
planned exploration wells was drilled during 1997. This well was abandoned after
testing at subcommercial rates. Plans are to drill the next exploration well in
1998 or 1999, testing another structure.
Activity in Bolivia during 1997 was relatively modest due to restriction of
the current gas market to Argentina. However, the activity in 1998 will see a
significant increase as the Bolivia-to-Brazil pipeline is completed and gas
begins to flow into the Brazilian market in early 1999. This third-party
pipeline is designed to deliver approximately one Bcf of gas per day, as
compared to the current export market to Argentina of approximately 200 MMcf of
gas per day.
The Company significantly expanded its operations in Bolivia by acquiring
the Naranjillos concession in December 1997. The Company believes this 15,444
acre concession contains significant upside exploration and development
potential which it plans to capitalize upon beginning in 1998. Multiple
exploration well targets have been located and more are expected to follow upon
completion of a 3-D seismic shoot that is currently underway.
In addition to the Naranjillos concession, the Company has exploration plans
in 1998 for its Chaco and Nupuco concessions in Bolivia. A 3-D seismic survey
covering a portion of both of these concessions is to be completed and
interpreted in the first quarter of 1998. At least two new wells are planned
for 1998 and more may follow upon completion of the 3-D seismic interpretation.
Yemen. The Company has entered into a farm-in agreement with
-----
TransGlobe Energy in the expectation of receiving approval by the Republic of
Yemen to explore on the S-1 Damis Block in central Yemen. The block covers
approximately one million acres (4,484 square kilometers). The Company will
receive a 75 percent interest in the S-1 Damis Block for its commitment of $11
million over two and one-half years in the initial exploration phase. The $11
million of expenditures will include a 3-D seismic survey of 58 square miles
(150 square kilometers) and the drilling of three exploration wells.
OIL AND GAS PROPERTIES
At December 31, 1997, the Company owned and operated producing properties in
ten 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, the
Company established a new core area in the San Jorge Basin of Argentina during
1995 and entered Bolivia during 1996. As of December 31, 1997, the Company
operated approximately 3,679 productive wells and also owned non-operating
interests in 842 productive wells. The Company continuously evaluates the
profitability of its oil, gas and related activities and has a policy of
divesting itself of unprofitable leases or areas of operations that are not
consistent with its operating philosophy.
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
two largest concessions in Bolivia at December 31, 1997, as
-11-
estimated by Netherland, Sewell. These fields and concessions represent
approximately 82 percent of the Company's proved reserves on such date.
LOCATION (COUNTY NET NET
OR PARISH, STATE OIL GAS
AREA FIELD/CONCESSION NAME OR PROVINCE) (MBbls) (MMcf) MBOE
---- ------------------------ -------------------- ------- -------- ------
West Coast.................... San Miguelito Ventura, CA 15,103 3,818 15,740
South Mountain Ventura, CA 5,535 6,305 6,586
Buena Vista Hills Kern, CA 4,122 4,661 4,898
Rincon Ventura, CA 4,054 3,034 4,560
Rio Vista Sacramento, CA 3 26,834 4,475
Ojai-Silverthread Ventura, CA 1,900 8,836 3,372
Pleito Ranch Kern, CA 2,650 1,512 2,902
North Tejon Kern, CA 1,387 7,321 2,607
Sespe Ventura, CA 2,081 3,010 2,583
Santa Maria Valley/Cat Canyon Santa Barbara, CA 2,043 0 2,043
North Antelope Hills Kern, CA 1,664 0 1,664
Lathrop San Joaquin, CA 0 9,224 1,537
Canfield Ranch Kern, CA 1,428 301 1,478
Zaca Santa Barbara, CA 1,452 0 1,452
Gulf Coast.................... Luling Branyon Guadalupe, TX 11,778 418 11,847
West Ranch Jackson, TX 7,248 700 7,365
South Pass 24 Plaquemines, LA 2,842 10,630 4,614
Umbrella Point Chambers, TX 304 20,763 3,764
Flomaton Escambia, AL 1,882 6,232 2,921
Fanny Church Escambia, AL 1,580 3,410 2,148
Tepetate Acadia, LA 2,018 583 2,115
Darst Creek Guadalupe, TX 1,635 103 1,653
Ville Platte Evangeline, LA 939 3,798 1,572
Waveland Hancock, MS 121 8,145 1,478
East Texas.................... South Gilmer Upshur, TX 703 23,863 4,680
Colgrade Winn, LA 3,681 0 3,681
Southern Pine Cherokee, TX 0 18,371 3,062
Fruitvale Van Zandt, TX 21 17,415 2,923
Mid-Continent................. Booker Lipscomb, TX 1,737 283 1,784
Strong City Roger Mills, OK 46 9,118 1,565
San Jorge Basin, Argentina.... Canadon Minerales Santa Cruz Province 27,044 0 27,044
Canadon Seco Santa Cruz Province 15,982 0 15,982
Meseta Espinosa Santa Cruz Province 15,690 0 15,690
Las Heras/Piedra Clavada Santa Cruz Province 12,207 0 12,207
Cerro Wenceslao Santa Cruz Province 7,680 0 7,680
Chaco Basin, Bolivia.......... Naranjillos Santa Cruz Province 845 122,067 21,189
Nupuco Tarija Province 5,313 67,660 16,589
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, 1997, the area comprised 25 percent of the
Company's total proved reserves and 43 percent of the Company's U.S. proved
reserves. The Company currently operates 1,168 active wells with current gross
daily production of approximately 9,850 Bbls of mid-gravity oil, 2,300 Bbls of
heavy oil and 29,200 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 underway in three of the producing zones. With the field still
producing in excess of 3,000 gross Bbls of oil per day, the Company believes
additional waterflood potential exists in lower sands currently producing on
primary depletion and it has just initiated a program to begin waterflooding a
fourth productive interval. The Company operates this
-12-
single lease property with a 100 percent working interest and an 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 1995 acquisition of certain producing oil and gas properties
from Texaco, which included certain properties in this field, the Company now
operates 253 active wells in the South Mountain field. Current gross daily
production of 1,100 Bbls of oil and 2,365 Mcf of gas comes from Eocene and
Pliocene sand intervals at depths of 3,000 feet to 10,000 feet. The Company's
working interests in the field range from 50 percent to 100 percent with revenue
interests from 42 percent to 100 percent; however, the properties are
predominantly owned 100 percent. The solution gas and gravity drainage producing
mechanisms are responsible for low decline rates which result in long-life
reserves.
