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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, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number 1-10578
VINTAGE PETROLEUM, INC.
(Exact name of registrant as specified in its charter)
Delaware 73-1182669
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
110 West Seventh Street
Tulsa, Oklahoma 74119-1029
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (918) 592-0101
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -------------------
Common Stock, $.005 Par Value New York Stock Exchange
Preferred Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes _X_ No ___
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
As of March 15, 2002, 63,081,322 shares of the Registrant's Common
Stock were outstanding, and the aggregate market value of the Common Stock held
by non-affiliates was approximately $628,176,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the Annual Meeting of
Stockholders to be held May 14, 2002, 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, 2001
TABLE OF CONTENTS
PART I
Page
----
Items 1 and 2. Business and Properties .............................................................................. 1
Item 3. Legal Proceedings .................................................................................... 29
Item 4. Submission of Matters to a Vote of Security-Holders .................................................. 29
Item 4A. Executive Officers of the Registrant ................................................................. 30
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ................................ 33
Item 6. Selected Financial Data .............................................................................. 34
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ................ 35
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ........................................... 46
Item 8. Financial Statements and Supplementary Data .......................................................... 50
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ................. 50
PART III
Item 10. Directors and Executive Officers of the Registrant ................................................... 50
Item 11. Executive Compensation ............................................................................... 50
Item 12. Security Ownership of Certain Beneficial Owners and Management ....................................... 51
Item 13. Certain Relationships and Related Transactions ....................................................... 51
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ...................................... 51
Signatures ........................................................................................................... 54
Index to Financial Statements ........................................................................................ 55
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(Degree) Fahrenheit. Equivalent Bbls of oil and equivalent Mcf of gas
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" 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:
o amounts and nature of future capital expenditures;
o wells to be drilled or reworked;
o oil and gas prices and demand;
o exploitation and exploration prospects;
o estimates of proved oil and gas reserves;
o reserve potential;
o development and infill drilling potential;
o expansion and other development trends of the oil and gas industry;
o business strategy;
o production of oil and gas reserves; and
o 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:
o 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;
o oil and gas prices;
o exploitation and exploration successes;
o actions taken and to be taken by Argentina as a result of its
economic instability;
o continued availability of capital and financing;
o general economic, market or business conditions;
o acquisitions and other business opportunities (or lack thereof) that
may be presented to and pursued by the Company;
o changes in laws or regulations; and
o 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 favorable prices, its technical expertise and its low
cost structure.
At December 31, 2001, the Company owned and operated producing
properties in nine states in the U.S., with its domestic proved reserves located
primarily in four core areas: Gulf Coast, East Texas, Mid-Continent and West
Coast. During 2001, the Company significantly expanded its North American
operations in Canada through the acquisition of 100 percent of Genesis
Exploration Ltd. ("Genesis," now Vintage Petroleum Canada, Inc.). See
"Acquisitions." Additionally, the Company has international core areas located
in Argentina, Bolivia and Ecuador. In Argentina, the Company owns 20 oil
concessions, 16 of which are operated by the Company. Fourteen of these operated
concessions are located in the south flank of the San Jorge Basin in southern
Argentina. The Company recently expanded its Argentina core area into the Cuyo
Basin in western Argentina with the purchase of the Piedras Colorados and
Cachueta concessions in 2000, and the purchase of the La Ventana and Rio Tunuyan
concessions in 2001. See "Acquisitions." In Bolivia, the Company owns and
operates three blocks in the Chaco Plains area of southern Bolivia and the
Naranjillos concession located in the Santa Cruz Province. The Company also
currently operates three blocks in the Oriente Basin in Ecuador and this area
provides substantial undeveloped acreage which the Company believes has
significant development and exploration potential.
As of December 31, 2001, the Company owned interests in 3,058 gross
(2,591 net) productive wells in the U.S., of which approximately 89 percent are
operated by the Company, 808 gross (446 net) productive wells in Canada, of
which approximately 55 percent are operated by the Company, 1,484 gross (1,329
net) productive wells in Argentina, of which approximately 83 percent are
operated by the Company, 15 gross (14 net) productive wells in Bolivia, all of
which are operated by the Company, nine gross (seven net) productive wells in
Ecuador, all of which are operated by the Company, and two gross (one net)
productive wells in Trinidad, both of which are operated by the Company. As of
December 31, 2001, the Company's properties had proved reserves of 535.0 MMBOE,
comprised of 332.3 MMBbls of oil and 1.2 Tcf of gas, with a present value of
estimated future net revenues before income taxes (utilizing a 10 percent
discount rate) of $1.9 billion and a standardized measure of discounted future
net cash flows of $1.4 billion. From the first quarter of 1999 through the
fourth quarter of 2001, the Company increased its average net daily production
from 42,100 Bbls of oil to 64,300 Bbls of oil and from 120,900 Mcf of gas to
240,300 Mcf of gas.
Financial information relating to the Company's industry segments is
set forth in Note 8 "Segment Information" to the Company's consolidated
financial statements included elsewhere in this Form 10-K.
The Company was incorporated in Delaware on May 31, 1983. The Company's
principal office is located at 110 West Seventh Street, Tulsa, Oklahoma
74119-1029, and its telephone number is (918) 592-0101.
1
Business Strategy
The Company's overall goal is to maximize its value through profitable
growth in its oil and gas reserves and production. The Company has been
successful at achieving this goal through its ongoing strategy of (a) acquiring
producing oil and gas properties with significant upside potential at favorable
prices, (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 structure and (e)
maintaining financial flexibility. Key elements of the Company's strategy
include:
o 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) favorable 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, large independent
and national oil companies has afforded in the past, and
should afford in the future, favorable 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,
1999, through December 31, 2001, the Company has spent $865.5
million acquiring 190.3 MMBOE of proved oil and gas reserves
at an average acquisition cost of $4.55 per BOE. The Company
replaced, through acquisitions, approximately 215 percent of
its production of 88.3 MMBOE during the same period. During
2001, the Company spent $607.2 million acquiring 74.1 MMBOE of
proved oil and gas reserves at an average acquisition cost of
$8.19 per BOE, reflecting the higher cost of the Company's
acquisition of Genesis. The 2001 acquisitions replaced
approximately 214 percent of the Company's production of 34.6
MMBOE during 2001. For additional information, see
"Acquisitions." 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.
o 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, 1999, through December 31, 2001,
the Company spent approximately $277.7 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,
2001, the Company succeeded in adding 61.9 MMBOE to proved
reserves, replacing approximately 70 percent of production
during the same period at a cost of $4.49 per BOE. During
2001, the Company spent $168.8 million on exploitation and
development activities and added 25.0 MMBOE to proved
reserves, replacing approximately 72 percent of 2001
production at a cost of $6.75 per BOE. For additional
information, see "Exploitation and Development." The Company
continues to maintain an extensive inventory of exploitation
and development opportunities. Due to the anticipated lower
oil and gas price environment for 2002, as compared to 2001,
and the economic instability in Argentina (see "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk -
Foreign Currency and Operations Risk" included elsewhere in
this Form 10-K), the Company has decreased its budgeted level
of spending to $105 million in 2002 on exploitation and
development projects, primarily in North America and Ecuador.
2
o Exploration. The Company's overall exploration strategy
balances high potential international prospects with lower
risk drilling in known formations in North America 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 data, which
further reduces the cost of its exploration program by
increasing its success. From January 1, 1999, through December
31, 2001, the Company spent approximately $189.8 million on
exploration activities, excluding $53.6 million to acquire the
large acreage inventory of Genesis in May 2001. During this
period, the Company drilled 92 gross (63 net) exploration
wells, of which approximately 62 percent were productive. As a
result of all of the Company's exploration activities during
the three-year period ended December 31, 2001, the Company
succeeded in adding 44.1 MMBOE to proved reserves, replacing
approximately 50 percent of production during this period at a
cost of $4.31 per BOE. For additional information, see
"Exploration." The Company's exploration activities in 2001
were focused on its core areas in the U.S. and Canada and
additionally in Trinidad and Yemen. Due to the anticipated
lower oil and gas price environment for 2002, as compared to
2001, the Company anticipates reduced 2002 spending of
approximately $39 million on exploration projects, primarily
in North America and Yemen.
o 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.
o 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 two Rule 144A private debt offerings, all of
which have provided the Company with aggregate net proceeds of
approximately $843 million. From December 31, 2000, to May 2,
2001, the Company's net long-term debt-to-book capitalization
ratio increased from 41.6 percent to 59.1 percent, primarily
as a result of the acquisition of Genesis. Since May 2, 2001,
the Company applied cash flow over non-acquisition capital
expenditures and proceeds from the sale of non-strategic oil
and gas properties to reduce outstanding long-term debt,
lowering its net long-term debt-to-book capitalization ratio
to 57.7 percent at December 31, 2001. The Company plans to
further reduce this ratio during 2002. It has restricted its
planned non-acquisition capital expenditure level and may
consider additional property sales and other measures,
including consideration of the method of funding future
acquisitions, to achieve this goal. Internally generated cash
flow, the borrowing capacity under its revolving credit
facility and its ability to adjust its level of capital
expenditures are the Company's major sources of liquidity. For
further information, see "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -
Liquidity" included elsewhere in this Form 10-K.
Acquisitions
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, large independent and national oil companies has afforded
in recent years, and should afford in the future, favorable opportunities to
purchase domestic and international producing properties.
3
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 U.S., 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 and Trinidad with the purchase of 100 percent of Cometra
Energy (Canada), Ltd. ("Cometra," now Vintage Energy (Canada), Ltd.), a
privately-held Canadian company. The Company significantly expanded its Canadian
operations in 2001 with the purchase of 100 percent of Genesis, a
publicly-traded Canadian company. The Company also extended its Argentina
operations in 2000 with its acquisition of two concessions from Perez Companc
and in 2001 with its purchase of the La Ventana and Rio Tunuyan concessions from
Shell C.A.P.S.A., a wholly-owned affiliate of Royal Dutch Shell. 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, 1999, through December 31, 2001, the Company made oil
and gas reserve acquisitions with costs totaling approximately $865.5 million.
As a result of these acquisitions, the Company acquired approximately 190.3
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:
1999 ................................ $ 31,662 10,343 14,947 12,834 $ 2.47
2000 ................................ 53,962 2,854 41,166 9,715 5.55
2001 ................................ 564,950 27,493 207,701 62,110 9.10
--------- ------ ------- -------
Total North America Acquisitions .. 650,574 40,690 263,814 84,659 7.68
--------- ------ ------- -------
South America Acquisitions:
1999 ................................ 135,125 67,733 81,072 81,245 1.66
2000 ................................ 37,486 11,970 2,278 12,350 3.04
2001 ................................ 42,267 11,724 1,636 11,997 3.52
--------- ------ ------- -------
Total South America Acquisitions .. 214,878 91,427 84,986 105,592 2.03
--------- ------ ------- -------
Total Acquisitions .................... $ 865,452 132,117 348,800 190,251 $ 4.55
========= ======= ======= =======
The Company estimates that 74.1 MMBOE of proved reserves, as of the
various acquisition dates, were acquired in 2001 for an aggregate cost
attributable to oil and gas reserves of $607.2 million, resulting in an average
cost of $8.19 per BOE. The average cost per BOE over the three-year period ended
December 31, 2001, is $4.55 and the cost since the Company's inception is $3.49
per BOE.
The following is a brief discussion of the significant acquisitions in
2001:
Genesis Exploration Ltd. (Canada). In May 2001, the Company acquired
100 percent of the outstanding common stock of Genesis for total consideration
of $617 million, including transaction costs and the assumption of the estimated
net indebtedness of Genesis at closing. Approximately $562.4 of the purchase
price was allocated to oil and gas reserves. The cash portion of the acquisition
price was paid through advances under the Company's revolving credit facility
and cash on hand.
4
The Company acquired 62.1 MMBOE of proved reserves in the transaction
with Genesis consisting of approximately 27.5 MMBbls of oil and 207.7 Bcf of
gas. Proved undeveloped reserves of oil and gas accounted for approximately 33
percent of total proved BOE of reserves. In addition, the Company acquired a
significant amount of probable reserves, representing upside potential which may
be realized through its 2002 work program and beyond. The reserves acquired in
the Genesis transaction are located primarily in the provinces of Alberta and
Saskatchewan with a significant exploration exposure in the Northwest
Territories.
In addition to reserves, the Company acquired over one million net
undeveloped acres located in Alberta and Saskatchewan with a significant
portion, aggregating to 440,000 net acres, in the Northwest Territories. Also,
the Genesis acquisition brought with it over 600 square miles of 3-D seismic
data and over 15,000 miles of 2-D seismic data. The Company estimates the
acquisition cost of proved reserves was approximately $9.06 per BOE, exclusive
of $54 million allocated to undeveloped acreage. At the time of acquisition, net
daily production from the Genesis properties was approximately 17,800 BOE,
composed of approximately 71 MMcf of gas and 6,000 Bbls of oil.
With the Genesis acquisition closely following the 2000 acquisition of
Cometra, the Company has not only added significant reserves and production to a
new core area, but also enhanced its ability to grow from its expanded North
American exploration program. At the same time, this acquisition accomplished a
better balance of the Company's geographical mix of production and proved oil
and gas reserves between North America and other international areas.
Cuyo Basin Properties (Argentina). In September 2001, the Company
acquired 100 percent of the outstanding common stock of a privately-held
Argentine company (now Vintage Petroleum Argentina S.A.) that held concessions
in the Cuyo Basin of western Argentina. Subsequently, Vintage Petroleum
Argentina S.A. purchased certain non-operated interests in the La Ventana and
Rio Tunuyan Blocks in the Cuyo Basin. Total consideration for these transactions
was approximately $66.8 million, including transaction costs, and was funded
through advances under the Company's revolving credit facility. Approximately
$42.3 million of the total purchase price was allocated to oil and gas reserves.
These acquisitions added approximately 12.0 MMBOE of proved reserves,
consisting of 11.7 MMBbls of oil and 1.6 Bcf of gas, and net daily production at
the time of acquisition of approximately 3,200 Bbls of oil and 500 Mcf of gas.
In addition to the producing concessions it now owns, Vintage Petroleum
Argentina S.A. had an Argentine income tax net operating loss carryforward at
December 31, 2001, of approximately 91 million pesos ($55 million) that expires
in varying annual amounts over a five-year period beginning in 2002 and can be
used to offset future income tax liabilities.
These acquisitions expanded the Company's presence in the western
basins of Argentina, which the Company entered in 2000. One exploration well and
one development well have been drilled in the La Ventana concession since the
acquisition. The exploration well is currently producing at a daily rate of over
450 gross Bbls (120 net Bbls) of oil per day with several potential offset
locations identified.
Divestitures
During 2001, the Company continued its divestiture program designed to
sell properties in the U.S. that were either marginally economical or
non-strategic to the Company's areas of operation. Net proceeds of $47.1 million
from the property sales were achieved primarily through public auctions held
during the fourth quarter of 2001. These sales resulted in $26.9 million in
gains ($16.7 million after tax), which were included in the Company's 2001
operating results.
Through these sales of 780 wells and over 600 leases in 85 fields, the
Company significantly reduced its domestic well and lease count while reducing
net domestic production by only six percent, and total net production by three
percent. Combined, the Company estimates that the properties sold accounted for
proved reserves of 5.7 MMBbls of oil and 27.8 Bcf of gas as of the closing dates
of these sales, which represents approximately seven percent of the Company's
U.S. proved reserves and two percent of the Company's total proved reserves at
December 31, 2001. Net daily production during 2001 from the properties sold
averaged approximately 1,330 Bbls of oil and 7,650 Mcf of gas. Divesting of
these lower-tier assets, which have average operating costs in excess of $10.00
per BOE, will allow the Company to focus more intently on its remaining
high-graded properties and new areas for future growth.
5
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 these
efforts, as well as the effect of period to period changes in year end oil and
gas prices and other items, are reflected in revisions to reserves. During the
three-year period ended December 31, 2001, net revisions to reserves (excluding
the 35.3 MMBOE positive impact of price changes and a 10.9 MMBOE upward revision
of proved reserves resulting from the 2001 devaluation of the Argentine peso)
totaled 61.9 MMBOE, replacing approximately 70 percent of the Company's
production during the same period at a cost of $4.49 per BOE. During 2001, net
revisions to reserves (excluding the 40.1 MMBOE negative impact of lower
year-end 2001 oil and gas prices and a 10.9 MMBOE upward revision to proved
reserves resulting from the devaluation of the Argentine peso) totaled 25.0
MMBOE, replacing approximately 72 percent of the Company's production of 34.6
MMBOE at a cost of $6.75 per BOE.
As a result of stronger oil and gas prices in the first half of 2001
and activity in the Company's new Canadian operations, the Company spent $62.0
million on workovers, recompletion operations and other projects during 2001,
significantly higher than 2000. A measure of the overall success of the
Company's recompletion and workover operations during 2001 (excluding minor
equipment repair and replacement) was that improved production or operating
efficiencies were achieved from approximately 79 percent of such operations
consistent with the average for the last three years of 79 percent.
Development drilling activity is generated both through the Company's
exploration efforts and as a result of obtaining undeveloped acreage in
connection with producing property acquisitions. In addition, there are many
opportunities for infill drilling on Company leases currently producing oil and
gas. The Company intends to continue to pursue development drilling
opportunities which offer potentially significant returns to the Company.
During 2001, the Company participated in the drilling of 142 gross (119
net) development wells, of which 132 gross (110 net) were productive. At
December 31, 2001, the Company's proved reserves included approximately 144
development or infill drilling locations on its U.S. acreage, 82 locations on
its Canada acreage, 331 locations on its Argentina acreage, 43 locations on its
Ecuador acreage, 16 locations on its Bolivia acreage and three locations on its
Trinidad 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
development and infill drilling capital expenditures for 2001, spending an
aggregate of $96.2 million, including approximately $13.1 million in the U.S.,
$21.4 million in Canada, $56.7 million in Argentina and $5.0 million in Ecuador.
The Company also spent approximately $10.6 million on the acquisition of
development seismic data and other development activities in 2001. As a result
of lower anticipated oil and gas prices for 2002, compared to 2001, and the
economic instability in Argentina (see "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk - Foreign Currency and Operations Risk" included
elsewhere in this Form 10-K), the Company has decreased its 2002 capital budget
for all exploitation and development work from $168.8 million in 2001 to $105
million, with spending primarily concentrated in North America and Ecuador.
Exploitation and development activities for 2001 were concentrated
mainly in the U.S., Canada and Argentina core areas of the Company. The
following is a brief description of significant developments in the Company's
recent exploitation and development activities:
6
United States. The Company's U.S. exploitation program for 2001
included the drilling of 18 gross (nine net) development wells, of which 16
gross (seven net), or 89 percent, were successful. The Stagecoach area in
southern Oklahoma was a focus of the Company's U.S. development drilling
activities in 2001. Eight gross (four net) successful development wells were
drilled in this area in 2001, along with seven gross (three net) exploratory
wells, five gross (two net) of which were successful. As a result, the play has
been extended both in area and into deeper producing horizons previously
untested, setting the stage for continued drilling activity in the next several
years. In 2001, the Company also continued its horizontal infill development
program in the Luling field in south central Texas, where it drilled a total of
five wells. These five wells had a combined initial gross daily production rate
of 790 Bbls (700 Bbls net).
The Company's 2001 U.S. exploitation program also included 140
workovers and recompletions, of which 103 gross (97 net) were successful for a
74 percent success rate. Three fields with significant workover activity in 2001
were Main Pass 116, West Ranch and Darst Creek. Two workovers were completed in
the Main Pass 116 field, located in shallow federal waters, increasing gross
daily gas production by 6.4 MMcf (5.3 MMcf net) through recompletions.
The Company implemented a significant gas reservoir de-watering project
in the West Ranch field in south central Texas, with 21 wells adding gross daily
production of 3.3 MMcf (2.8 MMcf net) of gas and 210 Bbls (184 Bbls net) of oil.
Response from this project is continuing to improve as reservoir pressure is
drawn down, liberating previously unrecoverable trapped gas.
The Company's 2002 exploitation and development budget includes $19
million targeted towards U.S. projects. These projects will focus primarily on
development drilling, workovers and production enhancement and maintenance
projects.
Canada. The Company's exploitation activity in Canada was significant
in 2001 as a result of the acquisition of Genesis and Cometra. The Company
drilled 54 gross (40 net) development wells in 2001, of which 47 gross (33 net),
or 87 percent, were successful. Development drilling in 2001 focused on the
Sturgeon Lake, Grouard and West Central operating areas.
Wells in the Sturgeon Lake area target shallow, by-passed gas pays in
the Cretaceous section and attic oil accumulations in Devonian reef structures
identified and exploited by the application of 3-D seismic data and horizontal
drilling. Two significant extensional wells, the South Sturgeon Lake 3-21 and
the South Sturgeon Lake 10-27, confirmed new reserve accumulations in the third
quarter of 2001. Offsets to both discoveries are anticipated in early 2002. In
the fourth quarter of 2001, the Company successfully extended the Banff
formation play in the Kakut area of Sturgeon Lake. The Puskawaskau 1-20 was
drilled to a total depth of 7,550 feet and tested at a net rate of 1.0 MMcf per
day. Installation of compression during the first quarter of 2002 is expected to
increase net production to approximately 2.3 MMcf per day. Two pool extension
wells are planned in the Kakut area during 2002. Activity in the West Central
operating area focused on gas opportunities targeting the Devonian,
Mississippian and Triassic pay sections. Fifteen gross (nine net) successful
wells, including four horizontal wells seeking attic Devonian reef gas
accumulations, were drilled in 2001.
Three gross (three net) successful wells were drilled in the Grouard
operating area during 2001, targeting the shallow, gas-prone Cretaceous section
and deeper, oil-productive Devonian Gilwood formations. New reserve potential is
being delineated in Gilwood structural traps by the application of 3-D seismic
data and surface geochemistry.
The Company has set its 2002 Canadian exploitation and development
budget at $58 million. During 2002, the Company anticipates drilling 125 gross
(100 net) development wells in Canada. Activity will be concentrated in the
Sturgeon Lake, Grouard and East of 5 operating areas. Drilling plans include 27
gross (23 net) wells in Sturgeon Lake, 22 gross (20 net) wells in Grouard and 32
gross (24 net) wells in the East of 5 area. Much of the drilling activity will
occur in the first quarter of 2002 due to winter-access-only and will capitalize
on the exploitation and extension of relatively shallow Cretaceous and Devonian
gas pools discovered during the previous winter drilling campaign.
7
Argentina. 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 continued its highly successful development drilling program in
Argentina with the drilling of 68 successful wells in 69 attempts for a 99
percent success rate. With the 1999 acquisition of the El Huemul concession and
the 2000 and 2001 acquisitions of the properties in the Cuyo Basin, the
Company's development drilling locations in Argentina have increased
substantially with 331 drilling locations being recorded in its year-end 2001
proved reserves.
