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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,