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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, 2000
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
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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.[_]
As of February 28, 2001, 62,890,416 shares of the Registrant's Common Stock
were outstanding, and the aggregate market value of the Common Stock held by
non-affiliates was approximately $987,332,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the Annual Meeting of
Stockholders to be held May 8, 2001, 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, 2000
TABLE OF CONTENTS
Page
----
PART I
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........................................................... 21
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.......................... 24
Item 6. Selected Financial Data........................................................................ 25
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 26
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..................................... 33
Item 8. Financial Statements and Supplementary Data.................................................... 35
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........... 35
PART III
Item 10. Directors and Executive Officers of the Registrant............................................. 35
Item 11. Executive Compensation......................................................................... 35
Item 12. Security Ownership of Certain Beneficial Owners and Management................................. 36
Item 13. Certain Relationships and Related Transactions................................................. 36
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K................................ 36
Signatures....................................................................................................... 39
Index to Financial Statements.................................................................................... 40
i
Certain Definitions
As used in this Form 10-K:
Unless the context requires otherwise, all references to the "Company"
include Vintage Petroleum, Inc., its consolidated subsidiaries and its
proportionately consolidated general partner interests in various joint
ventures.
"Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf"
means billion cubic feet, "Tcf" means trillion 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 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.
"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" ("PUD") 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; and
. expansion and growth of our business and operations.
These statements are based on certain assumptions and analyses made by the
Company in light of its experience and its perception of historical trends,
current conditions and expected future developments as well as other factors it
believes are appropriate in the circumstances. However, whether actual results
and developments will conform with the Company's expectations and predictions is
subject to a number of risks and uncertainties which could cause actual results
to differ materially from the Company's expectations, including:
. the risk factors discussed in this Form 10-K and listed from time to
time in the Company's filings with the Securities and Exchange
Commission;
. oil and gas prices;
. exploitation and exploration successes;
. continued availability of capital and financing;
. general economic, market or business conditions;
. the acquisition and other business opportunities (or lack thereof) that
may be presented to and pursued by the Company;
. changes in laws or regulations; and
. other factors, most of which are beyond the control of the Company.
Consequently, all of the forward-looking statements made in this Form 10-K
are qualified by these cautionary statements and there can be no assurance that
the actual results or developments anticipated by the Company will be realized
or, even if substantially realized, that they will have the expected
consequences to or effects on the Company or its business or operations. The
Company assumes no obligation to update publicly any such forward-looking
statements, whether as a result of new information, future events or otherwise.
iii
PART I
Items 1 and 2. Business and Properties.
General
The Company is an independent oil and gas company focused on the
acquisition of oil and gas properties which contain the potential for increased
value through exploitation and exploration. The Company, through its
experienced management and 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, 2000, the Company owned and operated producing properties
in 11 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 2000, the Company expanded its North
American operations into Canada through the acquisition of 100 percent of
Cometra Energy (Canada), Ltd. (now Vintage Energy (Canada), Ltd.). 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 2000, the Company expanded
this core area with the purchase of the Piedras Colorados and Cachueta
concessions in the Cuyo Basin in western Argentina. 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 with operations in Ecuador. This subsidiary currently operates
producing properties in the Oriente Basin in Ecuador and provides the Company
with substantial undeveloped acreage which the Company believes has significant
development and exploration potential.
As of December 31, 2000, the Company owned interests in 3,592 gross (2,827
net) productive wells in the United States, of which approximately 84 percent
are operated by the Company, 1,301 gross (1,285 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, 8 gross (6 net) productive wells in Ecuador, 100 percent of which
are operated by the Company, and 156 gross (78 net) productive wells in Canada,
of which approximately 50 percent are operated by the Company. As of December
31, 2000, the Company's properties had proved reserves of 489.1 MMBOE, comprised
of 318.6 MMBbls of oil and 1.0 Tcf of gas, with a present value of estimated
future net revenues before income taxes (utilizing a 10 percent discount rate)
of $4.3 billion and a standardized measure of discounted future net cash flows
of $3.0 billion. From the first quarter of 1998 through the fourth quarter of
2000, the Company increased its average net daily production from 45,000 Bbls of
oil to 59,900 Bbls of oil and from 128,500 Mcf of gas to 161,300 Mcf of gas.
Financial information relating to the Company's industry segments is set
forth in Note 7 "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 on existing properties, (c)
exploring undeveloped 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, 1998, through December 31, 2000, the Company acquired 152.0
MMBOE of proved oil and gas reserves at an average acquisition cost of
$2.39 per BOE. The Company replaced through acquisitions approximately
195 percent of its production of 78.1 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, 1998, through December
31, 2000, the Company spent approximately $216.8 million on
exploitation and development activities. As a result of all of its
exploitation activities, including development and infill drilling,
during the three-year period ended December 31, 2000, the Company
succeeded in adding 88.2 MMBOE to proved reserves, replacing
approximately 113 percent of production during this period. During
2000, the Company added 22.2 MMBOE through exploitation, replacing 77
percent of production. The Company continues to maintain an extensive
inventory of exploitation and development opportunities. Due to the
continued strong product price environment, the Company anticipates
increasing its level of spending to approximately $212 million in 2001
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, 1998, through December 31, 2000,
the Company spent approximately $201.4 million on exploration
activities, including $40.9 million on undeveloped leasehold and
exploratory drilling in progress which was unevaluated at December 31,
2000. The Company drilled 81 gross (48.37 net) exploration wells, of
which approximately 58 percent gross (66 percent net) were productive.
As a result of all of the Company's exploration activities during the
three-year period ended December 31, 2000, the Company succeeded in
adding 55.4 MMBOE to proved reserves, replacing approximately 71
percent of production during this period. The Company's exploration
activities in 2000 were focused on its core areas in the United
States, Bolivia, Ecuador and Yemen. The Company anticipates 2001
spending of approximately $73 million on exploration projects,
primarily in the United States, Canada, Yemen and Trinidad.
. 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. Since 1990, the Company has completed five public equity
offerings, two public debt offerings and a Rule 144A private debt
offering, all of which have provided the Company with aggregate net
proceeds of approximately $643 million. During 2000, the Company
applied excess cash flow over capital expenditures to substantially
reduce outstanding long-term debt, lowering its net long-term debt-to-
book capitalization ratio from 57.5 percent at December 31, 1999, to
41.6 percent at December 31, 2000. The unused portion of the Company's
revolving credit facility at February 28, 2001, of approximately $511
million and its strong balance sheet provide the Company flexibility
to capitalize on significant acquisition opportunities.
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. In 1999, the Company entered into a
farm-in agreement for the S-1 Damis exploration block in Yemen and in December
2000, made its initial entrance into Canada with the purchase of 100 percent of
Cometra Energy (Canada), Ltd., a privately-held Canadian company. The Company
also extended its Argentina operations into western Argentina with its September
2000 acquisition of two concessions from Perez Companc. 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.
From January 1, 1998, through December 31, 2000, the Company made oil and
gas property acquisitions involving total costs of
3
approximately $363.3 million. As a result of these acquisitions, the Company
acquired approximately 152.0 MMBOE of proved oil and gas reserves. The following
table summarizes the Company's acquisition experience during the periods
indicated:
Proved Reserves When Acquired
----------------------------- Cost
Per Boe
Acquisition Oil Gas When
Costs (MBbls) (MMcf) MBOE Acquired
------------- ------- ------ ---- --------
(In thousands)
North America Acquisitions:
1998.................................... $ 70,805 5,452 53,027 14,290 $ 4.95
1999.................................... 31,662 10,343 14,947 12,834 2.47
2000.................................... 53,962 2,854 41,166 9,715 5.55
--------- ------- ------- -------
Total North America Acquisitions..... 156,429 18,649 109,140 36,839 4.25
--------- ------- ------- -------
South America Acquisitions:
1998.................................... 34,218 21,577 - 21,577 1.59
1999.................................... 135,125 67,734 81,072 81,246 1.66
2000.................................... 37,486 11,970 2,278 12,350 3.04
--------- ------- ------- -------
Total South America Acquisitions.... 206,829 101,281 83,350 115,173 1.80
--------- ------- ------- -------
Total Acquisitions......................... $ 363,258 119,930 192,490 152,012 $ 2.39
========= ======= ======= =======
The Company estimates that 22.1 MMBOE of proved reserves, as of the various
acquisition dates, were acquired in 2000 for an aggregate cost attributable to
oil and gas assets of $91.4 million, resulting in an average cost of $4.14 per
BOE. The average cost per BOE over the three-year period ended December 31,
2000, is $2.39 and the cost since the Company's inception is $2.97 per BOE.
The following is a brief discussion of the significant acquisitions in
2000:
Cuyo Basin Properties (Argentina). In September 2000, the Company
purchased an interest in two concessions in the Cuyo Basin (the "Cuyo
Properties"), covering approximately 204,000 acres in Mendoza Province of
western Argentina. The Company purchased 100 percent of the interest formerly
held by Perez Companc for $40.1 million in cash funded through an advance under
the Company's unsecured revolving credit facility.
The Cuyo Properties had current net daily production at the time of the
acquisition of 2,000 Bbls of 32 degree gravity, light, sweet crude oil and are
similar in production and operating characteristics to the Company's existing
operations in the San Jorge Basin of southern Argentina. Exploitation
activities aimed at increasing production are targeted to begin in the second
quarter of 2001.
This acquisition marks the Company's entry as an operator into the western
basins of Argentina and is consistent with its long-term objective of expanding
the Company's presence in Argentina. The Company plans to apply 3-D seismic-
driven development drilling and cost reduction strategies that have proven
successful for it in the San Jorge Basin in Argentina and the U.S. to the Cuyo
Properties. Some of the cost reduction strategies have already been initiated.
Cometra Energy (Canada), Ltd. (North America). In December 2000, the
Company acquired 100 percent of the outstanding common stock of Cometra Energy
(Canada), Ltd. ("Cometra") from Electrafina, a part of Groupe Brussels Lambert
SA, for approximately $46.2 million (CAD $71.0 million) and the assumption of
estimated net liabilities of approximately $7.6 million (CAD $11.6 million) (the
"Cometra Acquisition"). The purchase was funded through an advance under the
Company's unsecured revolving credit facility.
The Cometra Acquisition contains properties consisting primarily of 13
producing fields, principally in the provinces of Alberta
4
and British Columbia with additional fields in Saskatchewan, certain processing
and pipeline facilities and approximately 126 thousand net undeveloped acres.
Additionally, through a wholly-owned subsidiary of Cometra, the Company also has
a 36 percent working interest in an exploration concession in Trinidad
representing approximately 10,000 net undeveloped acres. The Company operates
approximately 50 percent of the wells, which had a total net daily production at
the time of the acquisition averaging approximately 12 MMcf and 635 Bbls of
light crude oil, or a combined 2,670 BOE. The realized oil price for the
production averaged approximately 93 percent of the NYMEX price, while the
average price of gas is approximately 67 percent of the NYMEX reference price of
gas.
The Cometra Acquisition marks the Company's initial entry into Canada and
Trinidad. It also establishes western Canada as a new core area for the
Company, complementing its existing core operating areas in the U.S., Argentina,
Bolivia and Ecuador.
The Company anticipates spending approximately $14.3 million in 2001 for
identified exploitation and exploration projects arising from the acquisition,
primarily in Canada. In addition, an exploration commitment is also in place to
drill three wells in the long established productive region of southern onshore
Trinidad through a wholly-owned subsidiary of Cometra.
Divestiture Activities
During 1999, the Company instituted a divestiture program designed to sell
Company properties that were 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.
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
totaled 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 sale of these properties have not had a
material impact on the Company's continuing operations. A portion of the
proceeds from these property sales was used to fund the acquisition of certain
producing oil and gas properties from Nuevo Energy Company (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
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 2000
totaled 22.2 MMBOE, or 77 percent of the Company's production of 28.8 MMBOE.
As a result of the return of higher oil and gas prices, the Company spent
$25.8 million on workover and recompletion operations during 2000, significantly
higher than 1999. A measure of the overall success of the Company's
recompletion and workover operations during 2000 (excluding minor equipment
repair and replacement) was that improved production or operating efficiencies
were achieved from approximately 81 percent of such operations consistent with
the average for the last three years of 79 percent.
5
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.
During 2000, the Company participated in the drilling of 64 gross (57.61
net) development wells, of which 61 gross (54.93 net) were productive. At
December 31, 2000, the Company's proved reserves included approximately 145
development or infill drilling locations on its U.S. acreage, 212 locations on
its Argentina acreage, 44 locations on its Ecuador acreage, 25 locations on its
Canada acreage and 16 locations on its Bolivia acreage. In addition, the
Company has an extensive inventory of development and infill drilling locations
on its existing properties which are not included in proved reserves. The
Company significantly increased its exploitation and development capital
expenditures for 2000, spending approximately $18.0 million in the U.S., $33.5
million in South America on development/infill drilling and $1.0 million in
Canada. The Company also spent approximately $6.1 million on the acquisition of
seismic data and other development activities in 2000. The Company has
increased its 2001 capital budget for exploitation and development work to $212
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.
Exploitation and development activities for 2000 were concentrated mainly
in Argentina and the U.S. Gulf Coast and Mid-Continent core areas of the
Company. The following is a brief description of significant developments in the
Company's recent exploitation and development activities:
North America. The Company's U.S. exploitation program for 2000 included
the drilling of 23 gross (16.61 net) development wells, of which 21 gross (14.93
net), or 91 percent, were successful. Nine of these wells were horizontal wells
drilled to the producing Edwards "A" zone on the Company's Luling field in south
Texas where it has a 100 percent working interest, with eight of them being
successful. These eight wells had a combined initial gross daily production
buildup of 1,677 Bbls of oil (1,490 Bbls net). There are 11 additional Luling
locations similar to these included in the Company's year-end 2000 reserves.
The Company's 2000 U.S. exploitation program also included 114 workovers
and recompletions, of which 82 gross (76.92 net) were successful for a 72
percent success rate. The Company's Darst Creek field, in the same area as the
Luling field, saw the largest amount of activity with 47 projects, generally
recompletions to the deeper Edwards "A" zone from shallower zones. These
recompletions resulted in a total initial daily production increase of 1,282
Bbls of oil (1,100 Bbls net). There are 221 additional similar projects booked
to proved reserves in this field at year-end 2000. In addition, there are seven
PUD horizontal locations to be drilled in the Darst Creek field.