Buena Vista Hills. The Buena Vista Hills field is located
-----------------
approximately 25 miles east of Bakersfield, California. Production is from the
Stevens Upper Channel, Main Massive and Interbed zones at a depth of 5,000 feet
to 5,500 feet. The Company operates 27 productive wells in the field with a 100
percent working interest. The Company drilled two infill wells in the first half
of 1997, testing at rates in excess of 100 Bbls of oil per day. Plans are
underway to install electrical submersible pumps in order to efficiently produce
the wells. Daily rates are anticipated to be in excess of 200 Bbls per well when
installation is complete. In addition, the Company has identified 14 workovers
and recompletions in the field. Current gross daily production is 930 Bbls of
oil. The Company believes that upside reserve potential exists through infill
drilling and recompletions. For additional information regarding this field,
see "--Exploitation and Development Activities--West Coast Area."
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. Producing intervals range in
depth from approximately 3,500 feet to 14,000 feet. The Company operates this
field with a 100 percent working interest and an 80 percent revenue interest.
Current gross daily production is approximately 850 Bbls of oil and 800 Mcf of
gas. The Company has continued its exploitation program on uphole producing
intervals which it began in 1996. The Company believes that significant upside
reserve potential exists in the development of these shallow producing horizons
along with workover and stimulation activity in the presently producing
intervals. For additional information regarding this field, see "--Exploitation
and Development Activities--West Coast Area."
Rio Vista. The Company purchased the Rio Vista Deep field and an
---------
additional 31 percent working interest in the Rio Vista Gas Unit during 1997.
The field, located in Solano County, California, produces dry gas at depths
ranging from 5,500 feet to 11,000 feet. The Rio Vista Deep acquisition added 29
wells which are now operated by the Company. The Company has workover and
drilling plans to exploit the proven reserves as well as other probable and
possible reserve potential in the field. Deep exploration potential is also
being evaluated using the latest 3-D seismic technology. Current gross daily
production from these wells is 3,700 Mcf of gas. The Company owns a 95 percent
working interest in these wells. The Rio Vista Gas Unit, operated by Amerada
Hess, has current gross daily production of approximately 19,000 Mcf of gas from
71 wells.
Ojai-Silverthread and Timber Canyon. The Ojai field, which extends
-----------------------------------
to the Silverthread and Timber Canyon areas, is located in the central portion
of Ventura County, California. 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 111 productive wells in the 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 gross daily production is approximately 700 Bbls of oil and 3,000 Mcf of
gas.
-13-
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 daily production of approximately 560 Bbls of oil.
North Tejon. The North Tejon field is located near the southern
-----------
end of the San Joaquin Basin. The 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
interest. Current gross daily production rates average 250 Bbls of oil and 2,150
Mcf of gas.
Gulf Coast Area. The Gulf Coast area comprised approximately 20 percent of
the Company's December 31, 1997, total proved reserves. Production in this area
is predominantly from structural accumulations in reservoirs of Miocene age.
The depths of producing reservoirs in this area range from 1,200 feet to 14,500
feet. The Company currently operates 821 productive wells and owns an interest
in an additional 434 productive wells in this area. Gross daily operated
production from this area currently averages 14,700 Bbls of oil and 104,700 Mcf
of gas.
The Company's Umbrella Point exploration program in Galveston Bay, in which
the Company generally owns a 50 percent working interest, contributes current
gross daily production of 65,000 Mcf of gas and 1,100 Bbls of condensate of the
above total Gulf Coast production. This project is ongoing with several new
wells currently in the completion stage. Additional development potential
exists from horizontal well drilling in the West Ranch and Luling Branyon fields
which are 100 percent owned by the Company. Recompletion and development
drilling potential also exists in the South Pass 24 (70 percent working
interest) and Southern Pine (92 percent working interest) fields.
Luling Branyon. The Luling Branyon field is located in Caldwell and
--------------
Guadalupe Counties, Texas, and was purchased from Burlington Resources in 1997.
