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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, 1998
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-10578
VINTAGE PETROLEUM, INC.
(Exact name of registrant as specified in its charter)
Delaware 73-1182669
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
4200 One Williams Center
Tulsa, Oklahoma 74172
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (918) 592-0101
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ---------------------
Common Stock, $.005 Par Value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
As of March 3, 1999, 53,107,066 shares of the Registrant's Common Stock
were outstanding, and the aggregate market value of the Common Stock held by
non-affiliates was approximately $179,878,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the Annual Meeting of
Stockholders to be held May 11, 1999, are incorporated by reference into Part
III of this Form 10-K.
VINTAGE PETROLEUM, INC.
FORM 10-K
YEAR ENDED DECEMBER 31, 1998
TABLE OF CONTENTS
PART I
Page
----
Items 1 and 2 Business and Properties................................................................... 1
Item 3. Legal Proceedings......................................................................... 19
Item 4. Submission of Matters to a Vote of Security-Holders....................................... 19
Item 4A. Executive Officers of the Registrant...................................................... 20
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters..................... 23
Item 6. Selected Financial Data................................................................... 24
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 25
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................................ 34
Item 8. Financial Statements and Supplementary Data............................................... 36
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...... 36
PART III
Item 10. Directors and Executive Officers of the Registrant........................................ 36
Item 11. Executive Compensation.................................................................... 36
Item 12. Security Ownership of Certain Beneficial Owners and Management............................ 36
Item 13. Certain Relationships and Related Transactions............................................ 37
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K........................... 37
Signatures................................................................................................. 40
i
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 oil and gas reserves" are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. "Proved
developed oil and gas reserves" are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
"Proved undeveloped oil and gas reserves" are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
ii
Forward-Looking Statements
This Form 10-K includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included in this Form 10-K which address
activities, events or developments which the Company expects or anticipates will
or may occur in the future are forward-looking statements. The words
"believes," "intends," "expects," "anticipates," "projects," "estimates,"
"predicts" and similar expressions are also intended to identify forward-looking
statements.
These forward-looking statements include, among others, such things as:
. our Year 2000 plans;
. the amount and nature of future capital expenditures;
. wells to be drilled or reworked;
. oil and gas prices and demand;
. exploitation and exploration prospects;
. estimates of proved oil and gas reserves;
. reserve potential;
. development and infill drilling potential;
. expansion and other development trends of the oil and gas industry;
. business strategy;
. production of oil and gas reserves; and
. expansion and growth of our business and operations.
These statements are based on certain assumptions and analyses made by the
Company in light of its experience and its perception of historical trends,
current conditions and expected future developments as well as other factors it
believes are appropriate in the circumstances. However, whether actual results
and developments will conform with the Company's expectations and predictions is
subject to a number of risks and uncertainties which could cause actual results
to differ materially from the Company's expectations, including:
. the risk factors discussed in this Form 10-K and listed from time to
time in the Company's filings with the Securities and Exchange
Commission;
. oil and gas prices;
. exploitation and exploration successes;
. continued availability of capital and financing;
. general economic, market or business conditions;
. the acquisition and other business opportunities (or lack thereof) that
may be presented to and pursued by the Company ;
. changes in laws or regulations; and
. other factors, most of which are beyond the control of the Company.
Consequently, all of the forward-looking statements made in this Form 10-K
are qualified by these cautionary statements and there can be no assurance that
the actual results or developments anticipated by the Company will be realized
or, even if substantially realized, that they will have the expected
consequences to or effects on the Company or its business or operations. The
Company assumes no obligation to update publicly any such forward-looking
statements, whether as a result of new information, future events or otherwise.
iii
PART I
Items 1 and 2. Business and Properties.
General
The Company is an independent oil and gas company focused on the
acquisition of oil and gas properties which contain the potential for increased
value through exploitation and exploration. 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 exploratory wells. The Company believes that its primary strengths are its
ability to add reserves at attractive prices, and its low cost operating
structure.
At December 31, 1998, the Company owned and operated producing properties
in 13 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 1998, the Company acquired additional producing
properties in California and Texas. 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. In 1996, the Company 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. In November 1998,
the Company purchased, through a wholly-owned subsidiary, a subsidiary of Elf
Aquitaine which operates through a branch in Ecuador. This subsidiary currently
has producing properties in the Oriente Basin which it operates and provides the
Company with substantial undeveloped acreage which the Company believes has
significant exploration potential. While the Company has commenced operating
the subsidiary, the legal transfer of the subsidiary's stock to the Company is
subject to the prior approval by the Ecuadorian government. See "Acquisition
Activities."
As of December 31, 1998, the Company owned interests in 4,495 gross (2,398
net) producing wells in the United States, of which approximately 80 percent are
operated by the Company, 712 gross (696 net) producing wells in Argentina, of
which approximately 97 percent are operated by the Company, 4 gross (3 net)
producing wells in Bolivia, 100 percent of which are operated by the Company and
5 gross (2 net) producing wells in Ecuador, 100 percent of which are operated by
the Company. As of December 31, 1998, the Company's properties had proved
reserves of 298.9 MMBOE, comprised of 164.5 MMBbls of oil and 806.8 Bcf of gas,
with a present value of estimated future net revenues before income taxes
(utilizing a 10 percent discount rate) of $703 million and a standardized
measure of discounted future net cash flows of $648 million. From the first
quarter of 1996 through the fourth quarter of 1998, the Company increased its
average net daily production from 30,200 Bbls of oil to 45,500 Bbls of oil and
from 92,350 Mcf of gas to 126,850 Mcf of gas.
Financial information relating to the Company's industry segments is set
forth in Note 8 "Segment Information" to the Company's consolidated financial
statements included elsewhere in this Form 10-K.
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.
1
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 upside
potential, (b) focusing on exploitation, development and exploration 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
exploitation, development and exploration, (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
properties. This acquisition strategy has allowed the Company to rapidly
grow its reserves at favorable acquisition prices. From January 1, 1996,
through December 31, 1998, the Company acquired 119.2 MMBOE of proved oil and
gas reserves at an average acquisition cost of $2.82 per BOE. The Company
replaced through acquisitions approximately 1.9 times its production of 64.2
MMBOE during the same period. The Company is continually identifying and
evaluating acquisition opportunities, including acquisitions that would be
significantly larger than those consummated to date by the Company. No
assurance can be given that any such acquisitions will be successfully
consummated.
. 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, 1996, through December 31, 1998, the Company spent approximately
$277.5 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. As a result of all of its exploitation activities,
including development and infill drilling, during the three-year period ended
December 31, 1998, the Company succeeded in adding 54.1 MMBOE to proved
reserves, replacing approximately 84 percent of production during this
period. However, year-end 1998 oil and gas prices, which were much lower
than year-end 1997 prices, reduced reserves 49.0 MMBOE, resulting in net
upward revisions for the three years ended December 31, 1998, of 5.1 MMBOE.
The Company has an extensive inventory of exploitation and development
opportunities including identified projects which represent an inventory of
over 10 years at 1998 levels. Due to the current low oil and gas prices, the
Company anticipates reduced spending of approximately $17 million in 1999 on
exploitation and development projects, primarily in the United States.
. 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 reduces the cost
by increasing the success of its exploration program. From January 1, 1996,
through December 31, 1998, the Company spent approximately $128.2 million on
exploration activities, including the drilling of 70 gross (39.37 net)
exploration wells, of which approximately 57 percent gross (66 percent net)
were productive. The Company's exploration activities in 1998 were focused on
its core areas in the United States and Argentina as well as Bolivia. The
Company anticipates spending approximately $39 million during 1999 on
exploration projects, primarily in the United States and Bolivia.
2
. Low Cost Structure. The Company is an efficient operator and capitalizes on
its low cost structure in evaluating acquisition opportunities. The Company
generally achieves substantial reductions in labor and other field level
costs from those experienced by the previous operators. In addition, the
Company targets acquisition candidates which are located in its core areas
and provide opportunities for cost efficiencies through consolidation with
other Company operations. The lower cost structure has generally allowed the
Company to substantially improve the cash flow of newly acquired properties.
. Financial Flexibility. The Company is committed to maintaining 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 and a private
debt offering in January 1999 under Rule 144A. These seven offerings provided
the Company with aggregate net proceeds of approximately $561 million. The
unused portion of the Company's revolving credit facility as of February 28,
1999, was approximately $187 million. The Company anticipates, that as a
result of continued low oil and gas prices, the borrowing base will be
significantly reduced at the bank's next borrowing base redetermination in
April 1999. However, the amount of any such reduction is unknown at this
time.
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 continuing emphasis on reserve additions through property
acquisitions reflects its belief that 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.
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, the Company expanded its South American operations
into Bolivia and in 1998 into Ecuador. The Company is constantly identifying
and evaluating additional acquisition opportunities which may lead to expansion
into new domestic core areas or other countries which the Company believes are
politically stable.
3
From January 1, 1996, through December 31, 1998, the Company made oil and
gas property acquisitions involving total costs of approximately $336.1 million.
As a result of these acquisitions, the Company acquired approximately 119.2
MMBOE of proved oil and gas reserves. The following table summarizes the
Company's acquisition experience during the periods indicated:
Proved Reserves When Acquired Cost
---------------------------- Per BOE
Acquisition Oil Gas When
Costs (MBbls) (MMcf) MBOE Acquired
------------- ------- -------- ------- --------
(In thousands)
U.S. Acquisitions:
1996.......................................... $ 50,480 8,095 20,787 11,560 $4.37
1997.......................................... 133,548 24,653 62,253 35,029 3.81
1998.......................................... 70,805 5,452 53,027 14,290 4.96
-------- ------ ------- -------
Total U.S. Acquisitions................... 254,833 38,200 136,067 60,879 4.19
-------- ------ ------- -------
International Acquisitions:
1996.......................................... 40,802 7,802 57,758 17,428 2.34
1997.......................................... 6,201 758 111,212 19,293 0.32
1998.......................................... 34,218 21,577 - 21,577 1.59
-------- ------ ------- -------
Total International Acquisitions.......... 81,221 30,137 168,970 58,298 1.39
-------- ------ ------- -------
Total U.S. and International Acquisitions........ $336,054 68,337 305,037 119,177 $2.82
======= ====== ======= =======
The following is a brief discussion of the significant acquisitions in
1998:
Western Gas Resources Properties (East Texas). On October 29, 1998, the
Company purchased certain producing oil and gas properties located in East Texas
from Western Gas Resources, Inc. for $42.1 million in cash (the "Western
Properties"). The Western Properties consist of five key onshore fields and a
number of smaller fields. The Company now operates a substantial portion of the
properties, which had net daily production at the time of acquisition averaging
1,100 Bbls of condensate and natural gas liquids and 3,800 Mcf of gas or a total
of 1,733 BOE. Activities aimed at exploitation through development drilling,
workovers, recompletions and other projects as well as improving operational
efficiency are planned. Funds for this acquisition were provided through
advances on the Company's revolving credit facility.
Texaco Properties (West Coast). On November 10, 1998, the Company
purchased certain producing oil and gas properties located in northern
California from Texaco Exploration and Production, Inc. and an affiliate for
$28.7 million in cash (the "Texaco Properties"). The Texaco Properties consist
of 10 onshore fields in the Gas Country area of northern California covering
22,600 net acres. Net daily production at the time of acquisition was
approximately 9,700 Mcf of gas. The Company now operates fields representing
approximately 50 percent of the production. The Company plans activities aimed
at increasing gas production and reserves through focusing on improving
operational efficiency, exploitation activities and exploration drilling. Funds
for this acquisition were provided through advances on the Company's revolving
credit facility.
4
Elf Hydrocarbures Equateur (Ecuador). On November 4, 1998, the Company,
through a wholly-owned subsidiary, purchased from Elf Aquitaine 100 percent of
the outstanding shares of its French subsidiary, Elf Hydrocarbures Equateur,
S.A. ("EHE"). EHE has producing oil properties, along with substantial
undeveloped acreage, in Ecuador. The principal assets acquired include a 40
percent working interest in Block 14 and a 30 percent working interest in Block
17 in Ecuador's prolific Oriente Basin and estimated working capital of
approximately $7.2 million. Gross daily production is currently 3,300 Bbls of
oil (1,100 Bbls net). The Company believes that these properties have
significant upside potential which can be realized as additional pipeline
infrastructure is constructed. The acquisition cost for EHE of $41.4 million
(including the $7.2 million of working capital) was funded through $14.9 million
of advances on the Company's revolving credit facility and the issuance of
1,325,000 shares of common stock of the Company valued at a guaranteed amount of
$20 per share, or $26.5 million. If the prevailing share price is not equal to
at least $20 per share after two years, then the Company will be required to
deliver additional consideration under the price guarantee provisions of the
agreement. Such additional consideration, if any, is payable, at the Company's
option, in cash or additional shares of the Company's common stock. Had the
Company been required to fulfill its commitment under the price guarantee at
December 31, 1998 (based on the average price for the preceding 60 trading days
of $10.57), it would have had to pay an additional $12.5 million in cash or
issue an additional 1.2 million shares of its common stock. While the Company
has commenced operating this subsidiary, the legal transfer of the stock of EHE
to the Company is subject to the prior approval by the Ecuadorian government.
The Company estimates that 35.9 MMBOE of proved reserves, as of the various
acquisition dates, were acquired in these three transactions for an aggregate
cost attributable to oil and gas assets of $105.0 million, resulting in an
average cost of $2.93 per BOE. This average cost per BOE is comparable to the
Company's average acquisition cost over the three-year period ended December 31,
1998, of $2.82 per BOE and the average acquisition cost since the Company's
inception of $2.87 per BOE.
Exploitation and Development Activities
The Company concentrates its acquisition efforts on proved producing
properties which demonstrate a potential for significant additional development
through workovers, recompletions, secondary recovery operations, the drilling of
development, infill or exploratory 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 striving to offset normal production declines
and to replace the Company's annual production. The results of their efforts
are reflected in revisions to reserves. Net revisions to reserves for 1998
(before the impact of lower oil and gas prices) totaled 24.8 MMBOE, or 102
percent of the Company's production of 24.3 MMBOE. However, the replacement of
these reserves was entirely offset by a 49.0 MMBOE downward revision of reserves
resulting from sharply lower oil and gas prices at year-end 1998 used in the
calculation of proved reserves.
The Company spent approximately $29.9 million on workover and recompletion
operations during 1998. A measure of the overall success of the Company's
recompletion and workover operations during 1998 (excluding minor equipment
repair and replacement) was that improved production or operating efficiencies
were achieved from approximately 81 percent of such operations.
Development drilling activity is generated both through the Company's
exploration efforts and as a result of 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.
5
During 1998, the Company participated in the drilling of 94 gross (82.72
net) development wells of which approximately 94 percent gross (95 percent net)
were productive. At December 31, 1998, the Company's proved reserves included
approximately 82 development or infill drilling locations on its U.S. acreage
and 126 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 $30 million in the U.S. and $38 million in South America on
development/infill drilling during 1998. The Company also spent approximately
$9.5 million on the acquisition of development seismic data and other
development costs in 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 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:
United States. 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.
The Company believes ongoing reservoir studies will continue to identify
additional exploitation projects in addition to the 50 projects currently
identified.
Exploitation of the properties acquired from Burlington Resources, Inc. in
April 1997 (the "Burlington Properties") in the Company's Gulf Coast area
proceeded on schedule for the first half of 1998. Due to low oil prices, the
activity planned for the second half of 1998 was postponed. First half 1998
drilling and workovers produced the volumes the Company anticipated and it sees
no barrier to continued work other than product prices. A total of 14
horizontal wells were drilled in the Luling field and three in the West Ranch
field. The total of the gross initial rate for these 17 wells was 3,518 Bbls of
oil per day. In addition, a total of 24 workovers were completed on the
Burlington Properties in the Luling, Darst Creek, West Ranch, Main Pass and East
Picoso fields resulting in a gross production build-up of 546 Bbls of oil per
day and 2,862 Mcf of gas per day. A large inventory of similar jobs remains for
these fields. Other Gulf Coast activity occurred in seven fields where two
recompletions, five workovers and a new well resulted in total net production
increases of 290 Bbls of oil per day and 4,420 Mcf of gas per day.
South America. 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 19,450 Bbls
of oil currently. Drilling activity commenced during February 1996 and continued
through 1998, with 157 wells having been completed. The three focus areas for
drilling activity to date have been Canadon Minerales with 56 wells, Canadon
Seco with 43 wells, and Meseta Espinosa with 45 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 15,750 Bbls.
Currently, the Company has suspended its drilling program in Argentina pending
the return of higher oil prices.
During 1998, the Company acquired 57 square miles (147 square kilometers)
of 3-D seismic data for a total of 204 square miles (527 square kilometers)
acquired since 1996 to aid in the optimum placement of drilling locations in
Argentina. The Company believes that substantial upside potential can continue
to be economically exploited with the aid of this 3-D seismic. Acquisition of
additional 3-D seismic is planned when oil prices recover to a level that
supports additional drilling activities.
6
The Company has also continued its endeavor to optimize existing secondary
recovery projects and to initiate new waterfloods in Argentina. The waterflood
work in 1996 and 1997 on Canadon Minerales Block 123A, Canadon Minerales Block
123E, Cerro Wenceslao Flanco Oriental and Piedra Clavada Block 24 has resulted
in incremental gross daily production responses of 1,050 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. 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.
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. During the second
quarter of 1998, the Company drilled the Supuati X-1-ST located in the southern
Chaco block. The well was drilled to a depth of 12,515 feet encountering 20
feet of net oil pay in the Devonian Iquiri sand. Exploitation and production of
the Devonian Iquiri reservoir in the southern Chaco block will be deferred until
the return of higher oil prices.
Activity in early 1999 will continue to increase as the Bolivia-to-Brazil
pipeline is completed and gas deliveries to the Brazilian market are initiated
in mid-1999. In preparation for the opening of the Brazilian market, the Company
has completed work to upgrade the existing facilities and compression in Nupuco
and Naranjillos. These facility improvements along with planned additional
development drilling and exploration activities should position the Company to
take advantage of this increased gas market opportunity.
Exploration
The Company's exploration program is designed to contribute significantly
to its growth. Management divides the strategic objectives of its exploration
program into two parts. First, in the U.S. and in Argentina, the Company's
exploration focus is in its core areas where its geological and engineering
expertise and experience are greatest. State-of-the-art technology, including
3-D seismic, is employed to identify prospects. Exploration in the U.S. and
Argentina is designed to generate reserve growth in the Company's core areas in
combination with its exploitation activities. The Company's longer-term plans
are to increase the magnitude of this program with a goal of achieving
production replacement through core area exploration. Such exploration is
characterized by numerous individual projects with medium to low risk.
Secondly, international exploration targets significant long-term reserve growth
and value creation. International exploration projects in Ecuador, Bolivia and
Yemen are characterized by higher potential and higher risk. The Company spent
approximately $73 million on exploration activities during 1998, approximately
$58 million in the U.S. and Argentina and approximately $15 million in other
international areas.
