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Proc-Type: 2001,MIC-CLEAR
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<SEC-DOCUMENT>0000950134-01-002183.txt : 20010316
<SEC-HEADER>0000950134-01-002183.hdr.sgml : 20010316
ACCESSION NUMBER: 0000950134-01-002183
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 12
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010315
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: DEVON ENERGY CORP/DE
CENTRAL INDEX KEY: 0001090012
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 731567067
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 000-30176
FILM NUMBER: 1569656
BUSINESS ADDRESS:
STREET 1: 20 N BROADWAY
STREET 2: STE 1500
CITY: OKLAHOMA CITY
STATE: OK
ZIP: 73102
BUSINESS PHONE: 4052353611
MAIL ADDRESS:
STREET 1: 20 N BROADWAY
STREET 2: STE 1500
CITY: OKLAHOMA CITY
STATE: OK
ZIP: 73102
FORMER COMPANY:
FORMER CONFORMED NAME: DEVON DELAWARE CORP
DATE OF NAME CHANGE: 19990707
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>d84811e10-k405.txt
<DESCRIPTION>FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2000
<TEXT>
<PAGE> 1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 000-30176
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 73-1567067
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
20 NORTH BROADWAY, SUITE 1500
OKLAHOMA CITY, OKLAHOMA 73102-8260
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -------------------
<S> <C>
Common Stock, par value $.10 per share American Stock Exchange
4.9% Convertible Debentures, due 2008 The New York Stock Exchange
4.95% Convertible Debentures, due 2008 The New York Stock Exchange
</TABLE>
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 Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [x]
The aggregate market value of the voting stock held by non-affiliates of
the Registrant as of March 13, 2001, was $7,974,236,970. At such date
126,320,151 shares of common stock and 2,817,992 exchangeable shares of Devon's
wholly-owned subsidiary, Northstar Energy Corporation, were outstanding. Each
exchangeable share is exchangeable for one share of Devon common stock.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2001 annual meeting of stockholders - Part III
1
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
PART I
Item 1. Business........................................................... 5
Item 2. Properties......................................................... 13
Item 3. Legal Proceedings.................................................. 22
Item 4. Submission of Matters to a Vote of Security Holders................ 23
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters......................................... 24
Item 6. Selected Financial Data............................................ 25
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................... 28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........ 49
Item 8. Financial Statements and Supplementary Data........................ 53
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................ 108
PART III
Item 10. Directors and Executive Officers of the Registrant................ 109
Item 11. Executive Compensation............................................ 109
Item 12. Security Ownership of Certain Beneficial Owners and Management.... 109
Item 13. Certain Relationships and Related Transactions.................... 109
PART IV
Item 14. Exhibits, Financial Statements and Schedules,
and Reports on Form 8-K................................................. 110
</TABLE>
2
<PAGE> 3
DEFINITIONS
As used in this document:
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"Bcf" means billion cubic feet
"MMBtu" means million British thermal units, a measure of heating value
"Bbl" means barrel
"MBbls" means thousand barrels
"MMBbls" means million barrels
"Boe" means equivalent barrels of oil
"MBoe" means thousand equivalent barrels of oil
"MMBoe" means million equivalent barrels of oil
"Oil" includes crude oil and condensate
"NGLs" means natural gas liquids
"Permian/Mid-Continent, Rocky Mountain and Gulf" divisions of the Company
include onshore properties in the continental United States and
offshore properties primarily in the Gulf of Mexico
"Canada" means the division of the Company encompassing oil and gas properties
located in the Western Canadian Sedimentary Basin in Alberta and British
Columbia. All of these properties are held in the name of the Company's
wholly-owned subsidiary, Northstar Energy Company.
"International Division" means the division of the Company encompassing oil
and gas properties that lie outside the United States and Canada
3
<PAGE> 4
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report 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 or incorporated by reference in this
report, including, without limitation, statements regarding the company's future
financial position, business strategy, budgets, projected costs and plans and
objectives of management for future operations, are forward-looking statements.
In addition, forward-looking statements generally can be identified by the use
of forward-looking terminology such as "may," "will," "expect," "intend,"
"project," "estimate," "anticipate," "believe," or " continue" or the negative
thereof or variations thereon or similar terminology. Although the Company
believes that the expectations reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations will prove to have
been correct. Important factors that could cause actual results to differ
materially from the company's expectations ("Cautionary Statements") are
disclosed under "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations," "Item 2. Properties -- Proved Reserves and
Estimated Future Net Revenue" and elsewhere in this report. All subsequent
written and oral forward-looking statements attributable to the Company, or
persons acting on its behalf, are expressly qualified in their entirety by the
cautionary statements. The Company assumes no duty to update or revise its
forward-looking statements based on changes in internal estimates or
expectations or otherwise.
4
<PAGE> 5
PART I
ITEM 1. BUSINESS
GENERAL
Devon Energy Corporation, including its subsidiaries, ("Devon" or the
"Company") is an independent energy company engaged primarily in oil and gas
exploration, development and production, and in the acquisition of producing
properties. Through its predecessors, Devon began operations in 1971 as a
privately-held company. In 1988, the Company's common stock began trading
publicly on the American Stock Exchange under the symbol DVN. In addition,
commencing on December 15, 1998, a new class of Devon exchangeable shares began
trading on The Toronto Stock Exchange under the symbol NSX. These shares are
essentially equivalent to Devon common stock. However, because they are issued
by Devon's wholly-owned subsidiary, Northstar Energy Corporation ("Northstar"),
they qualify as a domestic Canadian investment for Canadian institutional
shareholders. They are exchangeable at any time, on a one-for-one basis, for
common shares of Devon.
The principal and administrative offices of Devon are located at 20
North Broadway, Suite 1500, Oklahoma City, OK 73102-8260 (telephone
405/235-3611).
Devon currently owns oil and gas properties concentrated in five
operating divisions: the Permian/Mid-Continent, Rocky Mountain and Gulf
divisions include onshore properties in the continental United States and
offshore properties primarily in the Gulf of Mexico; Canada, which includes
properties in the Western Canadian Sedimentary Basin in Alberta and British
Columbia; and the International Division, which includes properties in
Azerbaijan, South America, Southeast Asia and West Africa. (A detailed
description of the significant properties can be found under "Item 2. Properties
- -- Significant Properties" beginning on page 13 hereof.)
At December 31, 2000, Devon's estimated proved reserves were 1,097.4
MMBoe, of which 53% were natural gas reserves and 47% were oil and NGLs
reserves. The present value of pre-tax future net revenues discounted at 10% per
annum assuming essentially constant prices ("10% Present Value") of such
reserves was $17.7 billion. Devon is one of the top five public independent oil
and gas companies based in the United States, as measured by oil and gas
reserves.
STRATEGY
Devon's primary objectives are to build production, cash flow and
earnings per share by (a) acquiring oil and gas properties, (b) exploring for
new oil and gas reserves and (c) optimizing production from existing oil and gas
properties. Devon's management seeks to achieve these objectives by (a) keeping
debt levels low, (b) concentrating its properties in core areas to achieve
economies of scale, (c) acquiring and developing high profit margin properties,
(d) continually disposing of marginal and non-strategic properties and (e)
balancing reserves between oil and gas.
5
<PAGE> 6
During 1988, Devon expanded its capital base with its first issuance of
common stock to the public. This transaction began a substantial expansion
program that has continued through the subsequent years. Devon has used a
two-pronged strategy of acquiring producing properties and engaging in drilling
activities to achieve this expansion. Total proved reserves increased from 8.1
MMBoe at year-end 1987 (without giving effect to the 1998 and 2000 poolings) to
1,097.4 MMBoe at year-end 2000.
Devon's objective, however, is to increase value per share, not simply
to increase total assets. Reserves have grown from 1.31 Boe per share at
year-end 1987 (without giving effect to the 1998 and 2000 poolings) to 8.53 Boe
per share at year-end 2000. This represents a compound annual growth rate of
15%. Another measure of value per share is oil and gas production per share.
Production increased from 0.18 Boe per share in 1987 (without giving effect to
the 1998 and 2000 poolings) to 0.94 Boe per share in 2000, a compound annual
growth rate of 14%. At the same time, net debt (long-term debt less working
capital and marketable securities) has remained low. At year-end 2000, Devon's
net debt was $1.04 per Boe.
RECENT DEVELOPMENTS
On August 29, 2000, Devon completed a merger with Santa Fe Snyder
Corporation ("Santa Fe Snyder"). Santa Fe Snyder's domestic operations were
focused in the Rocky Mountain states, the Permian Basin of southeastern New
Mexico and west Texas and offshore in the Gulf of Mexico. Santa Fe Snyder also
had international operations located in Southeast Asia, South America and West
Africa. The merger of Santa Fe Snyder with Devon expanded Devon's reserves by
approximately 386 MMBoe and undeveloped leasehold by 16 million net acres. Total
assets increased by $1.8 billion. The total consideration to Santa Fe Snyder was
40.6 million common shares and the assumption of $1.2 billion of Santa Fe Snyder
debt and other liabilities. At year-end 2000, Devon's unused borrowing capacity
was in excess of $853 million.
The merger was accounted for as a pooling-of-interests of Devon and
Santa Fe Snyder. Therefore, Devon's results for 2000 and prior years have been
restated to include the results of both Devon and Santa Fe Snyder as if the two
companies had always been combined, unless otherwise indicated.
Santa Fe Snyder was formed on May 5, 1999 with the merger of Santa Fe
Energy Resources, Inc. and Snyder Oil Corporation ("Snyder"). The merger was
accounted for under the purchase method of accounting. Therefore, Devon's
results do not include any effect of Snyder's operations prior to May 5, 1999.
The Santa Fe Snyder merger was completed approximately one year after
completion of Devon's merger with PennzEnergy Company ("PennzEnergy") on August
17, 1999. The merger with PennzEnergy expanded Devon's reserves by approximately
396 MMBoe and undeveloped leasehold by approximately 13 million net acres. The
PennzEnergy merger was accounted for under the purchase method of accounting for
business combinations. Therefore, Devon's results do not include any effect of
PennzEnergy's operations prior to August 17, 1999.
6
<PAGE> 7
On December 10, 1998, Devon's merger with Northstar added 115 MMBoe of
reserves and 1.8 million undeveloped acres, all in Canada. The Northstar
combination was accounted for under the pooling-of-interests method of
accounting for business combinations. Accordingly, Devon's results for 1998 and
prior years include the results of both Devon and Northstar as if the two had
always been combined, unless otherwise indicated.
DRILLING ACTIVITIES
Devon is engaged in numerous drilling activities on properties presently
owned and intends to drill or develop other properties acquired in the future.
For 2001, Devon's drilling activities will be focused in the Rocky Mountains,
Permian Basin, Mid-Continent, Gulf of Mexico and onshore Gulf Coast areas in the
U.S.and the Western Sedimentary areas of Canada. Devon also has significant
international operations in Azerbaijan, Southeast Asia, South America and West
Africa.
The following tables set forth the results of Devon's drilling activity
for the past five years.
UNITED STATES PROPERTIES
<TABLE>
<CAPTION>
Development Wells Exploratory Wells
----------------------------------------------------- ------------------------------------------------------
Gross(1) Net(2) Gross(1) Net(2)
----------------------------------------------------- ------------------------------------------------------
Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- ----- ---------- --- ----- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 452 14 466 370.75 6.95 377.70 18 10 28 9.50 3.48 12.98
1997 484 17 501 303.00 9.10 312.10 30 23 53 11.30 9.00 20.30
1998 374 1 375 153.69 0.10 153.79 24 21 45 11.36 7.54 18.90
1999 547 8 555 345.35 3.80 349.15 71 9 80 51.91 5.78 57.69
2000 890 13 903 512.18 6.80 518.98 95 11 106 80.09 7.41 87.50
----- -- ----- -------- ----- -------- --- -- --- ------ ----- ------
Total 2,747 53 2,800 1,684.97 26.75 1,711.72 238 74 312 164.16 33.21 197.37
===== == ===== ======== ===== ======== === == === ====== ===== ======
</TABLE>
CANADIAN PROPERTIES
<TABLE>
<CAPTION>
Development Wells Exploratory Wells
----------------------------------------------------- ------------------------------------------------------
Gross(1) Net(2) Gross(1) Net(2)
----------------------------------------------------- ------------------------------------------------------
Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- ----- ---------- --- ----- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 63 11 74 29.70 5.10 34.80 35 18 53 24.70 15.10 39.80
1997 126 29 155 88.20 23.20 111.40 55 48 103 43.50 42.20 85.70
1998 112 15 127 74.88 11.04 85.92 45 37 82 32.99 30.50 63.49
1999 65 9 74 29.61 3.45 33.06 39 23 62 25.15 16.03 41.18
2000 130 6 136 68.74 3.25 71.99 70 27 97 40.60 19.27 59.87
--- -- --- ------ ----- ------ --- --- --- ------ ------ ------
Total 496 70 566 291.13 46.04 337.17 244 153 397 166.94 123.10 290.04
=== == === ====== ===== ====== === === === ====== ====== ======
</TABLE>
INTERNATIONAL PROPERTIES
<TABLE>
<CAPTION>
Development Wells Exploratory Wells
----------------------------------------------------- ------------------------------------------------------
Gross(1) Net(2) Gross(1) Net(2)
----------------------------------------------------- ------------------------------------------------------
Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- ----- ---------- --- ----- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 26 1 27 5.70 0.20 5.90 3 6 9 0.90 1.90 2.80
1997 43 2 45 10.00 0.60 10.60 1 5 6 0.30 1.80 2.10
1998 59 2 61 18.90 0.60 19.50 9 18 27 2.90 8.20 11.10
1999 42 2 44 10.00 0.60 10.60 1 4 5 0.50 1.60 2.10
2000 75 1 76 19.71 0.50 20.21 1 9 10 0.33 6.01 6.34
--- - --- ----- ---- ----- -- -- -- ---- ----- -----
Total 245 8 253 64.31 2.50 66.81 15 42 57 4.93 19.51 24.44
=== = === ===== ==== ===== == == == ==== ===== =====
</TABLE>
7
<PAGE> 8
TOTAL PROPERTIES
<TABLE>
<CAPTION>
Development Wells Exploratory Wells
----------------------------------------------------- ------------------------------------------------------
Gross(1) Net(2) Gross(1) Net(2)
----------------------------------------------------- ------------------------------------------------------
Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- ----- ---------- --- ----- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 541 26 567 406.15 12.25 418.40 56 34 90 35.10 20.48 55.58
1997 653 48 701 401.20 32.90 434.10 86 76 162 55.10 53.00 108.10
1998 545 18 563 247.47 11.74 259.21 78 76 154 47.25 46.24 93.49
1999 654 19 673 384.96 7.85 392.81 111 36 147 77.56 23.41 100.97
2000 1,095 20 1,115 600.63 10.55 611.18 166 47 213 121.02 32.69 153.71
----- --- ----- -------- ----- -------- --- --- --- ------ ------ ------
Total 3,488 131 3,619 2,040.41 75.29 2,115.70 497 269 766 336.03 175.82 511.85
===== === ===== ======== ===== ======== === === === ====== ====== ======
</TABLE>
- ------------------
(1) Gross wells are the sum of all wells in which Devon owns an interest.
(2) Net wells are the sum of Devon's working interests in gross wells.
As of December 31, 2000, Devon was participating in the drilling of 47
gross (21.32 net) wells in the U.S., 9 gross (5.70 net) wells in Canada and 16
gross (5.02 net) wells internationally. Of these wells, through February 15,
2001, 34 gross (16.92 net) wells in the U.S., 3 gross (2.50 net) wells in Canada
and 6 gross (2.02 net) wells internationally had been completed as productive.
Additionally, 1 gross (0.40 net) well in the U.S. and 2 gross (1.25 net) wells
in Canada were dry holes. The remaining wells were still in process.
CUSTOMERS
Devon sells its gas production to a variety of customers including
pipelines, utilities, gas marketing firms, industrial users and local
distribution companies. Existing gathering systems and interstate and intrastate
pipelines are used to consummate gas sales and deliveries.
The principal customers for Devon's crude oil production are refiners,
remarketers and other companies, some of which have pipeline facilities near the
producing properties. In the event pipeline facilities are not conveniently
available, crude oil is trucked or barged to storage, refining or pipeline
facilities.
For the year ended December 31, 2000, one significant purchaser, Enron
Capital and Trade Resource Corporation ("Enron"), accounted for 20% of Devon's
combined oil, gas and NGLs sales. For the year ended December 31, 1998, one
significant purchaser, Aquila Energy Marketing Corporation ("Aquila"), accounted
for 11% of Devon's combined oil, gas and NGLs sales. No purchaser accounted for
over 10% of such revenues in 1999. Enron and Aquila purchase production from
numerous Devon properties at variable and market-sensitive prices. Devon does
not consider itself dependent upon either of these purchasers, since other
purchasers are willing to purchase this same production at competitive prices.
OIL AND NATURAL GAS MARKETING
Oil Marketing. Devon's oil production is sold under both long-term and
short-term agreements at prices negotiated between the parties. Devon
periodically enters into hedging activities with a portion of its oil production
which are intended to support its oil price at targeted levels and to manage the
Company's exposure to oil price fluctuations. (See "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk.")
8
<PAGE> 9
Natural Gas Marketing. Devon's gas production is also sold under both
long-term and short-term agreements at negotiated prices. Although exact
percentages vary daily, as of February 2001 approximately 29% of Devon's natural
gas production was sold under short-term contracts at variable or
market-sensitive prices. These market-sensitive sales are referred to as "spot
market" sales. Another 68% were committed under various long-term contracts (one
year or more) which dedicate the natural gas to a purchaser for an extended
period of time, but still at market sensitive prices. Devon's remaining gas
production was dedicated under long-term contracts at fixed prices.
Under both long-term and short-term contracts, typically either the
entire contract (in the case of short-term contracts) or the price provisions of
the contract (in the case of long-term contracts) are renegotiated from daily
intervals up to one-year intervals. The spot market has become progressively
more competitive in recent years. As a result, prices on the spot market have
been volatile.
The spot market is subject to volatility as supply and demand factors in
various regions of North America fluctuate. In addition to long-term fixed price
contracts, Devon periodically enters into hedging arrangements or firm delivery
commitments with a portion of its gas production. These activities are intended
to support targeted gas price levels and to manage the Company's exposure to gas
price fluctuations. (See "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk.")
COMPETITION
The oil and gas business is highly competitive. Devon encounters
competition by major integrated and independent oil and gas companies in
acquiring drilling prospects and properties, contracting for drilling equipment
and securing trained personnel. Intense competition occurs with respect to
marketing, particularly of natural gas. Certain competitors have resources that
substantially exceed those of Devon.
SEASONAL NATURE OF BUSINESS
Generally, but not always, the demand for natural gas decreases during
the summer months and increases during the winter months. Seasonal anomalies
such as mild winters sometimes lessen this fluctuation. In addition, pipelines,
utilities, local distribution companies and industrial users utilize natural gas
storage facilities and purchase some of their anticipated winter requirements
during the summer. This can also lessen seasonal demand fluctuations.
GOVERNMENT REGULATION
Devon's operations are subject to various levels of government controls
and regulations in the United States, Canada and internationally.
UNITED STATES REGULATION
In the United States, legislation affecting the oil and gas industry has
been pervasive and is under constant review for amendment or expansion. Pursuant
to such legislation, numerous federal, state and local departments and agencies
have issued extensive rules and regulations binding on the oil and gas industry
and its individual members, some of which carry substantial penalties for
failure to comply. Such laws and regulations have a significant impact on oil
and gas drilling and production
9
<PAGE> 10
activities, increase the cost of doing business and, consequently, affect
profitability. Inasmuch as new legislation affecting the oil and gas industry is
commonplace and existing laws and regulations are frequently amended or
reinterpreted, Devon is unable to predict the future cost or impact of complying
with such laws and regulations.
Exploration and Production. Devon's United States operations 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; implementing spill
prevention plans; submitting notification and receiving permits relating to the
presence, use and release of certain materials incidental to oil and gas
operations; and regulating the location of wells, the method of drilling and
casing wells, the use, transportation, storage and disposal of fluids and
materials used in connection with drilling and production activities, surface
usage and the restoration of properties upon which wells have been drilled, the
plugging and abandoning of wells and the transporting of production. Devon's
operations are also subject to various conservation matters, including the
regulation of the size of drilling and spacing units or proration units, the
number of wells which may be drilled in a unit, and the unitization or pooling
of oil and gas properties. In this regard, some states allow the forced pooling
or integration of tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases, which may make it more difficult to
develop oil and gas properties. In addition, state conservation laws establish
maximum rates of production from oil and gas wells, generally limit the venting
or flaring of gas, and impose certain requirements regarding the ratable
purchase of production. The effect of these regulations is to limit the amounts
of oil and gas Devon can produce from its wells and to limit the number of wells
or the locations at which Devon can drill.
Certain of Devon's oil and gas leases, including its offshore Gulf of
Mexico leases, most of its leases in the San Juan Basin and many of the
Company's leases in southeast New Mexico and Wyoming, are granted by the federal
government and administered by various federal agencies, including the Minerals
Management Service of the Department of the Interior ("MMS"). Such leases
require compliance with detailed federal regulations and orders which regulate,
among other matters, drilling and operations on lands covered by these leases,
and calculation and disbursement of royalty payments to the federal government.
The MMS has been particularly active in recent years in evaluating and, in some
cases, promulgating new rules and regulations regarding competitive lease
bidding and royalty payment obligations for production from federal lands. The
Federal Energy Regulatory Commission ("FERC") also has jurisdiction over certain
offshore activities pursuant to the Outer Continental Shelf Lands Act.
Environmental and Occupational Regulations. Various federal, state and
local laws and regulations concerning the discharge of incidental materials into
the environment, the generation, storage, transportation and disposal of
contaminants or otherwise relating to the protection of public health, natural
resources, wildlife and the environment, affect Devon's exploration, development
and production operations and the costs attendant thereto. These laws and
regulations increase Devon's overall operating expenses. Devon maintains levels
of insurance customary in the industry to limit its financial exposure in the
event of a substantial environmental claim resulting from sudden, unanticipated
and accidental discharges of oil, salt water or other substances. However, 100%
coverage is not maintained concerning any environmental claim, and no coverage
is maintained with respect to any award of punitive damages against Devon or any
penalty or fine required to be paid by
10
<PAGE> 11
Devon because of its violation of any federal, state or local law. Devon is
committed to meeting its responsibilities to protect the environment wherever it
operates and anticipates making increased expenditures of both a capital and
expense nature as a result of the increasingly stringent laws relating to the
protection of the environment. Devon's unreimbursed expenditures in 2000
concerning such matters were immaterial, but Devon cannot predict with any
reasonable degree of certainty its future exposure concerning such matters.
Devon is also subject to laws and regulations concerning occupational
safety and health. Due to the continued changes in these laws and regulations,
and the judicial construction of same, Devon is unable to predict with any
reasonable degree of certainty its future costs of complying with these laws and
regulations.
Devon has historically maintained its own internal Environmental, Health
and Safety Department. This department is responsible for instituting and
maintaining an environmental and safety compliance program for Devon. The
program includes field inspections of properties and internal assessments of
Devon's compliance procedures.
Devon is subject to certain laws and regulations relating to
environmental remediation activities associated with past operations, such as
the Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA") and similar state statutes. In response to potential liabilities
associated with these activities, accruals have been established when reasonable
estimates are possible. Such accruals primarily include estimated costs
associated with remediation. Devon has not used discounting in determining its
accrued liabilities for environmental remediation, and no claims for possible
recovery from third party insurers or other parties related to environmental
costs have been recognized in Devon's consolidated financial statements. Devon
adjusts the accruals when new remediation responsibilities are discovered and
probable costs become estimable, or when current remediation estimates must be
adjusted to reflect new information.
Certain of Devon's historical operations acquired in historical and
recent mergers are involved in matters in which it has been alleged that such
subsidiaries are potentially responsible parties ("PRPs") under CERCLA or
similar state legislation with respect to various waste disposal areas owned or
operated by third parties. As of December 31, 2000, Devon's consolidated balance
sheet included $7.8 million of accrued liabilities, reflected in "Other
liabilities," for environmental remediation. Devon does not currently believe
there is a reasonable possibility of incurring additional material costs in
excess of the current accruals recognized for such environmental remediation
activities. With respect to the sites in which Devon subsidiaries are PRPs,
Devon's conclusion is based in large part on (i) the availability of defenses to
liability, including the availability of the "petroleum exclusion" under CERCLA
and similar state laws, and/or (ii) Devon's current belief that its share of
wastes at a particular site is or will be viewed by the Environmental Protection
Agency or other PRPs as being de minimis. As a result, Devon's monetary exposure
is not expected to be material.
11
<PAGE> 12
CANADIAN REGULATIONS
The oil and gas industry in Canada is subject to extensive controls and
regulations imposed by various levels of government. It is not expected that any
of these controls or regulations will affect Devon's Canadian operations in a
manner materially different than they would affect other oil and gas companies
of similar size. The following are the most important areas of control and
regulation.
The North American Free Trade Agreement. The North American Free Trade
Agreement ("NAFTA") which became effective on January 1, 1994 carries forward
most of the material energy terms contained in the Canada-U.S. Free Trade
Agreement. In the context of energy resources, Canada continues to remain free
to determine whether exports to the United States or Mexico will be allowed,
provided that any export restrictions do not (i) reduce the proportion of energy
exported relative to the supply of the energy resource; (ii) impose an export
price higher than the domestic price; or (iii) disrupt normal channels of
supply. All parties to NAFTA are also prohibited from imposing minimum export or
import price requirements.
Royalties and Incentives. Each province and the federal government of
Canada have legislation and regulations governing land tenure, royalties,
production rates and taxes, environmental protection and other matters under
their respective jurisdictions. The royalty regime is a significant factor in
the profitability of oil and natural gas production. Royalties payable on
production from lands other than Crown lands are determined by negotiations
between the parties. Crown royalties are determined by government regulation and
are generally calculated as a percentage of the value of the gross production
with the royalty rate dependent in part upon prescribed reference prices, well
productivity, geographical location, field discovery date and the type and
quality of the petroleum product produced. From time to time, the governments of
Canada, Alberta and British Columbia have also established incentive programs
such as royalty rate reductions, royalty holidays and tax credits for the
purpose of encouraging oil and natural gas exploration or enhanced recovery
projects. These incentives generally have the effect of increasing the cash flow
to the producer.
Pricing and Marketing. The price of oil and natural gas sold is
determined by negotiation between buyers and sellers. An order from the National
Energy Board ("NEB") is required for oil exports from Canada. Any oil export to
be made pursuant to an export contract of longer than one year, in the case of
light crude, and two years, in the case of heavy crude, duration (up to 25
years) requires an exporter to obtain an export license from the NEB. The issue
of such a license requires the approval of the Governor in Council. Natural gas
exported from Canada is also subject to similar regulation by the NEB. Exporters
are free to negotiate prices and other terms with purchasers, provided that the
export contracts in excess of two years must continue to meet certain criteria
prescribed by the NEB. The governments of Alberta and British Columbia also
regulate the volume of natural gas which may be removed from those provinces for
consumption elsewhere based on such factors as reserve availability,
transportation arrangements and market considerations.
Environmental Regulation. The oil and natural gas industry is subject to
environmental regulation pursuant to local, provincial and federal legislation.
Environmental legislation provides for restrictions and prohibitions on releases
or emissions of various substances produced or utilized in association with
certain oil and gas industry operations. In addition, legislation requires that
well and facility sites be abandoned and reclaimed to the satisfaction of
provincial authorities. A breach of such
12
<PAGE> 13
legislation may result in the imposition of fines and penalties. Devon is
committed to meeting its responsibilities to protect the environment wherever it
operates and anticipates making increased expenditures of both a capital and
expense nature as a result of the increasingly stringent laws relating to the
protection of the environment. Devon's unreimbursed expenditures in 2000
concerning such matters were immaterial, but Devon cannot predict with any
reasonable degree of certainty its future exposure concerning such matters.
Investment Canada Act. The Investment Canada Act requires Government of
Canada approval, in certain cases, of the acquisition of control of a Canadian
business by an entity that is not controlled by Canadians. In certain
circumstances, the acquisition of natural resource properties may be considered
to be a transaction requiring such approval.
INTERNATIONAL REGULATIONS
Environmental Regulation. The oil and gas industry is subject to various
environmental regulation and contract concession requirements pursuant to each
individual country's laws, agreements, and treaties. In general, this consists
of preparing Environmental Impact Assessments in order to receive required
environmental permits to conduct drilling or construction activities. Such
regulations also typically include requirements to develop emergency response
plans, waste management plans, and spill contingency plans. In some regions, the
application of world-wide standards, such as ISO 14000 governing Environmental
Management Systems, are required to be implemented for operations.
Protecting the environment and the safety and health of employees,
contractors, communities, and the public is fundamental to the way Devon
conducts its business. This is accomplished through the establishment of
corporate environmental, health, and safety policies and procedures that are
implemented worldwide.
EMPLOYEES
As of December 31, 2000, Devon's staff consisted of 1,750 full-time
employees. The Company also engages independent consulting petroleum engineers,
environmental professionals, geologists, geophysicists, landmen and attorneys on
a fee basis. The Company believes that it has good labor relations with its
employees.
ITEM 2. PROPERTIES
Substantially all of Devon's properties consist of interests in
developed and undeveloped oil and gas leases and mineral acreage located in the
Company's core operating areas. These interests entitle Devon to drill for and
produce oil, natural gas and NGLs from specific areas. Devon's interests are
mostly in the form of working interests and volumetric production payments, and,
to a lesser extent, overriding royalty, foreign government concessions, mineral
and net profits interests and other forms of direct and indirect ownership in
oil and gas properties.
13
<PAGE> 14
PROVED RESERVES AND ESTIMATED FUTURE NET REVENUE
"Proved reserves" are those quantities of oil, natural gas and NGLs,
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in the future from known reservoirs under existing economic and
operating conditions. Estimates of proved reserves are strictly technical
judgments and are not knowingly influenced by attitudes of conservatism or
optimism. The following table sets forth Devon's estimated proved reserves, the
estimated future net revenues therefrom and the 10% Present Value thereof as of
December 31, 2000. Approximately 80% of Devon's U.S. proved reserves were
estimated by LaRoche Petroleum Consultants, Ltd. and Ryder-Scott Company
Petroleum Consultants, independent petroleum consultants. Devon's internal staff
of engineers estimated the remainder of the U.S. reserves. All of the year-end
2000 Canadian proved reserves were calculated by the independent petroleum
consultants Paddock Lindstrom & Associates Ltd. The international proved
reserves, other than Canada as of December 31, 2000, were calculated by the
independent petroleum consultants of Ryder-Scott Company Petroleum Consultants.
All reserve estimates were prepared using standard geological and engineering
methods generally accepted by the petroleum industry and in accordance with SEC
guidelines (as described in the following notes). These estimates correspond
with the method used in presenting the `Supplemental Information on Oil and Gas
Operations" in Note 16 to Devon's Consolidated Financial Statements included
herein, except that federal income taxes attributable to such future net
revenues have been disregarded in the presentation below.
14
<PAGE> 15
<TABLE>
<CAPTION>
TOTAL PROVED PROVED
PROVED DEVELOPED UNDEVELOPED
RESERVES RESERVES(1) RESERVES(2)
-------- ------------ ------------
<S> <C> <C> <C>
TOTAL RESERVES
Oil (MBbls)................................................. 459,244 261,432 197,812
Gas (MMcf).................................................. 3,458,184 2,631,267 826,917
NGL (MBbls)................................................. 61,757 46,256 15,501
MBoe(3)..................................................... 1,097,366 746,232 351,134
Pre-tax Future Net Revenue ($ thousands)(4)................. 30,760,602 24,350,591 6,410,011
Pre-tax 10% Present Value ($ thousands)(4).................. 17,737,043 14,694,207 3,042,836
U.S. RESERVES
Oil (MBbls)................................................. 225,537 192,190 33,347
Gas (MMcf).................................................. 2,521,307 2,087,287 434,020
NGL (MBbls)................................................. 45,518 42,155 3,363
MBoe(3)..................................................... 691,273 582,226 109,047
Pre-tax Future Net Revenue ($ thousands)(4)................. 22,566,827 18,971,071 3,595,756
Pre-tax 10% Present Value ($ thousands)(4).................. 13,396,544 11,415,285 1,981,259
CANADIAN RESERVES
Oil (MBbls)................................................. 36,492 29,721 6,771
Gas (MMcf).................................................. 523,509 507,703 15,806
NGL (MBbls)................................................. 4,204 4,072 132
MBoe(3)..................................................... 127,948 118,410 9,538
Pre-tax Future Net Revenue ($ thousands)(4)................. 4,985,532 4,791,079 194,453
Pre-tax 10% Present Value ($ thousands)(4).................. 2,935,656 2,856,269 79,387
INTERNATIONAL RESERVES
Oil (MBbls)................................................. 197,215 39,521 157,694
Gas (MMcf).................................................. 413,368 36,277 377,091
NGL (MBbls)................................................. 12,035 29 12,006
MBoe(3)..................................................... 278,145 45,596 232,549
Pre-tax Future Net Revenue ($ thousands)(4)................. 3,208,243 588,441 2,619,802
Pre-tax 10% Present Value ($ thousands)(4).................. 1,404,843 422,653 982,190
</TABLE>
-----------------------------
(1) Proved developed reserves are proved reserves that are expected to
be recovered from existing wells with existing equipment and
operating methods.
(2) Proved undeveloped reserves are proved reserves to be recovered from
new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompleting or
deepening a well or for new fluid injection facilities.
(3) Gas reserves are converted to MBoe at the rate of six MMcf per MBbl
of oil, based upon the approximate relative energy content of
natural gas to oil, which rate is not necessarily indicative of the
relationship of gas to oil prices. The respective prices of gas and
oil are affected by market conditions and other factors in addition
to relative energy content.
(4) Estimated future net revenue represents estimated future gross
revenue to be generated from the production of proved reserves, net
of estimated production and development costs. The amounts shown do
not give effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expense
or to depreciation, depletion and amortization.
These amounts were calculated using prices and costs in effect as of
December 31, 2000. These prices were not changed except where
different prices were fixed and determinable from applicable
contracts. These assumptions yield average prices over the life of
Devon's properties of $23.77 per Bbl of oil, $8.04 per Mcf of
natural gas and $29.80 per Bbl of NGLs. These prices compare to
December 31, 2000, New York Mercantile Exchange prices of $26.80 per
Bbl for crude oil and of $9.23 per MMBtu for natural gas.
15
<PAGE> 16
No estimates of Devon's proved reserves have been filed with or included
in reports to any federal or foreign governmental authority or agency since the
beginning of the last fiscal year except (i) in filings with the SEC and (ii) in
filings with the Department of Energy ("DOE"). Reserve estimates filed by Devon
with the SEC correspond with the estimates of Devon reserves contained herein.
Reserve estimates filed with the DOE are based upon the same underlying
technical and economic assumptions as the estimates of Devon's reserves included
herein. However, the DOE requires reports to include the interests of all owners
in wells that Devon operates and to exclude all interests in wells that Devon
does not operate.
The prices used in calculating the estimated future net revenues
attributable to proved reserves do not necessarily reflect market prices for
oil, gas and NGL production subsequent to December 31, 2000. There can be no
assurance that all of the proved reserves will be produced and sold within the
periods indicated, that the assumed prices will be realized or that existing
contracts will be honored or judicially enforced.
The process of estimating oil, gas and NGLs reserves is complex,
requiring significant subjective decisions in the evaluation of available
geological, engineering and economic data for each reservoir. The data for a
given reservoir may change substantially over time as a result of, among other
things, additional development activity, production history and viability of
production under varying economic conditions. Consequently, material revisions
to existing reserve estimates may occur in the future.
PRODUCTION, REVENUE AND PRICE HISTORY
Certain information concerning oil and natural gas production, prices,
revenues (net of all royalties, overriding royalties and other third party
interests) and operating expenses for the three years ended December 31, 2000,
is set forth in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations."
WELL STATISTICS
The following table sets forth Devon's producing wells as of December
31, 2000:
<TABLE>
<CAPTION>
Oil Wells Gas Wells Total Wells
-------------------------- --------------------------- ---------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
U.S. 14,599 4,219 8,425 3,808 23,024 8,027
Canada 1,492 628 1,419 629 2,911 1,257
International 948 270 47 11 995 281
------------ ---------- ----------- ----------- ----------- -----------
Total 17,039 5,117 9,891 4,448 26,930 9,565
============ ========== =========== =========== =========== ===========
</TABLE>
(1) Gross wells are the total number of wells in which Devon owns a
working interest.
(2) Net refers to gross wells multiplied by Devon's fractional working
interests therein.
Devon also held numerous overriding royalty interests in oil and gas
wells, a portion of which are convertible to working interests after recovery of
certain costs by third parties. After converting to working interests, these
overriding royalty interests will be included in Devon's gross and net well
count.
16
<PAGE> 17
UNDEVELOPED ACREAGE
The following table sets forth Devon's developed and undeveloped oil and
gas lease and mineral acreage as of December 31, 2000.
<TABLE>
<CAPTION>
Developed Undeveloped
---------------------------- ----------------------------
Gross(1) Net(2) Gross(1) Net(2)
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Domestic
Permian/Mid-Continent Division
Permian Basin 751,282 370,590 1,013,728 392,002
Mid-Continent 780,644 415,434 1,204,297 608,861
---------- ---------- ---------- ----------
Total Permian/Mid-
Continent Division 1,531,926 786,024 2,218,025 1,000,863
---------- ---------- ---------- ----------
Rocky Mountain Division 583,500 308,355 2,159,480 1,493,846
---------- ---------- ---------- ----------
Gulf Division
Offshore 756,008 383,338 918,825 653,282
Onshore 429,235 247,918 140,420 54,047
---------- ---------- ---------- ----------
Total Gulf Division 1,185,243 631,256 1,059,245 707,329
---------- ---------- ---------- ----------
Total Domestic 3,300,669 1,725,635 5,436,750 3,202,038
Canada 878,457 539,904 3,117,093 2,228,510
---------- ---------- ---------- ----------
International 387,380 101,525 19,418,885 12,195,069
---------- ---------- ---------- ----------
Grand Total 4,566,506 2,367,064 27,972,728 17,625,617
========== ========== ========== ==========
</TABLE>
(1) Gross acres are the total number of acres in which Devon owns a
working interest.