This field produces primarily from the Upper Edwards carbonate at a depth of
2,100 feet. The field produces from a natural water drive with high water
rates. Gross daily production from this field is 2,700 Bbls of oil from 307
producing wells. The Company operates this field with a 100 percent working
interest. Since acquiring this field, the Company has drilled three horizontal
development wells, increasing gross daily oil production by 750 Bbls.
Recompletions and artificial lift upgrades have added another 150 Bbls per day.
Significant reductions in operating costs have also been achieved, including the
shutting in of approximately 40 marginal wells. Upside potential for this field
includes another 28 horizontal drilling locations and additional recompletions
and lift upgrades.
West Ranch. The West Ranch field, purchased from Burlington Resources
----------
in 1997, is located in Jackson County, Texas. Production is from numerous
Miocene and Frio age sands at depths between 2,900 feet and 7,200 feet. Current
gross daily production is 2,000 Bbls of oil and 3,660 Mcf of gas from 140 active
wells. Cumulative field production is over 350 MMBbls of oil and 850 Bcf of
gas. The Company drilled one horizontal well in 1997 making 250 Bbls of oil per
day in the Greta sand, the largest reservoir in the field, and plans on drilling
eight more in 1998, and seven in 1999. Production enhancements, such as
installing larger tubing and improved gas lift design, along with recompletions,
have increased production rates approximately 250 Bbls of oil per day. The
field is also being studied for enhanced oil recovery opportunities. The Company
has a working interest of 100 percent in the field.
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 31 productive oil wells and eight 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
-14-
approximately 7,000 feet. Current gross daily operated production from the field
is 965 Bbls of oil and 7,700 Mcf of gas. Recompletions to new zones in current
wellbores have been very successful in this field. Similar work is planned for
1998 and beyond.
Umbrella Point. This ongoing exploration project in Galveston Bay is a
--------------
top contributor to current producing rates and reserves in the Gulf Coast area.
For additional information regarding this field, see "--Exploration--Gulf Coast
Area."
Flomaton. This field, purchased from Exxon in 1996, is located in
--------
Escambia County, Alabama, and produces from the Norphlet sand at 15,300 feet.
Company operated gross daily production is 588 Bbls of oil and 11,300 Mcf of gas
from nine wells. The Company has had recent success in enhancing production by
installing velocity strings and plans on installing five more in 1998. The
Company owns approximately a 95 percent working interest in this field.
Fanny Church. Fanny Church field, purchased from Exxon in 1996, is
------------
located in Escambia County, Alabama, and produces from the Smackover carbonate
at 15,300 feet. Company operated gross daily production is 1,680 Bbls of oil
and 4,140 Mcf of gas from five wells. In mid-1997, gross oil production was
increased 770 Bbls per day by removing surface piping restrictions in one well.
Additional drilling and/or enhanced oil recovery options are being studied. The
Company owns approximately a 80 percent working interest in this field.
East Texas Area. The East Texas area comprised approximately seven percent
of the Company's December 31, 1997, total proved reserves. The Cotton Valley,
Smackover, Travis Peak and Wilcox formations are the dominant producing
reservoirs on the Company's acreage in this area. The Company currently operates
gross daily production of 1,425 Bbls of oil and 38,700 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, Southern Pine,
Rosewood, Bethany Longstreet and Bear Grass fields. The Company plans to
continue infill drilling programs in Southern Pine and South Gilmer fields.
South Gilmer. The South Gilmer field, the Company's largest field in
------------
the East Texas area, is located in Upshur County, Texas, and produces from the
Cotton Valley Lime formation at average depths of 11,300 feet to 11,800 feet.
The Company currently operates 20 productive wells and owns interest in two
additional wells in this field. Significant behind-pipe reserves are booked for
the Company's 6,727 gross acres in the Cotton Valley sand formation. Current
gross daily operated production is 6,500 Mcf of gas and 90 Bbls of oil. The
Company owns approximately a 80 percent working interest in this field.
Colgrade. The Colgrade field, located in Winn Parish, Louisiana,
--------
currently produces 1,140 Bbls of oil gross per day from the Wilcox formation at
a depth of 1,400 feet. The Company operates 439 active wells in this field.
During 1996, a pilot project was initiated to increase fluid withdrawal rates
using submersible pumps. To date, 156 electrical submersible pumps have been
installed, increasing oil production 390 Bbls per day. The Company plans to
install 139 additional pumps during the remainder of 1998. 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 an 85 percent working interest and a 91 percent net revenue
interest in this field due to significant fee mineral ownership.
Southern Pine. The Southern Pine field, located in Cherokee County,
-------------
Texas, produces from the Travis Peak formation at 10,800 feet. The Company
currently operates 25 productive wells in this field with current gross daily
production of 5,300 Mcf of gas. Operating costs were significantly lowered in
1997 by converting a marginal well to salt water disposal. The Company owns a
92 percent working interest in this field.
-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
comprised five percent of the Company's total proved reserves as of December 31,
1997. The Company currently operates gross daily production of 3,760 Bbls of
oil and 28,900 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.
For additional information regarding these operations, see "--Exploitation and
Development Activities--Mid-Continent Area" and "--Exploration--Mid-Continent
Area."