The Company's drilling program in Argentina relies heavily on
interpretation of 3-D seismic data to aid in the optimum placement of wells. A
total of 56 square miles of new 3-D seismic data was recorded in western Meseta
Espinosa Norte and northeast El Huemul in December 2001. Interpretation of this
data is underway to identify additional drilling prospects. With this new
seismic data, the Company now has 584 square miles of 3-D seismic data which
covers 32 percent of the area of all of its operated concessions. The Company
believes that significant additional drilling potential will continue to be
identified through the acquisition of future 3-D seismic surveys.
Planned 2002 investment activity in the San Jorge Basin includes a
reduced level of drilling and workovers as a result of the current political and
economic environment in Argentina (see "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk - Foreign Currency and Operations Risk" included
elsewhere in this Form 10-K). The total exploitation and development budget for
Argentina in 2002 is currently $11 million.
Bolivia. The focus for Bolivia continues to be on maximizing gas sales
to existing markets and the development of new gas markets. A geochemical survey
is scheduled for the second quarter of 2002. This survey will cover
approximately 100 square miles in the Chaco Block, located north of the Chaco
Sur exploitation block. The survey will test the probability of encountering gas
on structures identified by 2-D seismic data. The Company plans to spend $2
million on exploitation and development activities in Bolivia in 2002 and plans
to drill one well in 2003 at an estimated cost of $6.3 million to fulfill its
work commitment in this block.
Ecuador. During 2001, activity in Ecuador was focused on the
acquisition, processing and interpretation of a 160 square mile 3-D seismic
survey covering portions of Blocks 14 and 17 and the Shiripuno Block. A drilling
program is scheduled to begin in the second quarter of 2002 to build production
capacity to coincide with the expected opening of the OCP pipeline, currently
under construction, during the second half of 2003. Four development and
extensional drilling locations will be selected and drilled based on the new
seismic survey in Blocks 14 and 17. The two wells to be drilled in Block 17 will
be horizontal wells and will target measured depths of 12,000 feet and vertical
depths of approximately 10,000 feet in the Napo `U' formation. The rig will then
move to Block 14 to drill two vertical wells reaching depths of approximately
10,000 feet in the Napo `U' and Basal Tena formations. The Company's 2002
exploitation and development budget includes approximately $16 million for these
activities. The Company has a 75 percent working interest in Block 14, a 70
percent working interest in Block 17 and a 100 percent working interest in the
Shiripuno Block.
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 North America 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 data, is employed to identify prospects. Exploration in
North America is designed to generate reserve growth in this core area 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. The Company's international exploration projects currently underway in
Yemen and Trinidad are characterized by higher potential and higher risk.
8
From January 1, 1999, through December 31, 2001, the Company spent
approximately $189.8 million on exploration activities, excluding $53.6 million
to acquire the large acreage inventory of Genesis in May 2001. During this
period, the Company drilled 92 gross (63 net) exploration wells, of which
approximately 62 percent were productive. As a result of all of the Company's
exploration activities during the three-year period ended December 31, 2001, the
Company succeeded in adding 44.1 MMBOE to proved reserves, replacing
approximately 50 percent of production during this period at a cost of $4.31 per
BOE. The Company spent approximately $61.8 million on exploration activities
during 2001 (excluding $53.6 million to acquire the large acreage inventory of
Genesis in May 2001), spending approximately $52.7 million in North America and
$9.1 million in its other international areas, adding 21.0 MMBOE to its proved
reserves. The Company's 2002 exploration budget has been reduced to $38 million,
with approximately $24 million allocated to North American projects and $14
million targeted internationally. This reduction is due to the anticipated lower
oil and gas price environment for 2002, as compared to 2001, and the resulting
decrease in the Company's cash flow.
In conjunction with its focus on exploitation, the Company has
increased its attention on growing reserves through exploration efforts as well.
The following is a summary of major exploration activities:
United States. An exploratory well in the Stagecoach prospect, the
Cottonwood #1, was successfully completed in late 2001 in the deep Granite Wash
of the Dornick Hills formation below 15,800 feet at gross rates exceeding 600
gross (120 net) Bbls of oil per day and five gross (one net) MMcf of gas per
day. Additional uphole intervals remain to be completed pending long-term
production testing of the current completion interval. A new deep gas play in
the pre-Pennsylvanian formation has recently been identified and one well to
test that play is planned for 2002.
Another exploratory well in the Little Temple prospect in southern
Louisiana was in progress at December 31, 2001, and has now reached total depth
of 17,200 feet. Well logs and hydrocarbon shows while drilling indicate
approximately 53 feet of net pay in three zones in the middle Miocene formation.
Testing to determine the rate and reserve potential of these new zones is
expected to be completed by the end of the first quarter of 2002. The Company
has a 35 percent working interest in this well.
The Company has identified several new independent projects and leads
within the Tiger Bayou 3-D seismic survey in Terrebonne Parish in southern
Louisiana. The first prospect generated from this proprietary 3-D seismic survey
is the Richaud prospect. This gas prospect will target a deep (20,000 feet),
lower Miocene formation that is analogous to the producing horizon in the
prolific Lilly Boom field which is adjacent to and on trend with the Richaud
prospect. The Company holds a 38 percent working interest in this prospect.
Drilling is expected to begin in the second quarter of 2002.
The Company has leased 3,900 net acres in the Val Verde basin of west
Texas to develop a lower risk gas play based on horizontal drilling within the
Devonian formation. Drilling is expected to begin during the fourth quarter of
2002.
Activity is also underway to develop a balanced portfolio of
approximately 10 new exploration prospects during 2002. This work will be
concentrated within the three primary areas established for exploration in the
United States: southern Louisiana, west Texas and eastern New Mexico, and the
Texas gulf coast.
Canada. Consistent with the strategy that led to the entry into Canada,
the Company is progressing with a focused endeavor to generate additional impact
exploration prospects within the Canadian Western Sedimentary Basin. The
majority of these high potential prospects will target gas, which is consistent
with Vintage's overall business plan to focus its North American exploration
endeavor on significant reserve potential gas prospects.
Due to unseasonably warm weather, normal winter access this season has
not been available to the previously drilled exploratory wells within the
Northwest Territories license areas. Therefore, completion and testing of these
wells has been deferred until freeze-up next winter. During 2002, additional
seismic data and surface geochemistry will be acquired to further evaluate the
additional exploration potential within these licenses.
9
Trinidad. In Trinidad, the Company has a 36 percent working interest in
two exploration wells, the Carapal Ridge #1 and the Corosan #1, that were
drilled in the Central Block during 2001. Both wells successfully encountered
gas-bearing sands in the Miocene Herrera formation. The Carapal Ridge well
tested five separate intervals at a gross combined daily rate in excess of 50
MMcf of gas and 1,500 Bbls of condensate, while the Corosan well tested two
separate intervals at a gross combined daily rate in excess of eight MMcf of
gas. In light of these discoveries, evaluation of additional exploration
potential that has been identified within the Central Block is underway. The
high flow rate potential of the Carapal Ridge discovery resulted in the
development of an accelerated plan for an extended production test. The final
arrangements necessary to allow this early test to proceed are nearing
completion with the expected initiation of the test during the second half of
2002. The Company continues to work closely with Petroleum Company of Trinidad
and Tobago Limited (Petrotrin), the state oil company of Trinidad and a 35
percent working interest partner, to identify favorable long-term market options
that will allow further development of the project.
Yemen. During 2001, activity in Yemen focused on the acquisition of a
new 3-D seismic survey and a complementary, detailed grid geochemical survey in
Block S-1. These surveys were completed during the fourth quarter of 2001 and
are currently being utilized to evaluate several potentially large exploration
opportunities in the sub-salt (Lam) and intra-salt (Alif) sections. These
exploration targets are on trend with the adjacent Al-Nasr and Dhahab fields
that are currently producing at a combined daily rate of approximately 50 MBbls.
The Company has a 75 percent working interest in Block S-1. Current plans for
2002 are to drill up to four prospects. In addition, the Company is continuing
to evaluate the commerciality and potential of three wells previously drilled at
a total cost of approximately $15.0 million.
10
Oil and Gas Properties
At December 31, 2001, the Company owned and operated domestic producing
properties in nine states, with its U.S. proved reserves located primarily in
four core areas: Gulf Coast, East Texas, Mid-Continent and West Coast. In
addition, the Company established core areas in Argentina during 1995, Bolivia
during 1996, Ecuador in 1998 and Canada in 2000. As of December 31, 2001, the
Company operated 4,193 gross (3,703 net) productive wells and also owned
non-operating interests in 1,183 gross (685 net) 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
"Divestitures."
The following table sets forth estimates of the proved oil and gas
reserves of the Company at December 31, 2001, as estimated by the independent
petroleum consultants of Netherland, Sewell & Associates, Inc. for the U.S.,
Argentina, Ecuador and Trinidad, as estimated by the independent petroleum
consultants of DeGolyer and MacNaughton for Bolivia and as estimated by the
independent petroleum consultants of Outtrim Szabo Associates Ltd. for Canada:
Oil (MBbls) Gas (MMcf)
-------------------------------- -------------------------------- MBOE
Developed Undeveloped Total Developed Undeveloped Total Total
--------- ----------- ------- --------- ----------- --------- -------
West Coast ................... 41,711 4,606 46,317 89,175 5,080 94,255 62,027
Gulf Coast ................... 17,041 4,281 21,322 63,767 29,642 93,409 36,890
East Texas ................... 7,381 644 8,025 62,600 13,257 75,857 20,668
Mid-Continent ................ 523 761 1,284 36,520 25,108 61,628 11,555
------- ------- ------- ------- ------- --------- -------
Total U.S. ............ 66,656 10,292 76,948 252,062 73,087 325,149 131,140
Canada ....................... 13,259 8,549 21,808 206,539 29,573 236,112 61,160
------- ------- ------- ------- ------- --------- -------
Total North America ... 79,915 18,841 98,756 458,601 102,660 561,261 192,300
Argentina .................... 101,145 74,682 175,827 48,689 82,705 131,394 197,726
Bolivia ...................... 4,670 1,465 6,135 346,148 113,512 459,660 82,745
Ecuador ...................... 6,054 44,303 50,357 -- -- -- 50,357
Trinidad ..................... 545 641 1,186 25,085 39,324 64,409 11,920
------- ------- ------- ------- ------- --------- -------
Total Company ......... 192,329 139,932 332,261 878,523 338,201 1,216,724 535,048
======= ======= ======= ======= ======= ========= =======
- --------------------
Estimates of the Company's 2001 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 concentrated
behind-pipe in fields which it operates. Undeveloped proved reserves are
predominantly concentrated in development drilling locations and secondary
recovery projects.
As discussed in Note 1 to the Company's consolidated financial
statements included elsewhere in this Form 10-K, the Argentine government took
actions which, in effect, caused the devaluation of the peso in early December
2001. The translation of peso-denominated future production, development and
abandonment costs reduced the U.S. dollar cost of these expenses. This cost
reduction increased the Company's proved reserves in Argentina by approximately
10.9 MMBOE at December 31, 2001. As discussed in Note 12 to the Company's
consolidated financial statements included elsewhere in this Form 10-K, in
February 2002, the Argentina government also imposed a 20 percent excise tax on
oil exports, effective March 1, 2002. The tax is limited by law to a term of no
more than five years. Had this export tax been in effect at December 31, 2001,
it would not have materially affected the Company's proved reserve quantities in
Argentina.
11
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, 2001, the area
comprised 12 percent of the Company's total proved reserves and 47 percent of
the Company's U.S. proved reserves. The Company currently operates 1,382 gross
(1,346 net) productive wells in this area and owns an interest in 163 gross (13
net) productive wells operated by others. During 2001, net daily production for
this area averaged approximately 15,300 BOE, or 39 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, Tejon, Rio Vista and Buena Vista
fields. The San Miguelito field also has waterflood potential that may add
significant reserves and the Antelope Hills field has significant oil reserves
that may be added through steamflood expansion.
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, 2001, the Gulf Coast area comprised approximately seven percent of
the Company's total proved reserves and 28 percent of its U.S. proved reserves.
The Company currently operates 717 gross (697 net) productive wells in this area
and owns an additional interest in 50 gross (13 net) productive wells operated
by others. During 2001, net daily production from this area averaged
approximately 14,600 BOE, or 38 percent of total net daily U.S. production. A
significant inventory of workovers and recompletions exist in Gulf Coast fields
from Alabama to south Texas. Development drilling potential is also available in
fields in Texas and Louisiana.
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 with wells ranging in depth
from 1,300 feet to 14,800 feet. The East Texas area comprised approximately four
percent of the Company's December 31, 2001, total proved reserves and 16 percent
of its U.S. proved reserves. The Company currently operates 522 gross (452 net)
productive wells in this area and owns an interest in an additional 43 gross
(five net) productive wells operated by others. During 2001, net daily
production for this area averaged approximately 5,000 BOE, or 13 percent of
total net daily U.S. production. Significant infill drilling potential exists on
the Company's acreage in the South Gilmer, Edgewood, Southern Pine 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 two percent of the Company's
December 31, 2001, total proved reserves and nine percent of its U.S. proved
reserves. The Company currently operates 103 gross (54 net) productive wells in
this area and owns an interest in an additional 78 gross (10 net) productive
wells operated by others. During 2001, net daily production for this area
averaged approximately 3,700 BOE, or 10 percent of total net daily U.S.
production. Significant development drilling and recompletion opportunities
exist in the Marlow/Velma field. Additional projects to improve the ultimate
reserve recovery exist in the Shawnee Townsite waterflood.
Canada. The Company's Canadian producing properties are located in the
provinces of Alberta, Saskatchewan and British Columbia. The Company also has
approximately 1.2 million net undeveloped acres located in Alberta and
Saskatchewan with a significant portion, aggregating to 440,000 net acres, in
the Northwest Territories. The Canadian properties comprised approximately 11
percent of the Company's December 31, 2001, proved reserves. The Company
currently operates 443 gross (349 net) productive wells in Canada and owns
interests in 365 gross (97 net) wells operated by others. During 2001, net daily
production averaged approximately 6,000 Bbls of oil and 84,400 Mcf of gas.
12
Argentina. The Argentina properties consist primarily of 14 mature
producing concessions located on the south flank of the San Jorge Basin, all of
which are operated by the Company, four concessions located in the Cuyo Basin in
western Argentina, two of which are operated by the Company and two non-operated
concessions in the Neuguen Basin. These concessions comprised approximately 37
percent of the Company's December 31, 2001, total proved reserves. During 2001,
net daily production averaged approximately 28,900 Bbls of oil and 28,090 Mcf of
gas. The Company currently operates 1,232 gross (1,232 net) productive wells. In
addition, the Company owns an interest in 252 productive wells operated by
others. At December 31, 2001, the Company's proved reserves included
approximately 331 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 15 percent of the Company's December 31, 2001, total proved
reserves and include 15 gross (14 net) productive wells. Net daily production
during 2001 averaged approximately 24,900 Mcf of gas and 280 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 one exploration concession. 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 working
interest in the Shiripuno exploration concession. The Company currently operates
nine gross (seven net) productive wells with 2001 average net daily production
of approximately 3,770 Bbls of oil. These concessions comprised nine percent of
the Company's December 31, 2001, total proved reserves. Additional infill
drilling will be based on interpretation of the 3-D seismic data and will be
commensurate with the completion of the OCP pipeline currently estimated to
occur during the second half of 2003.
Marketing
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 Canadian
oil production is sold under short-term contracts at posted prices. The
Company's Argentina oil production is currently sold at port to Esso S.A.P.A.
(the Argentina affiliate of Exxon-Mobil), ENAP (the Chilean government-owned oil
company) 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. During 2001,
approximately 10 percent and 12 percent of the Company's total operating
revenues related to oil sales to ENAP and Esso S.A.P.A., respectively.
In January 2002, the Argentine government devalued the Argentine peso
("peso") and enacted an emergency law that required certain contracts that were
previously payable in U.S. dollars to be payable in pesos. Subsequently, on
February 13, 2002, the Argentine government announced a 20 percent tax on oil
exports, effective March 1, 2002. The tax is limited by law to a term of no more
than five years. For additional information, see "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk - Foreign Currency and Operations
Risk" included elsewhere in this From 10-K. Domestic Argentine oil sales are now
being paid in pesos, while export oil sales continue to be paid in U.S. dollars.
The Company currently exports approximately 35 percent of its Argentina
oil production. However, the Company believes that this export tax will have the
effect of decreasing all future Argentina oil revenues (not only export
revenues) by the tax rate for the duration of the tax. The Company believes that
the U.S. dollar equivalent value for domestic Argentina oil sales (now paid in
pesos) will move over time to parity with the U.S. dollar-denominated export
values, net of the export tax, thus impacting domestic Argentina values by a
like percentage to the tax. The adverse impact of this tax will be partially
offset by the net cost savings from the devaluation of the peso on
peso-denominated costs and may be further reduced by the Argentina income tax
savings related to deducting such impact.
13
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 North American gas is committed to
long-term fixed-price contracts, the Company is positioned to take advantage of
future strong gas price environments, 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. The Company's Argentina average gas price was historically
determined primarily by the realized oil price from the El Huemul concession
under a gas for oil exchange arrangement which expired at the end of 2001.
Beginning in 2002, the Company's Argentina gas will be sold under spot contracts
of varying lengths and, as a result of the emergency law enacted in January
2002, must now be paid in pesos as a result of the emergency law enacted in
January 2002. This will initially result in a decrease in sales revenue value
when converted to U.S. dollars due to the devaluation of the peso and current
market conditions. This value may improve over time as domestic Argentina gas
drilling declines and market conditions improve.
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 two affiliates of Enron South
America (the "Enron affiliates"). The terms of the short-term contract allowed
one of the Enron affiliates to 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. The terms of the long-term agreement allowed the other of the Enron
affiliates to purchase up to 15.4 MMcf of gas per day contingent upon its
development of emerging market opportunities in Brazil and Argentina. Sales
under the short-term contract began in April 2001 and the Company has received
payments in a timely manner. The Company has been notified that the short-term
contract will not be renewed at its expiration on March 31, 2002, and that the
long-term contract will be canceled prior to the commencement of gas deliveries.
The terms of the long-term contract require the Enron affiliate to make a $1.5
million payment to the Company in order to effect the early termination. No such
payment has been received. The Company is pursuing other alternative markets for
its Bolivia gas and believes that it is well positioned to continue to develop
markets as gas consumption continues to grow in the Southern Cone.
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) covering approximately 2.2 MMBbls at a
weighted average price of $23.77 per Bbl (NYMEX reference price) for various
periods in the first half of 2002. The Company has also entered into various gas
hedges (swap agreements) covering approximately 8.6 million MMBtu of its gas
production over the period from April through October 2002. The Canadian portion
of the gas swap agreements (approximately 4.3 million MMBtu) is at the AECO gas
price index reference price of 3.58 Canadian dollars per MMBtu and will be
settled in Canadian dollars. The AECO gas price index is the reference price
used for most of the Company's Canadian gas spot sales. The U.S. portion of the
gas swap agreements (approximately 4.3 million MMBtu) is at a NYMEX reference
price of $2.60 per MMBtu. Additionally, the Company has entered into basis swap
agreements for the approximately 4.3 million MMBtu of its U.S. gas production
covered by the gas swap agreements. These basis swaps establish a differential
between the NYMEX reference price and the various delivery points at levels that
are comparable to the historical differentials received by the Company. The
Company continues to monitor oil and gas prices and may enter into additional
oil and gas hedges or swaps in the future.
The following table reflects the Bbls hedged and the corresponding
weighted average NYMEX reference prices by quarter:
NYMEX
Reference Price
Quarter Ending Bbls Per Bbl
-------------- ---------------- -----------------
(in thousands)
March 31, 2002 1,150 $ 23.73
June 30, 2002 1,055 23.82
14
The following table reflects the MMBtu hedged in the U.S. and the
corresponding NYMEX reference price by quarter:
NYMEX
Reference Price
Quarter Ending MMBtu Per MMBtu
-------------- ---------------- -----------------
June 30, 2002 1,820,000 $ 2.60
September 30, 2002 2,440,000 2.60
December 31, 2002 620,000 2.60
The following table reflects the MMBtu hedged in Canada and the
corresponding AECO reference price by quarter:
AECO
Reference Price
Quarter Ending MMBtu Per MMBtu
-------------- ---------------- -----------------
(Canadian dollars)
June 30, 2002 1,819,903 C$ 3.58
September 30, 2002 2,439,870 3.58
December 31, 2002 619,967 3.58
The counterparties to the Company's swap agreements are commercial
banks. The Company had no derivative contracts with Enron Corp. or its
affiliates but does have minimal credit exposure of approximately $300,000 to
Enron North America Corp., which filed a voluntary petition for Chapter 11
reorganization in U.S. bankruptcy court along with Enron Corp., in addition to
the previously described contracts for Bolivia gas.
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 11 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 223 miles of varying diameter
pipe with a combined capacity in excess of 186 MMcf of gas per day. At December
31, 2001, there were 74 wells (61 of which are operated by the Company)
connected to these systems. Generally, the gathering systems buy gas at the
wellhead on the basis of a percentage of the resale price under contracts
containing terms of one to 10 years.
In 1999, the Company obtained ownership and operatorship of the Santa
Clara Valley gas plant located in Ventura County, California. This 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, natural gas liquids 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 is obtained from the process with a
turbo-expander compressor.
The plant is currently processing approximately eight MMcf of gas per
day and producing approximately 24,000 gallons per day of natural gas liquids
(butane/propane). The natural gas liquids 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.
15
Reserves
At December 31, 2001, the Company had proved reserves of 535.0 MMBOE,
comprised of 332.3 MMBbls of oil and 1.2 Tcf of gas, as estimated by the
independent petroleum consultants of Netherland, Sewell & Associates, Inc. for
the U.S., Argentina, Ecuador and Trinidad, as estimated by the independent
petroleum consultants of DeGolyer and MacNaughton for Bolivia and as estimated
by the independent petroleum consultants of Outtrim Szabo Associates Ltd. 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, 2001,
the present value of future net revenues (revenues less production, development
and abandonment costs) before income taxes attributable to the Company's proved
reserves at such date (in thousands):
Proved Reserves:
Future net revenues ........................................ $3,418,869
Present value of future net revenues before income taxes,
discounted at 10 percent ................................. 1,914,073
Standardized measure of discounted future net cash flows ... 1,438,141
Proved Developed Reserves:
Future net revenues......................................... $2,207,477
Present value of future net revenues before income taxes,
discounted at 10 percent ............................... 1,425,059
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, 2001, economic
conditions. The estimated future production is priced at prices prevailing at
December 31, 2001. The resulting estimated future gross revenues are reduced by
estimated future costs to develop and produce the proved reserves and by
estimated future abandonment costs, based on December 31, 2001, cost levels, but
such costs do not include debt service, general and administrative expenses and
income taxes.