The following is a brief discussion of the primary areas of exploration
activity for the Company:
United States. Since the initial discovery in 1996, the Company has made
successful completions on eight of 10 wells drilled in its Galveston Bay-
Umbrella Point exploration program in its Gulf Coast area. Gross oil and gas
production from these wells reached a peak of approximately 76 MMcf of gas per
day and 1,600 Bbls of oil per day and are currently producing at gross daily
rates of 38 MMcf of gas and 1,600 Bbls of oil. The recently completed ST 2-3A
was the most significant well drilled in 1998. This Text II discovery is
currently producing at gross rates of 1,500 Bbls of oil per day and 2.5 MMcf of
gas per day. This test was the first of four anomalies that are in close
proximity to the Company's Fisher's Reef field. The three remaining untested
features are planned to be drilled in the future.
7
Currently, an onshore 40-square-mile 3-D survey in the nearby Cedar Point
area is being interpreted. Preliminary interpretations look promising and
drilling of the initial test wells should take place in 1999. This project is
immediately northwest of the Company's Galveston Bay area and will have the same
targets with similar reserve potential. The Company also recently finished
processing a 180-square-mile 3-D survey in its South Texas E1 Sauz project.
Several gas prospects were identified and a minimum of two wells are planned for
drilling in 1999.
The Company is participating in a regional Western Anadarko 3-D Seismic
Alliance in its Mid-Continent area in which over 640 square miles of non-
contiguous, high-quality 3-D seismic has been shot. Several different play
concepts are being pursued and two significant discoveries were made in 1998.
The Thomas #2 was completed in the Gold prospect in Dewey County, Oklahoma. The
well was completed from the Hunton formation and is currently producing at a
gross rate exceeding 2.6 MMcf of gas per day. The Elise #1 was drilled in the
Sundevil prospect of Lipscomb County, Texas. The well is currently producing at
a gross rate of 1.5 MMcf of gas per day from the Morrow formation with
additional uphole potential yet to be tested. The first offset, the Katy, was
also found productive from the same Morrow sand.
South America. The Company believes that its existing projects in Bolivia
have the potential to significantly increase reserves. Activity in Bolivia
during 1997 and 1998 was relatively modest due to restriction of the current gas
market to Argentina. However, the activity increased beginning in late 1998 and
will continue to significantly increase in early 1999 as the Bolivia-to-Brazil
pipeline is completed and gas begins to flow into the Brazilian market by mid-
1999. This third-party pipeline is designed to deliver approximately one Bcf of
gas per day to Brazilian markets, as compared to the current export market to
Argentina of approximately 200 MMcf of gas per day.
During the first quarter of 1998, the Company completed acquisition of a
64-square-mile (165 square kilometer) 3-D seismic survey on the southern Chaco
and Nupuco concessions in Bolivia. Based on the seismic survey, the Company
drilled the Chaco Sur X-101 on the southern Chaco block to a depth of 6,500
feet. The well encountered approximately 115 feet of net gas pay based on log
analysis in the Carboniferous sands. This well tested at a gross daily rate of
13.5 MMcf of gas and will commence production early in the second quarter of
1999. Additional potential drilling locations targeting the shallow
Carboniferous and deep Devonian Huamampampa reservoirs have been identified.
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. Multiple exploration well targets have been located and more are
expected to follow based upon the interpretation of a 3-D seismic survey
covering the entire concession. This 3-D survey was acquired in early 1998. The
first exploration well drilled in this concession, the Naranjillos X-104, was a
new field discovery in the Devonian Iquiri. This well tested at a gross daily
rate of 5 MMcf of gas. The well is currently shut in pending the assignment of
market allocation volumes into the Bolivia-to-Brazil pipeline. Estimated initial
production is expected to occur early in the year 2000. Drilling is expected to
continue throughout 1999 and 2000 to develop reserves for the new Brazilian
market.
Yemen. The Company has entered into a farm-in agreement with TransGlobe
Energy to explore on the S-1 Damis Block in central Yemen. The block covers
approximately one million acres (4,484 square kilometers). The Company earned a
75 percent interest in the S-1 Damis Block for its commitment to fulfill 100
percent of the initial phase exploration work program of $11 million over two
and one-half years. 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. The 3-D seismic program commenced late in the fourth quarter
of 1998 and will conclude during the first quarter of 1999.
8
Oil and Gas Properties
At December 31, 1998, the Company owned and operated producing properties
in 13 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 new core areas in the San Jorge Basin of
Argentina during 1995, Bolivia during 1996 and Ecuador in 1998. As of December
31, 1998, the Company operated approximately 4,311 productive wells and also
owned non-operating interests in 905 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 sets forth estimates of the proved oil and gas reserves
of the Company at December 31, 1998, as estimated by the independent petroleum
consultants of Netherland, Sewell & Associates ("Netherland, Sewell") for the
United States, Argentina and Ecuador and as estimated by the independent
petroleum consultants of DeGolyer and MacNaughton for Bolivia:
Oil (MBbls) Gas (MMcf)
------------------------------------ ------------------------------------- MBOE
Developed Undeveloped Total Developed Undeveloped Total Total
--------- --------- -------- --------- --------- --------- ---------
West Coast......... 26,112 2,549 28,661 111,504 7,126 118,630 48,433
Gulf Coast......... 14,246 1,451 15,697 86,002 17,397 103,399 32,930
East Texas......... 8,125 467 8,592 82,426 13,977 96,403 24,659
Mid-Continent...... 2,998 1,259 4,257 50,439 16,641 67,080 15,437
-------- --------- -------- --------- --------- --------- ---------
Total U.S. ..... 51,481 5,726 57,207 330,371 55,141 385,512 121,459
-------- --------- -------- --------- --------- --------- ---------
Argentina.......... 47,167 27,674 74,841 12,024 - 12,024 76,845
Bolivia............ 4,390 3,974 8,364 278,317 130,980 409,297 76,580
Ecuador............ 1,255 22,790 24,045 - - - 24,045
-------- --------- -------- --------- --------- --------- ---------
Total Company... 104,293 60,164 164,457 620,712 186,121 806,833 298,929
======== ========= ======== ========= ========= ========= =========
Estimates of the Company's 1998 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.
The following is a brief discussion of the Company's oil and gas operations
in its core areas:
West Coast Area. The West Coast area includes oil and gas properties
located primarily in Kern, Ventura, Santa Barbara and Sacramento counties of
California. The Stevens, Forbes, Grubb and Sisquoc formations are the dominant
producing reservoirs on the Company's acreage in California with well depths
ranging from 800 feet to 14,300 feet. As of December 31, 1998, the area
comprised 16 percent of the Company's total proved reserves and 40 percent of
the Company's U.S. proved reserves. The Company currently operates 1,253 active
wells and owns an interest in 220 productive wells operated by others. During
1998, total net daily production averaged approximately 16,000 BOE, or 35
percent of the total U.S. production. Numerous workovers and recompletion
opportunities exist in the San Miguelito, Rio Vista, Buena Vista and Rincon
fields. Additional infill drilling locations are available in the San Miguelito
and Buena Vista fields. The San Miguelito field also has significant waterflood
potential that may add significant reserves.
9
Gulf Coast Area. The Gulf Coast area includes properties located in south
Texas, the south half of Louisiana, Alabama, Mississippi and wells located in
state and federal waters in the Gulf of Mexico. Production in this area is
predominantly from structural accumulations in reservoirs of Miocene age. The
depths of the producing reservoirs range from 1,200 feet to 14,500 feet. At
December 31, 1998, the Gulf Coast area comprised approximately 11 percent of the
Company's total proved reserves and 27 percent of its U.S. reserves. The
Company currently operates 1,531 productive wells in this area and owns an
additional interest in 178 productive wells. Total net daily production from
this area during 1998 averaged approximately 20,700 BOE, or 45 percent of total
U.S. production. A significant inventory of workovers and recompletions exist
in eight major Gulf Coast fields from Alabama to South Texas. Development
drilling potential is also available in six fields in Texas and Louisiana.
East Texas Area. The East Texas area includes properties located in the
northeastern portion of Texas and the north half of Louisiana. The Cotton
Valley, Smackover, Travis Peak and Wilcox formations are the dominant producing
reservoirs on the Company's acreage in this area from wells ranging in depth
from 1,300 feet to 14,800 feet. The East Texas area comprised approximately
eight percent of the Company's December 31, 1998, total proved reserves. The
Company currently operates 427 productive wells in this area and owns an
interest in an additional 206 productive wells. During 1998, net daily
production averaged approximately 5,500 BOE, or 12 percent of total U.S.
production. 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.
Mid-Continent Area. The Mid-Continent area extends from the Arkoma Basin
of eastern Oklahoma to the Texas Panhandle and north to include Kansas. The Red
Fork, Morrow, Skinner and Hoxbar formations are the dominant producing
reservoirs on the Company's acreage in this area with well depths ranging from
1,560 feet to 17,260 feet. This area comprised five percent of the Company's
total proved reserves as of December 31, 1998. The Company currently operates
400 productive wells in this area and owns an interest in an additional 279
productive wells. During 1998, net daily production averaged approximately
4,100 BOE, or nine percent of total U.S. production. Significant development
drilling and recompletion opportunities exist in the Marlow/Velma field plus
additional projects to improve the ultimate reserve recovery in the Shawnee
Townsite waterflood.
Argentina Concessions. The Argentina properties consist primarily of 13
mature producing concessions located on the south flank of the San Jorge Basin.
These concessions comprised approximately 26 percent of the Company's December
31, 1998, total proved reserves. During 1998, net daily production averaged
approximately 17,300 Bbls of oil. The Company currently operates 690 productive
wells (100 percent working interest) with net daily production of 17,000 Bbls of
oil. In addition, the Company owns an interest in 22 productive wells operated
by others. At December 31, 1998, the Company's proved reserves included
approximately 126 development or infill drilling locations and 306 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. For additional
information, see "Exploitation and Development Activities - South America."
Bolivia Concessions. The Bolivia properties consist of two producing
concessions and two exploration concessions located in the Chaco Basin of
Bolivia. The Company has 100 percent working interests in the Chaco and
Naranjillos exploration concession as well as in the producing Porvenir
concession. In the other producing concession, Nupuco, the Company has a 50
percent working interest. The Company operates all four concessions. These
concessions comprise approximately 26 percent of the Company's December 31,
1998, total proved reserves and include 4 gross (3 net) active producing wells,
all of which are operated by the Company. The current net daily production is
approximately 10,000 Mcf of gas and 180 Bbls of condensate. For additional
information, see "Exploitation and Development Activities - South America."
10
Ecuador Concessions. The Ecuador properties consist of two producing
concessions and one exploration concession. The Company has a 30 percent
working interest in the producing Block 17 concession and a 40 percent working
interest in the producing Block 14 concession. The Company also has a 53
percent interest in the Shiripuno exploration concession. The Company currently
operates 5 gross (2 net) productive wells with current gross daily production of
3,300 Bbls of oil (1,100 Bbls net). These concessions comprised eight percent
of the Company's December 31, 1998, total proved reserves. Development plans
for Block 14 and Block 17 were approved by the Ecuadorian Government during
December 1998. Under these plans, the existing production facilities will be
upgraded during the second half of 1999 to increase the oil handling capacity
from 3,500 Bbls of oil per day to approximately 10,000 Bbls of oil per day.
Development drilling on both concessions will be deferred until product prices
recover.
Marketing
The Company's U.S. gas production and gathered gas are sold 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 none of
the Company's gas in the U.S. 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. The Company's Bolivia average gas price is
tied to a long-term contract under which the base price is adjusted for changes
in specified fuel oil indexes. During 1998, these fuel oil indexes have
decreased in conjunction with the current low oil price environment.
The Company's domestic gas marketing activities are handled by Vintage Gas,
Inc., its wholly-owned gas marketing affiliate. This marketing affiliate earns
fees through the marketing of Company produced gas as well as purchases of gas
on the spot market from 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. No purchaser of
the Company's oil or gas during 1998 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. In 1998, the Company entered
into various natural gas basis swaps for the calender year 1999 covering a total
of 82,000 MMBtu of gas per day plus an additional 3,000 MMBtu per day for the
period of January through October 1999. These natural gas basis swaps were used
to reduce the Company's exposure to increases in the basis differential between
the NYMEX reference price and the Company's industry delivery point indexes
under which the gas is sold.
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 21 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 350 miles of varying diameter
pipe with a combined capacity in excess of 240 MMcf of gas per day. At December
31, 1998, there were 353 wells (331 wells (94 percent) which are operated by the
Company) connected to these systems. Generally, the gathering systems buy gas at
the wellhead on the basis of a percentage of the resale price under contracts
containing terms of one to 10 years.
11
Reserves
At December 31, 1998, the Company had proved reserves of 298.9 MMBOE,
comprised of 164.5 MMBbls of oil and 806.8 Bcf of gas as estimated by the
independent petroleum consultants of Netherland, Sewell for the United States,
Argentina and Ecuador and as estimated by the independent petroleum consultants
of DeGolyer and MacNaughton for Bolivia. For additional information on the
Company's oil and gas reserves, see "Oil and Gas Properties." The following
table sets forth, at December 31, 1998, 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................................................................. $1,216,347
Present value of future net revenues before income taxes, discounted at 10 percent.. 703,211
Standardized measure of discounted future net cash flows............................ 648,222
Proved Developed Reserves:
Future net revenues................................................................. $ 895,500
Present value of future net revenues before income taxes, discounted at 10 percent.. 590,766
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, 1998, economic
conditions. The estimated future production is priced at prices prevailing at
December 31, 1998. The resulting estimated future gross revenues are reduced by
estimated future costs to develop and produce the proved reserves, based on
December 31, 1998, 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 "Supplementary Financial Information for Oil and Gas
Producing Activities" to the Company's consolidated financial statements
included elsewhere in this Form 10-K.
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
"Supplementary Financial Information for Oil and Gas Producing Activities" to
the Company's consolidated financial statements included elsewhere in this Form
10-K.
12
Productive Wells; Developed Acreage
The following table sets forth the Company's productive wells and developed
acreage assignable to such wells at December 31, 1998:
Productive Wells
--------------------------------------
Developed Acreage Oil Gas Total
-------------------- ------------ ---------- ------------
Gross Net Gross Net Gross Net Gross Net
--------- -------- ------ ----- ----- ---- ------ ----
U.S. ....... 702,210 434,570 3,043 1,764 1,452 634 4,495 2,398
Argentina... 1,008,339 844,372 712 696 - - 712 696
Bolivia..... 99,458 88,339 - - 4 3 4 3
Ecuador..... 33,592 12,787 5 2 - - 5 2
--------- --------- ----- ----- ----- --- ----- -----
Total.... 1,843,599 1,380,068 3,760 2,462 1,456 637 5,216 3,099
========= ========= ===== ===== ===== === ===== =====
Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections to commence
deliveries and oil wells awaiting connection to production facilities. Wells
which are completed in more than one producing horizon are counted as one well.
Undeveloped Acreage
At December 31, 1998, the Company held the following undeveloped acres
located in the United States, Bolivia, Ecuador and Yemen. With respect to such
United States acreage held under leases, 22,769 gross (9,767 net) acres are held
under leases with primary terms that expire at varying dates through December
31, 2002, unless commercial production is commenced. The Bolivia, Ecuador and
Yemen acreage are held under concessions with primary terms that expire at
varying dates in 1999, 2000 and 2001. Although substantial undeveloped acreage
exists in the Company's concessions in Argentina, the concessions in their
entirety are held by production.
Gross Net
State/Country Acres Acres
- ------------------------ -------- -------
California............. 9,922 9,540
Colorado............... 1,248 468
Kansas................. 1,940 1,799
Louisiana.............. 1,100 1,100
Montana................ 6,986 2,477
New Mexico............. 1,471 368
Oklahoma............... 45,047 20,248
Texas.................. 86,188 28,023
Wyoming................ 10,879 3,576
------------------
Total U.S. ..... 164,781 67,599
Bolivia............... 485,552 485,552
Ecuador............... 494,226 148,268
Yemen................. 1,108,019 831,014
--------------------
Total Company... 2,252,578 1,532,433
====================
13
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,
--------------------------------
1998 1997 1996
--------- ------- ----------
Production:
Oil (MBbls) -
U.S.......................... 9,912 9,692 7,694
Argentina.................... 6,322 5,630 4,245
Bolivia...................... 122 135 -
Ecuador...................... 78 - -
Total................ 16,434 15,457 11,939
Gas (MMcf) -
U.S.......................... 42,176 36,623 32,366
Bolivia...................... 5,062 6,068 -
Total........................ 47,238 42,691 32,366
Total MBOE........... 24,307 22,573 17,333
Average Sales Prices:
Oil (per Bbl) -
U.S.......................... $ 11.20 $ 17.23 $ 17.19 (b)
Argentina.................... 10.41 16.67 (a) 15.91 (b)
Bolivia...................... 11.31 16.52 -
Ecuador...................... 5.77 - -
Total................ 10.87 17.02 (a) 16.73 (b)
Gas (per Mcf) -
U.S.......................... 1.99 2.33 1.81
Bolivia...................... .78 1.10 -
Total................ 1.86 2.16 1.81
Production Costs (per BOE):
U.S.......................... $ 5.57 $ 5.64 $ 5.42
Argentina.................... 4.23 4.29 4.93
Bolivia...................... 1.47 1.00 -
Ecuador...................... 3.00 - -
Total................ 5.05 5.07 5.30
(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.
14
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,
-----------------------------------------
1998 1997 1996
----------- ------------- ------------
Gross Net Gross Net Gross Net
----- ----- ----- ---- ----- -----
Development:
United States -
Productive.......... 34 24.94 30 15.74 22 12.67
Non-Productive...... 4 1.78 3 0.80 5 2.94
Argentina -
Productive.......... 54 54.00 55 55.00 39 39.00
Non-Productive...... 2 2.00 2 2.00 2 2.00
----- ----- ---- ----- ----- -----
Total.......... 94 82.72 90 73.54 68 56.61
===== ===== ==== ===== ===== =====
Exploratory:
United States -
Productive.......... 22 15.17 7 3.01 6 3.00
Non-Productive...... 13 3.78 6 2.87 7 3.12
Argentina -
Productive.......... 2 2.00 - - 2 2.00
Non-Productive...... - - 1 1.00 1 1.00
Other International -
Productive.......... 1 1.00 - - - -
Non-Productive...... - - 1 0.42 1 1.00
----- ----- ---- ----- ----- -----
Total.......... 38 21.95 15 7.30 17 10.12
===== ===== ==== ===== ===== =====
Total:
Productive ............ 113 97.11 92 73.75 69 56.67
Non-Productive......... 19 7.56 13 7.09 16 10.06
----- ----- ---- ----- ----- -----
Total............. 132 104.67 105 80.84 85 66.73
===== ====== ==== ===== ===== =====
The above well information excludes wells in which the Company has only a
royalty interest.
At December 31, 1998, the Company was a participant in the drilling or
completion of 11 gross (9.62 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.
15
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.
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.
16
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 any amounts that are material in the aggregate to the
Company's overall operations by reason of environmental or occupational safety
and health laws and regulations, but because such laws and regulations are
frequently changed, the Company is unable to predict the ultimate cost of
compliance.
Certain of the Company's oil and gas leases are granted by the federal
government and administered by various federal agencies. Such leases require
compliance with detailed federal regulations and orders which regulate, among
other matters, drilling and operations on these leases and calculation of
royalty payments to the federal government. The Mineral Lands Leasing Act of
1920 places limitations on the number of acres under federal leases that may be
owned in any one state. While subject to this law, the Company does not have a
substantial federal lease acreage position in any state or in the aggregate.