(2) Net refers to gross acres multiplied by Devon's fractional working
interests therein.
OPERATION OF PROPERTIES
The day-to-day operations of oil and gas properties are the
responsibility of an operator designated under pooling or operating agreements.
The operator supervises production, maintains production records, employs field
personnel and performs other functions. The charges under operating agreements
customarily vary with the depth and location of the well being operated.
Devon is the operator of 11,038 of its 26,930 wells. As operator, Devon
receives reimbursement for direct expenses incurred in the performance of its
duties as well as monthly per-well producing and drilling overhead reimbursement
at rates customarily charged in the area to or by unaffiliated third parties. In
presenting its financial data, Devon records the monthly overhead reimbursements
as a reduction of general and administrative expense, which is a common industry
practice.
17
<PAGE> 18
ORGANIZATION STRUCTURE
Devon's properties are distributed geographically in five separate
divisions. Operations in the United States are conducted by the
Permian/Mid-Continent, Rocky Mountain and Gulf divisions. Canadian operations
are conducted by Devon's Northstar Energy subsidiary and all operations outside
North America make up the International Division. Maintaining a tight geographic
focus in selected core areas is a key element of Devon's operating strategy.
Concentrating our operations enhances management efficiency and marketing and
purchasing power.
UNITED STATES PROPERTIES
PERMIAN/MID-CONTINENT DIVISION
The Permian Basin encompasses approximately 66,000 square miles in
southeastern New Mexico and west Texas and contains more than 500 major oil and
gas fields. It is characterized by prolific, long-lived oil and gas production
from numerous formations found at a wide variety of depths. Many formations
respond to enhanced recovery techniques, such as waterflood projects. Acreage
held by production from existing wells and large federal exploration units makes
leases difficult to obtain. Most of Devon's position in the Permian was
established through six major property transactions. Devon's merger with Santa
Fe Snyder Corporation in 2000 increased its proved reserves in the Permian Basin
by over 75%. Even though the Permian Basin is quite mature and not known as a
high growth area, Devon replaced more than 160% of its Permian Basin oil and gas
production in 2000 through exploration and development drilling.
The Mid-Continent area includes all or portions of the states of Kansas,
Oklahoma, Texas, Arkansas, Louisiana, Mississippi and Alabama. This area covers
a wide spectrum of geologic formations producing both oil and natural gas.
Although the Mid-Continent was the site of some of the earliest oil and gas
discoveries in the United States, several areas offer opportunities for growth
through exploitation and exploration drilling. For example, Devon has an active
drilling program underway in the Carthage, Bethany, Sligo area of eastern Texas
and western Louisiana in 2001. Devon has been able to increase production from
this area by downspacing, that is, drilling wells closer together in producing
fields. Over time, average spacing has been decreased from 640 acres per well to
as little as 40 acres per well. Devon has increased production in the Carthage,
Bethany, Sligo area five-fold since the early 1980's through downspacing and
improved reservoir management.
ROCKY MOUNTAIN DIVISION
The Rocky Mountain Division extends north from New Mexico and includes
the states of Colorado, Utah, Wyoming, Montana and North Dakota. It is Devon's
fastest growing division, and production of approximately 51,800 energy
equivalent barrels per day in 2000 is expected to increase by around 30% in
2001. Much of that growth will be due to expansion of coalbed methane (CBM)
production in the Powder River Basin of Wyoming. About 45% of division
production is from CBM and 55% is from conventional oil and gas.
18
<PAGE> 19
CBM is natural gas produced from shallow coal formations. Devon is a
leader in CBM production with four projects under various stages of development
in the Rocky Mountains. Devon first produced CBM from the San Juan Basin of
northwestern New Mexico in 1986, and the San Juan Basin remains today an
important producing area for the company. Devon began development of its CBM
acreage in the Powder River Basin of northeast Wyoming in 1998. Devon owns
250,000 net acres there. Production at year-end 2000 was 60 million cubic feet
per day from some 600 producing wells. Production is expected to average 90 to
100 million cubic feet per day in 2001 and to grow steadily over the next few
years as another thousand or more wells are drilled and tied into the gas
gathering system.
Earlier in the development stage is the company's Vermejo Ranch CBM
project in the Raton Basin of northeastern New Mexico. Devon has mineral
interests in 280,000 gross acres in the basin. Devon's current 25% working
interest will increase to 50% as the project is developed. The company drilled
89 wells there in 2000 and expects to drill about 100 wells each year for the
next few years. Gross production at year-end 2000 of 20 million cubic feet per
day from 120 producing wells is now beginning to reach meaningful rates.
Although it is early in the life of the project to determine ultimate success,
net resource potential could reach one trillion cubic feet.
The Rocky Mountain Division's fourth CBM project is in its infancy.
Devon has acquired over 50,000 acres in the Wind River Basin that includes
multiple coal seams. Five test wells were drilled in 2000, and early results are
encouraging. Although CBM is the fastest growing resource in the Rocky Mountain
Division, conventional gas still accounts for more than half of the gas
produced. The Washakie Field in south central Wyoming is Devon's largest
conventional gas area. The Washakie contains multiple producing formations. With
200,000 net acres and some 400 potential drilling locations, Devon expects to be
actively developing the Washakie for many years.
GULF DIVISION
Devon is one of the 10 largest oil and gas producers in the offshore
Gulf of Mexico. The Santa Fe Snyder merger nearly doubled Devon's asset base in
the Gulf. The offshore Gulf is a prolific producing area that provides
approximately 25% of the natural gas produced in the United States. The Gulf is
comprised of two major operating areas, as defined by water depth. The shallow
area, in water depths up to 600 feet, is known as the "shelf." Devon has a
substantial infrastructure of platforms and production facilities on the shelf,
where natural gas wells are known for providing high initial flow rates and
quick investment returns. Devon holds approximately 650,000 net acres on the
shelf, about 50% of which is developed.
Devon's shelf strategy emphasizes exploitation. Exploitation is drilling
for new reserves close to existing producing facilities. Exploitation success
has been greatly enhanced on the shelf through application of technological
advancements in seismic and drilling methods. We are especially optimistic about
four-component, or "4C" seismic. This technology improves the resolution of
seismic images below shallow gas deposits or "gas clouds." Devon is also
employing horizontal drilling on the shelf to economically penetrate relatively
thin sections of shallow gas deposits.
19
<PAGE> 20
The company had two notable offshore exploration discoveries in 2000.
These were on Eugene Island block 156, offshore Louisiana, and High Island
A-582, offshore Texas. Eugene Island 156 (100% working interest) began producing
in October at over 50 million cubic feet of gas and 1,600 barrels of liquids per
day from two wells. High Island A-582 (37% working interest) was a December
discovery. This well appears to be a significant oil find. A second well was
drilling at year-end. First production is expected in 2002 after completion of a
new producing platform.
While the shelf is a very mature area, the deep water of the Gulf is
believed to hold some of the largest remaining undiscovered reserves in North
America. Devon holds about 400,000 net acres in the deep water, of which about
90% is unexplored. Because costs are much higher to explore in the deep water
than on the shelf, the company's strategy is to move cautiously into deep water
drilling. Devon expects to participate in three to four deep water exploratory
wells per year.
The Gulf Division also holds about 300,000 net acres onshore in south
Texas and south Louisiana. About 80% of that acreage is developed for oil and
gas production. Last year was a turnaround year for the Gulf Division onshore.
Most of the onshore acreage was acquired in Devon's merger with PennzEnergy in
1999. As PennzEnergy was focused elsewhere, this acreage had received little
attention in recent years. An active onshore drilling program in 2000 resulted
in 14 net wells. This year we will more than double that number to a planned 38
net wells. A notable discovery in 2000 was in the Patterson Field in south
Louisiana. Devon's Zenor A-16 (50% working interest) was tested at over 20
million cubic feet of natural gas per day.
CANADA
Devon's Canadian operations are conducted through Northstar Energy, our
subsidiary in Calgary, Alberta. On a stand-alone basis, Devon's Canadian
operations would rank twelfth among Canadian independent producers. The Western
Canadian Sedimentary Basin is a vast geologic feature encompassing portions of
British Columbia, Alberta, Saskatchewan and Manitoba. Devon's properties in
Canada range from shallow oil and natural gas production in northern Alberta to
deep, long-lived gas reservoirs in the Foothills area near the Alberta/British
Columbia border. Over a third of Devon's Canadian oil and gas reserves are
located in the shallow gas areas of northern Alberta. Over 100 wells will be
drilled in these shallow gas fields in 2001. Devon has become very efficient at
drilling shallow gas wells in Alberta, and over the past three years we have cut
average drilling costs in half. In most of these shallow gas areas, drilling is
restricted to the winter months of December through March.
In addition to extensive exploitation and development drilling in the
shallow gas areas, the Canadian Division also has an aggressive exploration
program underway. The division has 2.2 million net undeveloped acres on which to
explore. The most exciting, high potential area for adding new gas reserves is
in the northern foothills of British Columbia and Alberta, where we hold 248,000
gross acres with an average working interest of 47%. We are currently drilling
two deep gas wells in the northern foothills following a significant gas
discovery on the Weejay prospect (49% working interest) in 1998. The Weejay
discovery, which produced over 20 million cubic feet of gas per day during
testing, will commence production in 2002.
20
<PAGE> 21
INTERNATIONAL
Approximately one quarter of Devon's proved reserves are located outside
North America. Most of these international reserves are concentrated in three
countries: Azerbaijan, Indonesia and Argentina. Approximately 37% of our proved
reserves outside North America are in Azerbaijan, located offshore in the
Caspian Sea. Devon has a 5.6% interest in the Azeri-Chirag-Gunashli (ACG) oil
field, including 0.8% acquired in February 2001. The ACG field is believed to
contain over 4 billion barrels of proved reserves, making it one of the largest
oil fields in the world.
Devon's international production is now predominantly oil. Natural gas
markets outside North America are not well developed. However, gas is expected
to become a growing part of Devon's international production mix in the coming
years. For example, in February 2001, Devon signed agreements to supply
Indonesian natural gas to Singapore from our extensive gas reserves on the
island of Sumatra. Singapore is replacing oil with cleaner burning natural gas
to fuel its growing power generation requirements. As other developing countries
make similar moves toward gas, worldwide gas markets will inevitably expand.
Devon is well positioned to supply gas to several of those developing markets.
Natural gas accounts for about two-thirds of Devon's reserves in
Argentina. Production growth is focused on the Neuquen Basin in the central part
of the country where Devon acquired a 100% working interest in the El Mangrullo
block early in 2000. Developing gas markets inside Argentina and in Chile and
Brazil are improving the economics of natural gas in South America. We believe
we can increase production from the El Mangrullo block by drilling additional
wells into the currently producing formation and also by producing gas from a
shallower formation that is productive in other parts of the Neuquen Basin.
Devon holds 12 million net acres of undeveloped lands in 14 different
countries outside North America. Much of this acreage was acquired in the merger
with Santa Fe Snyder. We hold substantial land positions offshore Ghana, Gabon
and Congo where we have active exploration programs underway. Through a joint
venture with another large U. S. independent, we will be conducting seismic
surveys and drilling exploratory wells on these blocks over the next few years.
In addition to the exploration program in west Africa, the company plans to
drill exploratory wells in Egypt, China, Malaysia and Brazil in 2001 and 2002.
21
<PAGE> 22
SIGNIFICANT PROPERTIES
The following table sets forth proved reserve information on the most
significant geographic areas in which Devon's properties are located as of
December 31, 2000.
<TABLE>
<CAPTION>
10% PRESENT
VALUE (3) 10% PRESENT
OIL(MBbls) GAS(MMcf) NGL(MBbls) MBoe(1) MBoe %(2) ($000) VALUE%(4)
-------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
PERMIAN/MID-CONTINENT DIVISION
Permian Basin 120,162 318,295 19,786 192,997 17.6% $2,645,957 14.9%
Mid-Continent 12,417 503,723 19,489 115,860 10.6% 2,316,626 13.1%
-------- -------- -------- -------- -------- -------- --------
Total 132,579 822,018 39,275 308,857 28.2% 4,962,583 28.0%
-------- -------- -------- -------- -------- -------- --------
ROCKY MOUNTAIN DIVISION
Total 45,618 1,248,534 4,495 258,202 23.5% 4,796,594 27.0%
-------- -------- -------- -------- -------- -------- --------
GULF DIVISION
Offshore 43,207 360,206 398 103,639 9.4% 3,098,340 17.5%
Onshore 4,133 90,549 1,350 20,575 1.9% 539,027 3.0%
-------- -------- -------- -------- -------- -------- --------
Total 47,340 450,755 1,748 124,214 11.3% 3,637,367 20.5%
-------- -------- -------- -------- -------- -------- --------
TOTAL U.S. 225,537 2,521,307 45,518 691,273 63.0% 13,396,544 75.5%
-------- -------- -------- -------- -------- -------- --------
CANADA
Total 36,492 523,509 4,204 127,948 11.7% 2,935,656(5) 16.6%
-------- -------- -------- -------- -------- -------- --------
INTERNATIONAL DIVISION
Total 197,215 413,368 12,035 278,145 25.3% 1,404,843 7.9%
-------- -------- -------- -------- -------- -------- --------
Grand Total 459,244 3,458,184 61,757 1,097,366 100.0% $17,737,043 100.0%
======== ======== ======== ======== ======== ======== ========
</TABLE>
(1) Gas reserves are converted to MBoe at the rate of six MMcf of gas per MBbl
of oil, based upon the approximate relative energy content of natural gas
to oil, which rate is not necessarily indicative of the relationship of gas
to oil prices. The respective prices of gas and oil are affected by market
and other factors in addition to relative energy content.
(2) Percentage which MBoe for the basin or region bears to total MBoe for all
Proved Reserves.
(3) Determined in accordance with SEC guidelines, except that no effect is
given to future income taxes.
(4) Percentages which present value for the basin or region bears to total
present value for all Proved Reserves.
(5) Canadian dollars converted to U.S. dollars at the rate of $1 Canadian:
$0.6666 U.S.
TITLE TO PROPERTIES
Title to properties is subject to contractual arrangements customary in
the oil and gas industry, liens for current taxes not yet due and, in some
instances, other encumbrances. Devon believes that such burdens do not
materially detract from the value of such properties or from the respective
interests therein or materially interfere with their use in the operation of the
business.
As is customary in the industry in the case of undeveloped properties,
little investigation of record title is made at the time of acquisition (other
than a preliminary review of local records). Investigations, generally including
a title opinion of outside counsel, are made prior to the consummation of an
acquisition of producing properties and before commencement of drilling
operations on undeveloped properties.
ITEM 3. LEGAL PROCEEDINGS
Royalty Matters
More than 30 oil companies, including Devon, are involved in disputes in
which it is alleged that such companies and related parties underpaid royalty,
overriding royalty and working interests owners in connection with the
production of crude oil. The proceedings include suits in federal court in
Texas, Louisiana, Mississippi and Wyoming that have been consolidated into one
proceeding in
22
<PAGE> 23
Texas. To avoid expensive and protracted litigation, certain parties, including
Devon, have entered into a global settlement agreement which provides for a
settlement of all claims of all members of the settlement class. The court held
a fairness hearing and issued an Amended Final Judgment approving the settlement
on September 10, 1999. However, certain entities have appealed their objections
to the settlement.
Also, pending in federal court in Texas is a similar suit alleging
underpaid royalties to the United States in connection with natural gas and
natural gas liquids produced and sold from United States owned and/or controlled
lands. The claims were filed by private litigants against Devon and numerous
other producers, under the federal False Claims Act. The United States served
notice of its intent to intervene as to certain defendants, but not Devon. Devon
and certain other defendants are challenging the constitutionality of whether a
claim under the federal False Claims Act can be maintained absent government
intervention. Devon believes that it has acted reasonably and paid royalties in
good faith. Devon does not currently believe that it is subject to material
exposure in association with this litigation. As a result, Devon's monetary
exposure in this suit is not expected to be material.
Maersk Rig Contract
In December 1997, the working interest owner partner of Pennzoil
Venezuela Corporation, S.A. ("PVC"), a subsidiary of Devon as a result of the
PennzEnergy merger, entered into a contract with Maersk Jupiter Drilling, S.A.
("Maersk") for the provision of a rig for drilling services relative to the
anticipated drilling program associated with Devon's Block 70/80 in Lake
Maracaibo, Venezuela. The rig was assembled and delivered by Maersk to Lake
Maracaibo where it performed an abbreviated drilling program for both Blocks
68/79 and 70/80. It is currently stacked in Lake Maracaibo. The contract, which
expires October 1, 2001, provides for early termination, with a charge for such
termination which is currently estimated at $42,000 per day with certain
escalation factors for the balance of the term. As of December 31, 2000, Devon's
consolidated balance sheet included accrued liabilities, reflected in "Other
liabilities," for the expected cost to terminate/settle the contract. Devon does
not currently believe there is a reasonable possibility of incurring additional
material costs in excess of the liability recognized for such
termination/settlement of the contract.
Devon is involved in other various routine legal proceedings incidental
to its business. However, to Devon's knowledge, as of March 12, 2001, there were
no other material pending legal proceedings to which Devon is a party or to
which any of its property is subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
23
<PAGE> 24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET PRICE
Devon's common stock has been traded on the American Stock Exchange (the
"AMEX") since September 29, 1988. Prior to September 29, 1988, Devon's common
stock was privately held. Commencing on December 15, 1998, a new class of Devon
exchangeable shares began trading on The Toronto Stock Exchange ("TSE") under
the symbol NSX. These shares are essentially equivalent to Devon common stock.
However, because they are issued by Devon's wholly-owned subsidiary, Northstar,
they qualify as a domestic Canadian investment for Canadian institutional
shareholders. They are exchangeable at any time, on a one-for-one basis, for
common shares of Devon at the holder's option.
The following table sets forth the high and low sales prices for Devon
common stock and exchangeable shares as reported by the AMEX and TSE for the
periods indicated.
<TABLE>
<CAPTION>
American Stock Exchange The Toronto Stock Exchange
------------------------------- -------------------------------
Average Average
High Low Daily High Low Daily
(US$) (US$) Volume (CN$) (CN$) Volume
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
1999:
Quarter Ended March 31, 1999 31.75 20.13 233,954 48.00 30.40 4,240
Quarter Ended June 30, 1999 37.44 25.94 225,938 54.85 39.60 15,457
Quarter Ended September 30, 1999 44.94 33.00 624,356 65.75 51.30 11,650
Quarter Ended December 31, 1999 42.00 29.50 486,409 61.60 43.45 3,108
2000:
Quarter Ended March 31, 2000 48.56 31.38 376,279 69.50 45.65 20,854
Quarter Ended June 30, 2000 60.94 43.75 613,910 90.10 65.30 12,021
Quarter Ended September 30, 2000 62.56 42.56 998,008 92.45 62.90 16,038
Quarter Ended December 31, 2000 64.74 48.00 829,198 97.45 73.40 4,526
2001:
Quarter Ended March 31, 2001
(through March 12, 2001) 66.75 52.30 996,310 102.00 79.90 9,657
</TABLE>
DIVIDENDS
Devon commenced the payment of regular quarterly cash dividends on its
common stock on June 30, 1993, in the amount of $0.03 per share. Effective
December 31, 1996, Devon increased its quarterly dividend payment to $0.05 per
share. Devon anticipates continuing to pay regular quarterly dividends in the
foreseeable future. Dividends are also paid on the exchangeable shares at the
same rate and on the same dates as dividends paid on the common stock.
On March 13, 2001, there were 32,972 holders of record of Devon common
stock and 340 holders of record for the exchangeable shares.
24
<PAGE> 25
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information (not covered by the
independent auditors' reports) should be read in conjunction with "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations," and the consolidated financial statements and the notes thereto
included in "Item 8. Financial Statements and Supplementary Data." Note 2 to the
consolidated financial statements included in Item 8 of this report contains
information on the 2000 merger between Devon and Santa Fe Snyder, the 1999
mergers between Devon and PennzEnergy Company and between Santa Fe Energy
Resources, Inc. and Snyder Oil Corporation and the 1998 combination of Devon and
Northstar Energy Corporation ("Northstar"), as well as unaudited pro forma
financial data for the years 1999 and 1998.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C> <C>
OPERATING RESULTS
Oil sales $1,078,759 561,018 309,990 555,237 584,519
Gas sales 1,485,221 627,869 347,273 375,193 220,556
NGL sales 154,465 67,985 24,715 35,838 28,712
Other revenue 65,658 20,596 24,248 48,255 36,470
---------- ---------- ---------- ---------- ----------
Total revenues 2,784,103 1,277,468 706,226 1,014,523 870,257
---------- ---------- ---------- ---------- ----------
Lease operating expenses 440,780 298,807 226,561 263,907 259,009
Transportation costs 53,309 33,925 23,186 20,364 15,822
Production taxes 103,244 44,740 24,871 33,317 21,505
Depreciation, depletion and amortization
of property and equipment 693,340 406,375 243,144 285,708 192,107
Amortization of goodwill 41,332 16,111 -- -- --
General and administrative expenses 93,008 80,645 45,454 53,081 47,411
Expenses related to mergers 60,373 16,800 13,149 -- --
Interest expense 154,329 109,613 43,532 41,488 48,762
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt 2,408 (13,154) 16,104 5,860 199
Distributions on preferred securities of
subsidiary trust -- 6,884 9,717 9,717 4,753
Reduction of carrying value of oil and
gas properties -- 476,100 422,500 641,314 33,100
---------- ---------- ---------- ---------- ----------
Total costs and expenses 1,642,123 1,476,846 1,068,218 1,354,756 622,668
---------- ---------- ---------- ---------- ----------
Earnings (loss) before income taxes, minority
interest and extraordinary item 1,141,980 (199,378) (361,992) (340,233) 247,589
Income tax expense (benefit):
Current 130,793 23,056 (3,713) 35,757 30,534
Deferred 280,845 (72,490) (122,394) (162,499) 58,752
---------- ---------- ---------- ---------- ----------
Total 411,638 (49,434) (126,107) (126,742) 89,286
---------- ---------- ---------- ---------- ----------
Earnings (loss) before minority interest and
extraordinary item 730,342 (149,944) (235,885) (213,491) 158,303
Minority interest in Monterey Resources, Inc. -- -- -- (4,700) (1,300)
---------- ---------- ---------- ---------- ----------
Earnings (loss) before extraordinary item 730,342 (149,944) (235,885) (218,191) 157,003
Extraordinary loss -- (4,200) -- -- (6,000)
---------- ---------- ---------- ---------- ----------
Net earnings (loss) $ 730,342 (154,144) (235,885) (218,191) 151,003
========== ========== ========== ========== ==========
Net earnings (loss) applicable to common
shareholders $ 720,607 (157,795) (235,885) (230,191) 103,803
========== ========== ========== ========== ==========
Net earnings (loss) per share before
extraordinary loss:
Basic $ 5.66 (1.64) (3.32) (3.35) 2.08
Diluted $ 5.50 (1.64) (3.32) (3.35) 2.03
Net earnings (loss) per share after
extraordinary loss:
Basic $ 5.66 (1.68) (3.32) (3.35) 1.97
Diluted $ 5.50 (1.68) (3.32) (3.35) 1.92
Cash dividends per common share(1) $ 0.17 0.14 0.10 0.09 0.09
Weighted average common shares outstanding:
Basic 127,421 93,653 70,948 68,732 52,744
Diluted 131,730 99,313 76,932 75,366 55,553
Ratio of earnings to combined fixed charges
and preferred stock dividends(2) 7.31 N/A N/A N/A 3.90
</TABLE>
25
<PAGE> 26
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
(THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA
Total assets $6,860,478 6,096,360 1,930,537 1,965,386 2,241,890
Debentures exchangeable into shares of
Chevron Corporation common stock $ 760,313 760,313 -- -- --
Other long-term debt $1,288,523 1,656,208 735,871 427,037 361,500
Convertible preferred securities of
subsidiary trust $ -- -- 149,500 149,500 149,500
Stockholders' equity $3,277,604 2,521,320 749,763 1,006,546 1,159,772
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
(THOUSANDS, EXCEPT PER UNIT DATA)
CASH FLOW DATA
<S> <C> <C> <C> <C> <C>
Net cash provided by operating activities $1,619,032 532,328 334,471 530,156 393,448
Net cash used in investing activities $(1,173,401) (768,317) (607,260) (545,683) (471,351)
Net cash provided by (used in) financing
activities $ (389,571) 377,198 256,518 34,859 47,120
Modified EBITDA(3,5) $2,033,389 802,551 373,005 643,854 526,510
Cash margin(4,5) $1,748,267 662,998 323,469 556,892 442,461
PRODUCTION, PRICE AND OTHER DATA
Production:
Oil (MBbls) 42,561 31,756 25,628 32,565 33,180
Gas (MMcf) 426,146 304,203 198,051 186,239 123,286
NGL (MBbls) 7,400 5,111 3,054 2,842 2,055
MBoe(6) 120,985 87,568 61,691 66,447 55,783
Average prices:
Oil (Per Bbl) $ 25.35 17.67 12.10 17.05 17.62
Gas (Per Mcf) $ 3.49 2.06 1.75 2.01 1.79
NGL (Per Bbl) $ 20.87 13.30 8.09 12.61 13.97
Per Boe(6) $ 22.47 14.35 11.05 14.54 14.95
Costs per Boe (6):
Operating costs $ 4.94 4.31 4.45 4.78 5.31
Depreciation, depletion and amortization
of oil and gas properties $ 5.48 4.46 3.74 4.17 3.31
General and administrative expenses $ 0.77 0.92 0.74 0.80 0.85
</TABLE>
- --------------------------------------------
(1) Cash dividends per share are presented based on the combined amount of
dividends paid by Devon, Santa Fe Snyder and Northstar in each year. The
dividends per share are also based on the number of shares outstanding in
each year assuming the Santa Fe Snyder merger and the Northstar combination
had been consummated as of the beginning of the earliest year presented.
Santa Fe Snyder did not pay any dividends in any of the years presented.
Northstar did not pay any dividends in 1997, or in 1998 prior to the
closing of the Northstar combination. Also, Northstar's dividends paid in
1996 were at a rate per share that was different from the rate paid by
Devon in 1996. Because of these facts, the cash dividends per share
presented for 1996 through 2000 are not representative of the actual
amounts paid by Devon on an historical basis. For the years 2000, 1999,
1998, 1997 and 1996, Devon's historical cash dividends per share were
$0.20, $0.20, $0.20, $0.20 and $0.14, respectively.
(2) For purposes of calculating the ratio of earnings to combined fixed charges
and preferred stock dividends, (i) earnings consist of earnings before
income taxes, plus fixed charges; (ii) fixed charges consist of interest
expense, deferred effect of changes in foreign currency exchange rate on
long-term debt, distributions on preferred securities of subsidiary trust,
amortization of costs relating to indebtedness and the preferred securities
of subsidiary trust, and one-third of rental expense estimated to be
attributable to interest; and (iii) preferred stock dividends consist of
the amount of pre-tax earnings required to pay dividends on the outstanding
preferred stock. For the years 1999, 1998 and 1997, earnings were
insufficient to cover combined fixed charges and preferred stock dividends
by $205.3 million, $362.0 million and $346.0 million, respectively.
26
<PAGE> 27
(3) Modified EBITDA represents earnings before interest (including deferred
effect of changes in foreign currency exchange rate on subsidiary's
long-term debt, and distributions on preferred securities of subsidiary
trust), taxes, depreciation, depletion and amortization and reduction of
carrying value of oil and gas properties.
(4) "Cash margin" equals total revenues less cash expenses. Cash expenses are
all expenses other than the non-cash expenses of depreciation, depletion
and amortization, deferred effect of changes in foreign currency exchange
rate on subsidiary's long-term debt, reduction of carrying value of oil and
gas properties and deferred income tax expense. Cash margin measures the
net cash which is generated by a company's operations during a given
period, without regard to the period such cash is actually physically
received or spent by the company. This margin ignores the non-operational
effect on a company's "net cash provided by operating activities", as
measured by accounting principles generally accepted in the United States
of America, from a company's activities as an operator of oil and gas
wells. Such activities produce net increases or decreases in temporary cash
funds held by the operator which have no effect on net earnings of the
company.
(5) Modified EBITDA is presented because it is commonly accepted in the oil and
gas industry as a financial indicator of a company's ability to service or
incur debt. Cash margin is presented because it is commonly accepted in the
oil and gas industry as a financial indicator of a company's ability to
fund capital expenditures or service debt. Modified EBITDA and cash margin
are also presented because investors routinely request such information.
Management interprets the trends of modified EBITDA and cash margin in a
similar manner as trends in net earnings.
Modified EBITDA and cash margin should be used as supplements to, and not
as substitutes for, net earnings and net cash provided by operating
activities determined in accordance with accounting principles generally
accepted in the United States of America as measures of Devon's
profitability or liquidity. There may be operational or financial demands
and requirements that reduce management's discretion over the use of
modified EBITDA and cash margin. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations." Modified EBITDA and cash
margin may not be comparable to similarly titled measures used by other
companies.
(6) Gas volumes are converted to Boe or MBoe at the rate of six Mcf of gas per
barrel of oil, based upon the approximate relative energy content of
natural gas and oil, which rate is not necessarily indicative of the
relationship of oil and gas prices. The respective prices of oil, gas and
NGL are affected by market and other factors in addition to relative energy
content.
27
<PAGE> 28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis addresses changes in Devon's
financial condition and results of operations during the three year period of
1998 through 2000. Reference is made to "Item 6. Selected Financial Data" and
"Item 8. Financial Statements and Supplementary Data."
OVERVIEW
On May 25, 2000, Devon and Santa Fe Snyder Corporation announced their
intent to merge. The transaction closed on August 29, 2000. The merger with
Santa Fe Snyder was the largest transaction in Devon's history. As a result of
the transaction, Devon issued approximately 40.6 million shares of common stock
and assumed $730.9 million of long-term debt and $492.7 million of other
liabilities. The merger increased Devon's proved reserves by 386.3 million
barrels, or 58%, and the company's undeveloped leasehold by 16 million acres,
or 99%.
The merger with Santa Fe Snyder significantly expanded Devon's
operations. However, another significant contributing factor to Devon's growth
over the last three years was the company's 1999 acquisition of PennzEnergy
Company ("PennzEnergy"). The acquisition of PennzEnergy added 396 million Boe of
reserves, 13 million net acres of undeveloped leasehold and $3.2 billion of
assets to Devon's balance sheet. In exchange, Devon issued approximately 21.5
million shares of common stock and assumed $1.6 billion of long-term debt and
$0.7 billion of other liabilities. The merger was accounted for under the
purchase method of accounting for business combinations. Therefore, Devon's 1999
results do not include any effect of PennzEnergy's operations prior to August
17, 1999.
On December 10, 1998, Devon and Northstar Energy Corporation
("Northstar") completed their merger. The combination of Devon and Northstar
added 115 million Boe of proved reserves and 1.8 million undeveloped acres, all
in Canada. The Northstar combination was accounted for under the
pooling-of-interests method of accounting for business combinations.
Accordingly, Devon's results for 1998 and prior years include the results of
both Devon and Northstar as if the two had always been combined.
In addition to the mergers and acquisitions, Devon's exploration and
development efforts have also been significant contributors to Devon's growth.
In 1998 and 1999, before the merger with Santa Fe Snyder, Devon spent
approximately $0.5 billion in its exploration, drilling and development efforts.
These costs included drilling 1,233 wells, of which 1,137 were completed as
producers. In 2000, Devon and Santa Fe Snyder combined spent $0.9 billion in its
exploration, drilling and development efforts. These costs included drilling
1,328 wells, of which 1,261 were completed as producers.
Devon's merger with Santa Fe Snyder was accounted for under the
pooling-of-interests method of accounting for business combinations.
Accordingly, Devon's prior years' results have been restated to combine such
results with those of Santa Fe Snyder for all years presented. Thus, the
three-year comparisons of various production, revenue and expense items
presented later in this section are shown as if Devon and Santa Fe Snyder had
been combined for all such periods.
28
<PAGE> 29
Although this is consistent with the financial presentation of the merger, it
disguises the substantial changes in Devon's operations that have occurred as a
result of that transaction.
To present the effects that Devon's merger with Santa Fe Snyder, the
acquisition of PennzEnergy and Devon's drilling and development activities have
had on operations during the last three years, the following statistics have
been developed. This data assumes that Devon's merger with Santa Fe Snyder was
closed at the beginning of 2000, but that prior year results were not restated.
Thus, it compares Devon's 2000 results, including Santa Fe Snyder, to those of
1998 for Devon only, without Santa Fe Snyder. Such comparison yields the
following fluctuations:
- - Combined oil, gas and NGL production increased 85.0 million Boe, or 236%.
- - Average combined price of oil, gas and NGL increased by $11.68 per Boe, or
108%.
- - Total revenues increased $2.3 billion, or 599%.
- - Net cash provided by operating activities increased $1.4 billion, or 745%.
Cash margin increased $1.6 billion, or 853%.
- - Net earnings increased $790.6 million.
- - Earnings per share increased to $5.50 per diluted share from a loss of
$1.25 per diluted share in 1998.
During 2000, Devon marked its twelfth anniversary as a public company.
While Devon has consistently increased production over this twelve-year period,
volatility in oil and gas prices has resulted in considerable variability in
earnings and cash flows. Prices for oil, natural gas and NGL are determined
primarily by market conditions. Market conditions for these products have been,
and will continue to be, influenced by regional and world-wide economic growth,
weather and other factors that are beyond Devon's control. Devon's future
earnings and cash flows will continue to depend on market conditions.
Like all oil and gas production companies, Devon faces the challenge of
natural production decline. As initial pressures are depleted, oil and gas
production from a given well naturally decreases. Thus, an oil and gas
production company depletes part of its asset base with each unit of oil or gas
it produces. Historically, Devon has been able to overcome this natural decline
by adding, through drilling and acquisitions, more reserves than it produces.
Devon's future growth, if any, will depend on its ability to continue to add
reserves in excess of production.
Because oil and gas prices are influenced by many factors outside of its
control, Devon's management has focused its efforts on increasing oil and gas
reserves and production and controlling expenses. Over its twelve-year history
as a public company, Devon has been able to significantly reduce its operating
costs per unit of production. Devon's future earnings and cash flows are
dependent on its ability to continue to contain operating costs at levels that
allow for profitable production.
29
<PAGE> 30
RESULTS OF OPERATIONS
The following discussion of Devon's results of operations from 1998
through 2000 include the restated results of Devon for the 2000 merger with
Santa Fe Snyder and the 1998 combination with Northstar, both of which were
accounted for using the pooling-of-interests method.
Devon's total revenues have risen from $706.2 million in 1998 to $2.8
billion in 2000. In each of these three years, oil, gas and NGL sales accounted
for over 96% of total revenues.
Changes in oil, gas and NGL production, prices and revenues from 1998 to
2000 are shown in the following tables. (Unless otherwise stated, all dollar
amounts are expressed in U.S. dollars.)