As discussed in Note 1 to the Company's consolidated financial
statements included elsewhere in this Form 10-K, the Argentine government took
actions which in effect caused the devaluation of the peso in early December
2001. The translation of peso-denominated future production, development and
abandonment costs reduced the U.S. dollar cost of these expenses. This cost
reduction increased the Company's proved reserves in Argentina by approximately
10.9 MMBOE, increased the Company's present value of future net revenues before
income taxes, discounted at 10 percent for proved reserves by approximately
$101.9 million and increased the Company's standardized measure of discounted
future net cash flows by approximately $68.2 million at December 31, 2001.
As discussed in Note 12 to the Company's consolidated financial
statements included elsewhere in this Form 10-K, in February 2002, the Argentine
government also imposed a 20 percent excise tax on oil exports, effective March
1, 2002. This tax is limited by law to a term of no more than five years. Had
this export tax been in effect at December 31, 2001, it would not have
materially affected the Company's proved reserve quantities in Argentina, but it
would have reduced the Company's present value of future net revenues before
income taxes, discounted at 10 percent for proved reserves by approximately
$145.2 million and reduced the Company's standardized measure of discounted
future net cash flows by approximately $98.8 million.
For additional information concerning the historical discounted future
net revenues to be derived from these reserves and the disclosure of the
Standardized Measure information in accordance with the provisions of Statement
of Financial Accounting Standards No. 69, Disclosures about Oil and Gas
Producing Activities, see Note 11 "Supplementary Financial Information for Oil
and Gas Producing Activities" to the Company's consolidated financial statements
included elsewhere in this Form 10-K.
16
The reserve data set forth in this Form 10-K represent only estimates.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner. The
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates of different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimate. Accordingly, reserve estimates often differ from the
quantities of oil and gas that are ultimately recovered. The meaningfulness of
such estimates is highly dependent upon the accuracy of the assumptions upon
which they were based.
For further information on reserves, costs relating to oil and gas
activities and results of operations from producing activities, see Note 11
"Supplementary Financial Information for Oil and Gas Producing Activities" to
the Company's consolidated financial statements included elsewhere in this Form
10-K.
Productive Wells; Developed Acreage
The following table sets forth the Company's productive wells and
developed acreage assignable to such wells at December 31, 2001:
Productive Wells
---------------------------------------------------------
Developed Acreage Oil Gas Total
----------------------- ----------------- ----------------- -----------------
Gross Net Gross Net Gross Net Gross Net
---------- ---------- -------- ------- -------- ------- ------- -------
U.S.................... 484,018 355,380 2,472 2,225 586 366 3,058 2,591
Canada................. 431,897 209,969 239 153 569 293 808 446
Argentina.............. 217,848 181,894 1,473 1,318 11 11 1,484 1,329
Bolivia................ 76,603 65,483 - - 15 14 15 14
Ecuador................ 33,425 24,745 9 7 - - 9 7
Trinidad............... 160 58 - - 2 1 2 1
---------- ---------- -------- ------- -------- ------- ------- -------
Total.... 1,243,951 837,529 4,193 3,703 1,183 685 5,376 4,388
========== ========== ======== ======= ======== ======= ======= =======
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.
17
Undeveloped Acreage
At December 31, 2001, the Company held the following undeveloped acres
located in the U.S., Canada, Argentina, Bolivia, Ecuador, Yemen, Trinidad and
other international areas. With respect to such U.S. acreage held under leases,
104,219 gross (55,143 net) acres are held under leases with primary terms that
expire at varying dates through December 31, 2005, unless commercial production
has commenced. With respect to such Canadian acreage held under leases,
1,819,642 gross (1,057,798 net) acres are held under leases with primary terms
that expire at varying dates through December 31, 2005, unless commercial
production has commenced. The Company has the option to relinquish portions of
its undeveloped acreage in Argentina at various dates through 2007 or pay
increased mining royalties. The Bolivia acreage is held under concessions with
terms that expire at varying dates in 2003. The Yemen acreage is held under
concessions with terms that expire in 2002; however, the Company will begin
Phase II of its exploration program in Yemen in March 2002, which will extend
the acreage expiration to 2004. The Ecuador concessions have primary terms that
expire at various dates in 2005, 2006 and 2007 unless there is a commercial
discovery.
Gross Net
State/Country Acres Acres
--------------------------------------------- ---------- ----------
California................................... 7,204 6,595
Colorado..................................... 1,248 468
Louisiana.................................... 7,622 2,820
North Dakota................................. 31,131 18,617
Oklahoma..................................... 43,578 20,623
Texas........................................ 18,620 9,586
Wyoming...................................... 9,500 3,505
---------- ----------
Total U.S........................... 118,903 62,214
---------- ----------
Canada....................................... 2,182,747 1,232,399
Argentina.................................... 1,407,802 1,206,105
Bolivia...................................... 336,989 336,989
Ecuador...................................... 782,134 579,520
Yemen........................................ 1,108,019 831,014
Trinidad..................................... 27,278 9,820
Other International Areas.................... 275,107 192,575
---------- ----------
Total Company....................... 6,238,979 4,450,636
========== ==========
18
Production; Unit Prices; Costs
The following table sets forth information with respect to production,
average unit prices and costs for the periods indicated:
Years Ended December 31,
-----------------------------------
2001 2000 1999
Production: --------- --------- ---------
Oil (MBbls) -
U.S....................... 8,409 9,044 8,643
Canada.................... 1,539 19 -
Argentina................. 10,548 9,406 7,560
Ecuador................... 1,375 1,261 597
Bolivia................... 101 131 77
Trinidad.................. 2 - -
Total.................. 21,974(a) 19,861(b) 16,877
Gas (MMcf) -
U.S....................... 34,168 35,764 39,150
Canada.................... 22,132 312 -
Argentina................. 10,253 8,705 4,682
Bolivia................... 9,088 8,948 4,522
Total.................. 75,641 53,729 48,354
Total MBOE...................... 34,581 28,816 24,936
Average Sales Prices:
Oil (per Bbl) -
U.S....................... $ 23.08(c) $ 22.85(d) $ 15.92(e)
Canada.................... 20.55 26.05 -
Argentina (f)............. 21.80(c) 28.25 18.00
Ecuador (f)............... 17.65 24.27 17.28
Bolivia (f)............... 20.06 29.62 19.05
Total (f).............. 21.93(c) 25.55(d) 16.92(e)
Gas (per Mcf) -
U.S....................... $ 4.83 $ 3.91 $ 2.06
Canada.................... 2.50 5.73 -
Argentina................. 1.30 1.79 1.34
Bolivia (f)............... 1.72 1.75 .96
Total (f).............. 3.30 3.22 1.89
Production Costs (per BOE):
U.S............................. $ 7.56 $ 6.42 $ 5.31
Canada.......................... 6.23 7.09 -
Argentina (f)................... 4.98 4.87 4.30
Bolivia (f)..................... 2.71 2.33 3.64
Ecuador (f)..................... 6.47 4.85 3.82
Total (f)................. 6.18 5.54 4.88
- -----------------
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) Total production for 2001, before the impact of changes in
inventories, was 22,094 MBbls (Argentina- 10,644 MBbls,
Bolivia- 125 MBbls).
(b) Total production for 2000, before the impact of changes in
inventories, was 19,921 MBbls (Argentina- 9,512 MBbls,
Ecuador- 1,227 MBbls, Bolivia- 119 MBbls).
(c) Reflects the impact of oil hedges which increased the
Company's 2001 U.S., Argentina and total average oil prices
per Bbl by 91 cents, $1.14 and 89 cents, respectively.
(d) 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.
(e) 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.
(f) The 1999 amounts have been restated to reflect the
reclassification of transportation and storage costs to lease
operating costs.
19
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,
---------------------------------------------------------
2001 2000 1999
----------------- --------------- ----------------
Gross Net Gross Net Gross Net
------- ------- ----- ------ ----- --------
Development:
United States -
Productive................ 16 7.40 21 14.93 6 1.94
Non-Productive............ 2 1.45 2 1.68 - -
Canada
Productive................ 47 33.40 - - - -
Non-Productive............ 7 6.80 - - - -
Argentina -
Productive................ 68 68.00 40 40.00 10 10.00
Non-Productive............ 1 1.00 1 1.00 1 1.00
Bolivia -
Productive................ - - - - 1 1.00
Non-Productive............ - - - - - -
Ecuador
Productive................ 1 0.75 - - - -
Non-Productive............ - - - - - -
----- ------- ---- ------ ---- -------
Total 142 118.80 64 57.61 18 13.94
===== ======= ==== ====== ==== =======
Exploratory:
United States -
Productive................ 7 4.44 14 6.17 1 0.47
Non-Productive............ 4 2.53 4 2.02 11 5.56
Canada -
Productive................ 26 20.00 - - - -
Non-Productive............ 10 8.90 1 0.45 - -
Bolivia
Productive................ - - - - 7 7.00
Non-Productive............ - - 3 3.00 - -
Ecuador -
Productive................ - - - - - -
Non-Productive............ - - 1 1.00 - -
Yemen -
Productive................ - - - - - -
Non-Productive............ - - 1 0.75 - -
Trinidad
Productive................ 2 0.72 - - - -
Non-Productive............ - - - - - -
----- ------- ---- ------ ---- -------
Total 49 36.59 24 13.39 19 13.03
===== ======= ==== ====== ==== =======
Total:
Productive................ 167 134.71 75 61.10 25 20.41
Non-Productive............ 24 20.68 13 9.90 12 6.56
----- ------- ---- ------ ---- -------
Total................. 191 155.39 88 71.00 37 26.97
===== ======= ==== ====== ==== =======
- -----------------
The above well information excludes wells in which the Company has only
a royalty interest.
At December 31, 2001, the Company was a participant in the drilling,
completion or evaluation of 12 gross (10 net) wells. All of the Company's
drilling activities are conducted with independent contractors. The Company owns
no drilling equipment.
20
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 for 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 non-compliance. 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 land and leases to facilitate
exploration, while other states rely on voluntary pooling of land 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.
21
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 U.S. 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 holding 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 U.S. 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 (the "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.
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 was required 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.
22
In 2000, the FERC issued Order 637 to make short-term capacity release
more viable and to foster a more competitive and transparent market in which
prices are more efficient. Among other things, Order 637 removes the price cap
on short-term capacity releases, allows peak/off peak 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 the FERC's decision to allow 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 are subject to the laws and
regulations established there. Beginning in December 2001, new measures have
been enacted by law and executive order that may materially impact, among other
items, (i) the realized prices the Company receives for oil and gas it produces
and sells as a result of export taxes; (ii) the timing of repatriations of cash
to the U.S.; (iii) the Company's asset valuations; and (iv) peso-denominated
monetary assets and liabilities. See "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk - Foreign Currency and Operations Risk."
The Company's operations in Canada, Bolivia, Ecuador, Yemen and
Trinidad are subject to various laws and regulations in those countries. Those
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. The Company's Trinidad project is dependent, in
part, on the ability to identify favorable long-term market options for its gas
production.
23
Risk Factors
The following risks and uncertainties should be carefully considered
when reading this Form 10-K. If any of the events described below were to occur,
they could have a material adverse effect on the Company's business, financial
condition and operating results.
Oil and gas prices fluctuate widely, and low oil and gas prices could
adversely affect, and in the past have adversely affected, the Company's
financial results.
The Company's revenues, operating results, cash flow and future rate of
growth depend substantially upon prevailing prices for oil and gas.
Historically, oil and gas prices and markets have been volatile and are likely
to continue to be volatile in the future. The average prices that the Company
currently receives for its production are comparable to their historical
averages. However, a future significant decrease in oil and gas prices, such as
that experienced in 1998 and the first half of 1999, could have a material
adverse effect on the Company's cash flow and profitability. The substantial and
extended decline in oil and gas prices during 1998 and 1999 adversely affected
the Company's financial condition and results of operations. A sustained period
of low prices could have a material adverse effect on the Company's earnings and
financial condition.
Prices for oil and gas are subject to wide fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors that are beyond the Company's
control, including:
o political conditions in oil producing regions, including the Middle
East;
o domestic and foreign supplies of oil and gas;
o levels of consumer demand;
o weather conditions;
o domestic and foreign government regulations;
o prices and availability of alternative fuels; and
o overall economic conditions.
In addition, various factors may adversely affect the Company's ability
to market its oil and gas production, including:
o capacity and availability of oil and gas gathering systems and
pipelines;
o effects of federal and state regulation of production and
transportation;
o general economic conditions;
o changes in supply due to drilling by other producers;
o availability of drilling rigs; and
o changes in demand.
Lower oil and gas prices may adversely affect the Company's level of
capital expenditures, reserve estimates and borrowing capacity.
Lower oil and gas prices, such as those experienced by the Company in
1998 and the first half of 1999, have various adverse effects on the Company's
business, including reducing cash flows which, among other things, have caused
the Company in the past, and may cause the Company in the future, to decrease
its capital expenditures. A smaller capital expenditure program may adversely
affect the Company's ability to increase or maintain its reserve and production
levels. Lower prices may also result in reduced reserve estimates, one-time
write-offs of impaired assets and decreased earnings or losses due to lower
reserves and higher depreciation, depletion and amortization expense. For
example, in the fourth quarter of 1998 the Company recorded a significant
non-cash charge for the impairment of the Company's oil and gas properties due
to lower oil and gas prices.
24
The amount the Company can borrow under its revolving credit facility
is subject to periodic redetermination based, in part, on expectations of future
oil and gas prices applied to the Company's oil and gas reserve estimates. Lower
oil and gas prices could result in future reductions in the borrowing base under
the Company's revolving credit facility because lower oil and gas reserve values
would reduce the Company's liquidity and possibly trigger mandatory loan
repayments. Furthermore, reduction in the Company's liquidity could impede its
ability to fund future acquisitions. Lower prices may also cause the Company to
not be in compliance with maintenance covenants under its revolving credit
facility and may negatively affect its credit statistics and coverage ratios.
The Company's significant level of indebtedness requires that a
significant portion of its cash flow be used to pay interest and may limit its
ability to fund capital expenditures or obtain additional financing to fund
other obligations.
The Company currently has a significant amount of indebtedness. At
December 31, 2001, the Company's total long-term debt outstanding was
approximately $1.0 billion and the Company had a long-term debt to total
capitalization ratio of 57.7 percent. The Company's significant indebtedness
could have important consequences. For example:
o the Company's ability to obtain any necessary financing in the
future for working capital, capital expenditures, acquisitions,
debt service requirements or other purposes may be limited;
o a portion of the Company's cash flow from operations must be
utilized for the payment of interest on its indebtedness and will
not be available for financing capital expenditures or other
purposes; for example, interest payments for 2001 represented
approximately 16 percent of the Company's cash flows from
operations before working capital changes and interest expense;
o the Company's level of indebtedness and the covenants governing
its current indebtedness could limit the Company's flexibility in
planning for, or reacting to, changes in its business because
certain financing options may be limited or prohibited;
o the Company is more highly leveraged than some of its
competitors, which may place the Company at a competitive
disadvantage;
o the Company's level of indebtedness may make it more vulnerable
during periods of low oil and gas prices or in the event of a
downturn in its business because of its fixed debt service
obligations; and
o the terms of the Company's revolving credit facility require
interest and principal payments and maintenance of stated
financial covenants. If the requirements of this facility are not
satisfied, the lenders under this facility would be entitled to
accelerate the payment of all outstanding indebtedness under this
facility, and a default would be deemed to have occurred under
the terms of the Company's outstanding senior subordinated notes.
In such event, the Company cannot provide assurance that it would
have sufficient funds available or could obtain the financing
required to meet its obligations.
The Company may be able to incur substantial additional indebtedness in
the future. The Company's revolving credit facility would permit additional
borrowings of up to approximately $200 million, as of December 31, 2001. For
further discussion of the Company's borrowing base, see "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Liquidity." If the Company were to add additional indebtedness to its current
debt levels, the related risks discussed above, which it now faces, could
intensify.
25
The Company's future performance depends upon its ability to find or
acquire additional oil and gas reserves that are economically recoverable.
Unless the Company successfully replaces the reserves that it produces,
its reserves will decline, eventually resulting in a decrease in oil and gas
production and lower revenues and cash flows from operations. The Company has
historically succeeded in substantially replacing reserves through acquisition,
exploitation, development and exploration. The Company has conducted such
activities on its existing oil and gas properties as well as on newly acquired
properties. The Company may not be able to continue to replace reserves from
such activities at acceptable costs. Lower oil and gas prices may further limit
the kinds of reserves that can be developed at acceptable costs. Lower prices
also decrease the Company's cash flow and may cause it to reduce capital
expenditures. The business of exploring for, developing or acquiring reserves is
capital intensive. The Company may not be able to make the necessary capital
investments to maintain or expand its oil and gas reserves if cash flow from
operations is reduced and external sources of capital become limited or
unavailable. In addition, exploitation, development and exploration involve
numerous risks that may result in dry holes, the failure to produce oil and gas
in commercial quantities and the inability to fully produce discovered reserves.
The Company is continually identifying and evaluating acquisition
opportunities, including acquisitions that would be significantly larger than
those it has consummated to date. The Company cannot ensure that it will
successfully consummate any acquisition, that it will be able to acquire
producing oil and gas properties that contain economically recoverable reserves
or that any acquisition will be profitably integrated into its operations.
Acquisitions carry unknown risks including the potential for
environmental problems.
The Company's focus on acquiring producing oil and gas properties may
increase its potential exposure to liabilities and costs for environmental and
other problems existing on such properties. The Company expects to continue to
focus, as it has done in the past, on acquiring producing oil and gas properties
to replace reserves. Although the Company performs reviews of the acquired
properties that it believes are consistent with industry practice, such reviews
are inherently incomplete. In general, it is not feasible to review in depth
each individual property being acquired. Ordinarily, the Company focuses its
review efforts on the higher-valued properties and samples the remainder.
However, even an in-depth review of all properties and records may not
necessarily reveal existing or potential problems, nor will it permit the
Company to become sufficiently familiar with the properties to fully assess
their deficiencies and capabilities. Inspections may not always be performed on
each well included in an acquisition, and environmental problems, such as ground
water contamination and surface and subsurface damages from leakage, spills,
disposal or other releases of hazardous substances on such properties or from
adjoining properties that have migrated to such properties, are not necessarily
observable even when an inspection is performed.
Estimating reserves and future net revenues involves uncertainties and
oil and gas price declines may lead to impairment of oil and gas assets.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
developmental expenditures, including many factors beyond the control of the
producer. The reserve data included in this Form 10-K represent only estimates.
In addition, the estimates of future net revenues from the Company's proved
reserves and the present value of such estimates are based upon certain
assumptions about future production levels, prices and costs that may not prove
to be correct over time.
Quantities of proved reserves are estimated based on economic
conditions in existence during the period of assessment. Lower oil and gas
prices may have the impact of shortening the economic lives of certain fields
because it becomes uneconomic to produce all recoverable reserves on such
fields, thus reducing proved property reserve estimates. If such revisions in
the estimated quantities of proved reserves were to occur, they would have the
effect of increasing the rates of depreciation, depletion and amortization on
the affected properties, which would decrease earnings or result in losses
through higher depreciation, depletion and amortization expense. The revisions
may also be sufficient to trigger impairment losses on certain properties which
would result in a further non-cash charge to earnings. For example, the Company
recorded a significant non-cash charge for the impairment of oil and gas
properties in the fourth quarter of 1998 due to lower oil and gas prices.
26
The Company's international operations may be adversely affected by
political and economic instability, changes in the legal and regulatory
environment and other factors.
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 Canada, Argentina, Bolivia,
Ecuador, Yemen and Trinidad. For 2001, the Company's operations in Argentina
accounted for approximately 27 percent of the Company's revenues, 39 percent of
the Company's net operating profit (pre-tax income before impairments of oil and
gas properties, goodwill amortization and general and administrative and
interest expense) and 25 percent of its total assets. During 2001, the Company's
operations in Argentina represented its only foreign operations accounting for
more than 10 percent of its revenues or net operating profit (pre-tax income
before impairments of oil and gas properties and general and administrative and
interest expense). The Company's operations in Canada accounted for
approximately 39 percent of its total assets, including goodwill, at December
31, 2001. A majority of these Canadian assets were purchased on May 2, 2001, as
part of the acquisition of Genesis. The Company's exploration and production
operations include only eight months of the operations of Genesis in 2001. At
December 31, 2001, none of the Company's other international operations
accounted for more than 10 percent of its 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.
The Company's foreign properties, operations or investments in Canada,
Argentina, Bolivia, Ecuador, Yemen and Trinidad may be adversely affected by a
number of factors. For example:
o local political and economic developments could restrict or
increase the cost of the Company's foreign operations;
o exchange controls and currency fluctuations could result in
financial losses;
o royalty and tax increases and retroactive tax claims could increase
costs of the Company's foreign operations;
o expropriation of the Company's property could result in loss of
revenue, property and equipment;
o import and export regulations and other foreign laws or policies
could result in loss of revenues; and
o laws and policies of the U.S. affecting foreign trade, taxation and
investment could restrict the Company's ability to fund foreign
operations or may make foreign operations more costly.
In particular, the Company's Bolivian projects are dependent, at least
in part, on the operation of the Bolivia-to-Brazil gas pipeline. The operation
of this pipeline is subject to various factors outside the Company's control. In
addition, in the event of a dispute arising from foreign operations, the Company
may be subject to the exclusive jurisdiction of foreign courts or may not be
successful in subjecting foreign persons to the jurisdiction of the courts in
the U.S. The Company may also be hindered or prevented from enforcing its rights
with respect to actions taken by a foreign government or its agencies.
The Argentina economic and political situation continues to evolve and
the Argentine government may enact future regulations or policies that, when
finalized and adopted, may materially impact, among other items:
o the realized prices the Company receives for oil and gas that it
produces and sells as a result of export taxes;
o the timing of repatriations of cash to the U.S.;
o the Company's asset valuations; and
o peso-denominated monetary assets and liabilities.
See "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk - Foreign Currency and Operations Risk" included elsewhere in this Form
10-K.
27
The Company's hedging activities may expose the Company to the risk of
financial loss in certain circumstances.
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 impact of changes in market
prices for oil and gas on the average oil and gas prices received by the Company
may be reduced based on the level of the Company's hedging activities. These
hedging arrangements may limit the Company's potential gains if the market
prices for oil and gas were to rise substantially over the price established by
the hedge. In addition, the Company's hedging arrangements expose it to the risk
of financial loss in certain circumstances, including instances in which:
o production is less than expected;
o a change in the difference between published price indexes
established by pipelines in which the Company's hedged production
is delivered and the reference price established in the hedging
arrangements is such that the Company is required to make payments
to the counterparties to the Company's arrangements; or
o the counterparties to the Company's hedging arrangements fail to
honor their financial commitments.
The Company currently has contracts hedging 2.2 MBbls of oil for
various periods in the first half of 2002 at an average NYMEX reference price of
$23.77 per Bbl, contracts hedging 4.3 million MMBtu of U.S. gas for 2002 at a
NYMEX reference price of $2.60 per MMBtu and a contract hedging 4.3 million
MMBtu of Canadian gas for 2002 at an AECO reference price of 3.58 Canadian
dollars per MMBtu.
