Annual Report — [x] Reg. S-K Item 405 — Form 10-K
Filing Table of Contents
Document/Exhibit Description Pages Size
1: 10-K405 Annual Report -- [x] Reg. S-K Item 405 78 434K
2: EX-10.13 Non-Qualified Stock Option Agreement 4 19K
3: EX-10.17 Amended and Restated Credit Agreement 31 78K
4: EX-21 Subsidiaries of the Registrant 1 5K
5: EX-23.1 Consent of Arthur Andersen L.L.P. 1 6K
6: EX-23.2 Consent of Netherland, Sewell & Associates, Inc. 1 7K
7: EX-23.3 Consent of Degolyer and Macnaughton 1 8K
8: EX-27 Financial Data Schedule 2 9K
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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, 1999
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.)
110 West Seventh Street
Tulsa, Oklahoma 74119-1029
(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
Preferred Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No _____
-----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
As of February 29, 2000, 62,411,866 shares of the Registrant's Common Stock
were outstanding, and the aggregate market value of the Common Stock held by
non-affiliates was approximately $725,961,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the Annual Meeting of
Stockholders to be held May 9, 2000, are incorporated by reference into Part III
of this Form 10-K.
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VINTAGE PETROLEUM, INC.
FORM 10-K
YEAR ENDED DECEMBER 31, 1999
TABLE OF CONTENTS
[Enlarge/Download Table]
PART I
Page
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Items 1 and 2. Business and Properties.................................................................... 1
Item 3. Legal Proceedings.......................................................................... 21
Item 4. Submission of Matters to a Vote of Security-Holders........................................ 21
Item 4A. Executive Officers of the Registrant....................................................... 22
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters...................... 25
Item 6. Selected Financial Data.................................................................... 26
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...... 27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................................. 36
Item 8. Financial Statements and Supplementary Data................................................ 38
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....... 38
PART III
Item 10. Directors and Executive Officers of the Registrant......................................... 38
Item 11. Executive Compensation..................................................................... 38
Item 12. Security Ownership of Certain Beneficial Owners and Management............................. 38
Item 13. Certain Relationships and Related Transactions............................................. 38
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................ 39
Signatures................................................................................................... 42
Index to Financial Statements................................................................................ 43
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 joint
ventures.
"Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf"
means billion cubic feet, "BCFE" means billion cubic feet of gas equivalent,
"MMbtu" means million British thermal units, "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:
. 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;
. expansion and growth of our business and operations; and
. Year 2000 plans and compliance.
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 technical 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, its technical expertise and its
low cost operating structure.
At December 31, 1999, the Company owned and operated producing properties
in 13 states in the United States, with its domestic proved reserves located
primarily in four core areas: the Gulf Coast, East Texas, Mid-Continent and West
Coast areas of the United States. During 1999, the Company acquired additional
producing properties in California. See "Acquisition Activities." In addition,
the Company has international core areas located in Argentina, Bolivia and
Ecuador. In Argentina the Company owns 15 oil concessions, 14 of which are
operated by the Company, in the south flank of the San Jorge Basin in southern
Argentina. During 1999, the Company expanded this core area with the purchase
of the El Huemul concession. See "Acquisition Activities." In Bolivia, the
Company owns and operates three blocks covering approximately 570,000 acres in
the Chaco Plains area of southern Bolivia and 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 operates producing properties in
the Oriente Basin and provides the Company with substantial undeveloped acreage
which the Company believes has significant exploration potential. During 1999,
the Company increased its ownership in these properties by purchasing an
additional interest from one of its partners. See "Acquisition Activities."
As of December 31, 1999, the Company owned interests in 3,505 gross (2,712
net) productive wells in the United States, of which approximately 82 percent
are operated by the Company, 1,057 gross (1,040 net) productive wells in
Argentina, of which approximately 98 percent are operated by the Company, 16
gross (15 net) productive wells in Bolivia, 100 percent of which are operated by
the Company, and 8 gross (6 net) productive wells in Ecuador, 100 percent of
which are operated by the Company. As of December 31, 1999, the Company's
properties had proved reserves of 468.0 MMBOE, comprised of 303.2 MMBbls of oil
and 989.0 Bcf of gas, with a present value of estimated future net revenues
before income taxes (utilizing a 10 percent discount rate) of $3.0 billion and a
standardized measure of discounted future net cash flows of $2.2 billion. From
the first quarter of 1997 through the fourth quarter of 1999, the Company
increased its average net daily production from 37,325 Bbls of oil to 50,250
Bbls of oil and from 97,700 Mcf of gas to 142,150 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 110 West Seventh Street, Tulsa, Oklahoma 74119-
1029, 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 technical 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, 1997, through December 31, 1999, the Company acquired 184.3
MMBOE of proved oil and gas reserves at an average acquisition cost of
$2.23 per BOE. The Company replaced through acquisitions approximately
260 percent of its production of 71.8 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, 1997, through December
31, 1999, the Company spent approximately $220.2 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 72 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, 1999, the Company succeeded in adding 65.7
MMBOE to proved reserves, replacing approximately 91 percent of
production during this period. During 1999, excluding the impact of
significantly higher year-end oil and gas prices, the Company added
14.7 MMBOE through exploitation, replacing 59 percent of production
even though exploitation capital spending was curtailed for a portion
of 1999. The impact of higher year-end oil and gas prices resulted in
an additional 75.4 MMBOE of reserve additions in 1999, which more than
replaced the 49.0 MMBOE of proved reserves lost at year-end 1998 due
to historically low oil and gas prices. The Company continues to
maintain an extensive inventory of exploitation and development
opportunities. Due to the improved product price environment, the
Company anticipates increasing its level of spending to approximately
$79 million in 2000 on exploitation and development projects,
primarily in the United States and Argentina.
2
. 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, 1997, through December 31, 1999,
the Company spent approximately $150.8 million on exploration
activities, including the drilling of 72 gross (42.28 net) exploration
wells, of which approximately 56 percent gross (68 percent net) were
productive. As a result of all of the Company's exploration activities
during the three-year period ending December 31, 1999, the Company
succeeded in adding 55.7 MMBOE to proved reserves, replacing
approximately 78 percent of production during this period. The
Company's exploration activities in 1999 were focused on its core
areas in the United States and Bolivia. The Company anticipates
spending approximately $67 million during 2000 on exploration
projects, primarily in the United States, Bolivia, Yemen and Ecuador.
. 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, 1995 and 1999, the Company completed four 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 eight offerings provided the
Company with aggregate net proceeds of approximately $643 million. The
unused portion of the Company's revolving credit facility as of
February 29, 2000, was approximately $363 million.
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 and economically stable.
3
From January 1, 1997, through December 31, 1999, the Company made oil and
gas property acquisitions involving total costs of approximately $411.6 million.
As a result of these acquisitions, the Company acquired approximately 184.3
MMBOE of proved oil and gas reserves. The following table summarizes the
Company's acquisition experience during the periods indicated:
[Enlarge/Download Table]
Proved Reserves When Acquired Cost
-----------------------------------
Per Boe
Acquisition Oil Gas When
Costs (MBbls) (MMcf) MBOE Acquired
-------------- --------- -------- -------- ----------
(In thousands)
U.S. Acquisitions:
1997........................................ $ 133,548 24,653 62,253 35,029 $3.81
1998........................................ 70,805 5,452 53,027 14,290 4.96
1999........................................ 31,662 10,343 14,947 12,834 2.47
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Total U.S. Acquisitions................ 236,015 40,448 130,227 62,153 3.80
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International Acquisitions:
1997........................................ 6,201 758 111,212 19,293 0.32
1998........................................ 34,218 21,577 - 21,577 1.59
1999........................................ 135,125 67,734 81,072 81,246 1.66
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Total International Acquisitions....... 175,544 90,069 192,284 122,116 1.44
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Total U.S. and International Acquisitions...... $ 411,559 130,517 322,511 184,269 $2.23
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The Company estimates that 94.1 MMBOE of proved reserves, as of the various
acquisition dates, were acquired in 1999 for an aggregate cost attributable to
oil and gas assets of $166.8 million, resulting in an average cost of $1.77 per
BOE. This average cost per BOE is substantially lower than the Company's
average acquisition cost over the three-year period ended December 31, 1999, of
$2.23 per BOE and the average acquisition cost since the Company's inception of
$2.63 per BOE.
The following is a brief discussion of the significant acquisitions in
1999:
Nuevo Energy Company (West Coast). In December 1999, the Company purchased
from Nuevo Energy Company and its affiliate certain oil and gas producing
properties and facilities located in the Ventura basin of Southern California
for $29.6 million in cash (the "Nuevo Acquisition"). This acquisition increases
the Company's significant producing presence in the Ventura basin and is
expected to allow the Company to achieve operating cost efficiencies with
minimal requirements for additional overhead or infrastructure costs. The
properties acquired consist of 13 mature onshore fields in which the Company has
an average working interest of 94 percent and a 100 percent operating interest
in the Santa Clara Valley gas plant which processes all of the gas from these
properties as well as other third party gas. The Company now operates 90
percent of the wells, which have total current net daily production averaging
approximately 2,190 Bbls of mid-gravity crude oil and natural gas liquids and
3,000 Mcf of gas. In addition to the expected operating cost efficiencies, the
properties contain various recompletion and infill drilling opportunities.
Total and Repsol S.A.- El Huemul concession (Argentina). In July 1999, the
Company acquired from Total Austral S.A. and Repsol S.A. their undivided 100
percent operating interest (effective 88 percent net revenue interest) in the El
Huemul-Koluel Kaike concession (the "El Huemul Properties") located in Santa
Cruz Province, Argentina, which Total previously operated (the "El Huemul
Acquisition"). The purchase price for the El Huemul Acquisition was $121.0
million in cash.
4
The El Huemul Properties cover approximately 150,000 gross acres and are
located adjacent to the Company's existing operated concessions in the Santa
Cruz Province. The El Huemul Properties are similar to the Company's existing
properties in this basin and are characterized by mature fields having stable
production decline trends, similar geological formations and production zones,
established waterflood potential and exploration and exploitation upside
potential. Because of these similarities, the Company believes that the
exploitation and exploration success it has experienced in its current Argentina
operations, including development drilling, workovers and recompletions,
secondary recovery projects and exploratory drilling, will be available in the
El Huemul Properties as well. The Company estimates that the El Huemul
Properties have proved exploitation potential through adding new non-producing
behind pipe zones in 107 wells, expanding upon the 13 waterflood areas and
infill or extensional drilling of up to 66 new wells. In addition, the Company
has identified non-proved opportunities within the concession that include
behind pipe zones in 117 wells, installing up to 18 additional waterflood areas
and 50 additional drilling locations. There is also exploration potential that
the Company identified from a review of 3-D seismic provided during the
evaluation process.
Proved reserves for the El Huemul Properties as of July 1, 1999, as
estimated by Netherland, Sewell & Associates, Inc., using a NYMEX reference oil
price of $17.32 per Bbl and an average gas price of $1.02 per Mcf, were 44.7
MMBbls of oil and 81.1 Bcf of gas, or 58.2 MMBOE, with a present value of the
estimated future net revenues before income taxes (utilizing a 10 percent
discount rate) of $233.3 million. Daily production at the time of acquisition,
net of royalties, was approximately 9,400 Bbls of oil and 19,000 Mcf of gas, or
12,567 BOE, from 462 active producing wells. The Company was able to reduce
operating costs on the El Huemul Properties to a level consistent with its
historical operating costs in Argentina by combining certain aspects of the
operations with those of its nearby existing properties. The Company
experienced no significant additions to its overhead costs as a result of this
acquisition.
Petrobras International (Ecuador). In December 1999, the Company, through
its wholly-owned subsidiary Vintage Oil Ecuador S.A., purchased from Petrobras
Internacional S.A. - Braspetro additional working interests in Block 14, Block
17 and the Shiripuno concession located in the Oriente Basin of Ecuador for
$14.1 million in cash. The Company acquired an additional 35 percent working
interest in the Block 14 producing concession increasing its interest to 75
percent, an additional 40 percent interest in the Block 17 producing concession
increasing its interest to 70 percent and an additional 47 percent in the
Shiripuno exploration concession increasing its interest to 100 percent. As a
result of this transaction, the Company's net daily production increased 87
percent from 1,925 Bbls to 3,600 Bbls.
5
Divestiture Activities
During 1999, the Company instituted a divestiture program designed to sell
Company properties that are either marginally economical or non-strategic to the
Company's areas of operation. As part of this program, the Company sold
approximately 227 leases, primarily non-operated, for cash proceeds of
approximately $9.5 million resulting in gains of $7.7 million ($4.7 million
after tax). The Company estimates the properties sold accounted for proved
reserves of approximately 2.6 Bcf of gas and 577 MBbls of oil as of the closing
dates for these sales. The Company's divestiture program is expected to
continue during 2000 with targeted additional estimated proceeds to be raised of
$30 to $55 million.