The Company's 2001 exploitation budget includes $105 million targeted
towards North American projects. The Company will primarily continue to focus on
areas in the U.S. where it has found recent success including the Stagecoach
prospect, Galveston Bay, South Pass 24 and in the Luling/Darst Creek/West Ranch
areas in south Texas. Also included in the $105 million, is $10 million to be
spent on the Company's newly acquired Canadian properties.
Argentina. The Company continued its highly successful development drilling
program in Argentina with the drilling of 40 successful wells in 41 attempts for
a 98 percent success rate. With the 1999 acquisition of the El Huemul concession
and the 2000 acquisition of the Cuyo Properties, the Company's development
drilling locations in Argentina have increased substantially with 212 locations
being recorded in its year-end 2000 reserves.
6
The Company's drilling program in Argentina relies heavily on
interpretation of 3-D seismic to aid in the optimum placement of wells with the
acquisition of 314 square miles of 3-D seismic in 2000 and early 2001, covering
portions of its Canadon Seco, Canadon Leon, Tres Picos and El Huemul
concessions. With this new seismic, the Company now has a total of 567 square
miles of 3-D seismic which covers 39 percent of the area of all of its
concessions. The Company believes that significant additional drilling potential
will continue to be identified through the acquisition of future 3-D seismic
surveys. Development and extensional drilling, along with implementation of
secondary recovery projects, have been the focus of the Company's historical
exploitation efforts on its Argentina properties.
The Company's 2001 international exploitation budget of $107 million is
heavily weighted toward projects in three of its concessions in the San Jorge
Basin in Argentina: Canadon Seco, Meseta Espinosa and El Huemul. The Company is
currently drilling with two rigs in its San Jorge Basin concessions and plans to
add a third rig during 2001. Additionally, six horizontal oil wells in the
recently acquired Piedras Colorados concession in the Cuyo Basin are planned.
The Company also plans to increase its efforts to initiate new waterfloods
and optimize existing secondary recovery projects in Argentina during 2001. Only
a small portion of the producing areas within the concessions controlled by the
Company have been subject to secondary recovery operations. The Company believes
that numerous areas currently under primary recovery will respond to
waterflooding. Existing and future waterflood projects will be enhanced with the
utilization of 3-D seismic as a tool to identify and high- grade specific
reservoir targets.
Bolivia. Exploitation activity in Bolivia during 2001 will be focused on
the Company's Naranjillos concession. Planned work includes a recompletion,
stimulation of existing Devonian completions and facility modifications to
increase the concession's deliverability. During 2000, the Company executed a
short-term contract and a long-term contract to supply gas to affiliates of
Enron South America ("Enron"). Under the terms of the short-term contract, Enron
may purchase up to 14.5 MMcf of gas per day for a minimum period of six months
to supply its Cuiaba integrated energy project in Brazil. Sales are anticipated
to start during the second half of 2001. Under the terms of the long-term
agreement, Enron may purchase up to 15.4 MMcf of gas per day contingent on its
development of emerging market opportunities in Brazil and Argentina. The
Company believes that it is well positioned to continue to develop markets as
gas consumption continues to grow in the Southern Cone.
Ecuador. As a result of the Ecuadorian government's recent authorization of
a second crude oil transportation pipeline (the "OCP"), the Company plans to
increase exploitation activity in Ecuador. A 116-square-mile (300 square
kilometer) 3-D seismic survey will be acquired on Block 14, Block 17 and
Shiripuno concessions during the first half of 2001. A 10,100 foot development
well in Block 14 targeting Cretaceous "M-1" Tena and the Napo "U" formations is
planned during the first quarter of 2001. The Company anticipates an increase in
its pipeline allowable (currently 6,439 gross (4,050 net) Bbls of oil per day)
to accommodate production from this well. Additional infill drilling will be
based on interpretation of the 3-D seismic and will be commensurate with the
completion of the OCP pipeline currently estimated for the first half of 2003.
7
Exploration
The Company's exploration program is designed to contribute significantly
to its growth. Management divides the strategic objectives of its exploration
program into two parts. First, in the U.S., Canada and 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., Canada
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 Yemen and Ecuador are
characterized by higher potential and higher risk. The Company spent
approximately $81.8 million on exploration activities during 2000 (including
$25.3 million on activities which are unevaluated as of December 31, 2000),
spending approximately $29.5 million in Ecuador and Bolivia, $20.1 million in
Yemen, $26.0 million in the United States and $6.2 million in Canada and
Trinidad, adding 6.2 MMBOE to its proved reserves. A significant portion of the
Company's Yemen exploration dollars were classified as unevaluated costs at
year-end 2000. The Company's 2001 exploration budget has been set at $73
million, focusing on North America drilling, principally in the U.S., and 3-D
seismic acquisition in Yemen.
In conjunction with its focus on exploitation, the Company has increased
its attention on growing reserves through exploration efforts as well, and while
the year 2000 saw mixed results from the Company's exploration efforts, there
were some positive outcomes. The following is a summary of the major exploration
activities in 2000:
North America. The Company's Stagecoach prospect in western Oklahoma and
its Galveston Bay and South Pass 24 areas in shallow state waters in Texas and
Louisiana were the areas of focus for U.S. exploration activities in 2000. Each
of these drilling programs found great success. The Company drilled nine
exploratory gas wells in the Stagecoach prospect during 2000 with seven of them
being successful. The Company also drilled five successful development wells in
this area as offsets to previously successful exploratory wells. These 12
successful wells have total net daily production of 14,544 Mcf of gas and 213
Bbls of oil. The Company has budgeted approximately $11 million for the drilling
of 19 additional exploratory wells and an additional $23 million for the
drilling of 21 development wells in this area during 2001.
The Company's Galveston Bay drilling program, begun in 1997, continued to
be successful in 2000 with the Company having success in five out of the six
wells drilled during 2000. These gas wells in shallow state waters of Texas
produce out of the Vicksburg formation from Text II sands and have a combined
net daily production of 5.7 MMcf of gas and 870 Bbls of oil. The Company will
continue this drilling program in 2001 with $8 million budgeted for the drilling
of six wells.
The Company's South Pass 24 field located in state waters of Louisiana also
produced successful gas wells in 2000, the most notable being the Tambour A-1
which has gross daily production rates of 8.6 MMcf (2.8 MMcf net) of gas and 100
Bbls (32 Bbls net) of condensate. This well, as well as the Tambour A-2, has
significant behind pipe reserves. The Tambour A-2, which had an initial gross
daily production rate of 5.9 MMcf (2.9 MMcf net) of gas, is currently being
recompleted uphole. Two other wells were drilled by the Company in this area in
2000. Total South Pass 24 initial net daily production build-up from the four
drill wells and three workovers performed in 2000 was 12.4 MMcf of gas and 180
Bbls of oil. The Company has budgeted in 2001 to continue its drilling program
in South Pass 24 as well as to drill a 17,000 foot exploratory well at its
Little Lake/Little Temple area of southern Louisiana.
Most recently, the Company found success in its Mills Ranch prospect in the
Texas panhandle with the completion of the Mills Ranch 1-97 which is currently
producing out of the Hunton formation at gross daily rates of 8.0 MMcf (1.9 MMcf
net) of gas and 100 Bbls (23 Bbls net) of condensate. The Company has an offset
to this well scheduled for drilling in the first half of 2001.
Bolivia. From an exploration standpoint, the Company's deep test of the
Huamampampa formation and its two deep tests of the Santa Rosa formation in
Bolivia also were unsuccessful. The Company did find reserves in the shallower,
previously-developed Iquiri formation in two of these wells and will produce
these wells from this formation when the demand for gas in Bolivia increases.
8
Yemen. The Company's Yemen exploration efforts consisted of three
exploratory wells still in the evaluation phase and one dry hole. The An Naeem
#1 found a significant gas accumulation and initially tested at a combined rate
of 40 MMcf per day and 1,020 Bbls of condensate per day from two Alif zones. The
An Naeem #2 was drilled down-dip from the An Naeem #1 in search of an oil rim
thought to reside below the gas accumulation found in the initial well. This
well also encountered gas reserves, testing at a daily rate of 27.7 MMcf of gas
and 880 Bbls of condensate. The Company is currently evaluating the information
obtained from these two wells to determine if an oil rim yet exists still
further down-dip from the An Naeem #2. If it is so determined, the Company will
drill the An Naeem #3 in a further attempt to locate the oil rim.
While the Company's Fordus well in Yemen was unsuccessful, its Harmel well
found what the Company believes is a significant, previously undiscovered pool
of oil which is a heavier gravity than that currently produced from this region.
The Company is currently performing tests on the oil to determine if it can be
commercially produced. The Company expects these tests to last into the third
quarter of 2001. If the tests prove the oil to be of commercial quality, the
Company will drill a second Harmel well before year end.
To aid in the evaluation of further prospects on its Yemen exploration
acreage, the Company has budgeted to spend $4 million in 2001 to acquire
additional 3-D seismic to fully evaluate several attractive exploration
opportunities in the Alif formation that have been identified through the
evaluation of existing 2-D seismic. These potential exploration targets are on
trend with the neighboring Al Nasr and Dhahab fields that are currently
producing oil at a combined daily rate in excess of 50,000 Bbls.
Ecuador. The Company's Rio Cotapino #1 exploration well in the Block 19
concession in Ecuador was unsuccessful. The well, drilled to a total depth of
7,060 feet, was non-productive in the Hollin and not commercially productive in
the Napo "T" sand. The Company has completed all the drilling obligations
associated with Block 19 and is in the process of relinquishing of the
concession.
Canada. The Company's Canadian acreage acquired as part of the Cometra
Acquisition in December 2000 has already produced two exploration successes for
the Company. The Malmo 13-26 logged hydrocarbon pay in a Devonian reef play.
Completion operations are currently underway with plans for an offset to be
drilled in the second quarter of 2001. In the Milo Lake area of British
Columbia, the Company has successfully discovered a new Devonian Keg River
pinnacle reef field in its Milo West prospect, located approximately three miles
to the west of its existing Milo Pine Point "A" pool. Based on the evidence of
similar geology, the Company expects production characteristics of the Milo West
discovery to be comparable to that of the Milo Pine Point "A" pool. The Pine
Point "A", also a Keg River pool, discovered in 1998, is estimated to contain
over 150 Bcf of gross original gas in place and currently produces at a net
daily rate of 3.0 MMcf to the Company's interest (10.0 MMcf gross). Initial
production from the newly discovered well at Milo West is anticipated by mid
2001. Additionally, three development wells are scheduled to be drilled in the
Pine Point "A" pool during the first quarter of 2001. The Company has budgeted
to spend $14 million on exploratory drilling and development activities in
Canada during 2001.
Trinidad. In conjunction with the Cometra Acquisition, the Company acquired
Cometra's wholly-owned subsidiary, Cometra Trinidad, Limited, which has a 36
percent working interest in approximately 28,400 gross undeveloped acreage in
Trinidad. The Company is the operator of this acreage and is obligated to drill
three exploratory wells on this acreage and plans to drill two of these wells,
the Carapel Ridge No.1 and the Corosan No.1, in the second quarter of 2001 as
Herrera sand tests.
Oil and Gas Properties
At December 31, 2000, the Company owned and operated domestic producing
properties in 11 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 Argentina during 1995,
Bolivia during 1996, Ecuador in 1998 and Canada in 2000. As of December 31,
2000, the Company operated approximately 4,387 productive wells and also owned
non-operating interests in 686 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, 2000, as estimated by the independent petroleum
consultants of Netherland, Sewell & Associates, Inc. ("Netherland, Sewell") for
the United States, Argentina and Ecuador, as estimated by the independent
petroleum consultants of DeGolyer and MacNaughton for Bolivia and as estimated
by the Company for Canada:
Oil (MBbls) Gas (MMcf)
------------------------------ ------------------------------- MBOE
Developed Undeveloped Total Developed Undeveloped Total Total
--------- ----------- ----- --------- ----------- ----- -----
West Coast.............. 52,456 4,878 57,334 117,320 5,219 122,539 77,757
Gulf Coast.............. 26,934 5,234 32,168 77,898 16,159 94,057 47,844
East Texas.............. 8,076 641 8,717 80,000 13,332 93,332 24,272
Mid-Continent........... 3,308 809 4,117 58,235 30,509 88,744 18,908
-------- ------- ------- ------- ------- --------- -------
Total U.S............ 90,774 11,562 102,336 333,453 65,219 398,672 168,782
-------- ------- ------- ------- ------- --------- -------
Argentina............... 94,191 63,345 157,536 41,822 79,377 121,199 177,736
Bolivia................. 5,668 1,157 6,825 385,623 78,236 463,859 84,135
Ecuador................. 3,915 45,560 49,475 - - - 49,475
Canada.................. 1,558 830 2,388 33,405 6,073 39,478 8,967
-------- ------- ------- ------- ------- --------- -------
Total Company........ 196,106 122,454 318,560 794,303 228,905 1,023,208 489,095
======== ======= ======= ======= ======= ========= =======
_________________
Estimates of the Company's 2000 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
development 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 and Santa Barbara Counties and the Sacramento
Basin 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, 2000, the area
comprised 16 percent of the Company's total proved reserves and 46 percent of
the Company's U.S. proved reserves. The Company currently operates 1,384
productive wells and owns an interest in 166 productive wells operated by
others. During 2000, net daily production for this area averaged approximately
16,200 BOE, or 40 percent of total net daily U.S. production. Numerous
workovers and recompletion opportunities exist in the San Miguelito, 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
waterflood potential that may add significant reserves.
Gulf Coast Area. The Gulf Coast area includes properties located in
southern Texas, the southern half of Louisiana, Alabama, Mississippi and wells
located in shallow state and federal waters. 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, 2000, the Gulf Coast area comprised approximately ten percent of
the Company's total proved reserves and 28 percent of its U.S. proved reserves.
The Company currently operates 818 productive wells in this area and owns an
additional interest in 121 productive wells operated by others. During 2000,
net daily production from this area averaged approximately 15,800 BOE, or 38
percent of total net daily 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 northern 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, 2000, total proved reserves and 15 percent
of its U.S. proved reserves. The Company currently operates 546 productive wells
in this area and owns an interest in an additional 106 productive wells operated
by others. During 2000, net daily production for this area averaged
approximately 5,500 BOE, or13 percent of total net daily 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 four percent of the Company's
December 31, 2000, total proved reserves and 11 percent of its U.S. proved
reserves. The Company currently operates 258 productive wells in this area and
owns an interest in an additional 193 productive wells operated by others.