<TABLE>
<CAPTION>
TOTAL
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
---------- ---------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
PRODUCTION
Oil (MBbls) ............................... 42,561 +34% 31,756 +24% 25,628
Gas (MMcf) ................................ 426,146 +40% 304,203 +54% 198,051
NGL (MBbls) ............................... 7,400 +45% 5,111 +67% 3,054
Oil, gas and NGL (MBoe) ................... 120,985 +38% 87,568 +42% 61,691
REVENUES
Per Unit of Production:
Oil (per Bbl) ........................... $ 25.35 +43% 17.67 +46% 12.10
Gas (per Mcf) ........................... $ 3.49 +69% 2.06 +18% 1.75
NGL (per Bbl) ........................... $ 20.87 +57% 13.30 +64% 8.09
Oil, gas and NGL (per Boe) .............. $ 22.47 +57% 14.35 +30% 11.05
Absolute:
Oil ..................................... $1,078,759 +92% 561,018 +81% 309,990
Gas ..................................... $1,485,221 +137% 627,869 +81% 347,273
NGL ..................................... $ 154,465 +127% 67,985 +175% 24,715
---------- ---------- ----------
Oil, gas and NGL ........................ $2,718,445 +116% 1,256,872 +84% 681,978
========== ========== ==========
</TABLE>
30
<PAGE> 31
<TABLE>
<CAPTION>
DOMESTIC
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
---------- ---------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
PRODUCTION
Oil (MBbls) ............................... 28,562 +60% 17,822 +45% 12,257
Gas (MMcf) ................................ 355,087 +61% 221,061 +82% 121,419
NGL (MBbls) ............................... 6,702 +52% 4,396 +78% 2,468
Oil, gas and NGL (MBoe) ................... 94,445 +60% 59,062 +69% 34,962
REVENUES
Per Unit of Production:
Oil (per Bbl) ........................... $ 25.45 +37% 18.64 +50% 12.43
Gas (per Mcf) ........................... $ 3.67 +62% 2.27 +12% 2.02
NGL (per Bbl) ........................... $ 20.30 +55% 13.11 +63% 8.05
Oil, gas and NGL (per Boe) .............. $ 22.95 +52% 15.10 +26% 11.94
Absolute:
Oil ..................................... $ 726,897 +119% 332,219 +118% 152,297
Gas ..................................... $1,304,626 +160% 501,841 +105% 245,145
NGL ..................................... $ 136,048 +136% 57,610 +190% 19,871
---------- ---------- ----------
Oil, gas and NGL ........................ $2,167,571 +143% 891,670 +114% 417,313
========== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
CANADA
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
---------- ---------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
PRODUCTION
Oil (MBbls) ............................... 4,760 -8% 5,178 -17% 6,257
Gas (MMcf) ................................ 62,284 -15% 73,561 +10% 67,158
NGL (MBbls) ............................... 682 -3% 700 +24% 566
Oil, gas and NGL (MBoe) ................... 15,823 -13% 18,138 +1% 18,016
REVENUES
Per Unit of Production:
Oil (per Bbl) ........................... $ 24.46 +58% 15.51 +29% 12.07
Gas (per Mcf) ........................... $ 2.71 +75% 1.55 +16% 1.34
NGL (per Bbl) ........................... $ 26.51 +84% 14.39 +75% 8.20
Oil, gas and NGL (per Boe) .............. $ 19.18 +70% 11.27 +20% 9.43
Absolute:
Oil ..................................... $ 116,427 +45% 80,298 +6% 75,493
Gas ..................................... $ 169,032 +48% 114,128 +27% 89,828
NGL ..................................... $ 18,078 +79% 10,075 +117% 4,644
---------- ---------- ----------
Oil, gas and NGL ........................ $ 303,537 +48% 204,501 +20% 169,965
========== ========== ==========
</TABLE>
31
<PAGE> 32
<TABLE>
<CAPTION>
INTERNATIONAL
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
---------- ---------- ---------- ---------- ----------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
PRODUCTION
Oil (MBbls) ............................... 9,239 +6% 8,756 +23% 7,114
Gas (MMcf) ................................ 8,775 -8% 9,581 +1% 9,474
NGL (MBbls) ............................... 16 +7% 15 -25% 20
Oil, gas and NGL (MBoe) ................... 10,717 +3% 10,368 +19% 8,713
REVENUES
Per Unit of Production:
Oil (per Bbl) ........................... $ 25.48 +50% 16.96 +47% 11.55
Gas (per Mcf) ........................... $ 1.32 +6% 1.24 -5% 1.30
NGL (per Bbl) ........................... $ 21.19 +6% 20.00 +100% 10.00
Oil, gas and NGL (per Boe) .............. $ 23.08 +49% 15.50 +43% 10.87
Absolute:
Oil ..................................... $ 235,435 +59% 148,501 +81% 82,200
Gas ..................................... $ 11,563 -3% 11,900 -3% 12,300
NGL ..................................... $ 339 +13% 300 +50% 200
---------- ---------- ----------
Oil, gas and NGL ........................ $ 247,337 +54% 160,701 +70% 94,700
========== ========== ==========
</TABLE>
OIL REVENUES 2000 vs. 1999 Oil revenues increased $517.7 million in
2000. Oil revenues increased $326.8 million due to a $7.68 per barrel increase
in the average price of oil in 2000. An increase in 2000's production of 10.8
million barrels caused oil revenues to increase by $190.9 million. The
PennzEnergy merger accounted for 6.8 million barrels of the 10.8 million barrel
increase in production. The 2000 period included twelve months of production
from the properties acquired in the 1999 PennzEnergy merger, while the 1999
period only included production for 4 1/2 months following the August 17, 1999
merger closing. Additionally, drilling activity and less significant
acquisitions, offset in part by property dispositions and natural declines,
caused a 4.0 million barrel increase in production.
1999 vs. 1998 Oil revenues increased $251.0 million in 1999. Oil
revenues increased $176.9 million due to a $5.57 per barrel increase in the
average price of oil in 1999. An increase in 1999's production of 6.1 million
barrels caused oil revenues to increase by $74.1 million. The August 1999
PennzEnergy merger added 5.3 million barrels of production during the last 4 1/2
months of 1999, and the Snyder merger added 1.1 million barrels of production
during the last eight months of 1999. This increase was partially offset by a
0.3 million barrel decline in 1999 production from Devon's other properties.
GAS REVENUES 2000 vs. 1999 Gas revenues increased $857.4 million in
2000. A 121.9 Bcf increase in production in 2000 added $251.7 million of gas
revenues compared to 1999. A $1.43 per Mcf increase in the average gas price in
2000 contributed $605.7 million of the increase in gas revenues. The PennzEnergy
merger accounted for 89.3 Bcf of the 121.9 Bcf increase in consolidated
production.
32
<PAGE> 33
All of the 89.3 Bcf added by the PennzEnergy merger was attributable to
domestic properties. Production from Devon's other domestic properties increased
44.7 Bcf, due primarily to additional development and acquisitions, net of
natural declines and dispositions.
Canadian gas production decreased 11.3 Bcf, or 15%, in 2000. Natural
decline, increased royalty rates and dispositions of certain properties were the
primary reasons for the production decline. Whereas domestic royalty rates are
fixed percentages, the Canadian royalties are based on a sliding scale. As
prices increased in 2000, the Canadian government's royalty percentage also
increased, causing Devon's net production to decrease. Gross Canadian gas
production, before royalties, was 83.4 Bcf in 2000 compared to 92.1 Bcf in 1999.
1999 vs. 1998 Gas revenues increased $280.6 million in 1999. A 106.2 Bcf
increase in production in 1999 added $186.1 million of gas revenues compared to
1998. A $0.31 per Mcf increase in the average gas price in 1999 contributed
$94.5 million of the increase in gas revenues. The production increase was
primarily related to the PennzEnergy and Snyder mergers. The PennzEnergy
properties added 55.5 Bcf of production during the 4 1/2 months following the
PennzEnergy merger. The Snyder properties added 36.9 Bcf of production during
the last eight months following the May 1999 Snyder merger. A 6.4 Bcf increase
in Devon's Canadian gas production also contributed to the increase in 1999 gas
production.
NGL REVENUES 2000 vs. 1999 NGL revenues increased $86.5 million in 2000.
An increase in 2000's average price of $7.57 per barrel caused NGL revenues to
increase $56.0 million. A production increase of 2.3 million barrels in 2000
caused revenues to increase $30.5 million. The 1999 PennzEnergy merger accounted
for 2.5 million barrels of increased NGL production in 2000. This increase was
partially offset by a 0.2 million barrel reduction in 2000 production from
Devon's other properties. This reduction was caused by property dispositions and
natural decline, offset in part by drilling activity and property acquisitions.
1999 vs. 1998 NGL revenues increased $43.3 million in 1999. An increase
in 1999's average price of $5.21 per barrel caused NGL revenues to increase
$26.6 million. A production increase of 2.1 million barrels in 1999 caused
revenues to increase $16.7 million. Production from the PennzEnergy properties
for the last 4 1/2 months of 1999 accounted for 1.7 million barrels of the 1999
increase.
OTHER REVENUES 2000 vs. 1999 Other revenues increased $45.1 million, or
219% in 2000. Increases in third party gas processing income and interest income
were the primary reasons for the substantial increase in other revenues.
Additionally, the 2000 period included $18.4 million of dividend income from the
7.1 million shares of Chevron Corporation common stock acquired in the 1999
PennzEnergy merger. The 1999 period included $6.7 million of dividend income on
these same shares.
1999 vs. 1998 Other revenues decreased $3.7 million in 1999. Other
revenues in 1998 included $8.8 million of one-time revenues recognized by
Northstar in 1998 from terminations of certain management agreements and gas
contracts, and $4.7 million of interest income from federal income tax audits
recognized by Santa Fe Snyder. In comparing 1999 to 1998, these nonrecurring
1998 revenues more than offset increases of $9.8 million in 1999 from other
sources of revenues, including dividend income, interest income and third-party
gas processing revenues.
33
<PAGE> 34
Other revenues in 1999 included $6.7 million of dividend income in the last 4
1/2 months of the year from the 7.1 million shares of Chevron Corporation common
stock.
EXPENSES The details of the changes in pre-tax expenses between 1998 and
2000 are shown in the table below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
--------- --------- --------- --------- ---------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Absolute:
Production and operating expenses:
Lease operating expenses .............................. $ 440,780 +48% 298,807 +32% 226,561
Transportation costs .................................. 53,309 +57% 33,925 +46% 23,186
Production taxes ...................................... 103,244 +131% 44,740 +80% 24,871
Depreciation, depletion and amortization of
oil and gas properties .............................. 662,890 +70% 390,117 +69% 230,419
Amortization of goodwill ................................ 41,332 +157% 16,111 N/M --
--------- --------- ---------
Subtotal ............................................ 1,301,555 +66% 783,700 +55% 505,037
Depreciation and amortization of non-oil and
gas properties ........................................ 30,450 +87% 16,258 +28% 12,725
General and administrative expenses ..................... 93,008 +15% 80,645 +77% 45,454
Expenses related to mergers ............................. 60,373 +259% 16,800 +28% 13,149
Interest expense ........................................ 154,329 +41% 109,613 +152% 43,532
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt ........ 2,408 N/M (13,154) N/M 16,104
Distributions on preferred securities of
subsidiary trust ...................................... -- -100% 6,884 -29% 9,717
Reduction of carrying value of oil and gas
properties ............................................ -- -100% 476,100 +13% 422,500
--------- --------- ---------
Total ............................................... $1,642,123 +11% 1,476,846 +38% 1,068,218
========= ========= =========
Per Boe:
Production and operating expenses:
Lease operating expenses .............................. $ 3.65 +7% 3.41 -7% 3.67
Transportation costs .................................. 0.44 +13% 0.39 +3% 0.38
Production taxes ...................................... 0.85 +67% 0.51 +28% 0.40
Depreciation, depletion and amortization of
oil and gas properties .............................. 5.48 +23% 4.46 +19% 3.74
Amortization of goodwill ................................ 0.34 +89% 0.18 N/M --
--------- --------- ---------
Subtotal ............................................ 10.76 +20% 8.95 +9% 8.19
Depreciation and amortization of non-oil and
gas properties(1) ..................................... 0.25 +32% 0.19 -10% 0.21
General and administrative expenses(1) .................. 0.77 -16% 0.92 +24% 0.74
Expenses related to prior mergers(1) .................... 0.50 +163% 0.19 -10% 0.21
Interest expense(1) ..................................... 1.27 +2% 1.25 +79% 0.70
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt(1) ..... 0.02 N/M (0.15) N/M 0.26
Distributions on preferred securities of
subsidiary trust(1) ................................... -- -100% 0.08 -50% 0.16
Reduction of carrying value of oil and gas
properties(1) ......................................... -- -100% 5.44 -21% 6.85
--------- --------- ---------
Total ................................................ $ 13.57 -20% 16.87 -3% 17.32
========= ========= =========
</TABLE>
(1) Though per Boe amounts for these expense items may be helpful for
profitability trend analysis, these expenses are not directly attributable
to production volumes.
N/M -- Not meaningful.
34
<PAGE> 35
PRODUCTION AND OPERATING EXPENSES The details of the changes in
production and operating expenses between 1998 and 2000 are shown in the table
below.
<TABLE>
<CAPTION>
TOTAL
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
--------- --------- --------- --------- ---------
(ABSOLUTE AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Absolute:
Recurring lease operating expenses ...................... $ 422,853 +45% 291,037 +33% 219,316
Well workover expenses .................................. 17,927 +131% 7,770 +7% 7,245
Transportation costs .................................... 53,309 +57% 33,925 +46% 23,186
Production taxes ........................................ 103,244 +131% 44,740 +80% 24,871
--------- --------- ---------
Total production and operating expenses .............. $ 597,333 +58% 377,472 +37% 274,618
========= ========= =========
Per Boe:
Recurring lease operating expenses ...................... $ 3.50 +5% 3.32 -7% 3.56
Well workover expenses .................................. 0.15 +67% 0.09 -18% 0.11
Transportation costs .................................... 0.44 +13% 0.39 +3% 0.38
Production taxes ........................................ 0.85 +67% 0.51 +28% 0.40
--------- --------- ---------
Total production and operating expenses .............. $ 4.94 +15% 4.31 -3% 4.45
========= ========= =========
</TABLE>
2000 vs. 1999 Recurring lease operating expenses increased $131.8
million, or 45%, in 2000. The 1999 PennzEnergy merger accounted for $92.4
million of the increase in expenses. Additionally, $11.0 million of costs were
added by the August 1999 and January 2000 acquisitions of certain properties and
$7.7 million of costs were added by the Snyder merger. Other than the added
costs from these acquisitions, Devon's recurring costs increased $20.7 million
in 2000. This increase was primarily caused by increased production and higher
ad valorem taxes and fuel costs.
Transportation costs represent those costs paid directly to third-party
providers to transport oil and gas production sold downstream from the wellhead.
Transportation costs increased $19.4 million, or 57% in 2000 primarily due to
increased production.
The majority of Devon's production taxes are assessed on its onshore
domestic properties. In the U.S., most of the production taxes are based on a
fixed percentage of revenues. Therefore, the 143% increase in domestic oil, gas
and NGL revenues was the primary cause of a 136% increase in domestic production
taxes. Production taxes did not increase proportionately to the increase in
revenues. This was primarily due to the addition in 1999 of oil and gas revenues
from offshore Gulf of Mexico properties acquired in the PennzEnergy merger.
Revenues generated from such offshore properties do not incur state production
taxes.
35
<PAGE> 36
1999 vs. 1998 Recurring lease operating expenses increased $71.7
million, or 33%, in 1999. The PennzEnergy properties added $57.3 million of
expenses in the last 4 1/2 months of the year, and the Snyder properties added
$17.7 million of expenses for the last eight months of the year. Other than the
added costs from the PennzEnergy and Snyder properties, recurring expenses on
Devon's other properties dropped $3.3 million in 1999. Efficiencies achieved in
certain of Devon's oil producing properties contributed a substantial portion of
this cost reduction.
Transportation costs increased $10.7 million, or 46% in 1999 primarily
due to increased production.
As previously stated, most of the U.S. production taxes are based on a
fixed percentage of revenues. Therefore, the 114% increase in domestic oil, gas
and NGL revenues was the primary cause of a 88% increase in domestic production
taxes.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") Devon's largest
recurring non-cash expense is DD&A. DD&A of oil and gas properties is calculated
as the percentage of total proved reserve volumes produced during the year,
multiplied by the net capitalized investment in those reserves including
estimated future development costs (the "depletable base"). Generally, if
reserve volumes are revised up or down, then the DD&A rate per unit of
production will change inversely. However, if the depletable base changes, then
the DD&A rate moves in the same direction. The per unit DD&A rate is not
affected by production volumes. Absolute or total DD&A, as opposed to the rate
per unit of production, generally moves in the same direction as production
volumes. Oil and gas property DD&A is calculated separately on a
country-by-country basis.
2000 vs. 1999 Oil and gas property related DD&A increased $272.8
million, or 70%, in 2000. Oil and gas property related DD&A increased $148.9
million due to the 38% increase in oil, gas and NGL production in 2000. Oil and
gas property related DD&A increased $123.9 million due to an increase in the
consolidated DD&A rate. The consolidated DD&A rate increased from $4.46 per Boe
in 1999 to $5.48 per Boe in 2000.
Non-oil and gas property DD&A increased $14.2 million in 2000 compared
to 1999. Depreciation of the non-oil and gas properties acquired in the
PennzEnergy and Snyder mergers and depreciation of Devon's new Wyoming gas
pipeline and gathering system, accounted for the increase in 2000's expense.
1999 vs. 1998 Oil and gas property related DD&A increased $159.7
million, or 69%, in 1999. Oil and gas property related DD&A increased $96.7
million due to the 42% increase in oil, gas and NGL production in 1999. Oil and
gas property related DD&A increased $63.0 million due to an increase in the
consolidated DD&A rate. The consolidated DD&A rate increased from $3.74 per Boe
in 1998 to $4.46 per Boe in 1999. The 1999 rate of $4.46 per Boe was a blended
rate of before and after the PennzEnergy and Snyder mergers.
Non-oil and gas property DD&A increased $3.5 million in 1999 compared to
1998. Depreciation of the non-oil and gas properties acquired in the PennzEnergy
and Snyder mergers and depreciation of Devon's new Wyoming gas pipeline and
gathering system, accounted for the increase in 1999's expense.
36
<PAGE> 37
AMORTIZATION OF GOODWILL In connection with the PennzEnergy merger,
Devon recorded $346.9 million of goodwill. The goodwill was allocated $299.5
million to domestic operations and $47.4 million to international operations.
The goodwill is being amortized using the units-of-production method.
Substantially all of the $41.3 million and $16.1 million of amortization
recognized in 2000 and 1999, respectively, was related to the domestic balance.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's net G&A consists of
three primary components. The largest of these components is the gross amount of
expenses incurred for personnel costs, office expenses, professional fees and
other G&A items. The gross amount of these expenses is partially reduced by two
offsetting components. One is the amount of G&A capitalized pursuant to the full
cost method of accounting. The other is the amount of G&A reimbursed by working
interest owners of properties for which Devon serves as the operator. These
reimbursements are received during both the drilling and operational stages of a
property's life. The gross amount of G&A incurred, less the amounts capitalized
and reimbursed, is recorded as net G&A in the consolidated statements of
operations. See the following table for a summary of G&A expenses by component.
<TABLE>
<CAPTION>
TOTAL
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
2000 1999
2000 vs 1999 1999 vs 1998 1998
---------- ---------- ---------- ----------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Gross G&A ............... $ 205,693 +37% 150,441 +57% 95,589
Capitalized G&A ......... (61,764) +114% (28,878) +95% (14,812)
Reimbursed G&A .......... (50,921) +24% (40,918) +16% (35,323)
---------- ---------- ----------
Net G&A ............. $ 93,008 +15% 80,645 +77% 45,454
========== ========== ==========
</TABLE>
2000 vs. 1999 Net G&A increased $12.4 million in 2000. Gross G&A
increased $55.3 million in 2000 compared to 1999. The increase in gross expenses
was primarily related to additional costs incurred as a result of the 1999
PennzEnergy and Snyder mergers. G&A was reduced $32.9 million in 2000 due to an
increase in the amount capitalized as part of oil and gas properties. G&A was
also reduced $10.0 million in 2000, by an increase in the amount of
reimbursements on operated properties in the 2000 period. The increase in
capitalized and reimbursed G&A was primarily related to the 1999 PennzEnergy and
Snyder mergers.
1999 vs. 1998 Net G&A increased $35.2 million in 1999. Gross G&A
increased $54.9 million in 1999. Included in the increase in gross expenses were
$36.7 million of expenses related to 4 1/2 months of the PennzEnergy operations.
G&A was lowered $14.1 million due to an increase in the amount capitalized as
part of oil and gas properties. The 1999 amount capitalized included $5.5
million related to the PennzEnergy operations for the last 4 1/2 months of the
year. G&A was also reduced by a $5.6 million increase in the amount of
reimbursements on operated properties. The 1999 reimbursements received from the
PennzEnergy properties were $6.0 million.
EXPENSES RELATED TO MERGERS Approximately $60.4 million of expenses were
incurred in 2000 in connection with the Santa Fe Snyder merger. These expenses
consisted primarily of severance and other benefit costs, investment banking
fees, other professional expenses, costs
37
<PAGE> 38
associated with duplicate facilities and various transaction related costs. The
pooling-of-interests method of accounting for business combinations requires
such costs to be expensed as opposed to capitalized as costs of the transaction.
Approximately $16.8 million of expenses were incurred by Santa Fe Snyder
in 1999 related to the Snyder merger. These costs included $14.4 million related
to compensation plans and other benefits, and $1.9 million of severance and
relocation costs. The $16.8 million of costs related to the operations and
employees of the former Santa Fe Energy Resources, Inc., not those of the former
Snyder Oil Corporation. Therefore, the costs were required to be expensed as
opposed to capitalized as part of the Snyder merger.
Approximately $13.1 million of expenses were incurred in 1998 in
connection with the Northstar combination. These expenses consisted primarily of
investment bankers' fees, legal fees and costs of printing and distributing the
proxy statement to shareholders.
INTEREST EXPENSE 2000 vs. 1999 Interest expense increased $44.7 million,
or 41%, in 2000. An increase in the average debt balance outstanding from $1.5
billion in 1999 to $2.3 billion in 2000 caused interest expense to increase by
$53.7 million. The increase in average debt outstanding in 2000 was attributable
to the long-term debt assumed in the Snyder and PennzEnergy mergers on May 5,
1999 and August 17, 1999, respectively. The average interest rate on outstanding
debt decreased from 7.0% in 1999 to 6.7% in 2000. This rate decrease caused
interest expense to decrease $4.7 million in 2000. Other items included in
interest expense that are not related to the debt balance outstanding, such as
facility and agency fees, amortization of costs and other miscellaneous items,
were $4.3 million lower in 2000 compared to 1999.
1999 vs. 1998 Interest expense increased $66.1 million in 1999. An
increase in the average debt balance outstanding from $588.3 million in 1998 to
$1.5 billion in 1999 caused interest expense to increase by $69.9 million. The
increase in average debt outstanding in 1999 was attributable to the long-term
debt assumed in the Snyder and PennzEnergy mergers on May 5, 1999 and August 17,
1999, respectively. The average interest rate on outstanding debt decreased from
7.3% in 1998 to 7.0% in 1999. This rate decrease caused interest expense to
decrease $4.9 million in 1999. Other items included in interest expense that are
not related to the debt balance outstanding, such as facility and agency fees,
amortization of costs and other miscellaneous items, were $1.1 million higher in
1999 compared to 1998.
DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON
SUBSIDIARY'S LONG-TERM DEBT 2000 vs. 1999 Until mid-January 2000, Devon's
Canadian subsidiary Northstar Energy Corporation had certain fixed-rate senior
notes which were denominated in U.S. dollars. Changes in the exchange rate
between the U.S. dollar and the Canadian dollar from the dates the notes were
issued to the dates of repayment increased or decreased the expected amount of
Canadian dollars eventually required to repay the notes. Such changes in the
Canadian dollar equivalent balance of the debt were required to be included in
determining net earnings for the period in which the exchange rate changed. In
mid-January 2000, the U.S. dollar denominated notes were retired prior to
maturity with cash on hand and borrowings under Devon's long-term credit
facilities. The Canadian-to-U.S. dollar exchange rate dropped slightly in
January prior to the debt retirement. As a result, $2.4 million of expense was
recognized in 2000.
38
<PAGE> 39
1999 vs. 1998 The rate of converting Canadian dollars to U.S. dollars
increased from $0.6535 at the end of 1998 to $0.6929 at the end of 1999. The
balance of Northstar's U.S. dollar denominated notes remained constant at $225
million throughout 1999. The higher conversion rate on the $225 million of debt
reduced the Canadian dollar equivalent of debt recorded by Northstar at the end
of 1999. Therefore, a $13.2 million reduction to expenses was recorded in 1999.
DISTRIBUTIONS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST As discussed
in Note 9 to the consolidated financial statements, Devon, through its affiliate
Devon Financing Trust, completed the issuance of $149.5 million of 6.5% Trust
Convertible Preferred Securities ("TCP Securities") in July 1996. The TCP
Securities had a maturity date of June 15, 2026. However, in October 1999, Devon
issued notice to the holders of the TCP Securities that it was exercising its
right to redeem such securities on November 30, 1999. Substantially all of the
holders of the TCP Securities elected to exercise their conversion rights
instead of receiving the redemption cash value. As a result, all but 950 of the
2.99 million units of TCP Securities were exchanged for shares of Devon common
stock. As a result, Devon issued approximately 4.9 million shares of common
stock for substantially all of the outstanding units of TCP Securities. The
redemption price for the 950 units redeemed was approximately $50,000.
2000 vs. 1999 There were no TCP Securities distributions in 2000
compared to $6.9 million in 1999. Substantially all of the TCP Securities were
exchanged for shares of Devon common stock on November 30, 1999.
1999 vs. 1998 The TCP Securities distributions in 1999 were $6.9 million
compared to $9.7 million in 1998. Substantially all of the TCP Securities were
exchanged for shares of Devon common stock on November 30, 1999. Therefore,
there was no fourth quarter 1999 distribution on the exchanged TCP Securities.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Under the
full-cost method of accounting, the net book value of oil and gas properties,
less related deferred income taxes, may not exceed a calculated "ceiling." The
ceiling limitation is the discounted estimated after-tax future net revenues
from proved oil and gas properties. The ceiling is imposed separately by
country. In calculating future net revenues, current prices and costs are
generally held constant indefinitely. The net book value, less deferred tax
liabilities, is compared to the ceiling on a quarterly and annual basis. Any
excess of the net book value, less deferred taxes, is written off as an expense.
Devon did not reduce the carrying value of its oil and gas properties in
2000. During 1999 and 1998, Devon reduced the carrying value of its oil and gas
properties by $476.1 million and $422.5 million, respectively, due to the
full-cost ceiling limitations. The after-tax effect of these reductions in 1999
and 1998 were $309.7 million and $280.8 million, respectively.
INCOME TAXES 2000 vs. 1999 Devon's 2000 financial tax expense rate was
36% of income before income tax expense. This rate was higher than the statutory
federal tax rate of 35% due to the effect of goodwill amortization that is not
deductible for income tax purposes and the effect of foreign income taxes,
offset in part by the recognition of a benefit from the disposition of Devon's
assets in Venezuela. The 1999 financial tax benefit rate was 25%. This rate was
lower than the
39
<PAGE> 40
statutory federal tax rate of 35% due to the effect of goodwill amortization
that is not deductible for income tax purposes and the effect of foreign income
taxes.
1999 vs. 1998 Devon's 1999 financial tax benefit rate was 25% of loss
before income tax benefit. This rate was lower than the statutory federal tax
rate of 35% due to the effect of goodwill amortization that is not deductible
for income tax purposes and the effect of foreign income taxes. The 1998
financial tax benefit rate was 35%.
CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY
The following discussion of capital expenditures, capital resources and
liquidity should be read in conjunction with the supplemental consolidated
statements of cash flows included elsewhere in this report.
CAPITAL EXPENDITURES Approximately $1.3 billion was spent in 2000 for
capital expenditures, of which $1.2 billion was related to the acquisition,
drilling or development of oil and gas properties. These amounts compare to 1999
total expenditures of $883.4 million ($784.9 million of which was related to oil
and gas properties) and 1998 total expenditures of $712.8 million ($704.6
million of which was related to oil and gas properties.)
OTHER CASH USES Devon's common stock dividends were $22.2 million, $12.7
million and $7.3 million in 2000, 1999 and 1998, respectively. Devon also paid
$9.7 million of preferred stock dividends in 2000 and $3.7 million in the last
4 1/2 months of 1999 following the PennzEnergy merger.
CAPITAL RESOURCES AND LIQUIDITY Net cash provided by operating
activities ("operating cash flow") has historically been the primary source of
Devon's capital and short-term liquidity. Operating cash flow was $1.6 billion,
$532.3 million and $334.5 million in 2000, 1999 and 1998, respectively. The
trends in operating cash flow during these periods have generally followed those
of the various revenue and expense items previously discussed.
In addition to operating cash flow, Devon's credit lines and the private
placement of long-term debt have been an important source of capital and
liquidity. In 2000 and 1999, debt repayments exceeded borrowings by $371.6
million and $144.7 million, respectively. During 1998, long-term debt borrowings
exceeded repayments by $264.2 million.
Prior to the August 2000 merger, Devon and Santa Fe Snyder each had
their own unsecured credit facilities. Devon's credit facilities prior to the
merger aggregated $750 million, with $475 million in a U.S. facility and $275
million in a Canadian facility. These Devon credit facilities were entered into
in October 1999. Santa Fe Snyder's credit facilities prior to the merger
aggregated $600 million.
Concurrent with the closing of the Santa Fe Snyder merger on August 29,
2000, Devon entered into new unsecured long-term credit facilities aggregating
$1 billion (the "Credit Facilities"). The Credit Facilities replaced the prior
separate facilities of Devon and Santa Fe Snyder. The Credit Facilities include
a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of
$275 million (the "Canadian Facility").
40
<PAGE> 41
The $725 million U.S. Facility consists of a Tranche A facility of $200
million and a Tranche B facility of $525 million. The Tranche B facility can be
increased to as high as $625 million and reduced to as low as $425 million by
reallocating the amount available between the Tranche B facility and the
Canadian Facility. The Tranche A facility matures on October 15, 2004. Devon may
borrow funds under the Tranche B facility until August 28, 2001 (the "Tranche B
Revolving Period"). Devon may request that the Tranche B Revolving Period be
extended an additional 364 days by notifying the agent bank of such request
between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt
borrowed under the Tranche B facility matures two years and one day following
the end of the Tranche B Revolving Period. As of December 31, 2000, Devon had no
borrowings under its U.S. Facility.
Devon may borrow funds under the $275 million Canadian Facility until
August 28, 2001 (the "Canadian Facility Revolving Period"). As disclosed in the
prior paragraph, the Canadian Facility can be increased to as high as $375
million and reduced to as low as $175 million by reallocating the amount
available between the Tranche B facility and the Canadian Facility. Devon may
request that the Canadian Facility Revolving Period be extended an additional
364 days by notifying the agent bank of such request between 45 and 90 days
prior to the end of the Canadian Facility Revolving Period. Debt outstanding as
of the end of the Canadian Facility Revolving Period is payable in semi-annual
installments of 2.5% each for the following five years, with the final
installment due five years and one day following the end of the Canadian
Facility Revolving Period. As of December 31, 2000, Devon had $146.7 million
borrowed under its Canadian Facility at a weighted average interest rate of
6.1%.
Amounts borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon may elect for periods up to six months. Such rates
are generally less than the prime rate, and are tied to margins determined by
Devon's corporate credit ratings. Devon may also elect to borrow at the prime
rate. The Credit Facilities provide for an annual facility fee of $0.9 million
that is payable quarterly.
On August 29, 2000, Devon entered into a commercial paper program. Total
borrowings under the U.S. credit facility and the commercial paper program may
not exceed $725 million. The commercial paper borrowings may have terms of up to
365 days and bear interest at rates agreed to at the time of the borrowing. The
interest rate will be based on a standard index such as the Federal Funds Rate,
London Interbank Offered Rate (LIBOR), or the money market rate as found on the
commercial paper market. As of December 31, 2000, Devon had no borrowings under
its commercial paper program.
In June 2000, Devon privately sold zero coupon convertible senior
debentures. The convertible debentures were sold at a price of $464.13 per
debenture with a yield to maturity of 3.875% per annum. Each of the 760,000
debentures is convertible into 5.7593 shares of Devon common stock. Devon may
call the debentures at any time after five years, and a debenture holder has the
right to require Devon to repurchase the debentures after five, 10 and 15 years,
at the issue price plus accrued original issue discount and interest. The
proceeds to Devon were approximately $346.1 million, net of debt issuance costs
of approximately $6.6 million. Devon used the proceeds from the sale of these
convertible debentures to pay down other domestic long-term debt.
41
<PAGE> 42
Another significant source of liquidity in 1999 was the $402 million
received from the sale of approximately 10.3 million shares of Devon's common
stock in a public offering. The proceeds were primarily used to retire $350
million of long-term debt in the fourth quarter of 1999. The retired debt, which
Devon assumed in the PennzEnergy merger, had an average interest rate of 10% per
year. Also, Santa Fe Snyder raised $108 million in 1999 from an equity offering
of its common stock following its merger with Snyder.
2001 ESTIMATES
The forward-looking statements provided in this discussion are based on
management's examination of historical operating trends, the information which
was used to prepare the December 31, 2000 reserve reports of independent
petroleum engineers and other data in Devon's possession or available from third
parties. Devon cautions that its future oil, natural gas and NGL production,
revenues and expenses are subject to all of the risks and uncertainties normally
incident to the exploration for and development and production and sale of oil
and gas. These risks include, but are not limited to, price volatility,
inflation, the lack of availability of goods and services, environmental risks,
drilling risks, regulatory changes, the uncertainty inherent in estimating
future oil and gas production or reserves, and other risks as outlined below.
Also, the financial results of Devon's foreign operations are subject to
currency exchange rate risks. Additional risks are discussed below in the
context of line items most affected by such risks.
SPECIFIC ASSUMPTIONS AND RISKS RELATED TO PRICE AND PRODUCTION ESTIMATES
Prices for oil, natural gas and NGL are determined primarily by prevailing
market conditions. Market conditions for these products are influenced by
regional and world-wide economic growth, weather and other substantially
variable factors. These factors are beyond Devon's control and are difficult to
predict. In addition to volatility in general, Devon's oil, gas and NGL prices
may vary considerably due to differences between regional markets,
transportation availability and demand for different grades of oil, gas and NGL.
Over 97% of Devon's revenues are attributable to sales of these three
commodities. Consequently, Devon's financial results and resources are highly
influenced by this price volatility.
Estimates for Devon's future production of oil, natural gas and NGL are
based on the assumption that market demand and prices for oil and gas will
continue at levels that allow for profitable production of these products. There
can be no assurance of such stability. Also, Devon's International production of
oil, natural gas and NGL is governed by payout agreements with the governments
of the countries in which Devon operates. If the payout under these agreements
is attained earlier than projected, Devon's net production and proved reserves
in such areas could be reduced.
The production, transportation and marketing of oil, natural gas and NGL
are complex processes which are subject to disruption due to transportation and
processing availability, mechanical failure, human error, meteorological events,
including, but not limited to, hurricanes, and numerous other factors. The
following forward-looking statements were prepared assuming demand, curtailment,
producibility and general market conditions for Devon's oil, natural gas and NGL
during 2001 will be substantially similar to those of 2000, unless otherwise
noted. Given the general limitations expressed herein, Devon's forward-looking
statements for 2001 are set forth below. Unless otherwise noted, all of the
following dollar amounts are expressed in U.S. dollars.
42
<PAGE> 43
Those amounts related to Canadian operations have been converted to U.S. dollars
using an exchange rate of $0.6695 U.S. dollar to $1.00 Canadian dollar. The
actual 2001 exchange rate may vary materially from this estimated rate. Such
variations could have a material effect on the following Canadian estimates.
GEOGRAPHIC REPORTING AREAS FOR 2001 The following estimates of
production, average price differentials and capital expenditures are provided
separately for each of Devon's geographic divisions. These divisions are as
follows:
- - the Gulf Division, which operates oil and gas properties located primarily
in the onshore South Texas and South Louisiana areas and offshore in the
Gulf of Mexico;
- - the Rocky Mountain Division, which operates oil and gas properties located
in the Rocky Mountains area of the United States stretching from the
Canadian border south into northern New Mexico;
- - the Permian/Mid-Continent Division, which operates all properties located
in the United States other than those operated by the Gulf Division and the
Rocky Mountain Division;
- - Canada; and
- - International Division, which encompasses all oil and gas properties that
lie outside of the United States and Canada.
YEAR 2001 POTENTIAL OPERATING ITEMS
OIL, GAS AND NGL PRODUCTION Set forth in the following paragraphs are
individual estimates of Devon's oil, gas and NGL production in 2001. On a
combined basis, Devon estimates its 2001 oil, gas and NGL production will total
between 120.4 million and 128.0 million barrels of oil equivalent. Devon's
estimates of 2001 production do not include certain oil, gas and NGL production
from various properties that were sold during 2000. These sold properties
produced approximately 2.9 million barrels of oil equivalent in 2000 that will
not be produced by Devon in 2001.
OIL PRODUCTION Devon expects its oil production in 2001 to total between
40.3 million barrels and 42.8 million barrels. The expected ranges of production
by division are as follows:
<TABLE>
<CAPTION>
Expected Range of
Production (MMBbls)
-------------------
<S> <C>
Permian/Mid-Continent 12.2 to 12.9
Gulf 10.1 to 10.8
Rocky Mountain 3.0 to 3.2
Canadian 5.3 to 5.6
International 9.7 to 10.3
</TABLE>
OIL PRICES -- FIXED Devon has fixed the price it will receive in 2001 on
a portion of its oil production through certain forward oil sales. Devon has
executed forward oil sales attributable to the Permian/Mid-Continent Division
for 3.7 million barrels at an average price of $16.84 per
43
<PAGE> 44
barrel. These fixed-price volumes represent 9% of Devon's expected consolidated
oil production in 2001. Santa Fe Snyder Corporation entered into these forward
oil sales agreements in late 1999 and early 2000, and used the proceeds to
acquire interests in producing properties in the Gulf of Mexico.
OIL PRICES -- FLOATING For the oil production for which prices have not
been fixed, Devon's 2001 average prices for each of its divisions are expected
to differ from the New York Mercantile Exchange price ("NYMEX") as set forth in
the following table. The NYMEX price is the monthly average of settled prices on
each trading day for West Texas Intermediate Crude oil delivered at Cushing,
Oklahoma.
<TABLE>
<CAPTION>
Expected Range of Oil Prices
Greater Than (Less Than) NYMEX
------------------------------
<S> <C>
Permian/Mid-Continent ($3.10) to ($2.10)
Gulf ($2.90) to ($1.90)
Rocky Mountain ($2.50) to ($1.50)
Canadian ($5.50) to ($4.50)
International ($3.65) to ($2.65)
</TABLE>
The above range of expected Canadian differentials compared to NYMEX
includes an estimated $0.11 per barrel decrease resulting from foreign currency
hedges. These hedges, in which Devon will sell $10 million in 2001 at an average
Canadian-to-U.S. exchange rate of $0.7102 and buy the same amount of dollars at
the floating exchange rate, offset a portion of the exposure to currency
fluctuations on those Canadian oil sales that are based on U.S. prices. The
$0.11 per barrel decrease is based on the assumption that the average
Canadian-to-U.S. conversion rate for the year 2001 is $0.6695.
GAS PRODUCTION Devon expects its 2001 gas production to total between
439 Bcf and 469 Bcf. The expected ranges of production by division are as
follows:
<TABLE>
<CAPTION>
Expected Range of
Production (Bcf)
----------------
<S> <C>
Permian/Mid-Continent 114 to 121
Gulf 144 to 153
Rocky Mountain 115 to 123
Canadian 58 to 62
International 8 to 10
</TABLE>
GAS PRICES -- FIXED Through various price swaps and fixed-price physical
delivery contracts, Devon has fixed the price it will receive in 2001 on a
portion of its natural gas production. The following tables include information
on this fixed-price production by division. Where necessary, the prices have
been adjusted for certain transportation costs that are netted against the price
recorded by Devon, and the price has also been adjusted for the Btu content of
the gas production that has been hedged.