During December 1999, the Company sold its interest in certain oil and gas
properties located in northern California's Sacramento basin to Calpine
Corporation for $70.0 million, subject to consents and customary post-closing
adjustments. In a separate transaction with an undisclosed buyer, the Company
sold certain royalty interests in Los Angeles county, California for $8.2
million. Combined, the Company estimates the properties sold accounted for
proved reserves of approximately 32.1 Bcf of gas and 682 MBbls of oil as of the
closing dates for these sales. Net daily production from the properties sold
totals approximately 250 Bbls of oil and 14.3 MMcf of gas, or approximately 3.5
percent of the Company's net average daily production rate on a BOE basis for
the fourth quarter of 1999. The Company does not expect that the sale of these
properties will have a material impact on its continuing operations. A portion
of the proceeds from these property sales were used to fund the Nuevo
Acquisition and the proceeds in excess of the Nuevo Acquisition costs were used
to reduce a portion of the Company's outstanding debt. The sales resulted in
$47.3 million in gains ($28.9 million after tax) which were included in the
Company's 1999 operating results.
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 opportunities.
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 1999
(before the impact of higher oil and gas prices) totaled 14.7 MMBOE, or 59
percent of the Company's production of 24.9 MMBOE. The impact of higher
year-end 1999 oil and gas prices on year-end 1998 proved reserves and the
reserves acquired in mid-1999 added another 75.4 MMBOE to the Company's
year-end 1999 proved reserves, more than replacing the reserves lost to the
historically low oil price environment of last year.
As a result of a restricted capital budget due to low oil and gas prices,
the Company only spent $10.8 million on workover and recompletion
operations during 1999, significantly lower than in prior years. A measure of
the overall success of the Company's recompletion and workover operations during
1999 (excluding minor equipment repair and replacement) was that improved
production or operating efficiencies were achieved from approximately 71 percent
of such operations consistent with the average for the last three years of 72
percent.
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.
6
During 1999, the Company participated in the drilling of 18 gross (13.94
net) development wells, of which 17 gross (12.94 net) were productive. At
December 31, 1999, the Company's proved reserves included approximately 126
development or infill drilling locations on its U.S. acreage and 186 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. As a result of low oil and gas prices, the
Company significantly reduced its capital expenditure budget for 1999 and only
spent approximately $3.6 million in the U.S. and $7.9 million in South America
on development/infill drilling during 1999. The Company also spent
approximately $2.3 million on the acquisition of development seismic data and
other development costs in 1999. With the return of higher commodity prices,
the Company has increased its 2000 capital budget for development and
exploitation work to $79 million with spending primarily aimed at U.S. and
Argentina reserves.
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. Compared to previous years, 1999 exploitation efforts were
severely curtailed due to low oil and gas prices. Recompletions and workover
activities were limited in 1999 and produced a 64 percent success rate. Most of
this work was to repair artificial lift equipment or install lift on wells that
had ceased to flow naturally. Recompletions to new zones were attempted in 14
wellbores, 10 of which were successful.
The State Tract 65-2, a 1999 development well drilled as the result of the
successful exploratory State Tract 65-1 well which was a part of the Galveston
Bay-Umbrella Point exploration program, is currently producing from the Text II
formation at gross daily rates of 170 Bbls of oil and 17.9 MMcf of gas. The
Company has a 50 percent working interest in this well.
The Company expects to spend $38 million in 2000 for various U.S.
exploitation projects including recompletions, sidetracks and development
drilling with approximately 50 percent budgeted to be spent in the Gulf Coast
area, primarily in the Company's South Pass Blk 24 and Main Pass Blk 116 fields.
South America. The Company's international exploitation budget of $41
million is heavily weighted toward projects in three of its concessions in
Argentina: El Huemul, Meseta Espinosa and Canadon Seco. Development and
extensional drilling along with the implementation and optimization of secondary
recovery projects have been the focus of the Company's historical exploitation
efforts on its Argentina properties. Drilling activity commenced during
February 1996, and continued through 1998, with 154 wells having been completed.
In January 1999, the Company suspended its Argentina drilling program due to
historic low oil prices. Following the recovery in oil prices, the Company re-
initiated drilling operations in August 1999. 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. 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 19,180 Bbls of oil in January 1999.
The Company is currently drilling with one rig and plans call for adding a
second rig during the year. The addition of the El Huemul concession during
1999 has provided significant additional drilling opportunities which the
Company plans to pursue during 2000 and beyond.
To aid in the optimum placement of drilling locations in Argentina, the
Company has acquired a total of 204 square miles (527 square kilometers) of 2-D
and 3-D seismic since 1996. The Company believes that substantial upside
potential can continue to be economically exploited with the aid of this 3-D
seismic. Additionally, with only approximately 15 percent of the Company's
acreage covered by 3-D seismic, the Company believes that significant additional
drilling potential will continue to be identified though the acquisition of
future 3-D seismic surveys.
7
The Company has also continued its endeavor to optimize existing secondary
recovery projects and to initiate new waterfloods in Argentina. 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 addition of the El Huemul
concession during 1999 provides substantial additional existing waterflood
projects and affords extensive areas amenable to future waterflood expansion
projects.
The Company has focused its exploitation work in Bolivia on its Naranjillos
concession in conjunction with the ongoing exploration work required to fulfill
the work commitment for this concession. As a result of additional geological
and petrophysical information gained from the wells drilled during 1999, the
year-end proven reserves for the previous known shallow reservoirs were revised
upward to 284 BCFE, a 21 percent increase over year-end 1998. Other activity
involved facility improvement required to allow gas to flow from the Naranjillos
concession into the Bolivia-to-Brazil pipeline. Although currently curtailed
due to demand restrictions, the work to date has positioned the Company to be
able to take immediate advantage of the increasing gas market opportunities
through the Bolivia-to-Brazil pipeline and other developing market opportunities
in Brazil and Bolivia.
The Company has focused its exploitation work in Ecuador on upgrading the
production facilities to increase the oil handling capacity from 3,500 Bbls of
oil per day to approximately 10,000 Bbls of oil per day commensurate with the
Block 14 and Block 17 development plans approved by the Ecuadorian government
during December 1998. During late 1999, high-capacity artificial lift equipment
was installed on two producing wells, which increased the combined productive
capacity of the Block 14 and Block 17 concessions from 3,500 Bbls of oil per day
to 5,800 Bbls of oil per day. This is the present production allocation for
these concessions. Additional infill drilling on Block 14 and Block 17 will be
dependent on the timing of the Ecuadorian government's approval and the
construction of an additional pipeline for transportation of oil.
Exploration Activities
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 yearly
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 Bolivia, Yemen and
Ecuador are characterized by higher potential and higher risk. The Company
spent approximately $46.1 million on exploration activities during 1999,
approximately $38.7 million in the U.S. and Bolivia and approximately $7.4
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 nine of 12 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 37
MMcf of gas and 1,120 Bbls of oil. The Company plans to drill two additional
wells in the Umbrella Point field during the first half of 2000.
8
During 1999, the Company extended its exploration activities in the
Galveston Bay area to the Cedar Point field. The recently completed USX
Hematite Unit #1 was the most significant well drilled in 1999. The Company has
a 47 percent working interest in this well. This Lower Vicksburg discovery is
currently producing at gross rates of 600 Bbls of oil per day and 11.3 MMcf of
gas per day. The Company plans to drill two more exploration wells during 2000
in this field.
The Company's $17 million domestic exploration budget for 2000 is targeted
primarily toward gas prospects and includes activities in three of its four U.S.
core areas. Along with the two Gulf Coast Cedar Point wells, the Company plans
to drill up to eight wells in its Stagecoach prospect and three wells in its
Western Oklahoma Alliance, both areas of which are located in the Company's Mid-
Continent core area. The Company also has three gas properties in its West
Coast Sacramento basin it plans to drill during 2000.
Bolivia. The Company believes that its existing projects in Bolivia have
the potential to continue to significantly increase reserves. Activity in
Bolivia during 1999 included the drilling of five wells targeting the Devonian
Iquiri and Los Monos formations. These wells resulted in the addition of 99
BCFE of newly discovered reserves. The Company believes that significant
exploration potential remains to be tested. During 2000, the Company will drill
three deep wells that will test the potential of the deeper Devonian Huamampampa
and Santa Rosa formations. Exploration results of other operators in Bolivia
during 1999 demonstrated the significant potential of these reservoirs.
Additional potential drilling locations targeting the shallow Carboniferous and
deep Devonian Iquiri, Huamampampa and Santa Rosa reservoirs also have been
identified on the Company's Chaco Block.
Yemen. The Company entered into a farm-in agreement during 1998 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 consisting of
3-D seismic and drilling three exploration wells. The Company completed a 175
square kilometer (68 square mile) 3-D seismic survey in early 1999 and
subsequently selected the three drilling locations. The first prospect, An
Naeem, is an offset to the adjacent Halewah field which is currently producing
approximately 25,000 Bbls of oil per day. Drilling of these three wells is
scheduled for the first half of 2000.
Ecuador. The Company originally joined in a project to explore Block 19 in
the Oriente Basin in Ecuador with a 30 percent working interest. Numerous
commercially productive fields have been discovered in this basin. Primary
targets are the Hollin, Napo "U" and Napo "T" sands that are productive in other
significant fields in this basin. The first of two obligatory exploration wells
was drilled and abandoned during 1997 after testing at sub-commercial rates.
During 1999, the Company assumed its partners' working interests in this
concession and is proceeding with plans to drill its Rio Cotapino prospect
during 2000.
Oil and Gas Properties
At December 31, 1999, the Company owned and operated producing properties
in 13 states, with its U.S. proved reserves located primarily in four core
areas: the Gulf Coast, East Texas, Mid-Continent and West Coast 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, 1999, the Company operated approximately 3,942 productive wells and also
owned non-operating interests in 644 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. See "Divestiture Activities."
9
The following table sets forth estimates of the proved oil and gas reserves
of the Company at December 31, 1999, as estimated by the independent petroleum
consultants of Netherland, Sewell & Associates, Inc. ("Netherland, Sewell") for
the United States, Argentina and Ecuador and as estimated by the independent
petroleum consultants of DeGolyer and MacNaughton for Bolivia:
[Enlarge/Download Table]
Oil (MBbls) Gas (MMcf) MBOE
-------------------------------- --------------------------------
Developed Undeveloped Total Developed Undeveloped Total Total
--------- ----------- ----- --------- ----------- ----- -------
West Coast............. 53,196 6,706 59,902 104,515 8,212 112,727 78,690
Gulf Coast............. 29,754 7,495 37,249 75,602 20,718 96,320 53,302
East Texas............. 8,098 502 8,600 75,960 12,884 88,844 23,407
Mid-Continent.......... 3,674 1,017 4,691 46,367 16,767 63,134 15,213
------- ------- ------- ------- ------- ------- -------
Total U.S........... 94,722 15,720 110,442 302,444 58,581 361,025 170,612
------- ------- ------- ------- ------- ------- -------
Argentina.............. 90,125 46,346 136,471 92,696 20,940 113,636 155,412
Bolivia................ 6,414 1,667 8,081 415,743 98,585 514,328 93,802
Ecuador................ 5,524 42,672 48,196 - - - 48,196
------- ------- ------- ------- ------- ------- -------
Total Company....... 196,785 106,405 303,190 810,883 178,106 988,989 468,022
======= ======= ======= ======= ======= ======= =======
Estimates of the Company's 1999 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, 1999, the area
comprised 17 percent of the Company's total proved reserves and 46 percent of
the Company's U.S. proved reserves. The Company currently operates 1,335 active
wells and owns an interest in 174 productive wells operated by others. During
1999, total net daily production averaged approximately 16,500 BOE, or 40
percent of 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.
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, 1999, the Gulf Coast area comprised approximately 11 percent of the
Company's total proved reserves and 31 percent of its U.S. proved reserves. The
Company currently operates 754 productive wells in this area and owns an
additional interest in 140 productive wells. Total net daily production from
this area during 1999 averaged approximately 15,800 BOE, or 38 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.
10
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
five percent of the Company's December 31, 1999, total proved reserves and 14
percent of its U.S. proved reserves. The Company currently operates 542
productive wells in this area and owns an interest in an additional 116
productive wells. During 1999, net daily production averaged approximately
5,500 BOE, or 13 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.