During 2000, net daily production for this area averaged approximately 3,600
BOE, or nine percent of total net daily U.S. production. Significant development
drilling and recompletion opportunities exist in the Marlow/Velma field, plus
additional projects to improve the ultimate reserve recovery exist in the
Shawnee Townsite waterflood.
Argentina. 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 and two concessions, both operated by the
Company, located in the Cuyo Basin in western Argentina. These concessions
comprised approximately 36 percent of the Company's December 31, 2000, total
proved reserves. During 2000, net daily production averaged approximately 25,770
Bbls of oil and 23,850 Mcf of gas. The Company currently operates 1,279
productive wells (100 percent working interest) with net daily production of
26,060 Bbls of oil and 23,800 Mcf of gas. In addition, the Company owns an
interest in 22 productive wells operated by others. At December 31, 2000, the
Company's proved reserves included approximately 212 development drilling
locations 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.
Bolivia. The Bolivia properties consist of four producing concessions and
one exploration concession located in the Chaco Basin of Bolivia. The Company
has 100 percent working interests in the Chaco exploration concession and the
Naranjillos, Chaco Sur and Porvenir producing concessions. In the other
producing concession, Nupuco, the Company has a 50 percent working interest. The
Company operates all four producing concessions. These concessions comprise
approximately 17 percent of the Company's December 31, 2000, total proved
reserves and include 16 gross (15 net) productive wells, all of which are
operated by the Company. Current net daily production is restricted by current
Brazil demand to approximately 18,900 Mcf of gas and 210 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.
Ecuador. 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
the Shiripuno and Block 19 exploration concessions. The Company is in the
process of relinquishing its interest in Block 19. The Company currently
operates 8 gross (6 net) productive wells with current gross daily production of
approximately 6,350 Bbls of oil (4,075 Bbls net). These concessions comprised
ten percent of the Company's December 31, 2000, total proved reserves. During
the fourth quarter of 1999, the production facilities were upgraded to increase
the oil storage 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 1999
and 2000, one well was recompleted and 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 6,700 Bbls of oil per day. As a result of an increase in the oil
transportation allowable during 2000, these concessions are currently producing
approximately 6,350 Bbls of oil per day. Additional infill drilling will be
based on interpretation of the 3-D seismic and will be commensurate with the
completion of the OCP pipeline currently estimated for the first half of 2003.
11
Canada. The Canada properties consist of 13 producing fields, principally
in the provinces of Alberta and British Columbia, with additional fields in
Saskatchewan and certain processing and pipeline facilities. These fields
comprise approximately two percent of the Company's December 31, 2000, total
proved reserves and include 156 gross (78 net) productive wells, approximately
50 percent of which are operated by the Company. Current net daily production is
approximately 10 MMcf of gas and 615 Bbls of light crude oil. The Company will
perform both exploitation and development activities as well as exploration
activities on these properties during 2001.
Marketing
The Company's U.S. and Canada gas production and gathered gas are generally
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 U.S. gas is committed to long-term fixed-price contracts,
the Company is positioned to take advantage of the current strong gas price
environment, but it is also subject to any future 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. These
indexes have risen in connection with the current higher oil prices. The
Company's Argentina average gas price is determined primarily by the realized
oil price from the El Huemul concession.
The Company's U.S. 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.
During 2000, the Company executed a short-term contract and a long-term
contract to supply a portion of its Bolivia gas to affiliates of Enron South
America ("Enron"). Under the terms of the short-term contract, Enron may
purchase up to 14.5 MMcf of gas per day for a minimum period of six months to
supply it Cuiaba integrated energy project in Brazil. Sales are anticipated to
start during the second half of 2001. Under the terms of the long-term
agreement, Enron may purchase up to 15.4 MMcf of gas per day contingent on its
development of emerging market opportunities in Brazil and Argentina. The
Company believes that it is well positioned to continue to develop markets as
gas consumption continues to grow in the Southern Cone.
Generally, the Company's U.S. 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., ENAP and Shell
C.A.P.S.A. 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's Ecuador Block 14 and Block 17 oil
production is sold to various third-party purchasers at West Texas Intermediate
spot prices less a specified differential. The Company's Canadian oil production
is sold under short-term contracts at posted prices. During 2000, approximately
17 percent and 12 percent of the Company's total operating revenues related to
oil sales to ENAP (the Chilean government-owned oil company) and Esso S.A.P.A.
(the Argentina affiliate of Exxon-Mobil), respectively.
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 2000, the Company entered into
various oil hedges (swap agreements) covering approximately 3.5 MMBbls at a
weighted average price of $30.76 per Bbl (NYMEX reference price) for the
calendar year 2001. The Company continues to monitor oil and gas prices and may
enter into additional oil and gas hedges or swaps in the future.
12
The following table reflects the Bbls hedged and the corresponding weighted
average NYMEX reference prices by quarter:
NYMEX
Reference Price
Quarter Ending Bbls Per Bbl
-------------- -------------- ---------------
(In Thousands)
March 31, 2001 2,160 $ 31.48
June 30, 2001 455 30.66
September 30, 2001 460 29.61
December 31, 2001 460 28.58
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 18 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 263 miles of varying diameter pipe with a
combined capacity in excess of 190 MMcf of gas per day. At December 31, 2000,
there were 83 wells (70 wells (84 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 in 1999, 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 8,000 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 under wet gas purchase
agreements.
13
Reserves
At December 31, 2000, the Company had proved reserves of 489.1 MMBOE,
comprised of 318.6 MMBbls of oil and 1.0 Tcf of gas as estimated by the
independent petroleum consultants of Netherland, Sewell for the United States,
Argentina and Ecuador, as estimated by the independent petroleum consultants of
DeGolyer and MacNaughton for Bolivia and as estimated by the Company for Canada.
For additional information on the Company's oil and gas reserves, see "Oil and
Gas Properties." The following table sets forth, at December 31, 2000, the
present value of future net revenues (revenues less production and development
costs) before income taxes attributable to the Company's proved reserves at such
date (in thousands):
Proved Reserves:
Future net revenues........................................ $ 7,641,200
Present value of future net revenues before income taxes,
discounted at 10 percent................................. 4,338,616
Standardized measure of discounted future net cash flows... 2,951,121
Proved Developed Reserves:
Future net revenues........................................ $ 5,852,746
Present value of future net revenues before income taxes,
discounted at 10 percent................................. 3,301,825
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, 2000, economic
conditions. The estimated future production is priced at prices prevailing at
December 31, 2000. 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, 2000, cost levels, but such costs do
not include debt service, general and administrative expenses and income taxes.
For additional information concerning the historical discounted future net
revenues to be derived from these reserves and the disclosure of the
Standardized Measure information in accordance with the provisions of Statement
of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas
Producing Activities," see Note 10 "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 10
"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, 2000:
Productive Wells
------------------------------------------------------
Developed Acreage Oil Gas Total
------------------ -------------- ------------- ---------------
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
U.S.......................... 638,202 419,625 2,705 2,375 887 452 3,592 2,827
Argentina.................... 529,072 365,097 1,301 1,285 - - 1,301 1,285
Bolivia...................... 99,458 88,339 - - 16 15 16 15
Ecuador...................... 33,623 24,889 8 6 - - 8 6
Canada....................... 103,875 40,668 57 27 99 51 156 78
--------- ------- ----- ----- ----- --- ----- -----
Total...................... 1,404,230 938,618 4,071 3,693 1,002 518 5,073 4,211
========= ======= ===== ===== ===== === ===== =====
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, 2000, the Company held the following undeveloped acres
located in the United States, Argentina, Bolivia, Ecuador, Canada, Yemen and
Trinidad. With respect to such United States acreage held under leases, 208,800
gross (69,692 net) acres are held under leases with primary terms that expire at
varying dates through December 31, 2004, unless commercial production is
commenced. The Company has the option to relinquish portions of the undeveloped
acreage in Argentina at various dates through 2007 or pay increased mining
royalties. The Bolivia and Yemen acreages are held under concessions with
primary terms that expire at varying dates in 2001. Of the Ecuador acreage,
494,200 acres (gross and net) relate to Block 19 which the Company is in the
process of relinquishing to the government. The remainder of the Ecuador
concessions have primary terms that expire at various dates in 2002 and 2006
unless there is a commercial discovery. The Canada acreage is held under leases
with primary terms that expire at varying dates through 2009, unless commercial
production is commenced.
Gross Net
State/Country Acres Acres
---------------------------------------------------------- -------- -------
California................................................ 8,615 7,934
Colorado.................................................. 1,248 468
Kansas.................................................... 320 179
Louisiana................................................. 2,327 1,688
North Dakota.............................................. 38,455 23,717
Oklahoma.................................................. 52,579 24,548
Texas..................................................... 109,595 15,658
Wyoming................................................... 10,239 3,618
--------- ---------
Total U.S.............................................. 223,378 77,810
Argentina................................................. 832,965 832,965
Bolivia................................................... 485,552 485,552
Ecuador................................................... 1,276,254 1,073,693
Canada.................................................... 397,136 125,913
Yemen..................................................... 1,108,019 831,014
Trinidad.................................................. 28,426 10,233
--------- ---------
Total Company.......................................... 4,351,730 3,437,180
========= =========
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:
Years Ended December 31,
---------------------------------------
Production: 2000 1999 1998
--------- ---------- ----------
Oil (MBbls) -
U.S............................ 9,044 8,643 9,912
Argentina...................... 9,406 7,560 6,322
Ecuador........................ 1,261 597 78
Bolivia........................ 131 77 122
Canada......................... 19 - -
Total....................... 19,861 16,877 16,434
Gas (MMcf) -
U.S............................ 35,764 39,150 42,176
Argentina...................... 8,705 4,682 -
Bolivia........................ 8,948 4,522 5,062
Canada......................... 312 - -
Total....................... 53,729 48,354 47,238
Total MBOE......................... 28,816 24,936 24,307
Average Sales Prices:
Oil (per Bbl) -
U.S............................ $ 22.85(a) $ 15.92(b) $ 11.20
Argentina (c).................. 28.25 18.00 10.86
Ecuador (c).................... 24.27 17.28 7.34
Bolivia (c).................... 29.62 19.05 12.56
Canada......................... 26.05 - -
Total (c)................... 25.55(a) 16.92(b) 11.06
Gas (per Mcf) -
U.S............................ $ 3.91 $ 2.06 $ 1.97
Argentina...................... 1.79 1.34 -
Bolivia (c).................... 1.75 .96 1.04
Canada......................... 5.73 - -
Total (c)................... 3.22 1.89 1.87
Production Costs (per BOE):
U.S................................ $ 6.42 $ 5.31 $ 5.57
Argentina (c)...................... 4.87 4.30 4.67
Bolivia (c)........................ 2.33 3.64 2.98
Ecuador (c)........................ 4.85 3.82 4.57
Canada............................. 7.09 - -
Total (c)...................... 5.54 4.88 5.23
____________________
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, transportation and storage costs, maintenance and
repairs, labor and utilities.
(a) Reflects the impact of oil hedges which reduced the Company's 2000
U.S. and total average oil prices per Bbl by $4.10 and $1.86,
respectively.
(b) 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.
(c) The 1999 and 1998 amounts have been restated to reflect the reclass of
transportation and storage costs to lease operating costs.
16
Drilling Activity
During the periods indicated, the Company drilled or participated in
the drilling of the following exploratory and development wells:
YEARS ENDED DECEMBER 31,
----------------------------------------------
2000 1999 1998
-------------- ----------- -------------
Gross Net Gross Net Gross Net
------- ----- ----- ----- ----- ------
Development:
United States -
Productive.............. 21 14.93 6 1.94 34 24.94
Non-Productive.......... 2 1.68 - - 4 1.78
Argentina - 40 40.00 10 10.00 54 54.00
Productive.............. 1 1.00 1 1.00 2 2.00
Non-Productive..........
Bolivia - - - 1 1.00 - -
Productive.............. - - - - - -
Non-Productive.......... ---- ----- --- ----- --- ------
64 57.61 18 13.94 94 82.72
Total................. ==== ===== === ===== === ======
Exploratory:
United States -
Productive.............. 14 6.17 1 0.47 22 15.17
Non-Productive.......... 4 2.02 11 5.56 13 3.78
Argentina -
Productive.............. - - - - 2 2.00
Non-Productive.......... - - - - - -
Bolivia
Productive.............. - - 7 7.00 1 1.00
Non-Productive.......... 3 3.00 - - - -
Ecuador -
Productive.............. - - - - - -
Non-Productive.......... 1 1.00 - - - -
Canada -
Productive.............. - - - - - -
Non-Productive.......... 1 0.45 - - - -
Yemen -
Productive.............. - - - - - -
Non-Productive.......... 1 0.75 - - - -
---- ----- --- ----- --- ------
24 13.39 19 13.03 38 21.95
==== ===== === ===== === ======
Total:
Productive.............. 75 61.10 25 20.41 113 97.11
Non-Productive.......... 13 9.90 12 6.56 19 7.56
---- ----- ---- ----- ---- ------
Total................. 88 71.00 37 26.97 132 104.67
==== ===== ==== ===== ==== ======
_________________
The above well information excludes wells in which the Company has only a
royalty interest.
At December 31, 2000, the Company was a participant in the drilling,
completion or evaluation of 22 gross (19.45 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, equipment or tools. Higher prices
for oil and gas production, however, may cause competition for these items as
well as drilling and workover rigs in particular to increase, and may result in
increased costs of operations and impact the timing of planned projects.
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, 636 and 637
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 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.
In 2000, the FERC issued Order 637 in order to make short-term capacity
release more viable and to foster the market becoming more competitive and
transparent and prices more efficient. Among other things, Order 637 removes
the price cap on short-term capacity releases, allows peak/offpeak rates for
short-term services to better reflect seasonal market demands and permits
pipelines to propose term-differentiated rates to better reflect the underlying
contracting risks of both pipelines and shippers.