The Mineral Lands Leasing Act of 1920 and related regulations also may restrict
a corporation from the holding of a federal onshore oil and gas lease if stock
of such corporation is owned by citizens of foreign countries which are not
deemed reciprocal under such Act. Reciprocity depends, in large part, on
whether the laws of the foreign jurisdiction discriminate against a United
States person's ownership of rights to minerals in such jurisdiction. The
purchase of such 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, the 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.
17
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's status as a gatherer. As a result of FERC's allowing a
number of interstate pipelines to spin-off gathering systems and thereby exempt
them from Federal regulation, states are now enacting or considering statutory
and/or regulatory provisions to regulate gathering systems. The Company's
gathering systems could be adversely affected should they be subjected in the
future to the application of such state regulation.
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.
The Company's operations in Argentina, Bolivia and Ecuador 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. The Company's Bolivian projects are dependent, in part,
on the development of the Bolivia-to-Brazil gas pipeline.
Employees
The Company employs approximately 220 people in its Tulsa office whose
functions are associated with management, engineering, geology, land and legal,
accounting, financial planning, and administration. In addition, approximately
190 full time employees are responsible for the supervision and operation of its
U.S. field activities. The Company also has approximately 145 employees located
in South America for the management and operation of its properties in
Argentina, Bolivia and Ecuador, as well as 13 employees in Yemen. The Company
believes its relations with its employees are excellent.
18
Item 3. Legal Proceedings.
On November 5, 1996, the Province of Santa Cruz, Argentina brought suit
against the Company's subsidiary Cadipsa S.A. in the Corte Suprema de Justicia
de la Nacion (the Supreme Court of Justice of the Argentine Republic, Buenos
Aires, Argentina), Dossier No. s-1451, seeking to recover approximately $10.6
million (which sum includes interest) allegedly due as additional royalties on
four concessions granted in 1990 in which the Company currently owns a 100
percent working interest. The Company and its predecessors in title have been
paying royalties at an eight percent rate; the Province of Santa Cruz claims the
rate should be 12 percent. The amount of such claim will increase at the
differential of these royalty rates until this claim is resolved. With respect
to the 50 percent interest in the two concessions that the Company acquired from
British Gas, plc, the Company believes that it is entitled to indemnification by
British Gas, plc for any loss sustained by the Company as a result of this
claim. Such indemnification equals approximately $4.7 million of the current
$18.0 million claim. The Company has no indemnification from its predecessors
in title with respect to the payment of royalties on the other two concessions.
Although the Company cannot predict the outcome of this litigation, based upon
the advice of counsel, the Company does not expect this claim to have a material
adverse impact on the Company's financial position or results of operations.
The Company is also a named defendant in other lawsuits and is a party in
governmental proceedings from time to time arising in the ordinary course of
business. While the outcome of such other lawsuits or proceedings against the
Company cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the Company's financial position or
results of operations.
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, 1998.
19
Item 4A. Executive Officers of the Registrant.
The following table sets forth as of the date hereof 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. 62 Director and Chairman of the Board of Directors
Jo Bob Hille 57 Director and Vice Chairman of the Board of Directors
S. Craig George 46 Director, President and Chief Executive Officer
William L. Abernathy 47 Executive Vice President and Chief Operating Officer
William C. Barnes 44 Director, Executive Vice President, Chief Financial Officer,
Secretary and Treasurer
William E. Dozier 46 Senior Vice President - Operations
Robert W. Cox 53 Vice President - General Counsel
Andy R. Lowe 47 Vice President - Marketing
Michael F. Meimerstorf 42 Vice President and Controller
Robert E. Phaneuf 52 Vice President - Corporate Development
Barry D. Quackenbush 57 Vice President - Engineering
Larry W. Sheppard 44 Vice President - International
Martin L. Thalken 38 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 has a
B.S. Degree in Petroleum Engineering from the University of Oklahoma, and has
approximately 39 years of oil and gas experience.
Mr. Hille, the other co-founder of the Company, has been a Director of the
Company since June 1983 and Vice Chairman of the Company since September 1995.
He was also Chief Executive Officer of the Company from March 1994 to December
1997, President of the Company from May 1990 to September 1995, Chief Operating
Officer of the Company from April 1987 to March 1994, Executive Vice President
of the Company from June 1983 to May 1990 and Treasurer and Secretary of the
Company from June 1983 to April 1987. From August 1972 to March 1983, Mr. Hille
was employed by Andover where he served at various times primarily as Executive
Vice President and Vice President--Operations. Mr. Hille has a B.S. Degree in
Petroleum Engineering from the University of Tulsa, and has approximately 33
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.
20
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. From May 1992 to December 1997, he was Vice President--
Operations of the Company. From June 1983 to April 1992, he was employed by
Santa Fe Minerals where he held various engineering and management positions
serving most recently as Manager of Operations Engineering. From January 1975
to May 1983, he was employed by Amoco Production Company serving in various
positions where he worked all phases of production, reservoir evaluations,
drilling and completions in the Mid-Continent and Gulf Coast areas. He has a
B.S. Degree in Petroleum Engineering from the University of Texas.
Mr. Cox has been Vice President--General Counsel of the Company since March
1988. From August 1982 to March 1988, he was employed by Santa Fe Minerals and
its subsidiary, Andover, where he served at various times as Vice President--Law
and Regional Attorney. From April 1982 to August 1982, he was employed as
Corporate Attorney by Andover. Prior to that time, Mr. Cox was employed by
Amerada Hess Corporation, a major oil company, served as General Counsel and
Secretary of Kissinger Petroleum Corporation, an independent oil and gas
company, and served on the legal staff of Champlin Petroleum Company, an
independent oil and gas company. He has a B.S. Degree in Business
Administration with a major in Petroleum Marketing from the University of Tulsa,
and a Juris Doctor from the University of Michigan Law School.
Mr. 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.
21
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--Engineering of the Company since
May 1998. He was Vice President--Production of the Company from May 1990 to May
1998 and 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 1996. 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
the University of Kansas.
22
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
The Company's common stock commenced trading on the New York Stock Exchange
on August 3, 1990, under the symbol "VPI." The following table sets forth the
high and low sale prices per share of the Company's common stock, as reported in
the New York Stock Exchange composite transactions, and the cash dividends paid
per share of common stock, for the periods indicated:
Dividends
High Low Paid
-------- -------- ---------
1998
- ----
First Quarter 23 1/8 16 13/16 $ .02
Second Quarter 21 1/2 15 7/8 .02
Third Quarter 19 1/2 7 5/16 .02
Fourth Quarter 15 1/2 7 1/4 .025
1997
- ----
First Quarter 18 11/16 13 .015
Second Quarter 18 1/16 12 1/2 .015
Third Quarter 25 1/2 15 3/8 .015
Fourth Quarter 25 7/8 17 .02
Substantially all of the Company's stockholders maintain their shares in
"street name" accounts and are not, individually, stockholders of record. As of
December 31, 1998, the common stock was held by 106 holders of record and
approximately 7,200 beneficial owners.
The Company began paying a quarterly cash dividend in the fourth quarter of
1992. On December 7, 1998, the Company declared a regular quarterly cash
dividend of $.025 per share payable on January 6, 1999, to stockholders of
record at December 22, 1998. Due to the current historically low oil and gas
price environment, the Company has temporarily suspended its regular quarterly
cash dividend. Subject to restrictions under credit arrangements, the
determination of the amount of future cash dividends, if any, to be declared and
paid, will depend upon, among other things, the Company's financial condition,
funds from operations, the level of its capital expenditures and its future
business prospects. The Company's credit arrangements (including the indentures
for its outstanding senior subordinated indebtedness) contain certain
restrictions on the payment of cash dividends, the most restrictive of which
prohibits the payment of cash dividends if the Company's Consolidated Interest
Coverage Ratio (as defined in indentures) does not exceed 2.5 to 1.0. The
Company is currently prohibited from paying cash dividends.
On November 4, 1998, a wholly-owned subsidiary of the Company acquired all
of the outstanding shares of capital stock of Elf Hydrocarbures Equateur, S.A.
from Elf Aquitaine. As part of the consideration for this acquisition, the
Company issued to Elf Aquitaine 1,325,000 shares of common stock of the Company
valued at a guaranteed amount of $20.00 per share on November 4, 2000, or $26.5
million. The Company effected such issuance of shares in accordance with Rule
506 of Regulation D under the Securities Act of 1933, as amended. Elf Aquitaine
was an "accredited investor" for purposes of such rule.
23
Item 6. Selected Financial Data.
SELECTED FINANCIAL AND OPERATING DATA
Years Ended December 31,
------------------------------------------------------------
1998 1997 (a) 1996 (a) 1995 (a) 1994 (a)
----------- ---------- ---------- --------- ---------
(In thousands, except per share amounts and operating data)
Income Statement Data:
Oil and gas sales.............................. $ 266,661 $ 355,113 $ 258,368 $160,254 $141,357
Gathering revenues............................. 7,741 18,063 20,508 12,380 14,635
Gas marketing revenues......................... 54,108 45,981 31,920 20,912 27,285
Total revenues................................. 328,935 416,590 312,147 195,215 185,751
Operating expenses............................. 180,544 172,676 138,438 95,121 96,549
Exploration costs.............................. 24,056 12,667 10,192 3,834 3,012
Impairment of oil and gas properties........... 70,913 8,785 - - -
Depreciation, depletion and amortization....... 108,975 96,307 66,861 48,336 39,341
Interest....................................... 43,680 36,762 30,109 20,178 12,002
Net income (loss).............................. (87,665) 54,954 33,188 9,449 14,389
Earnings (loss) per share(b)(c):
Basic....................................... (1.69) 1.07 .69 .23 .36
Diluted..................................... (1.69) 1.05 .68 .22 .34
Dividends declared per share(c)................ .09 .07 .055 .045 .035
----------- ---------- ---------- --------- ---------
Balance Sheet Data (end of year):
Total assets................................... $1,014,175 $ 915,394 $ 766,816 $613,397 $377,010
Long-term debt, less current portion........... 672,507 451,096 372,390 315,846 186,548
Stockholders' equity........................... 273,958 337,578 236,406 203,265 137,210
----------- ---------- ---------- --------- ---------
Operating Data:
Production:
Oil (MBbls).................................... 16,434 15,457 11,939 7,608 6,657
Gas (MMcf)..................................... 47,238 42,691 32,366 30,610 28,884
----------- ---------- ---------- --------- ---------
Average Sales Prices:
Oil (per Bbl).................................. $ 10.87 $ 17.02 $ 16.73 $ 15.26 $ 13.53
Gas (per Mcf).................................. 1.86 2.16 1.81 1.46 1.78
----------- ---------- ---------- --------- ---------
Proved Reserves (end of year):
Oil (MBbls).................................... 164,457 187,768 178,296 147,871 70,789
Gas (MMcf)..................................... 806,833 552,163 382,846 310,762 281,638
Total proved reserves (MBOE)................... 298,929 279,795 242,104 199,665 117,729
----------- ---------- ---------- --------- ---------
Present value of estimated future net revenues
before income taxes discounted at 10 percent
(in thousands):
Oil and gas properties.................. $ 703,211 $1,222,560 $1,807,137 $894,249 $446,987
Gathering systems....................... 4,493 5,940 10,364 10,641 9,215
Standardized measure of discounted future
net cash flows (in thousands)............... 648,222 1,016,645 1,392,841 736,546 385,721
----------- ---------- ---------- --------- ---------
Significant acquisitions of producing oil and gas properties during 1997
and 1995 affect the comparability between the Financial and Operating Data for
the years presented above.
(a) Restated for change in accounting method. See Note 1 to the Company's
consolidated financial statements included elsewhere in this Form 10-K.
(b) Amounts have been restated to give effect to the adoption of Statement of
Financial Accounting Standards No. 128, Earnings Per Share, as of December
31, 1997.
(c) Amounts have been adjusted to give effect to the two-for-one common stock
split effected on October 7, 1997.
24
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Change in Accounting Method
Effective January 1, 1998, the Company elected to convert from the full
cost method to the successful efforts method of accounting for its investments
in oil and gas properties. The Company believes that the successful efforts
method of accounting is preferable, as it more accurately presents the results
of the Company's exploration and development activities, minimizes asset write-
offs caused by temporary downward oil and gas price movements and reflects an
impairment in the carrying value of its oil and gas properties only when there
has been a permanent decline in their fair value. Accordingly, the consolidated
balance sheet as of December 31, 1997, and the consolidated statements of income
and cash flows for the years ended December 31, 1997 and 1996, included in this
Form 10-K have been restated to conform with successful efforts accounting. The
effect, net of income taxes, was to reduce December 31, 1997, retained earnings
by $46.0 million. For the statements of income for the years ended December 31,
1997 and 1996, the effect of the accounting change was to decrease net income by
$17.3 million ($.34 per diluted share), and $8.0 million ($.17 per diluted
share), respectively.
Results of Operations
The Company's results of operations have been significantly affected by its
success in acquiring oil and gas properties and its ability to maintain or
increase production through its exploitation and exploration activities.
Fluctuations in oil and gas prices have also significantly affected the
Company's results. The following table reflects the Company's oil and gas
production and its average oil and gas prices for the periods presented:
Years Ended December 31,
---------------------------
1998 1997 1996
-------- -------- --------
Production:
Oil (MBbls) -
U.S. ......... 9,912 9,692 7,694
Argentina..... 6,322 5,630 4,245
Bolivia....... 122 135 -
Ecuador....... 78 - -
Total....... 16,434 15,457 11,939
Gas (MMcf) -
U.S. ......... 42,176 36,623 32,366
Bolivia....... 5,062 6,068 -
Total....... 47,238 42,691 32,366
Total MBOE........ 24,307 22,573 17,333
Average Sales Prices:
Oil (per Bbl) -
U.S........... $ 11.20 $ 17.23 $ 17.19
Argentina..... 10.41 16.67 15.91
Bolivia....... 11.31 16.52 -
Ecuador....... 5.77 - -
Total....... 10.87 17.02 16.73
Gas (per Mcf) -
U.S. ......... $ 1.99 $ 2.33 $ 1.81
Bolivia....... .78 1.10 -
Total....... 1.86 2.16 1.81
25
Average U.S. oil prices received by the Company fluctuate generally with
changes in the West Texas Intermediate ("WTI") posted prices for oil. The
Company's Argentina oil production is sold at WTI spot prices less a specified
differential. The Company experienced a 36 percent decrease in its average oil
price in 1998 compared to 1997. The Company was not a party to any oil hedges
in 1998. During 1997, the impact of Argentina oil hedges reduced the Company's
overall average oil price 24 cents to $17.02 per Bbl and its average Argentina
oil price was reduced 66 cents to $16.67 per Bbl. Approximately 49 percent of
the 1997 Argentina oil production was covered by hedges. Oil hedges reduced the
Company's overall 1996 average oil price $2.00 to $16.73 per Bbl. The Company's
1996 average U.S. oil price was reduced $1.47 to $17.19 per Bbl while its
average Argentina oil price was reduced $2.96 to $15.91 per Bbl.
The Company realized an average oil price for 1998 which was approximately
91 percent of WTI posted prices compared to a realization of 93 percent (before
the impact of oil hedges) of WTI posted prices for the year earlier. However,
due to an increase in the differential between WTI posted prices and the NYMEX
reference price ("NYMEX"), the Company's average realized prices (before hedges)
declined to 75 percent of NYMEX in 1998 compared to 84 percent of NYMEX in 1997
and 85 percent of NYMEX in 1996.
Average U.S. gas prices received by the Company fluctuate generally with
changes in spot market prices, which may vary significantly by region. The
Company's Bolivia average gas price is tied to a long-term contract under which
the base price is adjusted for changes in specified fuel oil indexes. During
1998, these fuel oil indexes decreased in conjunction with the current low oil
price environment. The Company's average gas price for 1998 was 14 percent lower
than 1997's. The Company's average gas price for 1997 was 19 percent higher
than 1996's. Average realized gas prices for 1996 were negatively impacted by
five cents per Mcf as a result of certain gas hedges that were in place for
40,000 Mcf of gas per day for the period January through March 1996.
The Company 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. During 1998, the Company entered
into various natural gas basis swaps for the calender year 1999 covering a total
of 82,000 MMBtu of gas per day plus an additional 3,000 MMBtu per day for the
period of January through October 1999. These natural gas basis swaps were used
to reduce the Company's exposure to increases in the basis differential between
the NYMEX reference price and the Company's industry delivery point indexes
under which the gas is sold.
Relatively modest changes in either oil or gas prices significantly impact
the Company's results of operations and cash flow. However, the impact of
changes in the market prices for oil and gas on the Company's average realized
prices may be reduced from time to time based on the level of the Company's
hedging activities. Based on 1998 oil production, a change in the average oil
price realized by the Company of $1.00 per Bbl would result in a change in net
income and cash flow before income taxes on an annual basis of approximately
$10.2 million and $16.0 million, respectively. A 10 cent per Mcf change in the
average price realized by the Company for gas would result in a change in net
income and cash flow before income taxes on an annual basis of approximately
$2.8 million and $4.6 million, respectively, based on 1998 gas production.
26
Period to Period Comparison
Year Ended December 31, 1998, Compared to Year Ended December 31, 1997
The Company reported a net loss of $87.7 million for the year ended
December 31, 1998, compared to net income of $55.0 million for the same period
in 1997. An increase in the Company's oil and gas production of eight percent
on an equivalent barrel basis was more than offset by a 36 percent decrease in
average oil prices and a 14 percent decrease in average gas prices. The
production increases primarily relate to the exploration activities in the
United States, the exploitation activities in Argentina and the acquisition of
certain oil and gas properties from Burlington Resources Inc. (the "Burlington
Properties") in April 1997. However, a portion of the production increases were
reduced by the impact of severe weather in California during the first quarter
of 1998 and the Gulf of Mexico in the third quarter of 1998 forcing the Company
to temporarily shut in some of its oil and gas properties for portions of 1998
reducing production by approximately 167,000 Bbls of oil and 877,000 Mcf of gas.
Oil and gas sales decreased $88.4 million (25 percent), to $266.7 million
for 1998 from $355.1 million for 1997. A 36 percent decrease in average oil
prices, partially offset by a six percent increase in oil production, accounted
for a decrease of $84.4 million. A 14 percent decrease in average gas prices,
partially offset by an 11 percent increase in gas production, accounted for an
additional decrease of $4.0 million.
Oil and gas gathering net margins decreased $1.6 million (52 percent), to
$1.5 million for 1998 from $3.1 million for 1997, due primarily to the sale by
the Company of its two largest gathering systems in December 1997 and June 1998.
Lease operating expenses, including production taxes, increased $8.4
million (7 percent), to $122.7 million for 1998 from $114.3 million for 1997.
The increase in lease operating expenses is in line with the eight percent
increase in production and is due primarily to operating costs associated with
the Burlington Properties and costs in 1998 related to storm damage repair and
cleanup as a result of the severe weather in California and the Gulf of Mexico.
Lease operating expenses per equivalent barrel produced decreased to $5.05 in
1998 from $5.07 for the same period in 1997.