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 three percent of the Company's
December 31, 1999, total proved reserves and nine percent of its U.S. proved
reserves. The Company currently operates 252 productive wells in this area and
owns an interest in an additional 192 productive wells. During 1999, net daily
production averaged approximately 3,750 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 15
mature producing concessions, 14 of which are operated by the Company, located
on the south flank of the San Jorge Basin. These concessions comprised
approximately 33 percent of the Company's December 31, 1999, total proved
reserves. During 1999, net daily production averaged approximately 20,700 Bbls
of oil and 12,825 Mcf of gas including six months of production from the El
Huemul concession interest acquired in July 1999. The Company currently
operates 1,035 productive wells (100 percent working interest) with net daily
production of 24,200 Bbls of oil and 16,900 Mcf of gas. In addition, the
Company owns an interest in 22 productive wells operated by others. At December
31, 1999, the Company's proved reserves included approximately 186 development
or infill drilling locations and 388 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 concessions 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 20 percent of the Company's December 31,
1999, total proved reserves and include 6 gross (5 net) active producing wells,
all of which are operated by the Company. The Company also has 10 gross (10
net) productive wells in its operated Naranjillos concession which were shut-in
at year end due to the current limited gas demand in Brazil. Current net daily
production is restricted to approximately 10,400 Mcf of gas and 175 Bbls of
condensate. The Company is working to develop additional gas markets, both
inside and outside of Bolivia, to increase the level of production from its
concessions. For additional information, see "Exploitation and Development
Activities - South America."
11
Ecuador Concessions. The Ecuador properties consist of two producing
concessions and two exploration concessions. The Company has a 70 percent
working interest in the producing Block 17 concession and a 75 percent working
interest in the producing Block 14 concession. The Company also has a 100
percent interest in both the Shiripuno and Block 19 exploration concessions.
The Company currently operates 8 gross (6 net) productive wells with current
gross daily production of 5,800 Bbls of oil (3,740 Bbls net). These concessions
comprised 10 percent of the Company's December 31, 1999, total proved reserves.
During the fourth quarter of 1999, the production facilities were upgraded to
increase the oil handling capacity from 3,500 Bbls of oil per day to
approximately 10,000 Bbls of oil per day, commensurate with the Block 14 and
Block 17 development plans approved during December 1998, by the Ecuadorian
government. During the last half of 1999, high-capacity artificial lift
equipment was installed on two of the producing wells to increase the combined
productive capacity of the Block 14 and Block 17 concessions from 3,500 Bbls of
oil per day to 5,800 Bbls of oil per day. Additional infill drilling on Block
14 and Block 17 will be dependent on the timing of the Ecuadorian government's
approval and the construction of an additional pipeline for transportation of
oil.
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 1999, these fuel oil indexes have
increased in conjunction with the current higher oil price environment. In
Argentina, the Company's average gas price is primarily determined by the
realized price of oil from the El Huemul concession.
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 S.A.P.A., ARCO, ENAP and Shell
C.A.P.S.A. at West Texas Intermediate spot prices less a specified differential.
The Company's Ecuador Block 14 oil production is sold to various third party
purchasers at West Texas Intermediate spot prices less a specified differential.
The Company's Ecuador Block 17 oil production is delivered under a risk-service
contract to Petroecuador and revenue is received based on the average price of
oil sales realized by Petroecuador during each month. During 1999, approximately
14 percent and 11 percent of the Company's normal operating revenues related to
oil sales to Esso S.A.P.A. and Shell C.A.P.S.A., respectively.
12
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 1999, the Company entered
into various oil hedges (swap agreements) covering 1.8 MMBbls at a weighted
average price of $22.43 per Bbl (NYMEX reference price) for the calendar year
2000. During the first quarter of 2000, the Company entered into additional oil
hedging contracts through December 31, 2000, covering an additional 3.6 MMBbls
of oil at a weighted average NYMEX reference price of $25.77 per Bbl. The
Company continues to monitor oil and gas prices and may enter into additional
oil and gas hedges or swaps in the future. The following table reflects the
Bbls hedged and the corresponding weighted average NYMEX reference prices by
quarter:
NYMEX
Bbls Reference Price
Quarter Ending (In Thousands) Per Bbl
-------------------- ---------------- -----------------
March 31, 2000 1,310 $27.49
June 30, 2000 1,365 25.19
September 30, 2000 1,380 23.61
December 31, 2000 1,380 22.44
Gathering Systems and Plant
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 17 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 325 miles of varying diameter
pipe with a combined capacity in excess of 190 MMcf of gas per day. At December
31, 1999, there were 71 wells (49 wells (69 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.
As part of the Nuevo Acquisition, the Company obtained ownership and
operatorship of the Santa Clara Valley Gas Plant located in Ventura county,
California. The plant is a 1980-vintage Randall skid-mounted cryogenic expander
plant designed for 17,000 Mcf per day of inlet gas and is complete with inlet
gas compression, mole sieve dehydration facilities, propane refrigeration, NGL
product storage and truck loading. There are two inlet gas systems feeding the
compressor units, one is a 30 pound system and the other is an 80 pound system.
Sales line pressure is at 220 pounds and that pressure is obtained from the
process with a turbo-expander compressor.
The plant is currently processing about 10,000 Mcf of gas per day and
producing about 24,000 gallons per day of products (butane/propane). The
products are trucked from the plant for sale and the approximate split is 30
percent gasoline and 70 percent butane/propane mix. Gas is purchased from
various third parties, as well as the Company, primarily as wet gas purchase
agreements.
13
Reserves
At December 31, 1999, the Company had proved reserves of 468.0 MMBOE,
comprised of 303.2 MMBbls of oil and 989.0 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, 1999, 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):
[Enlarge/Download Table]
Proved Reserves:
Future net revenues...................................................................... $5,267,960
Present value of future net revenues before income taxes, discounted at 10 percent....... 2,989,626
Standardized measure of discounted future net cash flows................................. 2,247,237
Proved Developed Reserves:
Future net revenues...................................................................... $3,500,578
Present value of future net revenues before income taxes, discounted at 10 percent....... 2,117,259
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, 1999, economic
conditions. The estimated future production is priced at prices prevailing at
December 31, 1999. The resulting estimated future gross revenues are reduced by
estimated future costs to develop and produce the proved reserves and
abandonment costs, based on December 31, 1999, 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.
14
Productive Wells; Developed Acreage
The following table sets forth the Company's productive wells and developed
acreage assignable to such wells at December 31, 1999:
[Enlarge/Download Table]
Productive Wells
-------------------------------------------------
Developed Acreage Oil Gas Total
---------------------- -------------- ------------- --------------
Gross Net Gross Net Gross Net Gross Net
--------- --------- ----- ----- ----- --- ----- -----
U.S.......... 667,855 429,152 2,596 2,263 909 449 3,505 2,712
Argentina.... 1,158,339 994,372 1,057 1,040 - - 1,057 1,040
Bolivia...... 99,458 88,339 - - 16 15 16 15
Ecuador...... 33,623 24,889 8 6 - - 8 6
--------- --------- ----- ----- ---- --- ----- -----
Total...... 1,959,275 1,536,752 3,661 3,309 925 464 4,586 3,773
========= ========= ===== ===== ==== === ===== =====
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, 1999, 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, 174,690 gross (48,477 net) acres are
held under leases with primary terms that expire at varying dates through
December 31, 2003, unless commercial production is commenced. The Bolivia,
Ecuador and Yemen acreage are held under concessions with primary terms that
expire at varying dates in 2000 and 2002. 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................... 9,505 9,082
Colorado..................... 1,248 468
Kansas....................... 480 239
Louisiana.................... 52 52
Montana...................... 1,036 149
New Mexico................... 160 40
Oklahoma..................... 49,936 24,182
Texas........................ 113,523 16,785
Wyoming...................... 10,239 3,618
--------- ---------
Total U.S.............. 186,179 54,615
Bolivia...................... 485,552 485,552
Ecuador...................... 1,276,254 1,073,693
Yemen........................ 1,108,019 831,014
--------- ---------
Total Company.......... 3,056,004 2,444,874
========= =========
15
Production; Unit Prices; Costs
The following table sets forth information with respect to production and
average unit prices and costs for the periods indicated:
[Download Table]
Years Ended December 31,
------------------------------
Production: 1999 1998 1997
------- ------- -------
Oil (MBbls) -
U.S. ................. 8,643 9,912 9,692
Argentina............. 7,560 6,322 5,630
Ecuador............... 597 78 -
Bolivia............... 77 122 135
Total............. 16,877 16,434 15,457
Gas (MMcf) -
U.S. ................. 39,150 42,176 36,623
Argentina............. 4,682 - -
Bolivia............... 4,522 5,062 6,068
Total............. 48,354 47,238 42,691
Total MBOE................ 24,936 24,307 22,573
Average Sales Prices:
Oil (Per Bbl) -
U.S. ................. $ 15.92(a) $ 11.20 $ 17.23
Argentina............. 17.48 10.41 16.67(b)
Ecuador............... 15.67 5.77 -
Bolivia............... 17.03 11.31 16.52
Total............. 16.62(a) 10.87 17.02(b)
Gas (Per Mcf) -
U.S. ................. $ 2.06 $ 1.97 $ 2.31
Argentina............. 1.34 - -
Bolivia............... .71 .78 1.10
Total............. 1.87 1.85 2.14
Production Costs (Per BOE):
U.S....................... $ 5.31 $ 5.57 $ 5.64
Argentina................. 3.82 4.23 4.29
Bolivia................... 2.12 1.47 1.00
Ecuador................... 2.20 3.00 -
Total................. 4.63 5.05 5.07
____________________
(a) Reflects the impact of oil hedges which reduced the Company's 1999
U.S. and total average oil prices per Bbl by 11 cents and six cents,
respectively.
(b) 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.
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.
16
Drilling Activity
During the periods indicated, the Company drilled or participated in the
drilling of the following exploratory and development wells:
[Download Table]
Years Ended December 31,
-----------------------------------------
1999 1998 1997
------------ ------------- ------------
Gross Net Gross Net Gross Net
----- ----- ----- ------ ----- -----
Development:
United States -
Productive........ 6 1.94 34 24.94 30 15.74
Non-Productive.... - - 4 1.78 3 0.80
Argentina -
Productive........ 10 10.00 54 54.00 55 55.00
Non-Productive.... 1 1.00 2 2.00 2 2.00
Bolivia -
Productive........ 1 1.00 - - - -
Non-Productive.... - - - - - -
----- ----- ----- ------ ----- -----
Total........... 18 13.94 94 82.72 90 73.54
===== ===== ===== ====== ===== =====
Exploratory:
United States -
Productive........ 1 0.47 22 15.17 7 3.01
Non-Productive.... 11 5.56 13 3.78 6 2.87
Argentina -
Productive........ - - 2 2.00 - -
Non-Productive.... - - - - 1 1.00
Bolivia -
Productive........ 7 7.00 1 1.00 - -
Non-Productive.... - - - - 1 0.42
----- ----- ----- ------ ----- -----
Total........... 19 13.03 38 21.95 15 7.30
===== ===== ===== ====== ===== =====
Total:
Productive............ 25 20.41 113 97.11 92 73.75
Non-Productive........ 12 6.56 19 7.56 13 7.09
----- ----- ----- ------ ----- -----
Total............. 37 26.97 132 104.67 105 80.84
===== ===== ===== ====== ===== =====
The above well information excludes wells in which the Company has only a
royalty interest.
At December 31, 1999, the Company was a participant in the drilling or
completion of 13 gross (9.25 net) wells. All of the Company's drilling
activities are conducted with independent contractors. The Company owns no
drilling equipment.
17
Seasonality
The results of operations of the Company are somewhat seasonal due to
seasonal fluctuations in the price for gas. Gas prices have been generally
higher in the fourth and first quarters. Due to these seasonal fluctuations,
results of operations for individual quarterly periods may not be indicative of
results which may be realized on an annual basis.
Competition
Competition in the oil and gas industry is intense. Both in seeking to
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. Alternative fuel
sources, including heating oil and other fossil fuels, also present competition.
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.
18
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").
The Natural Gas Wellhead Decontrol Act of 1989 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.
19
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. Some of the individual pipeline company restructurings
are still the subject of appeals and resulting remand proceedings concerning
certain issues. 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, Ecuador and Yemen 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 continued market 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
175 full time employees are responsible for the supervision and operation of its
U.S. field activities. The Company also has approximately 250 employees for the
management and operation of its properties in Argentina, Bolivia, Ecuador and
Yemen. The Company believes its relations with its employees are excellent.
20
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 $5.2 million of the current
$21.4 million claim. The Company has no indemnification from its predecessors
in title with respect to the payment of royalties on the other two concessions.
The Company expects the outcome of this litigation to be decided during 2000 and
although the Company cannot predict the outcome, 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, results of operations, or total
proved reserves.
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, 1999.
21
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.
[Enlarge/Download Table]
Name Age Position
-------------------------------- --- ---------------------------------------------------------------
Charles C. Stephenson, Jr....... 63 Director and Chairman of the Board of Directors
S. Craig George................. 47 Director, President and Chief Executive Officer
William L. Abernathy............ 48 Director, Executive Vice President and Chief Operating Officer
William C. Barnes............... 45 Director, Executive Vice President, Chief Financial Officer,
Secretary and Treasurer
William E. Dozier............... 47 Senior Vice President - Operations
Robert W. Cox................... 54 Vice President - General Counsel
Andy R. Lowe.................... 48 Vice President - Marketing
Michael F. Meimerstorf.......... 43 Vice President and Controller
Robert E. Phaneuf............... 53 Vice President - Corporate Development
Larry W. Sheppard............... 45 Vice President - International
Martin L. Thalken............... 39 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 40 years of oil and gas experience.