<TABLE>
<CAPTION>
FIRST HALF OF 2001 SECOND HALF OF 2001
------------------------------- ----------------------------
DIVISION MCF/DAY PRICE/MCF MCF/DAY PRICE/MCF
-------- ------- --------- ------- ---------
<S> <C> <C> <C> <C>
Rocky Mountain 20,661 $1.90 57,955 $3.68
Gulf - $- 40,000 $5.45
Canada 60,011 $1.53 56,888 $1.52
</TABLE>
44
<PAGE> 45
Additionally, Devon has entered into a basis swap on 7.3 Bcf of 2001 gas
production. Under the terms of the basis swap, the counterparty pays Devon the
average NYMEX price for the last three trading days of each month, less $0.30
per Mcf. In return, Devon pays the counterparty the Colorado Interstate Gas Co.
("CIG") index price published by "Inside F.E.R.C.'s Gas Market Report" ("Inside
FERC"). The effect of this swap is included in Rocky Mountain Division gas
revenues. This basis swap does not qualify as a hedge under the provisions of
SFAS No. 133. Accordingly, fluctuations in the fair value of this basis swap
will be recorded in earnings beginning in the first quarter of 2001.
GAS PRICES -- FLOATING For the natural gas production for which prices
have not been fixed, Devon's 2001 average prices for each of its divisions are
expected to differ from NYMEX as set forth in the following table. NYMEX is
determined to be the first-of-month South Louisiana Henry Hub price index as
published monthly in "Inside FERC."
<TABLE>
<CAPTION>
Expected Range of Gas Prices
Greater Than (Less Than) NYMEX
------------------------------
<S> <C>
Permian/Mid-Continent ($0.40) to $0.10
Gulf ($0.15) to $0.35
Rocky Mountain ($0.90) to ($0.40)
Canadian ($0.85) to ($0.35)
International ($2.60) to ($2.10)
</TABLE>
Devon has also entered into a costless price collar that sets a floor
and ceiling price for 20,000 MMBtu/day of Rocky Mountain Division gas production
during the second half of 2001. The collar has a floor and ceiling price per
MMBtu of $4.10 and $8.00, respectively. The floor and ceiling prices are based
on the first-of-the-month CIG price index as published monthly by Inside FERC.
If the CIG index is outside of the ranges set by the floor and ceiling prices,
Devon and the counterparty to the collar will settle the difference. Any such
settlements will either increase or decrease Devon's gas revenues for the
period. Because Devon's gas volumes are often sold at prices that differ from
related regional indices, and due to differing Btu content of gas production,
the floor and ceiling prices of the collar do not reflect actual limits of
Devon's realized prices for the production volumes related to the collar.
NGL PRODUCTION Devon expects its 2001 production of NGL to total between
6.6 million barrels and 7.3 million barrels. The expected ranges of production
by division are as follows:
<TABLE>
<CAPTION>
Expected Range of
Production (MMBbls)
-------------------
<S> <C>
Permian/Mid-Continent 4.3 to 4.6
Gulf 1.0 to 1.1
Rocky Mountain 0.6 to 0.7
Canadian 0.5 to 0.6
International 0.2 to 0.3
</TABLE>
OTHER REVENUES Devon's other revenues in 2001 are expected to be between
$53 million and $59 million. This estimated range does not include the gain or
loss that could be recognized
45
<PAGE> 46
from changes in the fair values of Devon's derivatives that are not hedges.
Substantially all of Devon's derivatives are hedges, but the gas price basis
swap previously discussed and the option embedded in the debentures that are
exchangeable into shares of Chevron Corporation common stock are not hedges.
Accordingly, the changes in the fair value of these derivatives will be
recognized in Devon's operating results in 2001.
PRODUCTION AND OPERATING EXPENSES Devon's production and operating
expenses include lease operating expenses, transportation costs and production
taxes. These expenses vary in response to several factors. Among the most
significant of these factors are additions to or deletions from Devon's property
base, changes in production tax rates, changes in the general price level of
services and materials that are used in the operation of the properties and the
amount of repair and workover activity required. Oil, natural gas and NGL prices
also have an effect on lease operating expense and impact the economic
feasibility of planned workover projects.
These factors, coupled with uncertainty of future oil, natural gas and
NGL prices, increase the uncertainty inherent in estimating future production
and operating costs. Given these uncertainties, Devon estimates that year 2001
lease operating expense will be between $463 million and $492 million,
transportation costs will be between $62 million and $66 million and production
taxes will be between 4% and 5% of consolidated oil, natural gas and NGL
revenues.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2001 oil and gas
property DD&A rate will depend on various factors. Most notable among such
factors are the amount of proved reserves that will be added from drilling or
acquisition efforts in 2001 compared to the costs incurred for such efforts, and
the revisions to Devon's year-end 2000 reserve estimates that, based on prior
experience, are likely to be made during 2001.
In addition to oil and gas property related DD&A, Devon expects its 2001
DD&A expense related to non-oil and gas property fixed assets to total between
$30 million and $32 million. Based on this range and the production estimates
discussed earlier, Devon expects its 2001 consolidated DD&A rate to total
between $6.15 per Boe and $6.45 per Boe.
Devon also expects to record goodwill amortization in 2001 of between
$33 million and $35 million. The goodwill was recorded in connection with the
1999 merger with PennzEnergy.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's G&A includes the
costs of many different goods and services used in support of its business.
These goods and services are subject to general price level increases or
decreases. In addition, Devon's G&A varies with its level of activity and the
related staffing needs as well as with the amount of professional services
required during any given period. Should Devon's needs or the prices of the
required goods and services differ significantly from current expectations,
actual G&A could vary materially from the estimate. Given these limitations,
consolidated G&A in 2001 is expected to be between $89 million and $98 million.
46
<PAGE> 47
INTEREST EXPENSE Future interest rates and oil, natural gas and NGL
prices have a significant effect on Devon's interest expense. Approximately $1.9
billion of Devon's December 31, 2000, long-term debt balance of $2.0 billion
bears interest at fixed rates. Such fixed rates remove the uncertainty of future
interest rates from some, but not all, of Devon's long-term debt. Also, Devon
can only marginally influence the prices it will receive in 2001 from sales of
oil, natural gas and NGL and the resulting cash flow. These factors increase the
margin of error inherent in estimating future interest expense. Other factors
which affect interest expense, such as the amount and timing of capital
expenditures, are within Devon's control. Given the uncertainty of future
interest rates and commodity prices, and assuming that the fixed-rate debt
remains in place throughout the year, Devon estimates that the consolidated
interest expense in 2001 will be between $143 million and $146 million. Included
in this estimate is $12 million of discount accretion on the debentures that are
exchangeable into shares of Chevron Corporation common stock. The discount
accretion is the result of the adoption of SFAS 133 effective January 1, 2001.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES As of December 31,
2000, Devon does not expect to record a reduction in 2001 of its carrying value
of oil and natural gas properties under the full-cost accounting ceiling test.
At this time the ceiling for each full-cost pool exceeds Devon's carrying value
of oil and natural gas properties, less deferred income taxes. However, such
excess could be eliminated by declines in oil and/or natural gas prices between
now and the end of any quarter during 2001 or in subsequent periods.
INCOME TAXES Devon expects its consolidated financial income tax rate in
2001 to be between 35% and 45%. The current income tax rate is expected to be
between 20% and 25%. The deferred income tax rate is expected to be between 15%
and 20%. There are certain items that will have a fixed impact on 2001's income
tax expense regardless of the level of pre-tax earnings that are produced. These
items include Section 29 tax credits in the U.S., which reduce income taxes
based on production levels of certain properties and are not necessarily
affected by pre-tax financial earnings. The amount of Section 29 tax credits
expected to be generated to offset financial income tax expense in 2001 is
approximately $20 million. Also, Devon's Canadian subsidiaries are subject to
Canada's "large corporation tax" of approximately $3 million which is based on
total capitalization levels, not pre-tax earnings. The financial income tax in
2000 will also be increased by approximately $14 million due to the financial
amortization of certain costs, such as goodwill amortization, that are not
deductible for income tax purposes. Significant changes in estimated production
levels of oil, gas and NGL, the prices of such products, or any of the various
expense items could materially alter the effect of the aforementioned items on
2001's financial income tax rates.
YEAR 2001 POTENTIAL CAPITAL SOURCES, USES AND LIQUIDITY
CAPITAL EXPENDITURES Though Devon has completed several major property
acquisitions in recent years, these transactions are opportunity driven. Thus,
Devon does not "budget," nor can it reasonably predict, the timing or size of
such possible acquisitions, if any.
Devon's capital expenditures budget is based on an expected range of
future oil, natural gas and NGL prices as well as the expected costs of the
capital additions. Should Devon's price expectations for its future production
change significantly, some projects may be accelerated or deferred and,
consequently, may increase or decrease total 2001 capital expenditures. In
addition, if the actual costs of the budgeted items vary significantly from the
anticipated amounts, actual capital expenditures could vary materially from
Devon's estimates.
47
<PAGE> 48
Given the limitations discussed, the company expects its 2001 capital
expenditures for drilling and development efforts plus related facilities to
total between $1.05 billion and $1.15 billion. These amounts include between
$160 million and $180 million for drilling and facilities costs related to
reserves expected to be classified as proved as of year-end 2000. In addition,
these amounts include between $520 million and $560 million for other low
risk/reward projects and between $370 million and $410 million for new, higher
risk/reward projects. The following table shows expected drilling and facilities
expenditures by major operating division.
<TABLE>
<CAPTION>
DRILLING AND PRODUCTION FACILITIES EXPENDITURES (MILLIONS)
----------------------------------------------------------------------------------
PERMIAN/
ROCKY MID-
MOUNTAIN CONTINENT GULF OTHER
DIVISION DIVISION DIVISION CANADA INTERNATIONAL
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Related to Proved Reserves $45-$55 $70-$80 $0-$10 $10-$20 $20-$30
Lower Risk/Reward Projects $45-$55 $90-$100 $185-$215 $40-$50 $140-$170
Higher Risk/Reward Projects $20-$30 $40-$50 $110-$130 $105-$125 $80-$100
---------- ---------- ---------- ---------- ----------
Total $110-$140 $200-$230 $295-$355 $155-$195 $240-$300
========== ========== ========== ========== ==========
</TABLE>
In addition to the above expenditures for drilling and development,
Devon is participating through a joint venture in the construction of gas
transportation and processing systems in the Powder River Basin of Wyoming.
Devon expects to spend from $15 million to $20 million as its share of the
project in 2001. Devon also expects to capitalize between $70 million and $80
million of G&A expenses in accordance with the full-cost method of accounting.
Devon also expects to pay between $15 million and $20 million for plugging and
abandonment charges in 2001. Finally, Devon expects to spend between $15 million
and $20 million for non-oil and gas property fixed assets.
OTHER CASH USES Devon's management expects the policy of paying a
quarterly common stock dividend to continue. With the current $0.05 per share
quarterly dividend rate and 129 million shares of common stock outstanding, 2001
dividends are expected to approximate $26 million. Also, Devon has $150 million
of 6.49% cumulative preferred stock upon which it will pay $9.7 million of
dividends in 2001.
CAPITAL RESOURCES AND LIQUIDITY Devon's estimated 2001 cash uses,
including its drilling and development activities, are expected to be funded
primarily through a combination of working capital and operating cash flow, with
the remainder, if any, funded with borrowings from Devon's Credit Facilities.
The amount of operating cash flow to be generated during 2001 is uncertain due
to the factors affecting revenues and expenses as previously cited. However,
Devon expects its combined capital resources to be more than adequate to fund
its anticipated capital expenditures and other cash uses for 2001. As of
December 31, 2000, Devon had $853 million available under its $1 billion Credit
Facilities. If significant acquisitions or other unplanned capital requirements
arise during the year, Devon could utilize its existing Credit Facilities and/or
seek to establish and utilize other sources of financing.
48
<PAGE> 49
IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED In June
1998, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"), and in June 2000 issued SFAS 138, which amended
certain provisions of SFAS 133. SFAS 133, as amended, establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires
the recognition of all derivatives as either assets or liabilities in the
statement of financial position and measurement of those instruments at fair
value. If certain conditions are met, a derivative may be specifically
designated as a hedge. The accounting for changes in the fair value of a
derivative (that is gains and losses) depends on the intended use of the
derivative and whether it qualifies as a hedge. Devon adopted the provisions of
SFAS 133, as amended, in the first quarter of the year ending December 31, 2001.
In accordance with the transition provisions of SFAS 133, Devon recorded a
net-of-tax cumulative-effect-type adjustment of $36.6 million in accumulated
other comprehensive loss to recognize at fair value all derivatives that are
designated as cash-flow hedging financial instruments. Additionally, Devon
recorded a net-of-tax cumulative-effect-type adjustment to net earnings for a
$49.5 million gain related to the fair value of financial instruments that do
not qualify as hedges. This gain included $46.2 million related to the option
embedded in Devon's debentures that are exchangeable into shares of Chevron
Corporation common stock.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about Devon's potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in oil and gas prices, interest rates and foreign
currency exchange rates. The disclosures are not meant to be precise indicators
of expected future losses, but rather indicators of reasonably possible losses.
This forward-looking information provides indicators of how Devon views and
manages its ongoing market risk exposures. All of Devon's market risk sensitive
instruments were entered into for purposes other than trading.
COMMODITY PRICE RISK Devon's major market risk exposure is in the
pricing applicable to its oil and gas production. Realized pricing is primarily
driven by the prevailing worldwide price for crude oil and spot market prices
applicable to its U.S. and Canadian natural gas production. Pricing for oil and
gas production has been volatile and unpredictable for several years.
Devon periodically enters into financial hedging activities with respect
to a portion of its projected oil and natural gas production through various
financial transactions which hedge the future prices received. These
transactions include financial price swaps whereby Devon will receive a fixed
price for its production and pay a variable market price to the contract
counterparty and costless price collars that set a floor and ceiling price for
the hedged production. If the applicable monthly price indices are outside of
the ranges set by the floor and ceiling prices in the various collars, Devon and
the counterparty to the collars will settle the difference. These financial
hedging activities are intended to support oil and natural gas prices at
targeted levels and to manage Devon's exposure to oil and gas price
fluctuations. Realized gains or losses from the settlement of these financial
hedging instruments are recognized in oil and gas sales when the associated
production occurs. The gains and losses realized as a result of these hedging
activities are substantially offset in the cash market when the hedged commodity
is delivered. Devon does not hold or issue derivative instruments for trading
purposes.
49
<PAGE> 50
As of year-end 2000, Devon had certain financial gas price hedging
instruments in place. Subsequent to year-end 2000, Devon entered into additional
financial transactions which hedge the future prices to be received for some of
its natural gas production in 2001 and 2002. Devon's total hedged positions as
of January 29, 2001, are set forth below for each of Devon's operating
divisions.
PRICE SWAPS Through various price swaps, Devon has fixed the price it
will receive on a portion of its natural gas production in 2001 and 2002. The
following tables include information on this production by division. Where
necessary, the prices have been adjusted for certain transportation costs that
are netted against the price recorded by Devon, and the price has also been
adjusted for the Btu content of the gas production that has been hedged.
<TABLE>
<CAPTION>
FIRST HALF OF 2001 SECOND HALF OF 2001
---------------------------- ---------------------------
DIVISION MCF/DAY PRICE/MCF MCF/DAY PRICE/MCF
- -------- ------- --------- ------- ---------
<S> <C> <C> <C> <C>
Rocky Mountain 20,661 $1.90 57,955 $3.68
Gulf - $ - 40,000 $5.45
Canada 18,953 $1.68 17,404 $1.67
</TABLE>
<TABLE>
<CAPTION>
FIRST HALF OF 2002 SECOND HALF OF 2002
---------------------------- ---------------------------
DIVISION MCF/DAY PRICE/MCF MCF/DAY PRICE/MCF
- -------- ------- --------- ------- ---------
<S> <C> <C> <C> <C>
Rocky Mountain 26,395 $4.06 26,395 $4.06
Gulf 15,000 $4.62 15,000 $4.62
Canada 11,884 $1.73 6,294 $1.83
</TABLE>
COSTLESS PRICE COLLARS Devon has also entered into costless price
collars that set a floor and ceiling price for a portion of its 2001 and 2002
natural gas production. The following tables include information on these
collars for each division. The floor and ceiling prices related to domestic
production are based on various regional first-of-the-month price indices as
published monthly by "Inside F.E.R.C.'s Gas Market Report." The floor and
ceiling prices related to Canadian production are based on the AECO index as
published by the "Canadian Gas Price Reporter."
If the applicable monthly price indices are outside of the ranges set by
the floor and ceiling prices in the various collars, Devon and the counterparty
to the collars will settle the difference. Any such settlements will either
increase or decrease Devon's gas revenues for the period. Because Devon's gas
volumes are often sold at prices that differ from the related regional indices,
and due to differing Btu content of gas production, the floor and ceiling prices
of the various collars do not reflect actual limits of Devon's realized prices
for the production volumes related to the collars.
50
<PAGE> 51
<TABLE>
<CAPTION>
FIRST HALF OF 2001 SECOND HALF OF 2001
----------------------------------------------- --------------------------------------------
FLOOR PRICE CEILING PRICE FLOOR PRICE CEILING PRICE
DIVISION MMBTU/DAY PER MMBTU PER MMBTU MMBTU/DAY PER MMBTU PER MMBTU
- -------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Rocky Mountain - El Paso - $ - $ - 20,000 $ 4.10 $ 8.00
</TABLE>
<TABLE>
FIRST HALF OF 2002 SECOND HALF OF 2002
----------------------------------------------- --------------------------------------------
FLOOR PRICE CEILING PRICE FLOOR PRICE CEILING PRICE
DIVISION MMBTU/DAY PER MMBTU PER MMBTU MMBTU/DAY PER MMBTU PER MMBTU
- -------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Rocky Mountain - El Paso 25,000 $ 3.25 $ 7.85 25,000 $ 3.25 $ 7.85
Rocky Mountain -- CIG 80,000 $ 2.90 $ 6.75 80,000 $ 2.90 $ 6.75
Permian/Mid-Continent 81,800 $ 3.49 $ 7.25 81,800 $ 3.49 $ 7.25
Gulf 98,200 $ 3.49 $ 7.23 98,200 $ 3.49 $ 7.23
Canada 18,964 $ 3.27 $ 6.54 18,964 $ 3.27 $ 6.54
</TABLE>
BASIS SWAP Devon has entered into a basis swap on 20,000 MMBtu of gas
production per day that expires at the end of August 2004. Under the terms of
the basis swap, the counterparty pays Devon the average NYMEX price for the last
three trading days of each month, less $0.30, per MMBtu. In return, Devon pays
the counterparty the CIG index price published by Inside FERC. The effect of
this swap is included in Rocky Mountain Division gas revenues. This basis swap
does not qualify as a hedge under the provisions of SFAS No. 133. Accordingly,
fluctuations in the fair value of this basis swap will be recorded in earnings
beginning in the first quarter of 2001.
Devon uses a sensitivity analysis technique to evaluate the hypothetical
effect that changes in the market value of oil and gas may have on the fair
value of its commodity hedging instruments. At January 31, 2001, a 10% increase
in the underlying commodities' prices would have reduced the fair value of
Devon's commodity hedging instruments by $33.7 million.
FIXED-PRICE PHYSICAL DELIVERY CONTRACTS In addition to the commodity
hedging instruments described above, Devon also manages its exposure to oil and
gas price risks by periodically entering into fixed-price contracts.
Devon has fixed the price it will receive on a portion of its 2001 and
2002 oil production through certain forward oil sales. From January 2001 through
August 2002, 311,000 barrels of oil production per month have been fixed at an
average price of $16.84 per barrel. These fixed-price barrels are attributable
to the Permian/Mid-Continent Division.
For each of the years 2001 through 2006, Devon has fixed-price gas
contracts that cover approximately 15 Bcf, 12 Bcf, 8 Bcf, 8 Bcf, 8 Bcf and 8
Bcf, respectively, of Canadian production. Devon also has Canadian gas volumes
subject to fixed-price contracts in the years from 2007 through 2016, but the
yearly volumes are less than 6 Bcf.
INTEREST RATE RISK At December 31, 2000, Devon had long-term debt
outstanding of $2.0 billion. Of this amount, $1.9 billion, or 93%, bears
interest at fixed rates averaging 5.8%. The remaining $0.1 billion of debt
outstanding at the end of 2000 bears interest at floating rates which averaged
6.1% at the end of 2000.
51
<PAGE> 52
The terms of the Credit Facilities in place allow interest rates to be
fixed at Devon's option for periods of between 30 to 180 days. A 10% increase in
short-term interest rates on the floating-rate debt outstanding as of December
31, 2000, would equal approximately 61 basis points. Such an increase in
interest rates would increase Devon's 2001 interest expense by approximately
$0.9 million assuming borrowed amounts remain outstanding.
The above sensitivity analysis for interest rate risk excludes accounts
receivable, accounts payable and accrued liabilities because of the short-term
maturity of such instruments.
FOREIGN CURRENCY RISK Devon's net assets, net earnings and cash flows
from its Canadian subsidiaries are based on the U.S. dollar equivalent of such
amounts measured in the applicable functional currency. Assets and liabilities
of the Canadian subsidiaries are translated to U.S. dollars using the applicable
exchange rate as of the end of a reporting period. Revenues, expenses and cash
flow are translated using the average exchange rate during the reporting period.
Substantially all of Devon's Canadian oil sales are paid in Canadian
dollars, but at amounts based on the U.S. dollar price of oil. Therefore,
currency fluctuations between the Canadian and U.S. dollars impact the amount of
Canadian dollars received by Devon's Canadian subsidiaries for their oil
production. To mitigate the effect of volatility in the Canadian-to-U.S. dollar
exchange rate on Canadian oil revenues, Devon has existing foreign currency
exchange rate swaps. Under such swap agreements, in 2001 Devon will sell $10
million at an average Canadian-to-U.S. exchange rate of $0.7102 and buy the same
amount of dollars at the floating exchange rate. The amount of gains or losses
realized from such swaps are included as increases or decreases to realized oil
sales. At the year-end 2000 exchange rate, these swaps would result in decreases
to 2001's annual oil sales of approximately $0.6 million. A further $0.03
decrease in the Canadian-to-U.S. dollar exchange rate in 2001 would result in an
additional decrease in oil sales of approximately $0.4 million.
For purposes of the sensitivity analysis described above for changes in
the Canadian dollar exchange rate, a change in the rate of $0.03 was used as
opposed to a 10% change in the rate. During the last eight years, the
Canadian-to-U.S. dollar exchange rate has fluctuated an average of approximately
4% per year, and no year's fluctuation was greater than 7%. The $0.03 change
used in the above analysis represents an approximate 4% change in the year-end
2000 rate.
52
<PAGE> 53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
<TABLE>
<CAPTION>
Page
----
<S> <C>
Independent Auditors' Reports............................................. 54
Consolidated Financial Statements:
Consolidated Balance Sheets
December 31, 2000, 1999, and 1998................................... 57
Consolidated Statements of Operations
Years Ended December 31, 2000, 1999, and 1998....................... 58
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 2000, 1999, and 1998....................... 59
Consolidated Statements of Cash Flows
Years Ended December 31, 2000, 1999, and 1998....................... 60
Notes to Consolidated Financial Statements
December 31, 2000, 1999, and 1998................................... 61
</TABLE>
All financial statement schedules are omitted as they are inapplicable or the
required information has been included in the consolidated financial statements
or notes thereto.
53
<PAGE> 54
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Devon Energy
Corporation and subsidiaries (the Company) as of December 31, 2000, 1999 and
1998, and the related consolidated statements of operations, stockholders'
equity, and cash flows for each of the years then ended. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits. We did not audit the 1999 and 1998 financial
statements of Santa Fe Snyder Corporation, a wholly-owned subsidiary, which
statements reflect total assets constituting 24% and 38% in 1999 and 1998,
respectively, of the related consolidated totals, and which statements reflect
total revenues constituting 41% and 43% in 1999 and 1998, respectively, of the
related consolidated totals. We did not audit the 1998 financial statements of
Northstar Energy Corporation, a wholly-owned subsidiary, which statements
reflect total assets constituting 20% of the related consolidated 1998 total,
and which statements reflect total revenues constituting 22% in 1998 of the
related consolidated totals. The 1999 and 1998 financial statements of Santa Fe
Snyder Corporation and the 1998 financial statements of Northstar Energy
Corporation were audited by other auditors whose reports have been furnished to
us, and our opinion, insofar as it relates to the amounts included for Santa Fe
Snyder Corporation in 1999 and 1998, and Northstar Energy Corporation in 1998,
is based solely on the reports of the other auditors.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits and the reports of
the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, the
consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Devon Energy Corporation and
subsidiaries as of December 31, 2000, 1999 and 1998, and the results of their
operations and their cash flows for each of the years then ended, in conformity
with accounting principles generally accepted in the United States of America.
KPMG LLP
Oklahoma City, Oklahoma
January 30, 2001
54
<PAGE> 55
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
Santa Fe Snyder Corporation:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, comprehensive income, shareholders'
equity and of cash flows present fairly, in all material respects, the financial
position of Santa Fe Snyder Corporation and its subsidiaries at December 31,
1999 and 1998, and the results of their operations and their cash flows for each
of the two years in the period ended December 31, 1999 (not separately presented
herein) in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
the Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As further described in Note 2, these consolidated financial statements have
been retroactively restated to the full cost method of accounting for the
Company's oil and gas properties in order to conform to the accounting policies
of Devon Energy Corporation.
PricewaterhouseCoopers LLP
Houston, Texas
January 28, 2000, except for Note 2 and the second paragraph
above which are as of October 30, 2000
55
<PAGE> 56
AUDITORS' REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheet of Northstar Energy Corporation
(a wholly owned subsidiary of Devon Energy Corporation) as at December 31, 1998
and the related consolidated statements of operations and comprehensive income
(loss), stockholders' equity and cash flows for the year ended December 31, 1998
(not separately included herein). These consolidated financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audit.
We conducted our audit in accordance with Canadian generally accepted auditing
standards, which are substantially similar to generally accepted auditing
standards in the United States. Those standards require that we plan and perform
an audit to obtain reasonable assurance whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 1998,
and the results of its operations and the changes in its cash flow for the year
ended December 31, 1998 in accordance with generally accepted accounting
principles in the United States.
/s/ DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta
Canada
January 20, 1999
56
<PAGE> 57
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------------------
2000 1999 1998
----------- ----------- -----------
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 228,050 173,167 31,254
Accounts receivable 598,248 316,005 137,058
Inventories 47,272 38,941 21,750
Deferred income taxes 8,979 4,886 605
Investments and other current assets 51,588 57,295 35,981
----------- ----------- -----------
Total current assets 934,137 590,294 226,648
----------- ----------- -----------
Property and equipment, at cost, based on the full
cost method of accounting for oil and gas properties 9,709,352 8,592,010 4,854,211
Less accumulated depreciation, depletion and
amortization 4,799,816 4,168,590 3,230,683
----------- ----------- -----------
4,909,536 4,423,420 1,623,528
Investment in Chevron Corporation common stock,
at fair value 598,867 614,382 --
Deferred income taxes -- -- 54,381
Goodwill, net of amortization 289,489 322,800 --
Other assets 128,449 145,464 25,980
----------- ----------- -----------
Total assets $ 6,860,478 6,096,360 1,930,537
=========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade 320,713 266,825 155,377
Revenues and royalties due to others 116,481 67,330 20,608
Income taxes payable 65,674 12,587 1,200
Accrued interest payable 23,191 28,370 5,588
Merger related expenses payable 52,421 35,704 7,882
Accrued expenses 50,507 56,528 29,201
----------- ----------- -----------
Total current liabilities 628,987 467,344 219,856
----------- ----------- -----------
Other liabilities 164,469 241,782 71,947
Debentures exchangeable into shares of Chevron
Corporation common stock 760,313 760,313 --
Other long-term debt 1,288,523 1,656,208 735,871
Deferred revenue 113,756 104,800 3,600
Deferred income taxes 626,826 344,593 --
Company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trust holding
solely 6.5% convertible junior subordinated
debentures of Devon Energy Corporation -- -- 149,500
Stockholders' equity:
Preferred stock of $1.00 par value ($100
liquidation value) Authorized
4,500,000 shares; issued 1,500,000 in 2000 and
1999 and none in 1998 1,500 1,500 --
Common stock of $.10 par value
Authorized 400,000,000 shares; issued
128,638,000 in 2000,
126,323,000 in 1999 and 70,909,000 in 1998 12,864 12,632 7,090
Additional paid-in capital 3,563,994 3,491,828 1,523,944
Retained earnings (accumulated deficit) (214,708) (908,598) (737,009)
Accumulated other comprehensive loss (85,397) (65,242) (35,962)
Unamortized restricted stock awards (649) -- (1,500)
Treasury stock, at cost: 330,000 shares in 1999 and
176,000 shares in 1998 -- (10,800) (6,800)
----------- ----------- -----------
Total stockholders' equity 3,277,604 2,521,320 749,763
----------- ----------- -----------
Commitments and contingencies (Notes 12 and 13)
Total liabilities and stockholders' equity $ 6,860,478 6,096,360 1,930,537
=========== =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
57
<PAGE> 58
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2000 1999 1998
---------- ---------- ----------
<S> <C> <C> <C>
REVENUES
Oil sales $1,078,759 561,018 309,990
Gas sales 1,485,221 627,869 347,273
Natural gas liquids sales 154,465 67,985 24,715
Other 65,658 20,596 24,248
---------- ---------- ----------
Total revenues 2,784,103 1,277,468 706,226
---------- ---------- ----------
COSTS AND EXPENSES
Lease operating expenses 440,780 298,807 226,561
Transportation costs 53,309 33,925 23,186
Production taxes 103,244 44,740 24,871
Depreciation, depletion and amortization of property
and equipment 693,340 406,375 243,144
Amortization of goodwill 41,332 16,111 --
General and administrative expenses 93,008 80,645 45,454
Expenses related to mergers 60,373 16,800 13,149
Interest expense 154,329 109,613 43,532
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt 2,408 (13,154) 16,104
Distributions on preferred securities of
subsidiary trust -- 6,884 9,717
Reduction of carrying value of oil and gas properties -- 476,100 422,500
---------- ---------- ----------
Total costs and expenses 1,642,123 1,476,846 1,068,218
---------- ---------- ----------
Earnings (loss) before income tax expense (benefit)
and extraordinary item 1,141,980 (199,378) (361,992)
INCOME TAX EXPENSE (BENEFIT)
Current 130,793 23,056 (3,713)
Deferred 280,845 (72,490) (122,394)
---------- ---------- ----------
Total income tax expense (benefit) 411,638 (49,434) (126,107)
---------- ---------- ----------
Earnings (loss) before extraordinary item 730,342 (149,944) (235,885)
Extraordinary loss -- (4,200) --
---------- ---------- ----------
Net earnings (loss) 730,342 (154,144) (235,885)
Preferred stock dividends 9,735 3,651 --
---------- ---------- ----------
Net earnings (loss) applicable to common shareholders $ 720,607 (157,795) (235,885)
========== ========== ==========
Net earnings (loss) per average common share outstanding:
Before extraordinary loss:
Basic $ 5.66 (1.64) (3.32)
========== ========== ==========
Diluted $ 5.50 (1.64) (3.32)
========== ========== ==========
After extraordinary loss:
Basic $ 5.66 (1.68) (3.32)
========== ========== ==========
Diluted $ 5.50 (1.68) (3.32)
========== ========== ==========
Weighted average common shares outstanding:
Basic 127,421 93,653 70,948
========== ========== ==========
Diluted 131,730 99,313 76,932
========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
58
<PAGE> 59
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
ACCUMU-
RETAINED LATED
EARNINGS OTHER
PREFER- ADDITIONAL (ACCUMU- COMPRE-
RED COMMON PAID-IN LATED HENSIVE
STOCK STOCK CAPITAL DEFICIT) LOSS
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Balance as of December 31, 1997 $ -- 7,077 1,521,128 (493,246) (27,113)
Comprehensive loss:
Net loss -- -- -- (235,885) --
Other comprehensive loss, net of tax:
Foreign currency translation adjustments -- -- -- -- (8,130)
Minimum pension liability adjustment -- -- -- -- (719)
Other comprehensive loss -- -- -- -- --
Comprehensive loss
Stock issued -- 13 2,816 (600) --
Stock repurchased -- -- -- -- --
Dividends on common stock -- -- -- (7,278) --
Amortization of restricted stock awards -- -- -- -- --
---------- ---------- ---------- ---------- ----------
Balance as of December 31, 1998 -- 7,090 1,523,944 (737,009) (35,962)
Comprehensive loss:
Net loss -- -- -- (154,144) --
Other comprehensive loss, net of tax:
Foreign currency translation adjustments -- -- -- -- 7,517
Minimum pension liability adjustment -- -- -- -- (241)
Unrealized losses on marketable securities -- -- -- -- (36,556)
Other comprehensive loss -- -- -- -- --
Comprehensive loss
Stock issued 1,500 5,542 1,966,930 (1,100) --
Stock repurchased -- -- -- -- --
Tax benefit related to employee stock options -- -- 954 -- --
Dividends on common stock -- -- -- (12,694) --
Dividends on preferred stock -- -- -- (3,651) --
Amortization of restricted stock awards -- -- -- -- --
---------- ---------- ---------- ---------- ----------
Balance as of December 31, 1999 1,500 12,632 3,491,828 (908,598) (65,242)
Comprehensive income:
Net income -- -- -- 730,342 --
Other comprehensive loss, net of tax:
Foreign currency translation adjustments -- -- -- -- (10,213)
Minimum pension liability adjustment -- -- -- -- 822
Unrealized losses on marketable securities -- -- -- -- (10,764)
Other comprehensive loss -- -- -- -- --
Comprehensive income:
Stock issued -- 232 69,163 (4,497) --
Stock repurchased -- -- -- -- --
Tax benefit related to employee stock options -- -- 3,003 -- --
Dividends on common stock -- -- -- (22,220) --
Dividends on preferred stock -- -- -- (9,735) --
Grant of restricted stock awards -- -- -- -- --
Forfeiture of restricted stock awards -- -- -- -- --
Amortization of restricted stock awards -- -- -- -- --
---------- ---------- ---------- ---------- ----------
Balance as of December 31, 2000 $ 1,500 12,864 3,563,994 (214,708) (85,397)
========== ========== ========== ========== ==========
</TABLE>
<TABLE>
UNAMOR-
TIZED TOTAL
RESTRICTED STOCK-
STOCK TREASURY HOLDERS'
AWARDS STOCK EQUITY
---------- ---------- ----------
<S> <C> <C> <C>
Balance as of December 31, 1997 (700) (600) 1,006,546
Comprehensive loss:
Net loss -- -- (235,885)
Other comprehensive loss, net of tax:
Foreign currency translation adjustments -- -- (8,130)
Minimum pension liability adjustment -- -- (719)
----------
Other comprehensive loss -- -- (8,849)
----------
Comprehensive loss (244,734)
Stock issued (2,600) 5,400 5,029
Stock repurchased -- (11,600) (11,600)
Dividends on common stock -- -- (7,278)
Amortization of restricted stock awards 1,800 -- 1,800
---------- ---------- ----------
Balance as of December 31, 1998 (1,500) (6,800) 749,763
Comprehensive loss:
Net loss -- -- (154,144)
Other comprehensive loss, net of tax:
Foreign currency translation adjustments -- -- 7,517
Minimum pension liability adjustment -- -- (241)
Unrealized losses on marketable securities -- -- (36,556)
---------- ---------- ----------
Other comprehensive loss -- -- (29,280)
---------- ---------- ----------
Comprehensive loss (183,424)
Stock issued (100) 7,600 1,980,372
Stock repurchased -- (11,600) (11,600)
Tax benefit related to employee stock options -- -- 954
Dividends on common stock -- -- (12,694)
Dividends on preferred stock -- -- (3,651)
Amortization of restricted stock awards 1,600 -- 1,600
---------- ---------- ----------
Balance as of December 31, 1999 -- (10,800) 2,521,320
Comprehensive income:
Net income -- -- 730,342
Other comprehensive loss, net of tax:
Foreign currency translation adjustments -- -- (10,213)
Minimum pension liability adjustment -- -- 822
Unrealized losses on marketable securities -- -- (10,764)
---------- ---------- ----------
Other comprehensive loss -- -- (20,155)
---------- ---------- ----------
Comprehensive income: 710,187
Stock issued -- 21,499 86,397
Stock repurchased (10,699) (10,699)
Tax benefit related to employee stock options -- -- 3,003
Dividends on common stock -- -- (22,220)
Dividends on preferred stock -- -- (9,735)
Grant of restricted stock awards (5,217) -- (5,217)
Forfeiture of restricted stock awards 129 -- 129
Amortization of restricted stock awards 4,439 -- 4,439
---------- ---------- ----------
Balance as of December 31, 2000 (649) -- 3,277,604
========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
59
<PAGE> 60
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
2000 1999 1998
---------- ---------- ----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings (loss) $ 730,342 (154,144) (235,885)
Adjustments to reconcile net earnings (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization of property
and equipment 693,340 406,375 243,144
Amortization of goodwill 41,332 16,111 --
Accretion of interest on zero-coupon convertible senior debentures 6,950 -- --
Amortization of (premiums) discounts on other long-term debt, net (3,781) (728) 100
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt 2,408 (13,154) 16,104
Reduction of carrying value of oil and gas properties -- 476,100 422,500
(Gain) loss on sale of assets (683) 4,778 (264)
Deferred income tax expense (benefit) 280,845 (72,490) (122,394)
Other 3,849 2,100 4,801
Changes in assets and liabilities, net of effects of acquisitions of
businesses:
(Increase) decrease in:
Accounts receivable (283,787) (92,416) 30,760
Inventories (8,322) (8,514) (1,427)
Prepaid expenses 5,825 (4,418) (7,751)
Other assets 3,812 (36,673) 17,230
Increase (decrease) in:
Accounts payable 98,912 (22,495) (19,439)
Income taxes payable 60,548 (19,318) (10,426)
Accrued expenses 3,104 (38,387) 1,000
Deferred revenue 7,954 90,700 (100)
Long-term other liabilities (23,616) (1,099) (3,482)
---------- ---------- ----------
Net cash provided by operating activities 1,619,032 532,328 334,471
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property and equipment 101,531 114,384 64,997
Proceeds from sale of investments 12,781 -- 42,584
Capital expenditures (1,280,132) (883,420) (712,812)
(Increase) decrease in other assets (7,581) 719 (2,029)
---------- ---------- ----------
Net cash used in investing activities (1,173,401) (768,317) (607,260)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings of long-term debt, net of issuance costs 2,580,086 1,944,417 1,506,220
Principal payments on long-term debt (2,951,711) (2,089,109) (1,242,013)
Issuance of common stock, net of issuance costs 51,550 530,232 4,429
Retirement of preferred securities of subsidiary trust -- (50) --
Repurchase of common stock (10,699) (11,600) (11,600)
Issuance of treasury stock 24,937 6,200 --
Dividends paid on common stock (22,220) (12,694) (7,278)
Dividends paid on preferred stock (9,735) (3,651) --
(Decrease) increase in long-term other liabilities (51,779) 13,453 6,760
---------- ---------- ----------
Net cash (used in) provided by financing activities (389,571) 377,198 256,518
---------- ---------- ----------
Effect of exchange rate changes on cash (1,177) 704 (140)
---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents 54,883 141,913 (16,411)
Cash and cash equivalents at beginning of year 173,167 31,254 47,665
---------- ---------- ----------
Cash and cash equivalents at end of year $ 228,050 173,167 31,254
========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
60
<PAGE> 61
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by Devon Energy Corporation and subsidiaries
("Devon") reflect industry practices and conform to accounting principles
generally accepted in the United States of America. The more significant of such
policies are briefly discussed below.