Exploration costs increased $11.4 million (90 percent), to $24.1 million
for 1998 from $12.7 million for 1997. During 1998, the Company's exploration
costs included $13.9 million for the acquisition of 3-D seismic data primarily
in the U.S. Gulf Coast area and Bolivia, $4.8 million for unsuccessful
exploratory drilling, $3.0 million for lease impairments and $2.4 million in
other geological and geophysical costs. The Company's 1997 exploration costs
consisted primarily of $6.6 million for unsuccessful exploratory drilling, $5.6
million in 3-D seismic acquisition costs, and $0.5 million in lease impairments.
Impairments of oil and gas properties of $70.9 million were recognized in
1998, compared to $8.8 million of impairments in 1997, due primarily to the
decline in oil prices which took place in the last quarter of 1998. The Company
reviews its proved properties for impairment on a field basis and recognizes an
impairment whenever events or circumstances (such as declining oil and gas
prices) indicate that the properties' carrying value may not be recoverable. If
an impairment is indicated based on the Company's estimated future net revenues
for total proved reserves on a field basis, then a provision is recognized to
the extent that the carrying value exceeds the present value of the estimated
future net revenues ("fair value"). In estimating the future net revenues, the
Company assumed future oil and gas prices and costs would escalate annually and
that the current low oil and gas price environment would return to more
historical levels over a period of time. Due to the volatility of oil and gas
prices, it is possible that the Company's assumptions regarding oil and gas
prices may change in the future. If future price expectations were to be
reduced, it is possible that additional significant impairment provisions for
oil and gas properties would be required.
27
General and administrative expenses increased $4.6 million (17 percent), to
$32.0 million for 1998 from $27.4 million for 1997, due primarily to the
addition of personnel as a result of the acquisition of the Burlington
Properties and the Company's increased emphasis on exploration activities, and
additional costs associated with international acquisition and business
development activities and unsuccessful acquisition activities.
Depreciation, depletion and amortization increased $12.7 million (13
percent), to $109.0 million for 1998 from $96.3 million for 1997, due primarily
to the eight percent increase in production on an equivalent barrel basis and
the increase in the Company's DD&A rate. The Company's average DD&A rate per
equivalent barrel produced for 1998 was $4.32 compared to $4.14 for the year
earlier.
Interest expense increased $6.9 million (19 percent), to $43.7 million for
1998 from $36.8 million for 1997, due primarily to a 23 percent increase in the
Company's total average outstanding debt as a result of capital spending in the
Company's exploitation and exploration programs in excess of 1998's cash flow
and the acquisition of the Burlington Properties in April 1997. The increase in
interest expense was partially offset by a decrease in the Company's overall
average interest rate from 8.01% in 1997 to 7.72% in 1998.
Year Ended December 31, 1997, Compared to Year Ended December 31, 1996
Net income was $54.9 million for the year ended December 31, 1997, up 66
percent from $33.2 million in 1996. Increases in the Company's oil and gas
production of 30 percent on an equivalent barrel basis, an increase of 19
percent in natural gas prices, and an increase of two percent in oil prices are
primarily responsible for the increase in net income. The production increases
primarily relate to the acquisition of the Burlington Properties, exploitation
activities in Argentina, exploration activities in the Galveston Bay area, the
acquisitions of producing oil and gas properties from Conoco, Inc. and Exxon
Company, U.S.A. and the acquisition of 100 percent of the common stock of
Vintage Petroleum Boliviana, Inc. ("Vintage Boliviana") (formerly Shamrock
Ventures (Boliviana) Ltd.) (collectively, the "1996 Acquisitions").
Oil and gas sales increased $96.7 million (37 percent), to $355.1 million
for 1997 from $258.4 million for 1996. A 29 percent increase in oil production
and a two percent increase in average oil prices combined to account for $63.3
million of the increase. A 32 percent increase in gas production and a 19
percent increase in average gas prices contributed to an additional $33.4
million increase.
Other income (expense) decreased $3.9 million, to an expense of $2.5
million for 1997 from income of $1.4 million for 1996, due primarily to a $5.5
million charge in 1997 related to an adverse judgement in a lawsuit involving
the handling of proceeds received by the Company from a 1992 gas contract
termination. The charge was partially offset by a $1.6 million gain recognized
on the sale of a gas gathering system.
Lease operating expenses, including production taxes, increased $22.4
million (24 percent), to $114.3 million for 1997 from $91.9 million for 1996.
The increase in lease operating expenses is due primarily to costs associated
with the Burlington Properties, the 1996 Acquisitions, and an increase in
severance taxes due to higher oil and gas sales. Lease operating expenses per
equivalent barrel produced decreased to $5.07 in 1997 from $5.30 for 1996.
Exploration costs increased $2.5 million (24 percent) to $12.7 million for
1997 from $10.2 million for 1996. The Company's 1997 exploration costs included
$6.6 million for unsuccessful exploratory drilling, $5.6 million for the
acquisition of seismic data and $0.5 million in lease impairments. The
Company's 1996 exploration costs included $6.9 million for the acquisition of
seismic data, $3.2 million for unsuccessful exploratory drilling and $0.1
million in lease impairments.
28
Impairments of oil and gas properties of $8.8 million were recognized in
1997, due primarily to the decline in oil prices which took place in the last
quarter of 1997. There was no similar impairment provision required in 1996.
The Company reviews its proved properties for impairment on a field basis and
recognizes an impairment whenever events or circumstances (such as declining oil
and gas prices) indicate that the properties' carrying value may not be
recoverable. If an impairment is indicated based on the Company's estimated
future net revenues for total proved reserves then a provision is recognized to
the extent that the carrying value exceeds the present value of the estimated
future net revenues ("fair value").
General and administrative expenses increased $4.5 million (19 percent), to
$27.4 million for 1997 from $22.9 million for 1996, due primarily to the
acquisition of Vintage Boliviana, the addition of personnel as a result of the
acquisition of the Burlington Properties and additional costs associated with
unsuccessful acquisition activities.
Depreciation, depletion and amortization increased $29.4 million (44
percent), to $96.3 million for 1997 from $66.9 million for 1996, due primarily
to the 30 percent increase in production on an equivalent barrel basis. The
Company's average DD&A rate per equivalent barrel produced for 1997 was $4.14
compared to $3.73 for 1996.
Interest expense increased $6.7 million (22 percent), to $36.8 million for
1997 from $30.1 million for 1996, due primarily to a 29 percent increase in the
Company's total average outstanding debt as a result of the acquisition of the
Burlington Properties in April 1997, and the acquisitions made late in 1996.
The increase was partially offset by a decrease in the Company's overall average
interest rate from 8.36% in 1996 to 8.01% in 1997.
Capital Expenditures
During 1998, the Company's domestic oil and gas capital expenditures
totaled $178.0 million. Exploration activities accounted for $56.4 million of
the domestic capital expenditures with exploitation activities contributing
$50.8 million. The Company also had domestic capital expenditures in 1998 of
$70.8 million for the acquisitions of producing oil and gas properties, the
largest of which was the $42.1 million acquisition from Western Gas Resources,
Inc. in late October. During 1998, the Company's international oil and gas
capital expenditures totaled $108.4 million, including $44.6 million in
Argentina, primarily on exploitation activities, $24.3 million in Bolivia, on
exploitation and exploration activities, and $34.2 million in Ecuador related to
the acquisition of EHE.
The Company committed to perform 17,728 work units related to its
concession rights in the Naranjillos field in Santa Cruz Province, Bolivia
awarded in late 1997. The total work unit commitment was guaranteed by the
Company through an $88.6 million letter of credit; however, the Company
anticipated that it would fulfill this three-year work unit commitment through
approximately $50 to $60 million of various seismic and drilling capital
expenditures. During 1998, the Company spent approximately $7.6 million in the
fulfillment of 1,218 work units through the acquisition of seismic data and the
drilling of one well. The Company has budgeted to spend approximately $24
million (7,500 work units) in 1999 related to the fulfillment of its Naranjillos
field commitment.
In addition, the Company's commitment to perform 1,400 work units related
to an exploration program within the Chaco Block in Bolivia was fulfilled during
1998 through acquisitions of 3-D seismic and the drilling of two wells. Under
the Company's exploration contract on Block 19 in Ecuador, the Company is
required to participate in the drilling of one additional well. The Company
expects to drill the well during 2000 at a cost of approximately $4 million.
29
The Company is also committed to spend approximately $11 million in the
Republic of Yemen over a two and one-half year period which began in July 1998.
The expenditures will include the acquisition and interpretation of 150 square
kilometers of seismic and the drilling of three exploration wells. At the end
of the first two and one-half years, the Company has the option to extend the
work program for a second two and one-half year period with similar work and
capital commitments required. During 1998, approximately $0.6 million of the
$11 million commitment was spent. The Company has budgeted to spend
approximately $5 million in 1999 on the acquisition of 3-D seismic data in
Yemen.
Except for the commitments discussed above, the timing of most of the
Company's capital expenditures is discretionary with no material long-term
capital expenditure commitments. Consequently, the Company has a significant
degree of flexibility to adjust the level of such expenditures as circumstances
warrant. The Company uses internally generated cash flow, coupled with advances
under its revolving credit facility, to fund capital expenditures other than
significant acquisitions. Of the Company's 1998 non-acquisition capital
expenditures of $181 million, approximately 59 percent was spent on exploitation
activities, including development and infill drilling, and approximately 41
percent was spent on exploration activities. The Company's preliminary capital
expenditure budget for 1999 is currently set at $56 million, exclusive of
acquisitions. Because the timing of most of the Company's capital expenditures
is discretionary, should oil and gas prices improve during 1999, its 1999
capital expenditure program may be adjusted upward. The Company does not have a
specific acquisition budget since the timing and size of acquisitions are
difficult to forecast. The Company is actively pursuing additional acquisitions
of oil and gas properties. In addition to internally generated cash flow and
advances under its revolving credit facility, the Company may seek additional
sources of capital to fund any future significant acquisitions (see "--
Liquidity"), however, no assurance can be given that sufficient funds will be
available to fund the Company's desired acquisitions.
The Company's recent capital expenditure history is as follows:
Years Ended December 31,
---------------------------------
(In thousands) 1998 1997 1996
---------- --------- ---------
(Restated) (Restated)
Acquisition of oil and gas reserves............................. $105,023 $139,749 $ 91,282
Drilling........................................................ 114,773 71,069 51,175
Acquisition of undeveloped acreage and seismic.................. 35,024 10,349 14,847
Workovers and recompletions..................................... 29,939 32,856 33,482
Acquisition and construction of gathering systems............... 1,831 1,209 724
Other........................................................... 1,601 4,638 5,945
---------- --------- ---------
Total $288,191 $259,870 $197,455
========== ========= =========
Liquidity
Internally generated cash flow and the borrowing capacity under its
revolving credit facility are the Company's major sources of liquidity. In
addition, the Company may use other sources of capital, including the issuance
of additional debt securities or equity securities, to fund any major
acquisitions it might secure in the future and to maintain its financial
flexibility.
In the past, the Company has accessed the public markets to finance
significant acquisitions and provide liquidity for its future activities. In
conjunction with the purchase of substantial oil and gas assets in 1990, 1992
and 1995, the Company completed three public equity offerings, as well as a
public debt offering in 1995, which provided the Company with aggregate net
proceeds of approximately $272 million. In February 1997, the Company also
completed concurrent public debt and equity offerings. Net proceeds of
approximately $143 million were used to repay a portion of existing indebtedness
under the Company's revolving credit facility.
30
On January 26, 1999, the Company issued $150 million of its 9 3/4% Senior
Subordinated Notes Due 2009 (the "9 3/4% Notes"). The 9 3/4% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after February 1, 2004. In addition, prior to February 1, 2002, the Company may
redeem up to 33 1/3% of the 9 3/4% Notes with the proceeds of certain
underwritten public offerings of the Company's common stock. The 9 3/4% Notes
mature on June 30, 2009, with interest payable semiannually on June 30 and
December 30 of each year. The net proceeds to the Company from the sale of the
9 3/4% Notes (approximately $146 million) were used to repay a portion of the
existing indebtedness under the Company's revolving credit facility.
Under the Amended and Restated Credit Agreement dated October 21, 1998, as
amended (the "Bank Facility"), certain banks have provided to the Company an
unsecured revolving credit facility. The Bank Facility establishes a borrowing
base (currently $482.5 million) determined by the banks' evaluation of the
Company's oil and gas reserves.
Outstanding advances under the Bank Facility bear interest payable
quarterly at a floating rate based on Bank of Montreal's alternate base rate (as
defined) or, at the Company's option, at a fixed rate for up to six months based
on the Eurodollar market rate ("LIBOR"). The Company's interest rate increments
above the alternate base rate and LIBOR vary based on the level of outstanding
senior debt to the borrowing base. As of February 28, 1999, the Company had
elected a fixed rate based on LIBOR for a substantial portion of its outstanding
advances, which resulted in an average interest rate of approximately 6.2
percent per annum. In addition, the Company must pay a commitment fee ranging
from 0.25 to 0.375 percent per annum on the unused portion of the banks'
commitment.
On a semiannual basis, the Company's borrowing base is redetermined by the
banks based upon their review of the Company's oil and gas reserves. If the sum
of outstanding senior debt exceeds the borrowing base, as redetermined, the
Company must repay such excess. Any principal advances outstanding under the
Bank Facility at September 11, 2001, will be payable in eight equal consecutive
quarterly installments commencing December 1, 2001, with final maturity at
September 11, 2003.
At February 28, 1999, the unused portion of the Bank Facility was
approximately $187 million based on the current borrowing base of $482.5
million. The Company anticipates, that as a result of continued low oil and gas
prices, the borrowing base will be significantly reduced at the banks' next
borrowing base redetermination in April 1999. However, the amount of any such
reduction is unknown at this time. The unused portion of the Bank Facility and
the Company's internally generated cash flow provide liquidity which may be used
to finance future capital expenditures, including acquisitions. As additional
acquisitions are made and such properties are added to the borrowing base, the
banks' determination of the borrowing base and their commitments may be
increased.
The Company's internally generated cash flow, results of operations and
financing for its operations are dependent on oil and gas prices. For 1998,
approximately 68 percent of the Company's production was oil. Realized oil
prices for the year decreased by 36 percent as compared to 1997. As a result,
although total production on a BOE basis increased by eight percent, the
Company's earnings and cash flows have been materially reduced compared to 1997.
To the extent low oil prices continue, the Company's earnings and cash flow from
operations will be adversely impacted. The Company believes that its cash flows
and unused availability under the Bank Facility are sufficient to fund its
planned capital expenditures for the foreseeable future. However, continued low
oil and gas prices may cause the Company to not be in compliance with
maintenance covenants under its Bank Facility and may negatively affect its
credit statistics and coverage ratios and thereby affect its liquidity.
Inflation
In recent years inflation has not had a significant impact on the Company's
operations or financial condition.
31
Income Taxes
The Company realized a current benefit for income taxes of approximately
$4.1 million for 1998 and incurred a current provision of $5.2 million for 1997.
The total provision for U.S. income taxes is based on the Federal corporate
statutory income tax rate plus an estimated average rate for state income taxes.
Earnings of the Company's foreign subsidiaries are subject to foreign income
taxes. No U.S. deferred tax liability will be recognized related to the
unremitted earnings of these foreign subsidiaries as it is the Company's
intention, generally, to reinvest such earnings permanently.
As of December 31, 1998, the Company had estimated net operating loss
("NOL") carryforwards of $44.9 million for Argentina income tax reporting
purposes which can be used to offset future taxable income in Argentina. The
carryforward amount includes certain Argentina NOL carryforwards ($17.3 million)
which were acquired and are recorded at cost ($1.0 million), which is less than
the calculated value for the tax effect of these carryforwards ($6.0 million)
under the provisions of Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes ("SFAS 109"). These unrecorded NOL carryforwards
($14.4 million) will reduce the Company's foreign income tax provision for
financial purposes in future years by approximately $5.0 million if their
benefit is realized.
At the time the Company acquired a controlling interest in Cadipsa, S.A.
("Cadipsa") and 100 percent of Vintage Oil Argentina, Inc. ("VOA") in 1995,
Cadipsa and VOA had combined tax NOL carryforwards of approximately $62 million.
As the acquisitions were accounted for as business combinations and Cadipsa and
VOA had suffered cumulative losses in recent years prior to the acquisition, the
Company was required by the provisions of SFAS 109 to place a valuation
allowance on the carryforwards until it could be shown that it reasonably
expected to utilize the carryforwards prior to their expiration. During 1997, a
substantial benefit ($11.4 million) was realized from the utilization of
Argentina NOL carryforwards for tax purposes. As of the end of 1997, Cadipsa
and VOA had shown cumulative profits for the prior three-year period, and based
on estimated cash flows based on industry existing conditions at December 31,
1997, the Company believed it would be able to fully utilize 100 percent of the
remaining tax NOL carryforwards. It therefore reversed the remaining $3.1
million of the valuation allowance against its Argentina deferred tax asset in
1997 relating to the remaining unutilized carryforwards as of December 31, 1997.
As a result of the significant decline in oil prices in 1998, primarily in
the fourth quarter, the Company currently believes that of the $27.6 million of
Argentina NOL carryforwards generated by Cadipsa and VOA, $16.2 million will
expire in 1999 unutilized and has therefore recorded a valuation allowance
against its Argentina deferred tax asset of approximately $5.7 million in 1998
related to these carryforwards.
The Company has a U.S. Federal alternative minimum tax ("AMT") credit
carryforward of approximately $4.8 million which does not expire and is
available to offset U.S. Federal regular income taxes in future years, but only
to the extent that U.S. Federal regular income taxes exceed the AMT in such
years. The Company incurred a tax NOL for U.S. purposes in 1998 and will be
able to carry back the NOL two years and/or forward 20 years to receive a refund
of prior income taxes paid or to offset future income taxes to be paid.
Foreign Operations
For information on the Company's foreign operations, see "Foreign Currency
and Operations Risk" under Item 7A of this Form 10-K.
32
Year 2000 Compliance
Readers are cautioned that the forward-looking statements contained in the
following Year 2000 discussion should be read in conjunction with the Company's
disclosures under the heading "Forward-Looking Statements." The disclosures
also constitute a "Year 2000 Readiness Disclosure" and "Year 2000 Statement"
within the meaning of the Year 2000 Information and Readiness Disclosure Act of
1998. The Year 2000 Information and Readiness Disclosure Act of 1998 does not
insulate the Company from liability under the federal securities laws with
respect to disclosures relating to Year 2000 information.
Statement of Readiness. The Company has undertaken various initiatives to
ensure that its hardware, software and equipment will function properly with
respect to dates before and after January 1, 2000. For this purpose, the phrase
"hardware, software and equipment" includes systems that are commonly thought of
as Information Technology systems ("IT"), as well as those Non-Information
Technology systems ("Non-IT") and equipment which include embedded technology.
IT systems include computer hardware and software and other related systems.
Non-IT systems include certain oil and gas production and field equipment,
gathering systems, office equipment, telephone systems, security systems and
other miscellaneous systems. The Non-IT systems present the greatest compliance
challenge since identification of embedded technology is difficult and because
the Company is, to a great extent, reliant on third parties for Non-IT
compliance.
The Company has formed a Year 2000 ("Y2K") Project team, which is chaired
by its Manager of Information Services. The team includes corporate staff and
representatives from the Company's business units. The phases of
identification, assessment, remediation, and testing make up the Y2K directive.