Mr. George has been a Director since October 1991, President of the Company
since September 1995 and Chief Executive Officer of the Company since December
1997. He was also Chief Operating Officer of the Company from March 1994 to
December 1997, an Executive Vice President of the Company from March 1994 to
September 1995 and a Senior Vice President of the Company from October 1991 to
March 1994. From April 1991 to October 1991, Mr. George was Vice President of
Operations and International with Santa Fe Minerals, Inc., an independent oil
and gas company ("Santa Fe Minerals"). From May 1981 to March 1991, he served
in various other management and executive capacities with Santa Fe Minerals and
its subsidiary, Andover. From December 1974 to April 1981, Mr. George held
various management and engineering positions with Amoco Production Company. He
has a B.S. Degree in Mechanical Engineering from the University of Missouri-
Rolla.
Mr. Abernathy has been a Director since October 1999, and 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.
22
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.
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.
23
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.
24
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:
Dividend
High Low Paid
-------- --------- ---------
1999
----
First Quarter........ $10 1/16 $ 4 1/16 $.025
Second Quarter....... 12 1/4 8 1/8 -
Third Quarter........ 15 1/8 10 1/8 -
Fourth Quarter....... 13 3/4 9 1/16 -
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
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, 1999, the common stock was held by 112 holders of record and
approximately 9,000 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 historically low oil and gas price
environment during the first quarter of 1999, the Company suspended its regular
quarterly cash dividend for the remainder of 1999. The Company re-instituted
the payment of dividends beginning in the first quarter of 2000 with a $.025 per
share cash dividend paid on February 3, 2000, to stockholders of record on
January 25, 2000. 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 such payments would reduce Net Worth
(as defined in the Company's revolving credit facility) below the sum of $238.6
million plus 75 percent of net proceeds of any future equity offerings. Net
Worth was approximately $419.4 million at December 31, 1999.
25
Item 6. Selected Financial Data.
SELECTED FINANCIAL AND OPERATING DATA
[Enlarge/Download Table]
Years Ended December 31,
------------------------------------------------------------
1999 1998 1997 1996 1995
---------- ---------- --------- --------- ---------
(In thousands, except per share amounts and operating data)
Income Statement Data:
Oil and gas sales........................................ $ 370,731 $ 265,863 $ 354,490 $ 258,368 $160,254
Gas marketing revenues................................... 60,275 54,108 45,981 31,920 20,912
Gathering revenues....................................... 6,955 7,741 18,063 20,508 12,380
Total revenues........................................... 496,735 328,935 416,590 312,147 195,215
Operating expenses....................................... 178,174 180,544 172,676 138,438 95,121
Exploration costs........................................ 14,674 24,056 12,667 10,192 3,834
Impairment of oil and gas properties..................... 3,306 70,913 8,785 - -
Depreciation, depletion and amortization................. 107,807 108,975 96,307 66,861 48,336
Interest................................................. 58,665 43,680 36,762 30,109 20,178
Net income (loss)........................................ 73,371 (87,665) 54,954 33,188 9,449
Earnings (loss) per share:
Basic................................................. 1.27 (1.69) 1.07 .69 .23
Diluted............................................... 1.24 (1.69) 1.05 .68 .22
Dividends declared per share............................. - .09 .07 .055 .045
---------- ---------- ---------- ---------- ---------
Balance Sheet Data (end of year):
Total assets............................................. $1,168,134 $1,014,175 $ 915,394 $ 766,816 $613,397
Long-term debt, less current portion..................... 625,318 672,507 451,096 372,390 315,846
Stockholders' equity..................................... 431,129 273,958 337,578 236,406 203,265
---------- ---------- ---------- ---------- ---------
Operating Data:
Production:
Oil (MBbls).............................................. 16,877 16,434 15,457 11,939 7,608
Gas (MMcf)............................................... 48,354 47,238 42,691 32,366 30,610
---------- ---------- ---------- ---------- ---------
Average Sales Prices:
Oil (per Bbl)............................................ $ 16.62 $ 10.87 $ 17.02 $ 16.73 $ 15.26
Gas (per Mcf)............................................ 1.87 1.85 2.14 1.81 1.46
---------- ---------- ---------- ---------- ---------
Proved Reserves (end of year):
Oil (MBbls).............................................. 303,190 164,457 187,768 178,296 147,871
Gas (MMcf)............................................... 988,989 806,833 552,163 382,846 310,762
Total proved reserves (MBOE)............................. 468,022 298,929 279,795 242,104 199,665
---------- ---------- ---------- ---------- ---------
Present value of estimated future net revenues
before income taxes discounted at 10 percent
(in thousands):
Oil and gas properties............................. $2,989,626 $ 703,211 $1,222,560 $1,807,137 $ 894,249
Gathering systems and plant........................ 13,764 4,493 5,940 10,364 10,641
Standardized measure of discounted future
net cash flows (in thousands)......................... 2,247,237 648,222 1,016,645 1,392,841 736,546
---------- ---------- ---------- ---------- ---------
Significant acquisitions of producing oil and gas properties during 1999,
1997 and 1995 and significant dispositions of oil and gas properties during 1999
affect the comparability between the Financial and Operating Data for the years
presented above.
26
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
Results of Operations
The Company's results of operations have been significantly affected by its
success in acquiring oil and gas properties and its ability to maintain or
increase production through its exploitation and exploration activities.
Fluctuations in oil and gas prices have also significantly affected the
Company's results. The following table reflects the Company's oil and gas
production and its average oil and gas prices for the periods presented:
[Download Table]
Years Ended December 31,
------------------------------
1999 1998 1997
--------- -------- ---------
Production:
Oil (MBbls) -
U.S............................... 8,643 9,912 9,692
Argentina......................... 7,560 6,322 5,630
Ecuador........................... 597 78 -
Bolivia........................... 77 122 135
Total........................... 16,877 16,434 15,457
Gas (MMcf) -
U.S............................... 39,150 42,176 36,623
Argentina......................... 4,682 - -
Bolivia........................... 4,522 5,062 6,068
Total........................... 48,354 47,238 42,691
Total MBOE............................ 24,936 24,307 22,573
Average Sales Prices:
Oil (per Bbl) -
U.S............................... $ 15.92 $ 11.20 $ 17.23
Argentina......................... 17.48 10.41 16.67
Ecuador........................... 15.67 5.77 -
Bolivia........................... 17.03 11.31 16.52
Total........................... 16.62 10.87 17.02
Gas (per Mcf) -
U.S............................... $ 2.06 $ 1.97 $ 2.31
Argentina......................... 1.34 - -
Bolivia........................... .71 .78 1.10
Total........................... 1.87 1.85 2.14
Average U.S. oil prices received by the Company fluctuate generally with
changes in the NYMEX reference price for oil. The Company's Argentina oil
production is sold at West Texas Intermediate spot prices as quoted on the
Platt's Crude Oil Marketwire (approximately equal to the NYMEX reference price)
less a specified differential. The Company experienced a 53 percent increase in
its average oil price in 1999 compared to 1998 as a result of OPEC's efforts to
reduce the available supply of crude oil in the global markets. The Company
participated in oil hedges covering 1.84 MMBbls during 1999. The impact of these
hedges reduced the Company's U.S. average oil price by 11 cents to $15.92 per
Bbl and its overall average oil price by six cents to $16.62 per Bbl. 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.
27
The Company's realized average oil price for 1999 (before hedges) was
approximately 87 percent of the NYMEX reference price in 1999 compared to 75
percent in 1998 and 84 percent in 1997.
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
the last half of 1999, these fuel oil indexes increased in conjunction with the
current higher oil price environment. In Argentina, the Company's average gas
price is primarily determined by the realized price of oil from the El Huemul
concession. The Company's total average gas price for 1999 was one percent
higher than 1998's. The Company's average gas price for 1998 was 14 percent
lower than 1997's.
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 1999, the Company entered
into various oil hedges (swap agreements) for a total of 1.8 MMBbls of oil at a
weighted average price of $22.43 per Bbl (NYMEX reference price) for calendar
year 2000. During the first quarter of 2000, the Company entered into additional
oil hedging contracts through December 31, 2000, covering an additional 3.6
MMBbls of oil and a weighted average NYMEX reference price of $25.77 per Bbl.
For additional information, see "Business and Properties - Marketing" included
elsewhere in this Form 10-K. The Company continues to monitor oil and gas
prices and may enter into additional oil and gas hedges or swaps in the future.
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 1999 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
$15.6 million and $22.8 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
$3.0 million and $4.7 million, respectively, based on 1999 gas production.
Period to Period Comparison
Year Ended December 31, 1999, Compared to Year Ended December 31, 1998
The Company reported net income of $73.4 million for the year ended
December 31, 1999, compared to a net loss of $87.7 million for the same period
in 1998. A 53 percent increase in average oil prices received by the Company
was primarily responsible for the significant increase in its net income. The
Company also recorded after-tax gains on property sales of $33.6 million in
1999. The Company's net loss recorded in 1998 was primarily the result of
historically low oil prices which greatly reduced revenues and led to an oil and
gas property impairment of $70.9 million ($43.2 million net of tax).
Oil and gas sales increased $104.8 million (39 percent), to $370.7 million
for 1999 from $265.9 million for 1998. A 53 percent increase in average oil
prices combined with a three percent increase in oil production, accounted for
an increase of $101.7 million. A one percent increase in average gas prices,
coupled with a two percent increase in gas production, accounted for an
additional increase of $3.1 million. The Company experienced a three percent
increase in oil production primarily as a result of Argentina production added
through the El Huemul Acquisition which offset the decline in the Company's U.S.
oil production primarily due to the shutting in of certain high cost properties
during the first half of 1999 as a result of historically low oil prices. The
Company's gas production rose by two percent due to the gas production
attributable to the El Huemul concession acquired in July 1999 which more than
offset the decrease in U.S. gas production resulting from the natural decline in
the Galveston Bay field and the decrease in Bolivia production due to the
limited gas demand from the developing export market in Brazil.
28
Gains on disposition of assets of $55.0 million ($33.6 million net of
income taxes) were reflected in 1999 as a result of $87.9 million in proceeds
from various oil and gas property divestitures in the United States. Other than
the $55.0 million in gains reported, the divestitures did not have a significant
impact on the Company's results of operations as the majority of the
divestitures occurred during December 1999. The Company also does not expect a
significant impact on its continuing operations due to these divestitures as
interest savings from the reduction in debt are expected to generally offset any
future reduction in earnings.
Lease operating expenses, including production taxes, decreased $7.2
million (6 percent), to $115.5 million for 1999 from $122.7 million for 1998.
The decrease in lease operating expenses, despite the three percent increase in
production, is due primarily to actions taken by the Company to reduce costs
including shutting in certain high cost properties, rebidding field service and
product contracts and the reorganization of certain field operations. Lease
operating expenses per equivalent barrel produced decreased to $4.63 in 1999
from $5.05 for the same period in 1998.
Exploration costs decreased $9.4 million (39 percent), to $14.7 million for
1999 from $24.1 million for 1998. 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, and $5.4 million for lease impairments and other geological and
geophysical costs. Due to reduced cash flow levels, the Company significantly
reduced its capital budget for 1999. As a result, exploration expenses for 1999
consisted of only $5.3 million for seismic data acquisition, $4.4 million for
unsuccessful exploratory drilling and $5.0 million for lease impairments and
other geological and geophysical costs.
Impairments of oil and gas properties of $3.3 million were recognized in
1999, compared to $70.9 million of impairments in 1998, which resulted primarily
from the decline in oil prices which took place in the last quarter of 1998.
The impairments recorded in 1999 were primarily as a result of mechanical
failures which were uneconomic to repair and unsuccessful development projects
on various fields in the United States. 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 or unsuccessful
development projects) 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 that the current oil price environment would
return to more historical levels over a short period of time and thereafter
escalate annually. The Company assumed gas prices and operating costs would
escalate annually beginning at current levels. 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.
General and administrative expenses increased $4.4 million (14 percent), to
$36.4 million for 1999 from $32.0 million for 1998, due primarily to the accrual
of 1999 employee incentive bonuses and approximately $1.0 million in costs
associated with the Company's efforts to prepare for Y2K. The Company
implemented a bonus program effective for 1999 covering all U.S. employees
designed to provide additional incentive to achieve certain corporate goals.
The Company's G&A per BOE for 1999 was $1.46 ($1.34 before the 1999 bonus
accrual) compared to $1.32 for 1998.
