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
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SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
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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
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:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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
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
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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
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The aggregate market value of the voting stock held by non-affiliates
of the Registrant as of March 14, 2002, was $7,202,248,538. At such date
154,117,214 shares of common stock and 2,005,569 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 2002 annual meeting of stockholders - Part III
TABLE OF CONTENTS
Page
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PART I
Item 1. Business............................................................ 4
Item 2. Properties.......................................................... 16
Item 3. Legal Proceedings................................................... 25
Item 4. Submission of Matters to a Vote of Security Holders................. 26
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters.......................................... 27
Item 6. Selected Financial Data............................................. 28
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................................ 31
Item 7A. Quantitative and Qualitative Disclosures About Market Risk......... 64
Item 8. Financial Statements and Supplementary Data......................... 69
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................. 131
PART III
Item 10. Directors and Executive Officers of the Registrant................. 131
Item 11. Executive Compensation............................................. 131
Item 12. Security Ownership of Certain Beneficial Owners and Management..... 131
Item 13. Certain Relationships and Related Transactions..................... 131
PART IV
Item 14. Exhibits, Financial Statements and Schedules,
and Reports on Form 8-K.................................................. 132
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
"Domestic" means the properties of the Company in the onshore continental
United States and the offshore Gulf of Mexico
"Permian/Mid-Continent, Rocky Mountain and Gulf" means the divisions of the
Company with properties in the onshore continental United States and the
offshore properties 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
"International" means the division of the Company encompassing oil and gas
properties that lie outside the United States and Canada
2
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") include,
but are not limited to, the Company's assumptions about energy markets,
production levels, reserve levels, operating results, competitive conditions,
technology, the availability of capital resources, capital expenditure
obligations, the supply and demand for oil, natural gas, NGLs and other products
or services, the price of oil, natural gas, NGLs and the other products or
services, currency exchange rates, the weather, inflation, the availability of
goods and services, drilling risks, future processing volumes and pipeline
throughput, costs or difficulties related to the integration of the businesses
of Devon, Mitchell Energy & Development Corp. ("Mitchell") and Anderson
Exploration Ltd. ("Anderson"), general economic conditions, either
internationally or nationally or in the jurisdictions in which Devon or its
subsidiaries are doing business, legislative or regulatory changes, including
changes in environmental regulation, environmental risks and liability under
federal, state and foreign environmental laws and regulations, the securities or
capital markets and other factors 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.
3
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, acquisition of producing properties,
transportation of oil and gas and processing of natural gas. 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, 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
Argentina, Azerbaijan, China, Indonesia and West Africa. In addition, Devon
created a sixth operating division to incorporate its U.S. midstream activities
with its marketing activities. The responsibilities of the Marketing and
Midstream Division include marketing natural gas, crude oil and NGLs. The
division is also responsible for the construction and operation of pipelines,
storage and treating facilities and gas processing plants. These services are
performed for Devon as well as for unrelated third parties. (A detailed
description of the significant properties can be found under "Item 2. Properties
- Significant Properties" beginning on page 16 hereof).
At December 31, 2001, Devon's estimated proved reserves were 1,620
MMBoe, of which 56% were natural gas reserves and 44% 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 $7.2 billion. After taxes, the present value was $5.3 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 reserves, 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 and value from
existing oil and gas properties. Devon's management seeks
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to achieve these objectives by (a) concentrating its properties in core areas to
achieve economies of scale, (b) acquiring and developing high profit margin
properties, (c) continually disposing of marginal and non-strategic properties,
(d) balancing reserves between oil and gas, (e) maintaining a high degree of
financial flexibility, and (f) enhancing the value of Devon's production through
marketing and midstream activities.
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 mergers
accounted for as poolings of interests) to 1,620 MMBoe at year-end 2001.
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 12.84 Boe
per share at year-end 2001. This represents a compound annual growth rate of
17.7%. 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 1.07 Boe per share in 2001, a compound annual
growth rate of 13.6%.
DEVELOPMENT OF BUSINESS
In August and September 2001, Devon announced two major acquisitions
that eventually would almost double its total proved reserves to over two
billion Boe. On August 13, 2001, Devon announced an agreement to merge with
Mitchell Energy & Development Corp. ("Mitchell"). The terms of this merger
called for Devon to issue approximately 30 million shares of Devon common stock
and to pay $1.6 billion in cash to the Mitchell stockholders. Although the
merger agreement was signed in August 2001, the transaction did not close until
January 24, 2002. Therefore, this merger did not affect Devon's 2001 reported
results.
Following the Mitchell merger announcement, Devon announced on
September 4, 2001, that it had entered into an agreement to acquire Anderson
Exploration Ltd. ("Anderson") for approximately $3.5 billion in cash. This
acquisition closed on October 15, 2001, and therefore had an impact on Devon's
results for the last two and one-half months of the year.
To fund the cash portions of these two acquisitions, as well as to pay
related transaction costs and retire certain long-term debt assumed from
Mitchell and Anderson, Devon entered into long-term debt agreements in October
2001 that totaled $6 billion. As part of this $6 billion total, Devon issued $3
billion of notes and debentures on October 3, 2001. Of this total, $1.25 billion
bear interest at 7.875% and mature in September 2031. The remaining $1.75
billion bear interest at 6.875% and mature in September 2011.
The remaining $3 billion of the $6 billion of long-term debt is in the
form of a credit facility that bears interest at floating rates. At December 31,
2001, $1 billion of this facility was borrowed. Following the close of the
Mitchell transaction, the $3 billion facility was fully borrowed. Principal
payments due on this debt are $0.2 billion in October 2004, $1.2 billion in
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2005 and $1.6 billion in 2006. The 2005 and 2006 payments are split equally in
payments due in April and October of those years. The interest rate on this debt
at December 31, 2001 was 2.9%.
FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHICAL AREAS
Note 17 to the consolidated financial statements included in (Item 8.
Financial Statements and Supplemental Data) of this report contains information
on Devon's segments and geographical areas.
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. Devon's 2002 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., the Western Sedimentary areas of Canada and in China and West Africa
outside North America.
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The following tables set forth the results of Devon's drilling activity
for the past five years.
UNITED STATES PROPERTIES
Development Wells Exploratory Wells
----------------- -----------------
Gross (1) Net (2) Gross (1) Net(2)
--------- ------- --------- ------
Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- ----- ---------- --- ----- ---------- --- -----
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
2001 961 19 980 638.26 12.91 651.17 148 17 165 122.61 11.53 134.14
--- -- --- ------ ----- ------ --- -- --- ------ ----- ------
Total 3,256 58 3,314 1,952.48 32.71 1,985.19 368 81 449 277.27 41.26 318.53
===== == ===== ======== ===== ======== === == === ====== ===== ======
CANADIAN PROPERTIES
Development Wells Exploratory Wells
----------------- -----------------
Gross (1) Net (2) Gross (1) Net(2)
--------- ------- --------- ------
Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- ----- ---------- --- ----- ---------- --- -----
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
2001 163 26 189 100.91 16.53 117.44 82 21 103 63.96 14.05 78.01
--- -- --- ------ ----- ------ -- -- --- ----- ----- -----
Total 596 85 681 362.34 57.47 419.81 291 156 447 206.20 122.05 328.25
=== == === ====== ===== ====== === === === ====== ====== ======
INTERNATIONAL PROPERTIES
Development Wells Exploratory Wells
----------------- -----------------
Gross (1) Net (2) Gross (1) Net(2)
--------- ------- --------- ------
Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- ----- ---------- --- ----- ---------- --- -----
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
2001 84 1 85 21.71 0.51 22.22 6 17 23 1.96 9.30 11.26
-- - -- ----- ---- ----- - -- -- ---- ---- -----
Total 303 8 311 80.32 2.81 83.13 18 53 71 5.99 26.91 32.90
=== = === ===== ==== ===== == == == ==== ===== =====
TOTAL PROPERTIES
Development Wells Exploratory Wells
----------------- -----------------
Gross (1) Net (2) Gross (1) Net(2)
--------- ------- --------- ------
Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- ----- ---------- --- ----- ---------- --- -----
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
2001 1,208 46 1,254 760.88 29.95 790.83 236 55 291 188.53 34.88 223.41
----- -- ----- ------ ----- ------ --- -- --- ------ ----- ------
Total 4,155 151 4,306 2,395.14 92.99 2,488.13 677 290 967 489.46 190.22 679.68
===== === ===== ======== ===== ======== === === === ====== ====== ======
(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.
7
As of December 31, 2001, Devon was participating in the drilling of 45
gross (27.58 net) wells in the U.S., 35 gross (23.31 net) wells in Canada and 18
gross (7.96 net) wells internationally. Of these wells, through February 15,
2002, 22 gross (14.24 net) wells in the U.S., 26 gross (18.00 net) wells in
Canada and 6 gross (1.15 net) wells internationally had been completed as
productive. An additional 2 gross (2.00 net) wells in the U.S., 2 gross (2.00
net) wells in Canada and 1 gross (0.50 net) well internationally 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 years ended December 31, 2001 and 2000, one significant
purchaser, Enron Capital and Trade Resource Corporation ("Enron"), accounted for
16% and 20%, respectively, of Devon's combined oil, gas and NGLs sales. No
purchaser accounted for over 10% of such revenues in 1999. Devon does not
consider itself dependent upon this purchaser, since other purchasers are
willing to purchase this same production at competitive prices.
On December 2, 2001, Enron Corp. and certain of its subsidiaries filed
voluntary petitions for reorganization under Chapter 11 of the United States
Bankruptcy Code. Prior to this date, Devon had terminated substantially all of
its agreements to sell oil or gas to Enron related entities. Devon incurred $3
million of losses for sales to Enron related subsidiaries which were not
collected prior to the bankruptcy filing.
OIL AND NATURAL GAS MARKETING
Oil Marketing. Devon's oil production is sold under both long-term and
short-term agreements at prices negotiated with third parties. Devon
periodically enters into financial commodity 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.")
Natural Gas Marketing. Devon's gas production is also sold under both
long-term and short-term agreements at prices negotiated with third parties.
Devon periodically enters into financial commodity hedging activities with a
portion of its gas production which are intended to support its gas price at
targeted levels and to manage the Company's exposure to gas price fluctuations.
Although exact percentages vary daily, as of February 2002 approximately 65% 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 26% were committed under various long-term
contracts (one year or more) which dedicate the natural gas to a purchaser for
an
8
extended period of time, but still at market sensitive prices. Devon's remaining
gas production was sold under fixed price contracts: 8% under short-term
agreements and 1% under long-term contracts.
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 re-negotiated 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 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.
9
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, gas processing plants and production 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.
The Company considers the cost of environmental protection a necessary and
manageable part of its business. The Company has been able to plan for and
comply with new environmental initiatives without materially altering its
operating strategies.
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.
10
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, processing, 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 penalty
or fine required to be paid by 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 2001 concerning such matters were
immaterial, but Devon cannot predict with any reasonable degree of certainty its
future exposure concerning such matters. The Company considers the cost of
environmental protection a necessary and manageable part of its business. The
Company has been able to plan for and comply with new environmental initiatives
without materially altering its operating strategies.
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. The Company considers the cost of environmental protection a
necessary and manageable part of its business. The Company has been able to plan
for and comply with new environmental initiatives without materially altering
its operating strategies.
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, 2001, Devon's consolidated balance
sheet
11
included $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.
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
12
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 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 2001 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
The oil and gas industry is subject to various types of regulation
throughout the world. Legislation affecting the oil and gas industry has been
pervasive and is under constant review for amendment or expansion. Pursuant to
such legislation, government 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
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. The following are significant areas of
regulation.
Exploration and Production. Devon's oil and gas concessions and permits
are granted by host governments and administered by various foreign government
agencies. Such foreign governments require compliance with detailed regulations
and orders which regulate, among other matters, drilling and operations on areas
covered by concessions and permits and calculation and disbursement of royalty
payments, taxes and minimum investments to the government.
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
13
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 regulations which may limit the number of wells or the locations
at which Devon can drill.
Environmental Regulations. Various government 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, processing and production
operations and the costs attendant thereto. 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 countries,
the application of worldwide standards, such as ISO 14000 governing
Environmental Management Systems, are required to be implemented for
international oil and gas operations.
Brazil has stringent environmental laws. The basic federal law
governing the environment is Law No. 9.605 of February 12, 1998, which set up
areas of conservation that receive federal protection. The governmental
environmental agency is IBAMA, which has significant enforcement powers.
Environmental Impact Studies are required to determine the impact of activities
on the environment and provide ways to avoid or diminish negative effects of the
project on the environment. CONAMA Resolution 23 of December 7, 1994 established
licensing criteria for activities related to drilling and production. Prior to
commencement of exploration activities, IBAMA or a state environmental agency
inspects the equipment to be used and must grant a license; the inspection and
grant of the license may cause delays in start-up of operations. In addition to
federal regulations, state and local agencies may have additional jurisdiction.
Damage to the environment results in strict liability to the holder of the
Concession. Sanctions for violations can be civil, criminal and administrative
in nature.
GOVERNMENT TAKES AND TAXATION
Foreign governments have been evaluating in recent years in and, in
some cases, promulgating new rules and regulations regarding royalty payment
obligations and taxes.
In Brazil there are numerous taxes imposed by federal, state and
municipal governments on services and equipment, which require extensive record
keeping and withholdings. Among the most significant are the following: Law No.
9.779 of 1999 extended the tax for income legal entities earn with the rendering
of services, technical assistance and administrative services to 25%. There is a
Value Added Sales Tax (ICMS) ranging between 7% and 25% and a municipal service
tax (ISS), typically paid in the place of performance, of about 5%. Excise tax
(IPI) is paid on all goods manufactured or imported into Brazil that average
about 10% (see exception for imports of equipment for petroleum activities
above). There are "social contribution" taxes for funding Brazil's extensive
social welfare programs. COFINS, a social contribution tax charged on gross
receipts, including financial and currency transactions and investments is 3%,
and PIS, to fund the unemployment insurance program, is
14
financed by the employer at 0.65% of its gross monthly receipts. Additionally,
there is a severance fund contribution (FGTS). A banking tax ("CPMF") on the
debit of funds from an account is charges at 0.30%.
In Argentina Competitiveness Law No. 25,413 amended by Law 25,453
created a new tax applicable on bank credits and debits. The tax is applicable
on (1) credits and debits on current accounts in financial entities subject to
the Financial Entities Law; (2) the operations carried out by financial entities
subject to the Financial Entities Law where the person/entity ordering the
financial operation or the beneficiaries do not use the current accounts
mentioned above, and (3) the movement or handing over of funds (whether owned or
belonging to third parties), by any person or entity. The General Tax Rate
(subject to certain tax credits) is 0.6% in the case of debits and credits. In
the cases described in points 2 and 3 above, it will be deemed that said
financial operations replace the corresponding debits and credits and the tax
rate will be doubled.
GOVERNMENT AUTHORIZATIONS AND FILINGS.
Host country law and regulations in certain cases requires prior
approval by the national government of any acquisition of concession and permits
granting hydrocarbon rights and allowing petroleum operations to be conducted.
In Argentina, Section 72 of Hydrocarbons Law 17,319 provides that
permits and concessions granted under this law may be assigned with the prior
authorization of the Government to assignees who meet the conditions required to
be a concession holder. Such prior approval of the Government would be required
if the permits and concessions held by Devon were transferred directly to a
purchaser as assets. However, according to the past practice of the Secretariat
of Energy, indirect transfers of permits and concessions by sale of the stock
have not been subject to the prior approval of the Government.
Subject to certain exemptions, Section 8 of Antitrust Law 25,156 as
amended by Section 2 of National Executive Branch Decree No. 396/01, provides
that the purchase of the property or any other right to shares or capital
participations must be notified to the Comision Nacional de Defensa de la
Competencia before execution or within a week after the transaction is closed,
where the total volume of business of the participating companies exceeds US
$200,000,000 in Argentina.
EMPLOYEES
As of December 31, 2001, Devon's staff consisted of 2,826 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.
15
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.
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. All reserve estimates were prepared using standard
geological and engineering methods generally accepted by the petroleum industry
and in accordance with SEC definitions and guidelines (as described in the
following notes). 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, 2001. Approximately 67% 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.
Approximately 43% of the year-end 2001 Canadian proved reserves were calculated
by the independent petroleum consultants of Paddock Lindstrom & Associates and
Gilbert Laustsen Jung Associates, Ltd. The remaining percentage of Canadian
reserves are based on Devon's own estimates. The international proved reserves,
other than Canada, were calculated by the independent petroleum consultants of
Ryder Scott Company Petroleum Consultants. 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.
16
TOTAL PROVED PROVED
PROVED DEVELOPED UNDEVELOPED
RESERVES RESERVES (1) RESERVES (2)
-------- ------------ ------------
TOTAL RESERVES
Oil (MMBbls)................................................ 586 324 262
Gas (Bcf)................................................... 5,477 3,948 1,529
NGL (MMBbls)................................................ 121 88 33
MMBoe (3)................................................... 1,620 1,070 550
Pre-tax Future Net Revenue ($ millions)(4).................. 13,138 8,707 4,431
Pre-tax 10% Present Value ($ millions)(4)................... 7,174 5,800 1,374
Standardized measure of discounted future net
cash flows ($ millions)(5)................................ 5,314
U.S. RESERVES
Oil (MMBbls)................................................ 191 167 24
Gas (Bcf)................................................... 2,399 1,988 411
NGL (MMBbls)................................................ 52 48 4
MMBoe (3)................................................... 642 545 97
Pre-tax Future Net Revenue ($ millions)(4).................. 5,294 4,663 631
Pre-tax 10% Present Value ($ millions)(4)................... 3,270 2,952 318
Standardized measure of discounted future net
cash flows ($ millions)(5)................................ 2,801
CANADIAN RESERVES
Oil (MMBbls)................................................ 166 124 42
Gas (Bcf)................................................... 2,625 1,923 702
NGL (MMBbls)................................................ 56 40 16
MMBoe (3)................................................... 659 485 174
Pre-tax Future Net Revenue ($ millions)(4).................. 4,797 3,732 1,065
Pre-tax 10% Present Value ($ millions)(4)................... 2,744 2,614 130
Standardized measure of discounted future net
cash flows ($ millions)(5)................................ 1,596
INTERNATIONAL RESERVES
Oil (MMBbls)................................................ 229 33 196
Gas (Bcf)................................................... 453 37 416
NGL (MMBbls)................................................ 13 -- 13
MMBoe (3)................................................... 319 40 279
Pre-tax Future Net Revenue ($ millions)(4).................. 3,047 312 2,735
Pre-tax 10% Present Value ($ millions)(4)................... 1,160 234 926
Standardized measure of discounted future net
cash flows ($ millions)(5)................................ 917
(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 MMBoe at the rate of six Mcf per Bbl 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.
17
(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, 2001. 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
$16.54 per Bbl of oil, $2.28 per Mcf of natural gas and $13.21 per Bbl of
NGLs. These prices compare to December 31, 2001, New York Mercantile
Exchange prices of $19.84 per Bbl for crude oil and of $2.65 per MMBtu for
natural gas.
(5) See Note 16 to the consolidated financial statements included in Item 8 of
this report.
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, 2001. 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, 2001,
is set forth in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations."
18
WELL STATISTICS
The following table sets forth Devon's producing wells as of December
31, 2001:
Oil Wells Gas Wells Total Wells
--------- --------- -----------
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
--------- ------- --------- ------- --------- -------
U.S. 8,610 4,054 9,224 4,591 17,834 8,645
Canada 6,999 3,205 6,998 4,038 13,997 7,243
International 1,393 397 75 25 1,468 422
--------- ------- --------- ------- --------- -------
Total 17,002 7,656 16,297 8,654 33,299 16,310
========= ======= ========= ======= ========= =======
(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.
UNDEVELOPED ACREAGE
The following table sets forth Devon's developed and undeveloped oil
and gas lease and mineral acreage as of December 31, 2001.
Developed Undeveloped
--------- -----------
Gross (1) Net (2) Gross (1) Net (2)
--------- ------- --------- -------
United States (In Thousands)
--------------
Permian/Mid-Continent Division
Permian Basin 780 383 1,270 566
Mid-Continent 698 432 1,664 986
----- ----- ------ ------
Total Permian/Mid-
Continent Division 1,478 815 2,934 1,552
----- ----- ------ ------
Rocky Mountain Division 576 308 1,962 1,374
----- ----- ------ ------
Gulf Division
Offshore 638 333 903 579
Onshore 389 220 153 55
----- ----- ------ ------
Total Gulf Division 1,027 553 1,056 634
----- ----- ------ ------
Total U.S. 3,081 1,676 5,952 3,560
Canada 4,032 2,486 15,378 10,233
International 495 209 14,846 7,838
----- ----- ------ ------
Grand Total 7,608 4,371 36,176 21,631
===== ===== ====== ======
(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.
19
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 16,478 of its 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.
ORGANIZATION STRUCTURE
Devon's properties are distributed geographically in five separate
divisions. Operations in the United States are focused in the
Permian/Mid-Continent, the Rocky Mountain and Gulf divisions. Canadian
operations are focused in the Western Canadian Sedimentary Basin in Alberta and
British Columbia. All operations outside North America make up Devon's
International division. Maintaining a tight geographic focus in selected core
areas is a key element of Devon's operating strategy. This concentration has
allowed Devon to improve operating and capital efficiency.
UNITED STATES PROPERTIES
PERMIAN/MID-CONTINENT DIVISION
Devon's Permian/Mid-Continent Division includes portions of New Mexico,
Texas, Oklahoma, Kansas, Mississippi and Louisiana. This area encompasses a wide
variety of geologic formations and productive depths. The Permian/Mid-Continent
produces more oil than any other division in the company and a significant
portion of Devon's natural gas. Devon's Permian/Mid-Continent production has
historically come from conventional oil and gas properties. However, Devon
recently established dominant positions in two non-conventional gas plays in the
Permian/Mid-Continent: the Barnett Shale and the Cherokee coalbed methane
project.
The most significant asset brought to Devon in its January 24, 2002
acquisition of Mitchell Energy is the interest in the Barnett Shale of north
Texas. The Barnett Shale is known as a "tight gas" formation. This means that in
its natural state, the formation is resistant to the production of natural gas.
Mitchell spent decades understanding how to efficiently develop and produce this
gas. The resulting technology yielded a low-risk and highly profitable natural
gas play. Devon holds 525,000 net acres and over 800 producing wells in the
Barnett Shale. Devon's average working interest is approximately 95%. The
Barnett Shale is a unique, unconventional gas resource that offers immediate
low-risk production growth and the potential for significant reserve additions.
20
The key to unlocking the gas trapped within the tight shale is a
completion technique called light sand fracturing. Light sand fracturing yields
much better results than earlier techniques and costs less. Not only are new
wells fractured when completed, but older wells can be refractured with
excellent results. Refractured wells often exceed their original flow rates,
even after years of production. In spite of recent improvements in fracture
technology Devon anticipates recovering less than 10% of the gas in place.
Further technological improvements could unlock additional potential.
In 2002, Devon plans to drill 300 new Barnett Shale wells and
refracture 144 wells. The Company also plans to drill eight exploratory wells
outside the core development area with the hope of expanding the productive
area. The Barnett Shale is expected to be an important growth area for Devon for
many years to come.
The other important new asset in the Permian/Mid-Continent Division is
the Cherokee coalbed methane project. Coalbed methane is natural gas produced
from underground coal deposits. Unlike conventional natural gas wells, coalbed
methane wells initially produce water along with small quantities of gas. Over
time, the water is removed from the reservoir releasing the gas trapped within
the coal and gas production increases.
During the first half of 2001, Devon acquired over 400,000 net acres
within the Cherokee area of southeast Kansas and northeast Oklahoma. Devon began
drilling in the second half of 2001 and had drilled 131 wells by the end of the
year. Plans for 2002 are to drill 200 new wells and further refine completion
techniques. Aggregate gas production should begin to reach significant levels in
the second half of 2002 as drilling and de-watering progress. If the wells in
this project perform as Devon believes they will, the Company expects to
ultimately drill more than 1,000 wells in the play.