Basis of Presentation and Principles of Consolidation
Devon is engaged primarily in oil and gas exploration, development and
production, and the acquisition of producing properties. Such activities
domestically are managed in three divisions:
- the Gulf Division, which includes properties located primarily
in the onshore South Texas and South Louisiana areas and
offshore in the Gulf of Mexico;
- the Rocky Mountain Division, which includes properties located
in the Rocky Mountains area of the United States stretching from
the Canadian Border into northern New Mexico; and
- the Permian/Mid-Continent Division, which includes all domestic
properties other than those included in the Gulf Division and
the Rocky Mountain Division.
Devon's Canadian activities are located primarily in the Western
Canadian Sedimentary Basin, and Devon's international activities -- outside of
North America -- are located primarily in Argentina, Azerbaijan, Indonesia and
Gabon. Devon's share of the assets, liabilities, revenues and expenses of
affiliated partnerships and the accounts of its wholly-owned subsidiaries are
included in the accompanying consolidated financial statements. All significant
intercompany accounts and transactions have been eliminated in consolidation.
Information concerning common stock and per share data assumes the
exchange of all Exchangeable Shares issued in connection with the Northstar
combination described in Note 2.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual amounts could differ from those
estimates.
Inventories
Inventories, which consist primarily of injected gas and tubular goods,
parts and supplies, are stated at cost, determined principally by the average
cost method, which is not in excess of net realizable value.
61
<PAGE> 62
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas
properties. Accordingly, all costs incidental to the acquisition, exploration
and development of oil and gas properties, including costs of undeveloped
leasehold, dry holes and leasehold equipment, are capitalized. Net capitalized
costs are limited to the estimated future net revenues, discounted at 10% per
annum, from proved oil, natural gas and natural gas liquids reserves. Such
limitations are imposed separately on a country-by-country basis. Capitalized
costs are depleted by an equivalent unit-of-production method, converting gas to
oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil.
No gain or loss is recognized upon disposal of oil and gas properties unless
such disposal significantly alters the relationship between capitalized costs
and proved reserves.
Depreciation and amortization of other property and equipment, including
leasehold improvements, are provided using the straight-line method based on
estimated useful lives from 3 to 39 years.
Marketable Securities and Other Investments
Devon accounts for certain investments in debt and equity securities by
following the requirements of Statement of Financial Accounting Standards
("SFAS") No. 115, "Accounting for Certain Investments in Debt and Equity
Securities." This standard requires that, except for debt securities classified
as "held-to-maturity," investments in debt and equity securities must be
reported at fair value. As a result, Devon's investment in Chevron Corporation
common stock, which is classified as "available for sale," is reported at fair
value, with the tax effected unrealized gain or loss recognized in other
comprehensive loss and reported as a separate component of stockholders' equity.
Devon's investments in other short-term securities are also classified as
"available for sale."
Goodwill
Goodwill, which represents the excess of purchase price over the fair
value of net assets acquired, is amortized by an equivalent unit-of-production
method. Devon assesses the recoverability of this intangible asset by
determining whether the amortization of the goodwill balance over its remaining
life can be recovered through undiscounted future operating cash flows of the
acquired properties. The amount of goodwill impairment, if any, is measured
based on projected discounted future operating cash flows using a discount rate
reflecting Devon's average cost of funds. The assessment of the recoverability
of goodwill will be impacted if estimated future operating cash flows are not
achieved.
Accumulated goodwill amortization was $57.4 million and $16.1 million at
December 31, 2000 and 1999, respectively.
62
<PAGE> 63
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Revenue Recognition and Gas Balancing
Oil and gas revenues are recognized when sold. During the course of
normal operations, Devon and other joint interest owners of natural gas
reservoirs will take more or less than their respective ownership share of the
natural gas volumes produced. These volumetric imbalances are monitored over the
lives of the wells' production capability. If an imbalance exists at the time
the wells' reserves are depleted, cash settlements are made among the joint
interest owners under a variety of arrangements.
Devon follows the sales method of accounting for gas imbalances. A
liability is recorded when Devon's excess takes of natural gas volumes exceed
its estimated remaining recoverable reserves. No receivables are recorded for
those wells where Devon has taken less than its ownership share of gas
production.
Hedging Activities
Devon has periodically entered into oil and gas financial instruments
and foreign exchange rate swaps to manage its exposure to oil and gas price
volatility. The foreign exchange rate swaps mitigate the effect of volatility in
the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues that are
predominantly based on U.S. dollar prices. The hedging instruments are usually
placed with counterparties that Devon believes are minimal credit risks. The oil
and gas reference prices upon which the price hedging instruments are based
reflect various market indices that have a high degree of historical correlation
with actual prices received by Devon.
Devon accounts for its hedging instruments using the deferral method of
accounting. Under this method, realized gains and losses from Devon's price risk
management activities are recognized in oil and gas revenues when the associated
production occurs and the resulting cash flows are reported as cash flows from
operating activities. Gains and losses on hedging contracts that are closed
before the hedged production occurs are deferred until the production month
originally hedged. In the event of a loss of correlation between changes in oil
and gas reference prices under a hedging instrument and actual oil and gas
prices, a gain or loss is recognized currently to the extent the hedging
instrument has not offset changes in actual oil and gas prices.
Devon adopted the provisions of SFAS 133, as amended, in the first
quarter of the year ending December 31, 2001. In accordance with the transition
provisions of SFAS 133, Devon recorded a net-of-tax cumulative-effect-type
adjustment of $36.6 million in accumulated other comprehensive loss to recognize
at fair value all derivatives that are designated as cash-flow hedging financial
instruments. Additionally, Devon recorded a net-of-tax cumulative-effect-type
adjustment to net earnings for a $49.5 million gain related to the fair value of
financial instruments that do not qualify as hedges. This gain included $46.2
million related to the option embedded in Devon's debentures that are
exchangeable into shares of Chevron Corporation common stock.
63
<PAGE> 64
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Stock Options
Devon applies the intrinsic value-based method of accounting prescribed
by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations, in accounting for its fixed plan stock
options. As such, compensation expense would be recorded on the date of grant
only if the current market price of the underlying stock exceeded the exercise
price. SFAS No. 123, "Accounting for Stock-Based Compensation," established
accounting and disclosure requirements using a fair value-based method of
accounting for stock-based employee compensation plans. As allowed by SFAS No.
123, Devon has elected to continue to apply the intrinsic value-based method of
accounting described above, and has adopted the disclosure requirements of SFAS
No. 123 which are included in Note 10.
Major Purchasers
In 2000, Enron Capital and Trade Resource Corporation accounted for 20%
of Devon's combined oil, gas and natural gas liquids sales. In 1998, Aquila
Energy Marketing Corporation accounted for 11% of Devon's combined oil, gas and
natural gas liquids sales. No purchaser accounted for over 10% of such revenues
in 1999.
Income Taxes
Devon accounts for income taxes using the asset and liability method,
whereby deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of assets and liabilities and their respective tax bases, as
well as the future tax consequences attributable to the future utilization of
existing tax net operating loss and other types of carryforwards. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences and
carryforwards are expected to be recovered or settled. The effect on deferred
tax assets and liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date. U.S. deferred income taxes have not
been provided on Canadian earnings which are being permanently reinvested.
General and Administrative Expenses
General and administrative expenses are reported net of amounts
allocated to working interest owners of the oil and gas properties operated by
Devon and net of amounts capitalized pursuant to the full cost method of
accounting.
Net Earnings Per Common Share
Basic earnings per share is computed by dividing income available to
common stockholders by the weighted average number of common shares outstanding
for the period. Diluted earnings per share reflects the potential dilution that
could occur if Devon's dilutive outstanding stock options were exercised
(calculated using the treasury stock method) and if Devon's zero coupon
convertible senior debentures were converted to common stock.
64
<PAGE> 65
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
The following table reconciles the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
2000. The diluted loss per share calculations for 1999 and 1998 produce results
that are anti-dilutive. (The diluted calculation for 1999 reduced the net loss
by $4.3 million and increased the common shares outstanding by 5.7 million
shares. The diluted calculation for 1998 reduced the net loss by $6.0 million
and increased the common shares outstanding by 6.0 million shares.) Therefore,
the diluted loss per share amounts for 1999 and 1998 reported in the
accompanying consolidated statements of operations are the same as the basic
loss per share amounts.
<TABLE>
<CAPTION>
NET EARNINGS WEIGHTED
APPLICABLE AVERAGE NET
TO COMMON COMMON SHARES EARNINGS
STOCKHOLDERS OUTSTANDING PER SHARE
------------ ------------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31, 2000:
Basic earnings per share $720,607 127,421 $ 5.66
Dilutive effect of:
Potential common shares issuable upon conversion
of senior convertible debentures (the increase in net
earnings is net of income tax expense of $2,755,000) 4,309 2,248
Potential common shares issuable upon the exercise
of outstanding stock options -- 2,061
-------- --------
Diluted earnings per share $724,916 131,730 $ 5.50
======== ======== ========
</TABLE>
Options to purchase approximately 1.0 million shares of Devon's common
stock with exercise prices ranging from $55.54 per share to $89.66 per share
(with a weighted average price of $66.64 per share) were outstanding at December
31, 2000, but were not included in the computation of diluted earnings per share
for 2000 because the options' exercise price exceeded the average market price
of Devon's common stock during the year. The excluded options for 2000 expire
between February 12, 2001 and June 1, 2010. All options were excluded from the
diluted earnings per share calculations for 1999 and 1998.
65
<PAGE> 66
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Comprehensive Loss
Devon's comprehensive income information is included in the accompanying
consolidated statements of stockholders' equity. A summary of accumulated other
comprehensive loss as of December 31, 2000, 1999 and 1998, and changes during
each of the years then ended, is presented in the following table.
<TABLE>
<CAPTION>
FOREIGN MINIMUM UNREALIZED
CURRENCY PENSION LOSSES ON
TRANSLATION LIABILITY MARKETABLE
ADJUSTMENTS ADJUSTMENTS SECURITIES TOTAL
----------- ----------- ---------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Balance as of December 31, 1997 $(27,113) -- -- (27,113)
1998 activity (8,130) (1,179) -- (9,309)
Deferred taxes -- 460 -- 460
-------- -------- -------- --------
1998 activity, net of
deferred taxes (8,130) (719) -- (8,849)
-------- -------- -------- --------
Balance as of December 31, 1998 (35,243) (719) -- (35,962)
1999 activity 7,517 (394) (59,959) (52,836)
Deferred taxes -- 153 23,403 23,556
-------- -------- -------- --------
1999 activity, net of
deferred taxes 7,517 (241) (36,556) (29,280)
-------- -------- -------- --------
Balance as of December 31, 1999 (27,726) (960) (36,556) (65,242)
2000 activity (10,213) 1,346 (17,608) (26,475)
Deferred taxes -- (524) 6,844 6,320
-------- -------- -------- --------
2000 activity, net of
deferred taxes (10,213) 822 (10,764) (20,155)
-------- -------- -------- --------
Balance as of December 31, 2000 $(37,939) (138) (47,320) (85,397)
======== ======== ======== ========
</TABLE>
Foreign Currency Translation Adjustments
The assets and liabilities of certain foreign subsidiaries are prepared
in their respective local currencies and translated into U.S. dollars based on
the current exchange rate in effect at the balance sheet dates, while income and
expenses are translated at average rates for the periods presented. Translation
adjustments have no effect on net income and are included in accumulated other
comprehensive loss.
Dividends
Dividends on Devon's common stock were paid in 2000, 1999 and 1998 at a
per share rate of $0.05 per quarter. As adjusted for the pooling-of-interests
method of accounting followed for the Santa Fe Snyder merger and the Northstar
combination, annual dividends per share for 2000, 1999 and 1998 were $0.17,
$0.14 and $0.10, respectively.
Statements of Cash Flows
For purposes of the consolidated statements of cash flows, Devon
considers all highly liquid investments with original maturities of three months
or less to be cash equivalents.
66
<PAGE> 67
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments,
litigation or other sources are recorded when it is probable that a liability
has been incurred and the amount can be reasonably estimated.
Environmental expenditures are expensed or capitalized in accordance
with accounting principles generally accepted in the United States of America.
Liabilities for these expenditures are recorded when it is probable that
obligations have been incurred and the amounts can be reasonably estimated.
Reference is made to Note 13 for a discussion of amounts recorded for these
liabilities.
Reclassification
Certain of the 1999 and 1998 amounts in the accompanying consolidated
financial statements have been reclassified to conform to the 2000 presentation.
2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION
Santa Fe Snyder Merger
Devon closed its merger with Santa Fe Snyder Corporation ("Santa Fe
Snyder") on August 29, 2000. The merger was accounted for using the
pooling-of-interests method of accounting for business combinations.
Accordingly, all operational and financial information contained herein includes
the combined amounts for Devon and Santa Fe Snyder for all periods presented.
Devon issued approximately 40.6 million shares of its common stock to
the former stockholders of Santa Fe Snyder based on an exchange ratio of 0.22
shares of Devon common stock for each share of Santa Fe Snyder common stock.
Because the merger was accounted for using the pooling-of-interests method, all
combined share information has been retroactively restated to reflect the
exchange ratio.
During 2000, Devon recorded a pre-tax charge of $60.4 million ($37.2
million net of tax) for direct costs related to the Santa Fe Snyder merger.
PennzEnergy Merger
Devon closed its merger with PennzEnergy Company ("PennzEnergy") on
August 17, 1999. The merger was accounted for using the purchase method of
accounting for business combinations. Accordingly, the accompanying statement of
operations for 1999 includes the effects of PennzEnergy operations since August
17, 1999.
Devon issued approximately 21.5 million shares of its common stock to
the former stockholders of PennzEnergy. In addition, Devon assumed long-term
debt and other obligations
67
<PAGE> 68
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
totaling approximately $2.3 billion on August 17, 1999. The calculation of the
total purchase price and the allocation to assets and liabilities as of August
17, 1999, are shown below. Devon has sold certain of the assets acquired.
Generally, the proceeds from such sales reduced the carrying value of oil and
gas properties.
<TABLE>
<CAPTION>
(IN THOUSANDS,
EXCEPT SHARE PRICE)
-------------------
<S> <C>
Calculation and allocation of purchase price:
Shares of Devon common stock issued to PennzEnergy
stockholders 21,501
Average Devon stock price $ 33.40
-----------
Fair value of common stock issued $ 718,177
Plus preferred stock assumed by Devon 150,000
Plus estimated merger costs incurred 71,545
Plus fair value of PennzEnergy employee stock options
assumed by Devon 18,295
Less stock registration and issuance costs incurred (4,985)
-----------
Total purchase price 953,032
Plus fair value of liabilities assumed by Devon:
Current liabilities 200,708
Debentures exchangeable into Chevron Corporation
common stock 760,313
Other long-term debt 838,792
Other long-term liabilities 158,988
-----------
2,911,833
Less fair value of non oil and gas assets acquired by Devon:
Current assets 109,769
Non oil and gas properties 31,412
Investment in common stock of Chevron Corporation 676,441
Other assets 81,945
-----------
Fair value allocated to oil and gas properties, including $83.3
million of undeveloped leasehold $ 2,012,266
===========
</TABLE>
Additionally, $346.9 million was added as goodwill for deferred taxes
created as a result of the merger. Due to the tax-free nature of the merger,
Devon's tax basis in the assets acquired and liabilities assumed are the same as
PennzEnergy's tax basis. The $346.9 million of deferred taxes recorded represent
the deferred tax effect of the differences between the fair values assigned by
Devon for financial reporting purposes to the former PennzEnergy assets and
liabilities and their bases for income tax purposes.
Estimated proved reserves added in the PennzEnergy merger were 232.7
million barrels of oil, 782.6 billion cubic feet of natural gas and 32.7 million
barrels of natural gas liquids. Also, added in the PennzEnergy merger were
approximately 13 million net acres of undeveloped leasehold. (The quantities of
proved reserves stated in this paragraph are unaudited.)
68
<PAGE> 69
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Snyder Merger
Santa Fe Snyder was formed on May 5, 1999, when the former Santa Fe
Energy Resources, Inc. ("Santa Fe") closed its merger with Snyder Oil
Corporation ("Snyder"). Because Devon's merger with Santa Fe Snyder was
accounted for using the pooling-of-interests method, the accompanying
consolidated financial statements are presented as though Devon merged with
Snyder in May 1999.
The Snyder merger was accounted for using the purchase method of
accounting for business combinations. Accordingly, the accompanying statement of
operations for 1999 includes the effects of Snyder's operations since May 5,
1999.
As restated for the Devon-Santa Fe Snyder pooling, each share of Snyder
common stock was exchanged for 0.451 shares of Devon common stock. This resulted
in the issuance of approximately 15.1 million shares of Devon stock in the
Snyder merger. In addition, the Snyder merger also included the assumption of
approximately $219 million of Snyder's long-term debt as of May 5, 1999. The
calculation of the total purchase price and the allocation to assets and
liabilities as of May 5, 1999, are as follows.
<TABLE>
<CAPTION>
(IN THOUSANDS,
EXCEPT SHARE PRICE)
-------------------
<S> <C>
Calculation and allocation of purchase price:
Shares of Santa Fe common stock issued to Snyder
stockholders, as adjusted for the Devon-Santa Fe Snyder pooling 15,130
Average Santa Fe stock price, as adjusted for the
Devon-Santa Fe Snyder pooling $ 27.24
--------
Fair value of common stock issued $412,092
Plus estimated merger costs incurred 1,485
--------
Total purchase price 413,577
Plus fair value of liabilities assumed:
Current liabilities 55,118
Long-term debt 219,001
Other long-term liabilities 26,254
--------
713,950
Less fair value of non oil and gas assets acquired:
Current assets 16,755
Other assets 37,211
--------
Fair value allocated to oil and gas properties, including $14.7 million
of undeveloped leasehold $659,984
========
</TABLE>
Additionally, $135.4 million was added to oil and gas properties for
deferred taxes created as a result of the Snyder merger. Due to the tax-free
nature of the merger, Santa Fe's tax basis in the assets acquired and
liabilities assumed were the same as Snyder's tax basis. The $135.4 million of
deferred taxes recorded represent the deferred tax effect of the differences
between the
69
<PAGE> 70
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
fair values assigned by Santa Fe for financial reporting purposes to the former
Snyder assets and liabilities and their bases for income tax purposes.
Estimated proved reserves added in the Snyder merger were 17.7 million
barrels of oil and natural gas liquids and 424 billion cubic feet of natural
gas. Also added in the Snyder merger were approximately 800,000 net acres of
undeveloped leasehold. (The quantities of proved reserves stated in this
paragraph are unaudited.)
Wascana Properties Transaction
On December 23, 1998, Devon acquired certain natural gas properties
located in northeastern Alberta, Canada, from Wascana Oil and Gas Partnership, a
subsidiary of Canadian Occidental Petroleums Ltd. (the "Wascana Properties").
Devon acquired the properties for approximately $57.5 million, which was funded
with bank debt under Devon's then existing credit facilities.
Estimated proved reserves of the Wascana Properties as of December 31,
1998, were 71.5 billion cubic feet of natural gas. Approximately $52.2 million
of the purchase price was allocated to the proved reserves. The remaining $5.3
million of the purchase price was allocated to approximately 190,000 net
undeveloped acres and exclusive rights to associated seismic data. (The
quantities of proved reserves stated in this paragraph are unaudited.)
Pro Forma Information (Unaudited)
Set forth in the following table is certain unaudited pro forma
financial information for the years ended December 31, 1999 and 1998. This
information has been prepared assuming the PennzEnergy merger, the Snyder merger
and the Wascana Property transaction were consummated on January 1, 1998, and is
based on estimates and assumptions deemed appropriate by Devon. The pro forma
information is presented for illustrative purposes only. If the transactions had
occurred in the past, Devon's operating results might have been different from
those presented in the following table. The pro forma information should not be
relied upon as an indication of the operating results that Devon would have
achieved if the transactions had occurred on January 1, 1998. The pro forma
information also should not be used as an indication of the future results that
Devon will achieve after the transactions.
The pro forma information includes the effect of Devon's issuance of
10.3 million shares of common stock as if such shares had been issued on January
1, 1998. (See Note 10 for additional information on this issuance of shares of
common stock.) The pro forma information assumes that the approximately $402
million of net proceeds from the issuance of common stock was used to retire
long-term debt and therefore reduce interest expense.
The following should be considered in connection with the pro forma
financial information presented:
70
<PAGE> 71
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
- Expected annual cost savings of $30 to $35 million related to
the Santa Fe Snyder merger and $50 to $60 million related to the
PennzEnergy merger have not been reflected as an adjustment to
the historical data in preparing the following pro forma
information. These cost savings are expected to result from the
consolidation of the corporate headquarters of Devon, Santa Fe
Snyder and PennzEnergy and the elimination of duplicate staff
and expenses. Some of the cost savings related to the Santa Fe
Snyder merger involve items that, under the full cost method of
accounting, are capitalized rather than expensed in the
consolidated financial statements. Therefore, not all of the $30
to $35 million of expected savings will result in reductions to
expenses as reported in the accompanying consolidated statements
of operations.
- The 1999 pro forma results include a gain of $46.7 million
($29.8 million after-tax) from PennzEnergy's pre-merger sale of
land, timber and mineral rights in Pennsylvania and New York.
- In 1998, PennzEnergy realized pretax gains on the sale and
exchange of Chevron Corporation common stock of $203.1 million.
This gain is included in the 1998 pro forma financial
information presented in the following table. The pro forma
financial information does not include the related $207.0
million after-tax extraordinary loss resulting from the early
extinguishment of debt. The exclusion of the extraordinary loss
from the 1998 pro forma results is required by Securities and
Exchange Commission rules and regulations regarding presentation
of pro forma results of operations. If the extraordinary loss
were included in the 1998 pro forma results, the 1998 pro forma
net loss as presented in the following table would be $508.8
million, or $4.37 per share.
- The 1999 pro forma financial information does not include a $4.2
million extraordinary loss recorded by Santa Fe Snyder. This
loss related to the early extinguishment of debt. If the
extraordinary loss were included in the 1999 pro forma results,
the 1999 pro forma net loss as presented in the following table
would be $211.9 million, or $1.85 per share.
- The 1998 pro forma results include $24.3 million of nonrecurring
general and administrative expenses in connection with the
spin-off of Pennzoil-Quaker State Company on December 30, 1998.
- The 1999 and 1998 pro forma results include reductions of the
carrying value of oil and gas properties of $476.1 million and
$422.5 million, respectively. The after-tax effect of these
reductions, which were due to the full cost ceiling limitation,
were $309.7 million in 1999 and $280.8 million in 1998.
71
<PAGE> 72
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
<TABLE>
<CAPTION>
PRO FORMA INFORMATION
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998
----------- -----------
(DOLLARS IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
<S> <C> <C>
REVENUES
Oil sales $ 702,477 487,218
Gas sales 806,337 802,785
Natural gas liquids sales 93,829 71,726
Other 87,453 306,103
----------- -----------
Total revenues 1,690,096 1,667,832
----------- -----------
COSTS AND EXPENSES
Lease operating expenses 409,555 444,617
Production taxes 53,506 44,548
Depreciation, depletion and amortization of property
and equipment 665,865 723,908
Amortization of goodwill 46,321 52,637
General and administrative expenses 147,028 177,678
Expenses related to prior mergers 16,800 13,149
Interest expense 158,813 175,082
Deferred effect of changes in foreign currency exchange rate on
subsidiary's long-term debt (13,154) 16,104
Distributions on preferred securities of subsidiary trust 6,884 9,717
Reduction of carrying value of oil and gas properties 476,100 422,500
----------- -----------
Total costs and expenses 1,967,718 2,079,940
----------- -----------
Earnings (loss) before income tax expense (benefit) and (277,622) (412,108)
extraordinary item
INCOME TAX EXPENSE (BENEFIT)
Current 23,261 (1,076)
Deferred (93,173) (109,222)
----------- -----------
Total income tax expense (benefit) (69,912) (110,298)
----------- -----------
Earnings (loss) before extraordinary item (207,710) (301,810)
Preferred stock dividends 9,736 5,625
----------- -----------
Earnings (loss) before extraordinary item applicable to
common stockholders $ (217,446) (307,435)
=========== ===========
Earnings (loss) before extraordinary item per average common
share outstanding - basic and diluted $ (1.81) (2.61)
=========== ===========
Weighted average common shares outstanding - basic 119,988 117,703
=========== ===========
</TABLE>
Northstar Combination
On June 29, 1998, Devon and Northstar Energy Corporation ("Northstar")
announced they had entered into a definitive combination agreement subject to
shareholder approval and certain other conditions. The combination of the two
companies (the "Northstar combination") was closed on December 10, 1998. At that
date, Northstar became a wholly-owned subsidiary of
72
<PAGE> 73
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Devon. Pursuant to the Northstar combination, Northstar's common shareholders
received approximately 16.1 million exchangeable shares (the "Exchangeable
Shares") based on an exchange ratio of 0.235 Exchangeable Shares for each
Northstar common share outstanding. The Exchangeable Shares were issued by
Northstar, but are exchangeable at any time into Devon's common shares on a
one-for-one basis. Prior to such exchange, the Exchangeable Shares have rights
identical to those of Devon's common shares, including dividend, voting and
liquidation rights. Between December 10, 1998 and December 31, 2000,
approximately 13.1 million of the originally issued 16.1 million Exchangeable
Shares had been exchanged for shares of Devon common stock.
The Northstar combination was accounted for under the
pooling-of-interests method of accounting for business combinations. All
operational and financial information contained herein includes the combined
amounts for Devon and Northstar for all periods presented.
During the fourth quarter of 1998, Devon recorded a pre-tax charge of
$13.1 million ($9.7 million after tax) for direct costs related to the Northstar
combination.
3. SAN JUAN BASIN TRANSACTION
At the beginning of 1995, Devon entered into a transaction (the "San
Juan Basin Transaction") involving a volumetric production payment and a
repurchase option. The San Juan Basin Transaction allowed Devon to monetize tax
credits earned from certain of its coal seam gas production in the San Juan
Basin. During 2000, 1999 and 1998, the San Juan Basin Transaction added
approximately $12.3 million, $7.6 million and $8.4 million, respectively, to
Devon's gas revenues.
Under the terms of the San Juan Basin Transaction, Devon had a
repurchase option which it could exercise at anytime. Devon exercised the
repurchase option effective September 30, 2000. Devon had previously recorded a
portion of the quarterly cash payments received pursuant to the San Juan Basin
Transaction as a repurchase liability based upon the estimated eventual
repurchase price. Devon also received cash payments in exchange for agreeing not
to exercise its repurchase option for specific periods of time prior to 2000.
These payments were also added to the repurchase liability. As a result, in
addition to the cash flow recorded as revenues described in the previous
paragraph, Devon also received $16.6 million and $6.8 million in 1999 and 1998,
respectively, which were added to the repurchase liability. The actual
repurchase price as of September 30, 2000, was approximately $36.3 million.
4. SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest in 2000, 1999 and 1998 were approximately
$155.1 million, $115.6 million and $45.6 million, respectively. Cash payments
for federal, state and foreign income taxes in 2000, 1999 and 1998 were
approximately $81.8 million, $15.8 million and $19.4 million, respectively.
73
<PAGE> 74
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
The 1999 PennzEnergy merger and Snyder merger involved non-cash
consideration as presented below:
<TABLE>
<CAPTION>
1999
----------
(IN THOUSANDS)
<S> <C>
Value of common stock issued $1,130,269
Value of preferred stock issued 150,000
Employee stock options assumed 18,295
Liabilities assumed 2,259,174
Deferred tax liability created 474,306
----------
Fair value of assets acquired with
non-cash consideration $4,032,044
==========
</TABLE>
During the fourth quarter of 1999, substantially all of the 6.5% Trust
Convertible Preferred Securities were converted to Devon common stock (see Note
9).
5. ACCOUNTS RECEIVABLE
The components of accounts receivable included the following:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------
2000 1999 1998
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids
revenue accruals $ 438,304 218,462 74,660
Joint interest billings 122,778 66,658 33,136
Other 41,013 34,585 31,262
--------- --------- ---------
602,095 319,705 139,058
Allowance for doubtful accounts (3,847) (3,700) (2,000)
--------- --------- ---------
Net accounts receivable $ 598,248 316,005 137,058
========= ========= =========
</TABLE>
74
<PAGE> 75
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
6. PROPERTY AND EQUIPMENT
Property and equipment included the following:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties:
Subject to amortization $ 9,169,593 8,125,886 4,584,676
Not subject to amortization:
Acquired in 2000 74,164 -- --
Acquired in 1999 122,431 134,966 --
Acquired in 1998 44,833 56,922 65,702
Acquired prior to 1998 73,832 109,297 147,875
Accumulated depreciation, depletion
and amortization (4,752,670) (4,129,824) (3,204,775)
----------- ----------- -----------
Net oil and gas properties 4,732,183 4,297,247 1,593,478
----------- ----------- -----------
Other property and equipment 224,499 164,939 55,958
Accumulated depreciation and amortization (47,146) (38,766) (25,908)
----------- ----------- -----------
Net other property and equipment 177,353 126,173 30,050
----------- ----------- -----------
Property and equipment, net of accumulated
depreciation, depletion and amortization $ 4,909,536 4,423,420 1,623,528
=========== =========== ===========
</TABLE>
Depreciation, depletion and amortization of property and equipment
consisted of the following components:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Depreciation, depletion and amortization
of oil and gas properties $662,890 390,117 230,419
Depreciation and amortization of other
property and equipment 22,974 13,660 12,564
Amortization of other assets 7,476 2,598 161
-------- -------- --------
Total expense $693,340 406,375 243,144
======== ======== ========
</TABLE>
75
<PAGE> 76
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
7. LONG-TERM DEBT AND RELATED EXPENSES
A summary of Devon's long-term debt is as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Borrowings under credit facilities with banks $ 146,652 645,141 411,271
Debentures exchangeable into shares of Chevron
Corporation common stock
4.90% due August 15, 2008 443,807 443,807 --
4.95% due August 15, 2008 316,506 316,506 --
Zero coupon convertible senior debentures
exchangeable into shares of Devon
Energy Corp. common stock, 3.875% due
June 27, 2020 359,689 -- --
Other debentures:
10.25% due November 1, 2005 250,000 250,000 --
10.125% due November 15, 2009 200,000 200,000 --
11.00% due May 15, 2004 -- -- 100,000
Premium (discount) on debentures 33,375 37,467 (400)
Senior notes:
8.05% due June 15, 2004 124,881 125,000 --
6.76% due July 19, 2005 -- 75,000 75,000
8.75% due June 15, 2007 175,000 175,000 --
6.79% due March 2, 2009 -- 150,000 150,000
Discount on notes (1,074) (1,400) --
----------- ----------- -----------
2,048,836 2,416,521 735,871
Less amount classified as current -- -- --
----------- ----------- -----------
Long-term debt $ 2,048,836 2,416,521 735,871
=========== =========== ===========
</TABLE>
Maturities of long-term debt as of December 31, 2000, excluding the
$32.3 million of premiums net of discounts, are as follows (in thousands):
<TABLE>
<S> <C>
2001 $ --
2002 7,333
2003 7,333
2004 132,213
2005 257,332
2006 and thereafter 1,612,324
----------
Total $2,016,535
==========
</TABLE>
76
<PAGE> 77
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Credit Facilities with Banks
Concurrent with the closing of the Santa Fe Snyder merger on August 29,
2000, Devon entered into new unsecured long-term credit facilities aggregating
$1 billion (the "Credit Facilities"). The Credit Facilities include a U.S.
facility of $725 million (the "U.S. Facility") and a Canadian facility of $275
million (the "Canadian Facility").
The Credit Facilities replaced the prior separate facilities of Devon
and Santa Fe Snyder. Prior to the August 2000 merger, Devon and Santa Fe Snyder
each had their own unsecured credit facilities. Devon's credit facilities prior
to the merger aggregated $750 million, with $475 million in a U.S. facility and
$275 million in a Canadian facility. Santa Fe Snyder's credit facilities prior
to the merger aggregated $600 million.
The $725 million U.S. Facility consists of a Tranche A facility of $200
million and a Tranche B facility of $525 million. The Tranche B facility can be
increased to as high as $625 million and reduced to as low as $425 million by
reallocating the amount available between the Tranche B facility and the
Canadian Facility. The Tranche A facility matures on October 15, 2004. Devon may
borrow funds under the Tranche B facility until August 28, 2001 (the "Tranche B
Revolving Period"). Devon may request that the Tranche B Revolving Period be
extended an additional 364 days by notifying the agent bank of such request
between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt
borrowed under the Tranche B facility matures two years and one day following
the end of the Tranche B Revolving Period.
Devon may borrow funds under the $275 million Canadian Facility until
August 28, 2001 (the "Canadian Facility Revolving Period"). As disclosed in the
prior paragraph, the Canadian Facility can be increased to as high as $375
million and reduced to as low as $175 million by reallocating the amount
available between the Tranche B facility and the Canadian Facility. Devon may
request that the Canadian Facility Revolving Period be extended an additional
364 days by notifying the agent bank of such request between 45 and 90 days
prior to the end of the Canadian Facility Revolving Period. Debt outstanding as
of the end of the Canadian Facility Revolving Period is payable in semi-annual
installments of 2.5% each for the following five years, with the final
installment due five years and one day following the end of the Canadian
Facility Revolving Period.
Amounts borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon may elect for periods up to six months. Such rates
are generally less than the prime rate, and are tied to margins determined by
Devon's corporate credit ratings. Devon may also elect to borrow at the prime
rate. The Credit Facilities provide for an annual facility fee of $0.9 million
that is payable quarterly. The weighted average interest rate on the $146.7
million outstanding under the Credit Facilities at December 31, 2000, was 6.07%.
The average interest rate on bank debt outstanding under the previous facilities
at December 31, 1999 and 1998 was 6.85% and 6.28%, respectively.
77
<PAGE> 78
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
The agreements governing the Credit Facilities contain certain covenants
and restrictions, including a maximum debt-to-capitalization ratio. At December
31, 2000, Devon was in compliance with such covenants and restrictions.
Exchangeable Debentures
The exchangeable debentures consist of $443.8 million of 4.90%
debentures and $316.5 million of 4.95% debentures. The exchangeable debentures
were issued on August 3, 1998 and mature August 15, 2008. The exchangeable
debentures are callable beginning August 15, 2000, initially at 104.0% of
principal and at prices declining to 100.5% of principal on or after August 15,
2007. The exchangeable debentures are exchangeable at the option of the holders
at any time prior to maturity, unless previously redeemed, for shares of Chevron
Corporation common stock. In lieu of delivering Chevron Corporation common
stock, Devon may, at its option, pay to any holder an amount of cash equal to
the market value of the Chevron Corporation common stock to satisfy the exchange
request. However, at maturity, the holders will receive an amount at least equal
to the face value of the debt outstanding - either in cash or in a combination
of cash and Chevron Corporation common stock.
As of December 31, 2000, Devon beneficially owned approximately 7.1
million shares of Chevron Corporation common stock. These shares have been
deposited with an exchange agent for possible exchange for the exchangeable
debentures. Each $1,000 principal amount of the exchangeable debentures is
exchangeable into 9.3283 shares of Chevron Corporation common stock, an exchange
rate equivalent to $107-7/32 per share of Chevron stock.
The exchangeable debentures were assumed as part of the PennzEnergy
merger. The fair values of the exchangeable debentures were determined as of
August 17, 1999, based on market quotations. The fair value approximated the
face value of the exchangeable debentures. As a result, no premium or discount
was recorded on these exchangeable debentures.