Depreciation, depletion and amortization decreased $1.2 million (1
percent), to $107.8 million for 1999 from $109.0 million for 1998, despite the
three percent increase in total production due primarily to a lower DD&A rate
per equivalent barrel for 1999 versus 1998. The Company's average DD&A rate per
equivalent barrel produced decreased from $4.32 in 1998 to $4.15 in 1999
primarily as a result of the impact of the new production from the Company's El
Huemul concession which has a substantially lower amortization rate and the
effect of the U.S. impairments in 1998.
29
Interest expense increased $15.0 million (34 percent), to $58.7 million for
1999 from $43.7 million for 1998, due primarily to a 25 percent increase in the
Company's total average outstanding debt as a result of the Company's 1998 total
capital spending, including acquisitions, exceeding 1998's cash flow and an
increase in its average interest rate on its outstanding debt. The Company's
average interest rate for its outstanding debt for 1999 was 8.14 percent
compared to 7.72 percent in 1998.
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 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 $88.6 million (25 percent), to $265.9 million
for 1998 from $354.5 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 $4.2 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.
30
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.
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 percent in 1997 to 7.72 percent in 1998.
Capital Expenditures
During 1999, the Company's total oil and gas capital expenditures were
$237.5 million. Domestically, the Company's oil and gas capital expenditures
totaled $51.6 million. Exploration activities accounted for $10.8 million of
the domestic capital expenditures with exploitation activities contributing $9.1
million. The Company also had domestic capital expenditures in 1999 of $31.7
million for acquisitions of producing oil and gas properties, the largest of
which was the $29.6 million acquisition from Nuevo Energy Company in December.
During 1999, the Company's international oil and gas capital expenditures
excluding acquisitions totaled $50.8 million, consisting of $10.5 million in
Argentina on exploitation activities, $30.8 million in Bolivia on exploitation
and exploration activities, and $9.5 million in Yemen and Ecuador.
International acquisition capital expenditures for 1999 included $121.0 million
for the acquisition of the El Huemul concession in Argentina and $14.1 million
for additional interests in the Company's Ecuador concessions.
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. Through December 31, 1999, the Company has completed a
total of 8,977 work units through capital expenditures in 1998 and 1999 of $7.6
million and $24.1 million, respectively. The total remaining work unit
commitment is guaranteed by the Company through a $56.4 million letter of
credit; however, the Company anticipates that it will fulfill the remaining work
unit commitment through approximately $35 to $40 million of various drilling
capital expenditures. The Company has budgeted to spend $37 million in 2000 to
complete 8,751 work units, fulfilling its Naranjillos field commitment.
31
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. During
July 1999, the Company also committed to perform an additional 1,068 work units
in its Chaco field location in Bolivia over the next two years. This work
commitment is secured by a $5.3 million letter of credit. 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.
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. Through 1999, approximately $2 million of the $11 million
commitment has been spent. To fulfill its commitment, the Company has budgeted
to spend approximately $9 million in 2000 on the drilling of three wells.
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 to fund capital
expenditures other than significant acquisitions. Of the Company's 1999 non-
acquisition capital expenditures of $71.4 million, approximately 34 percent was
spent on exploitation activities, including development and infill drilling, and
approximately 65 percent was spent on exploration activities. The Company's
preliminary capital expenditure budget for 2000 is currently set at $146
million, exclusive of acquisitions. 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:
[Enlarge/Download Table]
Years Ended December 31,
--------------------------------
(In thousands) 1999 1998 1997
-------- -------- --------
Acquisition of oil and gas reserves..................... $166,787 $105,023 $139,749
Drilling................................................ 46,280 114,773 71,069
Acquisition of undeveloped acreage and seismic.......... 12,742 35,024 10,349
Workovers and recompletions............................. 10,749 29,939 32,856
Acquisition and construction of gathering systems....... 680 1,831 1,209
Other................................................... 927 1,601 4,638
-------- -------- --------
Total................................................ $238,165 $288,191 $259,870
======== ======== ========
32
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. Prior
to 1999 in conjunction with the purchase of substantial oil and gas assets, the
Company completed four public equity offerings as well as two public debt
offerings, which provided the Company with aggregate net proceeds of $415
million.
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.
On June 21, 1999, the Company completed a public offering of 9,000,000
shares of common stock, all of which were sold by the Company. Net proceeds of
approximately $81.2 million were used to partially fund the purchase of the El
Huemul concession from Total and Repsol in early July 1999. Also in July 1999,
in connection with the exercise by the underwriters of a portion of the over-
allotment option, the Company sold an additional 240,800 shares of common stock
using the additional $2.1 million of net proceeds to reduce a portion of the
Company's existing indebtedness under its 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 $545 million) determined by the banks' evaluation of the
Company's oil and gas reserves. The amount available to be borrowed under the
Bank Facility is limited to the lesser of the borrowing base or the facility
size, which is currently set at $535 million. The Company may increase the
facility size up to $625 million without further approvals from the existing
bank group if additional banks agree to join the group.
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 29, 2000, 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 seven
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 29, 2000, the unused portion of the Bank Facility was
approximately $363 million. 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.
33
The Company's internally generated cash flow, results of operations and
financing for its operations are dependent on oil and gas prices. For 1999,
approximately 68 percent of the Company's production was oil. Realized oil
prices for the year increased by 53 percent as compared to 1998 and total
production on a BOE basis increased by three percent. As a result, the
Company's earnings and cash flows have been materially increased compared to
1998. To the extent oil prices decline, the Company's earnings and cash flow
from operations may be adversely impacted. However, 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.
Inflation
In recent years inflation has not had a significant impact on the Company's
operations or financial condition.
Income Taxes
The Company incurred a current provision for income taxes of approximately
$6.0 million for 1999 and realized a current benefit of $4.1 million for 1998.
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.
During 1999, as a result of significantly improved oil prices, the Company
generated Argentina taxable income in excess of its $44.9 million of net
operating loss ("NOL") carryforwards, thereby utilizing all of the carryforwards
to offset 1999 taxable income. Included in the $44.9 million of carryforwards
are $16.2 million which had a valuation allowance recorded against them in 1998
and $14.4 million of NOL's that were acquired, but not recorded due to
provisions under SFAS No. 109. The utilization of these NOL's was benefitted in
the Company's 1999 tax provision, thereby reducing the tax provision and
increasing net income by approximately $10.7 million.
The Company has a U.S. Federal alternative minimum tax ("AMT") credit
carryforward of approximately $5.2 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 also has an estimated U.S. Federal NOL carryforward for
regular tax purposes at December 31, 1999, of approximately $49.4 million which
will expire in 2018 if not previously utilized.
Foreign Operations
For information on the Company's foreign operations, see "Foreign Currency
and Operations Risk" under Item 7A of this Form 10-K.
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.
34
Statement of Readiness. The Company completed various initiatives to
ensure that its hardware, software and equipment would 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 presented, and still presents,
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 formed a Year 2000 ("Y2K") Project team, which was chaired by
its Manager of Information Services. The team included corporate staff and
representatives from the Company's business units. The phases of
identification, assessment, remediation and testing made up the Y2K directive
and were all completed by the fourth quarter of 1999.
Included in the Company's Y2K Project were 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 allowed the Company to
determine the extent to which these business partners were addressing their Y2K
issues. Each returned document was examined for a response that could be
detrimental to the Company's operations. Those business partners who did not
respond and who were considered key businesses in the support of the Company's
operations were sent a second request, followed by direct correspondence, to
determine their readiness. Any material adverse responses were 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 cost of the Y2K Project was
approximately $2.3 million, excluding costs of Company employees working on the
Y2K Project. Costs incurred for the purchase of new software and hardware have
been capitalized and all other costs were expensed as incurred. Approximately
$1.0 million of third party consultant fees related to the Y2K Project were
recorded as part of the Company's 1999 general and administrative expenses.
Y2K Worst-Case Scenario. The Company's initial results from its
assessment phase of the Y2K Project was that its internal systems had fewer Y2K
compliance problems than initially anticipated. As the Company had all internal
systems within its control compliant and tested before the year 2000, it
believed its likely worst-case scenario was the possibility of operational
interruptions due to non-compliance by third parties. This non-compliance could
have caused 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 was minimized by the Company's
efforts to communicate and evaluate third party compliance.
The Company has contingency plans in the event that problems arise due to
third party non-compliance or any failures of the Company's systems. These
plans were completed during the fourth quarter of 1999 and 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. As anticipated, the Company did not experience
any material operational problems as a result of Y2K. Additionally, the Company
did not experience any material problems due to the lack of compliance by other
entities. While it is possible that the Company might still encounter problems
that may relate to Y2K issues, it does not believe they will pose a significant
operational problem or adversely impact the Company's results of operations,
liquidity or financial condition. As of March 1, 2000, the Company had
experienced no material adverse impact on the Company's operations or financial
condition as a result of Y2K issues.
35
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 1999, the Company entered into various oil hedges
(swap agreements) for a total of 1.8 MMBbls of oil at a weighted average price
of $22.43 per Bbl (NYMEX reference price) for 2000. The fair value of commodity
swap agreements is the amount at which they could be settled, based on quoted
market prices. At December 31, 1999, the Company would have received
approximately $700,000 to terminate its oil swap agreements then in place.
During the first quarter of 2000, the Company entered into additional oil
hedging contracts through December 31, 2000, covering an additional 3.6 MMBbls
of oil and a weighted average NYMEX reference price of $25.77 per Bbl. The
Company continues to monitor oil and gas prices and may enter into additional
oil and gas hedges or swaps in the future.
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, 1999, the amount of
the Company's fixed rate debt was approximately 64 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.
The following table provides information about the Company's long-term debt
principal payments and weighted average interest rates by expected maturity
dates:
[Enlarge/Download Table]
Fair
Value
There- at
2000 2001 2002 2003 2004 After Total 12/31/99
-------- -------- -------- -------- -------- -------- -------- --------
Long-Term Debt:
Fixed rate (in thousands)....... - - - - - $399,118 $399,118 $395,400
Average interest rate........... - - - - - 9.2% 9.2% -
Variable rate (in thousands).... - $ 28,275 $113,100 $ 84,825 - - $226,200 $226,200
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 1.75 percent.
Current increment above LIBOR is 0.875 percent.
36
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 1999,
the Company's operations in Argentina accounted for approximately 28 percent of
the Company's revenues, 39 percent of the Company's operating income (before
impairments of oil and gas properties) and 33 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 measured by the
Argentine Consumer Price Index declined from 200.7 percent as of June 1991 to
1.1 percent as of December 1999.
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, 1999, was
US$1:Bs 6.00. 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.
The economy of Ecuador has been uneven in recent years and has recently
reached a crisis level due in large part to the "El Nino" weather phenomenon,
the recent low oil price environment and political transition. Since 1992, the
Ecuadorian 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 Ecuadorian government has a favorable
attitude toward foreign investment and has strong international relationships
with the U.S.
37
Due to the current economic crisis, the sucre (Ecuador's monetary unit)
exchange rate against the US dollar increased from approximately 7,000:1 in
January 1999 to almost 21,000:1 in December 1999. During the same period,
inflation reached nearly 61 percent. The exchange rate has deteriorated further
during 2000 reaching 25,000:1 during February and inflation for the year has
reached 25 percent. The crisis has resulted in President Jamil Mahaud being
replaced by Gustavo Naboa during a peaceful coup de etat carried out on January
21, 2000. The new government, following proposals made by President Mahaud, has
adopted a plan to dollarize the sucre at 25,000:1 and the plan is currently in
the congressional approval process. Dollarization is expected to be implemented
and speculation against the sucre has been temporarily halted. 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 reduce its exposure to currency risk
related to the sucre including maintaining essentially all of its cash in US
dollar accounts primarily in U.S. bank accounts. At the present time,
approximately 90 percent of the Company's revenues in Ecuador are US dollar
based.
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 2000 Annual Meeting of Stockholders (the
"Proxy Statement") entitled "Election of Directors" and "Section 16(a)
Beneficial Ownership Reporting Compliance." The information required by this
Item with respect to the Company's executive officers appears at Item 4A of Part
I of this Form 10-K.
Item 11. Executive Compensation.
The information required by this Item is incorporated by reference from the
section of the Proxy Statement entitled "Executive Compensation."
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information required by this Item is incorporated by reference from the
section of the Proxy Statement entitled "Principal Stockholders and Security
Ownership of Management."
Item 13. Certain Relationships and Related Transactions.
The information required by this Item is incorporated by reference from the
section of the Proxy Statement entitled "Certain Transactions."
38
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 (Filed as Exhibit
4.4 to the Company's report on Form 10-K for the year ended
December 31, 1998, filed March 12, 1999 (the "1998 Form 10-
K")).
4.5 Rights Agreement, dated March 16, 1999, between the Company and
ChaseMellon Shareholder Services, L.L.C., as Rights Agent
(Filed as Exhibit 4.1 to the Company's Registration Statement
on Form 8-A, filed March 22, 1999).