ROCKY MOUNTAIN DIVISION
The Rocky Mountain Division includes Devon's properties in Wyoming,
Utah, Colorado and northern New Mexico. While Devon's assets in the Rocky
Mountains include significant conventional oil and gas properties, 2002 activity
is focused primarily on coalbed methane projects.
The Rocky Mountain Division manages three of Devon's four significant
coalbed methane projects. The most active of these is in Wyoming's Powder River
Basin. Devon began drilling coalbed methane wells in the Powder River Basin in
1998. To date, Devon has drilled almost 1,400 wells. Devon exited 2001 with net
Powder River coalbed methane sales at about 90 million cubic feet of natural gas
per day. This rate is expected to continue to rise as more wells are drilled and
de-watered.
Plans call for drilling more than 200 Powder River wells in 2002. This
will include
21
roughly 170 wells in existing producing areas and 90 wells in new project areas.
Current production is primarily from the Wyodak coal formation. In addition, the
Company has several new projects developing the deeper Big George coals. Success
in the Big George would significantly expand the potential of Devon's 250,000
net acres in this area.
GULF DIVISION
The Gulf Division manages Devon's properties in the Gulf of Mexico and
onshore in south Texas and south Louisiana. The division contributes roughly 17%
of current company-wide gas production, mostly from the shallow waters of the
Gulf of Mexico. The shallow water Gulf, or "shelf," is a mature producing area
with relatively high field decline rates. These characteristics present
challenges to Gulf operators. Devon has responded to those challenges by
continually utilizing technological advances in the search for new reserves.
Devon is applying four-component seismic technology to identify
prospects on large tracts of its shelf acreage. Traditional seismic techniques
have not been useful in imaging reservoirs lying below shallow gas reservoirs
and salt deposits. Four-component seismic, or 4C, is now allowing Devon's
geoscientists to more accurately picture these unexplored formations. Devon has
conducted two large 4C seismic surveys offshore Louisiana. In early 2002, Devon
began drilling and has achieved early success on prospects resulting from a 300
square mile 4C survey in the West Cameron area. Devon is currently interpreting
the results of its second 4C survey. This one covers 360 square miles in the
Eugene Island - South Marsh Island area.
Another response to declining shelf production has been the move into
deeper water. The deepwater Gulf is believed to contain some of the largest
remaining undiscovered oil and gas reserves in North America. Because deepwater
exploration is capital intensive, Devon's strategy is to move cautiously.
Devon's main focus is on prospects in water depths for which infrastructure and
production technology are well established. Devon limits its exploration
exposure in the deepwater to participation in a few wells each year.
Furthermore, Devon generally shares the risk of deepwater exploration wells with
industry partners. One of the deepwater exploration wells Devon plans to drill
in 2002 will assess one of the largest untested structures in the Gulf. The
Cortes Prospect lies in 3,300' of water and covers most of four 5,000-acre
blocks in the Port Isabel area. Devon has a 25% working interest in Cortes.
Another of Devon's deepwater projects is expected to begin producing in
2002. Devon has a 48% working interest in the Manatee Field which is located on
Green Canyon block 155 in about 1,900' of water. Production will be from two
wells in a sub-sea system. These wells will produce into the nearby Angus Field
and then flow to the Bullwinkle platform in 1,350' of water.
A further source of oil and gas reserves and production growth lies in
the Gulf Coast region onshore South Texas. Devon's activities in this area have
focused on exploration in the Edwards, Wilcox and Frio/Vicksberg trends. In 2001
Devon drilled five successful exploration
22
wells and 32 development wells. As a result, over the course of the year Devon's
share of production doubled to more than 60 million cubic feet per day. The
Mitchell acquisition, completed in early 2002, adds additional production and
undeveloped acreage in the South Texas area. With a large, high-quality
inventory of additional drilling locations, we expect South Texas to be a source
of continued growth.
CANADA
Devon's acquisition of Anderson Exploration in late 2001 dramatically
increased the significance of Canada to Devon's overall property portfolio and
enhanced our growth potential. Devon sought to expand its presence in Canada
because it believes that many of its oil and gas-prone areas are underdeveloped
or underexplored. Devon's properties in Canada offer a balance of drilling
opportunities spanning the entire risk-reward spectrum.
The Anderson acquisition strengthened Devon's holdings in almost all of
the important producing basins in Canada. One such area is the Deep Basin
located in western Alberta, along the border with British Columbia. Devon had
sought for years to obtain a significant acreage position in the Deep Basin.
However, other operators, including Anderson, already controlled most of the
acreage. As a result of the acquisition, Devon now holds over 800,000 net acres
in the Deep Basin. Furthermore, the profitability of Devon's operations is
enhanced by ownership in nine major gas processing plants in the area.
During 2002, Devon plans to drill about 85 wells in the Deep Basin.
These reservoirs tend to be rich in liquids, producing up to 100 barrels with
each million cubic feet of gas. Due to the multizone nature of this area,
drilling success rates are quite high, in the 70% to 90% range.
Another focus area for Devon's 2002 drilling program will be the Slave
Point region of northwestern Alberta and northeastern British Columbia. This
area includes the Hamburg/Ladyfern area where some of Canada's largest recent
gas discoveries have occurred. Devon plans to drill eight Slave Point wells in
2002, including five at Ladyfern.
Near the end of 2002, Devon plans to bring several previous deep gas
discoveries on stream in the Grizzly Valley area of the Foothills of
northeastern British Columbia. Since its initial discovery here in 1998, Devon
has drilled 11 successful wells. Devon expects to commence initial production at
a combined rate of about 50 million cubic feet of gas per day to Devon.
The Anderson acquisition significantly increased Devon's holdings in
the Foothills. Devon has interests ranging from 49% to 55% in over 1.2 million
gross acres in the area. While Devon had focused on exploring for deep gas
reservoirs in this area, Anderson had achieved considerable success in drilling
for shallower formations. The Anderson acquisition affords the Company the
opportunity to extend Anderson's shallow gas development onto Devon's acreage
and to apply Devon's deep gas exploration expertise to the Anderson acreage.
One of the highest potential exploration assets Devon acquired from
Anderson was its 1.5
23
million net acres in Canada's most prospective exploratory region, the far
north. Devon's position includes a working interest in nearly half of all the
lands held by the industry in the Mackenzie Delta and shallow water Beaufort
Sea. Devon plans to continue the long-term exploration program begun by
Anderson. These plans include active 2D and 3D seismic programs both onshore and
offshore. Beginning in 2002, Devon plans to drill up to four wells annually in
the Mackenzie Delta. While it will be years before construction of a pipeline
will allow production to begin, this area could hold significant long-term
potential for Devon.
INTERNATIONAL
Devon's assets outside North America were acquired in the PennzEnergy
and Santa Fe transactions. Since acquiring these properties, Devon has
critically evaluated each one and has disposed of many. Devon has identified our
assets in Argentina and Indonesia for sale in 2002 as part of our non-core asset
dispositions. From interests in 13 countries, Devon now is focusing on just
three international areas.
In Azerbaijan, Devon holds a 5.6% carried interest in a world-class oil
development project, the Azeri-Chirag-Gunashli Field. Significant production
from this multi-billion barrel oilfield is still several years away pending
completion of an additional export pipeline. In China, Devon is the largest
acreage holder in the Pearl River Mouth Basin in the South China Sea.
Development of our Panyu Project is underway and Devon expects first oil
production from two offshore platforms in late 2003. Devon expects its share of
production to approximate 15,000 barrels per day.
Devon's international exploration efforts are focused primarily on the
deepwater off West Africa. Devon holds over two million net acres in these
waters where several important discoveries have been made by the industry in
recent years. In 2002, Devon plans to drill a test well on our Rita Prospect
located offshore Congo.
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, 2001.
STANDARDIZED
MEASURE OF
DISCOUNTED
10% PRESENT FUTURE NET
OIL GAS NGLS MMBOE MMBOE % VALUE 10% PRESENT CASH FLOWS
(MMBBLS) (BCF) (MMBBLS) (1) (2) (IN MILLIONS) VALUE % (3) (IN MILLIONS)
-------- ----- -------- --- --- ------------- ----------- -------------
UNITED STATES
PERMIAN/MID-CONTINENT
Permian Basin 117 346 15 189 11.6% $ 960 13.4%
Mid-Continent 9 562 18 121 7.5% 659 9.2%
-------- ----- -------- ----- ------ --------- ---------
24
Total 126 908 33 310 19.1% 1,619 22.6%
-------- ----- -------- ----- ------ --------- ---------
ROCKY MOUNTAIN
Total 24 1,114 9 219 13.5% 859 12.0%
-------- ----- -------- ----- ------ --------- ---------
GULF
Offshore 37 275 8 90 5.6% 639 8.9%
Onshore 4 102 2 23 1.4% 153 2.1%
-------- ----- -------- ----- ------ --------- ---------
Total 41 377 10 113 7.0% 792 11.0%
-------- ----- -------- ----- ------ --------- ---------
TOTAL U.S. 191 2,399 52 642 39.6% 3,270 45.6% $ 2,801
-------- ----- -------- ----- ------ --------- --------- ---------
CANADA
Total(4) 166 2,625 56 659 40.7% 2,744 38.2% 1,596
INTERNATIONAL
Total 229 453 13 319 19.7% 1,160 16.2% 917
-------- ----- -------- ----- ------ --------- --------- ---------
Grand Total 586 5,477 121 1,620 100.0% $ 7,174 100.0% $ 5,314
======== ===== ======== ===== ====== ========= ========= =========
(1) Gas reserves are converted to MMBoe at the rate of six Mcf of gas per Bbl
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 MMBoe for the basin or region bears to total MMBoe for all
proved reserves.
(3) Percentages which present value for the basin or region bears to total
present value for all proved reserves.
(4) Canadian dollars converted to U.S. dollars at the rate of $1 Canadian:
$0.6279 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
Numerous gas producers and related parties, including Devon, have been
named in various lawsuits filed by private litigants alleging violation of the
federal False Claims Act. The suits allege
25
that the producers and related parties used below-market prices, improper
deductions, improper measurement techniques and transactions with affiliates
which resulted in underpayment of royalties in connection with natural gas and
natural gas liquids produced and sold from federal and Indian owned or
controlled lands. The various suits have been consolidated by the United States
Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the
matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United
States District Court for the District of Wyoming. Devon believes that it has
acted reasonably, has legitimate and strong defenses to all allegations in the
suits, and has paid royalties in good faith. Devon does not currently believe
that it is subject to material exposure in association with these lawsuits and
no liability has been recorded in connection therewith.
Devon is involved in other various routine legal proceedings incidental
to its business. However, to Devon's knowledge as of the date of this report,
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
There were no matters submitted to a vote of security holders during
the fourth quarter of 2001.
26
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.
American Stock Exchange The Toronto Stock Exchange
----------------------- --------------------------
Average Average
High Low Daily High Low Daily
(US$) (US$) Volume (CN$) (CN$) Volume
----- ----- ------ ----- ----- ------
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 66.75 52.30 977,648 102.85 78.19 645
Quarter Ended June 30, 2001 62.65 48.50 1,053,178 95.25 75.96 43
Quarter Ended September 30, 2001 55.25 30.55 1,582,815 84.40 49.00 685
Quarter Ended December 31, 2001 41.25 31.45 1,279,434 64.71 51.91 265
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 14, 2002, there were 30,431 holders of record of Devon common
stock and 298 holders of record for the exchangeable shares.
27
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." Notes 2 and
19 to the consolidated financial statements included in Item 8 of this report
contain information on mergers and acquisitions which occurred in 2002, 2001,
2000 and 1999, as well as unaudited pro forma financial data for the years 2001
and 2000.
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(MILLIONS, EXCEPT PER SHARE DATA AND RATIOS)
OPERATING RESULTS
Oil sales $ 958 1,079 561 310 555
Gas sales 1,890 1,485 628 347 375
NGL sales 132 154 68 25 36
Other revenue 95 66 21 24 48
------- --------- --------- --------- --------
Total revenues 3,075 2,784 1,278 706 1,014
------- --------- --------- --------- --------
Lease operating expenses 531 441 299 229 266
Transportation costs 83 53 34 23 20
Production taxes 117 103 45 23 31
Depreciation, depletion and amortization of property and
equipment 876 693 406 243 286
Amortization of goodwill 34 41 16 -- --
General and administrative expenses 111 93 81 45 53
Expenses related to mergers 1 60 17 13 --
Interest expense 220 155 109 43 41
Effects of changes in foreign currency exchange rates 13 3 (13) 16 6
Distributions on preferred securities of subsidiary trust -- -- 7 10 10
Change in fair value of financial instruments 2 -- -- -- --
Reduction of carrying value of oil and gas properties 1,003 -- 476 423 641
------- --------- --------- --------- --------
Total costs and expenses 2,991 1,642 1,477 1,068 1,354
------- --------- --------- --------- --------
Earnings (loss) before income taxes, minority interest,
extraordinary item and cumulative effect of change in
accounting principle 84 1,142 (199) (362) (340)
Income tax expense (benefit):
Current 71 131 23 (4) 36
Deferred (41) 281 (72) (122) (163)
-------- --------- ---------- --------- --------
Total 30 412 (49) (126) (127)
------- --------- ---------- --------- --------
Earnings (loss) before minority interest, extraordinary
item and cumulative effect of change in accounting
principle 54 730 (150) (236) (213)
Minority interest in Monterey Resources, Inc. -- -- -- (5)
------- --------- --------- --------- --------
Earnings (loss) before extraordinary item and cumulative
effect of change in accounting principle 54 730 (150) (236) (218)
Extraordinary loss -- -- (4) -- --
------- --------- ---------- --------- --------
Earnings (loss) before cumulative effect of change in
accounting principle 54 730 (154) (236) (218)
Cumulative effect of change in accounting principle 49 -- -- -- --
------- --------- --------- --------- --------
Net earnings (loss) $ 103 730 (154) (236) (218)
======= ========= ========= ========= ========
Net earnings (loss) applicable to common shareholders $ 93 720 (158) (236) (230)
======= ========= ========= ========= ========
Net earnings (loss) per share before extraordinary loss
and cumulative effect of change in accounting principle:
Basic $ 0.34 5.66 (1.64) (3.32) (3.35)
Diluted $ 0.34 5.50 (1.64) (3.32) (3.35)
Net earnings (loss) per share before cumulative effect of
change in accounting principle:
Basic $ 0.34 5.66 (1.68) (3.32) (3.35)
Diluted $ 0.34 5.50 (1.68) (3.32) (3.35)
Net earnings (loss) per share:
Basic $ 0.73 5.66 (1.68) (3.32) (3.35)
Diluted $ 0.72 5.50 (1.68) (3.32) (3.35)
Cash dividends per common share(1) $ 0.20 0.17 0.14 0.10 0.09
Weighted average common shares outstanding:
Basic 128 127 94 71 69
Diluted 130 132 99 77 75
Ratio of earnings to combined fixed charges and preferred
stock dividends(2) 1.28 7.39 N/A N/A N/A
28
DECEMBER 31,
-----------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(MILLIONS)
BALANCE SHEET DATA
Total assets $ 13,184 6,860 6,096 1,931 1,965
Debentures exchangeable into shares of ChevronTexaco
Corporation common stock $ 649 760 760 -- --
Other long-term debt $ 5,940 1,289 1,656 736 427
Convertible preferred securities of subsidiary trust $ -- -- -- 149 149
Stockholders' equity $ 3,259 3,277 2,521 750 1,007
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
2001 2000 1999 1998 1997
----------------------------------- --------------------
(MILLIONS, EXCEPT PER UNIT DATA)
CASH FLOW DATA
Net cash provided by operating activities $ 1,886 1,619 532 334 530
Net cash used in investing activities $ (5,285) (1,173) (768) (607) (546)
Net cash provided by (used in) financing activities $ 3,370 (390) 377 256 35
Modified EBITDA(3,5) $ 2,232 2,034 802 373 644
Cash margin(4,5) $ 1,941 1,748 663 324 557
PRODUCTION, PRICE AND OTHER DATA
Production:
Oil (MMBbls) 44 43 32 26 32
Gas (Bcf) 498 426 304 198 186
NGL (MMBbls) 8 7 5 3 3
MMBoe(6) 135 121 88 62 66
Average prices:
Oil (Per Bbl) $ 21.57 25.35 17.67 12.10 17.05
Gas (Per Mcf) $ 3.80 3.49 2.06 1.75 2.01
NGL (Per Bbl) $ 16.98 20.87 13.30 8.09 12.61
Per Boe(6) $ 22.05 22.47 14.35 11.05 14.54
Costs per Boe (6):
Operating costs $ 5.41 4.94 4.31 4.45 4.78
Depreciation, depletion and amortization
of oil and gas properties $ 6.20 5.48 4.46 3.74 4.17
General and administrative expenses $ 0.82 0.77 0.92 0.74 0.80
---------------
(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. Because of these facts, the cash
dividends per share presented for 1997 through 2000 are not representative
of the actual amounts paid by Devon on an historical basis. For the years
1997 through 2000, Devon's historical cash dividends per share were $0.20
in each year.
(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, 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 million, $362 million and $346 million, respectively.
(3) Modified EBITDA represents earnings before interest (including effects of
changes in foreign currency exchange rates, change in fair value of
financial instruments, 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, effects of changes in foreign currency exchange rates,
change in fair value of financial instruments, reduction of carrying value
of oil and gas properties and
29
deferred income tax expense (benefit). 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 MMBoe 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
NGLs are affected by market and other factors in addition to relative
energy content.
30
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
1999 through 2001. Reference is made to "Item 6. Selected Financial Data" and
"Item 8. Financial Statements and Supplementary Data."
OVERVIEW
In August and September 2001, Devon announced two major acquisitions that
eventually would almost double its total proved reserves to over two billion
Boe. On August 13, 2001, Devon announced an agreement to merge with Mitchell
Energy & Development Corp. ("Mitchell"). The terms of this merger called for
Devon to issue approximately 30 million shares of Devon common stock and to pay
$1.6 billion in cash to the Mitchell stockholders. Although the merger agreement
was signed in August 2001, the transaction did not close until January 24, 2002.
Therefore, this merger did not affect Devon's 2001 reported results.
Following the Mitchell merger announcement, Devon announced on September
4, 2001, that it had entered into an agreement to acquire Anderson Exploration
Ltd. ("Anderson") for approximately $3.5 billion in cash. This acquisition
closed on October 15, 2001, and therefore had an impact on Devon's results for
the last two and one-half months of the year.
To fund the cash portions of these two acquisitions, as well as to pay
related transaction costs and retire certain long-term debt assumed from
Mitchell and Anderson, Devon entered into long-term debt agreements in October
2001 that totaled $6 billion. As part of this $6 billion total, Devon issued $3
billion of notes and debentures on October 3, 2001. Of this total, $1.25 billion
bears interest at 7.875% and matures in September 2031. The remaining $1.75
billion bears interest at 6.875% and matures in September 2011.
The remaining $3 billion of the $6 billion of long-term debt is in the
form of a credit facility that bears interest at floating rates. At December 31,
2001, $1 billion of this facility was borrowed. Following the close of the
Mitchell transaction, the $3 billion facility was fully borrowed. Principal
payments due on this debt are $0.2 billion in October 2004, $1.2 billion in 2005
and $1.6 billion in 2006. The 2005 and 2006 payments are split equally in
payments due in April and October of those years. The interest rate on this debt
at December 31, 2001 was 2.9%.
The Mitchell and Anderson acquisitions followed two other significant
acquisitions by Devon in the two preceding years. In August 2000, Devon closed
its merger with Santa Fe Snyder Corporation, and in August 1999 Devon closed its
acquisition of PennzEnergy Company. These two transactions combined added
approximately 782 million Boe to Devon's proved reserves. By comparison, Devon's
total consolidated proved reserves at the end of 1998 were 299 million Boe.
In addition to the mergers and acquisitions, Devon's exploration and
development efforts have also been significant contributors to Devon's growth.
In 1999, before the merger with Santa Fe Snyder, Devon spent approximately $301
million in its exploration, drilling and development efforts. These costs
included drilling 678 wells, of which 636 were completed as producers. In 2000,
Devon and Santa Fe Snyder combined spent $904 million in its exploration,
drilling and development
31
efforts. These costs included drilling 1,328 wells, of which 1,261 were
completed as producers. In 2001, Devon spent $2.9 billion in its exploration,
drilling and development efforts. These costs included drilling 1,545 wells, of
which 1,444 were completed as producers, and acquiring $1.4 billion of unproved
leasehold in the Anderson acquisition.
Devon's acquisitions of Anderson in 2001 and PennzEnergy in 1999 were
accounted for using the purchase method of accounting for business combinations.
Also, in May 1999, prior to its merger with Devon in 2000, Santa Fe Snyder's
predecessor acquired Snyder Oil Company. This acquisition was also accounted for
using the purchase method. Accordingly, these acquisitions did not affect
Devon's reported results until after the closing dates of the acquisitions.
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. Although this is consistent with the
financial presentation of the merger, it distorts the fact that the transaction
did not actually affect Devon's operations prior to August 2000.
To present the effects that Devon's mergers and acquisitions and its
drilling and development activities have had on operations during the last three
years, the following statistics have been developed. This data compares Devon's
2001 results to those of 1999 for Devon only, without Santa Fe Snyder. Such
comparison yields the following fluctuations:
- Combined oil, gas and NGL production increased 82 million Boe, or 155%.
- Average combined price of oil, gas and NGLs increased by $8.43 per Boe, or
62%.
- Total revenues increased $2.3 billion, or 319%.
- Net cash provided by operating activities increased $1.7 billion, or 816%.
Cash margin increased $1.5 billion, or 395%.
During 2001, Devon marked its 13th anniversary as a public company. While
Devon has consistently increased production over this 13-year period, volatility
in oil and gas prices has resulted in considerable variability in earnings and
cash flows. Prices for oil, natural gas and NGLs are determined primarily by
market conditions. Market conditions for these products have been, and will
continue to be, influenced by regional and worldwide 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
32
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 13-year history as a
public company, Devon has been able to reduce its controllable 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.
RESULTS OF OPERATIONS
The following discussion of Devon's results of operations from 1999
through 2001 include the restated results of Devon for the 2000 merger with
Santa Fe Snyder which was accounted for using the pooling-of-interests method.
Devon's total revenues have risen from $1.3 billion in 1999 to $3.1
billion in 2001. 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 1999 to
2001 are shown in the following tables. (Unless otherwise stated, all dollar
amounts are expressed in U.S. dollars.)