The following is the Company's targeted Non-IT and IT compliance time line:
Completion Date
-----------------
Non-IT Systems and Equipment:
Identification Phase............ Completed
Compliance...................... August 1999
IT Systems and Equipment:
Identification Phase............ Completed
Compliance...................... August 1999
Included in the Company's Y2K Project are procedures to determine the
readiness of its business partners, such as service companies, technology
providers, transportation and communication providers, pipeline systems,
materials suppliers and oil and gas product purchasers. By use of
questionnaires, 14,000 notices were distributed which will allow the Company to
determine the extent to which these business partners are addressing their Y2K
issues. Each returned document is examined for a response that may be
detrimental to the Company's operations. To date, approximately 5,600 of the
Company's business partners have responded and those business partners who do
not respond and who are considered key businesses in the support of the
Company's operations will be sent a second request, followed by direct
correspondence, to determine their readiness. Any material adverse responses
will be reviewed to determine an alternate business partner selection or the
need for alternative actions to mitigate the impact on the Company.
The Cost to Address Y2K Issues. The Company believes that the cost of the
Y2K Project will not exceed $3.5 million, excluding costs of Company employees
working on the Y2K Project. Costs incurred for the purchase of new software and
hardware are being capitalized and all other costs are being expensed as
incurred. To date, the Company has incurred Y2K Project costs of approximately
$700,000. The expenditures relate primarily to the upgrading and replacement of
existing software and hardware and the use of contract service consultants.
33
Y2K Worst-Case Scenario. The Company's initial results from its
assessment phase of the Y2K Project is that its internal systems have fewer Y2K
compliance problems than initially anticipated. As the Company plans to have
all internal systems within its control compliant and tested before the year
2000, it believes its likely worst-case scenario is the possibility of
operational interruptions due to non-compliance by third parties. This non-
compliance could cause operational problems such as temporary disruptions of
certain production, delays in marketing and transportation of production and
delays of payments for oil and gas sales. This risk should be minimized by the
Company's efforts to communicate and evaluate third party compliance.
The Company is currently developing contingency plans in the event that
problems arise due to third party non-compliance or any failures of the
Company's systems. These plans should be completed by the third quarter of 1999
and will include, but are not limited to, backup and recovery procedures,
installations of new systems, replacement of current services with temporary
manual processes, finding non-technological alternatives or sources of
information, and finding alternative suppliers, service companies and
purchasers.
The Risks of Y2K Issues. The Company presently believes that the Y2K issue
will not pose significant operational problems. However, if all significant Y2K
issues are not properly identified, or assessment, remediation and testing are
not effected timely, the Y2K issues may materially and adversely impact the
Company's results of operations, liquidity and financial condition or materially
and adversely affect its relationships with its business partners.
Additionally, the lack of Y2K compliance by other entities may have a material
and adverse impact on the Company's operations or financial condition.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The Company's operations are exposed to market risks primarily as a result
of changes in commodity prices, interest rates and foreign currency exchange
rates. The Company does not use derivative financial instruments for
speculative or trading purposes.
Commodity Price Risk
The Company produces, purchases and sells crude oil, natural gas,
condensate, natural gas liquids and sulfur. As a result, the Company's
financial results can be significantly impacted as these commodity prices
fluctuate widely in response to changing market forces. 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. During 1998, the Company entered into various natural gas
basis swaps for the calendar year 1999 covering a total of 82,000 MMBtu of gas
per day plus an additional 3,000 MMBtu per day for the period of January through
October 1999 for a total weighted average differential of approximately one
cent below NYMEX. These natural gas basis swaps were used to reduce the
Company's exposure to increases in the basis differential between the NYMEX
reference price and the Company's industry delivery point indexes under which
the gas is sold. During the first three months of 1999, the actual basis
differential for this same volume of gas was approximately seven and one-half
cents above NYMEX.
Interest Rate Risk
The Company's interest rate risk exposure results primarily from short-term
rates, mainly LIBOR based borrowings from its commercial banks. To reduce the
impact of fluctuations in interest rates the Company maintains a portion of its
total debt portfolio in fixed rate debt. At December 31, 1998, the amount of
the Company's fixed rate debt was approximately 37 percent of total debt,
however, the Company issued additional fixed rate debt in January 1999 bringing
the current fixed rate debt level to 59 percent of total debt. In the past, the
Company has not entered into financial instruments such as interest rate swaps
or interest rate lock agreements. However, it may consider these instruments to
manage the impact of changes in interest rates based on management's assessment
of future interest rates, volatility of the yield curve and the Company's
ability to access the capital markets in a timely manner.
34
The following table provides information about the Company's long-term debt
cash flows and weighted average interest rates by expected maturity dates
(before the impact of the January 1999 fixed-rate debt issuance discussed
above):
Fair
Value
There- at
1999 2000 2001 2002 2003 after Total 12/31/98
---- ---- ---- ---- ---- --------- -------- --------
Long-Term Debt:
Fixed rate (in thousands) - - - - - $249,006 $249,006 $ 239,500
Average interest rate - - - - - 8.9% 8.9% -
Variable rate (in thousands) - - $52,938 $211,750 $158,812 - $423,500 $ 423,500
Average interest rate - - (a) (a) (a) - (a) (a)
(a) LIBOR plus an increment, based on the level of outstanding senior debt to
the borrowing base, up to a maximum increment of 1.5 percent. Current
increment above LIBOR is 1 percent.
Foreign Currency and Operations Risk
International investments represent, and are expected to continue to
represent, a significant portion of the Company's total assets. The Company has
international operations in Argentina, Bolivia, Ecuador and Yemen. For 1998,
the Company's operations in Argentina accounted for approximately 20 percent of
the Company's revenues, 80 percent of the Company's operating income (before
impairments of oil and gas properties) and 25 percent of its total assets.
During such period, the Company's operations in Argentina represented its only
foreign operations accounting for more than 10 percent of its revenues,
operating income (before impairments of oil and gas properties) or total assets.
The Company continues to identify and evaluate international opportunities but
currently has no binding agreements or commitments to make any material
international investment. As a result of such significant foreign operations,
the Company's financial results could be affected by factors such as changes in
foreign currency exchange rates, weak economic conditions or changes in the
political climate in these foreign countries.
The Company believes Argentina offers a relatively stable political
environment and does not anticipate any significant change in the near future.
The current democratic form of government has been in place since 1983 and,
since 1989, has pursued a steady process of privatization, deregulation and
economic stabilization and reforms involving the reduction of inflation and
public spending. Argentina's 12-month trailing inflation rate measure by the
Argentine Consumer Price Index declined from 200.7 percent as of June 1991 to a
negative 6.29 percent (-6.29%) as of December 1998.
All of the Company's Argentine revenues are U.S. dollar based, while a
large portion of its costs are denominated in Argentine pesos. The Argentina
Central Bank is obligated by law to sell dollars at a rate of one Argentine peso
to one U.S. dollar and has sought to prevent appreciation of the peso by buying
dollars at rates of not less than 0.998 peso to one U.S. dollar. As a result,
the Company believes that should any devaluation of the Argentine peso occur,
its revenues would be unaffected and its operating costs would not be
significantly increased. At the present time, there are no foreign exchange
controls preventing or restricting the conversion of Argentine pesos into
dollars.
Since the mid-1980's, Bolivia has been undergoing major economic reform,
including the establishment of a free-market economy and the encouragement of
foreign private investment. Economic activities that had been reserved for
government corporations were opened to foreign and domestic private investments.
Barriers to international trade have been reduced and tariffs lowered. A new
investment law and revised codes for mining and the petroleum industry, intended
to attract foreign investment, have been introduced.
On February 1, 1987, a new currency, the Boliviano ("Bs"), replaced the
peso at the rate of one million pesos to one Boliviano. The exchange rate is set
daily by the Government's exchange house, the Bolsin, which is under the
supervision of the Bolivian Central Bank. Foreign exchange transactions are not
subject to any controls. The US$:Bs exchange rate at December 31, 1998, was
US$1:Bs 5.65. The Company believes that any currency risk associated with its
Bolivian operations would not have a material impact on the Company's financial
position or results of operations.
35
Prior to the Company's acquisition of EHE in November 1998, its previous
operations in Ecuador were through a farm-in exploration joint venture with two
other companies in Block 19. The economy of Ecuador has been uneven in recent
years and has recently reached a crisis level, due in large part to decreases in
oil prices and damage from El Nino floods. Since 1992, the Government has
generally sought to reduce its participation in the economy and has implemented
certain macroeconomic reforms which were designed to reduce inflation. The
Company believes the current Government has a favorable attitude toward foreign
investment and has strong international relationships with the U.S.
Due to the current economic crisis, the sucre (Ecuador's monetary unit) has
lost approximately 45 percent of its value so far this year and inflation has
reached nearly 50 percent. President Jamil Mahaud announced March 11, 1999, a
comprehensive economic plan that calls for an increase in the Value Added Tax
from 10 percent to 15 percent and the freezing of Ecuadorian bank accounts for
one year. Furthermore, the Ecuadorian Government is likely to implement a
convertibility plan similar to that adopted by Argentina in 1991, whereby the
sucre will be tied to the U.S. dollar. Earlier this year the income tax was
replaced by a one percent tax on all financial transactions. The purpose of the
reform is to reduce tax evasion and increase tax collection by the Government,
without increasing the tax burden on taxpayers. Although the Company believes
any currency risk associated with its operations in Ecuador would not have a
material impact on its financial position or results of operations, it has
policies in place that will reduce its exposure to currency risk in Ecuador.
Item 8. Financial Statements and Supplementary Data.
The Consolidated Financial Statements and notes thereto, the report of
independent public accountants and the supplementary financial and operating
information are included elsewhere in this Form 10-K.
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 1999 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."
36
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 in the accompanying Index to Financial
Statements are filed as a part of this Form 10-K.
(2) Financial Statements 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 The Chase Manhattan
Bank (formerly 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 of 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).
4.4 Indenture dated as of January 26, 1999, between The Chase Manhattan
Bank, as Trustee, and the Company.
10.1* Employment and Noncompetition Agreement dated January 7, 1987,
between the Company and Charles C. Stephenson, Jr. (Filed as Exhibit
10.19 to the S-1 Registration Statement).
10.2* Employment and Noncompetition Agreement dated January 7, 1987,
between the Company and Jo Bob Hille (Filed as Exhibit 10.20 to the
S-1 Registration Statement).
37
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* Amendment No. 4 to Vintage Petroleum, Inc. 1990 Stock Plan dated
March 11, 1998 (Filed as Exhibit A to the Company's Proxy Statement
for annual meeting of stockholders dated March 31, 1998).
10.9* Vintage Petroleum, Inc. 401(k) Plan (Filed as Exhibit 4(c) to the
Company's Registration Statement on Form S-8, Registration No.
33-55706).
10.10* Vintage Petroleum, Inc. Non-Management Director Stock Option Plan
(Filed as Exhibit 10.18 to the Company's report on Form 10-K for the
year ended December 31, 1992, filed March 31, 1993 (the "1992 Form
10-K")).
10.11* Form of Incentive Stock Option Agreement under the Vintage
Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the
Company's report on Form 10-K for the year ended December 31, 1990,
filed April 1, 1991).
10.12* Form of Non-Qualified Stock Option Agreement under the Vintage
Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the 1992
Form 10-K).
10.13 Amended and Restated Credit Agreement dated as of October 21, 1998,
among the Company, as borrower, and certain commercial lending
institutions, as lenders, Bank of Montreal, as administrative agent,
Nations Bank, N.A., as syndication agent, and Societe Generale
Southwest Agency, as documentation agent (Filed as Exhibit 10 to the
Company's Report on Form 10-Q for the quarter ended September 30,
1998, filed on November 13, 1998).
10.14 First Amendment to the Amended and Restated Credit Agreement dated
as of December 10, 1998, among the Company, as borrower, and certain
commercial lending institutions, as lenders, Bank of Montreal, as
administrative agent, Nations Bank, N.A., as syndication agent, and
Societe Generale Southwest Agency, as documentation agent.
21. Subsidiaries of the Company.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Netherland, Sewell & Associates, Inc.
23.3 Consent of DeGolyer and MacNaughton.
38
27. Financial Data Schedule.
____________________
* Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the fourth quarter of the fiscal
year ended December 31, 1998.
39
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 12, 1999 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 of the Board March 12, 1999
- ----------------------------
C. C. Stephenson, Jr.
/s/ Jo Bob Hille Director and Vice Chairman of the Board March 12, 1999
- ----------------------------
Jo Bob Hille
/s/ S. Craig George Director, President and March 12, 1999
- ---------------------------- Chief Executive Officer
S. Craig George (Principal Executive Officer)
/s/ William C. Barnes Director, Executive Vice President, March 12, 1999
- ----------------------------- Chief Financial Officer and
William C. Barnes Treasurer (Principal Financial Officer)
/s/ Bryan H. Lawrence Director March 12, 1999
- ----------------------------
Bryan H. Lawrence
/s/ John T. McNabb, II Director March 12, 1999
- ----------------------------
John T. McNabb, II
/s/ Michael F. Meimerstorf Vice President and Controller March 12, 1999
- ---------------------------- (Principal Accounting Officer)
Michael F. Meimerstorf
40
INDEX TO FINANCIAL STATEMENTS
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
Page
----
AUDITED FINANCIAL STATEMENTS OF VINTAGE PETROLEUM, INC. AND SUBSIDIARIES:
Report of Independent Public Accountants......................................................... 42
Consolidated Balance Sheets as of December 31, 1998 and 1997..................................... 43
Consolidated Statements of Income for the years ended December 31, 1998, 1997 and 1996........... 44
Consolidated Statements of Changes in Stockholders' Equity for the years ended
December 31, 1998, 1997 and 1996............................................................. 45
Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996....... 46
Notes to Consolidated Financial Statements for the years ended December 31, 1998, 1997 and 1996.. 47
41
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of Vintage Petroleum, Inc.:
We have audited the accompanying consolidated balance sheets of Vintage
Petroleum, Inc. (a Delaware corporation) and subsidiaries as of December 31,
1998 and 1997, and the related consolidated statements of income (loss), changes
in stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Vintage Petroleum, Inc. and
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the
Company has given retroactive effect to the change in accounting for oil and gas
properties from the full cost method to the successful efforts method.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 24, 1999
42
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except shares
and per share amounts)
ASSETS
December 31,
------------------------
1998 1997
------------ ----------
(Restated)
CURRENT ASSETS:
Cash and cash equivalents................................... $ 5,245 $ 5,797
Accounts receivable -
Oil and gas sales......................................... 54,680 60,878
Joint operations.......................................... 5,905 6,358
Deferred income taxes....................................... - 4,206
Prepaids and other current assets........................... 18,312 12,443
------------ ----------
Total current assets...................................... 84,142 89,682
------------ ----------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method........... 1,368,914 1,158,749
Oil and gas gathering systems............................... 14,774 12,943
Other....................................................... 16,276 8,420
------------ ----------
1,399,964 1,180,112
Less accumulated depreciation, depletion and amortization... 501,722 373,225
------------ ----------
898,242 806,887
------------ ----------
OTHER ASSETS, net.............................................. 31,791 18,825
------------ ----------
$1,014,175 $ 915,394
============ ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Revenue payable............................................. $ 17,382 $ 27,085
Accounts payable - trade.................................... 24,812 21,088
Other payables and accrued liabilities...................... 24,731 31,504
------------ ----------
Total current liabilities................................. 66,925 79,677
------------ ----------
LONG-TERM DEBT................................................. 672,507 451,096
------------ ----------
DEFERRED INCOME TAXES.......................................... - 43,135
------------ ----------
OTHER LONG-TERM LIABILITIES.................................... 785 3,908
------------ ----------
COMMITMENTS AND CONTINGENCIES (Note 4)
STOCKHOLDERS' EQUITY, per accompanying statements:
Preferred stock, $.01 par, 5,000,000 shares authorized,
zero shares issued and outstanding...................... - -
Common stock, $.005 par, 80,000,000 shares authorized,
53,107,066 and 51,558,886 shares issued and outstanding. 266 258
Capital in excess of par value.............................. 230,736 202,008
Retained earnings........................................... 42,956 135,312
------------ ----------
273,958 337,578
------------ ----------
$1,014,175 $ 915,394
============ ==========
The accompanying notes are an integral part of these statements.
43
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(In thousands, except per share amounts)
For the Years Ended December 31,
-----------------------------------
1998 1997 1996
---------- ----------- ----------
(Restated) (Restated)
REVENUES:
Oil and gas sales........................................... $ 266,661 $355,113 $258,368
Oil and gas gathering....................................... 7,741 18,063 20,508
Gas marketing............................................... 54,108 45,981 31,920
Other income (expense)...................................... 425 (2,567) 1,351
---------- ---------- ---------
328,935 416,590 312,147
---------- ---------- ---------
COSTS AND EXPENSES:
Lease operating, including production taxes................. 122,726 114,346 91,916
Exploration costs........................................... 24,056 12,667 10,192
Impairment of oil and gas properties........................ 70,913 8,785 -
Oil and gas gathering....................................... 6,258 14,932 16,985
Gas marketing............................................... 51,560 43,398 29,537
General and administrative.................................. 31,996 27,361 22,902
Depreciation, depletion and amortization.................... 108,975 96,307 66,861
Interest.................................................... 43,680 36,762 30,109
---------- ---------- ---------
460,164 354,558 268,502
---------- ---------- ---------
Income (loss) before income taxes and minority interest... (131,229) 62,032 43,645
---------- ---------- ---------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current..................................................... (4,068) 5,235 2,610
Deferred.................................................... (39,496) 1,640 7,365
---------- ---------- ---------
(43,564) 6,875 9,975
---------- ---------- ---------
MINORITY INTEREST IN INCOME
OF SUBSIDIARY............................................... - (203) (482)
---------- ---------- ---------
NET INCOME (LOSS).................................................... $ (87,665) $ 54,954 $ 33,188
========== =========== =========
EARNINGS (LOSS) PER SHARE:
Basic....................................................... $(1.69) $1.07 $.69
========== =========== =========
Diluted..................................................... $(1.69) $1.05 $.68
========== =========== =========
Weighted Average Common Shares Outstanding:
Basic....................................................... 51,900 51,178 48,090
========== =========== =========
Diluted..................................................... 51,900 52,026 48,654
========== =========== =========
The accompanying notes are an integral part of these statements.
44
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(In thousands, except per share amounts)
Capital
Common Stock In Excess
---------------- of Par Retained
Shares Amount Value Earnings Total
-------- -------- --------- ---------- ----------
BALANCE AT DECEMBER 31, 1995 (Restated)............. 47,322 $237 $149,606 $ 53,422 $203,265
Net income................................ - - - 33,188 33,188
Exercise of warrants...................... 612 3 1,529 - 1,532
Exercise of stock options and
resulting tax effects................. 204 1 1,065 - 1,066
Cash dividends declared ($.055 per share). - - - (2,645) (2,645)
-------- ------- --------- -------- --------
BALANCE AT DECEMBER 31, 1996 (Restated)............. 48,138 241 152,200 83,965 236,406
Net income................................ - - - 54,954 54,954
Issuance of common stock.................. 3,000 15 46,978 - 46,993
Exercise of stock options and
resulting tax effects................. 421 2 2,830 - 2,832
Cash dividends declared ($.07 per share).. - - - (3,607) (3,607)
-------- ------- --------- -------- --------
BALANCE AT DECEMBER 31, 1997 (Restated)............. 51,559 258 202,008 135,312 337,578
Net loss.................................. - - - (87,665) (87,665)
Issuance of common stock.................. 1,325 7 26,493 - 26,500
Exercise of stock options and
resulting tax effects................. 223 1 2,235 - 2,236
Cash dividends declared ($.09 per share).. - - - (4,691) (4,691)
-------- ------- --------- -------- --------
BALANCE AT DECEMBER 31, 1998........................ 53,107 $266 $230,736 $ 42,956 $273,958
======== ======= ========= ======== ========
The accompanying notes are an integral part of these statements.