4.6 Certificate of Designation of Series A Junior Participating
Preferred Stock of the Company (Filed as Exhibit 3.3 to the
Company's Registration Statement on Form S-3, Registration No.
333-77619).
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).
39
10.2* 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).
10.3* 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).
10.4* 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).
10.5* 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).
10.6* 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).
10.7* 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).
10.8* Amendment No. 5 to Vintage Petroleum, Inc. 1990 Stock Plan dated
March 16, 1999 (Filed as Exhibit A to the Company's Proxy Statement
for Annual Meeting of Stockholders dated March 31, 1999).
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* Form of Non-Qualified Stock Option Agreement for non-employee
directors under the Vintage Petroleum, Inc. 1990 Stock Plan.
10.14 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, NationsBank, 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 November 13, 1998).
10.15 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 (Filed as Exhibit 10.14 to the 1998 Form 10-K).
40
10.16 Second Amendment to the Amended and Restated Credit Agreement dated
as of May 19, 1999, among the Company, as borrower, and certain
commercial lending institutions, as lenders, Bank of Montreal, as
administrative agent, NationsBank, N.A., as syndication agent, and
Societe Generale Southwest Agency, as documentation agent (Filed as
Exhibit 10.1 to the Company's report on Form 10-Q for the quarter
ended June 30, 1999, filed August 12, 1999).
10.17 Third Amendment to the Amended and Restated Credit Agreement dated
as of November 18, 1999, among the Company, as borrower, and certain
commercial lending institutions, as lenders, Bank of Montreal, as
administrative agent, Bank of America, N.A., successor-in-interest
by merger to NationsBank, 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.
(b) Reports on Form 8-K.
Form 8-K dated November 16, 1999, was filed November 16, 1999, to report
under Item 5 the Company's press release dated November 16, 1999,
announcing an increase in its borrowing base related to its unsecured
revolving credit facility.
No other reports on Form 8-K were filed during the fourth quarter of the
fiscal year ended December 31, 1999.
41
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 13, 2000 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:
[Download Table]
Signature Title Date
--------- ----- ----
/s/ C. C. Stephenson, Jr. Director and Chairman of the Board March 13, 2000
----------------------------
C. C. Stephenson, Jr.
/s/ S. Craig George Director, President and March 13, 2000
----------------------------
S. Craig George Chief Executive Officer
(Principal Executive Officer)
/s/ William L. Abernathy Director, Executive Vice President, March 13, 2000
----------------------------
William L. Abernathy Chief Operating Officer
/s/ William C. Barnes Director, Executive Vice President, March 13, 2000
----------------------------
William C. Barnes Chief Financial Officer and
Treasurer (Principal Financial Officer)
/s/ Bryan H. Lawrence Director March 13, 2000
----------------------------
Bryan H. Lawrence
/s/ John T. McNabb, II Director March 13, 2000
----------------------------
John T. McNabb, II
/s/ Michael F. Meimerstorf Vice President and Controller March 13, 2000
----------------------------
Michael F. Meimerstorf (Principal Accounting Officer)
42
INDEX TO FINANCIAL STATEMENTS
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
[Enlarge/Download Table]
Page
----
AUDITED FINANCIAL STATEMENTS OF VINTAGE PETROLEUM, INC. AND SUBSIDIARIES:
Report of Independent Public Accountants......................................................... 44
Consolidated Balance Sheets as of December 31, 1999 and 1998..................................... 45
Consolidated Statements of Income (Loss) for the years ended December 31, 1999, 1998 and 1997.... 46
Consolidated Statements of Changes in Stockholders' Equity for the years ended
December 31, 1999, 1998 and 1997............................................................. 47
Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997....... 48
Notes to Consolidated Financial Statements for the years ended December 31, 1999, 1998 and 1997.. 49
43
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,
1999 and 1998, 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, 1999. 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 auditing standards generally
accepted in the United States. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 21, 2000
44
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except shares
and per share amounts)
[Enlarge/Download Table]
ASSETS
December 31,
----------------------
1999 1998
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents......................................... $ 42,687 $ 5,245
Accounts receivable -
Oil and gas sales............................................... 87,484 54,680
Joint operations................................................ 5,211 5,905
Prepaids and other current assets................................. 19,109 18,312
---------- ----------
Total current assets............................................ 154,491 84,142
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method................. 1,521,672 1,368,914
Oil and gas gathering systems..................................... 15,453 14,774
Other............................................................. 17,287 16,276
---------- ----------
1,554,412 1,399,964
Less accumulated depreciation, depletion and amortization......... 583,060 501,722
---------- ----------
971,352 898,242
---------- ----------
OTHER ASSETS, net.................................................... 42,291 31,791
---------- ----------
$1,168,134 $1,014,175
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Revenue payable................................................... $ 25,899 $ 17,382
Accounts payable - trade.......................................... 26,118 24,812
Other payables and accrued liabilities............................ 41,885 24,731
---------- ----------
Total current liabilities.................................... 93,902 66,925
---------- ----------
LONG-TERM DEBT....................................................... 625,318 672,507
---------- ----------
DEFERRED INCOME TAXES................................................ 15,780 -
---------- ----------
OTHER LONG-TERM LIABILITIES.......................................... 2,005 785
---------- ----------
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,
62,407,866 and 53,107,066 shares issued and outstanding....... 312 266
Capital in excess of par value.................................... 314,490 230,736
Retained earnings................................................. 116,327 42,956
---------- ----------
431,129 273,958
---------- ----------
$1,168,134 $1,014,175
========== ==========
The accompanying notes are an integral part of these statements.
45
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(In thousands, except per share amounts)
[Enlarge/Download Table]
For the Years Ended December 31,
----------------------------------
1999 1998 1997
-------- --------- --------
REVENUES:
Oil and gas sales.................................................. $370,731 $ 265,863 $354,490
Gas marketing...................................................... 60,275 54,108 45,981
Oil and gas gathering.............................................. 6,955 7,741 18,063
Gain on disposition of assets...................................... 54,991 - -
Other income (expense)............................................. 3,783 1,223 (1,944)
-------- --------- --------
496,735 328,935 416,590
-------- --------- --------
COSTS AND EXPENSES:
Lease operating, including production taxes........................ 115,471 122,726 114,346
Exploration costs.................................................. 14,674 24,056 12,667
Impairment of oil and gas properties............................... 3,306 70,913 8,785
Gas marketing...................................................... 57,550 51,560 43,398
Oil and gas gathering.............................................. 5,153 6,258 14,932
General and administrative......................................... 36,409 31,996 27,361
Depreciation, depletion and amortization........................... 107,807 108,975 96,307
Interest........................................................... 58,665 43,680 36,762
-------- --------- --------
399,035 460,164 354,558
-------- --------- --------
Income (loss) before income taxes and minority interest......... 97,700 (131,229) 62,032
-------- --------- --------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current............................................................ 5,954 (4,068) 5,235
Deferred........................................................... 18,375 (39,496) 1,640
-------- --------- --------
24,329 (43,564) 6,875
-------- --------- --------
MINORITY INTEREST IN INCOME OF SUBSIDIARY............................ - - (203)
-------- --------- --------
NET INCOME (LOSS).................................................... $ 73,371 $ (87,665) $ 54,954
======== ========= ========
EARNINGS (LOSS) PER SHARE:
Basic.............................................................. $ 1.27 $ (1.69) $ 1.07
======== ========= ========
Diluted............................................................ $ 1.24 $ (1.69) $ 1.05
======== ========= ========
Weighted Average Common Shares Outstanding:
Basic.............................................................. 57,989 51,900 51,178
======== ========= ========
Diluted............................................................ 59,315 51,900 52,026
======== ========= ========
The accompanying notes are an integral part of these statements.
46
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(In thousands, except per share amounts)
[Enlarge/Download Table]
Capital
In Excess
Common Stock of Par Retained
--------------
Shares Amount Value Earnings Total
------ ------ -------- -------- --------
BALANCE AT DECEMBER 31, 1996.................................. 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.................................. 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
Net income............................................... - - - 73,371 73,371
Issuance of common stock................................. 9,241 46 83,284 - 83,330
Exercise of stock options and
resulting tax effects................................ 60 - 470 - 470
------ ------ -------- -------- --------
BALANCE AT DECEMBER 31, 1999.................................. 62,408 $ 312 $314,490 $116,327 $431,129
====== ====== ======== ======== ========
The accompanying notes are an integral part of these statements.
47
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
[Enlarge/Download Table]
For the Years Ended December 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................................ $ 73,371 $ (87,665) $ 54,954
Adjustments to reconcile net income (loss) to cash
provided by operating activities -
Depreciation, depletion and amortization...................... 107,807 108,975 96,307
Impairment of oil and gas properties.......................... 3,306 70,913 8,785
Exploration costs............................................. 14,674 24,056 12,667
Provision (benefit) for deferred income taxes................. 18,375 (39,496) 1,640
Gain on disposition of assets................................. (54,991) - -
Minority interest in income of subsidiary..................... - - 203
--------- --------- ---------
162,542 76,783 174,556
Decrease (increase) in receivables............................... (32,110) 9,353 5,428
U.S. income tax refund receivable................................ 5,323 (5,323) -
Increase (decrease) in payables and accrued liabilities.......... 29,500 (10,570) 7,187
Other............................................................ 3,603 (3,993) (569)
--------- --------- ---------
Cash provided by operating activities......................... 168,858 66,250 186,602
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties........................................ (237,484) (252,254) (257,275)
Gathering systems and other................................... (2,669) (9,960) (2,275)
Proceeds from sales of oil and gas properties.................... 78,241 588 360
Purchase of companies, net of cash acquired...................... - (10,651) (38,788)
Other............................................................ 634 (3,042) (2,670)
--------- --------- ---------
Cash used by investing activities............................. (161,278) (275,319) (300,648)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock............................................. 83,685 884 47,910
Sale of 9 3/4% Senior Subordinated Notes Due 2009................ 146,000 - -
Sale of 8 5/8% Senior Subordinated Notes Due 2009................ - - 96,270
Advances on revolving credit facility and other borrowings....... 50,213 232,736 192,521
Payments on revolving credit facility and other borrowings....... (248,708) (20,711) (216,335)
Dividends paid................................................... (1,328) (4,392) (3,297)
--------- --------- ---------
Cash provided by financing activities......................... 29,862 208,517 117,069
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............... 37,442 (552) 3,023
CASH AND CASH EQUIVALENTS, beginning of year....................... 5,245 5,797 2,774
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of year............................. $ 42,687 $ 5,245 $ 5,797
========= ========= =========
The accompanying notes are an integral part of these statements.
48
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 1999, 1998 and 1997
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 99 percent of the
Company's operations are within the exploration and production segment based on
1999 operating income before impairments of oil and gas properties and gains on
asset sales. 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.
The consolidated financial statements include the accounts of Vintage
Petroleum, Inc. and its wholly- and majority-owned subsidiaries and its
proportionately consolidated general partner interests in various joint ventures
(collectively, the "Company"). All significant intercompany accounts and
transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States ("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.
Certain 1998 and 1997 amounts have been reclassified to conform with
the 1999 presentation. These reclassifications have no impact on net income
(loss).
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.
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 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.
49
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 1999, the Company assumed that the current oil
price environment would return to more historical levels over a short period of
time and thereafter, escalate annually. The Company assumed gas prices and
operating costs would escalate annually beginning at current levels. 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 $3.3 million, $70.9 million and $8.8 million in
1999, 1998 and 1997, respectively.
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.
The Company participated in oil hedges covering 1.84 MMBbls during
1999. The impact of these hedges reduced the Company's U.S. average oil price by
11 cents to $15.92 per Bbl and its overall average oil price by six cents to
$16.62 per Bbl. 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.
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"). In June 1999, the FASB
issued Statement No. 137, Accounting for Derivative Instruments and Hedging
Activities- Deferral of the Effective Date of FASB Statement 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.
50
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SFAS No. 133, as amended, is effective for fiscal years beginning
after June 15, 2000; 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. 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.
However, it should be noted that the impact of SFAS No. 133 could increase
volatility in future reported earnings and other comprehensive income.
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. At December
31, 1999, the Company had approximately $40 million in escrow accounts primarily
related to potential like-kind exchange transactions. These funds were invested
in highly liquid investment funds at year end.
During the years ended December 31, 1999, 1998 and 1997, the Company
made cash payments for interest totaling $56.8 million, $42.4 million and $33.2
million, respectively. Cash payments for U.S. income taxes of $1.5 million and
$5.3 million were made for 1998 and 1997, respectively. No cash payments for
U.S. income taxes were made during 1999. Cash payments of $1.3 million were made
during 1998 for foreign tax withholdings. No cash payments were made during 1999
or 1997 for foreign income taxes.
In November 1998, the Company purchased 100 percent of the outstanding
common stock of Elf Hydrocarbures Equateur, S.A., 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.