Other Debentures
The 10.25% and 10.125% debentures were assumed as part of the
PennzEnergy merger. The fair values of the respective debentures were determined
using August 17, 1999, market interest rates. As a result, premiums were
recorded on these debentures which lowered their effective interest rates to
8.3% and 8.9% on the $250 million of 10.25% debentures and $200 million of
10.125% debentures, respectively. The premiums are being amortized using the
effective interest method.
Senior Notes
In connection with the Snyder merger, Devon assumed Snyder's $175
million of 8.75% notes due in 2007. The notes are redeemable by Devon on or
after June 15, 2002, initially at 104.375% of principal and at prices declining
to 100% of principal on or after June 15, 2005. The notes are general unsecured
obligations of Devon. In June 1999, Devon issued $125.0 million of 8.05% notes
due 2004. The notes were issued for 98.758% of face value and Devon received
78
<PAGE> 79
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
total proceeds of $121.6 million after deducting related costs and expenses of
$1.9 million. The notes, which mature June 15, 2004, are redeemable, upon not
less than thirty nor more than sixty days notice, as a whole or in part, at the
option of Devon at a redemption price equal to the sum of (i) 100% of the
principal amount thereof, (ii) the applicable make-whole premium as determined
by an independent investment banker and (iii) accrued and unpaid interest. The
notes are general unsecured obligations of Devon. The indentures for these notes
include covenants that restrict the ability of Devon SFS Operating, Inc., a
wholly-owned subsidiary of Devon, to take certain actions, including the ability
to incur additional indebtedness and to pay dividends or repurchase capital
stock.
In September 2000, Devon, as required under the $125 million senior note
agreement due to a "change of control", made a tender offer to repurchase the
senior notes at a premium of 101.000%. As a result of this tender offer,
$119,000 of senior notes were redeemed at a total cost to Devon of approximately
$120,000.
Zero Coupon Convertible Debentures
In June 2000, Devon privately sold zero coupon convertible senior
debentures. The debentures were sold at a price of $464.13 per debenture with a
yield to maturity of 3.875% per annum. Each of the 760,000 debentures is
convertible into 5.7593 shares of Devon common stock. Devon may call the
debentures at any time after five years, and a debenture holder has the right to
require Devon to repurchase the debentures after five, 10 and 15 years, at the
issue price plus accrued original issue discount and interest. Devon's proceeds
were approximately $346.1 million, net of debt issuance costs of approximately
$6.6 million. Devon used the proceeds from the sale of these debentures to pay
down other domestic long-term debt.
Interest Expense
Following are the components of interest expense for the years 2000,
1999 and 1998:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
2000 1999 1998
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Interest based on debt outstanding $ 157,028 108,064 43,114
Amortization of debt premium, net (3,781) (1,328) --
Facility and agency fees 2,696 1,930 932
Amortization of capitalized loan costs 1,467 1,583 556
Capitalized interest (3,239) (1,925) (1,100)
Other 158 1,289 30
--------- --------- ---------
Total interest expense $ 154,329 109,613 43,532
========= ========= =========
</TABLE>
79
<PAGE> 80
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Deferred Effect of Changes in Foreign Currency Exchange Rate on Long-term Debt
Until mid-January 2000, the 6.76 % and 6.79% fixed-rate Senior Notes
referred to in the first table of this note were payable by Northstar. However,
the notes were denominated in U.S. dollars. Changes in the exchange rate between
the U.S. dollar and the Canadian dollar from the dates the notes were issued to
the dates of repayment increased or decreased the expected amount of Canadian
dollars eventually required to repay the notes. Such changes in the Canadian
dollar equivalent of the debt were required to be included in determining net
earnings for the period in which the exchange rate changed. The rate of
conversion of Canadian dollars to U.S. dollars declined in 2000 and 1998 and
increased in 1999. Therefore, $2.4 million of increased expense was recorded in
2000, $13.2 million of reduced expense was recorded in 1999, and $16.1 million
of increased expense was recorded in 1998.
8. INCOME TAXES
At December 31, 2000, Devon had the following carryforwards available to
reduce future income taxes:
<TABLE>
<CAPTION>
YEARS OF CARRYFORWARD
TYPES OF CARRYFORWARD EXPIRATION AMOUNTS
- --------------------- ---------- --------------
(IN THOUSANDS)
<S> <C> <C>
Net operating loss - U.S. federal 2008 -- 2014 $ 344,038
Net operating loss - various states 2002 -- 2014 $ 37,357
Net operating loss -- Canada 2001 -- 2007 $ 2,180
Minimum tax credits Indefinite $ 84,991
</TABLE>
All of the carryforward amounts shown above have been utilized for
financial purposes to reduce deferred taxes.
80
<PAGE> 81
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
The earnings (loss) before income taxes and the components of income tax
expense (benefit) for the years 2000, 1999 and 1998 were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
2000 1999 1998
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Earnings (loss) before income taxes:
U.S $ 872,455 (313,101) (274,150)
Canada 156,085 57,402 19,958
International 113,440 56,321 (107,800)
---------- ---------- ----------
Total $1,141,980 (199,378) (361,992)
========== ========== ==========
Current income tax expense (benefit):
U.S. federal $ 106,742 12,544 (6,399)
Various states 6,015 2,804 (1,189)
Canada 2,268 2,908 1,975
Other 15,768 4,800 1,900
---------- ---------- ----------
Total current tax expense (benefit) 130,793 23,056 (3,713)
---------- ---------- ----------
Deferred income tax expense (benefit):
U.S. federal 151,832 (119,286) (88,824)
Various states 33,399 (495) (4,836)
Canada 67,318 26,654 11,166
Other 28,296 20,637 (39,900)
---------- ---------- ----------
Total deferred tax expense (benefit) 280,845 (72,490) (122,394)
---------- ---------- ----------
Total income tax expense (benefit) $ 411,638 (49,434) (126,107)
========== ========== ==========
</TABLE>
Total income tax expense differed from the amounts computed by applying the U.S.
federal income tax rate to earnings (loss) before income taxes as a result of
the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
U.S. statutory tax (benefit) rate 35% (35)% (35)%
Benefit from disposition of certain
foreign assets (11) -- --
Non-deductible expenses 3 3 3
Nonconventional fuel source credits (2) (3) (1)
State income taxes 2 1 (1)
Taxation on foreign operations 5 7 2
Other 4 2 (3)
--- --- ---
Effective income tax (benefit) rate 36% (25)% (35)%
=== === ===
</TABLE>
81
<PAGE> 82
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities at December 31, 2000, 1999
and 1998 are presented below:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------
2000 1999 1998
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Deferred tax assets:
Net operating loss carryforwards $ 122,843 207,322 48,418
Minimum tax credit carryforwards 84,991 88,447 16,900
Production payments -- 21,527 19,105
Long-term debt 17,176 17,583 --
Other 95,283 50,618 20,388
--------- --------- ---------
Total gross deferred tax assets 320,293 385,497 104,811
Less valuation allowance 100 100 100
--------- --------- ---------
Net deferred tax assets 320,193 385,397 104,711
--------- --------- ---------
Deferred tax liabilities:
Property and equipment, principally due
to differences in depreciation, and
the expensing of intangible drilling
costs for tax purposes (687,473) (500,156) (49,256)
Chevron Corporation common stock (166,596) (172,631) --
Other (83,971) (31,789) (469)
--------- --------- ---------
Total deferred tax liabilities (938,040) (704,576) (49,725)
--------- --------- ---------
Net deferred tax (liability) asset $(617,847) (319,179) 54,986
========= ========= =========
</TABLE>
As shown in the above table, Devon has recognized $320.2 million of net
deferred tax assets as of December 31, 2000. Such amount consists primarily of
$207.8 million of various carryforwards available to offset future income taxes.
The carryforwards include federal net operating loss carryforwards, the majority
of which do not begin to expire until 2008, state net operating loss
carryforwards which expire primarily between 2002 and 2014, Canadian
carryforwards which expire primarily between 2001 and 2007, and minimum tax
credit carryforwards which have no expiration. The tax benefits of carryforwards
are recorded as an asset to the extent that management assesses the utilization
of such carryforwards to be "more likely than not." When the future utilization
of some portion of the carryforwards is determined not to be "more likely than
not," a valuation allowance is provided to reduce the recorded tax benefits from
such assets.
Devon expects the tax benefits from the net operating loss carryforwards
to be utilized between 2001 and 2006. Such expectation is based upon current
estimates of taxable income during this period, considering limitations on the
annual utilization of these benefits as set forth by federal tax regulations.
Significant changes in such estimates caused by variables such as future oil and
gas prices or capital expenditures could alter the timing of the eventual
utilization of such carryforwards. There can be no assurance that Devon will
generate any specific level of continuing taxable earnings. However, management
believes that Devon's future taxable income will more likely than not be
sufficient to utilize substantially all its tax carryforwards prior to their
expiration. A $0.1 million valuation allowance has been recorded at December 31,
2000, related to depletion carryforwards acquired in a 1994 merger.
82
<PAGE> 83
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
9. TRUST CONVERTIBLE PREFERRED SECURITIES
On July 10, 1996, Devon, through its affiliate Devon Financing Trust,
completed the issuance of $149.5 million of 6.5% trust convertible preferred
securities (the "TCP Securities"). Devon Financing Trust issued 2,990,000 shares
of the TCP Securities at $50 per share with a maturity date of June 15, 2026.
Each TCP Security was convertible at the holder's option into 1.6393 shares of
Devon common stock, which equated to a conversion price of $30.50 per share of
Devon common stock.
Devon Financing Trust invested the $149.5 million of proceeds in 6.5%
convertible junior subordinated debentures issued by Devon (the "Convertible
Debentures"). In turn, Devon used the net proceeds from the issuance of the
Convertible Debentures to retire debt outstanding under its credit lines.
On October 27, 1999, Devon issued notice to the holders of the TCP
Securities that it was exercising its right to redeem such securities on
November 30, 1999. Substantially all of the holders of the TCP Securities
elected to exercise their conversion rights instead of receiving the redemption
cash value. As a result, all but 950 shares of the TCP Securities were converted
into approximately 4.9 million shares of Devon common stock. The redemption
price for the 950 shares not converted was $52.275 per share, or $50,000 total,
which included a 4.55% premium as required under the terms of the TCP
Securities.
Devon owned all the common securities of Devon Financing Trust. As such,
the accounts of Devon Financing Trust were included in Devon's consolidated
financial statements after appropriate eliminations of intercompany balances and
transactions. The distributions on the TCP Securities were recorded as a charge
to pre-tax earnings on Devon's consolidated statements of operations, and such
distributions were deductible by Devon for income tax purposes.
10. STOCKHOLDERS' EQUITY
The authorized capital stock of Devon consists of 400 million shares of
common stock, par value $.10 per share (the "Common Stock"), and 4.5 million
shares of preferred stock, par value $1.00 per share. The preferred stock may be
issued in one or more series, and the terms and rights of such stock will be
determined by the Board of Directors.
Effective August 17, 1999, Devon issued 1.5 million shares of 6.49%
cumulative preferred stock, Series A, to holders of PennzEnergy 6.49% cumulative
preferred stock, Series A. Dividends on the preferred stock are cumulative from
the date of original issue and are payable quarterly, in cash, when declared by
the Board of Directors. The preferred stock is redeemable at the option of Devon
at any time on or after June 2, 2008, in whole or in part, at a redemption price
of $100 per share, plus accrued and unpaid dividends to the redemption date.
In late September and early October 1999, Devon received $402.7 million
from the sale of approximately 10.3 million shares of its common stock in a
public offering. The price to the public
83
<PAGE> 84
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
for these shares was $40.50 per share. Net of underwriters' discount and
commissions, Devon received $38.98 per share. Devon paid approximately $0.8
million of expenses related to the equity offering, and these costs were
recorded as reductions of additional paid-in capital.
As discussed in Note 2, there were approximately 21.5 million shares of
Devon common stock issued on August 17, 1999, in connection with the PennzEnergy
merger. Also, as discussed in Note 2, there were 16.1 million Exchangeable
Shares issued on December 10, 1998, in connection with the Northstar
combination. As of year-end 2000, 13.1 million of the Exchangeable Shares had
been exchanged for shares of Devon's common stock. The Exchangeable Shares have
rights identical to those of Devon's common stock and are exchangeable at any
time into Devon's common stock on a one-for-one basis.
Devon's Board of Directors has designated 1.0 million shares of the
preferred stock as Series A Junior Participating Preferred Stock (the "Series A
Junior Preferred Stock") in connection with the adoption of the share rights
plan described later in this note. At December 31, 2000, there were no shares of
Series A Junior Preferred Stock issued or outstanding. The Series A Junior
Preferred Stock is entitled to receive cumulative quarterly dividends per share
equal to the greater of $10 or 100 times the aggregate per share amount of all
dividends (other than stock dividends) declared on Common Stock since the
immediately preceding quarterly dividend payment date or, with respect to the
first payment date, since the first issuance of Series A Junior Preferred Stock.
Holders of the Series A Junior Preferred Stock are entitled to 100 votes per
share (subject to adjustment to prevent dilution) on all matters submitted to a
vote of the stockholders. The Series A Junior Preferred Stock is neither
redeemable nor convertible. The Series A Junior Preferred Stock ranks prior to
the Common Stock but junior to all other classes of Preferred Stock.
Stock Option Plans
Devon has outstanding stock options issued to key management and
professional employees under three stock option plans adopted in 1988, 1993 and
1997 (the "1988 Plan," the "1993 Plan" and the "1997 Plan"). Options granted
under the 1988 Plan and 1993 Plan remain exercisable by the employees owning
such options, but no new options will be granted under these plans. At December
31, 2000, there were 109,000 and 487,540 options outstanding under the 1988 Plan
and the 1993 Plan, respectively.
On May 21, 1997, Devon's stockholders adopted the 1997 Plan and reserved
two million shares of Common Stock for issuance thereunder. On December 9, 1998,
Devon's stockholders voted to increase the reserved number of shares to three
million. On August 17, 1999, Devon's stockholders voted to increase the reserved
number of shares to six million. On August 29, 2000, Devon's stockholders voted
to increase the reserved number of shares to ten million.
The exercise price of stock options granted under the 1997 Plan may not
be less than the estimated fair market value of the stock at the date of grant,
plus 10% if the grantee owns or controls more than 10% of the total voting stock
of Devon prior to the grant. Options granted are exercisable during a period
established for each grant, which period may not exceed 10 years from
84
<PAGE> 85
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
the date of grant. Under the 1997 Plan, the grantee must pay the exercise price
in cash or in Common Stock, or a combination thereof, at the time that the
option is exercised. The 1997 Plan is administered by a committee comprised of
non-management members of the Board of Directors. The 1997 Plan expires on April
25, 2007. As of December 31, 2000, there were 3,306,329 options outstanding
under the 1997 Plan. There were 6,225,949 options available for future grants as
of December 31, 2000.
In addition to the stock options outstanding under the 1988 Plan, 1993
Plan and 1997 Plan, there were approximately 1,744,409, 1,630,123 and 78,553
stock options outstanding at the end of 2000 that were assumed as part of the
Santa Fe Snyder merger, the PennzEnergy merger and the Northstar combination,
respectively. Santa Fe Snyder, PennzEnergy and Northstar had granted these
options prior to the Santa Fe Snyder merger, the PennzEnergy merger and the
Northstar combination. As part of the Santa Fe Snyder merger, the PennzEnergy
merger and the Northstar combination, the options were assumed by Devon and
converted to Devon options at the exchange rate of 0.22, 0.4475 and 0.235 Devon
options for each Santa Fe Snyder, PennzEnergy and Northstar option,
respectively.
A summary of the status of Devon's stock option plans as of December 31,
1998, 1999 and 2000, and changes during each of the years then ended, is
presented below.
<TABLE>
<CAPTION>
OPTIONS EXERCISABLE
-------------------------
OPTIONS OUTSTANDING WEIGHTED
---------------------------- AVERAGE
NUMBER EXERCISE NUMBER EXERCISE
OUTSTANDING PRICE EXERCISABLE PRICE
----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
Balance at December 31, 1997 4,405,560 $ 31.564 2,744,115 $ 29.717
========== ==========
Options granted 1,652,789 $ 34.262
Options exercised (187,953) $ 23.943
Options forfeited (349,740) $ 35.326
----------
Balance at December 31, 1998 5,520,656 $ 31.768 4,079,125 $ 30.479
========== ==========
Options granted 1,564,108 $ 31.736
Options assumed in the
PennzEnergy merger 2,081,894 $ 55.643
Options assumed in the Snyder merger 979,220 $ 35.182
Options exercised (1,139,231) $ 28.509
Options forfeited (452,746) $ 36.369
----------
Balance at December 31, 1999 8,553,901 $ 38.202 7,063,983 $ 39.547
========== ==========
Options granted 1,624,800 $ 51.430
Options exercised (2,488,756) $ 33.106
Options forfeited (333,991) $ 60.354
----------
Balance at December 31, 2000 7,355,954 $ 41.843 6,024,796 $ 40.718
========== ========== ==========
</TABLE>
The weighted average fair values of options granted during 2000, 1999
and 1998 were $28.73, $12.80 and $13.44, respectively. The fair value of each
option grant was estimated for disclosure purposes on the date of grant using
the Black-Scholes Option Pricing Model with the
85
<PAGE> 86
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
following assumptions for 2000, 1999 and 1998, respectively: risk-free interest
rates of 5.5%, 6.0% and 5.0%; dividend yields of 0.4%, 0.5% and 0.4%; expected
lives of 5, 5 and 5 years; and volatility of the price of the underlying common
stock of 40.0%, 35.2% and 31.7%.
The following table summarizes information about Devon's stock options
which were outstanding, and those which were exercisable, as of December 31,
2000:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------ --------------------------
WEIGHTED WEIGHTED WEIGHTED
RANGE OF AVERAGE AVERAGE AVERAGE
EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE
PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE
- --------------- ----------- ---------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C>
$ 8.375-$26.501 886,899 2.98 Years $ 22.732 881,065 $ 22.719
$28.830-$33.381 1,892,214 6.52 Years $ 30.691 1,612,472 $ 30.705
$34.375-$39.773 1,288,365 6.10 Years $ 36.550 1,263,100 $ 36.554
$40.125-$49.950 522,150 5.56 Years $ 46.067 506,884 $ 46.017
$50.142-$59.813 2,146,853 7.75 Years $ 53.072 1,155,202 $ 54.212
$60.150-$89.660 619,473 4.84 Years $ 71.797 606,073 $ 72.050
---------- ----------
7,355,954 6.17 Years $ 41.843 6,024,796 $ 40.718
========== ==========
</TABLE>
Had Devon elected the fair value provisions of SFAS No. 123 and
recognized compensation expense over the vesting period based on the fair value
of the stock options granted as of their grant date, Devon's 2000, 1999 and 1998
pro forma net earnings (loss) and pro forma net earnings (loss) per share would
have differed from the amounts actually reported as shown in the following
table. The pro forma amounts shown below do not include the effects of stock
options granted prior to January 1, 1995.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Net earnings (loss) available to common shareholders
As reported $ 720,607 (157,795) (235,885)
Pro forma $ 701,852 (173,005) (252,070)
Net earnings (loss) per share available to common shareholders:
As reported:
Basic $ 5.66 (1.68) (3.32)
Diluted $ 5.50 (1.68) (3.32)
Pro forma:
Basic $ 5.51 (1.85) (3.55)
Diluted $ 5.36 (1.85) (3.55)
</TABLE>
Share Rights Plan
Under Devon's share rights plan, stockholders have one right for each
share of Common Stock held. The rights become exercisable and separately
transferable ten business days after a) an announcement that a person has
acquired, or obtained the right to acquire, 15% or more of the voting shares
outstanding, or b) commencement of a tender or exchange offer that could result
in a person owning 15% or more of the voting shares outstanding.
86
<PAGE> 87
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Each right entitles its holder (except a holder who is the acquiring
person) to purchase either (a) 1/100 of a share of Series A Preferred Stock for
$75.00, subject to adjustment or, (b) Devon Common Stock with a value equal to
twice the exercise price of the right, subject to adjustment to prevent
dilution. In the event of certain merger or asset sale transactions with another
party or transactions which would increase the equity ownership of a shareholder
who then owned 15% or more of Devon, each Devon right will entitle its holder to
purchase securities of the merging or acquiring party with a value equal to
twice the exercise price of the right.
The rights, which have no voting power, expire on April 16, 2005. The
rights may be redeemed by Devon for $.01 per right until the rights become
exercisable.
11. FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair
values of Devon's financial instruments at December 31, 2000, 1999 and 1998.
<TABLE>
<CAPTION>
2000 1999 1998
----------------------- ----------------------- -----------------------
CARRYING FAIR CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE AMOUNT VALUE
---------- --------- ----------- ---------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Investments $ 606,117 606,117 634,281 634,281 1,930 1,930
Oil and gas price
hedge agreements $ -- (57,560) -- (9,540) -- 1,988
Foreign exchange
hedge agreements $ -- (533) -- (2,535) -- (9,310)
Long-term debt
(including current portion) $(2,048,836) (2,049,779) (2,416,521) (2,400,334) (735,871) (758,075)
TCP Securities $ -- -- -- -- (149,500) (171,400)
</TABLE>
The following methods and assumptions were used to estimate the fair
values of the financial instruments in the above table. None of Devon's
financial instruments are held for trading purposes. The carrying values of cash
and cash equivalents, accounts receivable and accounts payable (including income
taxes payable and accrued expenses) included in the accompanying consolidated
balance sheets approximated fair value at December 31, 2000, 1999 and 1998.
Investments -- The fair values of investments are primarily based on
quoted market prices.
Oil and Gas Price Hedge Agreements -- The fair values of the oil and gas
price hedges are based on either (a) an internal discounted cash flow
calculation, (b) quotes obtained from the counterparty to the hedge agreement or
(c) quotes provided by brokers.
Foreign Exchange Hedge Agreements -- The fair values of the foreign
exchange agreements are based on quotes obtained from brokers.
Long-term Debt -- The fair values of the fixed-rate long-term debt have
been estimated based on quotes obtained from brokers or by discounting the
principal and interest payments at rates available for debt of similar terms and
maturity. The fair values of the floating-rate long-term debt are estimated to
approximate the carrying amounts due to the fact that the interest rates paid on
such debt are generally set for periods of three months or less.
87
<PAGE> 88
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
TCP Securities -- The fair values of the TCP securities are based on
quoted market prices provided by brokers.
The following table covers Devon's notional volumes and pricing on open
natural gas hedging instruments as of December 31, 2000:
<TABLE>
<CAPTION>
YEAR OF PRODUCTION
----------------------
2001 2002
-------- --------
<S> <C> <C>
Volumes (billion British thermal units) 14,027 3,333
Average price to be received $ 2.18 2.52
</TABLE>
The floating reference prices which Devon will pay the counterparties to
the above gas price hedging instruments include several index prices based upon
the area of the gas production that is hedged. For the hedged Canadian gas
production, these reference prices are primarily based on index prices published
by the Alberta Energy Company ("AECO"). For the hedged U.S. production, the
reference prices are primarily based on index prices published by "Inside
F.E.R.C.'s Gas Market Report" ("Inside FERC") for the Rocky Mountains.
In addition to the above gas hedging instruments, Devon also had a
natural gas basis swap in effect as of December 31, 2000. In this basis swap,
which covers 20,000 MMBtus per day, Devon owes the counterparty the applicable
monthly Colorado Interstate Gas Co. index price as published by Inside FERC,
while the counterparty owes Devon the average NYMEX price for the last three
settlement days of the month less $0.30 per MMBtu. The net difference is settled
by the parties each month. This basis swap continues through August 31, 2004.
Devon has certain foreign currency hedging instruments that offset a
portion of the exposure to currency fluctuations on Canadian oil sales that are
based on U.S. dollar prices. Gains and losses recognized on these foreign
currency hedging instruments are included as increases or decreases to realized
oil sales. As of December 31, 2000, Devon had open foreign currency hedging
instruments in which it will sell $10 million in 2001 at average
Canadian-to-U.S. dollar exchange rates of $0.7102. Under this agreement, Devon
will buy the same amount of dollars at the floating exchange rate.
Devon's 1999 and 1998 consolidated balance sheets include deferred
revenues of $0.4 million and $1.0 million, respectively, for gains realized on
the early termination of commodity and foreign currency hedging instruments in
prior years.
88
<PAGE> 89
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
12. RETIREMENT PLANS
Devon has non-contributory defined benefit retirement plans (the "Basic
Plans") which include U.S. employees meeting certain age and service
requirements. The benefits are based on the employee's years of service and
compensation. Devon's funding policy is to contribute annually the maximum
amount that can be deducted for federal income tax purposes. Rights to amend or
terminate the Basic Plans are retained by Devon.
Devon also has separate defined benefit retirement plans (the
"Supplementary Plans") which are non-contributory and include only certain
employees whose benefits under the Basic Plans are limited by income tax
regulations. The Supplementary Plans' benefits are based on the employee's years
of service and compensation. Devon's funding policy for the Supplementary Plans
is to fund the benefits as they become payable. Rights to amend or terminate the
Supplementary Plans are retained by Devon.
In 2000, Devon established a defined benefit postretirement plan, which
is unfunded, and covers substantially all current employees including former
Santa Fe Snyder and PennzEnergy employees who remained with Devon. Additionally,
Devon assumed responsibility for the PennzEnergy sponsored defined benefit
postretirement plans, which are unfunded. The plans provide medical and life
insurance benefits and are, depending on the type of plan, either contributory
or non-contributory. The accounting for the health care plan anticipates future
cost-sharing changes that are consistent with Devon's expressed intent to
increase, where possible, contributions for future retirees.
89
<PAGE> 90
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
The following table sets forth the plans' benefit obligations, plan
assets, reconciliation of funded status, amounts recognized in the consolidated
balance sheets and the actuarial assumptions used as of December 31, 2000, 1999
and 1998.
<TABLE>
<CAPTION>
PENSION BENEFITS OTHER RETIREMENT BENEFITS
------------------------------------- -------------------------------------
2000 1999 1998 2000 1999 1998
--------- --------- --------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning
of year $ 155,569 63,841 53,859 $ 37,860 8,100 6,600
Service cost 6,736 4,937 2,685 809 838 400
Interest cost 11,283 6,464 4,035 2,330 1,249 500
Participant contributions -- -- -- 147 -- 100
Amendments 4,303 -- 293 (1,985) -- --
Mergers and acquisitions -- 87,751 -- -- 28,659 --
Curtailment gain (3,037) -- -- (346) -- --
Actuarial (gain) loss (2,963) (3,525) 5,573 (3,153) 600 1,000
Benefits paid (7,290) (3,899) (2,604) (3,520) (1,586) (500)
--------- --------- --------- --------- --------- ---------
Benefit obligation at end of year 164,601 155,569 63,841 32,142 37,860 8,100
--------- --------- --------- --------- --------- ---------
Change in plan assets:
Fair value of plan assets at 157,894 41,531 43,136 -- -- --
beginning of year
Actual return on plan assets 2,574 14,808 113 -- -- --
PennzEnergy merger -- 104,181 -- -- -- --
Employer contributions 1,664 1,273 886 3,373 1,486 400
Participant contributions -- -- -- 147 100 100
Benefits paid (7,290) (3,899) (2,604) (3,520) (1,586) (500)
--------- --------- --------- --------- --------- ---------
Fair value of plan assets at end
of year 154,842 157,894 41,531 -- -- --
--------- --------- --------- --------- --------- ---------
Funded status (9,759) 2,325 (22,310) (32,142) (37,860) (8,100)
Unrecognized net actuarial (gain) loss 9,888 (2,723) 9,130 (2,199) 800 200
Unrecognized prior service cost 1,570 1,966 2,322 (1,201) -- --
Unrecognized net transition (asset) (6,331) (400) (500) 1,152 2,100 2,300
obligation
Other -- 100 -- -- 100 100
--------- --------- --------- --------- --------- ---------
Net amount recognized $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500)
========= ========= ========= ========= ========= =========
The net amounts recognized in the
consolidated balance sheets consist of:
(Accrued) prepaid benefit cost $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500)
Additional minimum liability (735) (3,110) (2,987) -- -- --
Intangible asset 508 1,537 1,808 -- -- --
Accumulated other comprehensive loss 227 1,573 1,179 -- -- --
--------- --------- --------- --------- --------- ---------
Net amount recognized $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500)
========= ========= ========= ========= ========= =========
Assumptions:
Discount rate 7.65% 7.34% 6.69% 7.65% 7.32% 6.75%
Expected return on plan assets 8.50% 8.37% 9.35% N/A N/A N/A
Rate of compensation increase 5.00% 4.88% 4.84% 5.00% 4.75% 4.75%
</TABLE>
The benefit obligation for the defined benefit pension plans with
benefit obligations in excess of assets was $87.0 million as of December 31,
2000. The plan assets for these plans at December 31, 2000 totaled $49.9
million.
90
<PAGE> 91
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Net periodic benefit cost included the following components:
<TABLE>
<CAPTION>
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
-------------------------------- -------------------------------
2000 1999 1998 2000 1999 1998
-------- -------- -------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 6,736 4,937 2,685 $ 809 838 400
Interest cost 11,283 6,464 4,035 2,330 1,249 500
Expected return on plan assets (13,247) (6,900) (3,932) -- -- --
Amortization of prior service cost 289 256 256 (37) -- --
Amortization of transition obligation (52) -- -- 170 200 200
Recognized net actuarial (gain) loss 294 320 11 (207) -- --
-------- -------- -------- -------- -------- --------
Net periodic benefit cost $ 5,303 5,077 3,055 $ 3,065 2,287 1,100
======== ======== ======== ======== ======== ========
</TABLE>
For measurement purposes, a 10% annual rate of increase in the per
capita cost of covered health care benefits was assumed in 2000. The rate was
assumed to decrease on a pro-rata basis annually to 5% in the year 2005 and
remain at that level thereafter. Assumed health care cost trend rates have a
significant effect on the amounts reported for the health care plan. A one
percentage-point change in assumed health care cost trend rates would have the
following effects:
<TABLE>
<CAPTION>
ONE-PERCENTAGE ONE-PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Effect on total of service and interest cost components for 2000 $ 230 $ (204)
Effect on year-end 2000 postretirement benefit obligation $ 1,062 $(1,009)
</TABLE>
Devon has incurred certain postemployment benefits to former or inactive
employees who are not retirees. These benefits include salary continuance,
severance and disability health care and life insurance which are accounted for
under SFAS No. 112, "Employer's Accounting for Postemployment Benefits." The
accrued postemployment benefit liability was approximately $12.7 million and
$2.5 million at the end of 2000 and 1999, respectively.
Devon has a 401(k) Incentive Savings Plan which covers all domestic
employees. At its discretion, Devon may match a certain percentage of the
employees' contributions to the plan. The matching percentage is determined
annually by the Board of Directors. Devon's matching contributions to the plan
were $5.0 million, $4.3 million and $2.3 million for the years ended December
31, 2000, 1999 and 1998, respectively.
Devon has defined contribution plans for its Canadian employees. Devon
contributes between 6% and 10% of the employee's base compensation, depending
upon the employee's classification. Such contributions are subject to maximum
amounts allowed under the Income Tax Act (Canada).
Devon also has a savings plan for its Canadian employees. Under the
savings plan, Devon contributes an amount equal to 2% of the base salary of each
employee. The employees may elect to contribute up to 4% of their salary. If
such employee contributions are made, they are matched by additional Devon
contributions.
91
<PAGE> 92
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
During the years 2000, 1999 and 1998, Devon's combined contributions to
the Canadian defined contribution plan and the Canadian savings plan were $2.1
million, $1.9 million and $1.8 million, respectively.
As a result of the Santa Fe Snyder merger, Devon also has a savings plan
with respect to certain personnel employed in foreign locations. The plan is an
unsecured creditor of Devon and at December 31, 2000, 1999 and 1998, Devon's
liability with respect to the plan totaled $0.4 million, $0.4 million and $0.3
million, respectively.
13. COMMITMENTS AND CONTINGENCIES
Devon is party to various legal actions arising in the normal course of
business. Matters that are probable of unfavorable outcome to Devon and which
can be reasonably estimated are accrued. Such accruals are based on information
known about the matters, Devon's estimates of the outcomes of such matters and
its experience in contesting, litigating and settling similar matters. None of
the actions are believed by management to involve future amounts that would be
material to Devon's financial position or results of operations after
consideration of recorded accruals.
Environmental Matters
Devon is subject to certain laws and regulations relating to
environmental remediation activities associated with past operations, such as
the Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA") and similar state statutes. In response to liabilities associated
with these activities, accruals have been established when reasonable estimates
are possible. Such accruals primarily include estimated costs associated with
remediation. Devon has not used discounting in determining its accrued
liabilities for environmental remediation, and no claims for possible recovery
from third party insurers or other parties related to environmental costs have
been recognized in Devon's consolidated financial statements. Devon adjusts the
accruals when new remediation responsibilities are discovered and probable costs
become estimable, or when current remediation estimates must be adjusted to
reflect new information.
Certain of Devon's subsidiaries acquired in the PennzEnergy merger are
involved in matters in which it has been alleged that such subsidiaries are
potentially responsible parties ("PRPs") under CERCLA or similar state
legislation with respect to various waste disposal areas owned or operated by
third parties. As of December 31, 2000, Devon's consolidated balance sheet
included $7.8 million of accrued liabilities, reflected in "Other liabilities,"
for environmental remediation. Devon does not currently believe there is a
reasonable possibility of incurring additional material costs in excess of the
current accruals recognized for such environmental remediation activities. With
respect to the sites in which Devon subsidiaries are PRPs, Devon's conclusion is
based in large part on (i) the availability of defenses to liability, including
the availability of the "petroleum exclusion" under CERCLA and similar state
laws, and/or (ii) Devon's current belief that its share of wastes at a
particular site is or will be viewed by the Environmental Protection Agency or
other PRPs as being de minimis. As a result, Devon's monetary exposure is not
expected to be material.
92
<PAGE> 93
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Royalty Matters
More than 30 oil companies, including Devon, are involved in disputes in
which it is alleged that such companies and related parties underpaid royalty,
overriding royalty and working interests owners in connection with the
production of crude oil. The proceedings include suits in federal court in
Texas, Louisiana, Mississippi and Wyoming that have been consolidated into one
proceeding in Texas. To avoid expensive and protracted litigation, certain
parties, including Devon, have entered into a global settlement agreement which
provides for a settlement of all claims of all members of the settlement class.
The court held a fairness hearing and issued an Amended Final Judgment approving
the settlement on September 10, 1999. However, certain entities have appealed
their objections to the settlement.
Also, pending in federal court in Texas is a similar suit alleging
underpaid royalties to the United States in connection with natural gas and
natural gas liquids produced and sold from United States owned and/or controlled
lands. The claims were filed by private litigants against Devon and numerous
other producers, under the federal False Claims Act. The United States served
notice of its intent to intervene as to certain defendants, but not Devon. Devon
and certain other defendants are challenging the constitutionality of whether a
claim under the federal False Claims Act can be maintained absent government
intervention. Devon believes that it has acted reasonably and paid royalties in
good faith. Devon does not currently believe that it is subject to material
exposure in association with this litigation. As a result, Devon's monetary
exposure in this suit is not expected to be material.
Maersk Rig Contract
In December 1997, the working interest owner partner of Pennzoil
Venezuela Corporation, S.A. ("PVC"), a subsidiary of Devon as a result of the
PennzEnergy merger, entered into a contract with Maersk Jupiter Drilling, S.A.
("Maersk") for the provision of a rig for drilling services relative to the
anticipated drilling program associated with Devon's Block 70/80 in Lake
Maracaibo, Venezuela. The rig was assembled and delivered by Maersk to Lake
Maracaibo where it performed an abbreviated drilling program for both Blocks
68/79 and 70/80. It is currently stacked in Lake Maracaibo. The contract, which
expires October 1, 2001, provides for early termination, with a charge for such
termination which is currently estimated at $42,000 per day with certain
escalation factors for the balance of the term. As of December 31, 2000, Devon's
consolidated balance sheet included accrued liabilities, reflected in "Other
liabilities," for the expected cost to terminate/settle the contract. Devon does
not currently believe there is a reasonable possibility of incurring additional
material costs in excess of the liability recognized for such
termination/settlement of the contract.
93
<PAGE> 94
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Operating Leases
The following is a schedule by year of future minimum rental payments
required under operating leases that have initial or remaining noncancelable
lease terms in excess of one year as of December 31, 2000:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, (IN THOUSANDS)
- ------------------------
<S> <C>
2001 $ 14,394
2002 12,279
2003 11,513
2004 10,779
2005 10,293
Thereafter 20,466
--------
Total minimum lease payments required $ 79,724
========
</TABLE>
Total rental expense for all operating leases is as follows for the
years ended December 31:
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
2000 $ 18,564
1999 $ 24,204
1998 $ 18,319
</TABLE>
Santa Fe Energy Trust
The Santa Fe Energy Trust (the "Trust") was formed in 1992 to hold 6.3
million Depository Units, each consisting of beneficial ownership of one unit of
undivided interest in the Trust and a $20 face amount beneficial ownership
interest in a $1,000 face amount zero coupon U.S. Treasury obligation maturing
on or about February 15, 2008, when the Trust will be liquidated. The assets of
the Trust consist of certain oil and gas properties conveyed to it by Santa Fe
Snyder.
For any calendar quarter ending on or prior to December 31, 2002, the
Trust will receive additional support payments to the extent that it needs such
payments to distribute $0.39 per Depository Unit per quarter. The source of such
support payments is limited to Devon's remaining royalty interest in certain of
the properties conveyed to the Trust. The aggregate amount of the additional
royalty payments (net of any amounts recouped) is limited to $19.4 million on a
revolving basis. If such support payments are made, certain proceeds otherwise
payable to the Trust in subsequent quarters may be reduced to recoup the amount
of such support payments. Through the end of 2000, the Trust had received
support payments totaling $4.2 million and Devon had recouped all such payments.