Uninsured risks associated with the Company's operations could result
in a substantial financial loss.
The Company's operations are subject to all of the risks and hazards
typically associated with the exploitation, development and exploration for, and
the production and transportation of oil and gas. These operating risks include,
but are not limited to:
o blowouts, cratering and explosions;
o uncontrollable flows of oil, natural gas or well fluids;
o fires;
o formations with abnormal pressures;
o pollution and other environmental risks; and
o natural disasters.
Any of these events could result in loss of human life, significant
damage to property, environmental pollution, impairment of the Company's
operations and substantial losses to the Company. In accordance with customary
industry practice, the Company maintains insurance against some, but not all, of
such risks and losses. The occurrence of such an event not fully covered by
insurance could have a material adverse effect on the Company's financial
position and results of operations.
Governmental and environmental regulations could adversely affect the
Company's business.
The Company's business is subject to certain foreign, federal, state
and local laws and regulations on taxation, the exploration for and development,
production and marketing of oil and gas, and environmental and safety matters.
Many laws and regulations require drilling permits and govern the spacing of
wells, rates of production, prevention of waste and other matters. Such laws and
regulations have increased the costs of planning, designing, drilling,
installing, operating and abandoning the Company's oil and gas wells and other
facilities. In addition, these laws and regulations, and any others that are
passed by the jurisdictions where the Company has production, could limit the
total number of wells drilled or the allowable production from successful wells,
which could decrease the Company's revenues.
28
The Company's operations are subject to complex environmental laws and
regulations adopted by the various jurisdictions where the Company operates. The
Company could incur liabilities to governments or third parties for any unlawful
discharge of oil, gas or other pollutants into the air, soil or water, including
responsibility for remedial costs. The Company could potentially discharge such
materials into the environment in any of the following ways:
o from a well or drilling equipment at a drill site;
o leakage from gathering systems, pipelines, transportation
facilities and storage tanks;
o damage to oil and natural gas wells resulting from accidents during
normal operations; and
o blowouts, cratering and explosions.
Because the requirements imposed by such laws and regulations are
frequently changed, the Company cannot ensure that laws and regulations enacted
in the future, including changes to existing laws and regulations, will not
adversely affect the Company's business. In addition, because the Company
acquires interests in properties that have been previously operated by others,
the Company may be liable for environmental damage caused by such former
operators.
Industry competition may impede the Company's growth.
The oil and gas industry is highly competitive, and the Company may not
be able to compete successfully or grow its business. The Company competes in
the areas of property acquisitions and the development, production and marketing
of, and exploration for, oil and gas with major oil companies, other independent
oil and gas concerns and individual producers and operators. The Company also
competes with major and independent oil and gas concerns in recruiting and
retaining qualified employees. Many of these competitors have substantially
greater financial and other resources than the Company. The Company may not be
able to successfully expand its business or attract or retain qualified
employees.
Employees
The Company employs approximately 240 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 180 full-time employees are responsible for the supervision and
operation of its U.S. field activities. The Company also employs approximately
350 people for the management and operation of its properties in Canada,
Argentina, Bolivia, Ecuador and Yemen. The Company believes its relations with
its employees are excellent.
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, 2001.
29
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........ 65 Director and Chairman of the Board of Directors
S. Craig George.................. 49 Director, President and Chief Executive Officer
William L. Abernathy............. 50 Director, Executive Vice President and Chief Operating Officer
William C. Barnes................ 47 Director, Executive Vice President, Chief Financial Officer,
Secretary and Treasurer
William E. Dozier................ 49 Senior Vice President - Operations
Kellam Colquitt.................. 54 Vice President - Exploration
Robert W. Cox.................... 56 Vice President - General Counsel
Andy R. Lowe..................... 50 Vice President - Marketing
Michael F. Meimerstorf........... 45 Vice President and Controller
Robert E. Phaneuf................ 55 Vice President - Corporate Development
Larry W. Sheppard................ 47 Vice President - New Ventures
Martin L. Thalken................ 41 Vice President - Acquisitions
Gary A. Watson................... 44 Vice President - Canadian Operations
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 42 years of oil and gas experience.
Mr. George has been a Director since October 1991, President of the
Company since September 1995 and Chief Executive Officer of the Company since
December 1997. He was also Chief Operating Officer of the Company from March
1994 to December 1997, an Executive Vice President of the Company from March
1994 to September 1995 and a Senior Vice President of the Company from October
1991 to March 1994. From April 1991 to October 1991, Mr. George was Vice
President of Operations and International with Santa Fe Minerals, Inc., an
independent oil and gas company ("Santa Fe Minerals"). From May 1981 to March
1991, he served in various other management and executive capacities with Santa
Fe Minerals and its subsidiary, Andover. From December 1974 to April 1981, Mr.
George held various management and engineering positions with Amoco Production
Company. He has a B.S. Degree in Mechanical Engineering from the University of
Missouri-Rolla.
Mr. Abernathy has been a Director since October 1999, and an Executive
Vice President and Chief Operating Officer of the Company since December 1997.
He was Senior Vice President--Acquisitions of the Company from March 1994 to
December 1997, Vice President--Acquisitions of the Company from May 1990 to
March 1994 and Manager--Acquisitions of the Company from June 1987 to May 1990.
From June 1976 to June 1987, Mr. Abernathy was employed by Exxon Company USA,
where he served at various times as Senior Staff Engineer, Senior Supervising
Engineer and in other engineering capacities, with assignments in drilling,
production and reservoir engineering in the Gulf Coast and offshore. He has B.S.
and M.S. Degrees in Mechanical Engineering from Auburn University.
30
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. Colquitt has been Vice President--Exploration of the Company since
May 2001. From April 2000 to May 2001, he was General Manager--North American
Exploration of the Company. He was employed by Ranger Oil Company, an
independent oil and gas company, from August 1995 to January 2000 where he
served as Vice President, International Exploration--Western Hemisphere and Vice
President, U.S. Operations. From December 1983 to July 1995 he was employed by
Santa Fe Minerals serving as Manager--International Exploitation, Exploration
and Production, and in various other management and supervisory capacities. He
was President of Colquitt Exploration, Inc. from 1978 to December 1983,
providing contract exploration services. From 1971 to 1978, he served in various
geology and supervisory capacities for Placid Oil Company. He has a B.S. Degree
in Geology from Texas A&M University.
Mr. Cox has been Vice President--General Counsel of the Company since
March 1988. From August 1982 to March 1988, he was employed by Santa Fe Minerals
and its subsidiary, Andover, where he served at various times as Vice
President--Law and Regional Attorney. From April 1982 to August 1982, he was
employed as Corporate Attorney by Andover. Prior to that time, Mr. Cox was
employed by Amerada Hess Corporation, a major oil company, served as General
Counsel and Secretary of Kissinger Petroleum Corporation, an independent oil and
gas company, and served on the legal staff of Champlin Petroleum Company, an
independent oil and gas company. He has a B.S. Degree in Business Administration
with a major in Petroleum Marketing from the University of Tulsa, and a Juris
Doctor from the University of Michigan Law School.
Mr. 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.
31
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--New Ventures of the Company since
May 2001. From November 1994 to May 2001, he was Vice President--International
of the Company. 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.
Mr. Watson has been Vice President--Canadian Operations of the Company
since June 2001. He was General Manager--Latin American Operations of the
Company from February 1998 to June 2001 and General Manager--Vintage Oil
Argentina, Inc. from August 1995 to February 1998. From March 1987 to July 1995,
he was employed by Santa Fe Minerals where he held various engineering and
management positions serving most recently as Manager of Project Development.
From August 1985 to January 1987, he was employed by Williams Exploration
Company as an engineer, with assignments in operations and reservoir
engineering. From September 1984 to July 1985, he was Bank Representative in the
Energy Group of Texas Commerce Bank. From May 1979 to August 1984, he was
employed by Texaco, Inc. as an engineer in the New Orleans Division. He has a
B.S. Degree in Chemical Engineering (Petroleum Option) from the University of
Pittsburgh.
32
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 sales 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
---------- ---------- ----------
2001
----
First Quarter............... $ 22.81 $ 18.44 $ .03
Second Quarter.............. 22.20 18.02 .03
Third Quarter............... 20.25 14.75 .035
Fourth Quarter.............. 18.95 11.77 .035
2000
----
First Quarter............... $ 20.56 $ 11.19 $ .025
Second Quarter.............. 25.13 18.13 .025
Third Quarter............... 24.75 16.81 .03
Fourth Quarter.............. 27.94 18.13 .03
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, 2001, the common stock was held by 168 holders of record and
approximately 16,500 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 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 Company is prohibited from
paying cash dividends if the Company's Consolidated Interest Coverage Ratio (as
defined in indentures) does not exceed 2.5 to 1.0. The Company is also
prohibited from paying 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 equity offerings subsequent to
November 30, 2000, 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 $559 million at December 31, 2001.
33
Item 6. Selected Financial Data.
SELECTED FINANCIAL AND OPERATING DATA
Years Ended December 31,
----------------------------------------------------------------
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
(In thousands, except per share amounts and operating data)
Income Statement Data:
Oil and gas sales (a)............................ $ 731,386 $ 680,350 $ 376,924 $ 270,251 $ 358,366
Gas marketing revenues........................... 130,209 128,836 60,275 54,108 45,981
Gathering revenues............................... 17,032 19,998 6,955 7,741 18,063
Total revenues (a)............................... 909,241 806,181 502,928 333,323 420,476
Operating expenses (a)........................... 357,683 300,477 184,367 184,932 176,552
Exploration costs................................ 22,073 25,242 14,674 24,056 12,667
Depreciation, depletion and amortization......... 168,944 100,109 107,807 108,975 96,307
Impairment of oil and gas properties............. 29,050 225 3,306 70,913 8,785
Amortization of goodwill......................... 11,940 - - - -
Interest......................................... 64,728 48,437 58,665 43,680 36,762
Net income (loss)................................ 133,507 195,893 73,371 (87,665) 54,954
Income (loss) per share before cumulative
effect of change in accounting principle:
Basic................................... 2.12 3.15 1.27 (1.69) 1.07
Diluted................................. 2.09 3.08 1.24 (1.69) 1.05
Income (loss) per share:
Basic................................... 2.12 3.13 1.27 (1.69) 1.07
Diluted................................. 2.09 3.06 1.24 (1.69) 1.05
Dividends declared per share..................... .14 .14 - .09 .07
----------- ----------- ----------- ----------- -----------
Balance Sheet Data (end of year):
Total assets..................................... $ 2,096,788 $ 1,338,397 $ 1,168,134 $ 1,014,175 $ 915,394
Long-term debt................................... 1,010,673 464,229 625,318 672,507 451,096
Stockholders' equity............................. 729,443 624,857 431,129 273,958 337,578
----------- ----------- ----------- ----------- -----------
Operating Data:
Production:
Oil (MBbls)...................................... 21,974 19,861 16,877 16,434 15,457
Gas (MMcf)....................................... 75,641 53,729 48,354 47,238 42,691
----------- ----------- ----------- ----------- -----------
Average Sales Prices:
Oil (per Bbl).................................... $ 21.93 $ 25.55 $ 16.92 $ 11.06 $ 17.20
Gas (per Mcf).................................... 3.30 3.22 1.89 1.87 2.17
----------- ----------- ----------- ----------- -----------
Proved Reserves (end of year):
Oil (MBbls)...................................... 332,261 318,560 303,190 164,457 187,768
Gas (MMcf)....................................... 1,216,724 1,023,208 988,989 806,833 552,163
Total proved reserves (MBOE)..................... 535,048 489,095 468,022 298,929 279,795
----------- ----------- ----------- ----------- -----------
Present value of estimated future net revenues
before income taxes discounted at 10 percent
(in thousands):
Oil and gas properties.................. $ 1,914,073 $ 4,338,616 $ 2,989,626 $ 703,211 $ 1,222,560
Gathering systems and plant............. 1,182 14,188 13,764 4,493 5,940
Standardized measure of discounted future
net cash flows (in thousands).................... 1,438,141 2,951,121 2,247,237 648,222 1,016,645
----------- ----------- ----------- ----------- -----------
- -----------------
(a) The 1999, 1998 and 1997 amounts have been restated to reflect
the reclassification of transportation and storage costs to
lease operating costs.
Significant acquisitions of producing oil and gas properties during
2001, 1999 and 1997 and significant dispositions of oil and gas properties
during 2001 and 1999 affect the comparability between the Financial and
Operating Data for the years presented above.
34
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,
--------------------------------
2001 2000 1999
-------- -------- --------
Production:
Oil (MBbls) -
U.S............................ 8,409 9,044 8,643
Canada......................... 1,539 19 -
Argentina...................... 10,548 9,406 7,560
Ecuador........................ 1,375 1,261 597
Bolivia........................ 101 131 77
Trinidad....................... 2 - -
Total...................... 21,974(a) 19,861(b) 16,877
Gas (MMcf) -
U.S............................ 34,168 35,764 39,150
Canada......................... 22,132 312 -
Argentina...................... 10,253 8,705 4,682
Bolivia........................ 9,088 8,948 4,522
Total...................... 75,641 53,729 48,354
Total MBOE........................ 34,581 28,816 24,936
Average Sales Prices:
Oil (per Bbl) -
U.S............................ $ 23.08(c) $ 22.85(d) $ 15.92(e)
Canada......................... 20.55 26.05 -
Argentina...................... 21.80(c) 28.25 18.00
Ecuador........................ 17.65 24.27 17.28
Bolivia........................ 20.06 29.62 19.05
Total...................... 21.93(c) 25.55(d) 16.92(e)
Gas (per Mcf) -
U.S............................ $ 4.83 $ 3.91 $ 2.06
Canada......................... 2.50 5.73 -
Argentina...................... 1.30 1.79 1.34
Bolivia........................ 1.72 1.75 .96
Total...................... 3.30 3.22 1.89
- ---------------------
(a) Total production for 2001, before the impact of changes in
inventories, was 22,094 MBbls (Argentina- 10,644 MBbls, Bolivia-
125 MBbls).
(b) Total production for 2000, before the impact of changes in
inventories, was 19,921 MBbls (Argentina- 9,512 MBbls, Ecuador-
1,227 MBbls, Bolivia- 119 MBbls).
(c) Reflects the impact of oil hedges which increased the Company's
2001 U.S., Argentina and total average oil prices per Bbl by 91
cents, $1.14 and 89 cents, respectively.
(d) 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.
(e) 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.
35
Average U.S. and Canada oil prices received by the Company fluctuate
generally with changes in the NYMEX reference price for oil. The Company's
Argentina oil production is sold at West Texas Intermediate spot prices as
quoted on the Platt's Crude Oil Marketwire (approximately equal to the NYMEX
reference price) less a specified differential. The Company's Ecuador oil
production is sold to various third party purchasers at West Texas Intermediate
spot prices less a specified differential. In 2001, the Company experienced a 14
percent decrease in its average oil price, including the impact of hedging
activities (23 percent decrease excluding hedging activities), compared to 2000.
The Company experienced a 51 percent increase in its average oil price,
including the impact of hedging activities (63 percent increase excluding
hedging activities) in 2000 compared to 1999 as a result of OPEC's efforts to
reduce the available supply of crude oil in the global markets along with
increasing demand.
As discussed in Note 1 to the Company's consolidated financial
statements included elsewhere in this Form 10-K, the Argentine government took
actions which in effect caused the devaluation of the peso in early December
2001 and, in January 2002, enacted an emergency law that required certain
contracts that were previously payable in U.S. dollars to be payable in pesos.
Subsequently, on February 13, 2002, the Argentine government announced a 20
percent tax on oil exports, effective March 1, 2002. The tax is limited by law
to a term of no more than five years. For additional information, see "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk - Foreign Currency
and Operations Risk" included elsewhere in this Form 10-K. Domestic Argentina
oil sales are now being paid in pesos, while export oil sales continue to be
paid in U.S. dollars.
The Company currently exports approximately 35 percent of its Argentina
oil production. However, the Company believes that this export tax will have the
effect of decreasing all future Argentina oil revenues (not only export
revenues) by the tax rate for the duration of the tax. The Company believes the
U.S. dollar equivalent value for domestic Argentina oil sales (now paid in
pesos) will move over time to parity with the U.S. dollar-denominated export
values, net of the export tax, thus impacting domestic Argentina values by a
like percentage to the tax. The adverse impact of this tax will be partially
offset by the net cost savings from the devaluation of the peso on
peso-denominated costs and may be further reduced by the Argentina income tax
savings related to deducting such impact.
The Company participated in oil hedges covering 5.5 MMBbls, 9.3 MMBbls
and 1.8 MMBbls in 2001, 2000 and 1999, respectively. The impact of the 2001
hedges increased the Company's U.S. average oil price by 91 cents to $23.08 per
Bbl, its Argentina average oil price by $1.14 to $21.80 per Bbl and its overall
average oil price by 89 cents to $21.93 per Bbl. The impact of the 2000 hedges
decreased 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 impact of the 1999
hedges decreased 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's realized average oil price for 2001 (before hedges) was
approximately 81 percent of the NYMEX reference price, compared to 91 percent in
2000 and 88 percent in 1999.
Average U.S. gas prices received by the Company fluctuate generally
with changes in spot market prices, which may vary significantly by region, as
evidenced by the significantly higher gas prices in California during the first
half of 2001 due to the localized power shortage. The Company's Canada gas is
generally sold at spot market prices as reflected by the AECO gas price index.
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. The
Company's Argentina average gas price was historically determined primarily by
the realized oil price from the El Huemul concession under a gas for oil
exchange arrangement which expired at the end of 2001. Beginning in 2002, the
Company's Argentina gas will be sold under spot contracts of varying lengths
and, as a result of the emergency law enacted in January 2002, must now be paid
in pesos as a result of the emergency law enacted in January 2002. This will
initially result in a decrease in sales revenue value when converted to U.S.
dollars due to the devaluation of the peso and current market conditions. This
value may improve over time as domestic Argentina gas drilling declines and
market conditions improve. The Company's total average gas price for 2001 was
two percent higher than 2000 and 2000 was 70 percent higher than 1999.
36
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) covering approximately 2.2 MMBbls at a
weighted average price of $23.77 per Bbl (NYMEX reference price) for various
periods in the first half of 2002. The Company has also entered into various gas
hedges (swap agreements) covering approximately 8.6 million MMBtu of its gas
production over the period April through October 2002. The Canadian portion of
the gas swap agreements (approximately 4.3 million MMBtu) is at the AECO gas
price index reference price of 3.58 Canadian dollars per MMBtu and will be
settled in Canadian dollars. The U.S. portion of the gas swap agreements
(approximately 4.3 million MMBtu) is at a NYMEX reference price of $2.60 per
MMBtu. Additionally, the Company has entered into basis swap agreements for the
approximately 4.3 million MMBtu of its U.S. gas production covered by the gas
swap agreements. These basis swaps establish a differential between the NYMEX
reference price and the various delivery points at levels that are comparable to
the historical differentials received by the Company. For additional
information, see "Items 1 and 2. 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 2001 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 $13.7 million and $21.5 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 $4.6 million and $7.5 million, respectively, based
on 2001 gas production.
Period to Period Comparison
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
During December 2000 and May 2001, the Company made two acquisitions
which significantly impacted the period to period comparison for the year ended
December 31, 2001, compared to the year ended December 31, 2000. These
acquisitions (the "Canadian Acquisitions") include the purchase of 100 percent
of the outstanding common stock of Cometra Energy (Canada) Ltd. (the "Cometra
Acquisition") in December 2000 and the purchase of 100 percent of the
outstanding common stock of Genesis Exploration Ltd. (the "Genesis Acquisition")
in May 2001. The Company's consolidated revenues and expenses for the year ended
December 31, 2001, include, under the purchase method of accounting, the
consolidation of the revenues and expenses of Genesis for the last eight months
of 2001.
The Company reported net income of $133.5 million for the year ended
December 31, 2001, compared to net income of $195.9 million for the same period
in 2000. An increase in the Company's oil and gas production of 20 percent on an
equivalent barrel basis was substantially offset by a 14 percent reduction in
average oil prices and higher charges for depreciation, depletion and
amortization of oil and gas properties and goodwill. Net income for 2001
included a $17.9 million after-tax loss due to the impairment of oil and gas
properties, a $16.7 million after-tax gain on sales of non-strategic properties
and a $3.3 million after-tax gain due to the devaluation of the Argentine peso
in December 2001. Net income for 2000 included a $16.3 million after-tax
non-recurring charge due to an adverse judgment from litigation, a $1.1 million
after-tax loss on sales of non-strategic properties and a $1.4 million after-tax
loss due to a change in accounting principle.
Oil and gas sales increased $51.0 million (eight percent), to $731.4
million for 2001 from $680.4 million for 2000. A 41 percent increase in gas
production, partially offset by a two percent decrease in average gas prices,
accounted for a $76.6 million increase in gas sales for 2001 as compared to
2000. A 14 percent decrease in average oil prices more than offset an 11 percent
increase in oil production and accounted for a $25.6 million decrease in oil
sales for 2001 as compared to 2000. The 11 percent increase in oil production
and the 41 percent increase in gas production are primarily the result of the
Canadian Acquisitions and the Company's exploitation and exploration activities,
partially offset by declines in U.S. production.
37
A gain on disposition of assets of $26.9 million ($16.7 million net of
tax) was reflected in 2001 as a result of $47.1 million in proceeds from
divestitures of non-strategic oil and gas properties in the United States. In
2000, the Company recorded a loss on disposition of assets of $1.7 million ($1.1
million net of tax). Other than the gain recorded, the 2001 divestitures did not
significantly affect the Company's 2001 results of operations as the majority of
the divestitures occurred in the fourth quarter of 2001.
As discussed in Note 1 to the Company's consolidated financial
statements included elsewhere in this Form 10-K, the Argentine government took
actions which, in effect, caused the devaluation of the peso in early December
2001. The translation of peso-denominated balances at December 31, 2001, and
peso-denominated transactions during December 2001 increased 2001 net income by
approximately $3.3 million, consisting of a foreign currency exchange gain of
approximately $2.3 million (included in other income (expense) on the statement
of operations) and approximately $1.0 million in reductions of certain operating
expenses. There was no such gain in 2000.
As a result of an unfavorable decision by the Supreme Court of
Argentina, the Company had recorded as other expense in 2000 a non-recurring
charge of $25.1 million ($16.3 million net of tax). No similar charge was
incurred in 2001.
Lease operating expenses, including production taxes, increased $54.0
million (34 percent), to $213.6 million for 2001 from $159.6 million for 2000
primarily due to the 20 percent increase in production, increased lease power
and fuels costs, higher costs for oilfield services and certain one-time repair
costs in the U.S. Lease operating expenses per equivalent barrel produced
increased 12 percent to $6.18 in 2001 from $5.54 for 2000. 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 35 cents and 36 cents to the reported lease operating
expense per BOE in 2001 and 2000, respectively.