Booker. The Booker field is located in Lipscomb and Ochiltree
------
Counties, in the Texas panhandle. Production from this field is primarily from
four waterflood units adjacent to each other, each targeting the Upper Morrow
sand at depths of approximately 8,000 feet. The Company owns working interests
in these units from 82 percent to 100 percent. Water injection into three of the
units began in 1996. Injection into the fourth unit began in July 1997. Two
analogous Upper Morrow units immediately adjacent to this field have responded
favorably to waterflood operations. First production response from the project
is anticipated in 1998. The Company anticipates the addition of proved reserves
based on the level of success of these secondary recovery projects.
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 29 percent of the Company's December
31, 1997, total proved reserves. The Company currently operates 682 productive
wells (100 percent working interest) with gross daily production of 18,500 Bbls
of oil. In addition, the Company owns an interest in 17 productive wells
operated by others. At December 31, 1997, the Company's proved reserves included
approximately 131 development or infill drilling locations and 267 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 6,200 feet. This concession currently has 183 producing wells and
36 water injection wells with gross daily production of approximately 6,000 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.
Future development plans at Canadon Minerales include numerous workovers and
development drilling locations. Many of the workovers are expected to return
idle wells back to production by perforating zones not produced by the former
owner. Log cross sections reveal many zones which do not appear to have been
previously tested. In addition, the Company plans to further develop the
significant waterflood potential in four areas of Block 130, Block 125 and two
areas in Block 123 West.
The proved undeveloped locations are generally infill development locations
in areas offsetting existing production. Well depths vary from 3,000 to 6,000
feet. Fifty-two wells have been drilled on this concession during 1996 and 1997.
See "--Exploitation and Development Activities--Argentina Concessions."
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
concession currently has 87 producing wells and 20 water injection wells with
gross daily production of approximately 4,000 Bbls of oil.
There are three active waterfloods at Canadon Seco which contain a total of
20 water injection wells. The Block VIIIAo waterflood has additional drilling
and water injection conversions scheduled for early 1998.
-16-
Twenty-six wells have been drilled on this concession during 1996 and 1997.
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."
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 108
producing wells and 10 water injection wells with gross daily production of
approximately 4,200 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. Twenty wells have been drilled on this
concession during 1996 and 1997. Additional development plans at Meseta Espinosa
include several workovers and the drilling of development and extensional wells.
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 87
producing wells and five water injection wells with gross daily 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 have been tested.
The proved undeveloped locations are generally infill development locations in
areas offsetting existing production. Seven wells have been drilled on this
concession during 1996 and 1997.
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 11 water injection wells with gross daily production of approximately
1,500 Bbls of oil. Two wells have been drilled on this concession during 1996
and 1997.
Future development plans at Cerro Wenceslao include workovers, fracture
stimulations, and development drilling on several locations. In addition, the
Company plans to further develop the significant waterflood potential in Block
2, Block 5 and the East Flank Block.
Bolivia Concessions. The Bolivia properties consist of three 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, the Porvenir producing concession and the Naranjillos
producing concession. In the other concession, Nupuco, the Company has a 50
percent working interest. The Company operates all four concessions. These
concessions comprise approximately 14 percent of the Company's December 31,
1997, total proved reserves and include 7 gross (6 net) active producing wells,
all of which are operated by the Company. The current gross daily production is
approximately 30,850 Mcf of gas and 800 Bbls of condensate.
Naranjillos. The Naranjillos concession is located approximately 25
-----------
miles west of the city of Santa Cruz, in the Santa Cruz Province. The
concession was shut in prior to the Company assuming operations. The Company
believes that the potential exists to significantly increase production above
historic
-17-
levels through gas compression and recompletion of wells. This potential will be
evaluated through testing operations, which are scheduled to begin in the second
quarter of 1998. The Company believes that significant exploration potential
also exists.
There are three exploration concepts to be tested in Naranjillos during
1998, the most significant of which is the Upper Devonian Iquiri formation. The
Iquiri sands appear to be trapped between two major thrust faults. Two previous
wells penetrated this formation but were not tested due to abnormally high
pressures. To evaluate this potential, the Company is currently shooting a 3-D
seismic survey which will cover the entire concession. This survey is scheduled
for completion by the end of April 1998. The data from this survey will be used
to select locations for drilling in 1998 and 1999. A total of five drilling
well locations have already been identified, without the aid of 3-D; drilling is
scheduled to begin in the second quarter of 1998. In preparation for the
opening of the Brazilian market, the Company has also initiated work to upgrade
existing facilities so that the Company's proved reserves can be delivered to
the new market.
Nupuco. The Nupuco concession 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 concession currently has two gross (one net) active
producing wells with gross daily production of approximately 25,000 Mcf of gas
and 675 Bbls of condensate. A study is currently underway to install gas
compression and plans are to have this installation completed by the end of the
year in anticipation of the opening of the Bolivia-to-Brazil gas pipeline.
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
domestic gas marketing activities are handled by Vintage Gas, Inc., its wholly-
owned gas marketing affiliate, which commenced operation on May 1, 1991. This
marketing affiliate purchases gas on the spot market from the Company and third
parties. Generally, the marketing affiliate purchases this gas on a month-to-
month basis at a percentage of resale prices.
Generally, the Company's domestic oil production is sold under short-term
contracts at posted prices plus a premium in some cases. The Company's Argentina
oil production is currently sold at port to ESSO SAPA, ARCO and Shell at West
Texas Intermediate spot prices less a specified differential.