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 most 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, Canada 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 239 full-time people in its Tulsa office
whose functions are associated with management, engineering, geology, land and
legal, accounting, financial planning, and administration. In addition,
approximately 188 full-time employees are responsible for the supervision and
operation of its U.S. field activities. The Company also has approximately 271
employees for the management and operation of its properties in Argentina,
Bolivia, Ecuador, Canada and Yemen. The Company believes its relations with its
employees are excellent.
20
Item 3. Legal Proceedings.
The Company is a named defendant in lawsuits and is a party in governmental
proceedings from time to time arising in the ordinary course of business. While
the outcome of such 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, 2000.
Item 4A. Executive Officers of the Registrant.
The following table sets forth as of the date hereof certain
information regarding the executive officers of the Company. Officers are
elected annually by the Board of Directors and serve at its discretion.
NAME AGE POSITION
- ---------------------------------- ----- --------------------------------------------------------------
Charles C. Stephenson, Jr......... 64 Director and Chairman of the Board of Directors
S. Craig George................... 48 Director, President and Chief Executive Officer
William L. Abernathy.............. 49 Director, Executive Vice President and Chief Operating Officer
William C. Barnes................. 46 Director, Executive Vice President, Chief Financial Officer,
Secretary and Treasurer
William E. Dozier................. 48 Senior Vice President - Operations
Robert W. Cox..................... 55 Vice President - General Counsel
Andy R. Lowe...................... 49 Vice President - Marketing
Michael F. Meimerstorf............ 44 Vice President and Controller
Robert E. Phaneuf................. 54 Vice President - Corporate Development
Larry W. Sheppard................. 46 Vice President - International
Martin L. Thalken................. 40 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 41 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.
21
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.
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 September 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.
22
Mr. Phaneuf has been Vice President--Corporate Development of the Company
since October 1995. From June 1995 to October 1995, he was employed in the
Corporate Finance Group of Arthur Andersen LLP, specializing in energy industry
corporate finance activities. From April 1993 to August 1994, he was Senior Vice
President and head of the Energy Research Group at Kemper Securities, an
investment banking firm. From 1988 until April 1993, he was employed by
Rauscher, Pierce Refsnes, Inc., an investment banking firm, as a Senior Vice
President, serving as an energy analyst involved in equity research. From 1978
to 1988, Mr. Phaneuf was Vice President of Kidder, Peabody, & Co., an investment
banking firm, serving as an energy analyst in the Research Department. From 1976
to 1978, he was employed by Schneider, Bernet, and Hickman, serving as an energy
analyst in the Research Department. From 1972 to 1976, he held the position of
Investment Advisor for First International Investment Management, a subsidiary
of NationsBank. He holds a B.A. Degree in Psychology and an M.B.A. Degree from
the University of Texas.
Mr. Sheppard has been Vice President--International of the Company since
November 1994. From June 1984 to August 1994, he was employed by Santa Fe
Minerals serving as Manager--Acquisitions & Special Projects, Manager--
International Operations, and in various other management and supervisory
capacities. From August 1977 to June 1984, he was employed by Amoco Production
Company serving in various engineering and supervisory capacities. He has a
B.S. Degree in Petroleum Engineering from Texas Tech University.
Mr. Thalken has been Vice President--Acquisitions of the Company since
December 1997. He was Acquisitions Technical Manager of the Company from May
1995 to December 1997 and an acquisitions engineer with the Company from January
1992 to May 1995. From October 1990 to December 1991, he was employed by Enron
Oil and Gas Company, serving as a production engineer. From May 1983 to
September 1990, he was employed by Exxon Company, USA, in various engineering
and supervisory capacities. He has a B.S. Degree in Mechanical Engineering from
the University of Kansas.
23
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
The Company's common stock commenced trading on the New York Stock Exchange
on August 3, 1990, under the symbol "VPI." The following table sets forth the
high and low sale prices per share of the Company's common stock, as reported in
the New York Stock Exchange composite transactions, and the cash dividends paid
per share of common stock, for the periods indicated:
Dividends
High Low Paid
-------- -------- ---------
2000
----
First Quarter.............. $20.5625 $11.1875 $.025
Second Quarter............. 25.1250 18.1250 .025
Third Quarter.............. 24.7500 16.8125 .03
Fourth Quarter............. 27.9375 18.1250 .03
1999
----
First Quarter.............. $10.0625 $ 4.0625 $.025
Second Quarter............. 12.2500 8.1250 -
Third Quarter.............. 15.1250 10.1250 -
Fourth Quarter............. 13.7500 9.0625 -
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, 2000, the common stock was held by 107 holders of record and
approximately 10,000 beneficial owners.
The Company began paying a quarterly cash dividend in the fourth quarter of
1992 and continued paying a regular quarterly cash dividend through the first
quarter of 1999. 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, and expects to continue paying a regular quarterly cash dividend.
However, 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 $375 million plus 75
percent of net proceeds of any future equity offerings less any impairment
writedowns required by GAAP or by the Securities and Exchange Commission and
excluding any impact related to SFAS No. 133. Net Worth was approximately $613
million at December 31, 2000.
24
Item 6. Selected Financial Data.
SELECTED FINANCIAL AND OPERATING DATA
Years Ended December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
-----------------------------------------------------------
(In thousands, except per share amounts and operating data)
Income Statement Data:
Oil and gas sales (a)...................................... $ 680,350 $ 376,924 $ 270,251 $ 358,366 $ 260,746
Gas marketing revenues..................................... 128,836 60,275 54,108 45,981 31,920
Gathering revenues......................................... 19,998 6,955 7,741 18,063 20,508
Total revenues (a)......................................... 806,181 502,928 333,323 420,476 314,525
Operating expenses (a)..................................... 300,477 184,367 184,932 176,552 140,816
Exploration costs.......................................... 25,242 14,674 24,056 12,667 10,192
Impairment of oil and gas properties....................... 225 3,306 70,913 8,785 -
Depreciation, depletion and amortization................... 100,109 107,807 108,975 96,307 66,861
Interest................................................... 48,437 58,665 43,680 36,762 30,109
Net income (loss).......................................... 195,893 73,371 (87,665) 54,954 33,188
Income (loss) per share before cumulative
effect of change in accounting principle:
Basic................................................. 3.15 1.27 (1.69) 1.07 .69
Diluted............................................... 3.08 1.24 (1.69) 1.05 .68
Income (loss) per share:
Basic................................................. 3.13 1.27 (1.69) 1.07 .69
Diluted............................................... 3.06 1.24 (1.69) 1.05 .68
Dividends declared per share............................... .14 - .09 .07 .055
-----------------------------------------------------------
Balance Sheet Data (end of year):
Total assets............................................... $1,338,397 $1,168,134 $1,014,175 $ 915,394 $ 766,816
Long-term debt, less current portion....................... 464,229 625,318 672,507 451,096 372,390
Stockholders' equity....................................... 624,857 431,129 273,958 337,578 236,406
-----------------------------------------------------------
Operating Data:
Production:
Oil (MBbls)................................................ 19,861 16,877 16,434 15,457 11,939
Gas (MMcf)................................................. 53,729 48,354 47,238 42,691 32,366
-----------------------------------------------------------
Average Sales Prices:
Oil (per Bbl).............................................. $ 25.55 $ 16.92 $ 11.06 $ 17.20 $ 16.93
Gas (per Mcf).............................................. 3.22 1.89 1.87 2.17 1.81
-----------------------------------------------------------
Proved Reserves (end of year):
Oil (MBbls)................................................ 318,560 303,190 164,457 187,768 178,296
Gas (MMcf)................................................. 1,023,208 988,989 806,833 552,163 382,846
Total proved reserves (MBOE)............................... 489,095 468,022 298,929 279,795 242,104
-----------------------------------------------------------
Present value of estimated future net revenues
before income taxes discounted at 10 percent
(in thousands):
Oil and gas properties................................ $4,338,616 $2,989,626 $ 703,211 $1,222,560 $1,807,137
Gathering systems and plant........................... 14,188 13,764 4,493 5,940 10,364
Standardized measure of discounted future
net cash flows (in thousands)............................ 2,951,121 2,247,237 648,222 1,016,645 1,392,841
-----------------------------------------------------------
_____________________
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.
(a) These amounts have been restated to reflect the reclass of
transportation and storage costs to lease operating costs.
25
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:
Years Ended December 31,
-----------------------------------
2000 1999 1998
------- ------- -------
Production:
Oil (MBbls) -
U.S.................... 9,044 8,643 9,912
Argentina.............. 9,406 7,560 6,322
Ecuador................ 1,261 597 78
Bolivia................ 131 77 122
Canada................. 19 - -
Total................ 19,861(a) 16,877 16,434
Gas (MMcf) -
U.S.................... 35,764 39,150 42,176
Argentina.............. 8,705 4,682 -
Bolivia................ 8,948 4,522 5,062
Canada................. 312 - -
Total................ 53,729 48,354 47,238
Total MBOE................. 28,816 24,936 24,307
Average Sales Prices:
Oil (per Bbl) -
U.S.................... $ 22.85(b) $ 15.92(c) $ 11.20
Argentina.............. 28.25 18.00 10.86
Ecuador................ 24.27 17.28 7.34
Bolivia................ 29.62 19.05 12.56
Canada................. 26.05 - -
Total................ 25.55(b) 16.92(c) 11.06
Gas (per Mcf) -
U.S.................... $ 3.91 $ 2.06 $ 1.97
Argentina.............. 1.79 1.34 -
Bolivia................ 1.75 .96 1.04
Canada................. 5.73 - -
Total................ 3.22 1.89 1.87
_____________________
(a) Total production for the year, before the impact of changes in
inventories (accounted for as a result of the mandated change in
accounting principle), was 19,921 MBbls (Argentina-9,512 MBbls,
Ecuador-1,227 MBbls, Bolivia-119 MBbls).
(b) Reflects the impact of oil hedges which reduced the Company's 2000 U.S.
and total average oil prices per Bbl by $4.10 and $1.86, respectively.
(c) 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.
26
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. Production from the Company's Block 14 and Block
17 in Ecuador is sold to various third party purchases at West Texas
Intermediate spot prices 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 along with increasing demand. This increase continued in 2000
with the Company experiencing a gain of 51 percent in its average oil price over
the 1999 average oil price. The Company participated in oil hedges covering 9.3
MMBbls and 1.84 MMBbls during 2000 and 1999, respectively. The impact of these
hedges reduced the Company's U.S. average oil price for 2000 and 1999 by $4.10
and 11 cents to $22.85 and $15.92 per Bbl, respectively, and its overall average
oil price by $1.86 and six cents to $25.55 and $16.92 per Bbl, respectively.
The Company was not a party to any oil hedges in 1998.
The Company's realized average oil price for 2000 (before hedges) was
approximately 91 percent of the NYMEX reference price compared to 88 percent in
1999 and 77 percent in 1998.
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
2000 and 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 its
El Huemul concession, however, this contract expires at the end of 2001. The
Company anticipates securing long-term contracts for this gas during 2001 and it
expects future gas prices to be at lower levels than the current contract. The
Company's Canada gas is generally sold at spot market prices as reflected by the
AECO gas price index. The Company's total average gas price for 2000 was 70
percent higher than 1999's and 1999 was one percent higher than 1998'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. The Company has entered into
various oil hedges (swap agreements) for a total of 3.5 MMBbls of oil at a
weighted average price of $30.76 per Bbl (NYMEX reference price) for calendar
year 2001. 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 2000 oil production, a change in the average oil
price realized, before hedges, 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 $12.7 million and $19.4 million, respectively. A 10 cent per Mcf
change in the average price realized, before hedges, 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 $3.3 million and $5.3 million, respectively, based
on 2000 gas production.
Period to Period Comparison
Year Ended December 31, 2000, Compared to Year Ended December 31, 1999
The Company reported net income of $195.9 million for the year ended
December 31, 2000, compared to net income of $73.4 million for the same period
in 1999. A 51 percent increase in average oil prices and a 70 percent increase
in average gas prices received by the Company and a 16 percent increase in
production on a BOE basis were primarily responsible for the significant
increase in its net income.
27
Oil and gas sales increased $303.5 million (81 percent), to $680.4 million
for 2000 from $376.9 million for 1999. A 51 percent increase in average oil
prices combined with an 18 percent increase in oil production accounted for an
increase of $221.9 million. A 70 percent increase in average gas prices,
coupled with an 11 percent increase in gas production, accounted for an
additional increase of $81.6 million. The Company had an 18 percent increase in
oil production primarily as a result of Argentina production added through the
1999 acquisitions of the El Huemul concession (the "El Huemul Acquisition") and
additional working interests in its two producing concessions in Ecuador
(collectively, the "1999 Acquisitions") and the exploitation activities in
Argentina. The Company's gas production rose by 11 percent due primarily to the
gas production from the El Huemul concession acquired in July 1999 and increased
production in Bolivia as a result of increased takes into the Bolivia-to-Brazil
pipeline. This increase more than offset the decline in U.S. gas production as
a result of the December 1999 sale of certain oil and gas properties located in
northern California's Sacramento Basin area.
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 1999 results of operations as the majority of the
divestitures occurred during December 1999. In 2000, the Company recorded a
loss on the disposition of assets, primarily as a result of post-closing
adjustments on 1999 dispositions, of $1.7 million.
As a result of an unfavorable decision by the Supreme Court of Argentina,
the Company recorded as other expense in 2000 a non-recurring charge of $25.1
million ($16.3 million net of tax). No similar charge existed in 1999. For
further information regarding this litigation see Note 4 "Commitments and
Contingencies" to the consolidated financial statements included elsewhere in
this Form 10-K.
Lease operating expenses, including production taxes, increased $37.9
million (31 percent), to $159.6 million for 2000 from $121.7 million for 1999.
The increase in lease operating expenses is due primarily the 1999 Acquisitions
and an increase in production taxes due to higher product prices. Lease
operating expenses per equivalent barrel produced increased to $5.54 in 2000
from $4.88 for the same period in 1999. As the result of a Securities and
Exchange Commission mandate, transportation and storage costs billed to the
Company have been reclassified to lease operating expenses for all periods
shown. These costs had been previously reported as a reduction of oil and gas
revenues consistent with oil and gas industry practice. This reclassification
added $0.25 and $0.40 to the reported lease operating expense per BOE for the
years 1999 and 2000, respectively.