51
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Earnings Per Share
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 1999 and 1997 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. Had the Company been in a net income position for 1998, the
Company's diluted weighted average outstanding common shares as calculated under
SFAS No. 128 would have been 54,604,530 with an additional 1,629,000 shares at
an average exercise price of $17.83 that would have been antidilutive. In
addition, for the year ended December 31, 1999, the Company had outstanding
stock options for 1,635,000 additional shares of the Company's common stock,
with an average exercise price of $17.70, which were antidilutive. The Company
had no antidilutive shares for the year ended December 31, 1997.
General and Administrative Expense
The Company receives fees for operation of jointly-owned oil and gas
properties and records such reimbursements as reductions of general and
administrative expense. Such fees totaled approximately $2.9 million, $2.7
million and $2.6 million in 1999, 1998 and 1997, respectively.
Lease Operating Expense
For the years ended December 31, 1999, 1998 and 1997, the Company
recorded gross production taxes of $7.5 million, $7.4 million and $8.9 million,
respectively, in lease operating expenses.
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.
52
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 1999, 1998 and 1997.
2. Long-Term Debt
Long-term debt at December 31, 1999 and 1998, consisted of the
following:
[Enlarge/Download Table]
(In thousands) 1999 1998
-------- --------
Revolving credit facility............................................. $226,200 $423,500
Senior subordinated notes:
9% Notes due 2005, less unamortized discount........................ 149,755 149,714
8 5/8% Notes due 2009, less unamortized discount.................... 99,363 99,293
9 3/4% Notes due 2009............................................... 150,000 -
-------- --------
$625,318 $672,507
======== ========
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 $28.3 million, $113.1 million
and $84.8 million, with $399.1 million thereafter. The Company had $5.9 million
and $5.3 million of accrued interest payable related to its long-term debt at
December 31, 1999 and 1998, 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 $545 million) based on the banks'
evaluation of the Company's oil and gas reserves. The amount available to be
borrowed under the Bank Facility is limited to the lesser of the borrowing base
or the facility size, which is currently set at $535 million. The Company may
increase the facility size up to $625 million without further approvals from the
existing bank group if additional banks agree to join the group.
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,
1999, were $226.2 million at an average interest rate of approximately 7.5
percent.
53
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 December 1999. 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 $238.6 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.
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
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.
54
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.
On March 16, 1999, the Company's Board of Directors adopted a
stockholder rights plan and declared a dividend distribution of one Preferred
Share Purchase Right on each outstanding share of the Company's common stock
which was made on April 5, 1999, to stockholders of record on that date. The
Rights will expire on April 5, 2009.
The Rights will be exercisable only if a person or group acquires 15
percent or more of the Company's common stock or announces a tender offer the
consummation of which would result in ownership by a person or group of 15
percent or more of the common stock. Each Right will entitle stockholders to
buy one-one-thousandth of a share of a new series of junior participating
preferred stock at an exercise price of $60. If the Company is acquired in a
merger or other business combination transaction after a person has acquired 15
percent or more of the Company's outstanding common stock, each Right will
entitle its holder to purchase, at the Right's then-current exercise price, a
number of the acquiring company's common shares having a market value of twice
such price. In addition, if a person or group acquires 15 percent or more of
the Company's outstanding common stock, each Right will entitle its holder
(other than such person or members of such group) to purchase, at the Right's
then-current exercise price, a number of the Company's common shares having a
market value of twice such price. Prior to the acquisition by a person or group
of beneficial ownership of 15 percent or more of the Company's common stock, the
Rights are redeemable for one cent per Right at the option of the Company's
Board of Directors.
On June 21, 1999, the Company completed a public offering of 9,000,000
shares of common stock, all of which were sold by the Company. Net proceeds of
approximately $81.2 million were used to partially fund the purchase of certain
oil and gas properties from a subsidiary of Total Fina S.A. and a subsidiary of
Repsol S.A. in early July 1999. On July 15, 1999, in connection with the
exercise by the underwriters of a portion of the over-allotment option, the
Company sold an additional 240,800 shares of common stock using the additional
$2.1 million of net proceeds to reduce a portion of the Company's existing
indebtedness under its revolving credit facility.
55
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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:
[Download Table]
(In thousands, except per share amounts) 1999 1998 1997
-------- -------- --------
Net income (loss) - as reported..................... $73,371 $(87,665) $ 54,954
Net income (loss) - pro forma....................... 71,130 (89,759) 53,501
Earnings (loss) per share - as reported:
Basic........................................ 1.27 (1.69) 1.07
Diluted...................................... 1.24 (1.69) 1.05
Earnings (loss) per share - pro forma:
Basic........................................ 1.23 (1.73) 1.05
Diluted...................................... 1.20 (1.73) 1.03
The pro forma effect on net income (loss) for 1999, 1998 and 1997 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 1999 include a dividend yield of 0.6 percent, expected
volatility of approximately 38.6 percent, a risk-free interest rate of
approximately 5.1 percent and expected lives of 4.2 years. 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.
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, 1997, all
available options had been granted and exercised under the 1983 Plan.
56
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 and
directors 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, 1999, awards for a total of 415,000
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, 1999, options for a
total of 20,000 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 1999, 1998 and 1997:
[Enlarge/Download Table]
1999 1998 1997
----------------------------- -------------------------- --------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------------ ------------- ----------- ------------ ----------- -----------
Beginning stock options
outstanding................ 3,606,142 $ 12.79 3,060,322 $ 10.53 2,688,904 $ 8.13
Stock options granted....... 1,070,000 7.30 819,000 20.11 810,000 15.53
Stock options canceled...... - - (50,000) 14.08 - -
Stock options exercised..... (60,000) 5.94 (223,180) 8.44 (438,582) 4.99
------------ ----------- -----------
Ending stock options
outstanding................ 4,616,142 $ 11.61 3,606,142 $ 12.79 3,060,322 $ 10.53
============ ========== =========== ======== =========== ========
Ending stock options
exercisable................ 1,967,256 $ 8.94 1,490,788 $ 8.47 1,406,757 $ 8.15
============ ========== =========== ======== =========== ========
Weighted average fair
value of options........... $ 2.24 $ 4.14 $ 4.92
============ =========== ===========
57
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Of the 4,616,142 options outstanding at December 31, 1999: (a) 1,705,000
options have exercise prices between $3.50 and $8.38, with a weighted average
exercise price of $7.28 and a weighted average contractual life of 7.3 years
(647,000 of these options are exercisable currently at a weighted average price
of $7.34); (b) 2,088,142 options have exercise prices between $8.78 and $15.50,
with a weighted average exercise price of $11.80 and a weighted average
contractual life of 6.0 years (1,310,032 of these options are exercisable
currently at a weighted average price of $9.66); and (c) 823,000 options have
exercise prices between $16.06 and $20.19, with a weighted average exercise
price of $20.06 and a weighted average contractual life of 8.2 years (10,224 of
these options are exercisable currently at a weighted average price of $17.21).
All of the outstanding options are exercisable at various times in years
2000 through 2009. All incentive stock options and non-qualified options were
granted at fair market value on the date of grant. As of December 31, 1999, 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, 1999, a total of 5,051,142 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, 1999, 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. Through December 31, 1999, the Company has completed a
total of 8,977 work units through capital expenditures in 1998 and 1999 of $7.6
million and $24.1 million, respectively. The total remaining work unit
commitment is guaranteed by the Company through a $56.4 million letter of
credit; however, the Company anticipates that it will fulfill the remaining work
unit commitment through approximately $35 to $40 million of various drilling
capital expenditures. The Company has budgeted to spend $37 million in 2000 to
complete 8,751 work units, fulfilling its Naranjillos field commitment.
During July 1999, the Company also committed to perform an additional 1,068
work units in its Chaco field location in Bolivia over the next two years. This
work commitment is secured by a $5.3 million letter of credit.
Under the Company's exploration contract on Block 19 in Ecuador, the
Company is required to drill one additional well. The Company expects to drill
this well during the third quarter of 2000 at a cost of approximately $4
million.
58
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.
This work commitment is guaranteed by an $11 million letter of credit. The
expenditures 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. Through 1999, approximately $2 million of the $11 million
commitment has been spent. To fulfill its commitment, the Company has budgeted
to spend approximately $9 million in 2000 on drilling the three exploration
wells.
The Company had $93.7 million in letters of credit (including the $72.7
million in letters of credit discussed above) outstanding at December 31, 1999.
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. The Company's availability
under its revolving credit facility is reduced by the outstanding balance of
letters of credit (excluding the $56.4 million Bolivia letter of credit
discussed above).
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, 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, 1999 (based on the average price for the preceding 60 trading days
of $11.28), it would have had to pay an additional $11.5 million in cash or
issue an additional 1.0 million shares of its common stock.
Rent expense was $1.8 million, $1.2 million and $1.2 million for 1999, 1998
and 1997, respectively. The future minimum commitments under long-term, non-
cancellable leases for office space are $1.2 million, $1.1 million, $1.3
million, $1.4 million and $1.5 million for the calendar years 2000 through 2004,
respectively with $3.6 million remaining in years thereafter.
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 $5.2 million of the current
$21.4 million claim as of December 31, 1999. The Company has no indemnification
from its predecessors in title with respect to the payment of royalties on the
other two concessions. The Company expects the outcome of this litigation to be
decided during 2000 and although the Company cannot predict the outcome, 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, results of
operations, or total proved reserves.
59
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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, 1999, the Company was a party to oil price swap agreements
for 2000 covering 1.8 MMBbls at a weighted average NYMEX reference price of
$22.43 per Bbl. During the first quarter of 2000, the Company entered into
additional oil hedging contracts through December 31, 2000, covering an
additional 3.6 MMBbls of oil and a weighted average NYMEX reference price of
$25.77 per Bbl. The Company continues to monitor oil and gas prices and may
enter into additional oil and gas hedges or swaps in the future.
At December 31, 1998, the Company was a party to natural gas basis swaps
for the calender year 1999 covering a total of 30.8 million 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.
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, 1999 and 1998, was
$621.6 million and $663.0 million, respectively, compared with a carrying value
of $625.3 million and $672.5 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 was unable to
estimate the fair value of the natural gas basis swaps in place at December 31,
1998, as there was no quoted market price available. At December 31, 1999, the
Company would have received approximately $700,000 to terminate its oil swap
agreements then in place.
The carrying value of other financial instruments approximates fair value
because of the short maturity of those instruments.
60
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:
[Download Table]
(In thousands) 1999 1998 1997
----------- ----------- -----------
Domestic....................... $ 33,097 $ (122,331) $ 31,919
Foreign........................ 64,603 (8,898) 30,113
----------- ----------- -----------
$ 97,700 $ (131,229) $ 62,032
=========== =========== ===========
The total provision (benefit) for income taxes consists of the following:
[Download Table]
(In thousands) 1999 1998 1997
----------- ----------- -----------
Current:
Domestic................ $ 1,036 $ (5,324) $ 4,277
Foreign................. 4,918 1,256 958
Deferred:
Domestic................ 11,730 (43,722) 6,003
Foreign................. 6,645 4,226 (4,363)
---------- ----------- -----------
$ 24,329 $ (43,564) $ 6,875
========== =========== ===========
A reconciliation of the Federal statutory income tax rate to the effective
rate is as follows:
[Enlarge/Download Table]
1999 1998 1997
----------- ----------- -----------
Statutory U.S. income tax rate..................... 35.0% (35.0)% 35.0%
State income tax................................... 3.9 (3.9) 3.9
Federal income tax credits......................... (0.1) 1.8 (3.0)
Foreign withholding tax............................ - 1.3 -
Foreign operations................................. (2.9) (3.4) 0.6
Argentina NOL valuation allowance.................. - 4.3 -
Argentina NOL valuation allowance reversal......... (5.8) - (5.0)
Argentina NOL carryforward utilization............. (5.2) - (18.4)
Other.............................................. - 1.7 (2.0)
----------- ----------- -----------
24.9% (33.2)% 11.1%
----------- ----------- -----------
61
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, 1999 and 1998, are as follows:
[Enlarge/Download Table]
(In thousands) 1999 1998
----------- ----------
Deferred Tax Assets:
U.S. Federal and State net operating loss carryforwards............... $ 20,426 $ 31,396
Argentina net operating loss carryforwards............................ - 10,682
U.S. Federal alternative minimum tax credit carryforward.............. 5,242 4,815
Argentina asset tax credit carryforward............................... - 1,739
Other temporary book/tax differences.................................. 4,101 5,433
----------- ----------
29,769 54,065
Valuation allowance................................................... - (5,677)
----------- ----------
29,769 48,388
----------- ----------
Deferred Tax Liabilities:
Book/tax differences in property basis................................ 45,183 45,436
Other temporary book/tax differences.................................. 366 447
----------- ----------
45,549 45,883
----------- ----------
Net deferred tax asset (liability)................................ $ (15,780) $ 2,505
=========== ==========
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, 1999, the Company had an estimated U.S. Federal
alternative minimum tax ("AMT") credit carryforward of approximately $5.2
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, 1999, the Company had an estimated net operating loss
("NOL") carryforward for U.S. Federal income tax purposes of $49.4 million. The
U.S. Federal carryforward can be carried forward up to the year 2018 and can be
used to offset future taxable income of the Company. The Company also has
various state NOL carryforwards which have varying lengths of allowable
carryforward periods ranging from 5 to 20 years and can be used to offset future
state taxable income. As of December 31, 1999, the Company has fully utilized
all NOL and asset tax credit carryforwards for Argentina income tax reporting
purposes and thus reversed in 1999 the valuation allowance previously placed
against its Argentina NOL carryforwards.