The most significant purchaser of the Company's oil during 1997 was Texaco
Trading and Transportation, Inc. Such oil purchases amounted to approximately 10
percent of the Company's total revenues for 1997. No other purchaser of the
Company's oil or gas during 1997 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. The Company had no oil or gas
hedges in place at December 31, 1997.
-18-
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 24 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 255 MMcf of gas per day. At December 31, 1997,
there were 360 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 ten years.
RESERVES
At December 31, 1997, the Company had proved reserves, as estimated by
Netherland, Sewell, of 279.8 MMBOE, comprised of 187.8 MMBbls of oil and 552.2
Bcf of gas. The following table sets forth, at December 31, 1997, 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):
Proved Reserves:
Future net revenues......................................... $1,981,616
Present value of future net revenues before income taxes,
discounted at 10 percent.................................. 1,222,560
Standardized measure of discounted future net cash flows.... 1,016,645
Proved Developed Reserves:
Future net revenues......................................... 1,405,821
Present value of future net revenues before income taxes,
discounted at 10 percent.................................. 934,899
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, 1997, economic
conditions. The estimated future production is priced at prices prevailing at
December 31, 1997, 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, 1997, 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 11 to
Consolidated Financial Statements--Supplementary Financial Information for Oil
and Gas Producing Activities" which is incorporated by reference from pages 47
through 52 of the Company's 1997 Annual Report to Stockholders.
Oil and gas prices have declined from the year-end prices used in
determining the Standardized Measure at December 31, 1997. Such declines may
reduce the Standardized Measure at March 31, 1998, to an extent that a writedown
of the Company's capitalized oil and gas costs would be required.
-19-
The following table sets forth estimates of the proved oil and gas reserves
of the Company at December 31, 1997, as evaluated by Netherland, Sewell:
OIL (MBBLS) GAS (MMCF)
---------------------------------- --------------------------------- MBOE
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL TOTAL
--------- ----------- ------- --------- ----------- ------- -------
West Coast......... 40,862 10,487 51,349 94,548 11,454 106,002 69,016
Gulf Coast......... 29,278 8,283 37,561 100,452 11,686 112,138 56,251
East Texas......... 4,930 365 5,295 77,415 14,536 91,951 20,620
Mid-Continent...... 4,424 1,305 5,729 43,890 6,866 50,756 14,188
------- ------ ------- ------- ------ ------- -------
Total U.S......... 79,494 20,440 99,934 316,305 44,542 360,847 160,075
Argentina.......... 47,806 33,845 81,651 -- -- -- 81,651
Bolivia............ 1,503 4,680 6,183 140,124 51,192 191,316 38,069
------- ------ ------- ------- ------ ------- -------
Total Company..... 128,803 58,965 187,768 456,429 95,734 552,163 279,795
======= ====== ======= ======= ====== ======= =======
Estimates of the Company's 1997 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 82 percent of
the December 31, 1997, 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 11 to
Consolidated Financial Statements--Supplementary Financial Information for Oil
and Gas Producing Activities" which is incorporated by reference from pages 47
through 52 of the Company's 1997 Annual Report to Stockholders.
PRODUCTIVE WELLS; DEVELOPED ACREAGE
The following table sets forth the Company's productive wells and developed
acreage assignable to such wells at December 31, 1997:
PRODUCTIVE WELLS
--------------------------------------------------
DEVELOPED ACREAGE OIL GAS TOTAL
---------------------- --------------- ------------ --------------
GROSS NET GROSS NET GROSS NET GROSS NET
--------- --------- ----- ----- ----- --- ----- -----
U.S.............. 666,069 407,428 2,804 2,304 1,011 474 3,815 2,778
Argentina........ 1,008,339 844,372 699 686 -- -- 699 686
Bolivia.......... 99,458 88,339 -- -- 7 6 7 6
--------- --------- ----- ----- ----- --- ----- -----
Total.......... 1,773,866 1,340,139 3,503 2,990 1,018 480 4,521 3,470
========= ========= ===== ===== ===== === ===== =====
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.
-20-
Wells which are completed in more than one producing horizon are counted as one
well. Of the gross wells reported above, two had multiple completions.
PRODUCTION; UNIT PRICES; COSTS
The following table sets forth information with respect to production and
average unit prices and costs for the periods indicated:
YEARS ENDED DECEMBER 31,
-------------------------------------
1997 1996 1995
------- ------- -------
PRODUCTION:
Oil (MBbls)-
U.S....................... 9,692 7,694 6,647
Argentina................. 5,630 4,245 961
Bolivia................... 135 -- --
Total..................... 15,457 11,939 7,608
Gas (MMcf)-
U.S....................... 36,623 32,366 30,610
Bolivia................... 6,068 -- --
Total..................... 42,691 32,366 30,610
Total MBOE................... 22,573 17,333 12,710
AVERAGE SALES PRICES:
Oil (per Bbl)-
U.S....................... $ 17.23 $ 17.19(b) $ 15.44
Argentina................. 16.67(a) 15.91(b) 13.98
Bolivia................... 16.52 -- --
Total..................... 17.02(a) 16.73(b) 15.26
Gas (per Mcf)-
U.S....................... 2.33 1.81 --
Bolivia................... 1.10 -- --
Total..................... 2.16 1.81 1.46
PRODUCTION COSTS (PER BOE):
U.S....................... $ 5.64 $ 5.42 $ 5.24
Argentina................. 4.29 4.93 5.42
Bolivia................... 1.00 -- --
Total..................... 5.07 5.30 5.25
- --------------
(a) Reflects the impact of oil hedges which reduced the Company's 1997 Argentina
and total average oil prices per Bbl by 66 cents and 24 cents, respectively.