Exploration costs increased $10.5 million (71 percent), to $25.2 million
for 2000 from $14.7 million for 1999. During 2000, the Company's exploration
costs included $24.5 million for unsuccessful exploratory drilling and leasehold
impairments associated with a much higher exploration capital budget and the
drilling of an increased number of higher-risk exploratory wells during the
year, and $0.7 million for seismic and other geological and geophysical costs.
Due to reduced cash flow levels, the Company significantly reduced its capital
budget for 1999. Exploration expenses for 1999 consisted of $5.1 million for
seismic data acquisition, $4.4 million for unsuccessful exploratory drilling and
$5.2 million for lease impairments and other geological and geophysical costs.
General and administrative expenses increased $5.0 million (14 percent), to
$41.4 million for 2000 from $36.4 million for 1999, due primarily to personnel
additions in conjunction with increased capital expenditures, the 1999
Acquisitions and the delay of 1999 annual compensation adjustments from January
until August. The Company's G&A per BOE for 2000 was $1.44 compared to $1.46
for 1999.
Depreciation, depletion and amortization decreased $7.7 million (7
percent), to $100.1 million for 2000 from $107.8 million for 1999, despite a 16
percent increase in total production due primarily to higher reserves resulting
from higher product prices used throughout the year in the DD&A calculation.
The Company's average DD&A rate per equivalent barrel produced decreased from
$4.15 in 1999 to $3.33 in 2000.
Interest expense decreased $10.3 million (17 percent), to $48.4 million for
2000 from $58.7 million for 1999, due primarily to a 25 percent decrease in the
Company's total average outstanding debt due to the Company's significant
repayment of outstanding debt as a result of significantly increased cash flow
and the $87.9 million of cash proceeds from the sale of oil and gas properties
in late 1999. The Company's average interest rate for its outstanding debt for
2000 was 8.87 percent compared to 8.14 percent in 1999.
28
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 $106.6 million (39 percent), to $376.9 million
for 1999 from $270.3 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 $103.7 million. A one percent increase in average gas prices,
coupled with a two percent increase in gas production, accounted for an
additional increase of $2.9 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 limited
gas demand from the developing export market in Brazil.
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 $5.4
million (4 percent), to $121.7 million for 1999 from $127.1 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 $4.88 in 1999
from $5.23 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.
29
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.
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.
Capital Expenditures
During 2000, the Company's total oil and gas capital expenditures were
$257.7 million. In North America, the Company's non-acquisition oil and gas
capital expenditures totaled $63.0 million. Exploration activities accounted
for $29.9 million of the North America capital expenditures with exploitation
activities contributing $33.1 million. During 2000, the Company's international
non-acquisition oil and gas capital expenditures totaled $103.2 million,
consisting of $49.5 million in Argentina on exploitation activities, $28.7
million in Bolivia on exploitation and exploration activities, and $25.0 million
in Yemen and Ecuador, principally on exploration. Total acquisition capital
expenditures for 2000 of $91.4 million included $40.1 million for the
acquisition of the Cuyo Basin concession in Argentina and $47.9 million
allocated to proved properties as part of the acquisition of 100 percent of the
outstanding common stock of Cometra Energy (Canada), Ltd., a privately-held
Canadian company.
As of December 31, 2000, the Company had total unevaluated oil and gas
property costs of approximately $47.2 million consisting of undeveloped
leasehold costs of $30.0 million and exploratory drilling in progress of $17.2
million. Approximately $20.5 million of the unevaluated costs are associated
with the Company's Yemen drilling program. Future exploration expense and
earnings may be impacted to the extent any of the exploratory drilling is
determined to be unsuccessful.
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 2000 non-acquisition capital expenditures of $166.2 million,
approximately 56 percent was spent on exploitation activities, including
development and infill drilling, and approximately 44 percent was spent on
exploration activities, a part of which satisfied all of the Company's previous
exploration commitments in Bolivia, Ecuador and Yemen. The Company's
preliminary capital expenditure budget for 2001 is currently set at $285
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.
30
The Company's recent capital expenditure history is as follows:
Years Ended December 31,
---------------------------------------------
(In thousands) 2000 1999 1998
----------- ----------- -----------
Acquisition of oil and gas reserves......................... $ 91,448 $ 166,787 $ 105,023
Drilling.................................................... 121,911 46,280 114,773
Acquisition of undeveloped acreage and seismic.............. 18,084 12,742 35,024
Workovers and recompletions................................. 25,811 10,749 29,939
Acquisition and construction of gathering systems........... 299 680 1,831
Other....................................................... 419 927 1,601
------------ ----------- -----------
Total..................................................... $ 257,972 $ 238,165 $ 288,191
============ =========== ===========
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 Second Amended and Restated Credit Agreement dated November 30,
2000, (the "Bank Facility"), certain banks have provided to the Company an
unsecured revolving credit facility. The Bank Facility establishes a borrowing
base (currently $625 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.
Outstanding advances under the Bank Facility bear interest payable
quarterly at a floating rate based on Bank of Montreal's alternate base rate (as
defined) or, at the Company's option, at a fixed rate for up to six months based
on the Eurodollar market rate ("LIBOR"). The Company's interest rate increments
above the alternate base rate and LIBOR vary based on the level of outstanding
senior debt to the borrowing base. As of February 28, 2001, the Company had
elected a fixed rate based on LIBOR for a substantial portion of its outstanding
advances, which resulted in an average interest rate of approximately 6.75
percent per annum. In addition, the Company must pay a commitment fee ranging
from 0.325 to 0.50 percent per annum on the unused portion of the banks'
commitment.
31
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. Final maturity of the Bank Facility is November
30, 2005.
At February 28, 2001, the unused portion of the Bank Facility was
approximately $511 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.
The Company's internally generated cash flow, results of operations and
financing for its operations are dependent on oil and gas prices. For 2000,
approximately 69 percent of the Company's production was oil. Realized oil
prices for the year increased by 51 percent as compared to 1999 and total
production on a BOE basis increased by 16 percent. As a result, the Company's
earnings and cash flows have been materially increased compared to 1999. 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
$68.9 million and $6.0 million for 2000 and 1999, respectively, 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.
The Company has an estimated U.S. Federal alternative minimum tax ("AMT")
credit carryforward of approximately $4.8 million at December 31, 2000, 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 fully utilized its $60.0 million U.S.
Federal regular tax net operating loss ("NOL") carryforward and its AMT credit
carryforward in 2000. The Company has a Bolivian income tax NOL of
approximately $65 million which does not expire and can be used to offset future
Bolivian tax liabilities of the Company.
Change in Accounting Principles
The Company adopted Securities and Exchange Commission Staff Accounting
Bulletin No. 101, Revenue Recognition ("SAB No. 101"), in the fourth quarter of
2000, effective January 1, 2000. SAB No. 101 requires oil inventories held in
storage facilities to be valued at cost. Cost is defined as lifting costs plus
depreciation, depletion and amortization. The Company previously followed
industry practice by valuing oil inventories at market. The cumulative effect
reduced net income by $1.4 million, net of income tax effects of $0.6 million.
Previously reported quarters during the year 2000 have been restated to give
effect to this change in accounting principle. Additional volatility in
quarterly and annually reported earnings may occur in the future as a result of
the required adoption of SAB No. 101 and fluctuations in oil inventory levels.
32
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended in June 1999 by Statement No. 137, Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB Statement No. 133 and in June 2000 by Statement No. 138, Accounting
for Certain Derivative Instruments and Certain Hedging Activities - an amendment
of FASB Statement No. 133 ("SFAS No. 133"). SFAS No. 133 establishes accounting
and reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
No. 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement. Companies
must formally document, designate and assess the effectiveness of transactions
that receive hedge accounting.
Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a
transition receivable of $16.3 million related to cash flow hedges in place that
are used to reduce the volatility in commodity prices for portions of the
Company's forecasted oil production. Additionally, the Company recorded, net of
tax, an adjustment to accumulated other comprehensive income (Stockholders'
Equity section of the balance sheet) of $10.6 million. The amount recorded to
accumulated other comprehensive income will be relieved over time and taken to
the income statement as the physical transactions being hedged are finalized.
Foreign Operations
For information on the Company's foreign operations, see "Foreign Currency
and Operations Risk" under Item 7A of this Form 10-K.
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 also entered into additional oil hedging contracts covering 3.9 MMBbls
for various periods during 2000. In total, the Company entered into oil hedging
contracts covering 2000 production of 9.3 MMBbls of oil at a weighted average
NYMEX reference price of $26.85 per Bbl. During 2000, the Company entered into
various oil hedges (swap agreements) for a total of 3.5 MMBbls of oil at a
weighted average NYMEX reference price of $30.76 per Bbl for the calendar year
2001. At December 31, 2000, the Company would have received approximately $16.3
million to terminate its oil swap agreements then in place. The Company
continues to monitor oil and gas prices and may enter into additional oil and
gas hedges or swaps in the future.
33
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, 2000, the amount of
the Company's fixed rate debt was approximately 86 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:
FAIR
Value
There- at
2001 2002 2003 2004 2005 After Total 12/31/00
------- -------- ------- ------- ------- --------- --------- ---------
Long-Term Debt:
Fixed rate (in thousands) - - - - $149,796 $249,433 $399,229 $ 410,155
Average interest rate - - - - 9.0% 9.3% 9.2% -
Variable rate (in thousands) - - - - $ 65,000 - $ 65,000 $ 65,000
Average interest rate - - - - (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 2.0 percent.
Current increment above LIBOR is 1.125 percent.
Foreign Currency and Operations Risk
International investments represent, and are expected to continue to
represent, a significant portion of the Company's total assets. The Company has
international operations in Argentina, Bolivia, Ecuador, Canada and Yemen. For
2000, the Company's operations in Argentina accounted for approximately 32
percent of the Company's revenues, 45 percent of the Company's operating income
(before impairments of oil and gas properties) and 34 percent of its total
assets. During 2000, the Company's operations in Argentina represented its only
foreign operations accounting for more than 10 percent of its revenues or
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.
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.
34
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, 2000, was
US$1:Bs 6.40. 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 new administration in Ecuador, led by President Gustavo Naboa, is
undertaking a broad-based program of economic reform to stem the decline in
economic activity and to lay the basis for renewed economic growth. The legal
basis for many of the reforms is the Ley Fundamental para la Transformacion
Economica del Ecuador (the "economic transformation law") enacted in March 2000,
which mandated dollarization of the economy. As a result of this reform, all of
the Company's Ecuadorian revenues and costs are U.S. dollar based. President
Naboa continues to seek majority support and to overcome legal challenges
necessary for the second phase of the economic transformation law (known as
Trole II), which would bring significant tax and labor reform and a defined
privatization program to increase inflows of foreign direct investment.
With the Cometra Acquisition in December 2000, the Company now has
producing operations in Canada. The Company views the operating environment in
Canada as stable and the economic stability as good. All of the Company's
Canadian revenues and costs are denominated in Canadian dollars and while the
value of the Canadian dollar does fluctuate in relation to U.S. dollar, the
Company believes that any currency risk associated with its Canadian operations
would not have a material impact on the Company's financial position or results
of operations.
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 2001 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."
35
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."
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, 2000, filed August 11, 2000).
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).
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).
36
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* Amendment No. 6 to Vintage Petroleum, Inc. 1990 Stock Plan dated
March 17, 2000 (Filed as Exhibit A to the Company's Proxy Statement
for Annual Meeting of Stockholders dated March 30, 2000).
10.10* 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).
10.11* 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")).
10.12* 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).
10.13* 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).
10.14* Form of Non-Qualified Stock Option Agreement for non-employee
directors under the Vintage Petroleum, Inc. 1990 Stock Plan (Filed
as Exhibit 10.13 to the Company's report on Form 10-K for the year
ended December 31, 1999, filed March 13, 2000).
37
10.15 Second Amended and Restated Credit Agreement dated as of November
30, 2000, among the Company, as borrower, and certain commercial
lending institutions, as lenders, Bank of Montreal, as
administrative agent, Bank of America, N.A., as syndication agent,
Societe Generale, Southwest Agency, as documentation agent, and ABN
AMRO Bank, N.A., as managing 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.
____________________
* Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K.
Form 8-K dated October 12, 2000, was filed October 19, 2000, to report
under Item 5 the Company's recent hedging activities and the Company's
press releases dated October 12 and 17, 2000, announcing Yemen drilling
update and Ecuador exploratory well results.
No other reports on Form 8-K were filed during the fourth quarter of the
fiscal year ended December 31, 2000.
38
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 9, 2001 By: /s/ C. C. Stephenson, Jr.