Exploration costs decreased $3.1 million (12 percent), to $22.1 million
for 2001 from $25.2 million for 2000. During 2001, the Company's exploration
costs included $12.2 million for unsuccessful exploratory drilling and lease
impairments, primarily in North America, and $9.9 million for seismic and other
geological and geophysical costs. Exploration costs for 2000 included $21.6
million for unsuccessful exploratory drilling, primarily in Bolivia, $2.9
million for leasehold impairments and $0.7 million for other geological and
geophysical costs.
Impairments of oil and gas properties of $29.1 million ($17.9 million
net of tax) were recognized in 2001, compared to $0.2 million of impairments in
2000, due primarily to reserve revisions on certain Canadian and U.S.
properties. The Company reviews its proved properties for impairment on a field
basis and recognizes an impairment whenever events or circumstances (such as
declining oil and gas prices) indicate that the properties' carrying values may
not be recoverable. If an impairment is indicated based on the Company's
estimated future net revenues for total proved and risk-adjusted probable and
possible 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 oil and 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. If future price expectations are reduced, it is possible that
additional significant impairment provisions for oil and gas properties would be
required. Also, the economic instability in Argentina could cause economic
conditions that would result in future significant impairments for the Company's
oil and gas properties in that country.
General and administrative expenses increased $9.4 million (23
percent), to $50.8 million for 2001 from $41.4 million for 2000 due primarily to
costs associated with the Canadian operations acquired through the Canadian
Acquisitions and personnel additions and consulting costs in conjunction with
the Company's higher level of capital expenditures. General and administrative
expenses per equivalent barrel produced increased slightly to $1.47 for 2001
from $1.44 for 2000.
Depreciation, depletion and amortization increased $68.8 million (69
percent), to $168.9 million for 2001 from $100.1 million for 2000, due primarily
to the 20 percent increase in production on a BOE basis and the 43 percent
increase in the average amortization rate per equivalent barrel produced from
$3.33 in 2000 to $4.75 in 2001 primarily due to the Genesis Acquisition.
38
Goodwill represents the excess of the purchase price over the estimated
fair value of the net assets acquired in the purchase of Genesis. In 2001,
goodwill was amortized using the unit-of-production basis over the total proved
reserves acquired and totaled approximately $11.9 million. There was no goodwill
amortization recorded in 2000. The Company adopted the provisions of Statement
of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
("SFAS No. 142") on January 1, 2002. Under SFAS 142, goodwill is no longer
subject to amortization. Rather, goodwill is subject to at least an annual
assessment for impairment by applying a fair-value based test. Management has
not determined at this time if the adoption of SFAS No. 142 will have any other
impact on the Company's financial position or results of operations. Management
plans to engage an independent appraisal firm to perform an assessment of the
fair value of its Canadian segment, which will be compared to the carrying value
of the segment to determine whether any impairment existed on the date of
adoption. Under the provisions of SFAS No. 142, the Company has six months from
the time of adoption to have its appraisal completed.
Interest expense increased $16.3 million (34 percent), to $64.7 million
for 2001 from $48.4 million for 2000, due primarily to a 60 percent increase in
the Company's total average outstanding debt year over year, primarily due to
the Canadian Acquisitions. This increase was partially offset as the Company's
overall average interest rate decreased to 7.58 percent in 2001 as compared to
8.87 percent in 2000. This reduction resulted from lower rates on its
floating-rate debt due to overall market reductions and a significant increase
in its level of lower-cost floating-rate borrowings versus fixed rate debt.
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, 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.
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 U.S. 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.
39
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 primarily due to 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 25 cents and 36 cents 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 (seven
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.
Capital Expenditures
During 2001, the Company's total oil and gas capital expenditures were
$891.4 million, including $560.1 million allocated to producing oil and gas
properties as part of the Genesis Acquisition and $42.3 million for the
acquisition of the La Ventana and Rio Tunuyan concessions in Argentina. In North
America, the Company's non-acquisition oil and gas capital expenditures totaled
$186.2 million, including $53.6 million for undeveloped leasehold as part of the
acquisition of Genesis. Exploration activities accounted for $106.3 million of
the North America capital expenditures with exploitation activities contributing
$79.9 million. During 2001, the Company's international non-acquisition oil and
gas capital expenditures totaled $98.0 million, consisting of $76.8 million in
Argentina on exploitation activities, $11.4 million in Ecuador, principally on
exploitation, and $5.7 million and $2.7 million on exploration projects in
Trinidad and Yemen, respectively. The Company also spent another $1.4 million in
other international areas.
As of December 31, 2001, the Company had total unproved oil and gas
property costs of approximately $100.0 million consisting of undeveloped
leasehold costs of $82.7 million, including $60.3 million in Canada, and
exploratory drilling in progress of $17.3 million. Approximately $20.4 million
of the unproved 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.
On May 2, 2001, the Company completed the Genesis Acquisition for total
consideration of $617 million, including transaction costs and the assumption of
the estimated net indebtedness of Genesis at closing (see Note 7 "Significant
Acquisition" to the consolidated financial statements included elsewhere in this
Form 10-K). The cash portion of the acquisition price was paid through advances
under the Company's revolving credit facility and cash on hand.
40
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. The Company's preliminary capital expenditure budget
for 2002 is currently set at $144 million, exclusive of acquisitions. The
Company does not have a specific acquisition budget since the timing and size of
acquisitions are difficult to forecast. The Company is actively pursuing
additional acquisitions of oil and gas properties. In addition to
internally-generated cash flow and advances under its revolving credit facility,
the Company may seek additional sources of capital to fund any future
significant acquisitions (see "Liquidity"), however, no assurance can be given
that sufficient funds will be available to fund the Company's desired
acquisitions.
The Company's recent capital expenditure history is as follows:
Years Ended December 31,
--------------------------------------
(In thousands) 2001 2000 1999
---------- ---------- ----------
Acquisition of oil and gas reserves..................... $ 607,217 $ 91,448 $ 166,787
Drilling................................................ 135,620 121,911 46,280
Acquisition of undeveloped acreage and seismic.......... 85,489 18,084 12,742
Workovers and recompletions............................. 62,038 25,811 10,749
Other................................................... 1,024 419 927
---------- ---------- ----------
Oil and gas capital expenditures................... 891,388 257,673 237,485
---------- ---------- ----------
Acquisition and construction of gathering systems....... 1,256 299 680
---------- ---------- ----------
Total.............................................. $ 892,644 $ 257,972 $ 238,165
========== ========== ==========
Liquidity
Internally generated cash flow, the borrowing capacity under its
revolving credit facility and its ability to adjust its level of capital
expenditures 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. Since
1990, in conjunction with the purchase of substantial oil and gas assets, the
Company has completed five public equity offerings as well as two public debt
offerings and two Rule 144A debt offerings, which provided the Company with
aggregate net proceeds of $843 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. 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.
41
On May 30, 2001, the Company issued $200 million of its 7 7/8% Senior
Subordinated Notes due 2011 (the "7 7/8% Notes"). The 7 7/8% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after May 15, 2006. In addition, prior to May 15, 2004, the Company may redeem
up to 35 percent of the 7 7/8% Notes with the proceeds of certain underwritten
public offerings of the Company's common stock. The 7 7/8% Notes mature on May
15, 2011, with interest payable semiannually on May 15 and November 15 of each
year. All of the net proceeds to the Company from the sale of the 7 7/8% Notes
were used to repay a portion of the existing indebtedness under the Company's
revolving credit facility.
Under the Second Amended and Restated Credit Agreement dated November
30, 2000, as amended, (the "Bank Facility"), certain banks have provided to the
Company a $625 million unsecured revolving credit facility. The Bank Facility
establishes a borrowing base 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 facility size or the borrowing
base.
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 December 31, 2001, the Company had
$411.4 million outstanding under its Bank Facility, excluding outstanding
letters of credit of approximately $12.3 million. As of February 28, 2002, 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 3.36 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.
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.
The Company's unused availability under the Bank Facility at February
28, 2002, was approximately $200 million; however, the borrowing base is
currently under review by the banks. Due to lower oil and gas price expectations
by the banks and the economic instability in Argentina, the Agent and
Syndication Agent banks have recommended a new borrowing base of $550 million,
with security provided by the Company on certain assets. This recommendation is
pending approval of 75 percent of the banks in the syndicate. If approved, the
Company will have approximately $124 million available under the Bank Facility.
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 next borrowing base
redetermination will be in May 2002.
The Company's internally generated cash flow, results of operations and
financing for its operations are dependent on oil and gas prices. For 2001,
approximately 64 percent of the Company's production was oil. Realized oil
prices for the year decreased by 14 percent as compared to 2000. This decline in
prices substantially offset an increase in total production on a BOE basis of 20
percent. 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. To the extent oil prices continue to decline, the
Company's earnings and cash flow from operations may be adversely impacted.
Continued low oil and gas prices could cause the Company to not be in compliance
with maintenance covenants under its Bank Facility and could negatively affect
its credit statistics and coverage ratios and thereby affect its liquidity.
Inflation
In recent years inflation has not had a significant impact on the
Company's operations or financial condition. However, industry specific
inflationary pressures built up in late 2000 and in 2001 due to favorable
conditions in the industry. While oil and gas prices have recently declined, the
cost of services in the oil and gas industry have not declined by a similar
percentage. Any increases in product prices could cause inflationary pressures
specific to the industry to also increase.
42
As a result of the recent devaluation of the peso, the Company expects
inflationary pressures to build in Argentina. The Company anticipates that
peso-denominated costs will gradually increase, but the ultimate impact of such
increases when converted to U.S. dollars cannot be determined due to the
uncertainty of future currency exchange rates.
Income Taxes
The Company incurred a current provision for income taxes of
approximately $80.5 million, $68.9 million and $6.0 million for 2001, 2000 and
1999, respectively. 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 has been 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 fully utilized its U.S. federal regular tax net operating
loss ("NOL") carryforward in 2000 and its U.S. federal alternative minimum tax
credit carryforward in 2001. The Company has a Bolivian income tax NOL
carryforward of approximately $57 million that does not expire and an Ecuadorian
income tax NOL of approximately $5 million that expires in varying annual
amounts over a five-year period beginning in 2002, both of which can be used to
offset its future income tax liabilities. In addition to its NOL carryforward in
Ecuador, the Company also has a $22.6 million deferred devaluation loss
carryforward that is available to offset future taxable income. No asset has
been recorded for this loss carryforward, which expires in 2009. The income tax
benefit will be recorded in the period in which the loss carryforward is
utilized. At December 31, 2001, the Company also had an Argentine income tax NOL
of approximately 91 million pesos ($55 million) from its recently acquired
subsidiary, Vintage Petroleum Argentina S.A., that expires in varying annual
amounts over a five-year period beginning in 2002 and can be used to offset
future income tax liabilities.
Critical Accounting Policies and Estimates
Management's discussion and analysis of its financial condition and
results of operations are based upon the Company's consolidated financial
statements, which have been prepared in accordance with accounting principles
generally accepted in the United States ("GAAP"). The preparation of these
consolidated financial statements 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. The Company bases its estimates on historical experience
and various other assumptions that are believed to be reasonable under the
circumstances. Actual results could differ from these estimates under different
assumptions or conditions. Note 1 to the Company's consolidated financial
statements included elsewhere in this Form 10-K, contains a comprehensive
summary of the Company's significant accounting policies. The following is a
discussion of the Company's most critical accounting policies, judgments and
uncertainties that are inherent in the Company's application of GAAP:
Proved reserve estimates. Estimates of the Company's proved reserves
included in its consolidated financial statements and elsewhere in this Form
10-K are prepared in accordance with guidelines established by GAAP and by the
SEC. The accuracy of a reserve estimate is a function of: (i) the quality and
quantity of available data; (ii) the interpretation of that data; (iii) the
accuracy of various mandated economic assumptions; and (iv) the judgment of the
persons preparing the estimate.
The Company's proved reserve information is based on estimates prepared
by its independent petroleum consultants. Estimates prepared by others may be
higher or lower than these estimates. Because these estimates depend on many
assumptions, all of which may substantially differ from actual results, reserve
estimates may be different from the quantities of oil and gas that are
ultimately recovered. In addition, results of drilling, testing and production
after the date of an estimate may justify material revisions to the estimate.
The present value of future net cash flows should not be assumed to be
the current market value of the Company's estimated proved reserves. In
accordance with SEC requirements, the estimated discounted future net cash flows
from proved reserves were based on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of the estimate.
43
The estimates of proved reserves materially impact depletion,
depreciation and amortization expense. If the estimates of proved reserves
decline, the rate at which the Company records depletion, depreciation and
amortization expense increases, reducing net income. Such a decline may result
from lower market prices, which may make it uneconomic to drill for and produce
higher cost reserves. In addition, the decline in proved reserve estimates may
impact the outcome of the Company's assessment of its oil and gas producing
properties for impairment.
Impairment of proved oil and gas properties. 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 and risk-adjusted probable and possible 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, consistent with methods
used for acquisition evaluations.
As discussed in Note 12 to the Company's consolidated financial
statements included elsewhere in this Form 10-K, in February 2002, the Argentina
government also imposed a 20 percent excise tax on oil exports, effective March
1, 2002. This tax is limited by law to a term of no more than five years. Had
this export tax been in effect at December 31, 2001, it would not have had a
material impact on the Company's assessment of impairment of its oil and gas
properties in Argentina.
Impairment of unproved oil and gas properties. Unproved leasehold costs
are capitalized and are reviewed periodically for impairment. Costs related to
impaired prospects are charged to expense. An impairment expense could result if
oil and gas prices decline in the future as it may not be economic to develop
some of these unproved properties.
Impairment of goodwill. The Company assesses the recoverability of
goodwill by determining whether the net book value of the goodwill can be
recovered through the aggregate of the excess of undiscounted future net
revenues of the acquired properties over the net book value of those properties.
The amount of goodwill impairment, if any, is measured based on fair value,
which is defined as projected discounted future net revenues. The assessment of
the recoverability of goodwill will be impacted if estimated future net revenues
are not achieved. See "New Accounting Pronouncements" for discussion of the
policy change that the Company adopted in 2002.
Revenue recognition. Revenue is a key component of the Company's
results of operations and also determines the timing of certain expenses, such
as severance taxes and royalties. The Company follows a very specific and
detailed guideline of recognizing revenues when oil and gas are delivered to the
purchaser. However, certain judgments affect the application of the Company's
revenue recognition policy. Revenue results are difficult to predict, and any
shortfall in revenue or delay in recognizing revenue could cause the Company's
operating results to vary significantly from quarter to quarter and could result
in future operating losses.
Income taxes. The Company provides deferred income taxes on
transactions which are recognized in different periods for financial and tax
reporting purposes. The Company has not recognized a U.S. deferred tax liability
related to the unremitted earnings of any of its foreign subsidiaries as it is
the Company's intention, generally, to reinvest such earnings permanently. The
Company has also recorded deferred tax assets related to operating loss and tax
credit carryforwards. Management periodically assesses the probability of
recovery of recorded deferred tax assets based on its assessment of future
earnings outlooks by tax jurisdiction. Such estimates are inherently imprecise
since many assumptions are utilized in the assessments that may prove to be
incorrect in the future.
Assessments of functional currencies. All of the Company's subsidiaries
use the U.S. dollar as their functional currency, except for the Company's
Canadian subsidiaries, which use the Canadian dollar. Management determines the
functional currencies of the Company's subsidiaries based on an assessment of
the currency of the economic environment in which a subsidiary primarily
realizes and expends its operating revenues, costs and expenses. The assessment
of functional currencies can have a significant impact on periodic results of
operations and financial position.
44
Argentina economic and currency measures. The accounting for and
translation of the Company's Argentina balance sheet as of December 31, 2001,
reflects management's assumptions regarding some uncertainties unique to
Argentina's current economic situation. See Note 1 to the Company's consolidated
financial statements included elsewhere in this Form 10-K, for a description of
the assumptions utilized in the preparation of these consolidated financial
statements. The Argentina economic and political situation continues to evolve
and the Argentine government may enact future regulations or policies that, when
finalized and adopted, may materially impact, among other items, (i) the
realized prices the Company receives for oil and gas it produces and sells as a
result of export taxes; (ii) the timing of repatriations of cash to the U.S.;
(iii) the Company's asset valuations; and (iv) peso-denominated monetary assets
and liabilities. For further information, see "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk - Foreign Currency and Operations
Risk" included elsewhere in this Form 10-K.
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.
In June 1998, the Financial Accounting Standards Board (the "FASB")
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 statement of operations. 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 $18.5 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 increase to accumulated other comprehensive income in the Stockholders'
Equity section of the balance sheet of approximately $14.9 million. The amount
recorded to accumulated other comprehensive income was taken to the statement of
operations as the physical transactions being hedged were finalized. All of the
Company's cash flow hedges in place at January 1, 2001, had settled as of
December 31, 2001, with the actual cash flow impact recorded in oil and gas
sales in the Company's statement of operations.
New Accounting Pronouncements
On July 20, 2001, the FASB issued Statement of Financial Accounting
Standards No. 141, Business Combinations ("SFAS No. 141"), and SFAS No. 142.
SFAS No. 141 requires all business combinations initiated after June 30, 2001,
to be accounted for using the purchase method of accounting. Under SFAS No. 142,
goodwill is no longer subject to amortization. Rather, goodwill will be subject
to at least an annual assessment for impairment by applying a fair-value based
test. Additionally, an acquired intangible asset should be separately recognized
if the benefit of the intangible asset is obtained through contractual or other
legal rights, or if the intangible asset can be sold, transferred, licensed,
rented or exchanged, regardless of the acquirer's intent to do so. SFAS No. 142
is required to be applied starting with fiscal years beginning after December
15, 2001.
45
The Company's May 2001 acquisition of Genesis was accounted for using
the purchase method of accounting. The Company adopted SFAS No. 142 effective
January 1, 2002, resulting in the elimination of goodwill amortization from
statements of operations in future periods. Management has not determined at
this time if the adoption of SFAS No. 142 will have any other impact on the
Company's financial position or results of operations. Management plans to
engage an independent appraisal firm to perform an assessment of the fair value
of its Canadian segment, which will be compared with the carrying value of the
segment to determine whether any impairments existed on the date of adoption.
Under the provisions of SFAS No. 142, the Company has six months from the time
of adoption to have its appraisal completed.
In August 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations. Currently the
Company accrues future abandonment costs of wells and related facilities through
its depreciation calculation and includes the cumulative accrual in accumulated
depreciation. The new standard will require that the Company record the
discounted fair value of the retirement obligation as a liability at the time a
well is drilled or acquired. The liability will accrete over time with a charge
to interest expense. The new standard will apply to financial statements for
years beginning after June 15, 2002. While the new standard will require that
the Company change its accounting for such abandonment obligations, the Company
has not had an opportunity to evaluate the impact of the new standard on its
financial statements.
In October 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets ("SFAS No. 144"). SFAS No. 144 sets forth accounting and reporting
standards to establish a single accounting model, based on the framework
established in Statement of Financial Accounting Standards No. 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of, for long-lived assets to be disposed of by sale. The provisions of SFAS No.
144 are effective for financial statements issued for fiscal years beginning
after December 15, 2001, and interim periods within those fiscal years, with
early application encouraged. The provisions of SFAS No. 144 generally are to be
applied prospectively. The Company does not believe that the adoption of SFAS
No. 144 will have a material impact on its financial position or results of
operations.
Foreign Operations
For information on the Company's foreign operations, see "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk - Foreign Currency
and Operations Risk" included elsewhere in 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. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations" for a discussion of
the impact of commodity price changes based on 2001 production levels. 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 various periods in 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 $0.7 million to terminate its oil swap agreements
then in place.
46
During 2000, the Company entered into additional oil hedging contracts
for various periods in 2000 covering an additional 7.5 MMBbls of oil and a
weighted average NYMEX reference price of $27.94 per Bbl. 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 $30.71 per Bbl for
various periods in 2001. At December 31, 2000, the Company would have received
approximately $16.3 million to terminate its oil swap agreements then in place.
During 2001, the Company entered into additional oil hedging contracts
for various periods in 2001 covering an additional 1.9 MMBbls of oil at a
weighted average NYMEX reference price of $29.28 per Bbl. In total, the Company
entered into oil hedging contracts covering 2001 production of 5.5 MMBbls of oil
at a weighted average NYMEX reference price of $30.20 per Bbl. During 2001, the
Company entered into various oil hedges (swap agreements) for a total of 0.9
MMBbls of oil at a weighted average NYMEX reference price of $25.54 per Bbl for
various periods in 2002. At December 31, 2001, the Company would have received
approximately $4.7 million to terminate its oil swap agreements then in place.
During 2002, the Company entered into additional oil hedging contracts
for various periods in 2002 covering an additional 1.3 MMBbls of oil at a
weighted average NYMEX reference price of $22.54 per Bbl. In total, the Company
has entered into oil hedging contracts covering 2002 oil production of 2.2
MMBbls at a weighted average NYMEX reference price of $23.77 per Bbl. The
Company has also entered into various gas hedges (swap agreements) covering
approximately 8.6 million MMBtu of its gas production over the period April
through October 2002. The Canadian portion of the gas swap agreements
(approximately 4.3 million MMBtu) is at the AECO gas price index reference price
of 3.58 Canadian dollars per MMBtu and will be settled in Canadian dollars. The
AECO gas price index is the reference price used for most of the Company's
Canadian gas spot sales. The U.S. portion of the gas swap agreements
(approximately 4.3 million MMBtu) is at a NYMEX reference price of $2.60 per
MMBtu. Additionally, the Company has entered into basis swap agreements for the
approximately 4.3 million MMBtu of its U.S. gas production covered by the gas
swap agreements. These basis swaps establish a differential between the NYMEX
reference price and the various delivery points at levels that are comparable to
the historical differentials received by the Company. The Company continues to
monitor oil and gas prices and may enter into additional oil and gas hedges or
swaps in the future.
Interest Rate Risk
The Company's interest rate risk exposure results primarily from
short-term rates, mainly LIBOR based borrowings from its commercial banks. To
reduce the impact of fluctuations in interest rates, the Company maintains a
portion of its total debt portfolio in fixed rate debt. At December 31, 2001,
the amount of the Company's fixed rate debt was approximately 59 percent of
total debt. In the past, the Company has not entered into financial instruments
such as interest rate swaps or interest rate lock agreements. However, it may
consider these instruments to manage the impact of changes in interest rates
based on management's assessment of future interest rates, volatility of the
yield curve and the Company's ability to access the capital markets in a timely
manner.
Based on the outstanding borrowings under variable rate debt
instruments at December 31, 2001, a change in the average interest rate of 100
basis points would result in a change in net income and cash flow before income
taxes on an annual basis of approximately $2.5 million and $4.1 million,
respectively.