TOTAL
-----
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000
2001 vs 2000 2000 vs 1999 1999
---- ------- ---- ------- ----
PRODUCTION
Oil (MMBbls) ......................... 44 +2% 43 +34% 32
Gas (Bcf) ............................ 498 +17% 426 +40% 304
NGLs (MMBbls) ........................ 8 +14% 7 +40% 5
Oil, gas and NGLs (MMBoe) ............ 135 +12% 121 +38% 88
REVENUES
Per Unit of Production:
Oil (per Bbl) ...................... $21.57 -15% 25.35 +43% 17.67
Gas (per Mcf) ...................... $ 3.80 +9% 3.49 +69% 2.06
NGLs (per Bbl) ..................... $16.98 -19% 20.87 +57% 13.30
Oil, gas and NGLs (per Boe) ........ $22.05 -2% 22.47 +57% 14.35
Absolute (in millions):
Oil ................................ $ 958 -11% 1,079 +92% 561
Gas ................................ $1,890 +27% 1,485 +136% 628
NGLs ............................... $ 132 -14% 154 +126% 68
------ ------ ------
Oil, gas and NGLs .................. $2,980 +10% 2,718 +116% 1,257
====== ====== ======
33
DOMESTIC
--------
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000
2001 vs 2000 2000 vs 1999 1999
---- ------- ---- ------- ----
PRODUCTION
Oil (MMBbls) ......................... 26 -10% 29 +61% 18
Gas (Bcf) ............................ 376 +6% 355 +61% 221
NGLs (MMBbls) ........................ 6 +0% 6 +50% 4
Oil, gas and NGLs (MMBoe) ............ 95 +1% 94 +59% 59
REVENUES
Per Unit of Production:
Oil (per Bbl) ...................... $22.36 -12% 25.45 +37% 18.64
Gas (per Mcf) ...................... $ 4.17 +14% 3.67 +62% 2.27
NGLs (per Bbl) ..................... $17.15 -16% 20.30 +55% 13.11
Oil, gas and NGLs (per Boe) ........ $23.80 +4% 22.95 +52% 15.10
Absolute (in millions):
Oil ................................ $ 586 -19% 727 +119% 332
Gas ................................ $1,571 +20% 1,305 +160% 502
NGLs ............................... $ 103 -24% 136 +134% 58
------ ------ ------
Oil, gas and NGLs .................. $2,260 +4% 2,168 +143% 892
====== ====== ======
CANADA
------
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000
2001 vs 2000 2000 vs 1999 1999
---- ------- ---- ------- ----
PRODUCTION
Oil (MMBbls) ......................... 8 +60% 5 +0% 5
Gas (Bcf) ............................ 113 +82% 62 -16% 74
NGLs (MMBbls) ........................ 2 +100% 1 +0% 1
Oil, gas and NGLs (MMBoe) ............ 29 +81% 16 -11% 18
REVENUES
Per Unit of Production:
Oil (per Bbl) ...................... $17.84 -27% 24.46 +58% 15.51
Gas (per Mcf) ...................... $ 2.73 +1% 2.71 +75% 1.55
NGLs (per Bbl) ..................... $16.43 -38% 26.51 +84% 14.39
Oil, gas and NGLs (per Boe) ........ $16.80 -12% 19.18 +70% 11.27
Absolute (in millions):
Oil ................................ $ 146 +26% 116 +45% 80
Gas ................................ $ 307 +82% 169 +48% 114
NGLs ............................... $ 28 +56% 18 +80% 10
------ ------ ------
Oil, gas and NGLs .................. $ 481 +59% 303 +49% 204
====== ====== ======
34
INTERNATIONAL
-------------
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000
2001 vs 2000 2000 vs 1999 1999
---- ------- ---- ------- ----
PRODUCTION
Oil (MMBbls) ......................... 10 +11% 9 +0% 9
Gas (Bcf) ............................ 9 +0% 9 +0% 9
NGLs (MMBbls) ........................ -- N/M -- N/M --
Oil, gas and NGLs (MMBoe) ............ 11 +0% 11 +0% 11
REVENUES
Per Unit of Production:
Oil (per Bbl) ...................... $22.57 -11% 25.48 +50% 16.96
Gas (per Mcf) ...................... $ 1.41 +7% 1.32 +6% 1.24
NGLs (per Bbl) ..................... $16.15 -24% 21.19 +6% 20.00
Oil, gas and NGLs (per Boe) ........ $20.76 -10% 23.08 +49% 15.50
Absolute (in millions):
Oil ................................ $ 226 -4% 236 +58% 149
Gas ................................ $ 12 +9% 11 -8% 12
NGLs ............................... $ 1 N/M -- N/M --
------ ------ ------
Oil, gas and NGLs .................. $ 239 -3% 247 +53% 161
====== ====== ======
The average sales prices per unit of production shown in the preceding
tables include the effect of Devon's hedging activities. Following is a
comparison of Devon's average sales prices with and without the effect of hedges
for each of the last three years.
With Hedges Without Hedges
----------- --------------
2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
Oil (per Bbl) $ 21.57 25.35 17.67 $ 21.41 26.20 17.75
Gas (per Mcf) $ 3.80 3.49 2.06 $ 3.94 3.57 2.07
NGLs (per Bbl) $ 16.98 20.87 13.30 $ 16.98 20.87 13.30
Oil, Gas and NGLs (per Boe) $ 22.05 22.47 14.35 $ 22.53 23.05 14.42
OIL REVENUES 2001 vs. 2000 Oil revenues decreased $121 million in 2001. Of
this total decrease, $167 million was due to a $3.78 per barrel decrease in the
average price of oil in 2001. An increase in production of one million barrels
caused oil revenues to increase by $46 million. The October 2001 Anderson merger
accounted for three million barrels of 2001 production. Oil production from
Devon's other properties declined two million barrels. This reduction was
primarily the result of domestic and international properties which were sold
prior to 2001 but whose production was included in 2000 prior to the sales.
2000 vs. 1999 Oil revenues increased $518 million in 2000. Of this total
increase, $327 million was due to a $7.68 per barrel increase in the average
price of oil in 2000. An increase in production of 11 million barrels caused the
remaining $191 million of increased revenues. The PennzEnergy merger accounted
for seven million barrels of the 11 million barrel increase. The year 2000
included 12 months of production from the properties acquired in the 1999
PennzEnergy merger, while 1999 only included production for four and one-half
months following the August 17, 1999 merger closing. The remaining four million
barrel increase in 2000's production was
35
caused by drilling activity and other acquisitions, offset in part by property
dispositions and natural declines.
GAS REVENUES 2001 vs. 2000 Gas revenues increased $405 million in 2001. Of
this total increase, $249 million was due to a 72 Bcf increase in production in
2001. The October 2001 Anderson merger accounted for 51 Bcf of the increase.
Production from Devon's domestic properties increased 21 Bcf, due primarily to
drilling and development in Devon's coalbed methane properties as well as the
acquisition of certain properties in the second quarter of 2001.
A $0.31 per Mcf increase in the average gas price in 2001 accounted for
the remaining $156 million of increased gas revenues.
2000 vs. 1999 Gas revenues increased $857 million in 2000. Of this total
increase, $605 million was due to a $1.43 per Mcf increase in the 2000 average
gas price. A 122 Bcf increase in production added the remaining $252 million
increase in gas revenues. The PennzEnergy merger accounted for 89 Bcf of the 122
Bcf increase in production. Production from Devon's other domestic properties
increased 45 Bcf, due primarily to additional development and acquisitions, net
of natural declines and dispositions. Canadian gas production decreased 12 Bcf,
or 16%, in 2000. Natural decline, increased royalty rates and dispositions of
certain properties were the primary reasons for the Canadian production decline.
NGL REVENUES 2001 vs. 2000 NGL revenues decreased $22 million in 2001. A
decrease in 2001's average price of $3.89 per barrel caused NGL revenues to
decrease $30 million. This was partially offset by an $8 million increase
related to a production increase of one million barrels. The October 2001
Anderson merger accounted for all of the increase.
2000 vs. 1999 NGL revenues increased $86 million in 2000. An increase in
2000's average price of $7.57 per barrel caused $56 million of the increase. A
production increase of two million barrels caused the remaining $30 million
increase. The 1999 PennzEnergy merger accounted for the entire increase in NGL
production in 2000.
OTHER REVENUES 2001 vs. 2000 Other revenues increased $29 million, or 44%
in 2001. Other revenues in 2001 included a $30 million gain from the settlement
of a foreign exchange forward purchase contract entered into by Devon related to
the funding of the Anderson acquisition.
2000 vs. 1999 Other revenues increased $45 million, or 214%, in 2000.
Increases in third party gas processing income of $17 million and interest
income of $5 million were the primary reasons for the increase. Additionally,
the 2000 period included $18 million of dividend income from the seven million
shares of ChevronTexaco Corporation common stock acquired in the 1999
PennzEnergy merger. The 1999 period included only $7 million of dividend income
on these same shares because Devon did not acquire the shares until August 1999.
EXPENSES The details of the changes in pre-tax expenses between 1999 and
2001 are shown in the table below.
36
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2001 2000
2001 vs 2000 2000 vs 1999 1999
---- ------- ---- ------- ----
Absolute (in millions):
Production and operating expenses:
Lease operating expenses ................ $ 531 +20% 441 +47% 299
Transportation costs .................... 83 +57% 53 +56% 34
Production taxes ........................ 117 +14% 103 +129% 45
Depreciation, depletion and amortization of
oil and gas properties .................. 838 +26% 663 +70% 390
Amortization of goodwill .................. 34 -17% 41 +156% 16
--------- -------- --------
Subtotal .............................. 1,603 +23% 1,301 +66% 784
Depreciation and amortization of non-oil
and gas properties ...................... 38 +27% 30 +88% 16
General and administrative expenses ....... 111 +19% 93 +15% 81
Expenses related to mergers ............... 1 -98% 60 +253% 17
Interest expense .......................... 220 +42% 155 +42% 109
Effects of changes in foreign currency
Exchange rates .......................... 13 +333% 3 -123% (13)
Change in fair value of
Financial instruments ................... 2 N/M -- N/M --
Distributions on preferred securities of
Subsidiary trust ........................ -- N/M -- -100% 7
Reduction of carrying value of oil and gas
Properties .............................. 1,003 N/M -- -100% 476
--------- -------- --------
Total ................................. $ 2,991 +82% 1,642 +11% 1,477
========= ======== ========
Per Boe:
Production and operating expenses:
Lease operating expenses ................ $ 3.93 +8% 3.65 +7% 3.41
Transportation costs .................... 0.61 +39% 0.44 +13% 0.39
Production taxes ........................ 0.87 +2% 0.85 +67% 0.51
Depreciation, depletion and amortization of
oil and gas properties ................. 6.20 +13% 5.48 +23% 4.46
Amortization of goodwill .................. 0.25 -26% 0.34 +89% 0.18
--------- -------- --------
Subtotal .............................. 11.86 +10% 10.76 +20% 8.95
Depreciation and amortization of non-oil
and gas properties (1) ................... 0.28 +12% 0.25 +32% 0.19
General and administrative expenses (1) ... 0.82 +6% 0.77 -16% 0.92
Expenses related to mergers (1) ........... 0.01 -98% 0.50 +163% 0.19
Interest expense (1) ...................... 1.63 +28% 1.27 +2% 1.25
Effects of changes in foreign currency
Exchange rates (1) ...................... 0.09 +350% 0.02 N/M (0.15)
Change in fair value of financial
Instruments (1) ......................... 0.02 N/M -- N/M --
Distributions on preferred securities of
Subsidiary trust (1) .................... -- N/M -- -100% 0.08
Reduction of carrying value of oil and gas
Properties (1) .......................... 7.43 N/M -- -100% 5.44
--------- -------- --------
Total .................................. $ 22.14 +63% 13.57 -20% 16.87
========= ======== ========
(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.
37
PRODUCTION AND OPERATING EXPENSES The details of the changes in production
and operating expenses between 1999 and 2001 are shown in the table below.
YEAR ENDED DECEMBER 31,
------------------------------------------------
2001 2000
2001 vs 2000 2000 vs 1999 1999
---- ------- ---- ------- ----
Absolute (in millions):
Recurring lease operating expenses $ 513 +21% 423 +45% 291
Well workover expenses 18 +0% 18 +125% 8
Transportation costs 83 +57% 53 +56% 34
Production taxes 117 +14% 103 +129% 45
------- ------- -------
Total production and operating expenses $ 731 +22% 597 +58% 378
======= ======= =======
Per Boe:
Recurring lease operating expenses $ 3.79 +8% 3.50 +5% 3.32
Well workover expenses 0.14 -7% 0.15 +67% 0.09
Transportation costs 0.61 +39% 0.44 +13% 0.39
Production taxes 0.87 +2% 0.85 +67% 0.51
------- ------- -------
Total production and operating expenses $ 5.41 +10% 4.94 +15% 4.31
======= ======= =======
2001 vs. 2000 Recurring lease operating expenses increased $90 million in
2001. The Anderson acquisition accounted for $47 million of the increase in
expenses. The remaining increase in recurring costs was primarily caused by
higher third-party service, fuel and electricity costs as well as increased
production.
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 $30 million, or 57% in 2001. Of this increase,
$12 million related to the Anderson acquisition. The remainder of the increase
was primarily due to an increase in coalbed methane gas production and increases
in transportation rates.
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 4% increase in domestic oil, gas
and NGL revenues was the primary cause of a 11% increase in domestic production
taxes. Production taxes did not increase proportionately to the increase in
revenues. This was primarily due to the fact that most of the change in domestic
revenues occurred in the Rocky Mountain division which has higher production tax
rates than the other domestic divisions.
2000 vs. 1999 Recurring lease operating expenses increased $132 million in
2000. The 1999 PennzEnergy merger accounted for $92 million of the increase in
expenses. Additionally, $19 million of costs were added by other 1999 and 2000
acquisitions. Other than the added costs from these acquisitions, Devon's
recurring costs increased $21 million, or 7%, in 2000. This increase was
primarily caused by increased production and higher ad valorem taxes and fuel
costs.
Transportation costs increased $19 million in 2000 primarily due to
increased production.
38
As previously stated, most of the U.S. 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.
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 and dismantlement and abandonment 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.
2001 vs. 2000 Oil and gas property related DD&A increased $175 million in
2001. Of this total increase, $77 million was due to the 12% increase in oil,
gas and NGL production in 2001. The remaining $98 million increase was due to an
increase in the consolidated DD&A rate. This rate increased from $5.48 per Boe
in 2000 to $6.20 per Boe in 2001.
Non-oil and gas property DD&A increased $8 million in 2001 compared to
2000. Depreciation of Devon's Wyoming gas pipeline and gathering systems,
accounted for the 2001 increase.
2000 vs. 1999 Oil and gas property related DD&A increased $273 million in
2000. Of this total increase, $149 million was due to the 38% increase in oil,
gas and NGL production in 2000. The remaining $124 million increase was 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 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 Wyoming gas pipeline and
gathering systems, accounted for the 2000 increase.
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.
39
YEAR ENDED DECEMBER 31,
------------------------------------------
2001 2000
2001 vs 2000 2000 vs 1999 1999
---- ------- ---- ------- ----
(IN MILLIONS)
Gross G&A ...................... $ 245 +19% 206 +36% 151
Capitalized G&A ................ (77) +24% (62) +114% (29)
Reimbursed G&A ................. (57) +12% (51) +24% (41)
----- ----- -----
Net G&A .................... $ 111 +19% 93 +15% 81
===== ===== =====
2001 vs. 2000 Net G&A increased $18 million in 2001. Gross G&A increased
$39 million primarily due to additional costs incurred as a result of the
Anderson acquisition and additional personnel related costs. G&A was reduced $15
million in 2001 due to an increase in the amount capitalized as part of oil and
gas properties. The increase in capitalized G&A was primarily related to
additional personnel related costs and increased acquisition, exploration and
development activities. G&A was also reduced $6 million by an increase in the
amount of reimbursements on operated properties. The increase in reimbursed G&A
was primarily related to an increase in the number of operated properties.
2000 vs. 1999 Net G&A increased $12 million in 2000. Gross G&A increased
$55 million primarily due to additional costs incurred as a result of the 1999
PennzEnergy and Snyder mergers. G&A was reduced $33 million due to an increase
in the amount capitalized. G&A was also reduced $10 million by an increase in
the amount of reimbursements on operated properties. The increase in capitalized
and reimbursed G&A was primarily related to the 1999 PennzEnergy and Snyder
mergers.
EXPENSES RELATED TO MERGERS Approximately $1 million of expenses were
incurred in 2001 in connection with the Anderson acquisition. These costs
related to Devon employees who were terminated as part of the Anderson
acquisition.
Approximately $60 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 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 $17 million of expenses were incurred by Santa Fe Snyder in
1999 related to the Snyder merger. These costs included $14 million related to
compensation plans and other benefits, and $2 million of severance and
relocation costs. The $17 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.
INTEREST EXPENSE 2001 vs. 2000 Interest expense increased $65 million in
2001. Of this total increase, $44 million was caused by an increase in the
average debt balance outstanding from $2.3 billion in 2000 to $3.0 billion in
2001. The increase in average debt outstanding was
40
attributable primarily to the long-term debt issued as a result of the October
2001 Anderson acquisition.
The average interest rate on outstanding debt decreased from 6.7% in 2000
to 6.6% in 2001. This rate decrease caused interest expense to decrease $1
million in 2001. 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 $22 million higher in 2001 compared
to 2000. The increase in other items was primarily related to an increase in
accretion of discounts and a $7 million loss related to the early retirement of
debt.
The increase in accretion of debt discounts in 2001 was related to the
adoption of Statement of Financial Accounting Standards No. 133 ("SFAS No. 133")
effective January 1, 2001. Devon's debentures that are exchangeable into shares
of ChevronTexaco Corporation common stock were revalued as of August 17, 1999.
This is the date the debentures were assumed as part of the PennzEnergy merger.
Under SFAS No. 133, the total fair value of the debentures was allocated between
the interest-bearing debt and the option to exchange ChevronTexaco Corporation
common stock that is embedded in the debentures. Accordingly, the debt portion
of the debentures was reduced by $140 million as of August 17, 1999. This
discount is being accreted in interest expense, which has raised the effective
interest rate on the debentures to 7.76% in 2001 compared to 4.92% recorded
prior to 2001. The accretion in 2001 was $12 million.
2000 vs. 1999 Interest expense increased $46 million in 2000. Of this
increase, $54 million was due to an increase in the average debt balance
outstanding from $1.5 billion in 1999 to $2.3 billion in 2000. 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% in 1999 to
6.7% in 2000. This rate decrease caused interest expense to decrease $5 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 $3 million lower in 2000 compared to
1999.
EFFECTS OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATES 2001 vs. 2000 As a
result of the Anderson acquisition, Devon's Canadian subsidiary, Devon Canada
Corporation, assumed certain fixed-rate senior notes which are 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 acquired to the dates of repayment
increase or decrease the expected amount of Canadian dollars eventually required
to repay the notes. Such changes in the Canadian dollar equivalent balance of
the debt are required to be included in determining net earnings for the period
in which the exchange rate changes. The drop in the Canadian-to-U.S. dollar
exchange rate from $0.642 at October 15, 2001 to $0.628 at December 31, 2001
resulted in an $11 million loss. Additionally, the devaluation of the Argentine
peso resulted in a $2 million loss in 2001.
41
Until mid-January 2000, Devon's Canadian subsidiary Northstar Energy
Corporation had certain fixed-rate senior notes which were denominated in U.S.
dollars. In mid-January 2000, these notes were retired prior to maturity. The
Canadian-to-U.S. dollar exchange rate dropped slightly in January prior to the
debt retirement. As a result, $3 million of expense was recognized in 2000.
2000 vs. 1999 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 million reduction to expenses was recorded in 1999.
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 plus the lower of cost or fair value of unproved
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 related 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.
During 2001 and 1999, Devon reduced the carrying value of its oil and gas
properties by $916 and $476 million, respectively, due to the full cost ceiling
limitations. The after-tax effect of these reductions in 2001 and 1999 were $556
million and $310 million, respectively. The following table summarizes these
reductions by country.
YEAR ENDED DECEMBER 31,
------------------------------------
2001 1999
---------------- ----------------
Net of Net of
Gross Taxes Gross Taxes
----- ----- ----- -----
(IN MILLIONS)
United States $449 281 464 302
Canada 434 252 -- --
Egypt 33 23 -- --
China -- -- 12 8
---- ---- ---- ----
Total $916 556 476 310
==== ==== ==== ====
The 2001 domestic and Canadian reductions were primarily the result of
lower prices. Under the purchase method of accounting for business combinations,
acquired oil and gas properties are recorded at fair value as of the date of
purchase. Devon estimates such fair value using its estimates of future oil and
gas prices. In contrast, the ceiling calculation dictates that prices in effect
as of the last day of the applicable quarter are held constant indefinitely.
Accordingly, the resulting value is not indicative of the true fair value of the
reserves. The oil and gas properties added from the Anderson acquisition and
other smaller acquisitions in 2001 were recorded at fair values that were based
on expected future oil and gas prices higher than the
42
year-end 2001 prices used to calculate the ceiling. The reduction in Egypt was
the result of high finding and development costs and negative revisions to
proved reserves.
The 1999 domestic reduction was primarily the result of lower prices. The
oil and gas properties added from the Snyder acquisition were recorded at fair
values that were based on expected future oil and gas prices higher than the
quarterly prices used to calculate the ceiling. The reduction in China was the
result of high finding and development costs.
Additionally, during 2001, Devon elected to discontinue operations in
Thailand, Malaysia, Qatar and on certain properties in Brazil. After meeting the
drilling and capital commitments on these properties, Devon determined that
these properties did not meet Devon's internal criteria to justify further
investment. Accordingly, Devon recorded an $87 million charge associated with
the impairment of these properties. The after-tax effect of this reduction was
$69 million.
INCOME TAXES 2001 vs. 2000 Devon's 2001 and 2000 effective financial tax
expense rates were 36% each year. The 2001 rate was higher than the statutory
federal tax rate of 35% due to the effect of state taxes, goodwill amortization
that was not deductible for income tax purposes and the effect of foreign income
taxes. The 2000 rate was higher than the statutory federal tax rate due to the
effect of state taxes, goodwill amortization that was 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.
2000 vs. 1999 Devon's 2000 effective financial tax expense rate was 36%.
This rate was higher than the statutory federal tax rate of 35% as discussed
previously. The 1999 effective financial tax benefit rate was 25%. This rate was
lower than the statutory federal tax rate of 35% due to the effect of goodwill
amortization that was not deductible for income tax purposes and the effect of
foreign income taxes.
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE At the time of
adoption of SFAS No. 133, Devon recorded a cumulative-effect-type adjustment to
net earnings for a $49.5 million gain related to the fair value of derivatives
that do not qualify as hedges. This gain included $46.2 million related to the
option embedded in the debentures that are exchangeable into shares of
ChevronTexaco Corporation common stock.
CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY
The following discussion of capital expenditures, capital resources and
liquidity should be read in conjunction with the consolidated statements of cash
flows included elsewhere in this report.
CAPITAL EXPENDITURES Approximately $5.3 billion was spent in 2001 for
capital expenditures, of which $5.2 billion was related to the acquisition,
drilling or development of oil and gas properties. These amounts compare to 2000
total expenditures of $1.3 billion ($1.2 billion of which was related to oil and
gas properties) and 1999 total expenditures of $0.9 billion ($0.8 billion of
which was related to oil and gas properties.)
43
OTHER CASH USES Devon's common stock dividends were $25 million, $22
million and $13 million in 2001, 2000 and 1999, respectively. Devon also paid
$10 million of preferred stock dividends in 2001 and 2000 and $4 million in the
last four and one-half months of 1999 following the PennzEnergy merger.
During 2001, Devon repurchased 3,754,000 shares of common stock at an
aggregate cost of $190 million or $50.71 per share. Devon also repurchased
shares of its common stock in 2001 under an odd-lot repurchase program. Pursuant
to this program, Devon purchased and retired 232,000 shares of its common stock
for a total cost of $14 million, or $57.40 per share.
CAPITAL RESOURCES AND LIQUIDITY Devon's primary source of liquidity has
historically been net cash provided by operating activities ("operating cash
flow"). This source has been supplemented as needed by accessing credit lines
and commercial paper markets and issuing equity securities and long-term debt
securities. In 2002, another major source of liquidity will be sales of oil and
gas properties.
Devon's operating cash flow is sensitive to many variables, the most
volatile of which is pricing of the oil, natural gas and NGLs produced. Prices
for these commodities are determined primarily by prevailing market conditions.
Regional and worldwide economic growth, weather and other substantially variable
factors influence market conditions for these products. These factors are beyond
Devon's control and are difficult to predict.
To mitigate some of the risk inherent in oil and natural gas prices, Devon
has entered into various fixed-price physical delivery contracts and financial
price swap contracts to fix the price to be received for a portion of future oil
and natural gas production. Additionally, Devon has utilized price collars to
set minimum and maximum prices on a portion of its production. The table below
provides the volumes associated with these various arrangements.
Fixed-Price Physical Price Swap Price
Delivery Contracts Contracts Collars Total
------------------ --------- ------- -----
Oil production (MMBbls)
2002 2 10 7 19
Natural gas production (Bcf)
2002 53 88 162 303
2003 26 36 126 188
2004 19 2 -- 21
For the years 2005 through 2011, Devon has fixed-price physical delivery
contracts covering natural gas production ranging from 13 Bcf to 19 Bcf per
year. Devon also has Canadian gas volumes subject to fixed-price contracts in
the years from 2012 through 2016, but the yearly volumes are less than 1 Bcf.