------------------------------
C. C. Stephenson, Jr.
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated:
Signature Title Date
--------- ----- ----
/s/ C. C. Stephenson, Jr. Director and Chairman of the Board March 9, 2001
- ------------------------------
C. C. Stephenson, Jr.
/s/ S. Craig George Director, President and March 9, 2001
- ------------------------------
S. Craig George Chief Executive Officer
(Principal Executive Officer)
/s/ William L. Abernathy Director, Executive Vice President March 9, 2001
- ------------------------------
William L. Abernathy and Chief Operating Officer
/s/ William C. Barnes Director, Executive Vice President, March 9, 2001
- ------------------------------
William C. Barnes Chief Financial Officer, Secretary and
Treasurer (Principal Financial Officer)
/s/ Bryan H. Lawrence Director March 9, 2001
- ------------------------------
Bryan H. Lawrence
/s/ John T. McNabb, II Director March 9, 2001
- ------------------------------
John T. McNabb, II
/s/ Michael F. Meimerstorf Vice President and Controller March 9, 2001
- ------------------------------
Michael F. Meimerstorf (Principal Accounting Officer)
39
INDEX TO FINANCIAL STATEMENTS
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
Page
----
AUDITED FINANCIAL STATEMENTS OF VINTAGE PETROLEUM, INC. AND SUBSIDIARIES:
Report of Independent Public Accountants........................................................................... 41
Consolidated Balance Sheets as of December 31, 2000 and 1999....................................................... 42
Consolidated Statements of Operations for the years ended December 31, 2000, 1999 and 1998......................... 43
Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2000,
1999 and 1998................................................................................................. 44
Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998......................... 45
Notes to Consolidated Financial Statements for the years ended December 31, 2000, 1999 and 1998.................... 46
40
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,
2000 and 1999, and the related consolidated statements of operations, changes in
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. 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, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 16, 2001
41
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except shares
and per share amounts)
ASSETS
December 31,
----------------------
2000 1999
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents........................................................ $ 19,506 $ 42,687
Accounts receivable -
Oil and gas sales.............................................................. 146,770 87,484
Joint operations............................................................... 6,267 5,211
Prepaids and other current assets................................................ 13,946 19,109
---------- ----------
Total current assets........................................................... 186,489 154,491
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method................................ 1,734,003 1,521,672
Oil and gas gathering systems and plants......................................... 19,252 15,453
Other............................................................................ 19,636 17,287
---------- ----------
1,772,891 1,554,412
Less accumulated depreciation, depletion and amortization........................ 667,837 583,060
---------- ----------
1,105,054 971,352
---------- ----------
OTHER ASSETS, net.................................................................. 46,854 42,291
---------- ----------
$1,338,397 $1,168,134
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Revenue payable.................................................................. $ 60,519 $ 25,899
Accounts payable - trade......................................................... 43,225 26,118
Current income taxes payable..................................................... 43,187 5,875
Other payables and accrued liabilities........................................... 65,361 36,010
---------- ----------
Total current liabilities................................................... 212,292 93,902
---------- ----------
LONG-TERM DEBT..................................................................... 464,229 625,318
---------- ----------
DEFERRED INCOME TAXES.............................................................. 33,252 15,780
---------- ----------
OTHER LONG-TERM LIABILITIES........................................................ 3,767 2,005
---------- ----------
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, 160,000,000 and 80,000,000 shares authorized,
62,801,416 and 62,407,866 shares issued and outstanding........................ 314 312
Capital in excess of par value................................................... 319,893 314,490
Retained earnings................................................................ 303,449 116,327
Accumulated other comprehensive income........................................... 1,201 -
---------- ----------
624,857 431,129
---------- ----------
$1,338,397 $1,168,134
========== ==========
The accompanying notes are an integral part of these statements.
42
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For The Years Ended December 31,
-------------------------------------------
2000 1999 1998
--------- --------- ---------
REVENUES:
Oil and gas sales............................................................... $ 680,350 $ 376,924 $ 270,251
Gas marketing................................................................... 128,836 60,275 54,108
Oil and gas gathering........................................................... 19,998 6,955 7,741
Gain (loss) on disposition of assets............................................ (1,731) 54,991 -
Other income (expense).......................................................... (21,272) 3,783 1,223
--------- --------- ---------
806,181 502,928 333,323
--------- --------- ---------
COSTS AND EXPENSES:
Lease operating, including production taxes..................................... 159,638 121,664 127,114
Exploration costs............................................................... 25,242 14,674 24,056
Impairment of oil and gas properties............................................ 225 3,306 70,913
Gas marketing................................................................... 123,787 57,550 51,560
Oil and gas gathering........................................................... 17,052 5,153 6,258
General and administrative...................................................... 41,416 36,409 31,996
Depreciation, depletion and amortization........................................ 100,109 107,807 108,975
Interest........................................................................ 48,437 58,665 43,680
--------- --------- ---------
515,906 405,228 464,552
--------- --------- ---------
Income (loss) before income taxes and cumulative effect of change in
accounting principle.................................................... 290,275 97,700 (131,229)
--------- --------- ---------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current......................................................................... 68,858 5,954 (4,068)
Deferred........................................................................ 24,102 18,375 (39,496)
--------- --------- ---------
92,960 24,329 (43,564)
--------- --------- ---------
Income (loss) before cumulative effect of change in accounting principle... 197,315 73,371 (87,665)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, net of income taxes of $644.......................................... (1,422) - -
--------- --------- ---------
NET INCOME (LOSS).................................................................... $ 195,893 $ 73,371 $ (87,665)
========= ========= =========
BASIC INCOME (LOSS) PER SHARE:
Income (loss) before cumulative effect of change in accounting principle........ $ 3.15 $ 1.27 $ (1.69)
Cumulative effect of change in accounting principle............................. (0.02) - -
--------- --------- ---------
Net income (loss)............................................................... $ 3.13 $ 1.27 $ (1.69)
========= ========= =========
DILUTED INCOME (LOSS) PER SHARE:
Income (loss) before cumulative effect of change in accounting principle........ $ 3.08 $ 1.24 $ (1.69)
Cumulative effect of change in accounting principle............................. (0.02) - -
--------- --------- ---------
Net income (loss)............................................................... $ 3.06 $ 1.24 $ (1.69)
========= ========= =========
Weighted Average Common Shares Outstanding:
Basic........................................................................... 62,644 57,989 51,900
========= ========= =========
Diluted......................................................................... 63,963 59,315 51,900
========= ========= =========
The accompanying notes are an integral part of these statements.
43
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(In thousands, except per share amounts)
Capital Accumulated
Common Stock In Excess Other
------------------ of Par Retained Comprehensive
Shares Amount Value Earnings Income Total
------ -------- -------- -------- -------- --------
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
Comprehensive income:
Net income.............................................. - - - 195,893 - 195,893
Foreign currency translation adjustment................. - - - - 1,201 1,201
--------
Total comprehensive income.............................. - - - - - 197,094
--------
Exercise of stock options and
resulting tax effects................................... 393 2 5,403 - - 5,405
Cash dividends declared ($.14 per share).................. - - - (8,771) - (8,771)
------ -------- -------- -------- -------- --------
BALANCE AT DECEMBER 31, 2000................................ 62,801 $ 314 $319,893 $303,449 $ 1,201 $624,857
====== ======== ======== ======== ======== ========
The accompanying notes are an integral part of these statements.
44
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For The Years Ended December 31,
---------------------------------------------
2000 1999 1998
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)........................................................ $ 195,893 $ 73,371 $ (87,665)
Adjustments to reconcile net income (loss) to cash
provided by operating activities, net of companies acquired -
Depreciation, depletion and amortization.............................. 100,109 107,807 108,975
Impairment of oil and gas properties.................................. 225 3,306 70,913
Exploration costs..................................................... 25,242 14,674 24,056
Provision (benefit) for deferred income taxes......................... 24,102 18,375 (39,496)
Cumulative effect of change in accounting principle................... 1,422 - -
(Gain) loss on disposition of assets.................................. 1,731 (54,991) -
--------- --------- ---------
348,724 162,542 76,783
Decrease (increase) in receivables.................................... (56,179) (32,110) 9,353
Increase (decrease) in payables and accrued liabilities............... 99,514 29,500 (10,570)
Income tax refund receivable.......................................... - 5,323 (5,323)
Other................................................................. 3,628 (4,275) (22,476)
--------- --------- ---------
Cash provided by operating activities............................. 395,687 160,980 47,767
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties.................................................. (209,552) (229,606) (233,771)
Gathering systems and other............................................. (2,633) (2,669) (9,960)
Proceeds from sales of oil and gas properties............................ 998 78,241 588
Purchase of companies, net of cash acquired.............................. (46,199) - (10,651)
Other.................................................................... (4,132) 634 (3,042)
--------- --------- ---------
Cash used by investing activities................................. (261,518) (153,400) (256,836)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock..................................................... 3,492 83,685 884
Sale of 9 3/4% Senior Subordinated Notes Due 2009........................ - 146,000 -
Advances on revolving credit facility and other borrowings............... 70,388 50,213 232,736
Payments on revolving credit facility and other borrowings............... (224,343) (248,708) (20,711)
Dividends paid........................................................... (6,887) (1,328) (4,392)
--------- --------- ---------
Cash provided (used) by financing activities...................... (157,350) 29,862 208,517
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....................... (23,181) 37,442 (552)
CASH AND CASH EQUIVALENTS, beginning of year............................... 42,687 5,245 5,797
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of year..................................... $ 19,506 $ 42,687 $ 5,245
========= ========= =========
The accompanying notes are an integral part of these statements.
45
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2000, 1999 and 1998
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 98 percent of the Company's
operations are within the exploration and production segment based on 2000
operating income before impairments of oil and gas properties and losses 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 and Cuyo Basin of Argentina, the Chaco Basin in
Bolivia, Canada 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 1999 and 1998 amounts have been reclassified to conform with the
2000 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.
46
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, 2000, the Company assumed that the current oil and
gas price environment would return to more historical levels over a short period
of time and thereafter, escalate annually. The Company assumed 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 $0.2 million, $3.3 million and $70.9 million in 2000,
1999 and 1998, 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. Oil revenues are
recognized at the time of delivery to pipelines or at the time of physical
transfer to purchaser.
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 9.3 MMBbls during 2000.
The impact of these hedges reduced the Company's U.S. average oil price by $4.10
to $22.85 per Bbl and its overall average oil price by $1.86 to $25.55 per Bbl.
The Company participated in oil hedges covering 1.84 MMBbls during 1999. The
impact of the 1999 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 $16.92
per Bbl. The Company was not a party to any oil hedges in 1998.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended in June 1999 by Statement No. 137, Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB Statement No. 133 and in June 2000 by Statement No. 138, Accounting
for Certain Derivative Instruments and Certain Hedging Activities - an amendment
of FASB Statement No. 133 ("SFAS No. 133"). SFAS No. 133 establishes accounting
and reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
No. 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement. Companies
must formally document, designate and assess the effectiveness of transactions
that receive hedge accounting.
47
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a
transition receivable of $16.3 million related to cash flow hedges in place that
are used to reduce the volatility in commodity prices for portions of the
Company's forecasted oil production. Additionally, the Company recorded, net of
tax, an adjustment to accumulated other comprehensive income (Stockholders'
Equity section of the balance sheet) of $10.6 million. The amount recorded to
accumulated other comprehensive income will be relieved over time and taken to
the income statement as the physical transactions being hedged are finalized.
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.
During the years ended December 31, 2000, 1999 and 1998, the Company made
cash payments for interest totaling $48.3 million, $56.8 million and $42.4
million, respectively. Cash payments for U.S. income taxes of $19.8 million and
$1.5 million were made during 2000 and 1998, respectively. No cash payments for
U.S. income taxes were made during 1999. The Company made cash payments of $9.5
million during 2000 for foreign income taxes, primarily in Argentina. No cash
payments were made during 1999 for foreign income taxes. Cash payments of $1.3
million were made during 1998 for foreign tax withholdings.
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 ("Elf"). 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.
In December 2000, the Company purchased 100 percent of the outstanding
common stock of Cometra Energy (Canada), Ltd. Total purchase price included
both cash and the assumption of $7.6 million in net liabilities. These net
liabilities are not reflected in the Company's 2000 Statement of Cash Flows.
48
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 2000 and 1999 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 Statement
of Financial Accounting Standards No. 128, Earnings Per Share, 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 years ended
December 31, 2000 and 1999, the Company had outstanding stock options for
714,000 and 1,635,000 additional shares of the Company's common stock,
respectively, with average exercise prices of $20.19 and $17.70, respectively,
which were antidilutive.
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 $3.3 million, $2.9
million and $2.7 million in 2000, 1999 and 1998, respectively.
Lease Operating Expense
For the years ended December 31, 2000, 1999 and 1998, the Company recorded
in lease operating expenses gross production taxes of $17.4 million, $7.5
million and $7.4 million, respectively, and transportation and storage expenses
of $10.5 million, $6.2 million and $4.4 million, respectively.
Revenue Payable
Amounts payable to royalty and working interest owners resulting from sales
of oil and gas from jointly-owned properties and from purchases of oil and gas
by the Company's marketing and gathering segments are classified as revenue
payable in the accompanying financial statements.
Accounts Receivable
The Company's oil and gas, gas marketing and gathering sales are made to a
variety of purchasers, including intrastate and interstate pipelines or their
marketing affiliates, independent marketing companies and major oil companies.
The Company's joint operations accounts receivable are from a large number of
major and independent oil companies, partnerships, individuals and others who
own interests in the properties operated by the Company.
Foreign Currency
Foreign currency transactions and financial statements are translated in
accordance with Statement of Financial Accounting Standards No. 52, Foreign
Currency Translation. All of the Company's subsidiaries use the U.S. dollar as
their functional currency, except for the Company's Canadian subsidiary, which
uses the Canadian dollar. Adjustments arising from translation of the Canadian
subsidiary's financial statements are reflected in accumulated other
comprehensive income. Transaction gains and losses that arise from exchange
rate fluctuations applicable to transactions denominated in a currency other
than the Company's or subsidiary's functional currency are included in the
results of operations as incurred.
49
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cumulative Effect of Change in Accounting Principle
The Company adopted Securities and Exchange Commission Staff Accounting
Bulletin No. 101, Revenue Recognition ("SAB No. 101"), in the fourth quarter of
2000, effective January 1, 2000. SAB No. 101 requires oil inventories held in
storage facilities to be valued at cost. Cost is defined as lifting costs plus
depreciation, depletion and amortization. The Company previously followed
industry practice by valuing oil inventories at market. The cumulative effect
reduced net income by $1.4 million, net of income tax effects of $0.6 million.
Previously reported quarters during the year 2000 have been restated to give
effect to this change in accounting principle. Additional volatility in
quarterly and annually reported earnings may occur in the future as a result of
the required adoption of SAB No. 101 and fluctuations in oil inventory levels.
Transportation and Storage Costs
The Company adopted Emerging Issues Task Force Issue 00-10, Accounting for
Shipping and Fees and Costs ("EITF 00-10") in the fourth quarter of 2000. EITF
00-10 requires that transportation and storage costs be shown as an expense in
the statement of operations and not deducted from revenues. The Company
previously followed industry practice by deducting transportation and storage
costs from revenues. The Company now records transportation and storage costs
as lease operating costs. Fiscal years 1999 and 1998 have been restated to
reflect the adoption of EITF 00-10. The adoption of EITF 00-10 did not impact
net income (loss).
Comprehensive Income
The Company applies the provisions of Statement of Financial Accounting
Standards No. 130, Reporting Comprehensive Income ("SFAS No. 130"). The Company
had no non-owner changes in equity other than net income and losses during the
years ended December 31, 1999 and 1998. The Company had foreign currency
translation adjustments of $1.2 million for the year ended December 31, 2000,
which it has included in accumulated other comprehensive income in the
Stockholders' Equity section of the accompanying balance sheet.