47
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
2002 2003 2004 2005 2006 after Total 12/31/01
---- ---- ---- -------- ---- -------- -------- ---------
Long-Term Debt:
Fixed rate (in thousands)..... - - - $149,837 - $449,436 $599,273 $608,763
Average interest rate......... - - - 9.0% - 8.7% 8.8% -
Variable rate (in thousands).. - - - $411,400 - - $411,400 $411,400
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 1.25 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 Canada, Argentina, Bolivia, Ecuador, Yemen and
Trinidad. For 2001, the Company's operations in Argentina accounted for
approximately 27 percent of the Company's revenues, 39 percent of the Company's
net operating profit (pre-tax income before impairments of oil and gas
properties, goodwill amortization and general and administrative and interest
expense) and 25 percent of its total assets. During 2001, the Company's
operations in Argentina represented its only foreign operations accounting for
more than 10 percent of its revenues or net operating profit (pre-tax income
before impairments of oil and gas properties and general and administrative and
interest expense). The Company's operations in Canada accounted for
approximately 39 percent of its total assets, including goodwill, at December
31, 2001. The majority of these Canadian assets were purchased on May 2, 2001,
as part of the acquisition of Genesis and the Company's exploration and
production operations include only eight months of the operations of Genesis in
2001. At December 31, 2001, none of the Company's other international operations
accounted for more than 10 percent of its 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.
Historically, the Company has not used derivatives or other financial
instruments to hedge the risk associated with the movement in foreign
currencies. However, the Company evaluates currency fluctuations and will
consider the use of derivative financial instruments or employment of other
investment alternatives if cash flows or investment returns so warrant.
The Company's international operations may be adversely affected by
political and economic instability, changes in the legal and regulatory
environment and other factors. The Company's foreign properties, operations or
investments in Canada, Argentina, Bolivia, Ecuador, Yemen and Trinidad may be
adversely affected by a number of factors. For example:
o local political and economic developments could restrict or increase
the cost of the Company's foreign operations;
o exchange controls and currency fluctuations could result in
financial losses;
o royalty and tax increases and retroactive tax claims could increase
costs of the Company's foreign operations;
o expropriation of the Company's property could result in loss of
revenue, property and equipment;
o import and export regulations and other foreign laws or policies
could result in loss of revenues; and
o laws and policies of the U.S. affecting foreign trade, taxation and
investment could restrict the Company's ability to fund foreign
operations or may make foreign operations more costly.
The Company does not currently maintain political risk insurance.
However, the Company will consider obtaining such coverage in the future if
conditions so warrant.
48
Canada. With the acquisition of Cometra in December 2000 and the
acquisition of Genesis in May 2001, the Company now has significant 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. 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.
The US$:C$ exchange rate at December 31, 2001, was US$1:C$1.59 as compared to
US$1:C$1.50 at December 31, 2000.
Argentina. Beginning in 1991, Peronist Carlos Menem, as newly-elected
President of Argentina, and Domingo Cavallo, as his economy minister, set out to
reverse economic decline through free-market reforms such as open trade. The key
to their plan was the "Law of Convertibility" under which the peso was tied to
the U.S. dollar at a rate of one peso to one U.S. dollar. Between 1991 and 1997
the plan succeeded. With the risk of devaluation apparently removed, capital
came in from abroad and much of Argentina's state-owned assets were privatized.
During this period, the economy grew at an annual average rate of 6.1 percent,
the highest in the region.
However, the "convertibility" plan left Argentina with few monetary
policy tools to respond to outside events. A series of external shocks began in
1998: prices for Argentina's commodities stopped rising; the dollar appreciated
against other currencies; and Brazil, Argentina's main trading partner, devalued
its currency. Argentina began a period of economic deflation, but failed to
respond by reforming government spending. During 2001, Argentina's budget
deficit exceeded $9 billion and its sovereign debt reached $140 billion.
As a result of economic instability and substantial withdrawals from
the banking system, in early December 2001, the Argentine government instituted
restrictions that prohibited foreign money transfers without Central Bank
approval and prohibited cash withdrawals from bank accounts above a certain
amount with certain limited exceptions. While the legal exchange rate remained
at one peso to one U.S. dollar, financial institutions were allowed to conduct
only limited activity due to these controls, and currency exchange activity was
effectively halted except for personal transactions in small amounts. These
actions by the government, in effect, caused a devaluation of the peso in
December 2001.
On January 6, 2002, the Argentine government enacted an emergency law
that required certain contracts that were previously payable in U.S. dollars to
be payable in pesos. U.S. dollars in Argentine banks on this date were converted
to pesos at the government- imposed rate of 1.4 pesos to one U.S. dollar.
Pursuant to the emergency law, U.S. dollar obligations between private parties
due after January 6, 2002, are to be liquidated in pesos at a negotiated rate of
exchange which reflects a sharing of the impact of the devaluation. The
emergency law requires the obligor to make an interim payment of one peso per
U.S. dollar of the claim and provides a period of 180 days for the parties to
negotiate the final amount to settle the U.S. dollar obligation.
On February 13, 2002, the Argentine government announced a 20 percent
tax on oil exports, effective March 1, 2002. The tax is limited by law to a term
of no more than five years. The Company currently exports approximately 35
percent of its Argentina oil production. However, management believes that this
export tax will have the effect of decreasing all future Argentina oil revenues
(not only export revenues) by the tax rate for the duration of the tax.
Management believes that the U.S. dollar equivalent value for domestic Argentina
oil sales (now paid in pesos) will move over time to parity with the U.S.
dollar-denominated export values, net of the export tax, thus impacting domestic
Argentina values by a like percentage to the tax. The adverse impact of this tax
will be partially offset by the net cost savings resulting from the devaluation
of the peso on peso-denominated costs and may be further reduced by the
Argentina income tax savings related to deducting such impact. At December 31,
2001, the imposition of the export tax would not have had a material impact on
the Company's assessment of impairment of its oil and gas properties in
Argentina.
The Company continues to monitor the political and economic environment
in Argentina. The Company's capital budgets have been adjusted to reflect a
reduced level of drilling in the country. In addition, the devaluation of the
peso is expected to result in a near-term reduction in revenues, substantially
offset by a reduction in peso-denominated operating, administrative and capital
costs, and the recognition of translation gains and losses, the impact of which
cannot currently be accurately estimated.
49
Bolivia. 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 Bolivian 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.
The political environment in Bolivia has changed as President Hugo
Banzer resigned and handed over power to his Vice-President, Jorge Quiroga. Mr.
Quiroga, who is a U.S. educated industrial engineer, will run the country until
new elections are held, which are currently scheduled for June 30, 2002. He will
be barred from running in those elections due to term limits.
In 1987, 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, 2001, was US$1:Bs 7.12. 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.
Ecuador. In Ecuador, President Gustavo Noboa and Congress continue to
debate further tax, social, and customs reforms to strengthen economic growth.
The legal basis for many of the recent 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. Even though the second phase of the economic transformation law (known as
Trole II), which was intended to bring significant tax and labor reform and a
defined privatization program to increase inflows of foreign direct investment,
was rejected by Congress, President Noboa used his veto powers to pass a tax
reform package which allowed the International Monetary Fund ("IMF") to make a
disbursement of its stand-by loan in the second quarter of 2001. Having met the
fiscal targets in 2001 agreed to by the IMF, the government will be seeking
further stand-by financing for 2002. Fixed investments significantly increased
in 2001 as construction of the new heavy oil pipeline (the OCP) continues to
progress on schedule.
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 2002 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."
50
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 because they are 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 Indenture dated as of May 30, 2001, between The Chase
Manhattan Bank, as Trustee, and the Company (Filed as Exhibit
4.1 to the Company's Registration Statement on Form S-4,
Registration No. 333-63896).
4.6 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).
51
4.7 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).
52
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 (Filed as
Exhibit 10.15 to the Company's report on Form 10-K for the
year ended December 31, 2000, filed March 12, 2001).
10.16 First Amendment to Second Amended and Restated Credit
Agreement dated as of August 8, 2001, between the Company, the
Lenders party thereto, Bank of Montreal, as administrative
agent, Bank of America, N.A., as syndication agent, Societe
General, Southwest Agency as documentation agent, and ABN AMRO
Bank, N.V., as managing agent (Filed as Exhibit 10 to the
Company's report on Form 10-Q for the quarter ended June 30,
2001, filed August 14, 2001).
10.17 Acquisition Agreement dated as of March 27, 2001, between the
Company and Genesis Exploration Ltd. (Filed as Exhibit 2 to
the Company's report on Form 8-K filed May 15, 2001).
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.
23.4 Consent of Outtrim Szabo Associates Ltd.
99.1 Letter to Commission Pursuant to Temporary Note 3T.
- -----------------
* Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the fourth quarter of the
fiscal year ended December 31, 2001.
53
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 19, 2002 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 19, 2002
- ------------------------------------
C. C. Stephenson, Jr.
/s/ S. Craig George Director, President and March 19, 2002
- ------------------------------------ Chief Executive Officer
S. Craig George (Principal Executive Officer)
/s/ William L. Abernathy Director, Executive Vice President March 19, 2002
- ------------------------------------ and Chief Operating Officer
William L. Abernathy
/s/ William C. Barnes Director, Executive Vice President, March 19, 2002
- ------------------------------------ Chief Financial Officer, Secretary and
William C. Barnes Treasurer (Principal Financial Officer)
/s/ Bryan H. Lawrence Director March 19, 2002
- ------------------------------------
Bryan H. Lawrence
/s/ Joseph D. Mahaffey Director March 19, 2002
- ------------------------------------
Joseph D. Mahaffey
/s/ John T. McNabb, II Director March 19, 2002
- ------------------------------------
John T. McNabb, II
/s/ Michael F. Meimerstorf Vice President and Controller March 19, 2002
- ------------------------------------ (Principal Accounting Officer)
Michael F. Meimerstorf
54
INDEX TO FINANCIAL STATEMENTS
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
Page
----
AUDITED FINANCIAL STATEMENTS OF VINTAGE PETROLEUM, INC. AND SUBSIDIARIES:
Report of Independent Public Accountants......................................................................... 56
Consolidated Balance Sheets as of December 31, 2001 and 2000..................................................... 57
Consolidated Statements of Operations for the years ended December 31, 2001, 2000 and 1999....................... 58
Consolidated Statements of Changes in Stockholders' Equity for the years ended
December 31, 2001, 2000 and 1999............................................................................ 59
Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999....................... 60
Notes to Consolidated Financial Statements for the years ended December 31, 2001, 2000 and 1999.................. 61
55
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,
2001 and 2000, 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, 2001. 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 1 to the consolidated financial statements,
effective January 1, 2001, the Company changed its method of accounting for
derivatives to adopt the requirements of Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 13, 2002
56
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except shares
and per share amounts)
A S S E T S
December 31,
--------------------------
2001 2000
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents ................................. $ 15,454 $ 19,506
Accounts receivable -
Oil and gas sales ...................................... 77,628 146,770
Joint operations ....................................... 9,354 6,267
Derivative financial instruments receivable ............... 4,701 --
Prepaids and other current assets ......................... 37,517 13,946
----------- -----------
Total current assets ................................... 144,654 186,489
----------- -----------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method ......... 2,498,552 1,734,003
Oil and gas gathering systems and plants .................. 20,508 19,252
Other ..................................................... 25,506 19,636
----------- -----------
2,544,566 1,772,891
Less accumulated depreciation, depletion and amortization . 809,522 667,837
----------- -----------
1,735,044 1,105,054
----------- -----------
GOODWILL, net of amortization .................................. 156,990 --
----------- -----------
OTHER ASSETS, net .............................................. 60,100 46,854
----------- -----------
$ 2,096,788 $ 1,338,397
=========== ===========
L I A B I L I T I E S A N D S T O C K H O L D E R S' E Q U I T Y
CURRENT LIABILITIES:
Revenue payable ........................................... $ 25,625 $ 60,519
Accounts payable - trade .................................. 62,362 43,225
Current income taxes payable .............................. 21,638 43,187
Short-term debt ........................................... 17,320 3,400
Other payables and accrued liabilities .................... 45,200 61,961
----------- -----------
Total current liabilities ............................ 172,145 212,292
----------- -----------
LONG-TERM DEBT ................................................. 1,010,673 464,229
----------- -----------
DEFERRED INCOME TAXES .......................................... 166,319 33,252
----------- -----------
OTHER LONG-TERM LIABILITIES .................................... 18,208 3,767
----------- -----------
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 shares authorized,
63,081,322 and 62,801,416 shares issued and outstanding 315 314
Capital in excess of par value ............................ 324,077 319,893
Retained earnings ......................................... 428,443 303,449
Accumulated other comprehensive income (loss) ............. (21,632) 1,201
----------- -----------
731,203 624,857
Less unamortized cost of restricted stock awards .......... 1,760 --
----------- -----------
729,443 624,857
----------- -----------
$ 2,096,788 $ 1,338,397
=========== ===========
The accompanying notes are an integral part of these statements.
57
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Years Ended December 31,
-----------------------------------
2001 2000 1999
--------- --------- ---------
REVENUES:
Oil and gas sales ................................................. $ 731,386 $ 680,350 $ 376,924
Gas marketing ..................................................... 130,209 128,836 60,275
Oil and gas gathering ............................................. 17,032 19,998 6,955
Gain (loss) on disposition of assets .............................. 26,871 (1,731) 54,991
Other income (expense) ............................................ 3,743 (21,272) 3,783
--------- --------- ---------
909,241 806,181 502,928
--------- --------- ---------
COSTS AND EXPENSES:
Lease operating, including production taxes ....................... 213,551 159,638 121,664
Exploration costs ................................................. 22,073 25,242 14,674
Gas marketing ..................................................... 126,373 123,787 57,550
Oil and gas gathering ............................................. 17,759 17,052 5,153
General and administrative ........................................ 50,844 41,416 36,409
Depreciation, depletion and amortization .......................... 168,944 100,109 107,807
Impairment of oil and gas properties .............................. 29,050 225 3,306
Amortization of goodwill .......................................... 11,940 -- --
Interest .......................................................... 64,728 48,437 58,665
--------- --------- ---------
705,262 515,906 405,228
--------- --------- ---------
Income before income taxes and cumulative effect of change in
accounting principle .................................. 203,979 290,275 97,700
--------- --------- ---------
PROVISION (BENEFIT) FOR INCOME TAXES:
Current ........................................................... 80,535 68,858 5,954
Deferred .......................................................... (10,063) 24,102 18,375
--------- --------- ---------
70,472 92,960 24,329
--------- --------- ---------
Income before cumulative effect of change in
accounting principle .................................. 133,507 197,315 73,371
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, net of income taxes of $644 ............................ -- (1,422) --
--------- --------- ---------
NET INCOME ................................................................. $ 133,507 $ 195,893 $ 73,371
========= ========= =========
BASIC INCOME PER SHARE:
Income before cumulative effect of change in accounting principle ... $ 2.12 $ 3.15 $ 1.27
Cumulative effect of change in accounting principle ................. -- (0.02) --
--------- --------- ---------
Net income .......................................................... $ 2.12 $ 3.13 $ 1.27
========= ========= =========
DILUTED INCOME PER SHARE:
Income before cumulative effect of change in accounting principle ... $ 2.09 $ 3.08 $ 1.24
Cumulative effect of change in accounting principle ................. -- (0.02) --
--------- --------- ---------
Net income .......................................................... $ 2.09 $ 3.06 $ 1.24
========= ========= =========
Weighted Average Common Shares Outstanding:
Basic ............................................................. 63,023 62,644 57,989
========= ========= =========
Diluted ........................................................... 64,027 63,963 59,315
========= ========= =========
The accompanying notes are an integral part of these statements.
58
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(In thousands, except per share amounts)
Capital Unamortized Accumulated
Common Stock In Excess Restricted Other
--------------------- of Par Stock Retained Comprehensive
Shares Amount Value Awards Earnings Income (Loss) Total
--------- --------- --------- --------- --------- --------- ---------
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
($.140 per share) ................... -- -- -- -- (8,771) -- (8,771)
--------- --------- --------- --------- --------- --------- ---------
BALANCE AT DECEMBER 31, 2000 ................ 62,801 314 319,893 -- 303,449 1,201 624,857
---------
Comprehensive income:
Transition adjustment for adoption of
SFAS No. 133 ..................... -- -- -- -- -- 14,915 14,915
Net income .......................... -- -- -- -- 133,507 -- 133,507
Foreign currency translation
adjustment ....................... -- -- -- -- -- (25,823) (25,823)
Change in value of derivatives ...... -- -- -- -- -- (11,925) (11,925)
---------
Total comprehensive income .......... 110,674
Exercise of stock options and
resulting tax effects ............... 170 1 1,970 -- -- -- 1,971
Issuance of restricted stock ........... 110 -- 2,214 (2,214) -- -- --
Amortization of restricted
stock awards ........................ -- -- -- 454 -- -- 454
Cash dividends declared
($.135 per share) ................... -- -- -- -- (8,513) -- (8,513)
--------- --------- --------- --------- --------- --------- ---------
BALANCE AT DECEMBER 31, 2001 ................ 63,081 $ 315 $ 324,077 $ (1,760) $ 428,443 $ (21,632) $ 729,443
========= ========= ========= ========= ========= ========= =========
The accompanying notes are an integral part of these statements.
59
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31,
-----------------------------------
2001 2000 1999
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................... $ 133,507 $ 195,893 $ 73,371
Adjustments to reconcile net income to cash
provided by operating activities, net of companies acquired -
Depreciation, depletion and amortization .................. 168,944 100,109 107,807
Impairment of oil and gas properties ...................... 29,050 225 3,306
Amortization of goodwill .................................. 11,940 -- --
Exploration costs ......................................... 22,073 25,242 14,674
Provision (benefit) for deferred income taxes ............. (10,063) 24,102 18,375
Cumulative effect of change in accounting principle ....... -- 1,422 --
(Gain) loss on disposition of assets ...................... (26,871) 1,731 (54,991)
Other non-cash items....................................... (1,215) -- --
--------- --------- ---------
327,365 348,724 162,542
Decrease (increase) in receivables ........................ 90,280 (56,179) (32,110)
Increase (decrease) in payables and accrued liabilities ... (95,789) 99,514 29,500
Income tax refund receivable .............................. -- -- 5,323
Other working capital changes.............................. (26,171) 3,628 (4,275)
--------- --------- ---------
Cash provided by operating activities ................. 295,685 395,687 160,980
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties ...................................... (269,328) (209,552) (229,606)
Gathering systems and other ................................. (5,817) (2,633) (2,669)
Proceeds from sales of oil and gas properties ................. 39,800 998 78,241
Purchase of companies, net of cash acquired ................... (478,158) (46,199) --
Other ......................................................... (9,398) (4,132) 634
--------- --------- ---------
Cash used by investing activities ..................... (722,901) (261,518) (153,400)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock ...................................... 1,231 3,492 83,685
Issuance of 7 7/8% Senior Subordinated Notes Due 2011 ......... 199,930 -- --
Issuance of 9 3/4% Senior Subordinated Notes Due 2009 ......... -- -- 146,000
Advances on revolving credit facility and other borrowings .... 319,050 70,388 50,213
Payments on revolving credit facility and other borrowings .... (88,431) (224,343) (248,708)
Dividends paid ................................................ (8,187) (6,887) (1,328)
--------- --------- ---------
Cash provided (used) by financing activities .......... 423,593 (157,350) 29,862
--------- --------- ---------
EFFECT OF EXCHANGE RATE CHANGE ON CASH ............................. (429) -- --
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ............... (4,052) (23,181) 37,442
CASH AND CASH EQUIVALENTS, beginning of year ....................... 19,506 42,687 5,245
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of year ............................. $ 15,454 $ 19,506 $ 42,687
========= ========= =========
The accompanying notes are an integral part of these statements.
60
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2001, 2000 and 1999
1. Business and Significant Accounting Policies
Vintage Petroleum, Inc. is an independent energy company with
operations primarily in the exploration and production, gas marketing and
gathering segments of the oil and gas industry. Approximately 99 percent of the
Company's operations are within the exploration and production segment based on
2001 operating income before impairments of oil and gas properties, gains on
asset sales and goodwill amortization. The Company's North American exploration
and production operations include the West Coast, Gulf Coast, East Texas and
Mid-Continent areas of the United States and the western sedimentary basins of
Canada. The Company also has core areas of operations in the San Jorge Basin and
Cuyo Basin of Argentina, the Chaco Basin in Bolivia and in Ecuador. The Company
also has exploration activities currently ongoing in Yemen and Trinidad.
Consolidation and Presentation
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.
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 gains or losses 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. An
impairment expense could result if oil and gas prices decline in the future as
it may not be economic to develop some of these unproved properties.
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.
61
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In August 2001, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards No. 143, Accounting for Asset
Retirement Obligations. Currently the Company accrues future abandonment costs
of wells and related facilities through its depreciation calculation and
includes the cumulative accrual in accumulated depreciation. The new standard
will require that the Company record the discounted fair value of the retirement
obligation as a liability at the time a well is drilled or acquired. The
liability will accrete over time with a charge to interest expense. The new
standard will apply to financial statements for years beginning after June 15,
2002. While the new standard will require that the Company change its accounting
for such abandonment obligations, the Company has not had an opportunity to
evaluate the impact of the new standard on its financial statements.
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 from estimated future net revenues. 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 and risk-adjusted probable and possible 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, consistent with methods used for acquisition
evaluations.
The Company recorded impairment provisions related to its proved oil
and gas properties of $29.1 million, $0.2 million and $3.3 million in 2001, 2000
and 1999, respectively. Prior to 2001, the Company considered only proved oil
and gas reserves in determining future net revenues and fair value. However,
with the December 2000 acquisition of Cometra Energy (Canada), Ltd. ("Cometra")
and, more significantly, the May 2001 acquisition of Genesis Exploration Ltd.
("Genesis"), the Company acquired what it considers to be substantial probable
and possible oil and gas reserves in Canada. The potential value of these
reserves, on a risk-adjusted basis, was considered in determining the value of
oil and gas properties during the Company's acquisition analyses. As a result of
the possibility of significant value attributable to the probable and possible
reserves, the Company accordingly began to include the future net revenues and
present value of risk-adjusted probable and possible reserves in its future net
revenues for impairment and fair value determinations.
In estimating the future net revenues at December 31, 2001, to be used
for impairment testing, the Company assumed that oil and 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.
In October 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets ("SFAS No. 144"). SFAS No. 144 establishes accounting and reporting
standards to establish a single accounting model, based on the framework
established in Statement of Financial Accounting Standards No. 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of, for long-lived assets to be disposed of by sale. The provisions of SFAS No.
144 are effective for financial statements issued for fiscal years beginning
after December 15, 2001, and interim periods within those fiscal years, with
early application encouraged. The provisions of SFAS No. 144 generally are to be
applied prospectively. The Company does not believe that the adoption of SFAS
No. 144 will have a material impact on its financial position or results of
operations.
62
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Goodwill
Goodwill represents the excess of the purchase price over the estimated
fair value of the net assets acquired in the purchase of Genesis (see Note 7).
In 2001, goodwill was amortized using the unit-of-production basis over the
total proved reserves acquired. Accumulated amortization was approximately $11.9
million at December 31, 2001. The Company assesses the recoverability of
goodwill by determining whether the net book value of the goodwill can be
recovered through the aggregate of the excess of undiscounted future net
revenues of the acquired properties over the net book value of those properties.