By removing the price volatility from the above volumes of oil and natural
gas production, Devon has mitigated, but not eliminated, the potential negative
effect of declining prices on its operating cash flow.
44
It is Devon's policy to only enter into derivative contracts with
investment grade rated counterparties deemed by management as competent and
competitive market makers.
In December 2001, Devon announced that its capital expenditure budget for
the year 2002 was approximately $1.5 billion. This capital budget represents the
largest planned use of available operating cash flow. To a certain degree, the
ultimate timing of these capital expenditures is within Devon's control.
Therefore, if oil and natural gas prices decline to levels below its acceptable
levels, Devon could choose to defer a portion of these planned 2002 capital
expenditures until later periods to achieve the desired balance between sources
and uses of liquidity.
Other sources of liquidity are Devon's revolving lines of credit. As of
December 31, 2001, these credit lines totaled $1.1 billion, of which $884
million was available to Devon for future borrowings as of the end of 2001. The
majority of the revolving credit lines consist of a U.S. facility of $725
million (the "U.S. Facility") and a Canadian facility of $275 million (the
"Canadian Facility").
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 A facility matures
on October 15, 2004. Devon may borrow funds under the Tranche B facility until
August 12, 2002 (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. On
December 31, 2001, there was $50 million of debt outstanding under Tranche A of
the $725 million U.S. Facility.
Devon may borrow funds under the $275 million Canadian Facility until
August 12, 2002 (the "Canadian Facility Revolving Period"). 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.
On December 31, 2001, there were no borrowings outstanding under the Canadian
Facility.
Under the terms of the revolving credit facilities, Devon has the right to
reallocate up to $100 million of the unused Tranche B facility maximum credit
amount to the Canadian Facility. Conversely, Devon also has the right to
reallocate up to $100 million of unused Canadian Facility maximum credit amount
to the Tranche B facility.
Amounts borrowed under the revolving credit facilities bear interest at
various fixed rate options that Devon may elect for periods up to six months.
Devon has historically elected a rate that is based upon LIBOR, plus a margin
dictated by Devon's debt rating. Borrowings under the Canadian facility have
also been made under a rate based upon the Bankers' Acceptance rate, plus
45
a margin dictated by Devon's debt rating. Based upon its current debt rating,
Devon can borrow under the revolving credit facilities at a rate of between 45.0
and 47.5 basis points above LIBOR, and 45.0 basis points above the Bankers'
Acceptance rate. Devon had $50 million of debt outstanding under its revolving
credit facilities at December 31, 2001, at an average interest rate of 4.8%.
Devon also has access to short-term credit under its commercial paper
program. Total borrowings under the U.S. Facility and the commercial paper
program may not exceed $725 million. Commercial paper debt generally has a
maturity of between seven to 90 days, although it can have a maturity of up to
365 days. Devon had $75 million of commercial paper debt outstanding at December
31, 2001, at an interest rate of 3.5%.
Devon's access to funds from its revolving credit facilities is not
restricted under any "material adverse condition" clauses. It is not uncommon
for credit agreements to include such clauses. These clauses can remove the
obligation of the banks to fund the credit line if any condition or event would
reasonably be expected to have a material and adverse effect on the borrower's
financial condition, operations, properties or prospects considered as a whole,
the borrower's ability to make timely debt payments, or the enforceability of
material terms of the credit agreement. While Devon's $1 billion revolving
credit facilities and its $3 billion term loan credit facility include covenants
that require Devon to report a condition or event having a material adverse
effect on the company, the obligation of the banks to fund the revolving credit
facilities is not expressly conditioned on the absence of a marked adverse
effect.
A portion of cash used in the Anderson and Mitchell acquisitions was
provided by a $3 billion senior unsecured credit facility. This credit facility,
which was entered into in October 2001, has a term of five years. The $3 billion
credit facility, which was fully borrowed upon the closing of the Mitchell
acquisition on January 24, 2002, will mature as follows:
(In Millions)
October 15, 2004 $ 232
April 15, 2005 $ 600
October 15, 2005 $ 600
April 15, 2006 $ 800
October 15, 2006 $ 800
------
$3,032
======
Borrowings under this $3 billion facility may be made under various rate
options elected by Devon, including a rate based on LIBOR plus a margin. Through
June 17, 2002, this margin is fixed at 100 basis points. Thereafter, the margin
will be based on Devon's debt rating. Based on Devon's current debt rating, the
margin after June 17, 2002, would be 100 basis points. Following the close of
the Mitchell acquisition, Devon had $3 billion borrowed under this facility as
of January 31, 2002, at an interest rate of 2.8%.
The terms of this $3 billion facility also provide that voluntary
prepayments of the debt may be applied, at Devon's option, to the earliest
scheduled maturities first. For example, if Devon were to prepay a portion of
the $3 billion of debt with proceeds from property sales or other cash sources,
the amount of
46
the prepayment would reduce, if so elected by Devon, the amounts otherwise due
first in 2004, then 2005 and finally 2006.
Devon's $1 billion revolving credit facilities and its $3 billion term
loan credit facility each contain only one material financial covenant. This
covenant requires Devon to maintain a ratio of total funded debt to total
capitalization of no more than 70% through June 30, 2002, and no more than 65%
thereafter. The credit agreements contain definitions of total funded debt and
total capitalization that include adjustments to the respective amounts reported
in Devon's consolidated financial statements. Per the agreements, total funded
debt excludes the debentures that are exchangeable into shares of ChevronTexaco
Corporation common stock. Also, total capitalization is adjusted to add back
noncash financial writedowns such as full cost ceiling property impairments or
goodwill impairments.
As of December 31, 2001, Devon's ratio of total funded debt to total
capitalization, as defined in its credit agreements, was 60.5%. On a pro forma
basis, assuming the Mitchell acquisition had closed on December 31, 2001, the
ratio was 59.5%.
Devon intends to divest approximately $1 billion of oil and gas properties
in 2002. Devon is currently in the early stages of its property divestiture
activities. Although Devon believes it will be able to generate the desired
amount of cash from these divestitures, it is possible that market conditions
could result in the properties being sold for less than originally believed. If
all the properties currently identified are sold, and the proceeds are less than
the stated goal of $1 billion, Devon's alternatives would depend on the
circumstances, including the actual amount of cash that is raised from the sales
and the overall market for property sales at the time. Failure to reduce Devon's
indebtedness to the extent desired through these property divestitures or other
cash sources could result in unfavorable actions by the various credit rating
agencies.
Devon receives debt ratings from the major ratings agencies in the United
States. In determining Devon's debt rating, the agencies consider a number of
items including, but not limited to, debt levels, planned asset sales, near-term
and long-term production growth opportunities, capital allocation challenges and
commodity pricing levels.
Devon's current debt ratings are BBB with a stable outlook by Standard &
Poor's and Baa2 with a negative outlook by Moody's. There are no "rating
triggers" in any of Devon's contractual obligations that would accelerate
scheduled maturities should Devon's debt rating fall below a specified level.
Certain of Devon's agreements related to its oil and natural gas hedges do
contain provisions that could require Devon to provide cash collateral in
situations where Devon's liability under the hedge is above a certain dollar
threshold and where Devon's debt rating is below investment grade (BBB- or
Baa3). However, Devon's liability under these agreements would only exceed the
maximum level in circumstances where the market prices for oil or natural gas
were rising. It is unlikely that Devon's debt rating would be subjected to
downgrades to non-investment grade levels during such a period of rising oil and
natural gas prices.
As summarized earlier in this section, Devon's cost of borrowing under its
$1 billion revolving credit facilities and its $3 billion term loan facility is
predicated on its corporate debt
47
rating. Therefore, even though a ratings downgrade would not accelerate
scheduled maturities, it would adversely impact Devon's interest rate on its
variable rate debt. Under the terms of the $1 billion revolving credit
facilities and the $3 billion term loan credit facility, a one notch downgrade
would increase Devon's borrowing rates by 22.5 basis points and 25 basis points,
respectively. A ratings downgrade could also adversely impact Devon's ability to
economically access future debt markets.
As of January 31, 2002, Devon is not aware of any potential ratings
downgrades being contemplated by the rating agencies.
A summary of Devon's contractual obligations as of December 31, 2001, is
provided in the following table.
PAYMENTS DUE BY YEAR
--------------------
After
2002 2003 2004 2005 2006 2006 Total
---- ---- ---- ---- ---- ---- -----
(IN MILLIONS)
Long-term debt $ -- -- 358 775 689 4,886 6,708
Operating leases 21 20 16 14 11 14 96
Drilling obligations 170 17 -- -- -- -- 187
Firm transportation agreements 93 82 65 49 42 219 550
----- ----- ----- ----- ----- ----- -----
Total $ 284 119 439 838 742 5,119 7,541
===== ===== ===== ===== ===== ===== =====
Firm transportation agreements represent "ship or pay" arrangements
whereby Devon has committed to ship certain volumes of gas for a fixed
transportation fee. Devon has entered into these agreements to ensure that Devon
can get its gas production to market. Devon expects to have sufficient volumes
to ship to satisfy the firm transportation agreements, so that Devon will be
receiving equivalent value for the firm transportation payments that it will
make.
The above table does not include $89 million of letters of credit that
have been issued by commercial banks on Devon's behalf which, if funded, would
become borrowings under Devon's revolving credit facility. Most of these letters
of credit have been granted by Devon's financial institutions to support Devon's
Canadian drilling commitments. The $6.7 billion of long-term debt shown in the
table excludes $119 million of discounts included in the December 31, 2001, book
balance of the debt.
CRITICAL ACCOUNTING POLICIES
In December 2001, the Securities and Exchange Commission encouraged public
companies to include in their annual report information on critical accounting
policies. These policies have been defined as those that are very important to
the portrayal of the company's financial condition and results, and require
management's most difficult, subjective or complex judgments.
48
Below is information on what Devon believes are its critical accounting
policies.
FULL COST CEILING CALCULATIONS Devon follows the full cost method of
accounting for its oil and gas properties. The full cost method subjects
companies to quarterly calculations of a "ceiling", or limitation on the amount
of properties that can be capitalized on the balance sheet. If Devon's
capitalized costs are in excess of the calculated ceiling, the excess must be
written off as an expense. The ceiling limitation is imposed separately for each
country in which Devon has oil and gas properties.
Devon's discounted present value of its proved oil, natural gas and NGL
reserves is a major component of the ceiling calculation, and represents the
component that requires the most subjective judgments. Estimates of reserves are
forecasts based on engineering data, projected future rates of production and
the timing of future expenditures. The process of estimating oil, natural gas
and NGL reserves requires substantial judgment, resulting in imprecise
determinations, particularly for new discoveries. Different reserve engineers
may make different estimates of reserve quantities based on the same data.
Certain of Devon's reserve estimates are prepared by outside consultants, while
other reserve estimates are prepared by Devon's engineers.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. In the past four years, Devon's annual revisions to its
reserve estimates have averaged approximately 3% of the previous year's
estimate. However, there can be no assurance that more significant revisions
will not be necessary in the future. If future significant revisions are
necessary that reduce previously estimated reserve quantities, it could result
in a full cost property writedown. In addition to the impact of the estimates of
proved reserves on the calculation of the ceiling, estimates of proved reserves
are also a significant component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the
associated prices of oil, natural gas and NGL reserves that are included in the
discounted present value of the reserves do not require judgment. The ceiling
calculation dictates that prices and costs in effect as of the last day of the
period are generally held constant indefinitely. Therefore, the future net
revenues associated with the estimated proved reserves are not based on Devon's
assessment of future prices or costs, but rather are based on such prices and
costs in effect as of the end of each quarter when the ceiling calculation is
performed. In calculating the ceiling, Devon does not adjust the end-of-period
price by the effect of cash flow hedges in place.
Because the ceiling calculation dictates that prices in effect as of the
last day of the applicable quarter are held constant indefinitely, the resulting
value is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at the end
of a quarter, can be either substantially higher or lower than Devon's long-term
price forecast that is a barometer for true fair value. Therefore, oil and gas
property writedowns that result from applying the full cost ceiling limitation,
and that are caused by fluctuations in price as opposed to reductions to the
underlying quantities of reserves, should not be viewed as absolute indicators
of a reduction of the ultimate value of the related reserves.
49
Devon recorded writedowns to its domestic and Canadian oil and gas
properties as of December 31, 2001. The domestic properties were reduced by $449
million and the Canadian properties were reduced by $434 million. The year-end
2001 prices used to calculate the ceiling were based on a NYMEX oil price of
$19.84 per barrel, and a Henry Hub gas price of $2.65 per MMBtu. If oil or gas
prices at the end of future quarters drop below these year-end 2001 prices, or
if Devon reduces its estimates of proved reserve quantities, further writedowns
would likely occur. Also, in January 2002, Devon closed its merger with
Mitchell. The oil and gas properties acquired in this transaction were recorded
at their estimated fair value. The fair values were based on Devon's estimates
of future oil and gas prices, and these estimated prices were higher than the
year-end 2001 market prices for oil and gas. Therefore, the Mitchell properties
were recorded at amounts which would have exceeded the related full cost ceiling
calculation as of the end of 2001. This increases the likelihood that Devon will
incur further property writedowns of its domestic oil and gas properties.
FAIR VALUES OF DERIVATIVE INSTRUMENTS The estimated fair values of Devon's
derivative instruments are recorded on Devon's 2001 consolidated balance sheet.
Substantially all of Devon's derivative instruments represent hedges of the
price of future oil and natural gas production. Therefore, while fair values of
such hedging instruments must be estimated as of the end of each reporting
period, the changes in the fair values are not included in Devon's consolidated
results of operations. Instead, the changes in fair value of hedging instruments
are recorded directly to stockholders' equity until the hedged oil or natural
gas quantities are produced.
The estimates of the fair values of Devon's hedging derivatives require
substantial judgment. Devon estimates the fair values of its derivatives on a
monthly basis using a discounted future cash flow technique. Devon obtains the
forecasts of future NYMEX oil and gas prices from independent third parties.
Many of Devon's hedges relate to regional prices other than NYMEX. Therefore,
where necessary, Devon adjusts the NYMEX prices to prices at other regional
delivery points using its own estimates of future differentials. The estimated
future prices are compared to the prices fixed by the hedge agreements, and the
resulting estimated future cash inflows or outflows over the lives of the hedges
are discounted using Devon's current borrowing rates under its revolving credit
facilities. These pricing and discounting variables are sensitive to market
volatility as well as changes in future price forecasts, regional price
differentials and interest rates.
As stated earlier, substantially all of Devon's derivative instruments are
hedges of the price of future oil and natural gas production. Devon is not
involved in any trading activities of derivatives.
BUSINESS COMBINATIONS Devon has grown substantially during recent years
through acquisitions of other oil and natural gas companies. Most of these
acquisitions have been accounted for using the purchase method of accounting,
and recent accounting pronouncements ensure that all future acquisitions will be
accounted for using the purchase method.
Under the purchase method, the acquiring company adds to its balance sheet
the estimated fair values of the acquired company's assets and liabilities. Any
excess of the purchase price over
50
the fair values of the tangible and intangible net assets acquired is recorded
as goodwill. As of January 1, 2002, the accounting for goodwill has changed. In
prior years, goodwill was amortized over its estimated useful life. As of 2002,
goodwill with an indefinite useful life is no longer amortized, but instead is
assessed for impairment at least annually.
There are various assumptions made by Devon in determining the fair values
of an acquired company's assets and liabilities. The most significant
assumptions, and the ones requiring the most judgment, involve the estimated
fair values of the oil and gas properties acquired. To determine the fair values
of these properties, Devon prepares estimates of oil, natural gas and NGL
reserves. These estimates are based on work performed by Devon's engineers and
that of outside consultants. The judgments associated with these estimated
reserves are described earlier in this section in connection with the full cost
ceiling calculation.
However, there are factors involved in estimating the fair values of
acquired oil, natural gas and NGL properties that require more judgment than
that involved in the full cost ceiling calculation. As stated above, the full
cost ceiling calculation applies current price and cost information to the
reserves to arrive at the ceiling amount. By contrast, the fair value of
reserves acquired in a business combination must be based on Devon's estimates
of future oil, natural gas and NGL prices. Devon's estimates of future prices
are based on its own analysis of pricing trends. These estimates are based on
current data obtained with regard to regional and worldwide supply and demand
dynamics such as economic growth forecasts. They are also based on industry data
regarding natural gas storage availability, drilling rig activity, changes in
delivery capacity and trends in regional pricing differentials. Future price
forecasts from independent third parties are also taken into account in arriving
at Devon's own pricing estimates.
Devon's estimates of future prices are applied to the estimated reserve
quantities acquired to arrive at estimates of future net revenues. For estimated
proved reserves, the future net revenues are then discounted using a 10% per
annum rate.
Devon also applies these same general principles in arriving at the fair
value of unproved reserves acquired in a business combination. These unproved
reserves are generally classified as either probable or possible reserves.
Because of their very nature, probable and possible reserve estimates are more
imprecise than those of proved reserves. To compensate for the inherent risk of
estimating and valuing unproved reserves, the discounted future net revenues of
probable and possible reserves are reduced by what Devon considers to be an
appropriate risk-weighting factor in each particular instance. It is common for
the discounted future net revenues of probable and possible reserves to be
reduced by factors ranging from 30% to 80% to arrive at what Devon considers to
be the appropriate fair values.
Generally, in Devon's business combinations, the determination of the fair
values of oil and gas properties requires much more judgment than the fair
values of other assets and liabilities. The acquired companies commonly have
long-term debt that Devon assumes in the acquisition, and this debt must be
recorded at the estimated fair value as if Devon had issued such debt. However,
significant judgment on Devon's behalf is usually not required in these
situations due to the existence of comparable market values of debt issued by
Devon's peer companies.
51
Effective January 1, 2002, Devon adopted the remaining provisions of SFAS
No. 142, Goodwill and Other Intangible Assets. Under SFAS No. 142, goodwill and
intangible assets with indefinite useful lives are no longer amortized, but are
instead tested for impairment at least annually. This will require Devon to
estimate the fair values of its own assets and liabilities. Therefore,
considerable judgment similar to that described above in connection with
estimating the fair value of an acquired company in a business combination will
be required to assess goodwill for impairment.
2002 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, 2001 reserve reports 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 or 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. Additionally, Devon cautions that its future
gas services revenues and expenses are subject to all of the risks and
uncertainties normally incident to the gas services business. These risks
include, but are not limited to, price volatility, environmental risks,
regulatory changes, the uncertainty inherent in estimating future processing
volumes and pipeline throughput, 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 NGLs are determined primarily by prevailing
market conditions. Market conditions for these products are influenced by
regional and worldwide 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 NGLs. Substantially
all of Devon's revenues are attributable to sales of these three commodities.
Consequently, Devon's financial results and resources are highly influenced by
price volatility.
Estimates for Devon's future production of oil, natural gas and NGLs 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 NGLs 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.
Estimates for Devon's future processing and transport of natural gas and
NGLs are based on the assumption that market demand and prices for gas and NGLs
will continue at levels that
52
allow for profitable processing and transport of these products. There can be no
assurance of such stability.
The production, transportation, processing and marketing of oil, natural
gas and NGLs 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 NGLs during 2002 will be substantially similar to those of
2001, unless otherwise noted. Given the general limitations expressed herein,
Devon's forward-looking statements for 2002 are set forth below. Unless
otherwise noted, all of the following dollar amounts are expressed in U.S.
dollars. Those amounts related to Canadian operations have been converted to
U.S. dollars using an exchange rate of $0.65 U.S. dollar to $1.00 Canadian
dollar. The actual 2002 exchange rate may vary materially from this estimated
rate. Such variations could have a material effect on the following Canadian
estimates.
The following forward-looking data excludes the financial and operating
effects of potential property acquisitions or divestitures, except for the
Mitchell acquisition and except as discussed in "Property Acquisitions and
Divestitures". The timing and ultimate results of such acquisition and
divestiture activity is difficult to predict, and may vary materially from that
discussed in this report.
GEOGRAPHIC REPORTING AREAS FOR 2002 The following estimates of production,
average price differentials and capital expenditures are provided separately for
each of the following geographic areas:
- the United States;
- Canada; and
- International, which encompasses all oil and gas properties that lie
outside of the United States and Canada.
YEAR 2002 POTENTIAL OPERATING ITEMS
The estimates related to oil, gas and NGL production, operating costs and
DD&A set forth in the following paragraphs are based on estimates for Devon's
properties other than those that have been designated for possible sale (See
"Property Acquisitions and Divestitures"). Therefore, the following estimates
exclude the results of the potential sale properties for the entire year.
OIL, GAS AND NGL PRODUCTION Set forth in the following paragraphs are
individual estimates of Devon's oil, gas and NGL production for 2002. On a
combined basis, Devon estimates its 2002 oil, gas and NGL production will total
between 175.4 and 186.4 MMBoe. Of this total, approximately 92% is estimated to
be produced from reserves classified as proved at December 31, 2001.
53
OIL PRODUCTION Devon expects its oil production to total between 34.5 and
36.7 MMBbls. Of this total, approximately 95% is estimated to be produced from
reserves classified as proved at December 31, 2001. The expected ranges of
production by area are as follows:
(MMBbls)
--------
United States 18.3 to 19.5
Canada 14.4 to 15.3
International 1.8 to 1.9
OIL PRICES - - FIXED Through certain forward oil sales agreements assumed
in the 2000 Santa Fe Snyder merger, the price on a portion of Devon's 2002 oil
production has been fixed. These agreements fixed the price on 2.5 MMBbls of
2002 oil production at an average price of $16.84 per Bbl. It should be noted
that these forward sales apply only to production in the first eight months of
2002.
Devon has executed price swaps attributable to 8 MMBbls of domestic
production at an average price of $23.85 per Bbl. Additionally, Devon has
entered into price swaps attributable to Canadian production of 1.6 MMBbls at an
average price of $20.33 per Bbl.
OIL PRICES - - FLOATING For oil production for which prices have not been
fixed, Devon's average prices are expected to differ from the NYMEX price as set
forth in the following table.
EXPECTED RANGE OF OIL PRICES
LESS THAN NYMEX PRICE
---------------------
United States ($2.35) to ($1.35)
Canada ($6.05) to ($4.05)
International ($4.05) to ($3.05)
Devon has also entered into costless price collars that set a floor price
and a ceiling price for 7.3 MMBbls of United States oil production that
otherwise is subject to floating prices. The collars have a floor and ceiling
price per Bbl of $23.00 and $28.19, respectively. The floor and ceiling prices
are based on the NYMEX price. The NYMEX price is the monthly average of settled
prices on each trading day for West Texas Intermediate Crude oil delivered at
Cushing, Oklahoma. If the NYMEX price is 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 oil revenues for the period. Because Devon's oil volumes are
often sold at prices that differ from the NYMEX price due to differing quality
(i.e., sweet crude versus sour crude) and transportation costs from different
geographic areas, 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.
GAS PRODUCTION Devon expects its gas production to total between 747 Bcf
and 793 Bcf. Of this total, approximately 90% is estimated to be produced from
reserves classified as proved at December 31, 2001. The expected ranges of
production are as follows:
(BCF)
-----
United States 473 to 502
Canada 274 to 291
54
GAS PRICES - - FIXED Through various price swaps and fixed-price physical
delivery contracts, Devon has fixed the price it will receive on a portion of
its natural gas production. The following tables include information on this
fixed-price production. Where necessary, the prices have been adjusted for
certain transportation costs that are netted against the prices recorded by
Devon, and the prices have also been adjusted for the Btu content of the gas
hedged.
FIRST HALF OF 2002 SECOND HALF OF 2002
------------------ -------------------
MCF/DAY PRICE/MCF MCF/DAY PRICE/MCF
------- --------- ------- ---------
United States 264,671 $ 3.01 198,346 $ 3.19
Canada 192,983 $ 1.88 121,758 $ 1.69
GAS PRICES - - FLOATING For the natural gas production for which prices
have not been fixed, Devon's average prices are expected to differ from the
NYMEX price as set forth in the following table. The NYMEX price is determined
to be the first-of-month South Louisiana Henry Hub price index as published
monthly in Inside FERC.