2. Long-Term Debt
Long-term debt at December 31, 2000 and 1999, consisted of the following:
(In thousands) 2000 1999
--------- ---------
Revolving credit facility....................................... $ 65,000 $ 226,200
Senior subordinated notes:
9% Notes due 2005, less unamortized discount.................. 149,796 149,755
8 5/8% Notes due 2009, less unamortized discount.............. 99,433 99,363
9 3/4% Notes due 2009......................................... 150,000 150,000
--------- ---------
$ 464,229 $ 625,318
========= =========
The Company has no long-term debt maturities prior to November 30, 2005.
The Company had $5.0 million and $5.9 million of accrued interest payable
related to its long-term debt at December 31, 2000 and 1999, respectively,
included in other payables and accrued liabilities.
50
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Revolving Credit Facility
The Company has available an unsecured revolving credit facility under the
Second Amended and Restated Credit Agreement dated November 30, 2000 (the "Bank
Facility"), between the Company and certain banks. The Bank Facility
establishes a borrowing base (currently $625 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.
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 0.325 to 0.50 percent per annum on the unused
portion of the banks' commitment. Total outstanding advances at December 31,
2000, were $65.0 million at an average interest rate of approximately 8.81
percent.
On a semiannual basis, the Company's borrowing base is redetermined by the
banks based upon their review of the Company's oil and gas reserves. The
Company's borrowing base was last redetermined in November 2000. If the sum of
outstanding senior debt exceeds the borrowing base, as redetermined, the Company
must repay such excess. Any principal advances outstanding at maturity on
November 30, 2005, will be due immediately.
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 $375 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 and excluding any impact related to SFAS No. 133.
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.
51
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 November 4, 1998, the Company issued 1,325,000 shares of common stock to
Elf 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.
On March 16, 1999, the Company's Board of Directors (the "Board") adopted a
stockholder rights plan and declared a dividend distribution of one Preferred
Share Purchase Right ("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 Company's 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
Board.
On June 21, 1999, the Company completed a public offering of 9,000,000
shares of newly issued common stock. 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.
52
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock Plans
The Company has two 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 adjusted to the following pro
forma amounts:
(In thousands, except per share amounts) 2000 1999 1998
-------- -------- --------
Net income (loss) - as reported......................... $195,893 $73,371 $(87,665)
Net income (loss) - pro forma........................... 193,252 71,130 (89,759)
Earnings (loss) per share - as reported:
Basic................................................. 3.13 1.27 (1.69)
Diluted............................................... 3.06 1.24 (1.69)
Earnings (loss) per share - pro forma:
Basic................................................. 3.08 1.23 (1.73)
Diluted............................................... 3.02 1.20 (1.73)
The pro forma effect on net income (loss) for 2000, 1999 and 1998 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 2000 include a dividend yield of 0.6 percent, expected
volatility of approximately 46.7 percent, a risk-free interest rate of
approximately 6.3 percent and expected lives of 4.4 years. 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.
Under the 1990 Stock Plan, as amended (the "1990 Plan"), ten percent of the
total number of outstanding shares of common stock less the total number of
shares of common stock subject to outstanding awards under any other stock-based
plan for employees or directors of the Company 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, 2000, awards
for a total of 1,235,550 shares of common stock remain available for grant under
the 1990 Plan.
The 1990 Plan is administered by 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.
53
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2000, options for
a total of 18,000 shares of common stock remain available for grant under the
Director Plan.
The following is an analysis of all option activity under the 1990 Plan and
the Director Plan for 2000, 1999 and 1998:
2000 1999 1998
--------------------- ----------------------- -----------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
--------- --------- --------- --------- --------- ---------
Beginning stock options outstanding............... 4,616,142 $11.61 3,606,142 $12.79 3,060,322 $10.53
Stock options granted............................. 853,000 19.62 1,070,000 7.30 819,000 20.11
Stock options canceled............................ (49,000) 13.70 - - (50,000) 14.08
Stock options exercised........................... (393,550) 8.87 (60,000) 5.94 (223,180) 8.44
---------- ---------- - ----------
Ending stock options outstanding.................. 5,026,592 $13.16 4,616,142 $11.61 3,606,142 $12.79
========== ====== ========== ====== ========== ======
Ending stock options exercisable.................. 2,238,142 $10.89 1,967,256 $ 8.94 1,490,788 $ 8.47
========== ====== ========== ====== ========== ======
Weighted average fair value of
options granted................................. $ 9.02 $ 2.24 $ 4.14
========== ========== ==========
Of the 5,026,592 options outstanding at December 31, 2000: (a) 2,411,342
options have exercise prices between $5.94 and $9.81, with a weighted average
exercise price of $8.15 and a weighted average contractual life of 5.8 years
(1,377,342 of these options are exercisable currently at a weighted average
price of $8.83); (b) 964,250 options have exercise prices between $10.00 and
$15.50, with a weighted average exercise price of $14.25 and a weighted average
contractual life of 5.7 years (834,100 of these options are exercisable
currently at a weighted average price of $14.06); and (c) 1,651,000 options have
exercise prices between $16.06 and $22.94, with a weighted average exercise
price of $19.84 and a weighted average contractual life of 8.4 years (26,700 of
these options are exercisable currently at a weighted average price of $18.36).
All of the outstanding options are exercisable at various times in years
2001 through 2010. All incentive stock options and non-qualified stock options
were granted at fair market value on the date of grant. As of December 31,
2000, 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, 2000, a total of 6,280,142 shares of the Company's common
stock are reserved for issuance pursuant to the 1990 Plan and the Director Plan.
54
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Preferred Stock
Preferred stock at December 31, 2000, 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, 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
During 2000, the Company fulfilled its international drilling and work unit
commitments in Bolivia, Ecuador and Yemen. Through its December 2000
acquisition of Cometra Energy (Canada), Ltd. ("Cometra"), the Company assumed
the drilling obligations of Cometra's wholly-owned subsidiary, Cometra Trinidad
Limited. These obligations require the acquisition of 15 line kilometers of 2-D
seismic, 40 square kilometers of 3-D seismic and drilling of three exploratory
wells.
The Company's stock price guarantee issued to Elf in connection with the
Company's acquisition of Elf's Ecuador operations in 1998 expired during 2000.
The Company was not required to make any additional cash payment or additional
stock issuance in fulfillment of this guarantee.
The Company had $8.7 million in letters of credit outstanding at December
31, 2000. 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
letters of credit.
Rent expense was $2.3 million, $1.8 million and $1.2 million for 2000, 1999
and 1998, respectively. The future minimum commitments under long-term, non-
cancellable leases for office space are $1.8 million, $1.9 million, $2.0
million, $2.1 million and $3.6 million for the years 2001 through 2005,
respectively, with $1.3 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
Aries, 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 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 claimed the rate
should be 12 percent. On May 19, 2000, the Company announced it had received
notice of an adverse decision regarding this suit. As a result of the court's
decision, the Company has recorded a one-time, after-tax charge to "Other
expense" in the second quarter of approximately $25.1 million ($16.3 million
after-tax). Further, the Company believes that it is entitled to partial
indemnification by a third party with respect to the decision. The pre-tax
amount remaining to be paid of $1.6 million is included in "Other payables and
accrued liabilities" in the accompanying balance sheet. The impact of the
decision on the Company's Argentina production, reserves and present value was
not material.
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.
55
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
5. Financial Instruments
Price Risk Management
The Company periodically uses hedges (swap agreements) to reduce the impact
of oil and natural gas price fluctuations on its operating results and cash
flows. These swap agreements typically entitle the Company to receive payments
from (or require it to make payments to) the counter parties based upon the
differential between a fixed price and a floating price based on a published
index. The Company's hedging activities are conducted with major corporations
and investment and commercial banks which the Company believes are minimal
credit risks. The Board of Directors has approved risk management policies and
procedures to utilize financial products for the reduction of defined commodity
price risks. These policies prohibit speculation with derivatives and limit
swap agreements to counter parties with appropriate credit standings.
At December 31, 2000, the Company was a party to oil price swap agreements
for various periods of 2001 covering 3.5 MMBbls at a weighted average NYMEX
reference price of $30.76 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.
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, 2000 and 1999, was
$475.2 million and $621.6 million, respectively, compared with a carrying value
of $464.2 million and $625.3 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. At December 31, 2000, the Company would have received
approximately $16.3 million 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.
6. Income Taxes
Income (loss) before income taxes and cumulative effect of change in
accounting principle is composed of the following:
(In thousands) 2000 1999 1998
-------- ------- ---------
Domestic.............................. $123,951 $33,097 $(122,331)
Foreign............................... 166,324 64,603 (8,898)
-------- ------- ---------
$290,275 $97,700 $(131,229)
======== ======= =========
56
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The total provision (benefit) for income taxes consists of the following:
(In thousands) 2000 1999 1998
----------- ---------- ----------
Current:
Domestic................... $ 17,053 $ 1,036 $ (5,324)
Foreign.................... 51,805 4,918 1,256
Deferred:
Domestic................... 32,460 11,730 (43,722)
Foreign.................... (8,358) 6,645 4,226
---------- --------- ----------
$ 92,960 $ 24,329 $ (43,564)
========== ========= ==========
A reconciliation of the U.S. Federal statutory income tax rate to the effective
rate is as follows:
2000 1999 1998
-------- -------- --------
U.S. Federal statutory income tax rate............................ 35.0% 35.0% (35.0)%
State income tax.................................................. 3.9 3.9 (3.9)
Foreign operations................................................ (2.8) (2.9) (2.1)
Effect of conversion of foreign production sharing
contracts....................................................... 4.0) - -
Argentina NOL valuation allowance (reversal)...................... - (5.8) 4.3
Argentina NOL carryforward utilization............................ - (5.2) -
U.S. Federal income tax credits................................... - (0.1) 1.8
Other............................................................. (0.1) - 1.7
------ ------ ------
32.0% 24.9% (33.2)%
====== ====== ======
The components of the Company's net deferred tax liability as of December 31,
2000 and 1999, are as follows:
(In thousands) 2000 1999
---------- ---------
Deferred Tax Assets:
U.S. Federal and state net operating loss carryforwards........... $ 976 $20,426
U.S. Federal alternative minimum tax credit carryforward.......... - 5,242
Foreign net operating loss carry forwards......................... 16,291 -
Other temporary book/tax differences.............................. 7,832 4,101
--------- ---------
25,099 29,769
--------- ---------
Deferred Tax Liabilities:
Book/tax differences in property basis............................ 58,057 45,183
Other temporary book/tax differences.............................. 294 366
--------- ---------
58,351 45,549
--------- ---------
Net deferred tax liability............................... $ 33,252 $ 15,780
========= =========
57
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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. The Company has a
Bolivian income tax net operating loss ("NOL") of approximately $65 million that
does not expire and can be used to offset its future income tax liabilities.
The Company fully utilized its $60.0 million U.S. Federal regular tax NOL
carryforward and its alternative minimum tax credit carryforward in 2000. The
Company also has various state NOL carryforwards which have varying lengths of
allowable carryforward periods ranging from five to 20 years and can be used to
offset future state taxable income.
7. Segment Information
The Company applies Statement of Financial Accounting Standards No. 131,
Disclosures About Segments of an Enterprise and Related Information. 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, Yemen and, beginning in December
2000, Canada. Summarized financial information for the Company's reportable
segments is shown on the following page.
58
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Exploration and Production
---------------------------------
Other Gas
U.S. Argentina Foreign Gathering Marketing Corporate Total
---------- ---------- --------- ---------- ---------- ---------- ----------
2000 (in thousands)
- --------------------------------------
Revenues from external customers........ $346,574 $ 256,234 $ 52,429 $ 19,998 $128,836 $ 2,110 $ 806,181
Intersegment revenues................... - - - 2,080 2,372 - 4,452
Depreciation, depletion and
amortization expense........... 53,184 33,077 10,074 1,567 - 2,207 100,109
Impairment of oil and gas properties.... 225 - - - - - 225
Operating income (loss)................. 192,508 170,301 10,988 1,380 5,049 (98) 380,128
Total assets............................ 524,588 459,219 257,926 13,479 35,977 47,208 1,338,397
Capital investments..................... 64,125 92,885 100,663 299 - 2,334 260,306
Long-lived assets....................... 477,198 401,702 215,352 5,862 - 4,940 1,105,054
1999 (in thousands)
- --------------------------------------
Revenues from external customers........ $275,486 $ 142,374 $ 16,103 $ 6,955 $ 60,275 $ 1,735 $ 502,928
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 $ 68,630 $ 7,359 $ 7,741 $ 54,108 $ 425 $ 333,323
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
______________________
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 2000, sales to two crude oil purchasers of the exploration and
production segment represented approximately 17 percent and 12 percent,
respectively, of the Company's total revenues (exclusive of eliminations of
intersegment sales and the impact of hedges). 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 total
revenues (exclusive of eliminations of intersegment sales, the impact of hedges
and $55.0 million of net proceeds from the sales of oil and gas properties). The
Company had no single purchaser to which sales of any segment in 1998 exceeded
10 percent of the Company's total revenues.
59
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
8. Detail of Prepaids and Other Current Assets
(In thousands) 2000 1999
------- -------
Property divestiture proceeds receivable.......... $ - $ 9,704
Other prepaids and current assets................. 13,946 9,405
------- -------
$13,946 $19,109
======= =======
9. Quarterly Results (Unaudited)
The following is a summary of the quarterly results of operations for the
years ended December 31, 2000 and 1999. The four quarters of 1999 and the first
three quarters of 2000 have been restated to reflect a reclassification of
transportation and storage charges from revenues to lease operating expense and
the first three quarters of 2000 have also been restated to reflect a change in
accounting principle related to inventory valuation.
(In thousands, except per share amounts) Quarter Ended
-------------------------------------------------------
Mar. 31 Jun. 30 Sept. 30 Dec. 31
----------- ----------- ------------ -----------
2000
----
Revenues................................................. $162,391 $156,266(b) $229,981 $257,543
Operating income......................................... 73,701 53,783(b) 100,995 110,234
Cumulative effect of change in accounting principle...... (1,422) - - -
Provision for income taxes............................... 20,580 14,800 30,837 26,743
Net income............................................... 38,284(a) 27,059(b) 58,548 72,001
Income per share:
Basic.................................................. .61(a) .43(b) .93 1.15
Diluted................................................ .60(a) .42(b) .92 1.12
1999
----
Revenues................................................. $ 67,388 $ 93,798 $138,272 $203,470(c)
Operating income (loss).................................. (14,856) 19,026 51,560 100,635(c)
Provision (benefit) for income taxes..................... (11,295) (733) 9,098 27,259
Net income (loss)........................................ (18,121) 5,183 27,278 59,031(c)
Income (loss) per share:
Basic................................................. (.34) .10 .44 .95(c)
Diluted............................................... (.34) .09 .43 .92(c)
____________________
(a) Net income for the quarter ended March 31, 2000, includes the
cumulative effect of a change in accounting principle, net of tax, of
$1.4 million, or two cents per share.