(b) Reflects the impact of oil hedges which 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, 1997, the Company held the following undeveloped acres
located in the United States, Bolivia and Ecuador. With respect to such United
States acreage held under leases, 113,438 gross
-21-
(44,551 net) acres are held under leases with primary terms that expire at
varying dates through December 31, 2001, unless commercial production is
commenced. The Bolivia and Ecuador acreage are held under concessions with
primary terms that expire at varying dates in 1999 and 2000. Although
substantial undeveloped acreage exists in the Company's concessions in
Argentina, the concessions in their entirety are held by production.
STATE/COUNTRY GROSS ACRES NET ACRES
------------- ----------- ---------
California........... 8,366 7,966
Kansas............... 2,020 2,020
Louisiana............ 2,353 2,330
Mississippi.......... 40 1
Montana.............. 9,811 4,425
New Mexico........... 8,285 1,011
Oklahoma............. 30,004 12,508
Texas................ 57,490 18,595
--------- -------
Total U.S.......... 118,369 48,856
Bolivia.............. 485,552 485,552
Ecuador.............. 494,226 148,268
--------- -------
Total Company...... 1,098,147 682,676
========= =======
DRILLING ACTIVITY
During the periods indicated, the Company drilled or participated in the
drilling of the following exploratory and development wells:
YEARS ENDED DECEMBER 31,
--------------------------------------------
1997 1996 1995
------------- ------------- ------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
DEVELOPMENT:
United States-
Productive........... 30 15.74 22 12.67 36 19.26
Non-Productive....... 3 0.80 5 2.94 5 3.49
Argentina-
Productive........... 55 55.00 39 39.00 -- --
Non-Productive....... 2 2.00 2 2.00 -- --
--- ----- --- ----- --- -----
Total.............. 90 73.54 68 56.61 41 22.75
=== ===== === ===== === =====
EXPLORATORY:
United States-
Productive........... 7 3.01 6 3.00 13 9.84
Non-Productive....... 6 2.87 7 3.12 5 2.69
Argentina-
Productive........... -- -- 2 2.00 -- --
Non-Productive....... 1 1.00 1 1.00 -- --
Other International- -- -- -- -- -- --
Productive........... -- -- -- -- -- --
Non-Productive....... 1 0.42 1 1.00 -- --
--- ----- --- ----- --- -----
Total.............. 15 7.30 17 10.12 18 12.53
=== ===== === ===== === =====
TOTAL:
Productive............. 92 73.75 69 56.67 49 29.10
Non-Productive......... 13 7.09 16 10.06 10 6.18
--- ----- --- ----- --- -----
Total.............. 105 80.84 85 66.73 59 35.28
=== ===== === ===== === =====
-22-
The above well information excludes wells in which the Company has only a
royalty interest.
At December 31, 1997, the Company was a participant in the drilling or
completion of 26 gross (20.84 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 43 percent of the
Company's total proved reserves at December 31, 1997, 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, civil unrest or war, 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.
-23-
In addition, in the event of a dispute arising from foreign operations, the
Company may be subject to the exclusive jurisdiction of foreign courts or may
not be successful in subjecting foreign persons to the jurisdiction of the
courts in the United States. The Company may also be hindered or prevented from
enforcing its rights with respect to a governmental instrumentality because of
the doctrine of sovereign immunity.
The Company's operations in Argentina and Bolivia are subject to various
laws and regulations in those countries. These laws and regulations as
currently imposed are not anticipated to have a material adverse effect upon the
Company's operations.
REGULATION
The domestic 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, quarterly and/or daily
allowable 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.
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
-24-
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"). 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 January 1, 1993, all
remaining natural gas wellhead pricing, sales, certificate and abandonment
regulation of first sales that had been regulated by the FERC.
Commencing in 1985, the FERC through Order Nos. 436, 500 and 636 promulgated
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,
buyers and sellers of gas 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.
In 1992 the FERC issued Order 636. 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. 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.
The FERC has issued a new policy regarding the use of nontraditional methods
of setting rates for interstate gas pipelines in certain circumstances as
alternatives to cost-of-service based rates. A number of pipelines have
obtained FERC authorization to charge negotiated rates as one such alternative.
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 of pipelines engaged in the intrastate
-25-
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 1994 FERC ruled that it generally
does not have jurisdiction over gathering facilities absent abuse involving the
pipeline-affiliate relationship. 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. 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 210 people in its Tulsa office whose
functions are associated with management, engineering, geology, land and legal,
accounting, financial planning, and administration. In addition, approximately
228 full time employees are responsible for the supervision and operation of its
U.S. field activities. The Company also has approximately 142 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 British Gas, plc for any loss
sustained by the Company as a result of this claim. Such indemnification equals
approximately $4.4 million of the current $15.1 million claim. The Company has
no indemnification from its predecessors in title with respect to the payment of
royalties on the other two concessions. Although the Company cannot predict the
outcome of this litigation, based upon the advice of counsel, the Company does
not expect this claim to have a material adverse impact on the Company's
financial position or results of operations.