EXPECTED RANGE OF GAS PRICES
GREATER THAN (LESS THAN) NYMEX PRICE
------------------------------------
United States ($0.45) to $0.05
Canada ($0.75) to ($0.25)
Devon has also entered into costless price collars that set a floor and
ceiling price for a portion of its natural gas production that otherwise is
subject to floating prices. 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 contents of gas produced,
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.
Devon has entered into costless collars concerning its 2002 gas
production. To simplify presentation, these collars have been aggregated in the
following table according to similar floor prices. The floor and ceiling prices
shown are weighted averages of the various collars in each aggregated group.
The prices shown in the following table have been adjusted to a
NYMEX-based price, using Devon's estimates of 2002 differentials between NYMEX
and the specific regional indices upon which the collars are based. The floor
and ceiling prices related to the domestic collars are based on various regional
first-of-the-month price indices as published monthly by Inside FERC. The floor
and ceiling prices related to the Canadian collars are based on the AECO index
as published by the Canadian Gas Price Reporter.
55
FIRST HALF OF 2002 SECOND HALF OF 2002
------------------ -------------------
FLOOR CEILING FLOOR CEILING
PRICE PRICE PRICE PRICE
PER PER PER PER
AREA (RANGE OF FLOOR PRICES) MMBtu/DAY MMBtu MMBtu MMBtu/DAY MMBtu MMBtu
---------------------------- --------- ----- ----- --------- ----- -----
United States ($3.35 - $3.65) 285,000 $ 3.52 $ 7.37 285,000 $ 3.52 $ 7.37
United States ($2.96 - $3.11) 130,000 $ 3.01 $ 4.53 -- $ -- $ --
United States ($2.75 - $2.79) 35,000 $ 2.76 $ 3.72 35,000 $ 2.76 $ 3.72
Canada ($3.54 - $3.72) 23,705 $ 3.64 $ 6.82 23,705 $ 3.64 $ 6.82
Canada ($3.19 - $3.32) 9,481 $ 3.26 $ 4.50 -- $ -- $ --
Canada ($2.72 - $2.99) 34,481 $ 2.79 $ 3.88 25,000 $ 2.72 $ 3.67
NGL PRODUCTION Devon expects its production of NGLs to total between 16.4
million barrels and 17.5 million barrels. Of this total, 98% is estimated to be
produced from reserves classified as proved at December 31, 2001. The expected
ranges of production are as follows:
(MMBbls)
--------
United States 11.9 to 12.7
Canada 4.5 to 4.8
GAS SERVICES REVENUES AND EXPENSES Devon's gas services revenues and
expenses are derived from its natural gas processing plants and natural gas
transport pipelines. These revenues and expenses vary in response to several
factors. The factors include, but are not limited to, changes in production from
wells connected to the pipelines and related processing plants, changes in the
absolute and relative prices of natural gas and NGLs, provisions of the contract
agreements and the amount of repair and workover activity required to maintain
anticipated processing levels.
These factors increase the uncertainty inherent in estimating future gas
services revenues and expenses. Given these uncertainties, Devon estimates that
2002 gas services revenues will be between $917 million and $974 million and gas
services expenses will be between $709 million and $752 million.
OTHER REVENUES Devon's other revenues in 2002 are expected to be between
$14 million and $18 million.
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.
Given these uncertainties, Devon estimates that lease operating expenses
will be between $540 million and $574 million, transportation costs will be
between $153 million and $163 million and production taxes will be between 3.9%
and 4.4% of consolidated oil, natural gas and NGL revenues.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2002 oil and gas
property DD&A rate will depend on various factors. Most notable among such
factors are the amount of
56
proved reserves that will be added from drilling or acquisition efforts compared
to the costs incurred for such efforts, and the revisions to Devon's year-end
2001 reserve estimates that, based on prior experience, are likely to be made
during 2002.
Oil and gas property related DD&A expense is expected to be between $1.1
billion and $1.3 billion. Additionally, Devon expects its DD&A expense related
to non-oil and gas property fixed assets to total between $88 million and $93
million. This range includes $54 million to $57 million related to gas services
assets. Based on these DD&A amounts and the production estimates set forth
earlier, Devon expects its consolidated DD&A rate will be between $6.52 per Boe
and $6.93 per Boe.
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 is
expected to be between $174 million and $184 million.
INTEREST EXPENSE Future interest rates, debt outstanding and oil, natural
gas and NGL prices have a significant effect on Devon's interest expense. Devon
can only marginally influence the prices it will receive in 2002 from sales of
oil, natural gas and NGLs and the resulting cash flow. The proceeds and the
timing of the potential property sales in 2002 will also affect interest
expense. Such proceeds could be used to retire either fixed-rate debt or
variable-rate debt. At this time, the amount of proceeds and the timing of such
property sales, as well as the application of the proceeds, are not possible to
accurately predict. (See "Property Acquisitions and Divestitures.") 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.
Assuming no changes in fixed-rate debt balances during 2002 other than the
assumption of $211 million of such debt from Mitchell, Devon's average balance
of fixed rate debt during 2002 will be $5.7 billion. The interest expense in
2002 related to this fixed-rate debt will be approximately $407 million. This
fixed-rate debt removes the uncertainty of future interest rates from some, but
not all, of Devon's long-term debt. Devon's floating rate debt is discussed in
the following paragraphs.
After completion of the Mitchell acquisition, Devon had 100% of its $3.0
billion senior unsecured term loan credit facility borrowed. Interest on
borrowings under this facility may be based, at Devon's option, on LIBOR plus a
margin determined by Devon's long-term senior unsecured debt ratings. Regardless
of the current debt ratings, the margin for borrowings based on LIBOR will be
100 basis points until June 17, 2002. As of January 31, 2002, the average
interest rate on this facility was 2.8%.
57
From time to time, Devon borrows under its $1 billion credit facilities.
Borrowings under the U.S. facility, currently set at $725 million, may be
borrowed at various rate options including LIBOR plus a margin with interest
periods of up to six months. Borrowings under the Canadian facility, currently
set at $275 million, may be made at various rate options including LIBOR plus a
margin with interest periods up to six months, or Bankers Acceptances plus a
margin with interest periods of 30 to 180 days. The current LIBOR margin ranges
from 45.0 to 47.5 basis points and the current Bankers Acceptance margin is 45.0
basis points. The total borrowed under these facilities was $50 million at
December 31, 2001, at an average interest rate of 4.8%.
From time to time, Devon also borrows under its commercial paper facility.
Total borrowings under the $725 million U.S. facility and the commercial paper
program cannot exceed $725 million. The total borrowed under the commercial
paper program was $75 million at December 31, 2001, at an average interest rate
of 3.5%. Debt outstanding under this program is generally borrowed for seven to
90 day periods, and may be borrowed up to 365 days, at prevailing commercial
paper market rates.
Devon has fixed the interest rate on $133 million Canadian dollars and $50
million U.S. dollars of its floating rate debt through interest-rate swap
agreements at average rates of 6.4% and 5.9%, respectively. The Canadian dollar
interest-rate swap agreements mature at various dates through July 2007 and the
U.S. dollar swap agreement matures in May 2003.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Devon follows the
full cost method of accounting for its oil and gas properties. Under the full
cost method, Devon's net book value of oil and gas properties, less related
deferred income taxes (the "costs to be recovered"), may not exceed a calculated
"full cost ceiling." The ceiling limitation is the discounted estimated
after-tax future net revenues from oil and gas properties plus the lower of cost
or fair value of unproved properties. The ceiling is imposed separately by
country. In calculating future net revenues, current prices and costs are
generally held constant indefinitely. The costs to be recovered are compared to
the ceiling on a quarterly basis. If the costs to be recovered exceed the
ceiling, the excess 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.
Because of the volatile nature of oil and gas prices, it is not possible
to predict whether Devon will incur a full cost writedown in future periods.
Because the ceiling calculation dictates that prices in effect as of the last
day of the applicable quarter are held constant indefinitely, the resulting
value is not indicative of the true fair value of the reserves. Oil and natural
gas prices have historically been cyclical and, on any particular day at the end
of a quarter, can be either substantially higher or lower than Devon's long-term
price forecast that is a barometer for true fair value. Therefore, oil and gas
property writedowns that result from applying the full cost ceiling limitation,
and that are caused by fluctuations in price as opposed to reductions to the
underlying quantities of reserves, should not be viewed as absolute indicators
of a reduction of the ultimate value of the related reserves.
Devon recorded writedowns to its domestic and Canadian oil and gas
properties as of December 31, 2001. The year-end 2001 prices used to calculate
the ceiling were a NYMEX oil
58
price of $19.84 per barrel, and a Henry Hub gas price of $2.65 per MMBtu. If oil
or gas prices at the end of future quarters drop below these year-end 2001
prices, or if Devon reduces its estimates of proved reserve quantities, further
writedowns would likely occur. Also, in January 2002, Devon closed its merger
with Mitchell. The oil and gas properties acquired in this transaction were
recorded at their estimated fair value. The fair values were based on Devon's
estimates of future oil and gas prices, and these estimated prices were higher
than the year-end 2001 market prices for oil and gas. Therefore, the Mitchell
properties were booked at amounts which would have exceeded the related full
cost ceiling calculation as of the end of 2001. This increases the likelihood
that Devon will incur further property writedowns of its domestic oil and gas
properties.
EFFECTS OF CHANGES IN FOREIGN CURRENCY RATES In the October 2001 Anderson
acquisition, Devon's subsidiary, Devon Canada, assumed $400 million of long-term
debt which is denominated in U.S. dollars. This debt matures in 2011. Changes in
the exchange rate between the U.S. dollar and the Canadian dollar from October
15, when Devon acquired Anderson, to the dates of repayment will increase or
decrease the expected amount of Canadian dollars eventually required to repay
the debt. Such changes in the Canadian dollar equivalent balance of the debt are
required to be included in determining net earnings for the period in which the
exchange rate changes. Because of the variability of the exchange rate, it is
not possible to estimate the effect which will be recorded in 2002. However, for
every $0.01 change in the exchange rate, Devon will record either revenue or
expense of approximately $9 million Canadian dollars. The resulting revenue or
expense in U.S. dollars will depend on the currency exchange rate in effect
throughout the year.
With the devaluation of the Argentine peso in January 2002, changes in the
exchange rate between the U.S. dollar and the Argentine peso will also result in
gains or losses for the period in which the exchange rate changes. The
functional currency of Devon's Argentine subsidiary is the U.S. dollar. As a
result, changes in the exchange rate between the U.S. dollar and the Argentine
peso will increase or decrease the expected amount of Argentine pesos eventually
collected or paid for transactions that are settled in pesos. Because of the
variability of the exchange rate, it is not possible to estimate the deferred
effect which will be recorded in 2002. The resulting revenue or expense in U.S.
dollars will depend on the currency exchange rate in effect throughout the year.
INCOME TAXES Devon's financial income tax rate in 2002 will vary
materially depending on the actual amount of financial pre-tax earnings. There
are certain tax deductions and credits that will have a fixed impact on 2002's
income tax expense regardless of the level of pre-tax earnings that are
produced. Due to the significance of these deductions and credits as compared to
potential pre-tax earnings, it is not possible to estimate an accurate single
range of financial income tax rates that would apply to all the possible levels
of pre-tax earnings during 2002. Therefore, the following estimates are provided
based on various ranges of financial pre-tax earnings for 2002.
59
INCOME TAX EXPENSE (BENEFIT) RATE
---------------------------------
PRE-TAX EARNINGS CURRENT DEFERRED TOTAL
---------------- ------- -------- -----
$100 - $225 million 65% to 40% (130%) to (50%) (65%) to (10%)
$226 - $450 million 40% to 35% (50%) to (20%) (10%) to 15%
$451 - $675 million 35% to 30% (20%) to (10%) 15% to 20%
It is uncertain whether Devon's pre-tax earnings will be within the ranges
presented in the above table. Among the factors which could cause Devon's
pre-tax earnings to fall outside these ranges is price volatility. In addition
to price volatility's effect on revenues, such volatility could also cause Devon
to incur a full cost reduction of oil and gas properties. Variances in revenues
or expenses resulting from price volatility could cause Devon's pre-tax earnings
to fall outside the ranges presented.
PROPERTY ACQUISITIONS AND DIVESTITURES 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, other than the Mitchell
acquisition closed on January 24, 2002.
During 2002, Devon contemplates the disposition of certain oil and gas
properties (the "Disposition Properties"). The Disposition Properties are
predominantly properties that are either outside of Devon's core-operating areas
or otherwise do not fit Devon's current strategic objectives. The Disposition
Properties are located in the U.S., Canada and International areas. At this
time, Devon is in the early stages of the disposition process, and it is
impossible to identify when, or if, the dispositions will occur.
The estimates of Devon's 2002 results previously set forth exclude any
results from the Disposition Properties. The Disposition Properties' actual
contributions to Devon's 2002 operating results will depend upon the timing of
the dispositions. The estimated full-year 2002 results from the Disposition
Properties (which are not included in the previous 2002 estimates included in
this report) are as follows:
EXPECTED RANGE OF PRODUCTION
----------------------------
OIL GAS NGL TOTAL
(MMBbls) (Bcf) (MMBbls) (MMBoe)
-------- ----- -------- -------
United States 6.8 to 7.2 45 to 48 0.6 to 0.7 14.9 to 15.9
Canada 2.9 to 3.1 13 to 14 0.3 to 0.4 5.4 to 5.8
International 7.1 to 7.5 10 to 11 0.1 to 0.2 8.9 to 9.5
Total 16.8 to 17.8 68 to 73 1.0 to 1.3 29.2 to 31.2
60
EXPECTED RANGE OF EXPENSE
($ IN MILLIONS)
---------------
Lease operating expenses $178 to $189
Transportation costs $ 10 to $ 11
DD&A $195 to $207
YEAR 2002 POTENTIAL CAPITAL EXPENDITURES AND OTHER CASH USES
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, other than the Mitchell acquisition.
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 actual prices differ materially from Devon's
expectations for its future production, some projects may be accelerated or
deferred and, consequently, may increase or decrease total 2002 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.
Given the limitations discussed, the company expects its 2002 capital
expenditures for drilling and development efforts, plus related facilities, to
total between $1.2 billion and $1.4 billion. These amounts include between $495
million and $595 million for drilling and facilities costs related to reserves
classified as proved as of year-end 2001. In addition, these amounts include
between $365 million and $435 million for other low risk/reward projects and
between $300 million and $350 million for new, higher risk/reward projects. Low
risk/reward projects include development drilling that does not offset currently
productive units and for which there is not a certainty of continued production
from a known productive formation. Higher risk/reward projects include
exploratory drilling to find and produce oil or gas in previously untested fault
blocks or new reservoirs.
The following table shows expected drilling and facilities expenditures by
geographic area.
DRILLING AND PRODUCTION FACILITIES EXPENDITURES
-----------------------------------------------
UNITED STATES CANADA INTERNATIONAL TOTAL
------------- ------ ------------- -----
($ in millions)
Related to Proved Reserves $435-$495 $ 15-$ 35 $45-$ 65 $ 495-$ 595
Lower Risk/Reward Projects $170-$200 $195-$225 $ 0-$ 10 $ 365-$ 435
Higher Risk/Reward Projects $ 70-$ 80 $210-$240 $20-$ 30 $ 300-$ 350
--------- --------- -------- -------------
Total $675-$775 $420-$500 $65-$105 $1,160-$1,380
========= ========= ======== =============
In addition to the above expenditures for drilling and development, Devon
expects to spend between $135 million and $165 million on its gas services
assets, which include its gas processing plants and gas transport pipelines.
Devon also expects to capitalize between $85
61
million and $105 million of G&A expenses in accordance with the full cost method
of accounting. Devon also expects to pay between $20 million and $30 million for
plugging and abandonment charges, and to spend between $15 million and $25
million for non-oil and gas property fixed assets.
The above capital expenditure estimates do not include the cost to acquire
Mitchell in 2002. At closing, Devon paid approximately $1.6 billion to the
Mitchell stockholders. Devon also issued approximately 30 million shares of
Devon common stock at closing. For accounting purposes, the Devon shares were
valued at $50.95 per share, which was the value at the time the Mitchell
acquisition was announced in August 2001. This resulted in the shares of Devon
common stock issued at closing to be valued at approximately $1.5 billion.
The actual allocation of the Mitchell acquisition cost to the various
assets and liabilities will not be final until sometime later in 2002. However,
the preliminary allocation of the acquisition cost to fixed assets was as
follows:
Proved oil and gas properties $1.5 billion
Unproved oil and gas properties $0.7 billion
Gas services facilities and equipment $0.8 billion
----
$3.0 billion
====
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 155 million shares of common stock outstanding after
completion of the Mitchell acquisition, 2002 dividends are expected to
approximate $31 million. Also, Devon has $150 million of 6.49% cumulative
preferred stock upon which it will pay $10 million of dividends in 2002.
IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED Effective
January 1, 2002, Devon adopted the remaining provisions of SFAS No. 142,
Goodwill and Other Intangible Assets. Under SFAS No. 142, goodwill and
intangible assets with indefinite useful lives are no longer amortized, but are
instead tested for impairment at least annually. Also, Devon adopted the
provisions of SFAS No. 141, Business Combinations, at the time of issuance in
July 2001 for business combinations after that date. Under the provisions of
SFAS No. 141 and the applicable portions of SFAS No. 142, any goodwill and any
intangible asset determined to have an indefinite useful life that are acquired
in a purchase business combination completed after June 30, 2001 are not
amortized, but are to be evaluated for impairment in accordance with the
appropriate pre- SFAS No. 142 accounting literature. Goodwill and intangible
assets acquired in business combinations completed before July 1, 2001 continued
to be amortized prior to the full adoption of SFAS No. 142.
Devon will perform an assessment of whether there is an indication that
goodwill is impaired as of January 1, 2002. Devon will identify its reporting
units and determine the carrying value of each reporting unit by assigning the
assets and liabilities, including the existing goodwill, to those reporting
units as of January 1, 2002. Devon then has until June 30, 2002, to determine
the fair value of each reporting unit and compare it to the reporting unit's
carrying amount. To the extent a reporting unit's carrying amount exceeds its
fair
62
value, an indication exists that the reporting unit's goodwill may be impaired
and Devon must perform the second step of the transitional impairment test. In
the second step, Devon must compare the implied fair value of the reporting
unit's goodwill, determined by allocating the reporting unit's fair value to all
of it assets (recognized and unrecognized) and liabilities in a manner similar
to a purchase price allocation in accordance with SFAS No. 141, to its carrying
amount, both of which would be measured as of January 1, 2002. This second step
is required to be completed as soon as possible, but no later than the end of
2002. Any transitional impairment loss will be recognized as the cumulative
effect of a change in accounting principle in Devon's 2002 statement of
operations.
As of January 1, 2002, Devon had unamortized goodwill in the amount of
$2.2 billion, which was subject to the transition provisions of SFAS Nos. 141
and 142. Devon has not completed its assessment of the impact of adopting the
remaining provisions of SFAS Nos. 141 and 142 on Devon's financial statements.
However, Devon does not believe that a transitional impairment loss will be
required to be recognized.
Also in June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. SFAS No. 143 requires liability recognition for
retirement obligations associated with tangible long-lived assets, such as
producing well sites, offshore production platforms, and natural gas processing
plants. The obligations included within the scope of SFAS No. 143 are those for
which a company faces a legal obligation for settlement. The initial measurement
of the asset retirement obligation is to be fair value, defined as "the price
that an entity would have to pay a willing third party of comparable credit
standing to assume the liability in a current transaction other than in a forced
or liquidation sale." Devon expects that it will use a valuation technique such
as expected present value to estimate fair value.
The asset retirement cost equal to the fair value of the retirement
obligation is to be capitalized as part of the cost of the related long-lived
asset and allocated to expense using a systematic and rational method.
Devon will be required to adopt SFAS No. 143 effective January 1, 2003
using a cumulative effect approach to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated depreciation.
Devon currently records estimated costs of dismantlement, removal, site
reclamation, and other similar activities as part of depreciation, depletion,
and amortization and does not record a separate liability for such amounts.
Devon has not completed the assessment of the impact that adoption of SFAS No.
143 will have on its consolidated financial statements. However, Devon expects
the amounts for capitalized oil and gas property costs and asset retirement
obligations will increase.
In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, which supersedes both SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of and the accounting and reporting provisions of APB Opinion No.
30, Reporting the Results of Operations-Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary,
63
Unusual and Infrequently Occurring Events and Transactions, for the disposal of
a segment of a business (as previously defined in that Opinion). SFAS No. 144
retains the fundamental provisions in SFAS No. 121 for recognizing and measuring
impairment losses on long-lived assets held for use and long-lived assets to be
disposed of by sale, while also resolving significant implementation issues
associated with SFAS No. 121. For example, SFAS No. 144 provides guidance on how
a long-lived asset that is used as part of a group should be evaluated for
impairment, establishes criteria for when a long-lived asset is held for sale,
and prescribes the accounting for a long-lived asset that will be disposed of
other than by sale. SFAS No. 144 retains the basic provisions of APB No. 30 on
how to present discontinued operations in the income statement but broadens that
presentation to include a component of an entity (rather than a segment of a
business). Unlike SFAS No. 121, an impairment assessment under SFAS No. 144 will
never result in a write-down of goodwill. Rather, goodwill is evaluated for
impairment under SFAS No. 142, Goodwill and Other Intangible Assets.
Devon adopted SFAS No. 144 effective January 1, 2002. Management does not
expect the adoption of SFAS No. 144 for long-lived assets held for use or for
disposal to have a material impact on Devon's financial statements because Devon
utilizes the full cost method of accounting for oil and gas exploration and
development activities and the impairment assessment under SFAS No. 144 is
largely unchanged from SFAS No. 121.
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. Devon does not hold or issue derivative instruments for trading
purposes.
64
Devon's total hedged positions as of January 31, 2002 are set forth in the
following tables.
PRICE SWAPS Through various price swaps, Devon has fixed the price it will
receive on a portion of its oil and natural gas production in 2002, 2003 and
2004. The following tables include information on this production. 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.
OIL PRODUCTION
------------------------------------------------------
FIRST HALF OF 2002 SECOND HALF OF 2002
---------------------- ----------------------
BBLS/DAY PRICE/BBL BBLS/DAY PRICE/BBL
-------- --------- -------- ---------
United States 22,000 $ 23.85 22,000 $ 23.85
Canada 4,350 $ 20.33 4,350 $ 20.33
GAS PRODUCTION
------------------------------------------------------
FIRST HALF OF 2002 SECOND HALF OF 2002
---------------------- ----------------------
MCF/DAY PRICE/MCF MCF/DAY PRICE/MCF
-------- --------- -------- ---------
United States 211,936 $3.11 198,346 $3.19
Canada 40,673 $2.13 33,472 $2.12
FIRST HALF OF 2003 SECOND HALF OF 2003
---------------------- ----------------------
MCF/DAY PRICE/MCF MCF/DAY PRICE/MCF
------- --------- ------- ---------
United States 89,726 $3.50 100,000 $3.32
Canada 5,000 $2.49 5,000 $2.03
FIRST HALF OF 2004 SECOND HALF OF 2004
---------------------- ----------------------
MCF/DAY PRICE/MCF MCF/DAY PRICE/MCF
------- --------- ------- ---------
United States -- $ -- -- $ --
Canada 5,000 $2.58 3,342 $2.03
COSTLESS PRICE COLLARS Devon has also entered into costless price collars
that set a floor and ceiling price for a portion of its 2002 and 2003 oil and
natural gas production. The following tables include information on these
collars for each geographic area. The floor and ceiling prices related to
domestic oil production are based on NYMEX. The NYMEX price is the monthly
average of settled prices on each trading day for West Texas Intermediate Crude
oil delivered at Cushing, Oklahoma. The gas prices shown in the following table
have been adjusted to a NYMEX-based price, using Devon's estimates of
differentials between NYMEX and the specific regional indices upon which the
collars are based. The floor and ceiling prices related to the domestic collars
are based on various regional first-of-the-month price indices as published
65
monthly by Inside FERC. The floor and ceiling prices related to the Canadian
collars 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.