Depending on various factors, such as sales volumes and prices and the
level of operating costs and capital expenditures incurred, proceeds payable to
the Trust with respect to operations in subsequent quarters may not be
sufficient to make the required quarterly distributions. In such instances,
Devon would be required to make support payments.
94
<PAGE> 95
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
At December 31, 2000 and 1999, accounts payable as shown on the
accompanying consolidated balance sheets included $4.1 million and $3.4 million,
respectively, due to the Trust.
14. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES
Under the full cost method of accounting, the net book value of oil and
gas properties, less related deferred income taxes, may not exceed a calculated
"ceiling." The ceiling limitation is the discounted estimated after-tax future
net revenues from proved oil and gas properties. The ceiling is imposed
separately by country. In calculating future net revenues, current prices and
costs are generally held constant indefinitely. The net book value, less
deferred tax liabilities, is compared to the ceiling on a quarterly and annual
basis. Any excess of the net book value, less deferred taxes, is written off as
an expense. An expense recorded in one period may not be reversed in a
subsequent period even though higher oil and gas prices may have increased the
ceiling applicable to the subsequent period.
During 1999 and 1998, Devon reduced the carrying value of its oil and
gas properties by $476.1 million and $422.5 million, respectively, due to the
full cost ceiling limitations. The after-tax effect of these reductions in 1999
and 1998 were $309.7 million and $280.8 million, respectively.
15. OIL AND GAS OPERATIONS
Costs Incurred
The following tables reflect the costs incurred in oil and gas property
acquisition, exploration, and development activities:
<TABLE>
<CAPTION>
TOTAL
YEAR ENDED DECEMBER 31,
---------------------------------
2000 1999 1998
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes $ 291,355 3,002,269 245,467
Deferred income taxes -- 131,700 21,382
--------- --------- ---------
Total proved, including deferred income taxes $ 291,355 3,133,969 266,849
========= ========= =========
Unproved, excluding deferred income taxes:
Business combinations -- 83,505 5,278
Other acquisitions 55,344 40,583 55,827
Deferred income taxes -- -- 661
--------- --------- ---------
Total unproved, including deferred income taxes $ 55,344 124,088 61,766
========= ========= =========
Exploration costs $ 212,719 157,706 176,014
Development costs $ 636,379 336,126 294,105
</TABLE>
95
<PAGE> 96
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
<TABLE>
<CAPTION>
DOMESTIC
YEAR ENDED DECEMBER 31,
---------------------------------
2000 1999 1998
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes $ 177,072 2,670,237 87,549
Deferred income taxes -- 131,700 --
--------- --------- ---------
Total proved, including deferred income taxes $ 177,072 2,801,937 87,549
========= ========= =========
Unproved, excluding deferred income taxes:
Business combinations -- 81,755 --
Other acquisitions 34,805 27,728 40,364
Deferred income taxes -- -- --
--------- --------- ---------
Total unproved, including deferred income taxes $ 34,805 109,483 40,364
========= ========= =========
Exploration costs $ 117,119 88,171 71,486
Development costs $ 466,090 228,095 149,286
</TABLE>
<TABLE>
<CAPTION>
CANADA
YEAR ENDED DECEMBER 31,
---------------------------
2000 1999 1998
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes $69,736 29,532 107,818
Deferred income taxes -- -- 21,382
------- ------- -------
Total proved, including deferred income taxes $69,736 29,532 129,200
======= ======= =======
Unproved, excluding deferred income taxes:
Business combinations -- -- 5,278
Other acquisitions 16,977 9,155 10,263
Deferred income taxes -- -- 661
------- ------- -------
Total unproved, including deferred income taxes $16,977 9,155 16,202
======= ======= =======
Exploration costs $54,769 37,197 49,928
Development costs $56,654 29,811 75,119
</TABLE>
<TABLE>
<CAPTION>
INTERNATIONAL
YEAR ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes $ 44,547 302,500 50,100
Deferred income taxes -- -- --
-------- -------- --------
Total proved, including deferred income taxes $ 44,547 302,500 50,100
======== ======== ========
Unproved, excluding deferred income taxes:
Business combinations -- 1,750 --
Other acquisitions 3,562 3,700 5,200
Deferred income taxes -- -- --
-------- -------- --------
Total unproved, including deferred income taxes $ 3,562 5,450 5,200
======== ======== ========
Exploration costs $ 40,831 32,338 54,600
Development costs $113,635 78,220 69,700
</TABLE>
Pursuant to the full-cost method of accounting, Devon capitalizes
certain of its general and administrative expenses which are related to property
acquisition, exploration and development activities. Such capitalized expenses,
which are included in the costs shown in the preceding tables, were $61.8
million, $28.9 million and $14.8 million in the years 2000, 1999 and 1998,
respectively.
96
<PAGE> 97
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Due to the tax-free nature of the merger between Santa Fe and Snyder in
May 1999, additional deferred tax liabilities of $131.7 million were allocated
to proved properties. Due to the tax-free nature of the PennzEnergy merger in
August 1999, additional deferred tax liabilities of $346.9 million were recorded
in 1999 and allocated to goodwill.
Results of Operations for Oil and Gas Producing Activities
The following tables include revenues and expenses associated directly
with Devon's oil and gas producing activities. They do not include any
allocation of Devon's interest costs or general corporate overhead and,
therefore, are not necessarily indicative of the contribution to net earnings of
Devon's oil and gas operations. Income tax expense has been calculated by
applying statutory income tax rates to oil and gas sales after deducting costs,
including depreciation, depletion and amortization and after giving effect to
permanent differences.
<TABLE>
<CAPTION>
TOTAL
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998
------------- ----------- --------------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 2,718,445 1,256,872 681,978
Production and operating expenses (597,333) (377,472) (274,618)
Depreciation, depletion and amortization (662,890) (390,117) (230,419)
Amortization of goodwill (41,332) (16,111) --
Reduction of carrying value of oil and gas
properties -- (476,100) (422,500)
Income tax (expense) benefit (571,755) (24,984) 65,515
----------- ----------- -----------
Results of operations for oil and gas producing
activities $ 845,135 (27,912) (180,044)
=========== =========== ===========
Depreciation, depletion and amortization per
equivalent barrel of production $ 5.48 4.46 3.74
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
DOMESTIC
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998
------------- ----------- --------------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 2,167,571 891,670 417,313
Production and operating expenses (462,849) (254,077) (164,612)
Depreciation, depletion and amortization (541,174) (293,841) (154,127)
Amortization of goodwill (41,303) (16,106) --
Reduction of carrying value of oil and gas
properties -- (463,700) (301,400)
Income tax (expense) benefit (445,783) 37,786 63,630
----------- ----------- -----------
Results of operations for oil and gas producing
activities $ 676,462 (98,268) (139,196)
=========== =========== ===========
Depreciation, depletion and amortization per
equivalent barrel of production $ 5.73 4.98 4.41
=========== =========== ===========
</TABLE>
97
<PAGE> 98
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
<TABLE>
<CAPTION>
CANADA
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998
------------- --------- ------------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 303,537 204,501 169,965
Production and operating expenses (64,773) (62,595) (58,506)
Depreciation, depletion and amortization (64,094) (64,514) (43,392)
Reduction of carrying value of oil and gas
properties -- -- --
Income tax (expense) benefit (79,363) (37,736) (37,615)
--------- --------- ---------
Results of operations for oil and gas producing
activities $ 95,307 39,656 30,452
========= ========= =========
Depreciation, depletion and amortization per
equivalent barrel of production $ 4.05 3.56 2.41
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
INTERNATIONAL
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998
------------- --------- ------------
(IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 247,337 160,701 94,700
Production and operating expenses (69,711) (60,800) (51,500)
Depreciation, depletion and amortization (57,622) (31,762) (32,900)
Amortization of goodwill (29) (5) --
Reduction of carrying value of oil and gas
properties -- (12,400) (121,100)
Income tax (expense) benefit (46,609) (25,034) 39,500
--------- --------- ---------
Results of operations for oil and gas producing
activities $ 73,366 30,700 (71,300)
========= ========= =========
Depreciation, depletion and amortization per
equivalent barrel of production $ 5.38 3.06 3.78
========= ========= =========
</TABLE>
16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)
The following supplemental unaudited information regarding the oil and
gas activities of Devon is presented pursuant to the disclosure requirements
promulgated by the Securities and Exchange Commission and SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities."
98
<PAGE> 99
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Quantities of Oil and Gas Reserves
Set forth below is a summary of the changes in the net quantities of
crude oil, natural gas and natural gas liquids reserves for each of the three
years ended December 31, 2000. Approximately 80%, 98% and 96%, of the respective
year-end 2000, 1999 and 1998 domestic proved reserves were calculated by the
independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and
Ryder-Scott Company Petroleum Consultants. The remaining percentages of domestic
reserves are based on Devon's own estimates. All of the year-end 2000 and 1999
Canadian proved reserves were calculated by the independent petroleum
consultants Paddock Lindstrom & Associates. All of the year-end 1998 Canadian
proved reserves were calculated by the independent petroleum consultants of
Paddock Lindstrom & Associates and AMH Group Ltd. All of the international
proved reserves other than Canada as of December 31, 2000 and 1999 were
calculated by the independent petroleum consultants of Ryder-Scott Company
Petroleum Consultants. Of the 1998 international reserves other than Canada, 87%
were calculated by Ryder-Scott Company Petroleum Consultants and 13% were based
on Devon's own estimates.
<TABLE>
<CAPTION>
TOTAL
------------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
---------- ---------- ----------
<S> <C> <C> <C>
Proved reserves as of December 31, 1997 218,741 1,403,204 24,478
Revisions of estimates (9,452) (53,209) 2,391
Extensions and discoveries 27,497 174,527 8,652
Purchase of reserves 30,283 164,429 518
Production (25,628) (198,051) (3,054)
Sale of reserves (5,984) (13,906) (306)
---------- ---------- ----------
Proved reserves as of December 31, 1998 235,457 1,476,994 32,679
Revisions of estimates 12,367 6,888 3,254
Extensions and discoveries 12,809 406,157 4,342
Purchase of reserves 272,412 1,417,747 32,795
Production (31,756) (304,203) (5,111)
Sale of reserves (4,572) (53,956) (142)
---------- ---------- ----------
Proved reserves as of December 31, 1999 496,717 2,949,627 67,817
Revisions of estimates (4,135) 99,223 3,312
Extensions and discoveries 33,939 601,317 6,041
Purchase of reserves 24,145 301,144 33
Production (42,561) (426,146) (7,400)
Sale of reserves (48,861) (66,981) (8,046)
---------- ---------- ----------
Proved reserves as of December 31, 2000 459,244 3,458,184 61,757
========== ========== ==========
Proved developed reserves as of:
December 31, 1997 187,758 1,204,874 21,832
December 31, 1998 179,746 1,282,447 19,381
December 31, 1999 301,149 2,500,985 52,102
December 31, 2000 261,432 2,631,267 46,256
</TABLE>
99
<PAGE> 100
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
<TABLE>
<CAPTION>
DOMESTIC
------------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
---------- ---------- ----------
<S> <C> <C> <C>
Proved reserves as of December 31, 1997 128,402 784,124 18,172
Revisions of estimates (19,849) 10,919 219
Extensions and discoveries 3,042 108,308 371
Purchase of reserves 1,813 58,655 --
Production (12,257) (121,419) (2,468)
Sale of reserves -- (2,300) --
---------- ---------- ----------
Proved reserves as of December 31, 1998 101,151 838,287 16,294
Revisions of estimates 23,986 35,751 3,407
Extensions and discoveries 1,890 230,059 2,794
Purchase of reserves 142,908 1,399,634 32,709
Production (17,822) (221,061) (4,396)
Sale of reserves (2,689) (8,284) (4)
---------- ---------- ----------
Proved reserves as of December 31, 1999 249,424 2,274,386 50,804
Revisions of estimates (3,196) 100,844 4,296
Extensions and discoveries 20,430 504,977 5,092
Purchase of reserves 20,418 52,929 9
Production (28,562) (355,087) (6,702)
Sale of reserves (32,977) (56,742) (7,981)
---------- ---------- ----------
Proved reserves as of December 31, 2000 225,537 2,521,307 45,518
========== ========== ==========
Proved developed reserves as of:
December 31, 1997 115,559 646,882 16,789
December 31, 1998 92,931 663,864 14,777
December 31, 1999 214,267 1,959,531 48,237
December 31, 2000 192,190 2,087,287 42,155
</TABLE>
100
<PAGE> 101
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
<TABLE>
<CAPTION>
CANADA
------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
-------- -------- --------
<S> <C> <C> <C>
Proved reserves as of December 31, 1997 36,139 582,780 5,106
Revisions of estimates 6,283 (70,402) (248)
Extensions and discoveries 655 62,519 81
Purchase of reserves 8,170 105,774 518
Production (6,257) (67,158) (566)
Sale of reserves (5,984) (11,606) (306)
-------- -------- --------
Proved reserves as of December 31, 1998 39,006 601,907 4,585
Revisions of estimates (2,828) (41,044) (268)
Extensions and discoveries 219 52,698 448
Purchase of reserves 2,796 11,890 86
Production (5,178) (73,561) (700)
Sale of reserves (1,883) (45,672) (138)
-------- -------- --------
Proved reserves as of December 31, 1999 32,132 506,218 4,013
Revisions of estimates 2,872 (5,854) 343
Extensions and discoveries 2,787 64,566 571
Purchase of reserves 3,597 27,224 24
Production (4,760) (62,284) (682)
Sale of reserves (136) (6,361) (65)
-------- -------- --------
Proved reserves as of December 31, 2000 36,492 523,509 4,204
======== ======== ========
Proved developed reserves as of
December 31, 1997 35,199 522,292 5,043
December 31, 1998 33,215 583,583 4,504
December 31, 1999 29,268 501,376 3,865
December 31, 2000 29,721 507,703 4,072
</TABLE>
101
<PAGE> 102
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
<TABLE>
<CAPTION>
INTERNATIONAL
------------------------------------------
NATURAL
GAS
OIL GAS LIQUIDS
(MBBLS) (MMCF) (MBBLS)
-------- -------- --------
<S> <C> <C> <C>
Proved reserves as of December 31, 1997 54,200 36,300 1,200
Revisions of estimates 4,114 6,274 2,420
Extensions and discoveries 23,800 3,700 8,200
Purchase of reserves 20,300 -- --
Production (7,114) (9,474) (20)
Sale of reserves -- -- --
-------- -------- --------
Proved reserves as of December 31, 1998 95,300 36,800 11,800
Revisions of estimates (8,791) 12,181 115
Extensions and discoveries 10,700 123,400 1,100
Purchase of reserves 126,708 6,223 --
Production (8,756) (9,581) (15)
Sale of reserves -- -- --
-------- -------- --------
Proved reserves as of December 31, 1999 215,161 169,023 13,000
Revisions of estimates (3,811) 4,233 (1,327)
Extensions and discoveries 10,722 31,774 378
Purchase of reserves 130 220,991 --
Production (9,239) (8,775) (16)
Sale of reserves (15,748) (3,878) --
-------- -------- --------
Proved reserves as of December 31, 2000 197,215 413,368 12,035
======== ======== ========
Proved developed reserves as of
December 31, 1997 37,000 35,700 --
December 31, 1998 53,600 35,000 100
December 31, 1999 57,614 40,078 --
December 31, 2000 39,521 36,277 29
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows
The accompanying tables reflect the standardized measure of discounted
future net cash flows relating to Devon's interest in proved reserves:
<TABLE>
<CAPTION>
TOTAL
------------------------------------------------------
DECEMBER 31,
------------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows $ 40,594,130 18,494,929 5,114,485
Future costs:
Development (1,634,888) (1,506,678) (495,977)
Production (8,198,640) (6,270,893) (2,091,688)
Future income tax expense (9,087,923) (1,928,398) (196,475)
------------ ------------ ------------
Future net cash flows 21,672,679 8,788,960 2,330,345
10% discount to reflect timing of cash flows (9,200,492) (4,020,526) (916,757)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 12,472,187 4,768,434 1,413,588
============ ============ ============
</TABLE>
102
<PAGE> 103
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
<TABLE>
<CAPTION>
DOMESTIC
------------------------------------------------------
DECEMBER 31,
------------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows $ 29,143,762 11,362,918 2,718,030
Future costs:
Development (915,969) (750,497) (162,715)
Production (5,660,966) (3,894,271) (1,123,932)
Future income tax expense (6,345,941) (1,071,699) (117,912)
------------ ------------ ------------
Future net cash flows 16,220,886 5,646,451 1,313,471
10% discount to reflect timing of cash flows (6,591,538) (2,335,312) (503,689)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 9,629,348 3,311,139 809,782
============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
CANADA
---------------------------------------------------
DECEMBER 31,
---------------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows $ 5,686,629 1,666,358 1,333,655
Future costs:
Development (84,492) (66,631) (85,362)
Production (616,605) (514,825) (491,256)
Future income tax expense (1,967,441) (204,290) (39,563)
----------- ----------- -----------
Future net cash flows 3,018,091 880,612 717,474
10% discount to reflect timing of cash flows (1,240,934) (320,722) (279,568)
----------- ----------- -----------
Standardized measure of
discounted future net cash flows $ 1,777,157 559,890 437,906
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
INTERNATIONAL
---------------------------------------------------
DECEMBER 31,
---------------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows $ 5,763,739 5,465,653 1,062,800
Future costs:
Development (634,427) (689,550) (247,900)
Production (1,921,069) (1,861,797) (476,500)
Future income tax expense (774,541) (652,409) (39,000)
----------- ----------- -----------
Future net cash flows 2,433,702 2,261,897 299,400
10% discount to reflect timing of cash flows (1,368,020) (1,364,492) (133,500)
----------- ----------- -----------
Standardized measure of
discounted future net cash flows $ 1,065,682 897,405 165,900
=========== =========== ===========
</TABLE>
Future cash inflows are computed by applying year-end prices (averaging
$23.77 per barrel of oil, adjusted for transportation and other charges, $8.04
per Mcf of gas and $29.80 per barrel of natural gas liquids at December 31,
2000) to the year-end quantities of proved reserves, except in those instances
where fixed and determinable price changes are provided by contractual
arrangements in existence at year-end. Subsequent to December 31, 2000, the
price of natural gas has declined. The average price in February 2001 for gas
sold at market sensitive prices in North America was approximately one-third
below the year-end 2000 price.
103
<PAGE> 104
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing proved oil and gas
reserves at the end of the year, based on year-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate
statutory tax rates to the future pre-tax net cash flows relating to proved
reserves, net of the tax basis of the properties involved. The future income tax
expenses give effect to permanent differences and tax credits, but do not
reflect the impact of future operations.
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
Principal changes in the standardized measure of discounted future net
cash flows attributable to Devon's proved reserves are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning balance $ 4,768,434 1,413,588 1,680,676
Sales of oil, gas and natural gas
liquids, net of production costs (2,010,675) (879,400) (407,360)
Net changes in prices and
production costs 9,753,295 1,737,640 (743,193)
Extensions, discoveries, and improved
recovery, net of future
development costs 2,742,182 315,932 280,414
Purchase of reserves, net of future
development costs 618,134 2,881,881 223,055
Development costs incurred during
the period which reduced future
development costs 182,533 233,880 284,999
Revisions of quantity estimates 420,250 (62,821) (181,314)
Sales of reserves in place (818,602) (77,707) (36,565)
Accretion of discount 581,172 146,904 201,465
Net change in income taxes (4,221,575) (929,237) 305,317
Other, primarily changes in timing 457,039 (12,226) (193,906)
------------ ------------ ------------
Ending balance $ 12,472,187 4,768,434 1,413,588
============ ============ ============
</TABLE>
17. SEGMENT INFORMATION
Devon manages its business by country. As such, Devon identifies its
segments based on geographic areas. Devon has three reportable segments: its
operations in the U.S., its operations in Canada, and its international
operations outside of North America. Substantially all of these segments'
operations involve oil and gas producing activities. Certain information
regarding such activities for each segment is included in Notes 15 and 16.
Following is certain financial information regarding Devon's segments
for 2000, 1999 and 1998. The revenues reported are all from external customers.
104
<PAGE> 105
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
17. SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
U.S. CANADA INTERNATIONAL TOTAL
---------- ---------- ------------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 2000:
Current assets $ 644,685 79,372 210,080 934,137
Property and equipment, net of accumulated 3,639,673 585,517 684,346 4,909,536
depreciation, depletion and amortization
Other assets 964,934 89 51,782 1,016,805
---------- ---------- ---------- ----------
Total assets $5,249,292 664,978 946,208 6,860,478
========== ========== ========== ==========
Current liabilities 448,994 74,154 105,839 628,987
Long-term debt 1,902,184 146,652 -- 2,048,836
Deferred tax liabilities (assets) 536,935 68,578 21,313 626,826
Other liabilities 258,812 1,831 17,582 278,225
Stockholders' equity 2,102,367 373,763 801,474 3,277,604
---------- ---------- ---------- ----------
Total liabilities and stockholders' equity $5,249,292 664,978 946,208 6,860,478
========== ========== ========== ==========
YEAR ENDED DECEMBER 31, 2000:
REVENUES
Oil sales $ 726,897 116,427 235,435 1,078,759
Gas sales 1,304,626 169,032 11,563 1,485,221
Natural gas liquids sales 136,048 18,078 339 154,465
Other 58,569 4,984 2,105 65,658
---------- ---------- ---------- ----------
Total revenues 2,226,140 308,521 249,442 2,784,103
---------- ---------- ---------- ----------
COSTS AND EXPENSES
Lease operating expenses 319,154 52,340 69,286 440,780
Transportation costs 41,956 11,353 -- 53,309
Production taxes 101,739 1,080 425 103,244
Depreciation, depletion and amortization of
property and equipment 565,633 64,735 62,972 693,340
Amortization of goodwill 41,303 -- 29 41,332
General and administrative expenses 80,358 10,380 2,270 93,008
Expenses related to mergers 60,373 -- -- 60,373
Interest expense 143,169 10,140 1,020 154,329
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt -- 2,408 -- 2,408
---------- ---------- ---------- ----------
Total costs and expenses 1,353,685 152,436 136,002 1,642,123
---------- ---------- ---------- ----------
Earnings before income tax expense 872,455 156,085 113,440 1,141,980
INCOME TAX EXPENSE
Current 112,757 2,268 15,768 130,793
Deferred 185,231 67,318 28,296 280,845
---------- ---------- ---------- ----------
Total income tax expense 297,988 69,586 44,064 411,638
---------- ---------- ---------- ----------
Net earnings $ 574,467 86,499 69,376 730,342
========== ========== ========== ==========
Capital expenditures $ 893,087 202,673 184,372 1,280,132
========== ========== ========== ==========
</TABLE>
105
<PAGE> 106
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
17. SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
U.S. CANADA INTERNATIONAL TOTAL
----------- ----------- ------------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 1999:
Current assets $ 391,328 69,279 129,687 590,294
Property and equipment, net of accumulated
depreciation, depletion and amortization 3,424,415 467,465 531,540 4,423,420
Other assets 944,958 98 137,590 1,082,646
----------- ----------- ----------- -----------
Total assets $ 4,760,701 536,842 798,817 6,096,360
=========== =========== =========== ===========
Current liabilities 356,944 44,989 65,411 467,344
Long-term debt 2,077,180 339,341 -- 2,416,521
Deferred tax liabilities (assets) 340,514 1,733 (18,182) 324,065
Other liabilities 317,706 3,098 46,306 367,110
Stockholders' equity 1,668,357 147,681 705,282 2,521,320
----------- ----------- ----------- -----------
Total liabilities and stockholders' $ 4,760,701 536,842 798,817 6,096,360
=========== =========== =========== ===========
equity
YEAR ENDED DECEMBER 31, 1999:
REVENUES
Oil sales $ 332,219 80,298 148,501 561,018
Gas sales 501,841 114,128 11,900 627,869
Natural gas liquids sales 57,610 10,075 300 67,985
Other 14,574 4,652 1,370 20,596
----------- ----------- ----------- -----------
Total revenues 906,244 209,153 162,071 1,277,468
----------- ----------- ----------- -----------
COSTS AND EXPENSES
Lease operating expenses 188,576 49,831 60,400 298,807
Transportation costs 22,524 11,401 -- 33,925
Production taxes 42,977 1,363 400 44,740
Depreciation, depletion and amortization
of property and equipment 309,292 65,176 31,907 406,375
Amortization of goodwill 16,106 -- 5 16,111
General and administrative expenses 68,807 12,189 (351) 80,645
Expenses related to mergers 16,800 -- -- 16,800
Interest expense 83,679 24,945 989 109,613
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt -- (13,154) -- (13,154)
Distributions on preferred securities of
subsidiary trust 6,884 -- -- 6,884
Reduction of carrying value of oil and
gas properties 463,700 -- 12,400 476,100
----------- ----------- ----------- -----------
Total costs and expenses 1,219,345 151,751 105,750 1,476,846
----------- ----------- ----------- -----------
Earnings (loss) before income tax expense
(benefit) and extraordinary item (313,101) 57,402 56,321 (199,378)
INCOME TAX EXPENSE (BENEFIT)
Current 15,348 2,908 4,800 23,056
Deferred (119,881) 26,654 20,737 (72,490)
----------- ----------- ----------- -----------
Total income tax expense (benefit) (104,533) 29,562 25,537 (49,434)
----------- ----------- ----------- -----------
Net earnings (loss) before extraordinary item (208,568) 27,840 30,784 (149,944)
Extraordinary loss (4,200) -- -- (4,200)
----------- ----------- ----------- -----------
Net earnings (loss) $ (212,768) 27,840 30,784 (154,144)
=========== =========== =========== ===========
Capital expenditures $ 686,669 91,853 104,898 883,420
=========== =========== =========== ===========
</TABLE>
106
<PAGE> 107
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
17. SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
U.S. CANADA INTERNATIONAL TOTAL
----------- ----------- ------------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 1998:
Current assets $ 90,698 53,550 82,400 226,648
Property and equipment, net of accumulated
depreciation, depletion and amortization 991,040 465,488 167,000 1,623,528
Deferred tax assets (liabilities) (36,093) 24,174 66,300 54,381
-----------
Other assets 17,126 1,454 7,400 25,980
----------- ----------- ----------- -----------
Total assets $ 1,062,771 544,666 323,100 1,930,537
=========== =========== =========== ===========
Current liabilities 119,132 55,624 45,100 219,856
Long-term debt 365,600 370,271 -- 735,871
Other liabilities 67,487 5,760 2,300 75,547
TCP Securities 149,500 -- -- 149,500
Stockholders' equity 361,052 113,011 275,700 749,763
----------- ----------- ----------- -----------
Total liabilities and stockholders' equity $ 1,062,771 544,666 323,100 1,930,537
=========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1998:
REVENUES
Oil sales $ 152,297 75,493 82,200 309,990
Gas sales 245,145 89,828 12,300 347,273
Natural gas liquids sales 19,871 4,644 200 24,715
Other 9,294 13,754 1,200 24,248
----------- ----------- ----------- -----------
Total revenues 426,607 183,719 95,900 706,226
----------- ----------- ----------- -----------
COSTS AND EXPENSES
Lease operating expenses 127,451 47,910 51,200 226,561
Transportation costs 14,251 8,935 -- 23,186
Production taxes 22,910 1,661 300 24,871
Depreciation, depletion and amortization 165,654 44,590 32,900 243,144
of property and equipment
General and administrative expenses 35,752 12,502 (2,800) 45,454
Expenses related to mergers 3,064 10,085 -- 13,149
Interest expense 20,558 21,974 1,000 43,532
Deferred effect of changes in foreign currency
exchange rate on subsidiary's long-term debt -- 16,104 -- 16,104
Distributions on preferred securities of
subsidiary trust 9,717 -- -- 9,717
Reduction of carrying value of oil and
gas properties 301,400 -- 121,100 422,500
----------- ----------- ----------- -----------
Total costs and expenses 700,757 163,761 203,700 1,068,218
----------- ----------- ----------- -----------
Earnings (loss) before income tax expense
(benefit) (274,150) 19,958 (107,800) (361,992)
INCOME TAX EXPENSE (BENEFIT)
Current (7,588) 1,975 1,900 (3,713)
Deferred (92,360) 11,166 (41,200) (122,394)
----------- ----------- ----------- -----------
Total income tax expense (benefit) (99,948) 13,141 (39,300) (126,107)
----------- ----------- ----------- -----------
Net earnings (loss) $ (174,202) 6,817 (68,500) (235,885)
=========== =========== =========== ===========
Capital expenditures $ 347,634 205,178 160,000 712,812
=========== =========== =========== ===========
</TABLE>
107
<PAGE> 108
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Following is a summary of the unaudited interim results of operations
for the years ended December 31, 2000 and 1999.
<TABLE>
<CAPTION>
2000
-----------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH FULL
QUARTER QUARTER QUARTER QUARTER YEAR
--------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 548,351 635,777 695,475 838,842 2,718,445
Total revenues $ 560,416 648,484 725,141 850,062 2,784,103
Net earnings (loss) $ 105,187 153,334 164,912 306,909 730,342
Net earnings (loss) per common share:
Basic $ 0.81 1.19 1.27 2.37 5.66
Diluted $ 0.80 1.17 1.22 2.27 5.50
</TABLE>
<TABLE>
<CAPTION>
1999
-----------------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH FULL
QUARTER QUARTER QUARTER QUARTER YEAR
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Oil, gas and natural gas liquids sales $ 159,632 221,129 380,562 495,549 1,256,872
Total revenues $ 162,205 224,048 385,972 505,243 1,277,468
Net earnings (loss) $ 6,580 (286,491) 50,852 74,915 (154,144)
Net earnings (loss) per common share:
Basic $ 0.09 (3.55) 0.50 0.59 (1.68)
Diluted $ 0.09 (3.55) 0.48 0.57 (1.68)
</TABLE>
The third and fourth quarters of 2000 include $57.2 million and $3.2
million, respectively, of expenses incurred in connection with the Santa Fe
Snyder merger. The after-tax effect of these expenses was $35.3 million and $1.9
million, respectively. The per share effect of these quarterly reductions was
$0.28 and $0.01, respectively.
The second and fourth quarters of 1999 include pre-tax reductions of the
carrying value of oil and gas properties of $463.8 million and $12.3 million,
respectively. The after-tax effects of these quarterly reductions were $301.7
million and $8.0 million, respectively. The per share effect of these quarterly
reductions were $3.74 and $0.06, respectively. The second quarter of 1999
includes $16.8 million of expenses incurred in connection with the Snyder
merger. The after-tax effect of these expenses was $10.9 million, or $0.14 per
share.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
108
<PAGE> 109
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item 10 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities and
Exchange Act of 1934 not later than April 30, 2001.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities and
Exchange Act of 1934 not later than April 30, 2001.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities and
Exchange Act of 1934 not later than April 30, 2001.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated herein by
reference to the definitive Proxy Statement to be filed by the Company pursuant
to Regulation 14A of the General Rules and Regulations under the Securities and
Exchange Act of 1934 not later than April 30, 2001.
109
<PAGE> 110
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial
Statements and Consolidated Financial Statement
Schedules appearing at Item 8 on Page 53 of this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they
are inapplicable, or the required information has been
included in the consolidated financial statements or
notes thereto.
3. Exhibits
2.1 Agreement and Plan of Merger by and among
Registrant, Devon Merger Co. and Santa Fe Snyder
Corporation dated as of May 25, 2000
(incorporated by reference to Registrant's
Registration Statement on Form S-4, File No.
333-39908).
2.2 Amendment No. One, dated as of July 11, 2000, to
Agreement and Plan of Merger by and among
Registrant, Devon Merger Co. and Santa Fe Snyder
Corporation dated as of May 25, 2000
(incorporated by reference to Exhibit 2.1 to
Registrant's Form 8-K filed on July 12, 2000).
2.3 Amended and Restated Agreement and Plan of
Merger among Registrant, Devon Energy
Corporation (Oklahoma), Devon Oklahoma
Corporation and PennzEnergy Company dated as of
May 19, 1999 (incorporated by reference to
Exhibit 2.1 to Registrant's Form S-4, File No.
333-82903).
2.4 Amended and Restated Combination Agreement
between Registrant and Northstar Energy
Corporation dated as of June 29, 1998
(incorporated by reference to Annex B to
Registrant's definitive proxy statement for a
special meeting of shareholders, filed November
6, 1998).
3.1 Registrant's Restated Certificate of
Incorporation (incorporated by reference to
Exhibit 3 to Registrant's Form 8-K filed August
18, 1999).
110
<PAGE> 111
3.2 Registrant's Amended and Restated Bylaws
(incorporated by reference to Exhibit 3.2 to
Registrant's definitive proxy statement for a
special meeting of shareholders filed July 21,
2000).
4.1 Form of Common Stock Certificate (incorporated
by reference to Exhibit 4.1 to Registrant's Form
8-K filed on August 18, 1999).
4.2 Registration Rights Agreement dated as of June
22, 2000 by and among Registrant and Morgan
Stanley & Co. Incorporated and Salomon Smith
Barney Inc. relating to Registrant's Zero Coupon
Convertible Senior Debentures due 2020
(incorporated by reference to Exhibit 4.1 to
Registrant's Form 8-K filed July 12, 2000).
4.3 Rights Agreement dated as of August 17, 1999
between Registrant and BankBoston, N.A.
(incorporated by reference to Exhibit 4.2 to
Registrant's Form 8-K filed on August 18, 1999).
4.4 Amendment to Rights Agreement dated as of May
25, 2000 between Registrant and Fleet National
Bank (f/k/a BankBoston, N.A.) (incorporated by
reference to Exhibit 4.2 to Registrant's
definitive proxy statement for a special meeting
of shareholders filed July 21, 2000).
4.5 Registration Rights Agreement dated December 31,
1996, by and between Registrant and Kerr-McGee
Corporation (incorporated by reference to
Exhibit 4.4 to Registrant's Form 8-K filed on
January 14, 1997).
4.6 Certificate of Designations of Series A Junior
Participating Preferred Stock of Registrant
(incorporated by reference to Exhibit 4.3 to
Registrant's Form 8-K filed on August 18, 1999).
4.7 Certificate of Designations of the 6.49%
Cumulative Preferred Stock, Series A of
Registrant (incorporated by reference to Exhibit
4(g) to Registrant's Form 8-K filed on August
18, 1999).
4.8 Description of Capital Stock of Registrant
(incorporated by reference to Exhibit 4.9 to
Registrant's Form 8-K filed on August 18, 1999).
4.9 Restated Declaration of Trust of Devon Financing
Trust II and Corrected Certificate of Trust of
Devon Financing Trust II (incorporated by
reference to Exhibits 4.5 and 4.6 of
Registrant's Registration Statement on Form S-3,
File Nos. 333-50034 and 333-50034-01).
4.10 Indenture dated as of June 27, 2000 between
Registrant and The Bank of New York, setting
forth the terms of the Zero Coupon
111
<PAGE> 112
Convertible Senior Debentures due 2020
(incorporated by reference to Exhibit 4.2 to
Registrant's Form 8-K filed July 12, 2000).
4.11 Senior Indenture dated as of June 1, 1999
between Santa Fe Snyder and The Bank of New
York, as Trustee, relating to Santa Fe Snyder
Corporation's 8.05% Senior Notes due 2004
(incorporated by reference to Exhibit 4.1 to
Santa Fe Snyder Corporation's Form 8-K filed on
June 15, 1999).
4.12 First Supplemental Indenture dated as of June
14, 1999 to Senior Indenture dated June 1, 1999
between Santa Fe Snyder and The Bank of New
York, as Trustee, relating to Santa Fe Snyder's
8.05% Senior Notes due 2004 (incorporated by
reference to Exhibit 4.2 to Santa Fe Snyder
Corporation's Form 8-K filed on June 15, 1999).
4.13 Indenture dated as of June 10, 1997 between
Snyder Oil Corporation (as predecessor by merger
to Santa Fe Snyder Corporation) and Texas
Commerce Bank National Association relating to
Snyder Oil Corporation's 8.75% Senior
Subordinated Notes due 2007 (incorporated by
reference to Exhibit 4.1 to Snyder Oil
Corporation's Form 8-K dated June 10, 1997, File
No. 1-10509).
4.14 First Supplemental Indenture dated as of June
10, 1997 between Snyder Oil Corporation and
Texas Commerce Bank National Association
relating to Snyder Oil Corporation's 8.75%
Senior Subordinated Notes due 2007 (incorporated
by reference to Exhibit 4.2 to Snyder Oil
Corporation's Form 8-K dated June 10, 1997, File
No. 1-10509).
4.15 Second Supplemental Indenture dated as of June
10, 1997 between Snyder Oil Corporation and
Texas Commerce Bank National Association
relating to Snyder Oil Corporation's 8.75%
Senior Subordinated Notes due 2007 (incorporated
by reference to Exhibit 4.2 to Snyder Oil
Corporation's Form 8-K dated June 10, 1997, File
No. 1-10509).
4.16 Indenture dated as of December 15, 1992 between
Registrant (as successor by merger to
PennzEnergy Company, formerly Pennzoil Company)
and Texas Commerce Bank National Association,
Trustee setting forth the terms of the 4.90%
Exchangeable Senior Debentures due 2008 and the
4.95% Exchangeable Senior Debentures due 2008
(incorporated by reference to Exhibit 4(o) to
Pennzoil Company's Form 10-K filed March 10,
1993 (SEC File No. 1-5591)).
4.17 Third Supplemental Indenture dated as of August
3, 1998 to
112
<PAGE> 113
Indenture dated as of December 15, 1992 among
Registrant (as successor by merger to
PennzEnergy Company, formerly Pennzoil Company)
and Chase Bank of Texas, National Association,
supplements the terms of the 4.90% Exchangeable
Senior Debentures due 2008 (incorporated by
reference to Exhibit 4(g) to PennzEnergy
Company's Form 10-K for the year ended December
31, 1998).