On April 4, 1997, Mr. Patrick I. Chapman of Hockley, Texas, former Vice
President-Marketing for the Company, sued the Company in the United States
District Court for the Southern District of Texas, alleging actual and exemplary
damages for breach of his employment contract with the Company and fraud. The
case
-26-
was transferred to the United States District Court for the Northern District of
Oklahoma on the motion of the Company. On February 26, 1998, this action was
settled by the parties. The settlement consisted of the purchase by the Company
of Mr. Chapman's interest in assets jointly owned by Mr. Chapman and the Company
for an amount that was less than the total of the fair market value of the
assets plus the costs of litigating this matter further.
The Company is also a named defendant in other lawsuits and is a party in
governmental proceedings from time to time arising in the ordinary course of
business. While the outcome of such other lawsuits or proceedings against the
Company cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the Company's financial position or
results of operations.
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, 1997.
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.
NAME AGE POSITION
- --------------------------- --- ----------------------------------------------------
Charles C. Stephenson, Jr.. 61 Director and Chairman of the Board of Directors
Jo Bob Hille............... 56 Director and Vice Chairman of the Board of Directors
S. Craig George............ 45 Director, President and Chief Executive Officer
William L. Abernathy....... 46 Executive Vice President and Chief Operating Officer
William C. Barnes.......... 43 Director, Executive Vice President, Chief Financial
Officer, Treasurer and Secretary
William E. Dozier.......... 45 Senior Vice President--Operations
Robert W. Cox.............. 52 Vice President--General Counsel
Andy R. Lowe............... 46 Vice President--Marketing
Michael F. Meimerstorf..... 41 Vice President and Controller
Robert E. Phaneuf.......... 51 Vice President--Corporate Development
Barry D. Quackenbush....... 56 Vice President--Production
Larry W. Sheppard.......... 43 Vice President--International
Martin L. Thalken.......... 37 Vice President--Acquisitions
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 38
years of oil and gas experience.
Mr. Hille, the other co-founder of the Company, has been a Director since
June 1983 and Vice Chairman of the Board of Directors of the Company since
September 1995. He was also President of the Company from May 1990 to September
1995, Chief Executive Officer of the Company from March 1994 to December 1997,
Chief Operating Officer of the Company from April 1987 to March 1994, Executive
Vice
-27-
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 32 years of oil and gas experience.
Mr. George has been a Director since October 1991, President of the Company
since September 1995 and Chief Executive Officer of the Company since December
1997. He was also Chief Operating Officer of the Company from March 1994 to
December 1997, 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. Abernathy has been an Executive Vice President and Chief Operating
Officer of the Company since December 1997. He was Senior Vice President--
Acquisitions of the Company from March 1994 to December 1997, 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. 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. Dozier has been Senior Vice President--Operations of the Company since
December 1997. He was Vice President--Operations of the Company from May 1992 to
December 1997. 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 on all phases of production, reservoir evaluations, drilling and
completions in the Mid-Continent and Gulf Coast areas. He has a B.S. Degree in
Petroleum Engineering from the University of Texas.
Mr. 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
-28-
major in Petroleum Marketing from the University of Tulsa, and a Juris Doctor
from the University of Michigan Law School.
Mr. Lowe has been Vice President--Marketing of the Company since December
1997. He was General Manager--Marketing of the Company from July 1992 to
December 1997. From September 1983 to November 1990, he was employed by Maxus
Energy Corporation, formerly Diamond Shamrock Exploration Company, serving as
Manager--Marketing and in various other management and supervisory capacities.
From 1981 to October 1983, he was employed by American Quasar Exploration
Company as Manager--Oil and Gas Marketing. From 1978 to 1981, he was employed by
Texas Pacific Oil Company serving in various positions in production and
marketing. He has a B.S. Degree in Education from Texas Tech University.
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 has been Vice President--Corporate Development of the Company
since 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.
Mr. Thalken has been Vice President--Acquisitions of the Company since
December 1997. He was Acquisitions Technical Manager of the Company from May
1995 to December 1997 and an acquisitions engineer with the Company from January
1992 to May 1995. From October 1990 to December 1991, he was employed by Enron
Oil and Gas Company, serving as a production engineer. From May 1983 to
September 1990, he was employed by Exxon Company, USA, in various engineering
and supervisory capacities. He has a B.S. Degree in Mechanical Engineering from
Kansas University.
-29-
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 54 of the Company's 1997 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
28 of the Company's 1997 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 29 through 33 of the Company's 1997 Annual Report to Stockholders.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this Item is incorporated by reference from
pages 34 through 53 of the Company's 1997 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 1998 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."
-30-
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."
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 1997 Annual Report to Stockholders:
Annual Report
Page
-------------
Consolidated Balance Sheets as of December 31, 1997 and 1996..... 34
Consolidated Statements of Income for the years ended
December 31, 1997, 1996 and 1995................................ 35
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1997, 1996 and 1995............ 36
Consolidated Statements of Cash Flows for the years ended
December 31, 1997, 1996 and 1995................................ 37
Notes to Consolidated Financial Statements for the years ended
December 31, 1997, 1996 and 1995 ............................... 38 through 52
Report of Independent Public Accountants......................... 53
(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 notes
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, as amended, of the Company
(Filed as Exhibit 3.2 to the Company's report on Form 10-Q for the
quarter ended June 30, 1997, filed August 13, 1997).