The floor and ceiling prices in the following table are weighted averages
of all the various collars.
OIL PRODUCTION
----------------------------------------------------------------------------------------
FIRST HALF OF 2002 SECOND HALF OF 2002
---------------------------------------- ----------------------------------------
FLOOR CEILING FLOOR CEILING
PRICE PRICE PRICE PRICE
PER PER PER PER
BBLS/DAY BBL BBL BBLS/DAY BBL BBL
-------- --- --- -------- --- ---
United States 20,000 $23.00 $28.19 20,000 $23.00 $28.19
GAS PRODUCTION
--------------------------------------------------------------------------------------
FIRST HALF OF 2002 SECOND HALF OF 2002
--------------------------------------- ---------------------------------------
FLOOR CEILING FLOOR CEILING
PRICE PRICE PRICE PRICE
PER PER PER PER
MMBTU/DAY MMBTU MMBTU MMBTU/DAY MMBTU MMBTU
--------- ----- ----- --------- ----- -----
United States 450,000 $3.32 $6.27 320,000 $3.44 $6.97
Canada 67,667 $3.15 $5.00 48,705 $3.17 $5.20
FIRST HALF OF 2003 SECOND HALF OF 2003
--------------------------------------- ---------------------------------------
FLOOR CEILING FLOOR CEILING
PRICE PRICE PRICE PRICE
PER PER PER PER
MMBTU/DAY MMBTU MMBTU MMBTU/DAY MMBTU MMBTU
--------- ----- ----- --------- ----- -----
United States 265,000 $3.18 $4.22 265,000 $3.18 $4.22
Canada 80,000 $3.27 $4.07 80,000 $3.27 $4.07
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, 2002, a 10% increase
in the underlying commodities' prices would have reduced the fair value of
Devon's commodity hedging instruments by $118 million.
66
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.
The price Devon will receive on a portion of its 2002 oil production has
been fixed through certain forward oil sales assumed in the 2000 Santa Fe Snyder
merger. From January 2002 through August 2002, 311,000 barrels of oil production
per month have been fixed at an average price of $16.84 per barrel.
For each of the years 2002 through 2011, Devon has fixed-price gas
contracts that cover approximately 24 Bcf, 19 Bcf, 19 Bcf, 19 Bcf, 19 Bcf, 17
Bcf, 16 Bcf, 16 Bcf, 15 Bcf and 13 Bcf, respectively, of Canadian production.
Devon also has Canadian gas volumes subject to fixed-price contracts in the
years from 2012 through 2016, but the yearly volumes are less than 1 Bcf.
INTEREST RATE RISK At December 31, 2001, Devon had long-term debt
outstanding of $6.6 billion. Of this amount, $5.4 billion, or 82%, bears
interest at fixed rates averaging 7%. The remaining $1.2 billion of debt
outstanding bears interest at floating rates which averaged 3%. In January 2002,
Devon borrowed the remaining $2 billion on its $3 billion term loan credit
facility to fund the Mitchell acquisition. The interest rate on the term loan
credit facility is floating.
The terms of Devon's various floating rate debt facilities (revolving
credit facilities, commercial paper and term loan credit facility) allow
interest rates to be fixed at Devon's option for periods of between seven to 180
days. A 10% increase in short-term interest rates on the floating-rate debt
outstanding as of December 31, 2001, as adjusted for the new floating rate debt
drawn down in January 2002, would equal approximately 30 basis points. Such an
increase in interest rates would increase Devon's 2002 interest expense by
approximately $4 million assuming borrowed amounts remain outstanding for the
remainder of 2002.
Devon assumed certain interest rate swaps as a result of the Anderson
acquisition. Under these interest rate swaps, Devon has swapped a floating rate
for a fixed rate. Under such swaps, Devon will record a fixed rate of 6.2% on
$132 million of debt in 2002, 6.3% on $97 million of debt in 2003, 6.4% on $79
million of debt in 2004 through 2006 and 6.3% on $24 million of debt in 2007.
The amount of gains or losses realized from such swaps are included as increases
or decreases to interest expense.
Devon uses a sensitivity analysis technique to evaluate the hypothetical
effect that changes in interest rates may have on the fair value of its interest
rate swap instruments. At January 31, 2002, a 10% increase in the underlying
interest rates would have decreased the fair value of Devon's interest rate
swaps by $1 million.
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 Canadian dollar functional currency. Assets and
liabilities of the Canadian subsidiaries are translated to U.S.
67
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.
As a result of the Anderson acquisition, Devon's Canadian subsidiary, Devon
Canada, assumed $400 million of fixed-rate long-term debt that is denominated in
U.S. dollars. Changes in the currency conversion rate between the Canadian and
U.S. dollars between the beginning and end of a reporting period increase or
decrease the expected amount of Canadian dollars required to repay the notes.
The amount of such increase or decrease is required to be included in
determining net earnings for the period in which the exchange rate changes. A
$0.03 decrease in the Canadian-to-U.S. dollar exchange rate would cause Devon to
record a charge of approximately $20 million. The $400 million becomes due in
March 2011. Until then, the gains or losses caused by the exchange rate
fluctuations have no effect on cash flow.
Devon assumed certain foreign currency exchange rate swaps in the Anderson
acquisition. These swaps require Devon to sell $30 million in 2002 and $12
million in 2003 at average Canadian-to-U.S. exchange rates of $0.680 and $0.676,
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 gas sales. At the December 31, 2001 exchange rate, these swaps would
result in a decrease to gas sales during 2002 and 2003 of approximately $2
million and $1 million, respectively. A further $0.03 decrease in the
Canadian-to-U.S. dollar exchange rate would result in an additional decrease to
2002 and 2003 gas sales of approximately $1 million in each year.
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 nine 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 2001 rate.
68
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
Page
----
Independent Auditors' Reports......................................... 70-71
Consolidated Financial Statements:
Consolidated Balance Sheets
December 31, 2001, 2000, and 1999............................... 72
Consolidated Statements of Operations
Years Ended December 31, 2001, 2000, and 1999................... 73
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 2001, 2000, and 1999................... 74
Consolidated Statements of Cash Flows
Years Ended December 31, 2001, 2000, and 1999................... 75
Notes to Consolidated Financial Statements
December 31, 2001, 2000, and 1999............................... 76
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.
69
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, 2001, 2000 and
1999, 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 financial statements
of Santa Fe Snyder Corporation, a wholly-owned subsidiary, which statements
reflect total assets constituting 24% in 1999 of the related consolidated
totals, and which statements reflect total revenues constituting 41% in 1999 of
the related consolidated totals. The 1999 financial statements of Santa Fe
Snyder Corporation were audited by other auditors whose report has been
furnished to us, and our opinion, insofar as it relates to the amounts included
for Santa Fe Snyder Corporation in 1999 is based solely on the report 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 report of
the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report 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, 2001, 2000 and 1999, 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.
As described in Note 1 to the consolidated financial statements, as of January
1, 2001, the Company changed its method of accounting for derivative instruments
and hedging activities and, effective July 1, 2001, adopted the provisions of
Statement of Financial Accounting Standards ("SFAS") No. 141, Business
Combinations, and certain provisions of SFAS No. 142, Goodwill and Other
Intangible Assets.
KPMG LLP
Oklahoma City, Oklahoma
February 5, 2002
70
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 the results of their operations and their cash flows for the year ended
December 31, 1999 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 audit. We conducted our audit 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
audit provides 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
71
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE DATA)
DECEMBER 31,
------------------------------------------
2001 2000 1999
-------- ------ ------
ASSETS
Current assets:
Cash and cash equivalents $ 193 228 173
Accounts receivable 537 598 316
Inventories 41 47 39
Deferred income taxes -- 9 5
Fair value of financial instruments 195 -- --
Income taxes receivable 68 -- --
Investments and other current assets 47 52 57
-------- ------ ------
Total current assets 1,081 934 590
-------- ------ ------
Property and equipment, at cost, based on the full cost method of
accounting for oil and gas properties ($1,939, $315 and $301
excluded from amortization in 2001, 2000 and 1999, respectively) 15,598 9,709 8,592
Less accumulated depreciation, depletion and amortization 6,570 4,799 4,168
-------- ------ ------
9,028 4,910 4,424
Investment in ChevronTexaco Corporation common stock, at fair value 636 599 614
Fair value of financial instruments 31 -- --
Goodwill 2,206 289 323
Other assets 202 128 145
-------- ------ ------
Total assets $ 13,184 6,860 6,096
======== ====== ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade 465 321 267
Revenues and royalties due to others 170 116 67
Income taxes payable 30 66 13
Accrued interest payable 102 23 28
Merger related expenses payable 7 52 36
Fair value of financial instruments 15 -- --
Deferred income taxes 57 -- --
Accrued expenses 73 51 56
-------- ------ ------
Total current liabilities 919 629 467
-------- ------ ------
Other liabilities 179 164 263
Debentures exchangeable into shares of ChevronTexaco Corporation
common stock 649 760 760
Other long-term debt 5,940 1,289 1,656
Deferred revenue 51 114 105
Fair value of financial instruments 45 -- --
Deferred income taxes 2,142 627 324
Stockholders' equity:
Preferred stock of $1.00 par value ($100 liquidation value)
Authorized 4,500,000 shares; issued 1,500,000 in 2001, 2000 and 1999 1 1 1
Common stock of $.10 par value
Authorized 400,000,000 shares; issued 126,132,000 in
2001, 128,638,000 in 2000 and 126,323,000 in 1999 13 13 13
Additional paid-in capital 3,610 3,564 3,492
Accumulated deficit (147) (215) (909)
Accumulated other comprehensive loss (28) (85) (65)
Unamortized restricted stock awards -- (1) --
Treasury stock, at cost: 3,754,000 shares in 2001 and 330,000
shares in 1999 (190) -- (11)
-------- ------ ------
Total stockholders' equity 3,259 3,277 2,521
-------- ------ ------
Commitments and contingencies (Notes 12 and 13)
Total liabilities and stockholders' equity $ 13,184 6,860 6,096
======== ====== ======
See accompanying notes to consolidated financial statements.
72
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
----------------------------------------
2001 2000 1999
------- ------ ------
REVENUES
Oil sales $ 958 1,079 561
Gas sales 1,890 1,485 628
Natural gas liquids sales 132 154 68
Other 95 66 21
------- ------ ------
Total revenues 3,075 2,784 1,278
------- ------ ------
COSTS AND EXPENSES
Lease operating expenses 531 441 299
Transportation costs 83 53 34
Production taxes 117 103 45
Depreciation, depletion and amortization of property and equipment 876 693 406
Amortization of goodwill 34 41 16
General and administrative expenses 111 93 81
Expenses related to mergers 1 60 17
Interest expense 220 155 109
Effects of changes in foreign currency exchange rates 13 3 (13)
Distributions on preferred securities of subsidiary trust -- -- 7
Change in fair value of financial instruments 2 -- --
Reduction of carrying value of oil and gas properties 1,003 -- 476
------- ------ ------
Total costs and expenses 2,991 1,642 1,477
------- ------ ------
Earnings (loss) before income taxes, extraordinary item and cumulative
effect of change in accounting principle 84 1,142 (199)
INCOME TAX EXPENSE (BENEFIT)
Current 71 131 23
Deferred (41) 281 (72)
------- ------ ------
Total income tax expense (benefit) 30 412 (49)
------- ------ ------
Earnings (loss) before extraordinary item and cumulative effect of
change in accounting principle 54 730 (150)
Extraordinary loss -- -- (4)
------- ------ ------
Earnings (loss) before cumulative effect of change in accounting
principle 54 730 (154)
Cumulative effect of change in accounting principle 49 -- --
------- ------ ------
Net earnings (loss) 103 730 (154)
Preferred stock dividends 10 10 4
------- ------ ------
Net earnings (loss) applicable to common shareholders $ 93 720 (158)
======= ====== ======
Net earnings (loss) per average common share outstanding:
Before extraordinary loss and cumulative effect of change in
accounting principle:
Basic $ 0.34 5.66 (1.64)
======= ====== ======
Diluted $ 0.34 5.50 (1.64)
======= ====== ======
Before cumulative effect of change in accounting principle:
Basic $ 0.34 5.66 (1.68)
======= ====== ======
Diluted $ 0.34 5.50 (1.68)
======= ====== ======
Applicable to common shareholders:
Basic $ 0.73 5.66 (1.68)
======= ====== ======
Diluted $ 0.72 5.50 (1.68)
======= ====== ======
Weighted average common shares outstanding:
Basic 128 127 94
======= ====== ======
Diluted 130 132 99
======= ====== ======
See accompanying notes to consolidated financial statements.
73
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS)
ACCUMU-
LATED
OTHER UNAMORTIZED
ADDITIONAL ACCUMU- COMPRE- RESTRICTED
PREFERRED COMMON PAID-IN LATED HENSIVE STOCK
STOCK STOCK CAPITAL DEFICIT LOSS AWARDS
----- ----- ------- ------- ---- ------
Balance as of December 31, 1998 $ -- 7 1,524 (737) (36) (1)
Comprehensive loss:
Net loss -- -- -- (154) -- --
Other comprehensive earnings (loss),
net of tax:
Foreign currency translation adjustments -- -- -- -- 7 --
Unrealized loss on marketable securities -- -- -- -- (36) --
Other comprehensive loss -- -- -- -- -- --
Comprehensive loss
Stock issued 1 6 1,967 (1) -- --
Stock repurchased -- -- -- -- -- --
Tax benefit related to employee stock -- -- 1 -- -- --
options
Dividends on common stock -- -- -- (13) -- --
Dividends on preferred stock -- -- -- (4) -- --
Amortization of restricted stock awards -- -- -- -- -- 1
----- ---- ------ ---- ---- ----
Balance as of December 31, 1999 1 13 3,492 (909) (65) --
Comprehensive loss:
Net earnings -- -- -- 730 -- --
Other comprehensive earnings (loss),
net of tax:
Foreign currency translation adjustments -- -- -- -- (10) --
Minimum pension liability adjustment -- -- -- -- 1 --
Unrealized loss on marketable securities -- -- -- -- (11) --
Other comprehensive loss -- -- -- -- -- --
Comprehensive earnings
Stock issued -- -- 69 (4) -- --
Stock repurchased -- -- -- -- -- --
Tax benefit related to employee stock
options -- -- 3 -- -- --
Dividends on common stock -- -- -- (22) -- --
Dividends on preferred stock -- -- -- (10) -- --
Grant of restricted stock awards -- -- -- -- -- (5)
Amortization of restricted stock awards -- -- -- -- -- 4
----- ---- ------ ---- ---- ----
Balance as of December 31, 2000 1 13 3,564 (215) (85) (1)
Comprehensive earnings:
Net earnings -- -- -- 103 -- --
Other comprehensive earnings (loss),
net of tax:
Foreign currency translation
adjustments -- -- -- -- (107) --
Cumulative effect of change in
Accounting principle -- -- -- -- (37) --
Reclassification adjustment for
Derivative (gains) losses
reclassified
Into oil and gas sales -- -- -- -- (20) --
Change in fair value of financial
instruments -- -- -- -- 216 --
Minimum pension liability adjustment -- -- -- -- (17) --
Unrealized gain on marketable
securities -- -- -- -- 22 --
Other comprehensive earnings -- -- -- -- -- --
Comprehensive earnings
Stock issued -- -- 48 -- -- --
Stock repurchased -- -- (14) -- -- --
Tax benefit related to employee stock
options -- -- 12 -- -- --
Dividends on common stock -- -- -- (25) -- --
Dividends on preferred stock -- -- -- (10) -- --
Amortization of restricted stock awards -- -- -- -- -- 1
----- ---- ------ ---- ---- ----
Balance as of December 31, 2001 $ 1 13 3,610 (147) (28) --
===== ==== ====== ==== ==== ====
TOTAL
STOCK-
TREASURY HOLDERS'
STOCK EQUITY
----- ------
Balance as of December 31, 1998 (7) 750
Comprehensive loss:
Net loss -- (154)
Other comprehensive earnings (loss),
net of tax:
Foreign currency translation adjustments -- 7
Unrealized loss on marketable securities -- (36)
------
Other comprehensive loss -- (29)
------
Comprehensive loss (183)
Stock issued 8 1,981
Stock repurchased (12) (12)
Tax benefit related to employee stock
options -- 1
Dividends on common stock -- (13)
Dividends on preferred stock -- (4)
Amortization of restricted stock awards -- 1
---- ------
Balance as of December 31, 1999 (11) 2,521
Comprehensive loss:
Net earnings -- 730
Other comprehensive earnings (loss),
net of tax:
Foreign currency translation adjustments -- (10)
Minimum pension liability adjustment -- 1
Unrealized loss on marketable securities -- (11)
------
Other comprehensive loss -- (20)
------
710
Comprehensive earnings
Stock issued 21 86
Stock repurchased (10) (10)
Tax benefit related to employee stock
options -- 3
Dividends on common stock -- (22)
Dividends on preferred stock -- (10)
Grant of restricted stock awards -- (5)
Amortization of restricted stock awards -- 4
---- ------
Balance as of December 31, 2000 -- 3,277
Comprehensive earnings:
Net earnings -- 103
Other comprehensive earnings (loss),
net of tax:
Foreign currency translation
adjustments -- (107)
Cumulative effect of change in
Accounting principle -- (37)
Reclassification adjustment for
Derivative (gains) losses
reclassified Into oil and
gas sales -- (20)
Change in fair value of financial
instruments -- 216
Minimum pension liability adjustment -- (17)
Unrealized gain on marketable
securities -- 22
------
Other comprehensive earnings -- 57
------
160
Comprehensive earnings
Stock issued -- 48
Stock repurchased (190) (204)
Tax benefit related to employee stock
options -- 12
Dividends on common stock -- (25)
Dividends on preferred stock -- (10)
Amortization of restricted stock awards -- 1
---- ------
Balance as of December 31, 2001 (190) 3,259
==== ======
See accompanying notes to consolidated financial statements.
74
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
------------------------------------------
2001 2000 1999
------- ------- ------
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings (loss) $ 103 730 (154)
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization of property
and equipment 876 693 406
Amortization of goodwill 34 41 16
Accretion (amortization) of discounts (premiums) on
long-term debt, net 26 3 (1)
Effects of changes in foreign currency exchange rates 13 3 (13)
Change in fair value of financial instruments 2 -- --
Reduction of carrying value of oil and gas properties 1,003 -- 476
Loss (gain) on sale of assets 2 (1) 5
Deferred income tax expense (benefit) (41) 281 (72)
Cumulative effect of change in accounting principle (49) -- --
Other (3) 4 2
Changes in assets and liabilities, net of effects of
acquisitions of businesses:
Decrease (increase) in:
Accounts receivable 191 (284) (93)
Inventories 15 (8) (9)
Income taxes receivable (68) -- --
Investments and other current assets 2 10 (41)
(Decrease) increase in:
Accounts payable 29 99 (23)
Income taxes payable (117) 61 (19)
Accrued interest and expenses (46) 3 (38)
Deferred revenue (63) 8 91
Long-term other liabilities (23) (24) (1)
------- ------- ------
Net cash provided by operating activities 1,886 1,619 532
------- ------- ------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property and equipment 41 101 114
Proceeds from sale of investments -- 13 --
Capital expenditures, including acquisitions of businesses (5,326) (1,280) (883)
(Increase) decrease in other assets -- (7) 1
------- ------- ------
Net cash used in investing activities (5,285) (1,173) (768)
------- ------- ------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings of long-term debt, net of issuance
costs 6,199 2,580 1,945
Principal payments on long-term debt (2,638) (2,952) (2,089)
Issuance of common stock, net of issuance costs 48 51 530
Repurchase of common stock (204) (10) (12)
Issuance of treasury stock -- 25 6
Dividends paid on common stock (25) (22) (13)
Dividends paid on preferred stock (10) (10) (4)
(Decrease) increase in long-term other liabilities -- (52) 14
------- ------- ------
Net cash provided by (used in) financing
activities 3,370 (390) 377
------- ------- ------
Effect of exchange rate changes on cash (6) (1) 1
------- ------- ------
Net (decrease) increase in cash and cash equivalents (35) 55 142
Cash and cash equivalents at beginning of year 228 173 31
------- ------- ------
Cash and cash equivalents at end of year $ 193 $ 228 173
======= ======= ======
See accompanying notes to consolidated financial statements.
75
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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.
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.
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. Internal costs
incurred that are directly identified with acquisition, exploration and
development activities undertaken by Devon for its own account, and which are
not related to production, general corporate overhead or similar activities are
also capitalized. For the years 2001, 2000 and 1999, such internal costs
capitalized totaled $77 million, $62 million and $29 million, respectively.
76
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
Unproved properties are excluded from amortized capitalized costs until it
is determined whether or not proved reserves can be assigned to such properties.
Devon assesses its unproved properties for impairment at least annually.
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 plus the lower of cost or fair value of unproved properties.
Such limitations are imposed separately on a country-by-country basis and are
tested quarterly. 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. Depletion is calculated using
the capitalized costs plus the estimated future expenditures (based on current
costs) to be incurred in developing proved reserves, and the estimated
dismantlement and abandonment costs, net of estimated salvage values. 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. All costs related to production activities, including workover costs
incurred solely to maintain or increase levels of production from an existing
completion interval, are charged to expense as incurred.
Depreciation and amortization of other property and equipment, including
leasehold improvements, are provided using the straight-line method based on
estimated useful lives from three 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 ChevronTexaco
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, acquired before June 30, 2001, is amortized by an
equivalent unit-of-production method. Goodwill acquired after June 30, 2001, is
not amortized. Devon assesses the recoverability of goodwill 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
77
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
funds. The assessment of the recoverability of goodwill will be impacted if
estimated future operating cash flows are not achieved.
Accumulated goodwill amortization was $91 million, $57 million and $16
million at December 31, 2001, 2000 and 1999, respectively.
Effective January 1, 2002, Devon adopted the remaining provisions of SFAS
No. 142, Goodwill and Other Intangible Assets. Under SFAS No. 142, goodwill and
intangible assets with indefinite useful lives are no longer amortized, but are
instead tested for impairment at least annually. Also, Devon adopted the
provisions of SFAS No. 141, Business Combinations, and certain provisions of
SFAS No. 142 in July 2001. Under the provisions of SFAS No. 142, any goodwill
and any intangible asset determined to have an indefinite useful life that were
acquired in a purchase business combination completed after June 30, 2001 are
not amortized, but are to be evaluated for impairment at December 31, 2001, in
accordance with the appropriate pre- SFAS No. 142 accounting. Goodwill and
intangible assets acquired in business combinations completed before July 1,
2001 continued to be amortized prior to the adoption of the remaining provisions
of SFAS No. 142.
Devon will perform an assessment of whether there is an indication that
goodwill is impaired as of January 1, 2002. Devon will identify its reporting
units and determine the carrying value of each reporting unit by assigning the
assets and liabilities, including the existing goodwill, to those reporting
units as of January 1, 2002. Devon has until June 30, 2002, to determine the
fair value of each reporting unit and compare such value to the reporting unit's
carrying amount. To the extent a reporting unit's carrying amount exceeds its
fair value, an indication exists that the reporting unit's goodwill may be
impaired and Devon must perform the second step of the transitional impairment
test. In the second step, Devon must compare the implied fair value of the
reporting unit's goodwill, determined by allocating the reporting unit's fair
value to all of it assets (recognized and unrecognized) and liabilities in a
manner similar to a purchase price allocation in accordance with SFAS No. 141,
to its carrying amount, both of which would be measured as of January 1, 2002.
This second step is required to be completed as soon as possible, but no later
than the end of 2002. Any transitional impairment loss will be recognized as the
cumulative effect of a change in accounting principle in Devon's 2002 statement
of operations.
As of January 1, 2002, Devon had unamortized goodwill in the amount of $2.2
billion, which was subject to the transition provisions of SFAS Nos. 141 and
142. Devon has not completed its assessment of the impact on its financial
statements of adopting SFAS Nos. 141 and 142. However, Devon does not believe
that a transitional impairment loss will be required to be recognized.