45
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
-----------------------------------
1998 1997 1996
----------- ----------- ---------
(Restated) (Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss).......................................... $ (87,665) $ 54,954 $ 33,188
Adjustments to reconcile net income (loss) to cash
provided by operating activities -
Depreciation, depletion and amortization............ 108,975 96,307 66,861
Impairment of oil and gas properties................ 70,913 8,785 -
Exploration costs................................... 24,056 12,667 10,192
Provision (benefit) for deferred income taxes....... (39,496) 1,640 7,365
Minority interest in income of subsidiary........... - 203 482
----------- ---------- ---------
76,783 174,556 118,088
Decrease (increase) in receivables......................... 9,353 5,428 (24,614)
U.S. income tax refund receivable.......................... (5,323) - -
Increase (decrease) in payables and accrued liabilities.... (10,570) 7,187 14,619
Other...................................................... (3,993) (569) 2,493
----------- ---------- ---------
Cash provided by operating activities.................. 66,250 186,602 110,586
----------- ---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties............................... (252,254) (257,275) (156,133)
Gathering systems and other.......................... (9,960) (2,275) (1,430)
Proceeds from sales of oil and gas properties.............. 588 360 1,291
Purchase of companies, net of cash acquired................ (10,651) (38,788) (9,160)
Other...................................................... (3,042) (2,670) (3,233)
----------- ---------- ---------
Cash used by investing activities...................... (275,319) (300,648) (168,665)
----------- ---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock....................................... 884 47,910 2,528
Sale of 8 5/8% Senior Subordinated Notes Due 2009.......... - 96,270 -
Advances on revolving credit facility and other borrowings. 232,736 192,521 149,014
Payments on revolving credit facility and other borrowings. (20,711) (216,335) (90,720)
Dividends paid............................................. (4,392) (3,297) (2,514)
----------- ---------- ---------
Cash provided by financing activities.................. 208,517 117,069 58,308
----------- ---------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............... (552) 3,023 229
CASH AND CASH EQUIVALENTS, beginning of year....................... 5,797 2,774 2,545
----------- ---------- ---------
CASH AND CASH EQUIVALENTS, end of year............................. $ 5,245 $ 5,797 $ 2,774
=========== ========== =========
The accompanying notes are an integral part of these statements.
46
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 1998, 1997 and 1996
1. Business and Significant Accounting Policies
Consolidation
Vintage Petroleum, Inc. is an independent energy company with operations
primarily in the exploration and production, gas marketing and gathering
segments of the oil and gas industry. Approximately 96 percent of the Company's
operations are within the exploration and production segment based on 1998
operating income before impairments of oil and gas properties. Its core areas
of exploration and production operations include the West Coast, Gulf Coast,
East Texas and Mid-Continent areas of the United States, the San Jorge Basin of
Argentina, the Chaco Basin in Bolivia, and Ecuador beginning in 1998.
The consolidated financial statements include the accounts of Vintage
Petroleum, Inc. and its wholly- and majority-owned subsidiaries (collectively,
the "Company"). All significant intercompany accounts and transactions have
been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles ("GAAP") requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities, if any, at the date of the
financial statements, and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Change in Accounting Method
Effective January 1, 1998, the Company elected to change its accounting
method for oil and gas properties from the full cost method to the successful
efforts method. Management believes that the successful efforts method of
accounting is preferable and that the accounting change will more accurately
present the results of the Company's exploration and development activities,
minimize asset write-offs caused by temporary declines in oil and gas prices and
reflect an impairment in the carrying value of the Company's oil and gas
properties only when there has been a permanent decline in their fair value.
As a result of this change in accounting, all prior year financial
statements have been retroactively restated to give effect to this change in
accounting method. The effect, net of income taxes, was a reduction of retained
earnings as of December 31, 1997, of $46.0 million, primarily resulting from a
reduction of net property, plant and equipment of $74.7 million and a reduction
of deferred income tax liability of $28.7 million. The change in accounting
method decreased net income by $17.3 million ($0.34 per diluted share) and $8.0
million ($0.17 per diluted share) for 1997 and 1996, respectively.
Oil and Gas Properties
Under the successful efforts method of accounting, the Company capitalizes
all costs related to property acquisitions and successful exploratory wells, all
development costs and the costs of support equipment and facilities. All costs
related to unsuccessful exploratory wells are expensed when such wells are
determined to be non-productive; other exploration costs, including geological
and geophysical costs, are expensed as incurred. The Company recognizes gain or
loss on the sale of properties on a field basis.
47
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Unproved leasehold costs are capitalized and are reviewed periodically for
impairment. Costs related to impaired prospects are charged to expense. If oil
and gas prices decline further in the future, some of these unproved prospects
may not be economic to develop which could lead to increased impairment expense.
Costs of development dry holes and proved leaseholds are amortized on the
unit-of-production method based on proved reserves on a field basis. The
depreciation of capitalized production equipment and drilling costs is based on
the unit-of-production method using proved developed reserves on a field basis.
Estimated abandonment costs, net of salvage value, are included in the
depreciation and depletion calculation.
The Company reviews its proved oil and gas properties for impairment on a
field basis. For each field, an impairment provision is recorded whenever
events or circumstances indicate that the carrying value of those properties may
not be recoverable. The impairment provision is based on the excess of carrying
value over fair value. Fair value is defined as the present value of the
estimated future net revenues from production of total proved oil and gas
reserves over the economic life of the reserves, based on the Company's
expectations of future oil and gas prices and costs. In estimating the future
net revenues at December 31, 1998, the Company assumed oil and gas prices and
costs would escalate annually and that the current low oil and gas price
environment would return to more historical levels over a period of time. Due
to the volatility of oil and gas prices, it is possible that the Company's
assumptions regarding oil and gas prices may change in the future and may result
in future impairment provisions. The Company recorded impairment provisions
related to its proved oil and gas properties of $70.9 million and $8.8 million
in 1998 and 1997, respectively. No impairment provision was required for 1996.
Revenue Recognition
Natural gas revenues are recorded using the sales method. Under this
method, the Company recognizes revenues based on actual volumes of gas sold to
purchasers. The Company and other joint interest owners may sell more or less
than their entitlement share of the natural gas volumes produced. A liability
is recorded and revenue is deferred if the Company's excess sales of natural gas
volumes exceed its estimated remaining recoverable reserves.
Hedging
The Company periodically uses hedges (swap agreements) to reduce the impact
of oil and natural gas price fluctuations. Gains or losses on swap agreements
are recognized as an adjustment to sales revenue when the related transactions
being hedged are finalized. Gains or losses from swap agreements that do not
qualify for accounting treatment as hedges are recognized currently as other
income or expense. The cash flows from such agreements are included in operating
activities in the consolidated statements of cash flows.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities ("SFAS No. 133"). SFAS No. 133 establishes accounting
and reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
No. 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement. Companies
must formally document, designate, and assess the effectiveness of transactions
that receive hedge accounting.
48
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999;
however, beginning June 16, 1998, companies may implement the statement as of
the beginning of any fiscal quarter. SFAS No. 133 cannot be applied
retroactively and must be applied to (a) derivative instruments and (b) certain
derivative instruments embedded in hybrid contracts that were issued, acquired,
or substantively modified after December 31, 1997 (and, at the company's
election, before January 1, 1998). The Company has not yet quantified the
impact of adopting SFAS No. 133 on its financial statements and has not
determined the timing of or method of the adoption of SFAS No. 133.
Depreciation
Depreciation of property, plant and equipment (other than oil and gas
properties) is provided using both straight-line and accelerated methods based
on estimated useful lives ranging from three to seven years.
Income Taxes
Deferred income taxes are provided on transactions which are recognized in
different periods for financial and tax reporting purposes. Such temporary
differences arise primarily from the deduction of certain oil and gas
exploration and development costs which are capitalized for financial reporting
purposes and differences in the methods of depreciation.
Statements of Cash Flows
Cash equivalents consist of highly liquid money-market mutual funds and
bank deposits with initial maturities of three months or less.
During the years ended December 31, 1998, 1997 and 1996, the Company made
cash payments for interest totaling $42.4 million, $33.2 million and $29.6
million, respectively, and cash payments for U.S. income taxes of $1.5 million,
$5.3 million and $1.3 million, respectively. Cash payments of $1.3 million and
$0.1 million were made during 1998 and 1996, respectively, for foreign tax
withholdings. No cash payments were made during 1997 for foreign income taxes.
In November 1996, the Company agreed to acquire 100 percent of the
outstanding common stock of Shamrock Ventures (Boliviana) Ltd. (subsequently
renamed Vintage Petroleum Boliviana Ltd.). Acquisition costs of $35.1 million
were unpaid at December 31, 1996. These acquisition costs were paid in 1997 and
are reflected in the Company's 1997 Consolidated Statement of Cash Flows.
In November 1998, the Company purchased 100 percent of the outstanding
common stock of Elf Hydrocarbures Equateur, S.A. ("EHE"), a French subsidiary of
Elf Aquitaine. Total consideration included cash and common stock of the
Company. The value of the non-cash consideration was $26.5 million and is not
reflected in the Company's 1998 Statement of Cash Flows.
49
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Earnings Per Share
In February 1997, the Financial Accounting Standards Board issued Statement
No. 128, Earnings Per Share ("SFAS No. 128"), establishing new standards for
computing and presenting earnings per share. The provisions of SFAS No. 128 are
effective for earnings per share calculations for periods ending after December
15, 1997. The Company has adopted SFAS No. 128 effective December 31, 1997, and
all earnings per share amounts disclosed herein have been calculated under the
provisions of SFAS No. 128. Basic earnings (loss) per common share were
computed by dividing net income (loss) by the weighted average number of shares
outstanding during the period. Diluted earnings per common share for 1997 and
1996 were computed assuming the exercise of all dilutive options, as determined
by applying the treasury stock method. For 1998, the computation of diluted
loss per share was antidilutive; therefore, the amounts reported for basic and
diluted loss per share were the same.
General and Administrative Expense
The Company receives fees for operation of jointly-owned oil and gas
properties and records such reimbursements as reductions of general and
administrative expense. Such fees totaled approximately $2.7 million, $2.6
million and $2.2 million in 1998, 1997 and 1996, respectively.
Revenue Payable
Amounts payable to royalty and working interest owners resulting from sales
of oil and gas from jointly-owned properties and from purchases of oil and gas
by the Company's marketing and gathering segments are classified as revenue
payable in the accompanying financial statements.
Accounts Receivable
The Company's oil and gas, gas marketing and gathering sales are made to a
variety of purchasers, including intrastate and interstate pipelines or their
marketing affiliates, independent marketing companies and major oil companies.
The Company's joint operations accounts receivable are from a large number of
major and independent oil companies, partnerships, individuals and others who
own interests in the properties operated by the Company.
Comprehensive Income
In June 1997, the Financial Accounting Standards Board issued Statement No.
130, Reporting Comprehensive Income ("SFAS No. 130"), establishing standards for
reporting and display of comprehensive income and its components in financial
statements. SFAS No. 130 defines comprehensive income as the total of net
income and all other non-owner changes in equity. SFAS No. 130 is effective for
fiscal years beginning after December 15, 1997. The Company had no non-owner
changes in equity other than net income and losses during the years ended
December 31, 1998, 1997 and 1996.
50
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2. Long-Term Debt
Long-term debt at December 31, 1998 and 1997, consisted of the following:
(In thousands) 1998 1997
----------- ----------
Revolving credit facility........................... $423,500 $202,200
Senior subordinated notes:
9% Notes due 2005, less unamortized discount...... 149,714 149,674
8 5/8% Notes due 2009, less unamortized discount.. 99,292 99,222
----------- ---------
$672,506 $451,096
=========== =========
The Company has no long-term debt maturities prior to December 1, 2001.
Aggregate maturities of long-term debt for each of the years ending December 31,
2001, through December 31, 2003, are $52.9 million, $211.8 million and $158.8
million, with $249.0 million thereafter. The Company had $5.3 million and $4.9
million of accrued interest payable related to its long-term debt at December
31, 1998 and 1997, respectively, included in other payables and accrued
liabilities.
Revolving Credit Facility
The Company has available an unsecured revolving credit facility under the
Amended and Restated Credit Agreement dated October 21, 1998, as amended (the
"Bank Facility"), between the Company and certain banks. The Bank Facility
establishes a borrowing base (currently $482.5 million including the impact of
the 9 3/4% Notes discussed below) based on the banks' evaluation of the
Company's oil and gas reserves.
Outstanding advances under the Bank Facility bear interest payable
quarterly at a floating rate based on Bank of Montreal's alternate base rate (as
defined) or, at the Company's option, at a fixed rate for up to six months based
on the eurodollar market rate ("LIBOR"). The Company's interest rate increments
above the alternate base rate and LIBOR vary based on the level of outstanding
senior debt to the borrowing base. In addition, the Company must pay a
commitment fee ranging from 0.25 to 0.375 percent per annum on the unused
portion of the banks' commitment. Total outstanding advances at December 31,
1998, were $423.5 million at an average interest rate of approximately 6.6
percent.
On a semiannual basis, the Company's borrowing base is redetermined by the
banks based upon their review of the Company's oil and gas reserves. The
Company's borrowing base was last redetermined in October 1998. Oil and gas
prices have dropped substantially since the last redetermination and as a
result, the Company anticipates that at the next borrowing base redetermination
in April 1999, its borrowing base will be reduced. However, the amount of any
such reduction is unknown at this time. If the sum of outstanding senior debt
exceeds the borrowing base, as redetermined, the Company must repay such excess.
Any principal advances outstanding at September 11, 2001, will be payable in
eight equal consecutive quarterly installments commencing December 1, 2001, with
maturity at September 11, 2003.
The terms of the Bank Facility impose certain restrictions on the Company
regarding the pledging of assets and limitations on additional indebtedness. In
addition, the Bank Facility requires the maintenance of a minimum current ratio
(as defined) and tangible net worth (as defined) of not less than $250 million
plus 75 percent of the net proceeds of any future equity offerings less any
impairment writedowns required by GAAP or by the Securities and Exchange
Commission.
51
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Senior Subordinated Notes
On December 20, 1995, the Company issued $150 million of its 9% Senior
Subordinated Notes Due 2005 (the "9% Notes"). The 9% Notes are redeemable at
the option of the Company, in whole or in part, at any time on or after December
15, 2000. The 9% Notes mature on December 15, 2005, with interest payable
semiannually on June 15 and December 15 of each year.
On February 5, 1997, the Company issued $100 million of its 8 5/8% Senior
Subordinated Notes Due 2009 (the "8 5/8% Notes"). The 8 5/8% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after February 1, 2002. The 8 5/8% Notes mature on February 1, 2009, with
interest payable semiannually on February 1 and August 1 of each year.
On January 26, 1999, the Company issued $150 million of its 9 3/4% Senior
Subordinated Notes Due 2009 (the "9 3/4% Notes"). The 9 3/4% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after February 1, 2004. In addition, prior to February 1, 2002, the Company may
redeem up to 33 1/3% of the 9 3/4% Notes with the proceeds of certain
underwritten public offerings of the Company's common stock. The 9 3/4% Notes
mature on June 30, 2009, with interest payable semiannually on June 30 and
December 30 of each year. The net proceeds to the Company from the sale of the
9 3/4% Notes (approximately $146 million) were used to repay a portion of the
existing indebtedness under the Company's Bank Facility.
The 9% Notes, 8 5/8% Notes, and 9 3/4% Notes (collectively, the "Notes")
are unsecured senior subordinated obligations of the Company, rank subordinate
in right of payment to all senior indebtedness (as defined) and rank pari passu
with each other. Upon a change in control (as defined) of the Company, holders
of the Notes may require the Company to repurchase all or a portion of the Notes
at a purchase price equal to 101 percent of the principal amount thereof, plus
accrued and unpaid interest. The indentures for the Notes contain limitations
on, among other things, additional indebtedness and liens, the payment of
dividends and other distributions, certain investments and transfers or sales of
assets.
3. Capital Stock
On May 13, 1997, the Company's stockholders approved an increase in the
number of authorized shares of common stock, $.005 par value per share, from 40
million to 80 million.
On September 12, 1997, the Company's Board of Directors approved a two-for-
one stock split of its common stock effective October 7, 1997, to stockholders
of record on September 26, 1997. All references to the number of shares and per
share amounts in the financial statements and notes thereto have been restated
to reflect the stock split.
Public Offerings and Other Issuances
On February 5, 1997, the Company completed a public offering of 3,000,000
shares of common stock, all of which were sold by the Company. Net proceeds to
the Company of approximately $47 million were used to repay a portion of
existing indebtedness under the Company's revolving credit facility.
52
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
On November 4, 1998, the Company issued 1,325,000 shares of common stock to
Elf Aquitaine as partial consideration for the acquisition of its French
subsidiary, Elf Hydrocarbures Equateur, S.A., which owns producing oil
properties and undeveloped acreage in Ecuador. The 1,325,000 shares of common
stock of the Company is valued at a guaranteed amount of $20 per share, or $26.5
million. If the Company's prevailing share price is not equal to at least $20
per share after two years from the date of closing, then the Company will be
required to deliver additional consideration under the price guarantee provision
of the agreement. Such additional consideration, if any, is payable, at the
Company's option, in cash or additional shares of the Company's common stock.
Stock Plans
The Company has three fixed plans which reserve shares of common stock for
issuance to key employees and non-management directors. The Company accounts
for these plans under Accounting Principles Board Opinion No. 25, Accounting for
Stock Issued to Employees ("APB No. 25") and has adopted the disclosure-only
provisions of Statement of Financial Accounting Standards No. 123, Accounting
for Stock-Based Compensation ("SFAS No. 123"). Accordingly, no compensation
cost has been recognized. Had compensation cost for these plans been determined
consistent with the provisions of SFAS No. 123, the Company's net income (loss)
and earnings (loss) per share would have been reduced (increased) to the
following pro forma amounts:
(In thousands, except per share amounts) 1998 1997 1996
--------- ---------- ----------
(Restated) (Restated)
Net income (loss) - as reported........... $(87,665) $54,954 $33,188
Net income (loss) - pro forma............. (89,759) 53,501 32,599
Earnings (loss) per share - as reported:
Basic.............................. (1.69) 1.07 .69
Diluted............................ (1.69) 1.05 .68
Earnings (loss) per share - pro forma:
Basic.............................. (1.73) 1.05 .68
Diluted............................ (1.73) 1.03 .67
The pro forma effect on net income (loss) for 1998, 1997 and 1996 may not
be representative of the pro forma effect on net income in future years because
SFAS No. 123 has not been applied to options granted prior to January 1, 1995.