The amount of goodwill impairment, if any, is measured based on projected
discounted future net revenues using a discount rate reflecting the Company's
average cost of funds. The assessment of the recoverability of goodwill will be
impacted if estimated future net revenues are not achieved.
On July 20, 2001, the FASB issued Statement of Financial Accounting
Standards No. 141, Business Combinations ("SFAS No. 141"), and Statement of
Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
("SFAS No. 142"). SFAS No. 141 requires all business combinations initiated
after June 30, 2001, to be accounted for using the purchase method of
accounting. Under SFAS No. 142, goodwill is no longer subject to amortization.
Rather, goodwill will be subject to at least an annual assessment for impairment
by applying a fair-value based test. Additionally, an acquired intangible asset
should be separately recognized if the benefit of the intangible asset is
obtained through contractual or other legal rights, or if the intangible asset
can be sold, transferred, licensed, rented or exchanged, regardless of the
acquirer's intent to do so. SFAS No. 142 is required to be applied starting with
fiscal years beginning after December 15, 2001.
The Company's May 2001 acquisition of Genesis was accounted for using
the purchase method of accounting. The Company adopted SFAS No. 142 effective
January 1, 2002, resulting in the elimination of goodwill amortization from
statements of operations in future periods. Management has not determined at
this time if the adoption of SFAS No. 142 will have any other impact on the
Company's financial position or results of operations. Management plans to
engage an independent appraisal firm to perform an assessment of the fair value
of its Canadian segment, which will be compared with the carrying value of the
segment to determine whether any impairment exists on the date of adoption.
Under the provisions of SFAS No. 142, the Company has six months from the time
of adoption to have its appraisal completed.
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 the 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.
63
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company participated in oil hedges covering 5.5 MMBbls during 2001,
the impact of which increased its U.S. average oil price by 91 cents to $23.08
per Bbl, its Argentina average oil price by $1.14 to $21.80 per Bbl, and its
overall average oil price by 89 cents to $21.93 per Bbl. The Company
participated in oil hedges covering 9.3 MMBbls during 2000, the impact of which
reduced its 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 1.8 MMBbls during 1999, the impact of which reduced its 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.
In June 1998, the FASB 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 statement of operations.
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 $18.5 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 in the
Stockholders' Equity section of the balance sheet of approximately $14.9
million. The amount recorded to accumulated other comprehensive income was
relieved and taken to the statement of operations as the physical transactions
being hedged were finalized. All of the Company's cash flow hedges in place at
January 1, 2001, had settled as of December 31, 2001, with the actual cash flow
impact recorded in oil and gas sales in the Company's statement of operations.
At December 31, 2001, the Company had a derivative financial instrument
receivable of $4.7 million related to 2002 cash flow hedges in place. During
2001, there were no significant gains or losses recognized in earnings for hedge
ineffectiveness. The Company did not discontinue any hedges because of the
probability that the original forecasted transaction would not occur.
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 from 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.
64
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During the years ended December 31, 2001, 2000 and 1999, the Company
made cash payments for interest totaling $58.6 million, $48.3 million and $56.8
million, respectively. Cash payments for U.S. income taxes of $24.1 million and
$19.8 million were made during 2001 and 2000, respectively. No cash payments for
U.S. income taxes were made during 1999. The Company made cash payments of $77.8
million and $9.5 million during 2001 and 2000 for foreign income taxes,
primarily in Argentina. No cash payments were made during 1999 for foreign
income taxes.
In December 2000, the Company purchased 100 percent of the outstanding
common stock of Cometra. The 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.
In May 2001, the Company purchased 100 percent of the outstanding
common stock of Genesis (see Note 7). The total purchase price included both
cash and the assumption of $154.1 million in net liabilities. These net
liabilities are not reflected in the Company's 2001 statement of cash flows.
Earnings Per Share
Basic earnings per common share were computed by dividing net income by
the weighted average number of shares outstanding during the period. Diluted
earnings per common share for 2001, 2000 and 1999 were computed assuming the
exercise of all dilutive options, as determined by applying the treasury stock
method. In addition, for the years ended December 31, 2001, 2000 and 1999, the
Company had outstanding stock options for 3,244,400, 714,000 and 1,635,000
additional shares of the Company's common stock, respectively, with average
exercise prices of $19.22, $20.19 and $17.70, respectively, which were
antidilutive.
General and Administrative Expense
The Company receives fees for the operation of jointly-owned oil and
gas properties and records such reimbursements as reductions of general and
administrative expense. Such fees totaled approximately $6.9 million, $4.2
million and $4.9 million in 2001, 2000 and 1999, respectively.
Lease Operating Expense
For the years ended December 31, 2001, 2000 and 1999, the Company
recorded in lease operating expenses gross production taxes of $15.8 million,
$17.4 million and $7.5 million, respectively, and transportation and storage
expenses of $12.2 million, $10.5 million and $6.2 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.
65
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 state-owned 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 subsidiaries, which
use the Canadian dollar. Adjustments arising from translation of the Canadian
subsidiaries' 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 its subsidiary's functional currency are included in the results of
operations as incurred.
The Company's operations in Argentina represented approximately 35
percent of its 2001 total production and approximately 37 percent of the
Company's total proved reserves at December 31, 2001.
Beginning in 1991, the Argentine peso ("peso") was tied to the U.S.
dollar at a rate of one peso to one U.S. dollar. As a result of economic
instability and substantial withdrawals from the banking system, in early
December 2001, the Argentine government instituted restrictions that prohibited
foreign money transfers without Central Bank approval and prohibited cash
withdrawals from bank accounts above a certain amount with certain limited
exceptions. While the legal exchange rate remained at one peso to one U.S.
dollar, financial institutions were allowed to conduct only limited activity due
to these controls, and currency exchange activity was effectively halted except
for personal transactions in small amounts. These actions by the government in
effect caused a devaluation of the peso in December 2001. On January 11, 2002,
the foreign currency markets re-opened with the floating exchange rate closing
at a range of 1.6 to 1.7 pesos to one U.S. dollar.
Because exchangeability of the peso was lacking from early December
2001 to January 11, 2002, the Company used the estimated exchange rate of 1.65
pesos to one U.S. dollar at January 11, 2002, (the first rate subsequent to year
end at which exchanges could be made) to translate peso-denominated balances at
December 31, 2001, and peso-denominated transactions during December 2001. This
translation increased 2001 net income by approximately $3.3 million, consisting
of a foreign currency exchange gain of approximately $2.3 million (included in
other income (expense) on the statement of operations) and approximately $1.0
million in reductions of certain operating expenses during December 2001.
On January 6, 2002, the Argentine government enacted an emergency law
that required certain contracts that were previously payable in U.S. dollars to
be payable in pesos. U.S. dollars in Argentine banks on this date were converted
to pesos at a rate of 1.4 pesos to one U.S. dollar. Pursuant to the emergency
law, U.S. dollar obligations between private parties due after January 6, 2002,
are to be liquidated in pesos at a negotiated rate of exchange which reflects a
sharing of the impact of the devaluation. The emergency law requires the obligor
to make an interim payment of one peso per U.S. dollar of the claim and provides
a period of 180 days for the parties to negotiate the final amount to settle the
U.S. dollar obligation.
Absent the January 6, 2002, emergency law, the devaluation of the peso
would have had no effect on the U.S. dollar-denominated payables and receivables
at December 31, 2001. Therefore, the effect of this involuntary conversion will
be recorded in 2002 and the Company does not expect it to have a material effect
on its financial position or results of operations.
66
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company evaluated the effect of the recent events on its
determination of the functional currency of its Argentina operations and it
believes that its functional currency remains the U.S. dollar. Management
believes that the recent changes in Argentina, some of which are expected to be
temporary, do not represent a significant change in fact or circumstance
sufficient to indicate a clear change in functional currency.
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
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 year 1999 has been restated to reflect the
adoption of EITF 00-10. The adoption of EITF 00-10 did not impact net income.
Comprehensive Income
The Company applies the provisions of Statement of Financial Accounting
Standards No. 130, Reporting Comprehensive Income ("SFAS No. 130"). The Company
had a foreign currency translation loss of $25.8 million (net of $20.8 million
tax benefit) for the year ended December 31, 2001, and a foreign currency
translation gain of $1.2 million (net of $0.9 million tax expense) for the year
ended December 31, 2000, which are included in accumulated other comprehensive
income in the Stockholders' Equity section of the accompanying balance sheet.
The Company had no non-owner changes in equity other than net income during the
year ended December 31, 1999.
The Company also recorded under SFAS No. 133 a net reduction in
unrealized derivative gains, of approximately $11.9 million (net of $4.1 million
tax benefit) related to oil swaps, reducing the unrealized gains to $3.0 million
(net of $1.9 million tax expense) included in accumulated other comprehensive
income at December 31, 2001. This net reduction consisted of the removal of the
$14.9 million (net of $6.0 million tax expense) transitional asset established
on January 1, 2001, for contracts in place at December 31, 2000, all of which
settled in 2001, and an increase for a current period change in value of $3.0
million for contracts to be settled in the first half of 2002. The actual cash
flow impact of settled oil swaps of $19.7 million, including oil swaps entered
into during 2001, has been reflected in the oil and gas sales line on the
Company's statement of operations for the year ended December 31, 2001.
67
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2. Long-Term Debt
Long-term debt at December 31, 2001 and 2000, consisted of the
following:
(In thousands) 2001 2000
----------- ---------
Revolving credit facility............................ $ 411,400 $ 65,000
Senior subordinated notes:
9% Notes due 2005, less unamortized discount....... 149,837 149,796
8 5/8% Notes due 2009, less unamortized discount... 99,503 99,433
9 3/4% Notes due 2009.............................. 150,000 150,000
7 7/8% Notes due 2011, less unamortized discount... 199,933 -
----------- ---------
$ 1,010,673 $ 464,229
=========== =========
The Company has no long-term debt maturities prior to November 30,
2005. A total of $561.2 million of debt matures in 2005 and all other debt
matures in 2009 or later. The Company had $9.5 million and $5.0 million of
accrued interest payable related to its long- term debt at December 31, 2001 and
2000, respectively, included in other payables and accrued liabilities.
Revolving Credit Facility
The Company has available an unsecured revolving credit facility under
the Second Amended and Restated Credit Agreement dated November 30, 2000, as
amended (the "Bank Facility"), between the Company and certain banks. The Bank
Facility establishes a borrowing base ($850 million at December 31, 2001) 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 $625 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,
2001, were $411.4 million at an average interest rate of approximately 3.95
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 August 2001. If the sum of
outstanding senior debt exceeds the borrowing base, as redetermined, the Company
must repay such excess. Any principal advances outstanding are due at maturity
on November 30, 2005.
The Company had $12.3 million in letters of credit outstanding at
December 31, 2001. 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 Bank Facility is reduced by the
outstanding letters of credit.
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.
68
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Senior Subordinated Notes
On December 20, 1995, the Company issued $150 million of its 9% Senior
Subordinated Notes due 2005 (the "9% Notes"). The 9% Notes are redeemable at the
option of the Company, in whole or in part, at any time on or after December 15,
2000. The 9% Notes mature on December 15, 2005, with interest payable
semiannually on June 15 and December 15 of each year.
On February 5, 1997, the Company issued $100 million of its 8 5/8%
Senior Subordinated Notes due 2009 (the "8 5/8% Notes"). The 8 5/8% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after February 1, 2002. The 8 5/8% Notes mature on February 1, 2009, with
interest payable semiannually on February 1 and August 1 of each year.
On January 26, 1999, the Company issued $150 million of its 9 3/4%
Senior Subordinated Notes due 2009 (the "9 3/4% Notes"). The 9 3/4% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after February 1, 2004. The 9 3/4% Notes mature on June 30, 2009, with interest
payable semiannually on June 30 and December 30 of each year. All of the net
proceeds to the Company from the sale of the 9 3/4% Notes (approximately $146.0
million) were used to repay a portion of the existing indebtedness under the
Company's Bank Facility.
On May 30, 2001, the Company issued $200 million of its 7 7/8% Senior
Subordinated Notes due 2011 (the "7 7/8% Notes"). The 7 7/8% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after May 15, 2006. In addition, prior to May 15, 2004, the Company may redeem
up to 35 percent of the 7 7/8% Notes with the proceeds of certain underwritten
public offerings of the Company's common stock. The 7 7/8% Notes mature on May
15, 2011, with interest payable semiannually on May 15 and November 15 of each
year. All of the net proceeds to the Company from the sale of the 7 7/8% Notes
(approximately $199.9 million) were used to repay a portion of the existing
indebtedness under the Company's Bank Facility.
The 9% Notes, 8 5/8% Notes, 9 3/4% Notes and 7 7/8% 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 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.
69
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 existing indebtedness under the Company's Bank Facility.
Stock Plans
The Company has two fixed plans which reserve shares of common stock
for issuance to key employees and 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
for stock options granted has been recognized. Had compensation cost for these
plans been determined consistent with the provisions of SFAS No. 123, the
Company's net income and earnings per share would have been adjusted to the
following pro forma amounts:
(In thousands, except per share amounts) 2001 2000 1999
-------- --------- ---------
Net income - as reported..................... $133,507 $ 195,893 $ 73,371
Net income - pro forma....................... 129,237 193,252 71,130
Earnings per share - as reported:
Basic................................... 2.12 3.13 1.27
Diluted................................. 2.09 3.06 1.24
Earnings per share - pro forma:
Basic................................... 2.05 3.08 1.23
Diluted................................. 2.02 3.02 1.20
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 2001 include a dividend yield of 0.7 percent,
expected volatility of approximately 49.1 percent, a risk-free interest rate of
approximately 4.7 percent and expected lives of 4.5 years. 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.
70
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Under the 1990 Stock Plan, as amended (the "1990 Plan"), 10 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, is 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, 2001, awards
for a total of 466,946 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.
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, 2001, options for a
total of 16,000 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 2001, 2000 and 1999:
2001 2000 1999
---------------------- ---------------------- ----------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
---------- ------ ---------- ------ ---------- ------
Beginning stock options outstanding.. 5,026,592 $13.16 4,616,142 $11.61 3,606,142 $12.79
Stock options granted ............... 1,038,000 20.87 853,000 19.62 1,070,000 7.30
Stock options canceled .............. (179,500) 18.53 (49,000) 13.70 -- --
Stock options exercised ............. (169,906) 7.24 (393,550) 8.87 (60,000) 5.94
---------- ---------- ----------
Ending stock options outstanding .... 5,715,186 $14.57 5,026,592 $13.16 4,616,142 $11.61
========== ====== ========== ====== ========== ======
Ending stock options exercisable .... 2,869,131 $13.47 2,238,142 $10.89 1,967,256 $ 8.94
========== ====== ========== ====== ========== ======
Weighted average fair value of
options granted ................ $ 9.09 $ 9.02 $ 2.24
====== ====== ======
71
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Of the 5,715,186 options outstanding at December 31, 2001: (a)
2,230,536 options have exercise prices between $5.94 and $9.81, with a weighted
average exercise price of $8.27 and a weighted average contractual life of 5.0
years (1,219,536 of these options are exercisable currently at a weighted
average price of $9.11); (b) 992,150 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 4.7 years (952,150 of these options are exercisable
currently at a weighted average price of $14.24); and (c) 2,492,500 options have
exercise prices between $16.06 and $22.94, with a weighted average exercise
price of $20.33 and a weighted average contractual life of 7.5 years (697,445 of
these options are exercisable currently at a weighted average price of $20.05).
All of the outstanding options are exercisable at various times in
years 2002 through 2011. All incentive stock options and non- qualified stock
options were granted at fair market value on the date of grant. Generally,
options granted under the 1990 Plan have a 10-year term and provide for vesting
over three years.
In addition to the above option activity, the Company has granted under
the 1990 Plan 110,000 shares of restricted stock to employees during 2001. All
of the shares vest over a three-year period. The related compensation expense of
$2.2 million (based on the stock price on the date of grant) is being amortized
over the vesting periods and during 2001 the Company recorded compensation
expense of $0.5 million. As of December 31, 2001, none of the shares have vested
to employees.
At December 31, 2001, a total of 6,198,132 shares of the Company's
common stock are reserved for issuance pursuant to the 1990 Plan and the
Director Plan.
Preferred Stock
Preferred stock at December 31, 2001, consisted 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 Yemen. In Ecuador, the Company is committed to drill two
wells in Block 14 at an estimated cost of approximately $4.2 million each and
two wells in Block 17 at an estimated cost of approximately $3.2 million each in
2002 and is committed to drill one well in the Shiripuno Block in 2003 at an
estimated cost of approximately $4.2 million. The Company is also committed to
drill one well in the Chaco concession in Bolivia in 2003 at an estimated cost
of approximately $6.3 million.
Through its December 2000 acquisition of 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. As of December 31, 2001, the Company had fulfilled the seismic
requirements and had drilled two of the three exploratory wells.
The Company had $12.3 million in letters of credit outstanding at
December 31, 2001. 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 Bank Facility is reduced by the
outstanding letters of credit.
72
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Rent expense was $2.9 million, $2.3 million and $1.8 million for 2001,
2000 and 1999, respectively. The future minimum commitments under long-term,
non-cancellable leases for office space are $2.7 million, $2.7 million, $2.8
million, $4.4 million and $2.0 million for the years 2002 through 2006,
respectively, with $0.8 million remaining in years thereafter.
On November 5, 1996, the Province of Santa Cruz, Argentina brought suit
against the Company's subsidiary Cadipsa S.A. in the Corte Suprema de Justicia
de la Nacion (the Supreme Court of Justice of the Argentine Republic, Buenos
Aires, Argentina), Dossier No. s-1451, seeking to recover approximately $10.6
million (which sum includes interest) allegedly due as additional royalties on
four concessions granted in 1990 in which the Company currently owns 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 charge to "Other expense" in the
second quarter of 2000 for 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 million pesos ($600,000) 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 lawsuits and is a party in
governmental proceedings from time to time arising in the ordinary course of
business. In the opinion of management, none of the various other pending
lawsuits and proceedings should have a material adverse impact on the Company's
financial position or results of operations.
5. Financial Instruments
Price Risk Management
The Company periodically uses hedges (swap agreements) to reduce the
impact of oil and natural gas price fluctuations on its operating results and
cash flows. These swap agreements typically entitle the Company to receive
payments from (or require it to make payments to) the counterparties 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 counterparties with appropriate credit standings.
At December 31, 2001, the Company was a party to oil price swap
agreements for various periods of 2002 covering 0.9 MMBbls at a weighted average
NYMEX reference price of $25.54 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 (see Note 2)
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, 2001 and
2000, was $1.02 billion and $475.2 million, respectively, compared with a
carrying value of $1.01 billion and $464.2 million, respectively.
73
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The fair value of commodity swap agreements is the amount at which they
could be settled, based on quoted market prices. At December 31, 2001 and 2000,
the Company would have received approximately $4.7 million and $16.3 million,
respectively, 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 before income taxes and cumulative effect of change in
accounting principle is composed of the following:
(In thousands) 2001 2000 1999
-------- -------- --------
Domestic ..... $117,240 $123,951 $ 33,097
Foreign ...... 86,739 166,324 64,603
-------- -------- --------
$203,979 $290,275 $ 97,700
======== ======== ========
The total provision (benefit) for income taxes consists of the
following:
(In thousands) 2001 2000 1999
-------- -------- --------
Current:
Domestic .... $ 46,486 $ 17,053 $ 1,036
Foreign ..... 34,049 51,805 4,918
Deferred:
Domestic .... (2,087) 32,460 11,730
Foreign ..... (7,976) (8,358) 6,645
-------- -------- --------
$ 70,472 $ 92,960 $ 24,329
======== ======== ========
A reconciliation of the U.S. federal statutory income tax rate to the
effective rate is as follows:
2001 2000 1999
---- ---- ----
U.S. federal statutory income tax rate ....... 35.0% 35.0% 35.0%
State income tax ............................. 3.9 3.9 3.9
Foreign operations ........................... (3.8) (2.8) (2.9)
Effect of conversion of foreign production
sharing contracts .......................... -- (4.0) --
Argentina NOL valuation allowance reversal ... -- -- (5.8)
Argentina NOL carryforward utilization ....... -- -- (5.2)
U.S. federal income tax credits .............. (0.8) -- (0.1)
Other ........................................ 0.2 (0.1) --
---- ---- ----
34.5% 32.0% 24.9%
==== ==== ====
74
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The components of the Company's net deferred tax liability as of
December 31, 2001 and 2000, are as follows:
(In thousands) 2001 2000
---------- ----------
Deferred Tax Assets:
U.S. federal and state net operating loss carryforwards..... $ 1,073 $ 976
Foreign NOL carryforwards................................... 34,724 16,291
Foreign tax credit carryforwards............................ 3,559 -
Other temporary book/tax differences........................ 3,385 7,832
---------- ----------
42,741 25,099
---------- ----------
Deferred Tax Liabilities:
Book/tax differences in property basis...................... 201,367 58,057
Other temporary book/tax differences........................ 7,693 294
---------- ----------
209,060 58,351
---------- ----------
Net deferred tax liability.............................. $ 166,319 $ 33,252
========== ==========
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") carryforward of approximately $57
million that does not expire and an Ecuadorian income tax NOL carryforward of
approximately $5 million that expires in varying annual amounts over a five-year
period beginning in 2002, both of which can be used to offset its future income
tax liabilities. In addition to its NOL in Ecuador, the Company also has a $22.6
million deferred devaluation loss carryforward that is available to offset
future taxable income. No asset has been recorded for this loss carryforward,
which expires in 2009. The income tax benefit will be recorded in the period in
which the loss carryforward is utilized. The Company also has an Argentine
income tax NOL at December 31, 2001, of approximately 91 million pesos ($55
million) in its recently acquired subsidiary, Vintage Petroleum Argentina S.A.,
that expires in varying annual amounts over a five-year period beginning in 2002
and can be used to offset future income tax liabilities.
The Company fully utilized its U.S. federal regular tax NOL
carryforward in 2000, and its alternative minimum tax credit carryforward in
2001. 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. Significant Acquisition
On May 2, 2001, the Company completed the acquisition of Canadian-based
Genesis for total consideration of $617 million, including transaction costs and
the assumption of the estimated net indebtedness of Genesis at closing (the
"Genesis Acquisition"). The cash portion of the acquisition price was paid
through advances under the Company's revolving credit facility and cash on hand.
The Genesis Acquisition was accounted for using purchase accounting and, as
such, only eight months of Genesis activity are included in the Company's
statement of operations for the year ended December 31, 2001.
The Company acquired 62.1 million barrels of oil equivalent ("BOE") of
proved reserves in the transaction with Genesis, consisting of approximately
27.5 MMBbls of oil and 207.7 Bcf of gas. Proved undeveloped reserves of oil and
gas account for 33 percent of the total proved reserves acquired. In addition,
the Company estimates that the properties have significant upside potential
which may be realized through its 2002 work program and beyond. The reserves
acquired in the Genesis Acquisition are located primarily in the provinces of
Alberta and Saskatchewan, with significant exploration exposure in the Northwest
Territories.