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
78
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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 and gas 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.
It is Devon's policy to only enter into derivative contracts with investment
grade rated counterparties deemed by management to be competent and competitive
market makers. 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.
As of January 1, 2001, Devon adopted the provisions of SFAS No. 133,
Accounting for Derivative Instruments and Certain Hedging Activities and SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an Amendment of SFAS No. 133. SFAS Nos. 133 and 138 require that all
derivative instruments be recorded on the balance sheet at their respective fair
values. In accordance with the transition provisions of SFAS No. 133, Devon
recorded a net-of-tax cumulative-effect-type adjustment of $37 million loss in
accumulated other comprehensive loss to recognize the fair value of all
derivatives that were designated as cash-flow hedging instruments. Additionally,
Devon recorded a net-of-tax cumulative-effect-type adjustment to net earnings of
$49 million gain ($0.38 per basic share and $0.37 per diluted share) related to
the fair value of derivative instruments that did not qualify as hedges. This
gain related principally to the option embedded in Devon's debentures that are
exchangeable into shares of ChevronTexaco Corporation common stock.
All derivatives are recognized on the balance sheet at their fair value.
The majority of Devon's derivatives that qualify for hedge accounting treatment
are either "cash flow" hedges or "foreign currency cash flow" hedges
(collectively, "cash flow hedges"). Devon designates its cash flow hedge
derivatives as such on the date the derivative contract is entered into or the
date of a business combination which includes cash flow hedges. Devon formally
documents all relationships between hedging instruments and hedged items, as
well as its risk-management objective and strategy for undertaking various hedge
transactions. Devon also assesses, both at the hedge's inception and on an
ongoing basis, whether the derivatives that are used in hedging transactions are
highly effective in offsetting changes in cash flows of hedged items.
79
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
During 2001, there were no gains or losses reclassified into earnings as a
result of the discontinuance of hedge accounting treatment for any of Devon's
derivatives.
By using derivative instruments to hedge exposures to changes in commodity
prices and exchange rates, Devon exposes itself to credit risk and market risk.
Credit risk is the failure of the counterparty to perform under the terms of the
derivative contract. To mitigate this risk, the hedging instruments are usually
placed with counterparties that Devon believes are minimal credit risks.
Market risk is the adverse effect on the value of a derivative instrument
that results from a change in interest rates, commodity prices, or currency
exchange rates. The market risk associated with commodity price and foreign
exchange contracts is managed by establishing and monitoring parameters that
limit the types and degree of market risk that may be undertaken.
Devon does not hold or issue derivative instruments for trading purposes.
The majority of Devon's commodity price swaps and costless price collars,
interest rate swaps, and foreign exchange rate swaps in place at January 1, 2001
through December 31, 2001 have been designated as cash flow hedges. Changes in
the fair value of these derivatives are reported on the balance sheet in
"Accumulated other comprehensive loss" ("AOCL"). These amounts are reclassified
to oil and gas sales or interest expense when the forecasted transaction takes
place.
During the third quarter of 2001, Devon entered into foreign exchange
forward contracts to mitigate the effect of volatility in the Canadian-to-U.S.
dollar exchange rate on the Anderson acquisition. Under SFAS No. 133, these
derivative instruments were not considered hedges and, as such, the realized
gain of $30 million from settling these contracts is included in the 2001
consolidated statement of operations as other revenues.
During the third quarter of 2001, Devon also entered into interest rate
locks to reduce exposure to the variability in market interest rates,
specifically U.S. Treasury rates, in anticipation of the sale of the debt
securities discussed in Note 7. These derivative instruments were designated as
cash flow hedges. A $28 million loss was incurred on these interest rate locks.
This loss will be amortized into interest expense using the effective interest
method over the life of the debt securities.
Devon assesses the effectiveness of its hedges based on changes in the
derivative's intrinsic value. The change in the time value of the derivative is
excluded from the assessment of hedge effectiveness and, along with any
ineffectiveness, is recorded on the statement of operations in "Change in fair
value of derivative instruments." For the year ended December 31, 2001, Devon
recorded a net charge of approximately $10 million which represented (i) the
ineffectiveness of the various cash flow hedges and (ii) the component of the
derivative instrument gain or loss excluded from the assessment of hedge
effectiveness.
As of December 31, 2001, $180 million of net deferred gains on derivative
instruments accumulated in AOCL are expected to be reclassified to earnings
during the next 12 months. Transactions and events expected to occur over the
next 12 months that will necessitate reclassifying
80
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
these derivatives' gains to earnings are primarily the production and sale of
oil and gas which includes the production hedged under the various derivative
instruments. The maximum term over which Devon is hedging exposures to the
variability of cash flows for commodity price risk is 34 months.
Devon recorded in its statements of operations a loss of $2 million for the
year ended December 31, 2001 for the change in fair value of derivative
instruments that do not qualify for hedge accounting treatment.
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 2001 and 2000, Enron Capital and Trade Resource Corporation accounted
for 16% and 20%, respectively, of Devon's combined oil, gas and natural gas
liquids sales. No purchaser accounted for over 10% of such revenues in 1999.
On December 2, 2001, Enron Corp. and certain of its subsidiaries filed
voluntary petitions for reorganization under Chapter 11 of the United States
Bankruptcy Code. Prior to this date, Devon had terminated substantially all of
its agreements to sell oil or gas to Enron related entities. Devon incurred $3
million of losses for sales to Enron related subsidiaries which were not
collected prior to the bankruptcy filing.
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.
81
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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.
The following table reconciles the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
2001 and 2000. The diluted loss per share calculations for 1999 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.) Therefore, the diluted loss per share amounts for 1999 reported in the
accompanying consolidated statements of operations are the same as the basic
loss per share amounts.
82
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
NET EARNINGS WEIGHTED
APPLICABLE AVERAGE NET
TO COMMON COMMON SHARES EARNINGS
STOCKHOLDERS OUTSTANDING PER SHARE
------------ ----------- ---------
(IN MILLIONS)
YEAR ENDED DECEMBER 31, 2001:
Basic earnings per share $ 93 128 $0.73
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options -- 2
---- ---
Diluted earnings per share $ 93 130 $0.72
==== === =====
YEAR ENDED DECEMBER 31, 2000:
Basic earnings per share $720 127 $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 $3) 5 3
Potential common shares issuable upon the exercise
of outstanding stock options -- 2
---- ---
Diluted earnings per share $725 132 $5.50
==== === =====
The senior convertible debentures were not included in the 2001 dilution
calculation because the inclusion was anti-dilutive.
Options to purchase approximately three million shares of Devon's common
stock with exercise prices ranging from $48.13 per share to $89.66 per share
(with a weighted average price of $56.11 per share) were outstanding at December
31, 2001, but were not included in the computation of diluted earnings per share
for 2001 because the options' exercise price exceeded the average market price
of Devon's common stock during the year. The excluded options for 2001 expire
between February 18, 2002 and December 4, 2011. Options to purchase
approximately one 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. All options were excluded from the diluted earnings per
share calculations for 1999.
Comprehensive Earnings or Loss
Devon's comprehensive earnings or loss information is included in the
accompanying consolidated statements of stockholders' equity. A summary of
accumulated other comprehensive
83
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
earnings or loss as of December 31, 2001, 2000 and 1999, and changes during each
of the years then ended, is presented in the following table.
CHANGE IN FAIR MINIMUM
FOREIGN VALUE OF PENSION UNREALIZED
CURRENCY FINANCIAL LIABILITY GAIN (LOSS) ON
TRANSLATION INSTRU- ADJUST- MARKET-ABLE
ADJUSTMENTS MENTS MENTS SECURITIES TOTAL
----------- ----- ----- ---------- -----
(IN MILLIONS)
Balance as of December 31, 1998 $ (35) $ -- $ (1) $ -- $ (36)
1999 activity 7 -- -- (60) (53)
Deferred taxes -- -- -- 24 24
----- ----- ---- ---- -----
1999 activity, net of deferred taxes 7 -- -- (36) (29)
----- ----- ---- ---- -----
Balance as of December 31, 1999 (28) -- (1) (36) (65)
2000 activity (10) -- 1 (18) (27)
Deferred taxes -- -- -- 7 7
----- ----- ---- ---- -----
2000 activity, net of deferred taxes (10) -- 1 (11) (20)
----- ----- ---- ---- -----
Balance as of December 31, 2000 (38) -- -- (47) (85)
2001 activity (107) 243 (28) 36 144
Deferred taxes -- (84) 11 (14) (87)
----- ----- ---- ---- -----
2001 activity, net of deferred taxes (107) 159 (17) 22 57
----- ----- ---- ---- -----
Balance as of December 31, 2001 $(145) $ 159 $(17) $(25) $ (28)
===== ===== ==== ==== =====
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 2001, 2000 and 1999 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, annual dividends per
share for 2001, 2000 and 1999 were $0.20, $0.17 and $0.14, 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.
84
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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 2000 and 1999 amounts in the accompanying consolidated
financial statements have been reclassified to conform to the 2001 presentation.
2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION
Mitchell Energy & Development Corp. Merger
On January 24, 2002, Devon completed its acquisition of Mitchell Energy
& Development Corp. ("Mitchell") for cash and stock. For each Mitchell common
share outstanding, Mitchell stockholders received $31 cash and 0.585 of a share
of Devon common stock. The purchase price was approximately $3.2 billion. The
$1.6 billion cash portion of the purchase price was funded from the $3.0 billion
senior unsecured term loan credit facility (see Note 7).
Because the Mitchell merger was not closed until 2002, it had no effect
on Devon's 2001 financial condition or results of operations. See Note 19 for
unaudited pro forma information concerning the Mitchell merger and the October
2001 acquisition of Anderson Exploration Ltd. ("Anderson").
Anderson Exploration Ltd. Acquisition
On October 15, 2001, Devon accepted all of the Anderson common shares
tendered by Anderson stockholders in the tender offer, which represented
approximately 97% of the outstanding Anderson common shares. On October 17,
2001, Devon completed its acquisition of Anderson by a compulsory acquisition
under the Canada Business Corporations Act of the remaining 3% of Anderson
common shares. The cost to Devon of acquiring Anderson's outstanding common
shares and paying for the intrinsic value of Anderson's outstanding options and
appreciation rights was approximately $3.5 billion, which was funded from the
sale of $3.0 billion of debt securities and borrowings under the $3.0 billion
senior unsecured term loan credit facility (see Note 7).
85
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
Devon acquired Anderson to increase the scope of its Canadian
operations, for the exposure to north Canada's exploratory areas and to increase
exposure to the North American natural gas market.
The calculation of the purchase price and the preliminary allocation to
assets and liabilities as of October 15, 2001, are shown below. The purchase
price allocation is preliminary because certain items such as the tax basis of
the assets and liabilities acquired and the allocation of fair value to
undeveloped properties have not been completed.
(IN MILLIONS,
EXCEPT SHARE PRICE)
-------------------
Calculation and preliminary allocation of purchase price:
Number of Anderson common shares outstanding 132
Acquisition price per share $25.68
------
Cash paid to Anderson stockholders $3,386
Cash paid to settle Anderson employees' stock options
and appreciation rights 92
--
3,478
Plus estimated acquisition costs incurred 35
--
Total purchase price 3,513
Plus fair value of liabilities assumed by Devon:
Current liabilities 249
Long-term debt 1,017
Other long-term liabilities 7
Fair value of financial instruments 30
Deferred income taxes 1,427
-----
Total purchase price plus liabilities assumed $6,243
======
Fair value of assets acquired by Devon:
Current assets 214
Proved oil and gas properties 2,605
Unproved oil and gas properties 1,432
Other property and equipment 21
Goodwill (none deductible for income tax purposes) 1,971
-----
Total fair value of assets acquired $6,243
======
See Note 19 for unaudited pro forma information concerning the Anderson
acquisition and the Mitchell merger.
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.
86
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
Devon issued approximately 41 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 million ($37
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 22 million shares of its common stock to the
former stockholders of PennzEnergy. In addition, Devon assumed long-term debt
and other obligations totaling approximately $2.3 billion on August 17, 1999.
Additionally, $347 million of deferred taxes were 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 $347 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.
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.
87
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 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 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.
Additionally, $135 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 million of
deferred taxes recorded represent the deferred tax effect of the differences
between the fair values assigned by Santa Fe for financial reporting purposes to
the former Snyder assets and liabilities and their bases for income tax
purposes.
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 and 1999, the San Juan Basin Transaction added approximately
$12 million and $8 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 $17 million in 1999 which was added to the
repurchase liability. The actual repurchase price as of September 30, 2000, was
approximately $36 million.
4. SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest in 2001, 2000 and 1999 were approximately
$118 million, $155 million and $116 million, respectively. Cash payments for
federal, state and foreign income taxes in 2001, 2000 and 1999 were
approximately $192 million, $82 million and $16 million, respectively.
88
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
The 2001 Anderson acquisition and the 1999 PennzEnergy merger and
Snyder merger involved non-cash consideration as presented below:
2001 1999
---- ----
(IN MILLIONS)
Value of common stock issued $ -- 1,130
Value of preferred stock issued -- 150
Employee stock options assumed -- 18
Liabilities assumed 1,303 2,259
Deferred tax liability created 1,427 475
----- ---
Fair value of assets acquired with non-cash consideration $2,730 4,032
====== =====
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:
DECEMBER 31,
------------
2001 2000 1999
----- ----- -----
(IN MILLIONS)
Oil, gas and natural gas liquids revenue
accruals $ 323 438 218
Joint interest billings 108 123 67
Other 110 41 35
----- ----- -----
541 602 320
Allowance for doubtful accounts (4) (4) (4)
----- ----- -----
Net accounts receivable $ 537 598 316
===== ===== =====
89
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
6. PROPERTY AND EQUIPMENT
Property and equipment included the following:
DECEMBER 31,
------------
2001 2000 1999
-------- -------- --------
(IN MILLIONS)
Oil and gas properties:
Subject to amortization $ 13,266 9,170 8,126
Not subject to amortization:
Acquired in 2001 1,638 -- --
Acquired in 2000 74 74 --
Acquired in 1999 116 122 135
Acquired prior to 1999 111 119 167
Accumulated depreciation, depletion
and amortization (6,481) (4,752) (4,130)
-------- -------- --------
Net oil and gas properties 8,724 4,733 4,298
-------- -------- --------
Other property and equipment 393 224 165
Accumulated depreciation and amortization (89) (47) (39)
-------- -------- --------
Net other property and equipment 304 177 126
-------- -------- --------
Property and equipment, net of accumulated
depreciation, depletion and amortization $ 9,028 4,910 4,424
======== ======== ========
The costs not subject to amortization relate to unproved properties,
none of which are individually significant. Subject to industry conditions,
evaluation of these properties is expected to be completed within five years.
Depreciation, depletion and amortization of property and equipment
consisted of the following components:
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Depreciation, depletion and amortization
of oil and gas properties $838 663 390
Depreciation and amortization of other
property and equipment 30 23 14
Amortization of other assets 8 7 2
---- ---- ----
Total $876 693 406
==== ==== ====
90
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
7. LONG-TERM DEBT AND RELATED EXPENSES
A summary of Devon's long-term debt is as follows:
DECEMBER 31,
------------
2001 2000 1999
------- ------- -------
(IN MILLIONS)
Borrowings under credit facilities with banks $ 50 147 645
Commercial paper borrowings 75 -- --
$3 billion term loan credit facility 1,046 -- --
Debentures exchangeable into shares of
ChevronTexaco Corporation common stock:
4.90% due August 15, 2008 444 444 444
4.95% due August 15, 2008 316 316 316
Discount on exchangeable debentures (111) -- --
Zero coupon convertible senior debentures Exchangeable into shares of
Devon Energy Corp.
common stock, 3.875% due June 27, 2020 374 360 --
Other debentures:
10.25% due November 1, 2005 236 250 250
10.125% due November 15, 2009 177 200 200
7.875% due September 30, 2031 1,250 -- --
Net premium on debentures 6 33 37
Senior notes:
8.05% due June 15, 2004 125 125 125
7.25% due July 18, 2005 110 -- --
6.76% due July 19, 2005 -- -- 75
7.42% due October 1, 2005 23 -- --
7.57% due October 4, 2005 31 -- --
6.55% due August 2, 2006 126 -- --
8.75% due June 15, 2007 175 175 175
6.79% due March 2, 2009 -- -- 150
6.75% due March 15, 2011 400 -- --
6.875% due September 30, 2011 1,750 -- --
Net discount on notes (14) (1) (1)
------- ------- -------
6,589 2,049 2,416
Less amount classified as current -- -- --
------- ------- -------
Long-term debt $ 6,589 2,049 2,416
======= ======= =======
Maturities of long-term debt as of December 31, 2001, excluding the
$119 million of discounts net of premiums, are as follows (in millions):
2002 $ --
2003 --
2004 358
2005 775
2006 689
2007 and thereafter 4,886
-----
Total $6,708
======
91
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
Credit Facilities With Banks
On August 13, 2001, Devon renewed its 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 $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 12, 2002 (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 12, 2002 (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 $50 million
and $147 million outstanding under the Credit Facilities at December 31, 2001
and 2000, was 4.8% and 6.1%, respectively. The average interest rate on bank
debt outstanding under the previous facilities at December 31, 1999 was 6.8%.
The agreements governing the Credit Facilities contain certain
covenants and restrictions, including a maximum debt-to-capitalization ratio. At
December 31, 2001, Devon was in compliance with such covenants and restrictions.
92
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
Commercial Paper
On August 29, 2000, Devon entered into a commercial paper program.
Devon may borrow up to $725 million under the commercial paper program. Total
borrowings under the U.S. 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 is 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, 2001, Devon had $75 million of
borrowings under its commercial paper program at an average rate of 3.5%.
Because Devon had the intent and ability to refinance the balance due with
borrowings under its U.S. Facility, the $75 million outstanding under the
commercial paper program was classified as long-term debt on the December 31,
2001 consolidated balance sheet.
$3 Billion Term Loan Credit Facility
On October 12, 2001, Devon and its wholly-owned financing subsidiary
Devon Financing Corporation, U.L.C. ("Devon Financing") entered into a new $3
billion senior unsecured term loan credit facility. The facility has a term of
five years. Devon and Devon Financing may borrow funds under this facility
subject to conditions usual in commercial transactions of this nature, including
the absence of any default under this facility. Interest on borrowings under
this facility may be based, at the borrower's option, on LIBOR or on UBS Warburg
LLC's base rate (which is the higher of UBS Warburg's prime commercial lending
rate and the weighted average of rates on overnight Federal funds transactions
with members of the Federal Reserve System plus 0.50%).
The interest rates will include a margin determined by Devon's
long-term senior unsecured debt rating for borrowings made subsequent to June
17, 2002. Prior to that time, the margin for borrowings based on LIBOR will be
an additional 100 basis points. Based on LIBOR rates as of December 31, 2001,
Devon's average interest rate was 2.9%. In addition, Devon incurred an
availability fee on the daily average unused lending commitments through the
date of the Mitchell closing on January 24, 2002, equal to a percentage
determined by Devon's long-term senior unsecured debt rating.
Prior to December 31, 2001, Devon used proceeds of $1 billion from
borrowings on this facility to partially fund the Anderson acquisition. The
remaining $2 billion of availability was utilized upon the closing of the
Mitchell acquisition on January 24, 2002.
93
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
The terms of this facility require repayment of the debt during the
following years:
(In Millions)
2002 $ --
2003 --
2004 232
2005 1,200
2006 1,600
-------
Total $ 3,032
=======
The terms of this facility also provide that voluntary prepayments of
the debt may be applied, at Devon's option, to the earliest scheduled maturities
first. For example, if Devon were to prepay a portion of the $3 billion of debt
with proceeds from property sales or other cash sources, the amount of the
prepayment would reduce, if so elected by Devon, the amounts otherwise due first
in 2004, then 2005 and finally 2006.
This credit facility contains certain covenants and restrictions,
including a maximum allowed debt-to-capitalization ratio as defined in the
credit facility. At December 31, 2001, Devon was in compliance with such
covenants and restrictions.
Exchangeable Debentures
The exchangeable debentures consist of $444 million of 4.90% debentures
and $316 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 ChevronTexaco
Corporation common stock. In lieu of delivering ChevronTexaco Corporation common
stock, Devon may, at its option, pay to any holder an amount of cash equal to
the market value of the ChevronTexaco 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. Such amount will either
be in cash or in a combination of cash and ChevronTexaco Corporation common
stock.
As of December 31, 2001, Devon beneficially owned approximately seven
million shares of ChevronTexaco 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 ChevronTexaco Corporation common stock, an
exchange rate equivalent to $107-7/32 per share of ChevronTexaco 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. However, pursuant to the adoption
of SFAS No. 133 effective January 1, 2001, these debentures were
94
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
revalued as of August 17, 1999. Under SFAS No. 133, the total fair value of the
debentures was allocated between the interest-bearing debt and the option to
exchange ChevronTexaco Corporation common stock that is embedded in the
debentures. Accordingly, the debt portion of the debentures was reduced by $140
million as of August 17, 1999. This discount is being accreted using the
effective interest method, and has raised the effective interest rate on the
debentures to 7.76% in 2001 compared to 4.92% prior to 2001.
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 million, net of debt issuance costs of approximately $7
million. Devon used the proceeds from the sale of these debentures to pay down
other domestic long-term debt.
Debt Securities
On October 3, 2001, Devon, through Devon Financing, sold $1.75 billion
of 6.875% notes due September 30, 2011 and $1.25 billion of 7.875% debentures
due September 30, 2031. The debt securities are unsecured and unsubordinated
obligations of Devon Financing. Devon has fully and unconditionally guaranteed
on an unsecured and unsubordinated basis the obligations of Devon Financing
under the debt securities. The proceeds from the issuance of these debt
securities were used to fund a portion of the Anderson acquisition.
The $3 billion of debt securities were structured in a manner that
results in an expected weighted average after-tax borrowing rate of
approximately 1.76%.
Interest on the debt securities will be payable by Devon Financing
semiannually on March 30 and September 30 of each year, beginning on March 30,
2002. The indenture governing the debt securities limits both Devon Financing's
and Devon's ability to incur liens or enter into mergers or consolidations, or
transfer all or substantially all of their respective assets, unless the
successor company assumes Devon Financing's or Devon's obligations under the
indenture.
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 $236 million of 10.25% debentures and $177 million of
10.125% debentures, respectively. The premiums are being amortized using the
effective interest method.
95
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
During October 2001, Devon repurchased $14 million and $23 million of
its 10.25% debentures and 10.125% debentures, respectively. Devon recorded a
loss on the early retirement of debt of $5 million related to this repurchase.
Senior Notes
In connection with the Anderson acquisition, Devon assumed $702 million
of senior notes. The table below summarizes the debt assumed, the fair value of
the debt at October 15, 2001, and the effective interest rate of the debt
assumed after determining the fair values of the respective notes using October
15, 2001, market interest rates. The premiums and discounts are being amortized
or accreted using the effective interest method. All of the notes are general
unsecured obligations of Devon.
FAIR VALUE OF EFFECTIVE RATE OF
DEBT ASSUMED DEBT ASSUMED DEBT ASSUMED
------------------------------- ------------ ------------
(IN MILLIONS)
6.75% senior notes due 2011 $400 6.8%
6.55% senior notes due 2006 129 6.5%
7.25% senior notes due 2005 116 6.3%
7.57% senior notes due 2005 33 5.7%
7.42% senior notes due 2005 24 5.7%
Devon recorded a $2 million loss in 2001 related to the early
retirement of the above 7.57% and 7.42% 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 million of 8.05% notes due
2004. The notes were issued for 98.758% of face value and Devon received total
proceeds of $122 million after deducting related costs and expenses of $2
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.
96
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
Interest Expense
Following are the components of interest expense for the years 2001,
2000 and 1999:
YEAR ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
----- ----- -----
(IN MILLIONS)
Interest based on debt outstanding $ 200 157 108
Accretion (amortization) of debt discount
(premium), net 10 (4) (1)
Facility and agency fees 1 3 2
Amortization of capitalized loan costs 3 2 2
Capitalized interest (3) (3) (2)
Loss on debt retirement 7 -- --
Other 2 -- --
----- ----- -----
Total interest expense $ 220 155 109
===== ===== =====
Effects of Changes in Foreign Currency Exchange Rates
The 6.75% fixed-rate senior notes referred to in the first table of
this note are payable by Devon Canada, a wholly-owned subsidiary of Devon.