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option-pricing model. The weighted average assumptions used
for options granted in 1998 include a dividend yield of 0.6 percent, expected
volatility of approximately 27.1 percent, a risk-free interest rate of
approximately 5.7 percent, and expected lives of 4.2 years. The weighted
average assumptions used for options granted in 1997 include a dividend yield of
0.4 percent, expected volatility of approximately 28.9 percent, a risk-free
interest rate of approximately 6.3 percent, and expected lives of 4.2 years.
The weighted average assumptions used for options granted in 1996 include a
dividend yield of 0.4 percent, expected volatility of approximately 29.5
percent, a risk-free interest rate of approximately 6.2 percent, and expected
lives of 4.2 years.
Under the 1983 Stock Option Plan, as amended (the "1983 Plan"), incentive
stock options were granted to key employees of the Company. Generally, options
granted under the 1983 Plan were exercisable for a two to seven year period
beginning three years from the date granted. As of December 31, 1998, all
available options have been granted and exercised under the 1983 Plan.
53
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Under the 1990 Stock Plan, as amended (the "1990 Plan"), a total of up to
6,000,000 shares of common stock are available for issuance to key employees of
the Company. The 1990 Plan permits the granting of any or all of the following
types of awards: (a) stock options, (b) stock appreciation rights, and (c)
restricted stock. As of December 31, 1998, awards for a total of 1,483,000
shares of common stock remain available for grant under the 1990 Plan.
The 1990 Plan is administered by the Board of Directors of the Company (the
"Board"). Subject to the terms of the 1990 Plan, the Board has the authority to
determine plan participants, the types and amounts of awards to be granted and
the terms, conditions and provisions of awards. Options granted pursuant to the
1990 Plan may, at the discretion of the Board, be either incentive stock options
or non-qualified stock options. The exercise price of incentive stock options
may not be less than the fair market value of the common stock on the date of
grant and the term of the option may not exceed 10 years. In the case of non-
qualified stock options, the exercise price may not be less than 85 percent of
the fair market value of the common stock on the date of grant. Any stock
appreciation rights granted under the 1990 Plan will give the holder the right
to receive cash in an amount equal to the difference between the fair market
value of the share of common stock on the date of exercise and the exercise
price. Restricted stock under the 1990 Plan will generally consist of shares
which may not be disposed of by participants until certain restrictions
established by the Board lapse.
Under the Non-Management Director Stock Option Plan (the "Director Plan"),
60,000 shares of common stock are available for issuance to the outside
directors of the Company. Each outside director receives an initial option to
purchase 5,000 shares of common stock during the director's first year of
service to the Company. Annually thereafter, options to purchase 1,000 shares
of common stock are to be granted to each outside director. Options granted
pursuant to the Director Plan are non-qualified stock options with terms not to
exceed 10 years and the option exercise price must equal the fair market value
of the common stock on the date of grant. As of December 31, 1998, options for
a total of 22,000 shares of common stock remain available for grant under the
Director Plan.
The following is an analysis of all option activity under the 1983 Plan,
the 1990 Plan and the Director Plan for 1998, 1997 and 1996:
1998 1997 1996
------------------------ ---------------------------- ----------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
----------- ----------- --------- ----------- --------- -----------
Beginning stock options
outstanding........................... 3,060,322 $10.53 2,688,904 $ 8.13 2,266,204 $7.41
Stock options granted.................. 819,000 20.11 810,000 15.53 630,000 9.71
Stock options canceled................. (50,000) 14.08 - - (4,000) 9.69
Stock options exercised................ (223,180) 8.44 (438,582) 4.99 (203,300) 4.94
------------ ----------- ------------
Ending stock options oustanding........ 3,606,142 $12.79 3,060,322 $10.53 2,688,904 $8.13
============ ======== =========== ======== ============ =======
Ending stock options exercisable....... 1,490,788 $ 8.47 1,406,757 $ 8.15 1,198,774 $6.93
============ ======== =========== ======== ============ =======
Weighted average fair value............ $4.14 $ 4.92 $3.17
of options............................ ========== ========== ==========
54
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Of the 3,606,142 options outstanding at December 31, 1998: (a) 1,782,342
options have exercise prices between $3.50 and $9.81, with a weighted average
exercise price of $8.56 and a weighted average contractual life of 5.8 years
(1,261,988 of these options are exercisable currently at a weighted average
price of $8.10); (b) 1,823,800 options have exercise prices between $10.00 and
$20.19, with a weighted average exercise price of $16.92 and a weighted average
contractual life of 8.4 years (228,800 of these options are exercisable
currently at a weighted average price of $10.47).
All of the outstanding options are exercisable at various times in years
1999 through 2008. All incentive stock options and non-qualified options were
granted at fair market value on the date of grant. As of December 31, 1998, no
awards other than incentive and non-qualified stock options have been granted
under the 1990 Plan. Generally, options granted under the 1990 Plan have a 10-
year term and provide for vesting after three years.
At December 31, 1998, a total of 5,111,142 shares of the Company's common
stock are reserved for issuance pursuant to the 1990 Plan and the Director Plan.
Preferred Stock
Preferred stock at December 31, 1998, consists of 5,000,000 authorized but
unissued shares. Preferred stock may be issued from time to time in one or more
series, and the Board of Directors, without further approval of the
stockholders, is authorized to fix the dividend rates and terms, conversion
rights, voting rights, redemption rights and terms, liquidation preferences,
sinking fund and any other rights, preferences, privileges and restrictions
applicable to each series of preferred stock.
4. Commitments and Contingencies
The Company committed to perform 17,728 work units related to its
concession rights in the Naranjillos field in Santa Cruz Province, Bolivia
awarded in late 1997. The total work unit commitment was guaranteed by the
Company through an $88.6 million letter of credit; however, the Company
anticipated that it would fulfill this three-year work unit commitment through
approximately $50 to $60 million of various seismic and drilling capital
expenditures. During 1998, the Company spent approximately $7.6 million in the
fulfillment of 1,218 work units through the acquisition of seismic data and the
drilling of one well. The Company has budgeted to spend $24 million (7,500 work
units) in 1999 related to the fulfillment of its Naranjillos field commitment.
The Company had $111.2 million in letters of credit (including the $88.6
million letter of credit discussed above) outstanding at December 31, 1998.
These letters of credit relate primarily to various obligations for acquisition
and exploration activities in South America and bonding requirements of various
state regulatory agencies for oil and gas operations.
Under the Company's exploration contract on Block 19 in Ecuador, the
Company is required to participate in the drilling of one additional well. The
Company expects to drill this well during 2000 at a cost of approximately $4
million.
55
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company is also committed to spend approximately $11 million in the
Republic of Yemen over a two and one-half year period which began July 28, 1998.
The expenditures will include the acquisition and interpretation of over 150
square kilometers of seismic and the drilling of three exploration wells. At
the end of the first two and one-half years, the Company has the option to
extend the work program for a second two and one-half year period with similar
work and capital commitments required. During 1998, approximately $0.6 million
of the $11 million commitment was spent. The Company has budgeted to spend
approximately $5 million in 1999 on the acquisition of seismic data in Yemen.
On November 4, 1998, the Company issued 1,325,000 shares of common stock to
Elf Aquitaine as partial consideration for the acquisition of its French
subsidiary, Elf Hydrocarbures Equateur, S.A., which owns producing oil
properties and undeveloped acreage in Ecuador. The 1,325,000 shares of common
stock of the Company is valued at a guaranteed amount of $20 per share, or $26.5
million. If the Company's prevailing share price is not equal to at least $20
per share after two years from the date of closing, then the Company will be
required to deliver additional consideration under the price guarantee provision
of the agreement. Such additional consideration, if any, is payable, at the
Company's option, in cash or additional shares of the Company's common stock.
Had the Company been required to fulfill its commitment under the price
guarantee at December 31, 1998 (based on the average price for the preceding 60
trading days of $10.57), it would have had to pay an additional $12.8 million or
issue an additional 1.2 million shares of its common stock.
Rent expense was $1.2 million, $1.2 million and $1.0 million for 1998, 1997
and 1996, respectively. The future minimum commitments under long-term non-
cancellable leases for office space are $1.4 million, $1.4 million, $1.2 million
and $0.1 million for the calendar years 1999 through 2002, respectively.
On November 5, 1996, the Province of Santa Cruz, Argentina brought suit
against the Company's subsidiary Cadipsa S.A. in the Corte Suprema de Justicia
de la Nacion (the Supreme Court of Justice of the Argentine Republic, Buenos
Aires, Argentina), Dossier No. s-1451, seeking to recover approximately $10.6
million (which sum includes interest) allegedly due as additional royalties on
four concessions granted in 1990 in which the Company currently owns a 100
percent working interest. The Company and its predecessors in title have been
paying royalties at an eight percent rate; the Province of Santa Cruz claims the
rate should be 12 percent. The amount of such claim will increase at the
differential of these royalty rates until this claim is resolved. With respect
to the 50 percent interest in the two concessions that the Company acquired from
British Gas, plc, the Company believes that it is entitled to indemnification by
British Gas, plc for any loss sustained by the Company as a result of this
claim. Such indemnification equals approximately $4.7 million of the current
$18.0 million claim as of December 31, 1998. The Company has no indemnification
from its predecessors in title with respect to the payment of royalties on the
other two concessions. Although the Company cannot predict the outcome of this
litigation, based upon the advice of counsel, the Company does not expect this
claim to have a material adverse impact on the Company's financial position or
results of operations.
The Company is a defendant in various other lawsuits and is a party in
governmental proceedings from time to time arising in the ordinary course of
business. In the opinion of management, none of the various other pending
lawsuits and proceedings should have a material adverse impact on the Company's
financial position or results of operations.
56
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
5. Financial Instruments
Price Risk Management
The Company periodically uses hedges (swap agreements) to reduce the impact
of oil and natural gas price fluctuations on its operating results and cash
flows. These swap agreements typically entitle the Company to receive payments
from (or require it to make payments to) the counter parties based upon the
differential between a fixed price and a floating price based on a published
index. The Company's hedging activities are conducted with major corporations
and investment and commercial banks which the Company believes are minimal
credit risks.
At December 31, 1998, the Company was a party to natural gas basis swaps
for the calender year 1999 covering a total of 30,842,000 MMBtu of gas. These
natural gas basis swaps were used to hedge the basis differential between the
NYMEX reference price and industry delivery point indexes under which the gas is
sold. At December 31, 1997, the Company was not a party to any financial
derivative agreements.
Fair Value of Financial Instruments
The Company values financial instruments as required by Statement of
Financial Accounting Standards No. 107, Disclosures About Fair Value of
Financial Instruments. The Company estimates the value of the Notes based on
quoted market prices. The Company estimates the value of its other long-term
debt based on the estimated borrowing rates currently available to the Company
for long-term loans with similar terms and remaining maturities. The estimated
fair value of the Company's long-term debt at December 31, 1998 and 1997, was
$663.0 million and $463.6 million, respectively, compared with a carrying value
of $672.5 million and $451.1 million, respectively.
The fair value of commodity swap agreements is the amount at which they
could be settled, based on quoted market prices. The Company had no commodity
swap agreements in place at December 31, 1997. The Company is unable to
estimate the fair value of the natural gas basis swaps in place at December 31,
1998, as there is no quoted market price available.
The carrying value of other financial instruments approximates fair value
because of the short maturity of those instruments.
57
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
6. Income Taxes
Income (loss) before income taxes and minority interest is composed of the
following:
(In thousands) 1998 1997 1996
------------ ----------- ---------
(Restated) (Restated)
Domestic........................... $(122,331) $31,919 $27,999
Foreign............................ (8,898) 30,113 15,646
------------ ---------- ----------
$(131,229) $62,032 $43,645
============ ========== ==========
The total provision (benefit) for income taxes consists of the following:
(In thousands) 1998 1997 1996
----------- ----------- ----------
(Restated) (Restated)
Current:
Domestic......................... $ (5,324) $ 4,277 $ 2,610
Foreign.......................... 1,256 958 -
Deferred:
Domestic......................... (43,722) 6,003 8,431
Foreign.......................... 4,226 (4,363) (1,066)
---------- ---------- ----------
$(43,564) $ 6,875 $ 9,975
========== ========== ==========
A reconciliation of the Federal statutory income tax rate to the effective
rate is as follows:
1998 1997 1996
-------- ------------ ------------
(Restated) (Restated)
Statutory income tax rate...................... (35.0)% 35.0% 35.0%
State income tax............................... (3.9) 3.9 3.9
Federal income tax credits..................... 1.8 (3.0) (4.0)
Foreign withholding tax........................ 1.3 - -
Foreign operations............................. (3.4) 0.6 (10.6)
Argentina NOL valuation allowance.............. 4.3 - -
Argentina NOL valuation allowance reversal..... - (5.0) -
Argentina NOL carryforward utilization......... - (18.4) -
Other.......................................... 1.7 (2.0) (1.4)
----- --------- ---------
(33.2)% 11.1% 22.9%
===== ========= =========
58
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The components of the Company's net deferred tax asset (liability) as of
December 31, 1998 and 1997, are as follows:
(In thousands) 1998 1997
--------- ---------
(Restated)
Deferred Tax Assets:
U.S. net operating loss carryforwards............. $31,396 $ -
Argentina net operating loss carryforwards........ 10,682 4,206
U.S. alternative minimum tax credit carryforward.. 4,815 2,949
Argentina asset tax credit carryforward........... 1,739 -
Other temporary book/tax differences.............. 5,433 425
--------- ---------
54,065 7,580
Valuation allowance............................... (5,677) -
--------- ---------
48,388 7,580
--------- ---------
Deferred Tax Liabilities:
Book/tax differences in property basis............ 45,436 45,890
Other temporary book/tax differences.............. 447 619
--------- ---------
45,883 46,509
--------- ---------
Net deferred tax asset (liability)............ $ 2,505 $(38,929)
========== =========
Earnings of the Company's foreign subsidiaries are subject to foreign income
taxes. No U.S. deferred tax liability will be recognized related to the
unremitted earnings of these foreign subsidiaries, as it is the Company's
intention, generally, to reinvest such earnings permanently.
As of December 31, 1998, the Company has a U.S. Federal alternative minimum
tax ("AMT") credit carryforward of approximately $4.8 million. The AMT credit
carryforward does not expire and is available to offset U.S. Federal regular
income taxes in future years, but only to the extent that U.S. Federal regular
income taxes exceed the AMT in such years.
As of December 31, 1998, the Company had estimated net operating loss ("NOL")
carryforwards for U.S. Federal income tax purposes and U.S. state income tax
purposes of $75.3 million and $105.1 million, respectively. The U.S. Federal
carryforward can be carried forward 20 years and used to offset future taxable
income of the Company. The state carryforwards have varying lengths of
allowable carryforward periods ranging from 5 to 20 years and can be used to
offset future state taxable incomes.
As of December 31, 1998, the Company had estimated NOL carryforwards for
Argentina income tax reporting purposes of approximately $44.9 million which can
be used to offset future taxable income in Argentina. The carryforward amount
includes certain Argentina NOL carryforwards ($17.3 million) which were acquired
and are recorded at cost ($1.0 million), which is less than the calculated value
for the tax effect of these carryforwards ($6.0 million) under the provisions of
Statement of Financial Accounting Standards No. 109, Accounting for Income
Taxes. These unrecorded NOL carryforwards ($14.4 million) will reduce the
Company's foreign income tax provision in future years by approximately $5.0
million if their benefit is realized. As a result of the significant decline in
oil prices in 1998, primarily in the fourth quarter, the Company currently
believes that of the $27.6 million of Argentina NOL carryforwards generated by
Cadipsa and VOA, $16.2 million will expire on December 31, 1999, unutilized and
has therefore recorded a valuation allowance against its Argentina deferred tax
asset of $5.7 million in 1998 related to these carryforwards.
59
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table details the year of expiration of the Argentina tax NOL
carryforwards and the financial statement value of the net operating losses
before any valuation allowances:
(In thousands) Tax Financial
NOL Statement
Year of NOL Expiration Value Value
- ----------------------- --------- ---------
1999................... $17,114 $ 5,677
2000................... 3,843 654
2001................... 14,448 1,024
2002................... - -
2003................... 9,505 3,327
--------- ---------
$44,910 $10,682
========= =========
7. Significant Acquisitions
On April 1, 1997, the Company acquired certain producing oil and gas
properties and facilities located in the Gulf Coast area of Texas and Louisiana
from subsidiaries of Burlington Resources Inc. for approximately $102.7 million
in cash (the "Burlington Acquisition"). Funds for this acquisition were provided
by advances under the Company's revolving credit facility.
If the Burlington Acquisition had been consummated as of January 1, 1996,
the Company's unaudited pro forma revenues, net income and earnings per share
for the years ended December 31, 1997 and 1996, would have been as shown below;
however, such pro forma information is not necessarily indicative of what
actually would have occurred had the transaction occurred on such date.
1997 1996
----------------------
(Restated)
Revenues (in thousands).... $431,306 $376,207
Net income (in thousands).. 57,565 44,334
Earnings per share:
Basic................... 1.12 .92
Diluted................. 1.11 .91
60
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
8. Segment Information
The Company adopted Statement of Financial Accounting Standards No. 131,
Disclosures About Segments of an Enterprise and Related Information, in 1998
which changes the way the Company reports information about its operating
segments. The information for 1997 and 1996 has been restated from the prior
year's presentation to conform to the 1998 presentation.
The Company's reportable business segments have been identified based on
the differences in products or services provided. Revenues for the exploration
and production segment are derived from the production and sale of natural gas
and crude oil. Revenues for the gathering segment arise from the transportation
and sale of natural gas and crude oil. The gas marketing segment generates
revenue by earning fees through the marketing of Company produced gas volumes
and the purchase and resale of third party produced gas volumes. The Company
evaluates the performance of its operating segments based on operating income.
Operations in the gathering and gas marketing industries are in the United
States. The Company operates in the oil and gas exploration and production
industry in the United States, South America and in Yemen beginning in 1998.
Summarized financial information for the Company's reportable segments is shown
on the following page.