3.2 Restated By-laws of the Company (Filed as Exhibit 3.2 to the
Company's Registration Statement on Form S-1, Registration No.
33-35289 (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).
-31-
4.3 Indenture dated as February 5, 1997, between The Chase Manhattan
Bank, as Trustee, and the Company (Filed as Exhibit 4.3 to the
Company's report on Form 10-K for the year ended December 31, 1996,
filed March 27, 1997).
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* 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).
10.4* 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).
10.5* 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).
10.6* 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).
10.7* 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).
10.8* 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).
10.9* 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")).
10.10* 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).
10.11* 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).
10.12 Amended and Restated Credit Agreement dated December 8, 1997, among
the Company, as borrower, certain commercial lending institutions,
as lenders, and Bank of Montreal, as agent.
10.13 Purchase and Sale Agreement dated as of February 12, 1997, among the
Company, Burlington Resources Oil & Gas Company and Glacier Park
Company, and Amendments thereto dated March 11, 1997, and March 20,
1997 (filed as Exhibit 2 to the Company's report on Form 8-K filed
April 16, 1997).
13. Portions of the Company's 1997 Annual Report to Stockholders.
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21. Subsidiaries of the Company.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Netherland, Sewell & Associates, Inc.
27.1 Financial Data Schedule for fiscal 1997.
27.2 Restated Financial Data Schedule for fiscal 1997 interim periods.
27.3 Restated Financial Data Schedule for fiscal 1996 and fiscal 1996
interim periods.
99.1 Letter of Netherland, Sewell & Associates, Inc. dated March 18,
1998, regarding U.S. oil and gas reserve information.
99.2 Letter of Netherland, Sewell & Associates, Inc. dated March 19,
1998, regarding South American oil and gas reserve information.
____________________
* Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K.
Form 8-K was filed October 16, 1997, to report under Item 5 (a) the
Company's two-for-one common stock split effected on October 7, 1997, and (b)
certain pro forma financial information of the Company.
No other reports on Form 8-K were filed during the fourth quarter of the
fiscal year ended December 31, 1997.
-33-
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, 1998 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:
SIGNATURE TITLE DATE
--------- ----- ----
/s/ C. C. Stephenson, Jr. Director and Chairman March 27, 1998
- ---------------------------- of the Board
C. C. Stephenson, Jr.
/s/ Jo Bob Hille Director and Vice March 27, 1998
- ---------------------------- Chairman of the Board
Jo Bob Hille
/s/ S. Craig George Director, President and March 27, 1998
- --------------------------- Chief Executive Officer
S. Craig George (Principal Executive Officer)
/s/ William C. Barnes Director, Executive Vice March 27, 1998
- ---------------------------- President, Chief Financial
William C. Barnes Officer and Treasurer
(Principal Financial Officer)
/s/ Bryan H. Lawrence Director March 27, 1998
- ----------------------------
Bryan H. Lawrence
/s/ John T. McNabb, II Director March 27, 1998
- ----------------------------
John T. McNabb, II
/s/ Michael F. Meimerstorf Vice President and Controller March 27, 1998
- ---------------------------- (Principal Accounting Officer)
Michael F. Meimerstorf
-34-
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, as amended, of the Company
(Filed as Exhibit 3.2 to the Company's report on Form 10-Q for the
quarter ended June 30, 1997, filed August 13, 1997).
3.2 Restated By-laws of the Company (Filed as Exhibit 3.2 to the
Company's Registration Statement on Form S-1, Registration No.
33-35289 (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 (Filed as Exhibit 4.3 to the
Company's report on Form 10-K for the year ended December 31, 1996,
filed March 27, 1997).
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* 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) .
10.4* 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).
10.5* 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).
10.6* 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).
10.7* 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).
10.8* 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).
10.9* 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")).
10.10* 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).
10.11* 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).
10.12 Amended and Restated Credit Agreement dated December 8, 1997, among
the Company, as borrower, certain commercial lending institutions,
as lenders, and Bank of Montreal, as agent.
10.13 Purchase and Sale Agreement dated as of February 12, 1997, among the
Company, Burlington Resources Oil & Gas Company and Glacier Park
Company, and Amendments thereto dated March 11, 1997, and March 20,
1997 (filed as Exhibit 2 to the Company's report on Form 8-K filed
April 16, 1997).
13. Portions of the Company's 1997 Annual Report to Stockholders.
21. Subsidiaries of the Company.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Netherland, Sewell & Associates, Inc.
27.1 Financial Data Schedule for fiscal 1997.
27.2 Restated Financial Data Schedule for fiscal 1997 interim periods.
27.3 Restated Financial Data Schedule for fiscal 1996 and fiscal 1996
interim periods.
99.1 Letter of Netherland, Sewell & Associates, Inc. dated March 18,
1998, regarding U.S. oil and gas reserve information.
99.2 Letter of Netherland, Sewell & Associates, Inc. dated March 19,
1998, regarding South American oil and gas reserve information.
_____________________
* Management contract or compensatory plan or arrangement.