4.18 Fourth Supplemental Indenture dated as of August
3, 1998 to Indenture dated as of December 15,
1992 among Registrant (as successor by merger to
PennzEnergy Company, formerly Pennzoil Company)
and Chase Bank of Texas, National Association,
supplements the terms of the 4.95% Exchangeable
Senior Debentures due 2008 (incorporated by
reference to Exhibit 4(h) to PennzEnergy
Company's Form 10-K for the year ended December
31, 1998).
4.19 Fifth Supplemental Indenture dated as of August
17, 1999 to Indenture dated as of December 15,
1992 among Registrant (as successor by merger to
PennzEnergy Company, formerly Pennzoil Company)
and Chase Bank of Texas, National Association
supplements the terms of the 4.90% Exchangeable
Senior Debentures due 2008 and the 4.95%
Exchangeable Senior Debentures due 2008
(incorporated by reference to Exhibit 4.7 to
Registrant's Form 8-K filed on August 18, 1999).
4.20 Indenture dated as of February 15, 1986 among
Registrant (as successor by merger to
PennzEnergy Company, formerly Pennzoil Company)
and Mellon Bank, N.A. (incorporated by reference
to Exhibit 4(a) to Pennzoil Company's Form 10-Q
for the quarter ended June 30, 1986 (SEC File
No. 1-5591).
4.21 First Supplemental Indenture dated as of August
17, 1999 to Indenture dated as of February 15,
1986 among Registrant (as successor by merger to
PennzEnergy Company, formerly Pennzoil Company)
and Chase Bank of Texas, National Association
supplementing the terms of the 10.625%
Debentures due 2001, 10.125% Debentures due
2009, 9.625% Notes due 1999 and 10.25%
Debentures due 2005 (incorporated by reference
to Exhibit 4.8 to Registrant's Form 8-K filed on
August 18, 1999).
4.22 Support Agreement, dated December 10, 1998,
between the Registrant and Northstar Energy
Corporation (incorporated by reference to
Exhibit 4.1 to Devon Energy Corporation
(Oklahoma)'s (predecessor to Registrant) Form
8-K dated as of December 11, 1998).
4.23 Amending Support Agreement dated August 17,
1999, between the
113
<PAGE> 114
Registrant and Northstar Energy Corporation
(incorporated by reference to Exhibit 4.5 to
Registrant's Form 8-K filed on August 18, 1999).
4.24 Exchangeable Share Provisions (incorporated by
reference to Exhibit 4.2 to Registrant's Form
8-K filed December 23, 1998).
4.25 Amended Exchangeable Share Provisions dated as
of August 17, 1999 (incorporated by reference to
Exhibit 4.17 to Registrant's Form 10-K for the
year ended December 31, 1999).
9.1 Voting and Exchange Trust Agreement, dated
December 10, 1998, by and between the
Registrant, Northstar Energy Corporation and
CIBC Mellon Trust Company (incorporated by
reference to Exhibit 9 to Registrant's Form 8-K
filed on December 23, 1998).
9.2 Amending Voting and Exchange Trust Agreement,
dated as of August 17, 1999, by and between
Registrant, Northstar Energy Corporation and
CIBC Mellon Trust Company (incorporated by
reference to Exhibit 9 to Registrant's Form 8-K
filed on August 18, 1999).
10.1 U.S. Credit Agreement, dated August 29, 2000
among the Registrant, as U.S. Borrower, Bank of
America, N.A., as Administrative Agent, Banc of
America Securities, LLC, as Lead Arranger, Banc
One Capital Markets, Inc., as Syndication Agent,
The Chase Manhattan Bank, as Documentation
Agent, First Union National Bank, as
Co-Documentation Agent, and Certain Financial
Institutions, as Lenders for the $725 million
credit facility.
10.2 Canadian Credit Agreement dated August 29, 2000,
among Northstar Energy Corporation and Devon
Energy Canada Corporation, as Canadian
Borrowers, Bank of America Canada, as
Administrative Agent, Banc of America
Securities, LLC, as Lead Arranger, BancOne
Capital Markets, Inc., as Syndication Agent, The
Chase Manhattan Bank, as Documentation Agent,
First Union National Bank, as Co-Documentation
Agent, and Certain Financial Institutions, as
Lenders for the $275 million credit facility.
10.3 Devon Energy Corporation Restricted Stock Bonus
Plan (incorporated by reference to Registrant's
Form S-8 filed on August 29, 2000, File No.
333-44702).*
10.4 Santa Fe Snyder Corporation 1999 Stock
Compensation Retention Plan (incorporated by
reference to Exhibit 10(a) to Santa Fe Snyder
Corporation's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1999).*
114
<PAGE> 115
10.5 PennzEnergy Company 1998 Incentive Plan
(incorporated by reference to Exhibit 4.3 to
Pennzoil Company's Form S-8 filed on December
29, 1998 SEC No. 333-69845).*
10.6 Santa Fe Energy Resources Incentive Compensation
Plan, as amended (incorporated by reference to
exhibit 10(a) to Santa Fe Energy Resources,
Inc.'s Annual Report on Form 10-K for the year
ended December 31, 1998).*
10.7 Devon Energy Corporation 1997 Stock Option Plan
(incorporated by reference to Exhibit A to
Registrant's Proxy Statement for the 1997 Annual
Meeting of Shareholders filed on April 3,
1997).*
10.8 Pennzoil Company 1997 Incentive Plan
(incorporated by reference to Exhibit A to
Pennzoil Company definitive proxy material filed
on March 21, 1997, SEC File No. 1-5591).*
10.9 Devon Energy Corporation 1993 Stock Option Plan
(incorporated by reference to Exhibit A to
Registrant's Proxy Statement for the 1993 Annual
Meeting of Shareholders filed on May 6, 1993).*
10.10 Pennzoil Company 1993 Conditional Stock Award
Program (incorporated by reference to Exhibit B
to Pennzoil Company's definitive proxy material
filed on April 13, 1993, File No. 1-5591).*
10.11 Pennzoil Company 1992 Stock Option Plan
(incorporated by reference to Exhibit A to
Pennzoil Company definitive proxy material filed
on April 13, 1993, File No. 1-5591).*
10.12 Santa Fe Energy Resources Deferred Compensation
Plan, effective as of January 1, 1991, as
amended and restated, effective February 1, 1994
(incorporated by reference to Exhibit 10(p) to
Santa Fe Energy Resources, Inc.'s Annual Report
on Form 10-K for the year ended December 31,
1993).*
10.13 Pennzoil Company 1990 Conditional Stock Award
Program (incorporated by reference to Exhibit B
to Pennzoil Company's definitive proxy material
filed on April 26, 1990, File No. 1-5591).*
10.14 Pennzoil Company 1990 Stock Option Plan
(incorporated by reference to Pennzoil Company's
definitive proxy material filed on April 26,
1990, File No. 1-5591).*
10.15 Santa Fe Energy Resources 1990 Incentive Stock
Compensation Plan, Third Amendment and
Restatement (incorporated by reference to
Exhibit 10(a) to Santa Fe Energy Resources,
Inc.'s Quarterly Report on Form 10-Q for the
quarter ended March 31, 1996).*
115
<PAGE> 116
10.16 Santa Fe Energy Resources, Inc. Supplemental
Retirement Plan effective as of December 4, 1990
(incorporated by reference to Exhibit 10(h) to
Santa Fe Energy Resources, Inc.'s Annual Report
on Form 10-K for the year ended December 31,
1996).*
10.17 Devon Energy Corporation 1988 Stock Option Plan
(incorporated by reference to Exhibit 10.4 to
Registrant's Registration Statement on Form S-8
filed on August 19, 1999, SEC File No.
333-85553).*
10.18 Supplemental Retirement Income Agreement among
Devon Energy Corporation (Nevada), Registrant
and John W. Nichols, dated March 26, 1997
(incorporated by reference to Exhibit 10.13 to
Registrant's Form 10-Q for the quarter ended
June 30, 1997).*
10.19 Severance Agreement between Devon Energy
Corporation (Nevada), Devon Energy Corporation,
Devon Delaware Corporation and J. Larry Nichols,
dated May 19, 1999 (incorporated by reference to
Exhibit 10.4 to Registrant's Form 10-Q for the
quarter ended September 30, 1999).*
10.20 Form of Severance Agreement between Registrant
and J. Michael Lacey, Marian J. Moon, Duke R.
Ligon, Darryl G. Smette, H. Allen Turner and
William T. Vaughn, dated May 19, 1999
(incorporated by reference to Exhibit 10.3 to
Registrant's Form 10-Q for the quarter ended
September 30, 1999).*
10.21 Consulting Agreement between Registrant (as
successor by merger to PennzEnergy) and Brent
Scowcroft dated May 17, 1999 (incorporated by
reference to Registrant's Form 10-K for the year
ended December 31, 1999).*
12 Computation of ratio of earnings to combined
fixed charges and preferred stock dividends.
21 Subsidiaries of Registrant.
23.1 Consent of LaRoche Petroleum Consultants, Ltd.
23.2 Consent of AMH Group, Ltd.
23.3 Consent of Paddock Lindstrom & Associates Ltd.
23.4 Consent of Ryder Scott Company, L.P.
23.5 Consent of KPMG LLP.
23.6 Consent of PricewaterhouseCoopers LLP
116
<PAGE> 117
23.7 Consent of Deloitte & Touche LLP
* Compensatory plans or arrangements.
(b) Reports on Form 8-K -- A Current Report on Form 8-K dated
December 12, 2000, was filed by the Registrant regarding year
2001 forward looking estimates. A Current Report on Form 8-K
dated January 29, 2001, was filed by the Registrant regarding
year-end 2000 oil and gas reserves and fixed prices of future
oil and gas production.
117
<PAGE> 118
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
DEVON ENERGY CORPORATION
March 15, 2001 By /s/ J. Larry Nichols
-----------------------------------
J. Larry Nichols,
Chairman of the Board,
President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
March 15, 2001 By /s/ J. Larry Nichols
-----------------------------------
J. Larry Nichols
Chairman of the Board,
President and
Chief Executive Officer
March 15, 2001 By /s/ William T. Vaughn
-----------------------------------
William T. Vaughn
Senior Vice President --
Finance
March 15, 2001 By /s/ Danny J. Heatly
-----------------------------------
Danny J. Heatly
Vice President - Accounting
118
<PAGE> 119
March 15, 2001 By /s/ Thomas F. Ferguson
-----------------------------------
Thomas F. Ferguson, Director
March 15, 2001 By /s/ David M. Gavrin
-----------------------------------
David M. Gavrin, Director
March 15, 2001 By /s/ Michael E. Gellert
-----------------------------------
Michael E. Gellert, Director
March 15, 2001 By /s/ William E. Greehey
-----------------------------------
William E. Greehey, Director
March 15, 2001 By /s/ John A. Hill
-----------------------------------
John A. Hill, Director
March 15, 2001 By /s/ William J. Johnson
-----------------------------------
William J. Johnson, Director
March 15, 2001 By /s/ Michael M. Kanovsky
-----------------------------------
Michael M. Kanovsky,
Director
March 15, 2001 By /s/ Melvyn N. Klein
-----------------------------------
Melvyn N. Klein, Director
March 15, 2001 By /s/ Robert Mosbacher, Jr.
-----------------------------------
Robert Mosbacher, Jr.,
Director
March 15, 2001 By /s/ Robert B. Weaver
-----------------------------------
Robert B. Weaver, Director
119
<PAGE> 120
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
2.1 Agreement and Plan of Merger by and among Registrant, Devon
Merger Co. and Santa Fe Snyder Corporation dated as of May 25,
2000 (incorporated by reference to Registrant's Registration
Statement on Form S-4, File No. 333-39908).
2.2 Amendment No. One, dated as of July 11, 2000, to Agreement and
Plan of Merger by and among Registrant, Devon Merger Co. and
Santa Fe Snyder Corporation dated as of May 25, 2000
(incorporated by reference to Exhibit 2.1 to Registrant's Form
8-K filed on July 12, 2000).
2.3 Amended and Restated Agreement and Plan of Merger among
Registrant, Devon Energy Corporation (Oklahoma), Devon Oklahoma
Corporation and PennzEnergy Company dated as of May 19, 1999
(incorporated by reference to Exhibit 2.1 to Registrant's Form
S-4, File No. 333-82903).
2.4 Amended and Restated Combination Agreement between Registrant and
Northstar Energy Corporation dated as of June 29, 1998
(incorporated by reference to Annex B to Registrant's definitive
proxy statement for a special meeting of shareholders, filed
November 6, 1998).
3.1 Registrant's Restated Certificate of Incorporation (incorporated
by reference to Exhibit 3 to Registrant's Form 8-K filed August
18, 1999).
</TABLE>
<PAGE> 121
<TABLE>
<S> <C>
3.2 Registrant's Amended and Restated Bylaws (incorporated by
reference to Exhibit 3.2 to Registrant's definitive proxy
statement for a special meeting of shareholders filed July 21,
2000).
4.1 Form of Common Stock Certificate (incorporated by reference to
Exhibit 4.1 to Registrant's Form 8-K filed on August 18, 1999).
4.2 Registration Rights Agreement dated as of June 22, 2000 by and
among Registrant and Morgan Stanley & Co. Incorporated and
Salomon Smith Barney Inc. relating to Registrant's Zero Coupon
Convertible Senior Debentures due 2020 (incorporated by reference
to Exhibit 4.1 to Registrant's Form 8-K filed July 12, 2000).
4.3 Rights Agreement dated as of August 17, 1999 between Registrant
and BankBoston, N.A. (incorporated by reference to Exhibit 4.2 to
Registrant's Form 8-K filed on August 18, 1999).
4.4 Amendment to Rights Agreement dated as of May 25, 2000 between
Registrant and Fleet National Bank (f/k/a BankBoston, N.A.)
(incorporated by reference to Exhibit 4.2 to Registrant's
definitive proxy statement for a special meeting of shareholders
filed July 21, 2000).
4.5 Registration Rights Agreement dated December 31, 1996, by and
between Registrant and Kerr-McGee Corporation (incorporated by
reference to Exhibit 4.4 to Registrant's Form 8-K filed on
January 14, 1997).
4.6 Certificate of Designations of Series A Junior Participating
Preferred Stock of Registrant (incorporated by reference to
Exhibit 4.3 to Registrant's Form 8-K filed on August 18, 1999).
4.7 Certificate of Designations of the 6.49% Cumulative Preferred
Stock, Series A of Registrant (incorporated by reference to
Exhibit 4(g) to Registrant's Form 8-K filed on August 18, 1999).
4.8 Description of Capital Stock of Registrant (incorporated by
reference to Exhibit 4.9 to Registrant's Form 8-K filed on August
18, 1999).
4.9 Restated Declaration of Trust of Devon Financing Trust II and
Corrected Certificate of Trust of Devon Financing Trust II
(incorporated by reference to Exhibits 4.5 and 4.6 of
Registrant's Registration Statement on Form S-3, File Nos.
333-50034 and 333-50034-01).
4.10 Indenture dated as of June 27, 2000 between Registrant and The
Bank of New York, setting forth the terms of the Zero Coupon
</TABLE>
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Convertible Senior Debentures due 2020 (incorporated by reference
to Exhibit 4.2 to Registrant's Form 8-K filed July 12, 2000).
4.11 Senior Indenture dated as of June 1, 1999 between Santa Fe Snyder
and The Bank of New York, as Trustee, relating to Santa Fe Snyder
Corporation's 8.05% Senior Notes due 2004 (incorporated by
reference to Exhibit 4.1 to Santa Fe Snyder Corporation's Form
8-K filed on June 15, 1999).
4.12 First Supplemental Indenture dated as of June 14, 1999 to Senior
Indenture dated June 1, 1999 between Santa Fe Snyder and The Bank
of New York, as Trustee, relating to Santa Fe Snyder's 8.05%
Senior Notes due 2004 (incorporated by reference to Exhibit 4.2
to Santa Fe Snyder Corporation's Form 8-K filed on June 15,
1999).
4.13 Indenture dated as of June 10, 1997 between Snyder Oil
Corporation (as predecessor by merger to Santa Fe Snyder
Corporation) and Texas Commerce Bank National Association
relating to Snyder Oil Corporation's 8.75% Senior Subordinated
Notes due 2007 (incorporated by reference to Exhibit 4.1 to
Snyder Oil Corporation's Form 8-K dated June 10, 1997, File No.
1-10509).
4.14 First Supplemental Indenture dated as of June 10, 1997 between
Snyder Oil Corporation and Texas Commerce Bank National
Association relating to Snyder Oil Corporation's 8.75% Senior
Subordinated Notes due 2007 (incorporated by reference to Exhibit
4.2 to Snyder Oil Corporation's Form 8-K dated June 10, 1997,
File No. 1-10509).
4.15 Second Supplemental Indenture dated as of June 10, 1997 between
Snyder Oil Corporation and Texas Commerce Bank National
Association relating to Snyder Oil Corporation's 8.75% Senior
Subordinated Notes due 2007 (incorporated by reference to Exhibit
4.2 to Snyder Oil Corporation's Form 8-K dated June 10, 1997,
File No. 1-10509).
4.16 Indenture dated as of December 15, 1992 between Registrant (as
successor by merger to PennzEnergy Company, formerly Pennzoil
Company) and Texas Commerce Bank National Association, Trustee
setting forth the terms of the 4.90% Exchangeable Senior
Debentures due 2008 and the 4.95% Exchangeable Senior Debentures
due 2008 (incorporated by reference to Exhibit 4(o) to Pennzoil
Company's Form 10-K filed March 10, 1993 (SEC File No. 1-5591)).
4.17 Third Supplemental Indenture dated as of August 3, 1998 to
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Indenture dated as of December 15, 1992 among Registrant (as
successor by merger to PennzEnergy Company, formerly Pennzoil
Company) and Chase Bank of Texas, National Association,
supplements the terms of the 4.90% Exchangeable Senior Debentures
due 2008 (incorporated by reference to Exhibit 4(g) to
PennzEnergy Company's Form 10-K for the year ended December 31,
1998).
4.18 Fourth Supplemental Indenture dated as of August 3, 1998 to
Indenture dated as of December 15, 1992 among Registrant (as
successor by merger to PennzEnergy Company, formerly Pennzoil
Company) and Chase Bank of Texas, National Association,
supplements the terms of the 4.95% Exchangeable Senior Debentures
due 2008 (incorporated by reference to Exhibit 4(h) to
PennzEnergy Company's Form 10-K for the year ended December 31,
1998).
4.19 Fifth Supplemental Indenture dated as of August 17, 1999 to
Indenture dated as of December 15, 1992 among Registrant (as
successor by merger to PennzEnergy Company, formerly Pennzoil
Company) and Chase Bank of Texas, National Association
supplements the terms of the 4.90% Exchangeable Senior Debentures
due 2008 and the 4.95% Exchangeable Senior Debentures due 2008
(incorporated by reference to Exhibit 4.7 to Registrant's Form
8-K filed on August 18, 1999).
4.20 Indenture dated as of February 15, 1986 among Registrant (as
successor by merger to PennzEnergy Company, formerly Pennzoil
Company) and Mellon Bank, N.A. (incorporated by reference to
Exhibit 4(a) to Pennzoil Company's Form 10-Q for the quarter
ended June 30, 1986 (SEC File No. 1-5591).
4.21 First Supplemental Indenture dated as of August 17, 1999 to
Indenture dated as of February 15, 1986 among Registrant (as
successor by merger to PennzEnergy Company, formerly Pennzoil
Company) and Chase Bank of Texas, National Association
supplementing the terms of the 10.625% Debentures due 2001,
10.125% Debentures due 2009, 9.625% Notes due 1999 and 10.25%
Debentures due 2005 (incorporated by reference to Exhibit 4.8 to
Registrant's Form 8-K filed on August 18, 1999).
4.22 Support Agreement, dated December 10, 1998, between the
Registrant and Northstar Energy Corporation (incorporated by
reference to Exhibit 4.1 to Devon Energy Corporation (Oklahoma)'s
(predecessor to Registrant) Form 8-K dated as of December 11,
1998).
4.23 Amending Support Agreement dated August 17, 1999, between the
</TABLE>
<PAGE> 124
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Registrant and Northstar Energy Corporation (incorporated by
reference to Exhibit 4.5 to Registrant's Form 8-K filed on August
18, 1999).
4.24 Exchangeable Share Provisions (incorporated by reference to
Exhibit 4.2 to Registrant's Form 8-K filed December 23, 1998).
4.25 Amended Exchangeable Share Provisions dated as of August 17, 1999
(incorporated by reference to Exhibit 4.17 to Registrant's Form
10-K for the year ended December 31, 1999).
9.1 Voting and Exchange Trust Agreement, dated December 10, 1998, by
and between the Registrant, Northstar Energy Corporation and CIBC
Mellon Trust Company (incorporated by reference to Exhibit 9 to
Registrant's Form 8-K filed on December 23, 1998).
9.2 Amending Voting and Exchange Trust Agreement, dated as of August
17, 1999, by and between Registrant, Northstar Energy Corporation
and CIBC Mellon Trust Company (incorporated by reference to
Exhibit 9 to Registrant's Form 8-K filed on August 18, 1999).
10.1 U.S. Credit Agreement, dated August 29, 2000 among the
Registrant, as U.S. Borrower, Bank of America, N.A., as
Administrative Agent, Banc of America Securities, LLC, as Lead
Arranger, Banc One Capital Markets, Inc., as Syndication Agent,
The Chase Manhattan Bank, as Documentation Agent, First Union
National Bank, as Co-Documentation Agent, and Certain Financial
Institutions, as Lenders for the $725 million credit facility.
10.2 Canadian Credit Agreement dated August 29, 2000, among Northstar
Energy Corporation and Devon Energy Canada Corporation, as
Canadian Borrowers, Bank of America Canada, as Administrative
Agent, Banc of America Securities, LLC, as Lead Arranger, BancOne
Capital Markets, Inc., as Syndication Agent, The Chase Manhattan
Bank, as Documentation Agent, First Union National Bank, as
Co-Documentation Agent, and Certain Financial Institutions, as
Lenders for the $275 million credit facility.
10.3 Devon Energy Corporation Restricted Stock Bonus Plan
(incorporated by reference to Registrant's Form S-8 filed on
August 29, 2000, File No. 333-44702).*
10.4 Santa Fe Snyder Corporation 1999 Stock Compensation Retention
Plan (incorporated by reference to Exhibit 10(a) to Santa Fe
Snyder Corporation's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999).*
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<PAGE> 125
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10.5 PennzEnergy Company 1998 Incentive Plan (incorporated by
reference to Exhibit 4.3 to Pennzoil Company's Form S-8 filed on
December 29, 1998 SEC No. 333-69845).*
10.6 Santa Fe Energy Resources Incentive Compensation Plan, as amended
(incorporated by reference to exhibit 10(a) to Santa Fe Energy
Resources, Inc.'s Annual Report on Form 10-K for the year ended
December 31, 1998).*
10.7 Devon Energy Corporation 1997 Stock Option Plan (incorporated by
reference to Exhibit A to Registrant's Proxy Statement for the
1997 Annual Meeting of Shareholders filed on April 3, 1997).*
10.8 Pennzoil Company 1997 Incentive Plan (incorporated by reference
to Exhibit A to Pennzoil Company definitive proxy material filed
on March 21, 1997, SEC File No. 1-5591).*
10.9 Devon Energy Corporation 1993 Stock Option Plan (incorporated by
reference to Exhibit A to Registrant's Proxy Statement for the
1993 Annual Meeting of Shareholders filed on May 6, 1993).*
10.10 Pennzoil Company 1993 Conditional Stock Award Program
(incorporated by reference to Exhibit B to Pennzoil Company's
definitive proxy material filed on April 13, 1993, File No.
1-5591).*
10.11 Pennzoil Company 1992 Stock Option Plan (incorporated by
reference to Exhibit A to Pennzoil Company definitive proxy
material filed on April 13, 1993, File No. 1-5591).*
10.12 Santa Fe Energy Resources Deferred Compensation Plan, effective
as of January 1, 1991, as amended and restated, effective
February 1, 1994 (incorporated by reference to Exhibit 10(p) to
Santa Fe Energy Resources, Inc.'s Annual Report on Form 10-K for
the year ended December 31, 1993).*
10.13 Pennzoil Company 1990 Conditional Stock Award Program
(incorporated by reference to Exhibit B to Pennzoil Company's
definitive proxy material filed on April 26, 1990, File No.
1-5591).*
10.14 Pennzoil Company 1990 Stock Option Plan (incorporated by
reference to Pennzoil Company's definitive proxy material filed
on April 26, 1990, File No. 1-5591).*
10.15 Santa Fe Energy Resources 1990 Incentive Stock Compensation Plan,
Third Amendment and Restatement (incorporated by reference to
Exhibit 10(a) to Santa Fe Energy Resources, Inc.'s Quarterly
Report on Form 10-Q for the quarter ended March 31, 1996).*
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<PAGE> 126
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10.16 Santa Fe Energy Resources, Inc. Supplemental Retirement Plan
effective as of December 4, 1990 (incorporated by reference to
Exhibit 10(h) to Santa Fe Energy Resources, Inc.'s Annual Report
on Form 10-K for the year ended December 31, 1996).*
10.17 Devon Energy Corporation 1988 Stock Option Plan (incorporated by
reference to Exhibit 10.4 to Registrant's Registration Statement
on Form S-8 filed on August 19, 1999, SEC File No. 333-85553).*
10.18 Supplemental Retirement Income Agreement among Devon Energy
Corporation (Nevada), Registrant and John W. Nichols, dated March
26, 1997 (incorporated by reference to Exhibit 10.13 to
Registrant's Form 10-Q for the quarter ended June 30, 1997).*
10.19 Severance Agreement between Devon Energy Corporation (Nevada),
Devon Energy Corporation, Devon Delaware Corporation and J. Larry
Nichols, dated May 19, 1999 (incorporated by reference to Exhibit
10.4 to Registrant's Form 10-Q for the quarter ended September
30, 1999).*
10.20 Form of Severance Agreement between Registrant and J. Michael
Lacey, Marian J. Moon, Duke R. Ligon, Darryl G. Smette, H. Allen
Turner and William T. Vaughn, dated May 19, 1999 (incorporated by
reference to Exhibit 10.3 to Registrant's Form 10-Q for the
quarter ended September 30, 1999).*
10.21 Consulting Agreement between Registrant (as successor by merger
to PennzEnergy) and Brent Scowcroft dated May 17, 1999
(incorporated by reference to Registrant's Form 10-K for the year
ended December 31, 1999).*
12 Computation of ratio of earnings to combined fixed charges and
preferred stock dividends.
21 Subsidiaries of Registrant.
23.1 Consent of LaRoche Petroleum Consultants, Ltd.
23.2 Consent of AMH Group, Ltd.
23.3 Consent of Paddock Lindstrom & Associates Ltd.
23.4 Consent of Ryder Scott Company, L.P.
23.5 Consent of KPMG LLP.
23.6 Consent of PricewaterhouseCoopers LLP
23.7 Consent of Deloitte & Touche LLP
* Compensatory plans or arrangements.
</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.1
<SEQUENCE>2
<FILENAME>d84811ex10-1.txt
<DESCRIPTION>U.S. CREDIT AGREEMENT
<TEXT>
<PAGE> 1
EXHIBIT 10.1
================================================================================
US CREDIT AGREEMENT
------------------------------------------
DEVON ENERGY CORPORATION
as US Borrower
BANK OF AMERICA, N.A.
as Administrative Agent
BANC OF AMERICA SECURITIES LLC
as Lead Arranger
BANC ONE CAPITAL MARKETS, INC.
as Syndication Agent
THE CHASE MANHATTAN BANK
as Documentation Agent
FIRST UNION NATIONAL BANK
as Documentation Agent
and CERTAIN FINANCIAL INSTITUTIONS
as Lenders
------------------------------------------
US $725,000,000
August 29, 2000
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
Page
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CREDIT AGREEMENT........................................................................................... 1
ARTICLE I - The US Loans .................................................................................. 1
Section 1.1. Commitments to Lend; US Notes.......................................................... 1
Section 1.2. Requests for New US Loans.............................................................. 4
Section 1.3. Continuations and Conversions of Existing US Loans..................................... 6
Section 1.4. Use of Proceeds........................................................................ 7
Section 1.5. Interest Rates and Fees................................................................ 7
Section 1.6. Prepayments............................................................................ 9
Section 1.7. Competitive Bid Loans.................................................................. 9
Section 1.8. Refinancings of US Swing Loans......................................................... 12
Section 1.9. Re-allocation of Tranche B Maximum Credit Amount and Canadian
Maximum Credit Amount.................................................................. 13
ARTICLE II - Letters of Credit ............................................................................ 14
Section 2.1. Letters of Credit...................................................................... 14
Section 2.2. Requesting Letters of Credit........................................................... 15
Section 2.3. Reimbursement and Participations....................................................... 16
Section 2.4. Letter of Credit Fees.................................................................. 17
Section 2.5. No Duty to Inquire..................................................................... 17
Section 2.6. LC Collateral.......................................................................... 18
ARTICLE III - Payments to Lenders.......................................................................... 19
Section 3.1. General Procedures..................................................................... 19
Section 3.2. Increased Cost and Reduced Return...................................................... 20
Section 3.3. Limitation on Types of US Loans........................................................ 22
Section 3.4. Illegality............................................................................. 22
Section 3.5. Treatment of Affected US Loans......................................................... 22
Section 3.6. Compensation........................................................................... 23
Section 3.7. Change of Applicable Lending Office.................................................... 23
Section 3.8. Replacement of Lenders................................................................. 24
Section 3.9. Taxes.................................................................................. 24
Section 3.10. Currency Conversion and Currency Indemnity............................................. 26
ARTICLE IV - Conditions Precedent to Lending .............................................................. 27
Section 4.1. Documents to be Delivered.............................................................. 27
Section 4.2. Additional Conditions Precedent to First US Loan or First Letter of Credit............. 28
Section 4.3. Additional Conditions Precedent to all US Loan and Letters of Credit................... 28
</TABLE>
i
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<TABLE>
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ARTICLE V - Representations and Warranties................................................................. 29
Section 5.1. No Default............................................................................. 29
Section 5.2. Organization and Good Standing......................................................... 29
Section 5.3. Authorization.......................................................................... 29
Section 5.4. No Conflicts or Consents............................................................... 29
Section 5.5. Enforceable Obligations................................................................ 30
Section 5.6. Full Disclosure........................................................................ 30
Section 5.7. Litigation............................................................................. 30
Section 5.8. ERISA Plans and Liabilities............................................................ 30
Section 5.9. Environmental and Other Laws........................................................... 31
Section 5.10. Names and Places of Business........................................................... 31
Section 5.11. US Borrower's Subsidiaries............................................................. 31
Section 5.12. Title to Properties; Licenses.......................................................... 32
Section 5.13. Government Regulation.................................................................. 32
Section 5.14. Insider................................................................................ 32
Section 5.15. Solvency............................................................................... 32
ARTICLE VI - Affirmative Covenants of US Borrower.......................................................... 32
Section 6.1. Payment and Performance................................................................ 32
Section 6.2. Books, Financial Statements and Reports................................................ 33
Section 6.3. Other Information and Inspections...................................................... 34
Section 6.4. Notice of Material Events and Change of Address........................................ 34
Section 6.5. Maintenance of Properties.............................................................. 35
Section 6.6. Maintenance of Existence and Qualifications............................................ 35
Section 6.7. Payment of Trade Liabilities, Taxes, etc............................................... 35
Section 6.8. Insurance.............................................................................. 35
Section 6.9. Performance on US Borrower's Behalf.................................................... 35
Section 6.10. Interest............................................................................... 35
Section 6.11. Compliance with Law.................................................................... 36
Section 6.12. Environmental Matters.................................................................. 36
Section 6.13. Bank Accounts; Offset.................................................................. 36
ARTICLE VII - Negative Covenants of US Borrower............................................................ 36
Section 7.1. Indebtedness........................................................................... 37
Section 7.2. Limitation on Liens.................................................................... 38
Section 7.3. Limitation on Mergers ................................................................. 38
Section 7.4. Limitation on Issuance of Securities by Subsidiaries of US Borrower; Ownership of
certain Restricted Subsidiaries by US Borrower....................................... 38
Section 7.5. Limitation on Restricted Payments...................................................... 38
Section 7.6. Transactions with Affiliates........................................................... 39
Section 7.7. Prohibited Contracts; ERISA............................................................ 39
Section 7.8. Funded Debt to Total Capitalization.................................................... 39
</TABLE>
ii
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<TABLE>
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ARTICLE VIII - Events of Default and Remedies.............................................................. 39
Section 8.1. Events of Default...................................................................... 39
Section 8.2. Remedies............................................................................... 41
ARTICLE IX - US Agent...................................................................................... 42
Section 9.1. Appointment, Powers, and Immunities.................................................... 42
Section 9.2. Reliance by US Agent................................................................... 43
Section 9.3. Defaults............................................................................... 43
Section 9.4. Rights as Lender....................................................................... 44
Section 9.5. Indemnification........................................................................ 44
Section 9.6. Non-Reliance on US Agent and Other Lenders............................................. 44
Section 9.7. Administrative Agent in its Individual Capacity........................................ 45
Section 9.8. Sharing of Set-Offs and Other Payments................................................. 45
Section 9.9. Investments............................................................................ 45
Section 9.10. Benefit of Article IX.................................................................. 46
Section 9.11. Resignation............................................................................ 46
Section 9.12. Lenders to Remain Pro Rata............................................................. 46
Section 9.13. Other Agents........................................................................... 47
ARTICLE X - Miscellaneous.................................................................................. 47
Section 10.1. Waivers and Amendments; Acknowledgments................................................ 47
Section 10.2. Survival of Agreements; Cumulative Nature.............................................. 48
Section 10.3. Notices................................................................................ 49
Section 10.4. Payment of Expenses; Indemnity......................................................... 49
Section 10.5. Parties in Interest.................................................................... 50
Section 10.6. Assignments and Participations......................................................... 51
Section 10.7. Confidentiality........................................................................ 54
Section 10.8. Governing Law; Submission to Process................................................... 54
Section 10.9. Limitation on Interest................................................................. 54
Section 10.10. Termination; Limited Survival.......................................................... 55
Section 10.11. Severability........................................................................... 55
Section 10.12. Counterparts; Fax...................................................................... 56
Section 10.13. Waiver of Jury Trial, Punitive Damages, etc............................................ 56
Section 10.14. Defined Terms.......................................................................... 56
Section 10.15. Annex I, Exhibits and Schedules; Additional Definitions................................ 56
Section 10.16. Amendment of Defined Instruments....................................................... 56
Section 10.17. References and Titles.................................................................. 57
Section 10.18. Calculations and Determinations........................................................ 57
Section 10.19. Construction of Indemnities and Releases............................................... 57
Section 10.20. Termination of Existing US Agreement................................................... 57
</TABLE>
iii
<PAGE> 5
Schedules and Exhibits:
Annex I - Defined Terms
Annex II - Lenders Schedule
Schedule 1 - Disclosure Schedule
Schedule 2 - Surety Bonds & Letters of Credit
Exhibit A-1 - Tranche A Promissory Note
Exhibit A-2 - Tranche B Promissory Note
Exhibit A-3 - US Swing Promissory Note
Exhibit B - Borrowing Notice
Exhibit C - Continuation/Conversion Notice
Exhibit D - Certificate Accompanying Financial Statements
Exhibit E - Opinion of Counsel for Restricted Persons
Exhibit F - Assignment and Acceptance Agreement
Exhibit G - Letter of Credit Application and Agreement
Exhibit H - Competitive Bid Request
Exhibit I - Invitation to Bid
Exhibit J - Competitive Bid
Exhibit K - Competitive Bid Accept/Reject Letter
Exhibit L - Competitive Bid Note
Exhibit M - Re-allocation Notice
iv
<PAGE> 6
CREDIT AGREEMENT
THIS CREDIT AGREEMENT is made as of August 29, 2000, by and among Devon
Energy Corporation, a Delaware corporation (herein called "US Borrower"), Bank
of America, N.A., individually and as administrative agent (herein called "US
Agent"), and the undersigned Lenders. In consideration of the mutual covenants
and agreements contained herein the parties hereto agree as follows:
ARTICLE I - The US Loans
Section 1.1. Commitments to Lend; US Notes.
(a) Tranche A. Subject to the terms and conditions hereof, each Tranche A
Lender agrees to make loans to US Borrower (herein called such Tranche A
Lender's "Tranche A Loans") upon US Borrower's request from time to time during
the US Facility Commitment Period, provided that (i) subject to Sections 3.3,
3.4 and 3.5, all Tranche A Lenders are requested to make Tranche A Loans of the
same Type in accordance with their respective Tranche A Percentage Shares and as
part of the same Borrowing, (ii) such Tranche A Lender's Tranche A Percentage
Share of the Tranche A Facility Usage shall never exceed such Tranche A Lender's
Percentage Share of the Tranche A Maximum Credit Amount, and (iii) such Tranche
A Lender's Percentage Share of the US Facility Usage shall never exceed such
Tranche A Lender's Percentage Share of the US Maximum Credit Amount. The
aggregate amount of all Tranche A Loans in any Borrowing must be an integral
multiple of US $100,000 which equals or exceeds US $200,000 or must equal the
unadvanced portion of the US Maximum Credit Amount. The obligation of US
Borrower to repay to each Tranche A Lender the aggregate amount of all Tranche A
Loans made by such Tranche A Lender, together with interest accruing in
connection therewith, shall be evidenced by a single promissory note (herein
called such Tranche A Lender's "Tranche A Note") made by US Borrower payable to
the order of such Tranche A Lender in the form of Exhibit A-1 with appropriate
insertions. The amount of principal owing on any Tranche A Lender's Tranche A
Note at any given time shall be the aggregate am