61
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Exploration and Production
-------------------------------
Other Gas
U.S. Argentina Foreign Gathering Marketing Corporate Total
----------------------------------------------------------------------------
1998
- --------------------------------------
Revenues from external customers...... $195,060 $ 65,819 $ 5,782 $ 7,741 $54,108 $ 425 $ 328,935
Intersegment revenues................. - - - 884 1,466 - 2,350
Depreciation, depletion and
amortization expense............ 75,479 26,610 2,968 1,693 - 2,225 108,975
Impairment of oil and gas properties.. 70,913 - - - - - 70,913
Operating income (loss)............... (66,275) 12,282 (2,098) (210) 2,548 (1,800) (55,553)
Total assets.......................... 569,560 256,525 113,956 7,500 8,735 57,899 1,014,175
Capital investments................... 177,970 44,592 63,798 1,831 - 3,156 291,347
Long-lived assets..................... 536,885 245,831 100,441 4,350 - 10,735 898,242
1997
- --------------------------------------
Revenues from external customers...... $252,353 $ 93,864 $ 8,896 $18,063 $45,981 $(2,567) $ 416,590
Intersegment revenues................. - - - 1,750 1,671 - 3,421
Depreciation, depletion and
amortization expense............ 66,798 23,333 3,419 1,360 - 1,397 96,307
Impairment of oil and gas properties.. 8,785 - - - - - 8,785
Operating income (loss)............... 78,927 45,707 1,131 3,388 2,584 (5,582) 126,155
Total assets.......................... 567,279 237,544 50,887 8,564 12,427 38,693 915,394
Capital investments................... 193,816 52,819 12,026 1,209 - 1,799 261,669
Long-lived assets..................... 527,321 227,774 42,933 4,190 - 4,669 806,887
1996
- --------------------------------------
Revenues from external customers...... $190,839 $ 67,529 $ - $20,508 $31,920 $ 1,351 $ 312,147
Intersegment revenues................. - - - 1,740 1,091 - 2,831
Depreciation, depletion and
and amortization expense........ 48,969 15,636 - 1,337 - 919 66,861
Operating income (loss)............... 64,961 30,601 (3,907) 2,186 2,383 432 96,656
Total assets.......................... 455,547 228,559 40,674 10,249 8,422 23,365 766,816
Capital investments................... 107,976 48,028 40,727 724 - 706 198,161
Long-lived assets..................... 418,162 199,244 37,496 5,073 - 4,050 664,025
Intersegment sales are priced in accordance with terms of existing
contracts and current market conditions. Capital investments include expensed
exploratory costs. Corporate general and administrative costs and interest
costs are not allocated to segments.
During 1997 and 1996, sales to one crude oil purchaser of the exploration
and production segment represented approximately 10 percent and 15 percent,
respectively, of the Company's total revenues (exclusive of eliminations of
intersegment sales and the impact of hedges). The Company had no single
purchaser to which sales of any segment in 1998 exceeded 10 percent of the
Company's 1998 total revenues.
62
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
9. Detail of Prepaids and Other Current Assets
(In thousands) 1998 1997
--------------------
Value added tax receivable......... $ 2,750 $ 5,494
U.S. Income tax refund receivable.. 5,323 -
Other prepaids and current assets.. 10,239 6,949
--------------------
$18,312 $12,443
====================
10. Quarterly Results (Unaudited)
The following is a summary of the quarterly results of operations for the
years ended December 31, 1998 and 1997:
(In thousands, except per share amounts) Quarter Ended
---------------------------------------
Mar. 31 Jun. 30 Sept. 30 Dec. 31
---------------------------------------
1998
- ------------------------------------------
Revenues................................... $89,994 $84,932 $ 79,285 $ 74,724
Operating income (loss).................... 13,497 4,137 3,781 (74,744)
Net income (loss).......................... (1,582) (9,508) (9,925) (66,650)
Earnings (loss) per share:
Basic................................... (.03) (.18) (.19) (1.27)
Diluted................................. (.03) (.18) (.19) (1.27)
1997 (Restated)
- ------------------------------------------
Revenues................................... $99,234 $99,843 $104,387 $113,124
Operating income........................... 37,658 29,364 33,067 27,463
Net income................................. 17,863 10,900 13,526 12,665
Earnings per share:
Basic................................... .36 .21 .26 .25
Diluted................................. .35 .21 .26 .24
Revenues and operating income for the quarter ended December 31, 1997,
were decreased by a $4.4 million charge resulting from an adverse judgement
against the Company in a lawsuit involving a 1992 gas contract termination and
increased by $1.6 million from a gain on the sale of a gas gathering system.
Operating income for the quarters ended December 31, 1998 and 1997, were
decreased by $70.9 million and $8.8 million, respectively, due to impairments of
oil and gas properties resulting from declines in oil and gas prices during the
fourth quarters of each year. The net impact of these items reduced net income
for the quarters ended December 31, 1998 and 1997, by $43.3 million and $5.4
million, respectively, or 83 cents and 10 cents per basic and diluted share.
63
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
11. Supplementary Financial Information for Oil and Gas Producing Activities
Results of Operations from Oil and Gas Producing Activities
The following sets forth certain information with respect to the Company's
results of operations from oil and gas producing activities for the years ended
December 31, 1998, 1997 and 1996. The Company began operations in Bolivia in
January 1997.
1998
-------------------------------------------------
(In thousands) U.S. Argentina Bolivia Other Total
-------------------------------------------------
Revenues.................................... $195,060 $65,819 $ 5,334 $ 448 $266,661
Production (lifting) costs.................. 94,332 26,737 1,424 233 122,726
Exploration costs........................... 20,610 191 2,255 1,000 24,056
Impairment of proved properties............. 70,913 - - - 70,913
Depreciation, depletion and amortization.... 75,479 26,610 2,858 110 105,057
-------------------------------------------------
Results of operations before income taxes... (66,274) 12,281 (1,203) (895) (56,091)
Income tax expense (benefit)................ (25,781) 4,299 (423) (356) (22,261)
-------------------------------------------------
Results of operations (excluding corporate
overhead and interest costs)......... $(40,493) $ 7,982 $ (780) $ (539) $(33,830)
=================================================
1997 (Restated)
---------------------------------------------------
(In thousands).............................. U.S. Argentina Bolivia Other Total
---------------------------------------------------
Revenues.................................... $252,353 $93,864 $8,896 $ - $355,113
Production (lifting) costs.................. 89,069 24,129 1,148 - 114,346
Exploration costs........................... 8,774 695 130 3,068 12,667
Impairment of proved properties............. 8,785 - - - 8,785
Depreciation, depletion and amortization.... 66,798 23,333 3,401 18 93,550
---------------------------------------------------
Results of operations before income taxes... 78,927 45,707 4,217 (3,086) 125,765
Income tax expense (benefit)................ 30,703 - 1,433 (1,193) 30,943
---------------------------------------------------
Results of operations (excluding corporate
overhead and interest costs)......... $ 48,224 $45,707 $2,784 $(1,893) $ 94,822
===================================================
64
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
1996 (Restated)
-----------------------------------------
(In thousands) U.S. Argentina Other Total
-----------------------------------------
Revenues.................................... $190,839 $67,529 $ - $258,368
Production (lifting) costs.................. 70,991 20,925 - 91,916
Exploration costs........................... 5,918 367 3,907 10,192
Depreciation, depletion and amortization.... 48,969 15,636 - 64,605
-----------------------------------------
Results of operations before income taxes... 64,961 30,601 (3,907) 91,655
Income tax expense (benefit)................ 23,256 - (1,360) 21,896
-----------------------------------------
Results of operations (excluding corporate
overhead and interest costs)......... $ 41,705 $30,601 $(2,547) $ 69,759
=========================================
Capitalized Costs and Costs Incurred Relating to Oil and Gas Producing
Activities
The Company's net investment in oil and gas properties at December 31, 1998
and 1997, was as follows:
1998
-----------------------------------------------------
(In thousands) U.S. Argentina Bolivia Other Total
-----------------------------------------------------
Unproved properties not being amortized.. $ 14,906 $ - $ - $ 4,784 $ 19,690
Proved properties being amortized........ 932,334 314,997 67,675 34,218 1,349,224
-----------------------------------------------------
Total capitalized costs........... 947,240 314,997 67,675 39,002 1,368,914
Less accumulated depreciation,
depletion and amortization........ 410,355 69,166 6,126 110 485,757
-----------------------------------------------------
Net capitalized costs............. $536,885 $245,831 $61,549 $38,892 $ 883,157
=====================================================
1997 (Restated)
---------------------------------------------------
(In thousands) U.S. Argentina Bolivia Other Total
---------------------------------------------------
Unproved properties not being amortized.. $ 9,491 $ - $ - $477 $ 9,968
Proved properties being amortized........ 832,529 270,395 45,857 - 1,148,781
---------------------------------------------------
Total capitalized costs........... 842,020 270,395 45,857 477 1,158,749
Less accumulated depreciation,
depletion and amortization........ 314,699 42,621 3,401 - 360,721
---------------------------------------------------
Net capitalized costs............. $527,321 $227,774 $42,456 $477 $ 798,028
===================================================
65
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following sets forth certain information with respect to costs incurred
(exclusive of general support facilities) in the Company's oil and gas
activities during 1998, 1997 and 1996:
1998
-------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Other Total
----------- ---------- --------- ------- ----------
Acquisitions:
Undeveloped properties. $ 6,460 $ - $ - $ 4,301 $ 10,761
Producing properties... 70,805 - - 34,218 105,023
Exploratory................... 49,952 1,416 10,324 1,000 62,692
Development................... 50,753 43,176 13,949 6 107,884
----------- ---------- --------- -------- ---------
Total costs incurred... $177,970 $44,592 $24,273 $39,525 $286,360
=========== ========== ========= ======== =========
1997 (Restated)
-------------------------------------------------------
(In thousands)................ U.S. Argentina Bolivia Other Total
----------- ---------- --------- ------- ----------
Acquisitions:
Undeveloped properties. $ 7,138 $ - $ 560 $ 75 $ 7,773
Producing properties... 133,548 - 6,201 - 139,749
Exploratory................... 16,463 3,971 - 2,983 23,417
Development................... 36,667 48,848 2,148 59 87,722
----------- ---------- -------- ------- --------
Total costs incurred... $193,816 $52,819 $8,909 $3,117 $258,661
=========== ========== ======== ======== ========
1996 (Restated)
-------------------------------------------------------
(In thousands)................ U.S. Argentina Bolivia Other Total
----------- ---------- --------- ------- ----------
Acquisitions:
Undeveloped properties. $ 9,868 $ 2,080 $ - $3,679 $ 15,627
Producing properties... 50,480 3,754 37,048 - 91,282
Exploratory................... 6,502 1,383 - - 7,885
Development................... 41,126 40,811 - - 81,937
---------- ---------- --------- ------- --------
Total costs incurred... $107,976 $48,028 $37,048 $3,679 $196,731
========== ========== ======== ======== ========
66
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. The
following is an analysis of the Company's proved oil and gas reserves located in
the United States, Argentina and Ecuador as estimated by the independent
petroleum consultants of Netherland, Sewell & Associates, Inc. and in Bolivia as
estimated by the independent petroleum consultants of DeGolyer and MacNaughton.
U.S. Argentina Bolivia Ecuador Total
------------------- ------------------ ----------------- -------- ------------------
Oil Gas Oil Gas Oil Gas Oil Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf)
--------- -------- --------- ------- ----------------- -------- -------- --------
Proved reserves at December 31, 1995... 80,227 310,762 67,644 - - - - 147,871 310,762
Revisions of previous estimates........ 13,382 21,834 12,449 - - - - 25,831 21,834
Extensions, discoveries and
other additions....................... 458 5,445 308 - - - - 766 5,445
Production............................. (7,694) (32,366) (4,245) - - - - (11,939) (32,366)
Purchase of reserves-in-place.......... 8,095 20,787 2,849 - 4,953 57,758 - 15,897 78,545
reserves-in-place
Sales of reserves-in-place............. (130) (1,374) - - - - - (130) (1,374)
--------- -------- ------- -------- ------ -------- ------- -------- -------
Proved reserves at December 31, 1996... 94,338 325,088 79,005 - 4,953 57,758 - 178,296 382,846
Revisions of previous estimates........ (9,693) (18,045) 7,065 - 607 28,414 - (2,021) 10,369
Extensions, discoveries and
other additions....................... 345 29,451 1,211 - - - - 1,556 29,451
Production............................. (9,692) (36,623) (5,630) - (135) (6,068) - (15,457) (42,691)
Purchase of reserves-in-place.......... 24,653 62,253 - - 758 111,212 - 25,411 173,465
Sales of reserves-in-place............. (17) (1,277) - - - - - (17) (1,277)
--------- -------- ------- -------- ------ -------- ------- -------- -------
Proved reserves at December 31, 1997... 99,934 360,847 81,651 - 6,183 191,316 - 187,768 552,163
Revisions of previous estimates........ (38,473) (11,252) (4,579) 12,024 (665) 101,624 2,546 (41,171) 102,396
Extensions, discoveries and
other additions....................... 306 28,345 4,091 - 2,968 121,419 - 7,365 149,764
Production............................. (9,912) (42,176) (6,322) - (122) (5,062) (78) (16,434) (47,238)
Purchase of reserves-in-place.......... 5,452 53,027 - - - - 21,577 27,029 53,027
Sales of reserves-in-place............. (100) (3,279) - - - - - (100) (3,279)
--------- -------- ------- -------- ------ -------- ------- -------- -------
Proved reserves at December 31, 1998... 57,207 385,512 74,841 12,024 8,364 409,297 24,045 164,457 806,833
========= ======== ======= ======== ====== ======== ======= ======= =======
Proved developed reserves at:
December 31, 1996............... 79,250 289,464 46,582 - 1,007 51,276 - 126,839 340,740
========= ======== ======= ======== ====== ======== ======= ======= =======
December 31, 1997............... 79,494 316,306 47,806 - 1,502 140,124 - 128,802 456,430
========= ======== ======= ======== ====== ======== ======= ======= =======
December 31, 1998............... 51,481 330,371 47,167 12,024 4,390 278,317 1,255 104,293 620,712
========= ======== ======= ======== ====== ======== ======= ======= =======
67
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves (Unaudited)
The Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves ("Standardized Measure") is a disclosure requirement
under SFAS No. 69. The Standardized Measure does not purport to present the
fair market value of proved oil and gas reserves. This would require
consideration of expected future economic and operating conditions which are not
taken into account in calculating the Standardized Measure.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end prices to the estimated future production of year-end proved
reserves. Future cash inflows were reduced by estimated future production,
development and abandonment costs based on year-end costs to determine pre-tax
cash inflows. Future income taxes were computed by applying the statutory tax
rate to the excess of pre-tax cash inflows over the Company's tax basis in the
associated proved oil and gas properties. Tax credits and permanent differences
were also considered in the future income tax calculation. Future net cash
inflows after income taxes were discounted using a 10 percent annual discount
rate to arrive at the Standardized Measure.
Set forth below is the Standardized Measure relating to proved oil and gas
reserves at December 31, 1998 and 1997:
1998
-------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Ecuador Total
-------------------------------------------------------
Future cash inflows................ $1,314,729 $638,317 $439,241 $145,230 $2,537,517
Future production costs............ 570,034 311,989 41,582 44,758 968,363
Future development and
abandonment costs............... 129,903 125,204 48,613 49,087 352,807
-------------------------------------------------------
Future net cash inflows before
income tax expense.............. 614,792 201,124 349,046 51,385 1,216,347
Future income tax expense.......... 42,539 - 107,025 6,008 155,572
-------------------------------------------------------
Future net cash flows.............. 572,253 201,124 242,021 45,377 1,060,775
10 percent annual discount for
estimated timing of cash flows.. 188,044 74,049 130,825 19,635 412,553
-------------------------------------------------------
Standardized Measure of discounted
future net cash flows........... $ 384,209 $127,075 $111,196 $ 25,742 $ 648,222
=======================================================
68
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
1997
-----------------------------------------------
(In thousands) U.S. Argentina Bolivia Total
-----------------------------------------------
Future cash inflows....................................... $2,321,760 $1,138,154 $357,767 $3,817,681
Future production costs................................... 1,005,407 448,262 32,321 1,485,990
Future development and abandonment costs.................. 177,792 150,544 27,985 356,321
-----------------------------------------------
Future net cash inflows before income tax expense......... 1,138,561 539,348 297,461 1,975,370
Future income tax expense................................. 281,019 99,588 97,739 478,346
-----------------------------------------------
Future net cash flows..................................... 857,542 439,760 199,722 1,497,024
10 percent annual discount for
estimated timing of cash flows.......................... 253,026 142,735 84,618 480,379
-----------------------------------------------
Standardized Measure of discounted future net cash flows.. $ 604,516 $ 297,025 $115,104 $1,016,645
===============================================
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves (Unaudited)
The following is an analysis of the changes in the Standardized Measure
during 1998, 1997 and 1996:
(In thousands) 1998 1997 1996
-------------------------------------
Standardized Measure - beginning of year............... $1,016,645 $1,392,841 $ 736,546
Increases (decreases) -
Sales, net of production costs...................... (145,709) (240,767) (166,452)
Net change in sales price, net of production costs.. (505,314) (824,264) 644,367
Discoveries and extensions, net of related
future development and production costs............. 98,521 56,334 20,085
Changes in estimated future development costs....... (17,025) (89,637) (69,433)
Development costs incurred.......................... 98,434 77,127 77,174
Revisions of previous quantity estimates............ (124,097) 3,508 251,736
Accretion of discount............................... 122,256 180,714 88,411
Net change in income taxes.......................... 150,582 215,131 (248,427)
Purchase of reserves-in-place....................... 110,389 240,658 149,900
Sales of reserves-in-place.......................... (1,493) (2,518) (1,859)
Timing of production of reserves and other.......... (154,967) 7,518 (89,207)
-------------------------------------
Standardized Measure - end of year..................... $ 648,222 $1,016,645 $1,392,841
=====================================
69
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 The Chase Manhattan
Bank (formerly 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 of 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).
4.4 Indenture dated as of January 26, 1999, between The Chase Manhattan
Bank, as Trustee, and the Company.
10.1* Employment and Noncompetition Agreement dated January 7, 1987, between
the Company and Charles C. Stephenson, Jr. (Filed as Exhibit 10.19 to
the S-1 Registration Statement).
10.2* Employment and Noncompetition Agreement dated January 7, 1987, between
the Company and Jo Bob Hille (Filed as Exhibit 10.20 to the S-1
Registration Statement).
10.3* 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* Amendment No. 4 to Vintage Petroleum, Inc. 1990 Stock Plan dated March
11, 1998 (Filed as Exhibit A to the Company's Proxy Statement for
annual meeting of stockholders dated March 31, 1998).
10.9* Vintage Petroleum, Inc. 401(k) Plan (Filed as Exhibit 4(c) to the
Company's Registration Statement on Form S-8, Registration No. 33-
55706).
10.10* Vintage Petroleum, Inc. Non-Management Director Stock Option Plan
(Filed as Exhibit 10.18 to the Company's report on Form 10-K for the
year ended December 31, 1992, filed March 31, 1993 (the "1992 Form 10-
K")).
10.11* Form of Incentive Stock Option Agreement under the Vintage Petroleum,
Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the Company's report on
Form 10-K for the year ended December 31, 1990, filed April 1, 1991).
10.12* Form of Non-Qualified Stock Option Agreement under the Vintage
Petroleum, Inc. 1990 Stock Plan (Filed as Exhibit 10.20 to the 1992
Form 10-K).
10.13 Amended and Restated Credit Agreement dated as of October 21, 1998,
among the Company, as borrower, and certain commercial lending
institutions, as lenders, Bank of Montreal, as administrative agent,
Nations Bank, N.A., as syndication agent, and Societe Generale
Southwest Agency, as documentation agent (Filed as Exhibit 10 the
Company's Report on Form 10-Q for the quarter ended September 30, 1998,
filed November 13, 1998).
10.14 First Amendment to the Amended and Restated Credit Agreement dated as
of December 10, 1998, among the Company, as borrower, and certain
commercial lending institutions, as lenders, Bank of Montreal, as
administrative agent, Nations Bank, N.A., as syndication agent, and
Societe Generale Southwest Agency, as documentation agent.
21. Subsidiaries of the Company.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Netherland, Sewell & Associates, Inc.
23.3 Consent of DeGolyer and MacNaughton.
27. Financial Data Schedule.
____________________
* Management contract or compensatory plan or arrangement.