75
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In addition to reserves, the Company acquired over one million net
undeveloped acres located in Alberta and Saskatchewan along with a significant
portion, aggregating to 440,000 net acres, in the Northwest Territories. The
Company estimates the acquisition cost of proved reserves was approximately
$9.06 per BOE, exclusive of $54 million allocated to undeveloped acreage.
The Genesis Acquisition purchase price was allocated as of May 2, 2001,
as follows (in thousands):
C$ US$ (a)
--------- ---------
Total purchase price ...................................... $ 944,423 $ 616,866
Long-term debt assumed .................................... (135,000) (88,178)
Negative working capital assumed .......................... (100,854) (65,874)
--------- ---------
Amount paid ............................................... 708,569 462,814
Net assets at May 2, 2001 ................................. (221,000) (144,350)
--------- ---------
Excess of purchase price over net assets at May 2, 2001 ... $ 487,569 $ 318,464
========= =========
Allocation of excess of purchase price over net assets:
Fair market value adjustment to oil and gas properties .... $ 394,584 $ 257,729
Goodwill .................................................. 268,763 175,547
Increase in deferred income taxes ......................... (170,347) (111,265)
Increase in accrued liabilities ........................... (5,431) (3,547)
--------- ---------
$ 487,569 $ 318,464
========= =========
- -----------------
(a) Converted at the May 2, 2001, exchange rate of US$1/C$1.5310.
The Company has not yet completed its final evaluation of the assets
acquired and the liabilities assumed. Therefore, the purchase price allocation
is subject to change.
If the Genesis Acquisition had been consummated as of January 1, 2000,
the Company's unaudited pro forma revenues and net income for the years ended
December 31, 2001 and 2000, would have been as shown below; however, such pro
forma information is not necessarily indicative of what actually would have
occurred had the transaction occurred on such date.
2001 2000
----------- -----------
(In thousands, except
per share amounts)
Revenues ................................................................. $ 968,031 $ 935,933
Income before cumulative effect of change in accounting principle ........ 131,117 174,365
Net income ............................................................... 131,117 172,943
Basic Income Per Share:
Income before cumulative effect of change in accounting principle ... $ 2.08 $ 2.78
Net income .......................................................... 2.08 2.76
Diluted Income Per Share:
Income before cumulative effect of change in accounting principle ... $ 2.05 $ 2.73
Net income .......................................................... 2.05 2.70
76
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
8. 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 below and on the following page.
Exploration and Production
----------------------------------------------------------------------
Other
2001 (in thousands) U.S. Canada Argentina Bolivia Ecuador Foreign
- ------------------------------------------------- ----------- ------------ ----------- ----------- ---------- ----------
Revenues from external customers................. $ 386,344 $ 86,274 $ 243,329 $ 17,648 $ 24,270 $ 27
Intersegment revenues............................ - - - - - -
Depreciation, depletion and amortization expense. 60,426 52,072 44,252 5,033 2,933 -
Impairment of oil and gas properties............. 9,555 18,895 600 - - -
Segment operating income (loss).................. 196,894 (34,845) 137,459 8,230 12,025 (3,201)
Total assets..................................... 477,415 818,564 530,201 119,655 58,117 29,537
Capital investments.............................. 61,821 689,308 119,105 1,030 11,399 8,725
Long-lived assets................................ 436,327 795,000 475,418 93,572 49,724 28,348
Gathering/ Gas
2001 (in thousands) Plant Marketing Corporate Total
- ------------------------------------------------- ----------- ------------ ----------- -----------
Revenues from external customers................. $ 17,032 $ 130,209 $ 4,108 $ 909,241
Intersegment revenues............................ - 1,968 - 1,968
Depreciation, depletion and amortization expense. 1,326 - 2,902 168,944
Impairment of oil and gas properties............. - - - 29,050
Segment operating income (loss).................. (2,053) 3,836 1,206 319,551
Total assets..................................... 8,456 8,459 46,384 2,096,788
Capital investments.............................. 1,256 - 5,870 898,514
Long-lived assets................................ 5,798 - 7,847 1,892,034
77
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Exploration and Production
----------------------------------------------------------------------
Other
2000 (in thousands) U.S. Canada Argentina Bolivia Ecuador Foreign
- ------------------------------------------------- ----------- ------------ ----------- ----------- ---------- ----------
Revenues from external customers................. $ 346,574 $ 2,281 $ 256,234 $ 19,535 $ 30,613 $ -
Intersegment revenues............................ - - - - - -
Depreciation, depletion and amortization expense. 53,184 586 33,077 7,421 2,067 -
Impairment of oil and gas properties............. 225 - - - - -
Segment operating income (loss).................. 192,508 1,001 170,301 (3,796) 19,904 (6,121)
Total assets..................................... 524,588 60,274 459,219 126,399 50,223 21,030
Capital investments.............................. 64,124 52,788 92,885 28,740 (3,354) 22,489
Long-lived assets................................ 477,198 55,626 401,702 97,526 41,659 20,541
Gathering/ Gas
2000 (in thousands) Plant Marketing Corporate Total
- ------------------------------------------------- ----------- ------------ ----------- -----------
Revenues from external customers................. $ 19,998 $ 128,836 $ 2,110 $ 806,181
Intersegment revenues............................ 2,080 2,372 - 4,452
Depreciation, depletion and amortization expense. 1,567 - 2,207 100,109
Impairment of oil and gas properties............. - - - 225
Segment operating income (loss).................. 1,380 5,049 (98) 380,128
Total assets..................................... 13,479 35,977 47,208 1,338,397
Capital investments.............................. 299 - 2,334 260,305
Long-lived assets................................ 5,862 - 4,940 1,105,054
Exploration and Production
-----------------------------------------------------------
Other
1999 (in thousands) U.S. Argentina Bolivia Ecuador Foreign
- ------------------------------------------------- ----------- ------------ ----------- ----------- ----------
Revenues from external customers................. $ 275,486 $ 142,374 $ 5,786 $ 10,316 $ -
Intersegment revenues............................ - - - - -
Depreciation, depletion and amortization expense. 70,520 29,496 2,380 1,323 -
Impairment of oil and gas properties............. 3,306 - - - -
Segment operating income (loss).................. 112,902 77,033 (1,289) 6,714 (4,761)
Total assets..................................... 520,443 379,099 107,847 59,634 6,528
Capital investments.............................. 51,571 131,551 30,789 16,091 7,482
Long-lived assets................................ 476,153 342,179 88,292 49,853 6,528
Gathering/ Gas
1999 (in thousands) Plant Marketing Corporate Total
- ------------------------------------------------- ----------- ------------ ----------- -----------
Revenues from external customers................. $ 6,955 $ 60,275 $ 1,736 $ 502,928
Intersegment revenues............................ 1,350 1,285 - 2,635
Depreciation, depletion and amortization expense. 1,400 - 2,688 107,807
Impairment of oil and gas properties............. - - - 3,306
Segment operating income (loss).................. 402 2,725 (952) 192,774
Total assets..................................... 6,372 6,601 81,610 1,168,134
Capital investments.............................. 680 - 1,989 240,153
Long-lived assets................................ 3,629 - 4,718 971,352
78
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 2001, sales to two crude oil purchasers of the exploration and
production segment represented approximately 12 percent and 11 percent,
respectively, of the Company's total revenues (exclusive of eliminations of
intersegment sales, the impact of hedges and $26.9 million of gains on the sale
of oil and gas properties). 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 gains on the sales of oil and gas
properties).
9. Detail of Prepaids and Other Current Assets
(In thousands) 2001 2000
--------- ---------
Property divestiture proceeds receivable..... $ 7,287 $ -
Other prepaids and current assets............ 30,230 13,946
--------- ---------
$ 37,517 $ 13,946
========= =========
10. Quarterly Results (Unaudited)
The following is a summary of the quarterly results of operations for
the years ended December 31, 2001 and 2000. 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
--------- --------- ---------- ----------
2001(c)
- -------
Revenues............................................. $ 275,490 $ 251,914 $ 193,823 $ 188,014
Operating income..................................... 120,180 99,829 27,834 20,864
Provision (benefit) for income taxes................. 38,565 31,736 1,725 (1,554)
Net income........................................... 70,698 52,219 6,242 4,348
Income per share:
Basic........................................... 1.12 .83 .10 .07
Diluted......................................... 1.10 .81 .10 .07
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 72,002
Income per share:
Basic........................................... .61(a) .43(b) .93 1.15
Diluted......................................... .60(a) .42(b) .92 1.12
- -----------------
(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) The quarters ended June 30, 2001, September 30, 2001, and December 31,
2001 include the results of Genesis (see Note 7).
79
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
11. Supplementary Financial Information for Oil and Gas Producing Activities
Results of Operations from Oil and Gas Producing Activities
The following sets forth certain information with respect to the
Company's results of operations from oil and gas producing activities for the
years ended December 31, 2001, 2000 and 1999. The Company began operations in
Canada in December 2000.
2001
---------------------------------------------------------------------------
(In thousands) U.S. Canada Argentina Bolivia Ecuador Other Total
-------- -------- --------- --------- -------- -------- --------
Revenues ................................. $359,471 $ 86,277 $243,329 $ 17,648 $ 24,270 $ 27 $731,022
Production (lifting) costs ............... 106,680 32,567 61,018 4,385 8,901 - 213,551
Exploration costs ........................ 12,789 5,645 - - 411 3,228 22,073
Impairment of proved properties .......... 9,555 18,895 600 - - - 29,050
Depreciation, depletion and amortization.. 60,426 52,072 44,252 5,033 2,933 - 164,716
-------- -------- -------- -------- -------- -------- --------
Results of operations before income taxes 170,021 (22,902) 137,459 8,230 12,025 (3,201) 301,632
Income tax expense (benefit) ............. 66,138 (8,112) 41,238 2,058 3,005 (1,120) 103,207
-------- -------- -------- -------- -------- -------- --------
Results of operations (excluding corporate
overhead and interest costs) ........ $103,883 $(14,790) $ 96,221 $ 6,172 $ 9,020 $ (2,081) $198,425
======== ======== ======== ======== ======== ======== ========
2000
---------------------------------------------------------------------------
(In thousands) U.S. Canada Argentina Bolivia Ecuador Other Total
-------- -------- --------- --------- -------- -------- --------
Revenues.................................. $348,305 $ 2,281 $281,334 $ 19,535 $ 30,613 $ - $682,068
Production (lifting) costs................ 96,386 503 52,856 3,777 6,116 - 159,638
Exploration costs......................... 4,271 191 - 12,133 2,526 6,121 25,242
Impairment of proved properties........... 225 - - - - - 225
Depreciation, depletion and amortization.. 53,184 586 33,077 7,421 2,067 - 96,335
-------- -------- -------- -------- -------- -------- --------
Results of operations before income taxes 194,239 1,001 195,401 (3,796) 19,904 (6,121) 400,628
Income tax expense (benefit).............. 75,559 447 68,390 (949) 4,976 (2,142) 146,281
-------- -------- -------- -------- -------- -------- --------
Results of operations (excluding corporate
overhead and interest costs)......... $118,680 $ 554 $127,011 $ (2,847) $ 14,928 $ (3,979) $254,347
======== ======== ======== ======== ======== ======== ========
80
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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) 37,118
----------- ----------- ----------- ----------- ----------- ----------
Results of operations (excluding corporate
overhead and interest costs)......... $ 35,384 $ 60,338 $ (851) $ 6,714 $ (3,095) $ 98,490
=========== =========== =========== =========== =========== ==========
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,
2001 and 2000, was as follows:
2001
---------------------------------------------------------------------------------------
(In thousands) U.S. Canada Argentina Bolivia Ecuador Other Total
---------- --------- ----------- ----------- ----------- ----------- -----------
Unproved properties
not being amortized........... $ 19,188 $ 60,393 $ - $ - $ - $ 20,427 $ 100,008
Proved properties
being amortized............... 919,399 647,888 652,832 114,429 56,075 7,921 2,398,544
---------- --------- ----------- ----------- ----------- ----------- -----------
Total capitalized costs..... 938,587 708,281 652,832 114,429 56,075 28,348 2,498,552
Less accumulated depreciation,
depletion and amortization.... 506,719 70,271 177,414 20,857 6,351 - 781,612
---------- --------- ----------- ----------- ----------- ----------- -----------
Net capitalized costs....... $ 431,868 $ 638,010 $ 475,418 $ 93,572 $ 49,724 $ 28,348 $ 1,716,940
========== ========= =========== =========== =========== =========== ===========
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............... 944,582 49,981 533,727 113,399 45,086 - 1,686,775
---------- --------- ----------- ----------- ----------- ----------- -----------
Total capitalized costs..... 965,028 53,903 533,727 113,399 45,086 22,860 1,734,003
Less accumulated depreciation,
depletion and amortization.... 493,149 596 132,025 15,873 3,427 - 645,070
---------- --------- ----------- ----------- ----------- ----------- -----------
Net capitalized costs....... $ 471,879 $ 53,307 $ 401,702 $ 97,526 $ 41,659 $ 22,860 $ 1,088,933
========== ========= =========== =========== =========== =========== ===========
81
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 2001, 2000 and 1999:
2001
------------------------------------------------------------------------------------
(In thousands) U.S. Canada Argentina Bolivia Ecuador Other Total
----------- ----------- ----------- ----------- --------- ----------- -----------
Acquisitions:
Undeveloped properties...... $ 1,455 $ 59,033 $ - $ - $ - $ 338 $ 60,826
Producing properties........ 2,506 562,444 42,267 - - - 607,217
Exploratory.................... 20,963 24,839 - - 411 8,342 54,555
Development.................... 36,897 42,992 76,838 1,030 10,988 45 168,790
----------- ----------- ----------- ----------- --------- ----------- -----------
Total costs incurred..... $ 61,821 $ 689,308 $ 119,105 $ 1,030 $ 11,399 $ 8,725 $ 891,388
=========== =========== =========== =========== ========= =========== ===========
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
=========== =========== =========== =========== =========== ===========
82
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, Ecuador and Trinidad 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 independent petroleum consultants
of Outtrim Szabo Associates Ltd.
As discussed in Note 1, the Argentine government took actions which, in
effect, caused the devaluation of the peso in early December 2001. Consistent
with the assumptions used for the financial statements, as described in Note 1,
the Company used the estimated exchange rate of 1.65 pesos to one U.S. dollar to
translate peso-denominated future production, development and abandonment costs
in estimating proved oil and gas reserves. The resulting reduction in the U.S.
dollar cost of these expenses increased the Company's proved reserves in
Argentina by approximately 10.9 million BOE at December 31, 2001. As discussed
in Note 12, in February 2002, the Argentine government also imposed a 20 percent
excise tax on oil exports, effective March 1, 2002. The tax is limited by law to
a term of no more than five years. Had this export tax been in effect at
December 31, 2001, it would not have materially affected the Company's proved
reserve quantities in Argentina.
Oil (MBbls)
----------------------------------------------------------------------
U.S. Canada Argentina Bolivia Ecuador Trinidad Total
---------- --------- ---------- --------- --------- --------- --------
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
Revisions of previous estimates.................. (11,727) (8,719) 16,899 (589) 2,257 - (1,879)
Extensions, discoveries and other additions...... 487 2,185 216 - - 1,188 4,076
Production....................................... (8,409) (1,539) (10,548) (101) (1,375) (2) (21,974)
Purchase of reserves-in-place.................... - 27,493 11,724 - - - 39,217
Sales of reserves-in-place....................... (5,739) - - - - - (5,739)
---------- --------- ---------- --------- --------- --------- --------
Proved reserves at December 31, 2001............. 76,948 21,808 175,827 6,135 50,357 1,186 332,261
========== ========= ========== ========= ========= ========= ========
Proved developed oil reserves at:
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
========== ========= ========== ========= ========= ========= ========
December 31, 2001......................... 66,656 13,259 101,145 4,670 6,054 545 192,329
========== ========= ========== ========= ========= ========= ========
83
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Gas (MMcf)
----------------------------------------------------------------- Total
U.S. Canada Argentina Bolivia Trinidad Total (MBOE)
---------- ---------- ---------- ---------- ---------- ---------- ----------
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
Revisions of previous estimates............ (16,640) (21,092) 18,768 4,889 - (14,075) (4,225)
Extensions, discoveries and other additions 5,045 32,157 44 - 64,409 101,655 21,018
Production................................. (34,168) (22,132) (10,253) (9,088) - (75,641) (34,581)
Purchase of reserves-in-place.............. - 207,701 1,636 - - 209,337 74,107
Sales of reserves-in-place................. (27,760) - - - - (27,760) (10,366)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Proved reserves at December 31, 2001....... 325,149 236,112 131,394 459,660 64,409 1,216,724 535,048
========== ========== ========== ========== ========== ========== ==========
Proved developed gas reserves at:
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
========== ========== ========== ========== ========== ========== ==========
December 31, 2001........ 252,062 206,539 48,689 346,148 25,085 878,523 338,750
========== ========== ========== ========== ========== ========== ==========
84
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,
Disclosures about Oil and Gas Producing Activities. 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.
The translation of the peso-denominated future production, development
and abandonment costs in Argentina discussed above and the resulting reduction
in the U.S. dollar cost of these expenses increased the Company's Standardized
Measure by approximately $68.2 million at December 31, 2001. Had the Argentina
oil export tax discussed above been in effect at December 31, 2001, it would
have reduced the Company's Standardized Measure by approximately $98.8 million.
Set forth below is the Standardized Measure relating to proved oil and
gas reserves at December 31, 2001 and 2000:
2001
-------------------------------------------------------------------------------------------
(In thousands) U.S. Canada Argentina Bolivia Ecuador Trinidad Total
----------- ----------- ------------ ----------- ----------- ------------ -----------
Future cash inflows............... $ 2,131,498 $ 930,656 $ 2,885,530 $ 450,358 $ 528,726 $ 78,730 $ 7,005,498
Future production costs........... 929,408 299,818 1,152,217 47,277 242,802 43,949 2,715,471
Future development and
abandonment costs.............. 231,237 73,795 340,597 50,950 169,440 5,139 871,158
----------- ----------- ------------ ----------- ----------- ------------ -----------
Future net cash inflows before
income tax expense............. 970,853 557,043 1,392,716 352,131 116,484 29,642 3,418,869
Future income tax expense......... 271,409 141,784 323,109 80,911 11,339 11,966 840,518
----------- ----------- ------------ ----------- ----------- ------------ -----------
Future net cash flows............. 699,444 415,259 1,069,607 271,220 105,145 17,676 2,578,351
10 percent annual discount for
estimated timing of cash flows. 296,603 143,552 484,570 147,612 54,639 13,234 1,140,210
----------- ----------- ------------ ----------- ----------- ------------ -----------
Standardized Measure of discounted
future net cash flows.......... $ 402,841 $ 271,707 $ 585,037 $ 123,608 $ 50,506 $ 4,442 $ 1,438,141
=========== =========== ============ =========== =========== ============ ===========
85
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 39,435 682,169 200,329 97,138 2,385,124
----------- ---------- ------------ ------------ ----------- ------------
Standardized Measure of discounted
future net cash flows............... $ 1,566,257 $ 147,150 $ 907,231 $ 174,419 $ 156,064 $ 2,951,121
=========== ========== ============ ============ =========== ============
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 2001, 2000 and 1999:
(In thousands) 2001 2000 1999
----------- ----------- -----------
Standardized Measure - beginning of year.................. $ 2,951,121 $ 2,247,237 $ 648,222
Increases (decreases) -
Sales, net of production costs......................... (517,835) (522,545) (255,260)
Net change in sales prices, net of production costs.... (2,404,154) 1,131,540 1,218,764
Discoveries and extensions, net of related
future development and production costs............. 83,976 148,727 62,427
Changes in estimated future development costs.......... (123,254) (87,127) (52,195)
Development costs incurred............................. 163,122 93,276 21,472
Revisions of previous quantity estimates............... (8,646) 267,178 732,703
Accretion of discount.................................. 433,862 298,963 70,357
Net change in income taxes............................. 911,566 (645,108) (687,057)
Purchase of reserves-in-place.......................... 368,552 278,740 496,237
Sales of reserves-in-place............................. (141,509) (4,787) (54,135)
Timing of production of reserves and other............. (278,660) (254,973) 45,702
----------- ----------- -----------
Standardized Measure - end of year........................ $ 1,438,141 $ 2,951,121 $ 2,247,237
=========== =========== ===========
86
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
12. Subsequent Events
On January 6, 2002, the Argentine government enacted an emergency law
that required certain contracts that were previously payable in U.S. dollars to
be payable in pesos (see Note 1).
On February 13, 2002, the Argentine government announced a 20 percent
tax on oil exports, effective March 1, 2002. The tax is limited by law to a term
of no more than five years. The Company currently exports approximately 35
percent of its Argentina oil production. However, management believes that this
export tax will have the effect of decreasing all future Argentina oil revenues
(not only export revenues) by the tax rate for the duration of the tax.
Management believes that the U.S. dollar equivalent value for domestic Argentina
oil sales (now paid in pesos) will move over time to parity with the U.S.
dollar-denominated export values, net of the export tax, thus impacting domestic
Argentina values by a like percentage to the tax. The adverse impact of this tax
will be partially offset by the net cost savings resulting from the devaluation
of the peso on peso-denominated costs and may be further reduced by the
Argentina income tax savings related to deducting such impact. At December 31,
2001, the imposition of the export tax would not have had a material impact on
the Company's assessment of impairment of its oil and gas properties in
Argentina.
87
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 Indenture dated as of May 30, 2001, between The Chase
Manhattan Bank, as Trustee, and the Company (Filed as Exhibit
4.1 to the Company's Registration Statement on Form S-4,
Registration No. 333-63896).
4.6 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).
4.7 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).
88
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).
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 (Filed as
Exhibit 10.15 to the Company's report on Form 10-K for the
year ended December 31, 2000, filed March 12, 2001).
10.16 First Amendment to Second Amended and Restated Credit
Agreement dated as of August 8, 2001, between the Company, the
Lenders party thereto, Bank of Montreal, as administrative
agent, Bank of America, N.A., as syndication agent, Societe
General, Southwest Agency as documentation agent, and ABN AMRO
Bank, N.V., as managing agent (Filed as Exhibit 10 to the
Company's report on Form 10-Q for the quarter ended June 30,
2001, filed August 14, 2001).
10.17 Acquisition Agreement dated as of March 27, 2001, between the
Company and Genesis Exploration Ltd. (Filed as Exhibit 2 to
the Company's report on Form 8-K filed May 15, 2001).
21. Subsidiaries of the Company.
23.1 Consent of Arthur Andersen LLP.
89
23.2 Consent of Netherland, Sewell & Associates, Inc.
23.3 Consent of DeGolyer and MacNaughton.
23.4 Consent of Outtrim Szabo Associates Ltd.
99.1 Letter to Commission Pursuant to Temporary Note 3T.
- -----------------
* Management contract or compensatory plan or arrangement.
90