(b) The quarter ended June 30, 2000, includes a reduction in revenues of
$25.1 million ($16.3 million net of tax, or 25 cents per share),
related to a non-recurring charge resulting from an Argentina
litigation loss related to a royalty dispute.
(c) 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.
60
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
10. 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, 2000, 1999 and 1998. The Company began operations in Ecuador in
November 1998 and Canada in December 2000.
2000
----------------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Ecuador Other Total
---------- ----------- --------- --------- --------- ---------
Revenues......................................... $348,305 $281,334 $19,535 $30,613 $ 2,281 $682,068
Production (lifting) costs....................... 96,386 52,856 3,777 6,116 503 159,638
Exploration costs................................ 4,271 - 12,133 2,526 6,312 25,242
Impairment of proved properties.................. 225 - - - - 225
Depreciation, depletion and amortization......... 53,184 33,077 7,421 2,067 586 96,335
-------- -------- ------- ------- ------- --------
Results of operations before income taxes........ 194,239 195,401 (3,796) 19,904 (5,120) 400,628
Income tax expense (benefit)..................... 75,559 68,390 (949) 4,976 (1,695) 146,281
-------- -------- ------- ------- ------- --------
Results of operations (excluding corporate
overhead and interest costs).................. $118,680 $127,011 $(2,847) $14,928 $(3,425) $254,347
======== ======== ======= ======= ======= ========
1999
----------------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Ecuador Other Total
---------- ----------- --------- --------- --------- ---------
Revenues......................................... $220,495 $142,374 $ 5,786 $10,316 $ - $378,971
Production (lifting) costs....................... 80,516 35,845 3,024 2,279 - 121,664
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) 6,714 (4,761) 135,608
Income tax expense (benefit)..................... 22,527 16,695 (438) - (1,666) 37,110
-------- -------- ------- ------- ------- --------
Results of operations (excluding corporate
overhead and interest costs).................. $ 35,384 $ 60,338 $ (851) $ 6,714 $(3,095) $ 98,490
======== ======== ======= ======= ======= ========
61
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
1998
----------------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Other Total
--------- --------- --------- ------- ---------
Revenues....................................... $ 195,060 $ 68,630 $ 6,789 $ 570 $ 271,049
Production (lifting) costs..................... 94,332 29,548 2,879 355 127,114
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)
========= ========= ========= ======= =========
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, 2000
and 1999, was as follows:
2000
--------------------------------------------------------------------------------------------
(In thousands) U.S. Canada Argentina Bolivia Ecuador Other Total
----------- -------- ---------- -------- --------- -------- ----------
Unproved properties
not being amortized......... $ 20,446 $ 3,922 $ - $ - $ - $ 22,860 $ 47,228
Proved properties
being amortized............. 949,901 49,981 533,727 113,399 45,086 - 1,692,094
----------- -------- ---------- -------- --------- -------- ----------
Total capitalized costs... 970,347 53,903 533,727 113,399 45,086 22,860 1,739,322
Less accumulated depreciation,
depletion and amortization.. 493,149 596 132,025 15,873 3,427 - 645,070
----------- -------- ---------- -------- --------- -------- ----------
Net capitalized costs..... $ 477,198 $ 53,307 $ 401,702 $ 97,526 $ 41,659 $ 22,860 $1,094,252
=========== ======== ========== ======== ========= ======== ==========
1999
-----------------------------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Ecuador Other Total
---------- ---------- -------- -------- ------- ----------
Unproved properties not being amortized........ $ 15,867 $ - $ - $ 977 $ 6,527 $ 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 51,286 6,527 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 $ 49,853 $ 6,527 $ 957,917
========== ========== ======== ======== ======= ===========
62
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 2000, 1999 and 1998:
2000
----------------------------------------------------------------------
(In thousands) U.S. Canada Argentina Bolivia Ecuador Other Total
--------- --------- ---------- --------- --------- --------- ---------
Acquisitions:
Undeveloped properties......................... $ 2,176 $ 3,614 $ - $ 225 $ 265 $ 2,768 $ 9,048
Producing properties........................... 6,035 47,927 43,428 - (5,942) - 91,448
Exploratory..................................... 23,841 212 - 27,532 1,494 19,721 72,800
Development..................................... 32,072 1,035 49,457 983 829 - 84,376
------- -------- ------- ------- ------- ------- --------
Total costs incurred......................... $64,124 $52,788 $92,885 $28,740 $(3,354) $22,489 $257,672
======= ======== ======= ======= ======= ======= ========
1999
------------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Ecuador 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 $16,091 $7,482 $237,484
======= ======== ======= ======= ====== ========
1998
--------------------------------------------------------------
(In thousands) U.S. Argentina Bolivia Ecuador Other Total
---------- ----------- -------- --------- -------- ---------
Acquisitions:
Undeveloped properties......................... $ 6,460 $ - $ - $ 101 $ 4,200 $ 10,761
Producing properties........................... 70,805 - - 34,218 - 105,023
Exploratory..................................... 49,952 1,416 10,324 396 604 62,692
Development..................................... 50,753 43,176 13,949 - 6 107,884
---------- ---------- -------- --------- -------- ---------
Total costs incurred......................... $ 177,970 $ 44,592 $ 24,273 $ 34,715 $ 4,810 $ 286,360
========== ========== ======== ========= ======== ==========
63
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., in Bolivia as
estimated by the independent petroleum consultants of DeGolyer and MacNaughton,
and in Canada as estimated by the Company.
Oil (MBbls)
------------------------------------------------------------
U.S. Canada Argentina Bolivia Ecuador Total
--------- ------- ------ -------- -------- --------
Proved reserves at December 31, 1997....................... 99,934 - 81,651 6,183 - 187,768
Revisions of previous estimates............................ (38,473) - (4,579) (665) 2,546 (41,171)
Extensions, discoveries and other additions................ 306 - 4,091 2,968 - 7,365
Production................................................. (9,912) - (6,322) (122) (78) (16,434)
Purchase of reserves-in-place.............................. 5,452 - - - 21,577 27,029
Sales of reserves-in-place................................. (100) - - - - (100)
--------- ------ ------- -------- -------- --------
Proved reserves at December 31, 1998....................... 57,207 - 74,841 8,364 24,045 164,457
Revisions of previous estimates............................ 52,684 - 24,496 (1,952) 1,709 76,937
Extensions, discoveries and other additions................ 110 - - 1,746 - 1,856
Production................................................. (8,643) - (7,560) (77) (597) (16,877)
Purchase of reserves-in-place.............................. 10,343 - 44,694 - 23,039 78,076
Sales of reserves-in-place................................. (1,259) - - - - (1,259)
--------- ------ ------- -------- -------- --------
Proved reserves at December 31, 1999....................... 110,442 - 136,471 8,081 48,196 303,190
Revisions of previous estimates............................ 397 - 18,501 (1,125) 2,540 20,313
Extensions, discoveries and other additions................ 329 - - - - 329
Production................................................. (9,044) (19) (9,406) (131) (1,261) (19,861)
Purchase of reserves-in-place.............................. 447 2,407 11,970 - - 14,824
Sales of reserves-in-place................................. (235) - - - - (235)
--------- ------ ------- -------- -------- --------
Proved reserves at December 31, 2000....................... 102,336 2,388 157,536 6,825 49,475 318,560
========= ====== ======= ======== ======== ========
Proved developed oil reserves at:
December 31, 1998...................................... 51,481 - 47,167 4,390 1,255 104,293
========= ====== ======= ======== ======== ========
December 31, 1999...................................... 94,722 - 90,125 6,414 5,524 196,785
========= ====== ======= ======== ======== ========
December 31, 2000...................................... 90,774 1,558 94,191 5,668 3,915 196,106
========= ====== ======= ======== ======== ========
64
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Gas (MMcf)
----------------------------------------------------
Total
U.S. Canada Argentina Bolivia Total (MBOE)
-------- ------- --------- -------- -------- --------
Proved reserves at December 31, 1997........................ 360,847 - - 191,316 552,163 279,795
Revisions of previous estimates............................. (11,252) - 12,024 101,624 102,396 (24,105)
Extensions, discoveries and other additions................. 28,345 - - 121,419 149,764 32,326
Production.................................................. (42,176) - - (5,062) (47,238) (24,307)
Purchase of reserves-in-place............................... 53,027 - - - 53,027 35,867
Sales of reserves-in-place.................................. (3,279) - - - (3,279) (647)
--------- ------- ---------- -------- --------- --------
Proved reserves at December 31, 1998........................ 385,512 - 12,024 409,297 806,833 298,929
Revisions of previous estimates............................. 32,505 - 25,222 21,129 78,856 90,080
Extensions, discoveries and other additions................. 1,844 - - 88,424 90,268 16,901
Production.................................................. (39,150) - (4,682) (4,522) (48,354) (24,936)
Purchase of reserves-in-place............................... 14,947 - 81,072 - 96,019 94,079
Sales of reserves-in-place.................................. (34,633) - - - (34,633) (7,031)
--------- ------- ---------- -------- --------- --------
Proved reserves at December 31, 1999........................ 361,025 - 113,636 514,328 988,989 468,022
Revisions of previous estimates............................. 39,123 - 13,990 (41,521) 11,592 22,245
Extensions, discoveries and other additions................. 34,990 - - - 34,990 6,160
Production.................................................. (35,764) (312) (8,705) (8,948) (53,729) (28,816)
Purchase of reserves-in-place............................... 1,376 39,790 2,278 - 43,444 22,065
Sales of reserves-in-place.................................. (2,078) - - - (2,078) (581)
--------- ------- ---------- -------- --------- --------
Proved reserves at December 31, 2000........................ 398,672 39,478 121,199 463,859 1,023,208 489,095
========= ======= ========== ======== ========= ========
Proved developed gas reserves at:
December 31, 1998....................................... 330,371 - 12,024 278,317 620,712 207,745
========= ======= ========= ======== ========= ========
December 31, 1999....................................... 302,444 - 92,696 415,743 810,883 331,932
========= ======= ========= ======== ========= ========
December 31, 2000....................................... 333,453 33,405 41,822 385,623 794,303 328,490
========= ======= ========= ======== ========= ========
65
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 Statement of Financial Accounting Standards 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, 2000 and 1999:
2000
----------------------------------------------------------------------------
(In thousands) U.S. Canada Argentina Bolivia Ecuador Total
------------- ---------- ------------ ---------- ---------- -------------
Future cash inflows...................... $ 6,484,886 $ 355,171 $ 3,757,493 $ 572,917 $ 660,374 $ 11,830,841
Future production costs.................. 1,656,100 45,558 1,221,302 48,796 208,957 3,180,713
Future development and
abandonment costs....................... 221,193 12,696 281,555 51,900 139,990 707,334
------------- ---------- ------------ ---------- ---------- -------------
Future net cash inflows before
income tax expense...................... 4,607,593 296,917 2,254,636 472,221 311,427 7,942,794
Future income tax expense................ 1,675,283 110,332 665,236 97,473 58,225 2,606,549
------------- ---------- ------------ ---------- ---------- -------------
Future net cash flows.................... 2,932,310 186,585 1,589,400 374,748 253,202 5,336,245
10 percent annual discount for
estimated timing of cash flows.......... 1,366,053 39,435 682,161 200,329 97,138 2,385,124
------------- ---------- ------------ ---------- ---------- -------------
Standardized Measure of discounted
future net cash flows................... $ 1,566,257 $ 147,150 $ 907,239 $ 174,419 156,064 $ 2,951,121
============= ========== ============ ========== ========== =============
66
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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
============ ============ =========== ============ =============
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 2000, 1999 and 1998:
(In thousands) 2000 1999 1998
------------ ---------- ----------
Standardized Measure - beginning of year............................. $2,247,237 $ 648,222 $1,016,645
Increases (decreases) -
Sales, net of production costs...................................... (522,545) (255,260) (145,709)
Net change in sales prices, net of production costs................. 1,131,540 1,218,764 (505,314)
Discoveries and extensions, net of related
future development and production costs........................... 148,727 62,427 98,521
Changes in estimated future development costs....................... (87,127) (52,195) (17,025)
Development costs incurred.......................................... 93,276 21,472 98,434
Revisions of previous quantity estimates............................ 267,178 732,703 (124,097)
Accretion of discount............................................... 298,963 70,357 122,256
Net change in income taxes.......................................... (645,108) (687,057) 150,582
Purchase of reserves-in-place....................................... 278,740 496,237 110,389
Sales of reserves-in-place.......................................... (4,787) (54,135) (1,493)
Timing of production of reserves and other.......................... (254,973) 45,702 (154,967)
------------ ---------- ----------
Standardized Measure - end of year................................... $2,951,121 $2,247,237 $ 648,222
============ ========== ==========
67
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, 2000, filed August 11, 2000).
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).
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).
68
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* Amendment No. 6 to Vintage Petroleum, Inc. 1990 Stock Plan dated
March 17, 2000 (Filed as Exhibit A to the Company's Proxy
Statement for Annual Meeting of Stockholders dated March 30,
2000).
10.10* 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).
10.11* 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")).
10.12* 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).
10.13* 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).
10.14* Form of Non-Qualified Stock Option Agreement for non-employee
directors under the Vintage Petroleum, Inc. 1990 Stock Plan
(Filed as Exhibit 10.13 to the Company's report on Form 10-K for
the year ended December 31, 1999, filed March 13, 2000).
10.15 Second Amended and Restated Credit Agreement dated as of November
30, 2000, among the Company, as borrower, and certain commercial
lending institutions, as lenders, Bank of Montreal, as
administrative agent, Bank of America, N.A., as syndication
agent, Societe Generale, Southwest Agency, as documentation
agent, and ABN AMRO Bank, N.V., as managing 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.
____________________
* Management contract or compensatory plan or arrangement.
69