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.
62
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
If the Burlington Acquisition had been consummated as of January 1, 1997,
the Company's unaudited pro forma revenues, net income and earnings per share
for the year ended December 31, 1997, 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
-----------
Revenues (in thousands)........... $431,306
Net income (in thousands)......... 57,565
Earnings per share:
Basic.......................... 1.12
Diluted........................ 1.11
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 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.
63
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
[Enlarge/Download Table]
Exploration and Production
-------------------------------
Other Gas
U.S. Argentina Foreign Gathering Marketing Corporate Total
---------- ----------- -------- --------- --------- --------- ----------
1999 (in thousands)
--------------------------------------
Revenues from external customers................ $275,486 $138,411 $ 13,873 $ 6,955 $60,275 $ 1,735 $ 496,735
Intersegment revenues........................... - - - 1,350 1,285 - 2,635
Depreciation, depletion and
amortization expense...................... 70,520 29,496 3,703 1,400 - 2,688 107,807
Impairment of oil and gas properties............ 3,306 - - - - - 3,306
Operating income (loss)......................... 112,902 77,033 665 402 2,725 (953) 192,774
Total assets.................................... 520,443 379,099 174,009 6,372 6,601 81,610 1,168,134
Capital investments............................. 51,571 131,551 54,362 680 - 1,989 240,153
Long-lived assets............................... 476,153 342,179 144,673 3,629 - 4,718 971,352
1998 (in thousands)
--------------------------------------
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 (in thousands)
--------------------------------------
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
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, sales to one crude oil purchaser of the exploration and
production segment represented approximately 10 percent 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 total revenues. During 1999, sales to
two crude oil purchasers of the exploration and production segment represented
approximately 14 percent and 11 percent, respectively, of the Company's normal
operating revenues (exclusive of eliminations of intersegment sales and the
impact of hedges).
U.S. exploration and production revenues from external customers for 1999
include $55.0 million of net proceeds from sales of oil and gas properties.
64
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
9. Detail of Prepaids and Other Current Assets
[Download Table]
(In thousands) 1999 1998
--------- ----------
Property divestiture proceeds receivable................ $ 9,704 $ -
Value added tax receivable.............................. - 2,750
U.S. Income tax refund receivable....................... - 5,323
Other prepaids and current assets....................... 9,405 10,239
--------- ----------
$ 19,109 $ 18,312
========= ==========
10. Quarterly Results (Unaudited)
The following is a summary of the quarterly results of operations for the
years ended December 31, 1999 and 1998:
[Enlarge/Download Table]
(In thousands, except per share amounts) Quarter Ended
--------------------------------------------
Mar. 31 Jun. 30 Sept. 30 Dec. 31
---------- --------- ---------- ---------
1999
----
Revenues.................................. $ 66,004 $ 92,561 $ 136,429 $201,741
Operating income (loss)................... (6,372) 27,724 60,916 113,196
Net income (loss)......................... (18,121) 5,183 27,278 59,031
Earnings (loss) per share:
Basic.................................. (.34) .10 .44 .95
Diluted................................ (.34) .09 .43 .92
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)
Revenues and operating income for the quarter ended December 31, 1999, were
increased by $47.3 million related to gains recognized on the sale of certain
oil and gas properties. The impact of this item increased net income for the
quarter ended December 31, 1999, by $28.9 million or 46 cents per basic share
and 45 cents per diluted share.
Operating income for the quarter ended December 31, 1998, was decreased by
$70.9 million due to impairments of oil and gas properties resulting from
declines in oil and gas prices during the fourth quarter. The impact of this
item reduced net income for the quarter ended December 31, 1998, by $43.3
million or 83 cents per basic and diluted share.
65
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, 1999, 1998 and 1997. The Company began operations in
Ecuador in November 1998.
[Enlarge/Download Table]
1999
----------------------------------------------------
(In thousands) U.S. Argentina Bolivia Other Total
-------- --------- ------- ------- --------
Revenues......................................... $220,495 $ 138,411 $ 4,519 $ 9,353 $372,778
Production (lifting) costs....................... 80,516 31,882 1,757 1,316 115,471
Exploration costs................................ 8,242 - 1,671 4,761 14,674
Impairment of proved properties.................. 3,306 - - - 3,306
Depreciation, depletion and amortization......... 70,520 29,496 2,380 1,323 103,719
-------- --------- ------- ------- --------
Results of operations before income taxes........ 57,911 77,033 (1,289) 1,953 135,608
Income tax expense (benefit)..................... 22,527 16,695 (438) (1,670) 37,114
-------- --------- ------- ------- --------
Results of operations (excluding corporate
overhead and interest costs)................. $ 35,384 $ 60,338 $ (851) $ 3,623 $ 98,494
======== ========= ======= ======= ========
[Enlarge/Download Table]
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)
======== ========= ======= ======= ========
66
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
[Enlarge/Download Table]
1997
-----------------------------------------------------
(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
======== ========= ======= ======= ==========
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, 1999
and 1998, was as follows:
[Enlarge/Download Table]
1999
-----------------------------------------------------
(In thousands) U.S. Argentina Bolivia Other Total
-------- --------- ------- ------- ----------
Unproved properties not being amortized........... $ 15,867 $ - $ - $ 7,504 $ 23,371
Proved properties being amortized................. 910,357 440,842 96,793 50,309 1,498,301
-------- --------- ------- ------- ----------
Total capitalized costs.................... 926,224 440,842 96,793 57,813 1,521,672
Less accumulated depreciation,
depletion and amortization................. 455,158 98,663 8,501 1,433 563,755
-------- --------- ------- ------- ----------
Net capitalized costs...................... $471,066 $ 342,179 $88,292 $56,380 $ 957,917
======== ========= ======= ======= ==========
[Enlarge/Download Table]
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
======== ========= ======= ======= ==========
67
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 1999, 1998 and 1997:
[Enlarge/Download Table]
1999
-----------------------------------------------------
(In thousands) U.S. Argentina Bolivia Other Total
-------- --------- ------- -------- ---------
Acquisitions:
Undeveloped properties........... $ 510 $ - $ - $ 600 $ 1,110
Producing properties............. 31,662 121,015 - 14,110 166,787
Exploratory........................... 10,316 - 27,834 6,882 45,032
Development........................... 9,083 10,536 2,955 1,981 24,555
-------- --------- ------- -------- ---------
Total costs incurred............. $ 51,571 $131,551 $30,789 $ 23,573 $ 237,484
======== ========= ======= ======== =========
[Enlarge/Download Table]
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
======== ========= ======= ======== =========
[Enlarge/Download Table]
1997
-----------------------------------------------------
(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
======== ========= ======= ======== =========
68
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.
[Enlarge/Download Table]
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, 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
Revisions of previous
estimates..................... 52,684 32,505 24,496 25,222 (1,952) 21,129 1,709 76,937 78,856
Extensions, discoveries
and other additions........... 110 1,844 - - 1,746 88,424 - 1,856 90,268
Production..................... (8,643) (39,150) (7,560) (4,682) (77) (4,522) (597) (16,877) (48,354)
Purchase of
reserves-in-place............. 10,343 14,947 44,694 81,072 - - 23,039 78,076 96,019
Sales of reserves-in-place..... (1,259) (34,633) - - - - - (1,259) (34,633)
------- -------- ------- -------- -------- -------- --------- --------- --------
Proved reserves at
December 31, 1999............. 110,442 361,025 136,471 113,636 8,081 514,328 48,196 303,190 988,989
======= ======== ======= ======== ======== ======== ========= ========= ========
Proved developed reserves at:
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
======= ======== ======= ======== ======== ======== ========= ========= ========
December 31, 1999........... 94,722 302,444 90,125 92,696 6,414 415,743 5,524 196,785 810,883
======= ======== ======= ======== ======== ======== ========= ========= ========
69
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, 1999 and 1998:
[Enlarge/Download Table]
1999
----------------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Ecuador Total
---------- ----------- --------- ----------- -----------
Future cash inflows...................... $3,287,165 $ 3,326,461 $ 713,314 $ 1,012,113 $ 8,339,053
Future production costs.................. 1,265,432 947,564 51,564 235,312 2,499,872
Future development and
abandonment costs..................... 188,019 195,729 47,050 140,423 571,221
---------- ----------- --------- ----------- -----------
Future net cash inflows before
income tax expense.................... 1,833,714 2,183,168 614,700 636,378 5,267,960
Future income tax expense................ 538,602 654,633 189,054 204,990 1,587,279
---------- ----------- --------- ----------- -----------
Future net cash flows.................... 1,295,112 1,528,535 425,646 431,388 3,680,681
10 percent annual discount for
estimated timing of cash flows........ 475,281 583,187 222,991 151,985 1,433,444
---------- ----------- --------- ----------- -----------
Standardized Measure of discounted
future net cash flows................. $ 819,831 $ 945,348 $ 202,655 $ 279,403 $ 2,247,237
========== =========== ========= =========== ===========
70
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
[Enlarge/Download Table]
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
========== ========= ======== ======== ==========
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 1999, 1998 and 1997:
[Enlarge/Download Table]
(In thousands) 1999 1998 1997
---------- ---------- ----------
Standardized Measure - beginning of year.............................. $ 648,222 $1,016,645 $1,392,841
Increases (decreases) -
Sales, net of production costs..................................... (255,260) (145,709) (240,767)
Net change in sales prices, net of production costs................ 1,218,764 (505,314) (824,264)
Discoveries and extensions, net of related
future development and production costs............................ 62,427 98,521 56,334
Changes in estimated future development costs...................... (52,195) (17,025) (89,637)
Development costs incurred......................................... 21,472 98,434 77,127
Revisions of previous quantity estimates........................... 732,703 (124,097) 3,508
Accretion of discount.............................................. 70,357 122,256 180,714
Net change in income taxes......................................... (687,057) 150,582 215,131
Purchase of reserves-in-place...................................... 496,237 110,389 240,658
Sales of reserves-in-place......................................... (54,135) (1,493) (2,518)
Timing of production of reserves and other......................... 45,702 (154,967) 7,518
---------- ---------- ----------
Standardized Measure - end of year.................................... $2,247,237 $ 648,222 $1,016,645
========== ========== ==========
71
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 (Filed as Exhibit 4.4 to the
Company's report on Form 10-K for the year ended December 31, 1998,
filed March 12, 1999 (the "1998 Form 10-K")).
4.5 Rights Agreement, dated March 16, 1999, between the Company and
ChaseMellon Shareholder Services, L.L.C., as Rights Agent (Filed as
Exhibit 4.1 to the Company's Registration Statement on Form 8-A, filed
March 22, 1999).
4.6 Certificate of Designation of Series A Junior Participating Preferred
Stock of the Company (Filed as Exhibit 3.3 to the Company's
Registration Statement on Form S-3, Registration No. 333-77619).
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* 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).
10.3* 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).
10.4* 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).
10.5* 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).
10.6* 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).
10.7* 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).
10.8* Amendment No. 5 to Vintage Petroleum, Inc. 1990 Stock Plan dated March
16, 1999 (Filed as Exhibit A to the Company's Proxy Statement for
Annual Meeting of Stockholders dated March 31, 1999).
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* Form of Non-Qualified Stock Option Agreement for non-employee
directors under the Vintage Petroleum, Inc. 1990 Stock Plan.
10.14 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,
NationsBank, 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 November 13, 1998).
10.15 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 (Filed as
Exhibit 10.14 to the 1998 Form 10-K).
10.16 Second Amendment to the Amended and Restated Credit Agreement dated as
of May 19, 1999, among the Company, as borrower, and certain
commercial lending institutions, as lenders, Bank of Montreal, as
administrative agent, NationsBank, N.A., as syndication agent, and
Societe Generale Southwest Agency, as documentation agent (Filed as
Exhibit 10.1 to the Company's report on Form 10-Q for the quarter
ended June 30, 1999, filed August 12, 1999).
10.17 Third Amendment to the Amended and Restated Credit Agreement dated as
of November 18, 1999, among the Company, as borrower, and certain
commercial lending institutions, as lenders, Bank of Montreal, as
administrative agent, Bank of America, N.A., successor-in-interest by
merger to NationsBank, 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.
Dates Referenced Herein and Documents Incorporated by Reference
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