However, the notes are denominated in U.S. dollars. Until their retirement in
mid-January 2000, the 6.76% and 6.79% fixed-rate senior notes payable by Devon
Canada were also 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 increase or decrease the expected amount of
Canadian dollars eventually required to repay the notes. Such changes in the
Canadian dollar equivalent of the debt are 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 2001 and 2000
and increased in 1999. Therefore, $11 million and $3 million of increased
expense was recorded in 2001 and 2000, respectively, and $13 million of reduced
expense was recorded in 1999.
8. INCOME TAXES
At December 31, 2001, Devon had the following carryforwards available
to reduce future income taxes:
YEARS OF CARRYFORWARD
TYPES OF CARRYFORWARD EXPIRATION AMOUNTS
--------------------- ---------- -------
(IN MILLIONS)
Net operating loss - U.S. federal 2008 - 2021 $ 22
Net operating loss - various states 2002 - 2014 $ 60
Net operating loss - Canada 2002 - 2008 $ 3
Net operating loss - International Indefinite $ 91
Minimum tax credits Indefinite $ 118
All of the carryforward amounts shown above have been utilized for
financial purposes to reduce the deferred tax liability.
97
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
The earnings (loss) before income taxes and the components of income tax
expense (benefit) for the years 2001, 2000 and 1999 were as follows:
YEAR ENDED DECEMBER 31,
2001 2000 1999
----- ----- -----
(IN MILLIONS)
Earnings (loss) before income taxes:
U.S $ 458 872 (313)
Canada (357) 156 58
International (17) 114 56
----- ----- -----
Total $ 84 1,142 (199)
===== ===== =====
Current income tax expense:
U.S. federal $ 23 107 12
Various states 6 6 3
Canada 8 2 3
Other 34 16 5
----- ----- -----
Total current tax expense 71 131 23
----- ----- -----
Deferred income tax expense (benefit):
U.S. federal 124 152 (119)
Various states (32) 33 --
Canada (145) 67 27
Other 12 29 20
----- ----- -----
Total deferred tax expense (benefit) (41) 281 (72)
----- ----- -----
Total income tax expense (benefit) $ 30 412 (49)
===== ===== =====
Total income tax expense (benefit) 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:
YEAR ENDED DECEMBER 31,
2001 2000 1999
---- ---- ----
U.S. statutory tax (benefit) rate 35% 35% (35)%
Benefit from disposition of certain
Foreign assets -- (4) --
Financial expenses not deductible for 14 1 3
Income tax purposes
Nonconventional fuel source credits (23) (1) (3)
State income taxes 5 1 1
Taxation on foreign operations 12 2 7
Other (7) 2 2
---- ---- ----
Effective income tax (benefit) rate 36% 36% (25)%
==== ==== ====
98
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities at December 31, 2001, 2000
and 1999 are presented below:
DECEMBER 31,
2001 2000 1999
------- ------- -------
(IN MILLIONS)
Deferred tax assets:
Net operating loss carryforwards $ 39 123 207
Minimum tax credit carryforwards 118 85 88
Production payments -- -- 21
Long-term debt 6 17 18
Fair value of financial instruments 7 -- --
Other 37 95 51
------- ------- -------
Total deferred tax assets 207 320 385
------- ------- -------
Deferred tax liabilities:
Property and equipment, principally due
to nontaxable business combinations,
differences in depreciation, and
the expensing of intangible drilling
costs for tax purposes (2,182) (687) (500)
ChevronTexaco Corporation common stock (213) (167) (172)
Other (11) (84) (32)
------- ------- -------
Total deferred tax liabilities (2,406) (938) (704)
------- ------- -------
Net deferred tax liability $(2,199) (618) (319)
======= ======= =======
As shown in the above table, Devon has recognized $207 million of
deferred tax assets as of December 31, 2001. Such amount consists primarily of
$157 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 2002 and 2008, International
carryforwards which have no expiration 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 2002 and 2010. 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.
99
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
9. TRUST CONVERTIBLE PREFERRED SECURITIES
On July 10, 1996, Devon, through its affiliate Devon Financing Trust,
completed the issuance of $149 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 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 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.
100
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
In late September and early October 1999, Devon received $403 million
from the sale of approximately 10 million shares of its common stock in a public
offering. The price to the public for these shares was $40.50 per share. Net of
underwriters' discount and commissions, Devon received $38.98 per share. Devon
paid approximately $1 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 22 million shares of
Devon common stock issued on August 17, 1999, in connection with the PennzEnergy
merger. Also, there were 16 million Exchangeable Shares issued on December 10,
1998, in connection with the Northstar Energy Corporation combination. As of
year-end 2001, 14 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 a certain number of 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
shareholder rights plan described later in this note. Effective January 22,
2002, the Board voted to increase the designated shares from one million to two
million. At December 31, 2001, 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, 2001, there were 63,000 and 320,860 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 10 million.
101
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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 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, 2001, there were 5,274,235 options outstanding
under the 1997 Plan. There were 3,745,334 options available for future grants as
of December 31, 2001.
In addition to the stock options outstanding under the 1988 Plan, 1993
Plan and 1997 Plan, there were approximately 1,053,807, 1,410,158 and 62,270
stock options outstanding at the end of 2001 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, 1999, 2000 and 2001, and changes during each of the years then ended, is
presented below.
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------- -------------------
WEIGHTED
AVERAGE
NUMBER EXERCISE NUMBER EXERCISE
OUTSTANDING PRICE EXERCISABLE PRICE
----------- ----- ----------- -----
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
========== ==========
Options granted 2,600,650 $ 62.808
Options exercised (1,504,691) $ 31.133
Options forfeited (267,583) $ 62.774
----------
Balance at December 31, 2001 8,184,330 $ 41.089 5,515,958 $ 41.934
========== ========== ==========
102
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
The weighted average fair values of options granted during 2001, 2000
and 1999 were $13.17, $28.73 and $12.80, 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 following assumptions for 2001,
2000 and 1999, respectively: risk-free interest rates of 3.8%, 5.5% and 6%;
dividend yields of 0.6%, 0.4% and 0.5%; expected lives of five, five and five
years; and volatility of the price of the underlying common stock of 42.2%,
40.0% and 35.2%.
The following table summarizes information about Devon's stock options
which were outstanding, and those which were exercisable, as of December 31,
2001:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
RANGE OF AVERAGE AVERAGE AVERAGE
EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE
PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE
------ ----------- ---- ----- ----------- -----
$ 8.375-$26.501 442,204 2.38 Years $23.014 442,204 $23.014
$28.830-$33.381 1,314,346 5.29 Years $30.726 1,239,114 $30.713
$34.375-$39.773 3,445,957 7.04 Years $35.308 1,569,779 $35.818
$40.190-$49.950 454,980 4.01 Years $45.941 444,996 $45.916
$50.142-$59.813 2,028,308 6.66 Years $53.177 1,329,064 $53.865
$60.150-$89.660 498,535 5.36 Years $70.788 490,801 $70.954
--------- ---------
8,184,330 6.15 Years $41.089 5,515,958 $41.934
========= =========
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 2001, 2000 and 1999
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.
YEAR ENDED DECEMBER 31,
------------------------------------
2001 2000 1999
-------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Net earnings (loss) available to common shareholders:
As reported $ 93 720 (158)
Pro forma $ 79 702 (173)
Net earnings (loss) per share available
to common shareholders:
As reported:
Basic $ 0.73 5.66 (1.68)
Diluted $ 0.72 5.50 (1.68)
Pro forma:
Basic $ 0.62 5.51 (1.85)
Diluted $ 0.61 5.36 (1.85)
103
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
Shareholder Rights Plan
Under Devon's shareholder 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.
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, 2001, 2000 and 1999.
2001 2000 1999
---- ---- ----
CARRYING FAIR CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE AMOUNT VALUE
------ ----- ------ ----- ------ -----
(IN MILLIONS)
Investments $ 644 644 606 606 634 634
Oil and gas price hedge agreements $ 225 225 -- (58) -- (10)
Interest rate swap agreements $ (9) (9) -- -- -- --
Electricity hedge agreements $ (12) (12) -- -- -- --
Foreign exchange hedge agreements $ (4) (4) -- (1) -- (3)
Embedded option in exchangeable $ (34) (34) -- -- -- --
debentures
Long-term debt (including current $(6,589) (6,699) (2,049) (2,050) (2,416) (2,400)
portion)
104
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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, 2001, 2000 and 1999.
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.
Interest Rate Swap Agreements - The fair values of the interest rate
swaps are based on quotes obtained from the counterparty to the swap agreement.
Electricity Hedge Agreements - The fair values of the electricity
hedges are based on an internal discounted cash flow calculation.
Foreign Exchange Hedge Agreements - The fair values of the foreign
exchange agreements are based on either (a) an internal discounted cash flow
calculation or (b) quotes obtained from brokers.
Embedded Option in Exchangeable Debentures - The fair values of the
embedded options 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.
Devon's total hedged positions as of January 31, 2002 are set forth in
the following tables.
PRICE SWAPS Through various price swaps, Devon has fixed the price it
will receive on a portion of its oil and natural gas production in 2002, 2003
and 2004. The following tables include information on this production. 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.
105
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
OIL PRODUCTION
YEAR BBLS/DAY PRICE/BBL
2002 26,350 $ 23.27
GAS PRODUCTION
YEAR MCF/DAY PRICE/MCF
2002 242,128 $ 2.99
2003 99,905 $ 3.35
2004 4,164 $ 2.36
COSTLESS PRICE COLLARS Devon has also entered into costless price
collars that set a floor and ceiling price for a portion of its 2002 and 2003
oil and natural gas production. The following tables include information on
these collars. The floor and ceiling prices related to domestic oil production
are based on NYMEX. The NYMEX price is the monthly average of settled prices on
each trading day for West Texas Intermediate Crude oil delivered at Cushing,
Oklahoma. The gas prices shown in the following table have been adjusted to a
NYMEX-based price, using Devon's estimates of differentials between NYMEX and
the specific regional indices upon which the collars are based. The floor and
ceiling prices related to the domestic collars are based on various regional
first-of-the-month price indices as published monthly by Inside FERC. The floor
and ceiling prices related to the Canadian collars 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.
The floor and ceiling prices in the following table are weighted
averages of all the various collars.
OIL PRODUCTION
FLOOR CEILING
PRICE PRICE
PER PER
YEAR BBLS/DAY BBL BBL
2002 20,000 $ 23.00 $ 28.19
106
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
GAS PRODUCTION
FLOOR CEILING
PRICE PRICE
PER PER
YEAR MCF/DAY MCF MCF
2002 442,574 $ 3.34 $ 6.37
2003 345,000 $ 3.20 $ 4.19
INTEREST RATE SWAPS Devon assumed certain interest rate swaps as a
result of the Anderson acquisition. Under these interest rate swaps, Devon has
swapped a floating rate for a fixed rate. Under such swaps, Devon will record a
fixed rate of 6.2% on $132 million of debt in 2002, 6.3% on $97 million of debt
in 2003, 6.4% on $79 million of debt in 2004 through 2006 and 6.3% on $24
million of debt in 2007.
FOREIGN CURRENCY EXCHANGE RATE SWAPS Devon assumed certain foreign
currency exchange rate swaps in the Anderson acquisition. These swaps require
Devon to sell $30 million and $12 million at average Canadian-to-U.S. exchange
rates of $0.680 and $0.676, and buy the same amount of dollars at the floating
exchange rate, in 2002 and 2003, respectively.
12. RETIREMENT PLANS
Devon has non-contributory defined benefit retirement plans (the "Basic
Plans") which include U.S. and Canadian 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.
107
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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, 2001, 2000
and 1999.
OTHER
POSTRETIREMENT
PENSION BENEFITS BENEFITS
---------------- --------
2001 2000 1999 2001 2000 1999
----- ----- ----- ----- ----- -----
(IN MILLIONS)
Change in benefit obligation:
Benefit obligation at beginning of year $ 165 156 64 $ 32 38 8
Service cost 5 7 5 -- 1 1
Interest cost 13 11 6 2 2 1
Participant contributions -- -- -- 1 -- --
Amendments 5 4 -- (1) (2) --
Mergers and acquisitions 16 -- 88 -- -- 29
Special termination benefits 3 -- -- -- -- --
Settlement payments (4) -- -- -- -- --
Curtailment gain (1) (3) -- -- -- --
Actuarial (gain) loss 17 (3) (3) 4 (3) 1
Benefits paid (9) (7) (4) (5) (4) (2)
----- ----- ----- ----- ----- -----
Benefit obligation at end of year 210 165 156 33 32 38
----- ----- ----- ----- ----- -----
Change in plan assets:
Fair value of plan assets at
beginning of year 155 158 42 -- -- --
Actual return on plan assets (9) 3 15 -- -- --
Mergers and acquisitions 17 -- 104 -- -- --
Employer contributions 6 1 1 4 4 2
Participant contributions -- -- -- 1 -- --
Settlement payments (4) -- -- -- -- --
Administrative expenses -- -- -- -- -- --
Benefits paid (9) (7) (4) (5) (4) (2)
----- ----- ----- ----- ----- -----
Fair value of plan assets at end of year 156 155 158 -- -- --
----- ----- ----- ----- ----- -----
Funded status (54) (10) 2 (33) (32) (38)
Unrecognized net actuarial (gain) loss 35 10 (3) 2 (2) 1
Unrecognized prior service cost 6 1 2 (1) (1) --
Unrecognized net transition (asset) obligation -- (6) -- -- 1 2
----- ----- ----- ----- ----- -----
Net amount recognized $ (13) (5) 1 $ (32) (34) (35)
===== ===== ===== ===== ===== =====
The net amounts recognized in the
consolidated balance sheets consist of:
(Accrued) prepaid benefit cost $ (13) (5) 1 $ (32) $ (34) $ (35)
Additional minimum liability (33) (1) (3) -- -- --
Intangible asset 5 1 1 -- -- --
Accumulated other comprehensive loss 28 -- 2 -- -- --
----- ----- ----- ----- ----- -----
Net amount recognized $ (13) (5) 1 $ (32) (34) (35)
===== ===== ===== ===== ===== =====
Assumptions:
Discount rate 7.10% 7.65% 7.34% 7.15% 7.65% 7.32%
Expected return on plan assets 8.27% 8.50% 8.37% N/A N/A N/A
Rate of compensation increase 4.88% 5.00% 4.88% 5.00% 5.00% 4.75%
The benefit obligation for the defined benefit pension plans with
benefit obligations in excess of assets was $201 million as of December 31,
2001. The plan assets for these plans at December 31, 2001 totaled $138 million.
Net periodic benefit cost included the following components:
108
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
------------------------------------- --------------------
2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
(IN MILLIONS)
Service cost $ 5 7 5 $ -- 1 1
Interest cost 13 11 6 2 2 1
Expected return on plan assets (13) (13) (7) -- -- --
Amortization of prior service cost 1 -- -- -- -- --
Recognized net actuarial (gain) loss 1 -- -- -- -- --
---- ---- ---- ---- ---- ----
Net periodic benefit cost $ 7 5 4 $ 2 3 2
==== ==== ==== ==== ==== ====
For measurement purposes, a 9% annual rate of increase in the per
capita cost of covered health care benefits was assumed in 2001. 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:
ONE-PERCENTAGE ONE-PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(IN MILLIONS)
Effect on total of service and interest cost components for 2001 $ -- $ --
Effect on year-end 2001 postretirement benefit obligation $ 1 $ (1)
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 $7
million, $13 million and $3 million at the end of 2001, 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 million, $5 million and $4 million for the years ended December 31,
2001, 2000 and 1999, 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.
109
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
During the years 2001, 2000 and 1999, Devon's combined contributions to
the Canadian defined contribution plan and the Canadian savings plan were $3
million, $2 million and $2 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 although actual amounts could differ from
management's estimate.
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, 2001, Devon's consolidated balance sheet
included $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.
Royalty Matters
Numerous gas producers and related parties, including Devon, have been
named in various lawsuits filed by private litigants alleging violation of the
federal False Claims Act. The suits allege
110
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
that the producers and related parties used below-market prices, improper
deductions, improper measurement techniques and transactions with affiliates
which resulted in underpayment of royalties in connection with natural gas and
natural gas liquids produced and sold from federal and Indian owned or
controlled lands. The various suits have been consolidated by the United States
Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the
matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United
States District Court for the District of Wyoming. Devon believes that it has
acted reasonably, has legitimate and strong defenses to all allegations in the
suits, and has paid royalties in good faith. Devon does not currently believe
that it is subject to material exposure in association with these lawsuits and
no liability has been recorded in connection therewith.
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, 2001:
YEAR ENDING DECEMBER 31, (IN MILLIONS)
------------------------ -------------
2002 $ 21
2003 20
2004 16
2005 14
2006 11
Thereafter 14
--------
Total minimum lease payments required $ 96
========
Total rental expense for all operating leases is as follows for the
years ended December 31:
(IN MILLIONS)
2001 $ 17
2000 $ 19
1999 $ 24
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 from Devon to the extent that the
Trust needs such payments to distribute $0.38 per Depository Unit per quarter.
The source of such support payments is limited
111
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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 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 2001, the Trust had received support payments
totaling $4 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.
At December 31, 2001, 2000 and 1999, accounts payable as shown on the
accompanying consolidated balance sheets included $3 million, $4 million and $3
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 plus the lower of cost or fair
value of unproved 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 related 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 2001 and 1999, Devon reduced the carrying value of its oil and
gas properties by $916 and $476 million, respectively, due to the full cost
ceiling limitations. The after-tax effect of these reductions in 2001 and 1999
were $556 million and $310 million, respectively. The following table summarizes
these reductions by country.
YEAR ENDED DECEMBER 31,
-----------------------
2001 1999
---- ----
Net of Net of
Gross Taxes Gross Taxes
----- ----- ----- -----
(IN MILLIONS)
United States $ 449 281 464 302
Canada 434 252 -- --
Egypt 33 23 -- --
China -- -- 12 8
------ ------ ------ ------
Total $ 916 556 476 310
====== ====== ====== ======
112
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
The 2001 domestic and Canadian reductions were primarily the result of
lower prices. Under the purchase method of accounting for business combinations,
acquired oil and gas properties are recorded at fair value as of the date of
purchase. Devon estimates such fair value using its estimates of future oil and
gas prices. In contrast, the ceiling calculation dictates that prices in effect
as of the last day of the applicable quarter are held constant indefinitely.
Accordingly, the resulting value is not indicative of the true fair value of the
reserves. The oil and gas properties added from the Anderson acquisition and
other smaller acquisitions in 2001 were recorded at fair values that were based
on expected future oil and gas prices higher than the year-end 2001 prices used
to calculate the ceiling. The reduction in Egypt was the result of high finding
and development costs and negative revisions to proved reserves.
The 1999 domestic reduction was primarily the result of lower prices.
The oil and gas properties added from the Snyder acquisition were recorded at
fair values that were based on expected future oil and gas prices higher than
the quarterly prices used to calculate the ceiling. The reduction in China was
the result of high finding and development costs.
Additionally, during 2001, Devon elected to discontinue operations in
Thailand, Malaysia, Qatar and on certain properties in Brazil. After meeting the
drilling and capital commitments on these properties, Devon determined that
these properties did not meet Devon's internal criteria to justify further
investment. Accordingly, Devon recorded an $87 million charge associated with
the impairment of these properties. The after-tax effect of this reduction was
$69 million.
15. OIL AND GAS OPERATIONS
Costs Incurred
The following tables reflect the costs incurred in oil and gas property
acquisition, exploration, and development activities:
TOTAL
-----
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
------ ------ ------
(IN MILLIONS)
Property acquisition costs:
Proved, excluding deferred income taxes $2,975 291 3,002
Deferred income taxes 84 -- 132
------ ------ ------
Total proved, including deferred income taxes $3,059 291 3,134
====== ====== ======
Unproved, excluding deferred income taxes:
Business combinations 1,433 -- 84
Other acquisitions 183 55 40
Deferred income taxes 27 -- --
------ ------ ------
Total unproved, including deferred income taxes $1,643 55 124
====== ====== ======
Exploration costs $ 356 213 158
Development costs $ 978 636 336
113
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
DOMESTIC
------------------------------
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
------ ------ ------
(IN MILLIONS)
Property acquisition costs:
Proved, excluding deferred income taxes $ 292 177 2,670
Deferred income taxes 79 -- 132
------ ------ ------
Total proved, including deferred income taxes $ 371 177 2,802
====== ====== ======
Unproved, excluding deferred income taxes:
Business combinations -- -- 82
Other acquisitions 158 35 28
Deferred income taxes 27 -- --
------ ------ ------
Total unproved, including deferred income taxes $ 185 35 110
====== ====== ======
Exploration costs $ 166 117 88
Development costs $ 726 466 228
CANADA
------------------------------
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
------ ------ ------
(IN MILLIONS)
Property acquisition costs:
Proved, excluding deferred income taxes $2,621 70 29
Deferred income taxes 5 -- --
------ ------ ------
Total proved, including deferred income taxes $2,626 70 29
====== ====== ======
Unproved, excluding deferred income taxes:
Business combinations 1,433 -- --
Other acquisitions 24 17 9
Deferred income taxes -- -- --
------ ------ ------
Total unproved, including deferred income taxes $1,457 17 9
====== ====== ======
Exploration costs $ 126 55 37
Development costs $ 168 57 30
INTERNATIONAL
-------------------------------
YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
------ ------ ------
(IN MILLIONS)
Property acquisition costs:
Proved, excluding deferred income taxes $ 62 44 303
Deferred income taxes -- -- --
------ ------ ------
Total proved, including deferred income taxes $ 62 44 303
====== ====== ======
Unproved, excluding deferred income taxes:
Business combinations -- -- 2
Other acquisitions 1 3 3
Deferred income taxes -- -- --
------ ------ ------
Total unproved, including deferred income taxes $ 1 3 5
====== ====== ======
Exploration costs $ 64 41 33
Development costs $ 84 113 78
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
114
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
tables, were $77 million, $62 million and $29 million in the years 2001, 2000
and 1999, respectively.
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.
TOTAL
-------------------------------------------
YEAR ENDED DECEMBER 31,
-------------------------------------------
2001 2000 1999
------- ------- -------
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales $ 2,980 2,718 1,257
Production and operating expenses (731) (597) (378)
Depreciation, depletion and amortization (838) (663) (390)
Amortization of goodwill (34) (41) (16)
Reduction of carrying value of oil and gas properties (1,003) -- (476)
Income tax expense (159) (572) (25)
------- ------- -------
Results of operations for oil and gas producing activities $ 215 845 (28)
======= ======= =======
Depreciation, depletion and amortization per equivalent
barrel of production $ 6.20 5.48 4.46
======= ======= =======
115
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
DOMESTIC
--------
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999
---- ---- ----
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales $ 2,260 2,168 892
Production and operating expenses (512) (463) (254)
Depreciation, depletion and amortization (615) (541) (294)
Amortization of goodwill (34) (41) (16)
Reduction of carrying value of oil and gas properties (449) -- (464)
Income tax (expense) benefit (267) (446) 38
------- ------- -------
Results of operations for oil and gas producing activities $ 383 677 (98)
======= ======= =======
Depreciation, depletion and amortization per equivalent
barrel of production $ 6.47 5.73 4.98
======= ======= =======
CANADA
------
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999
---- ---- ----
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales $ 481 303 204
Production and operating expenses (137) (64) (63)
Depreciation, depletion and amortization (164) (64) (64)
Reduction of carrying value of oil and gas properties (434) -- --
Income tax benefit (expense) 99 (80) (38)
------- ------- -------
Results of operations for oil and gas producing activities $ (155) 95 39
======= ======= =======
Depreciation, depletion and amortization per equivalent
barrel of production $ 5.74 4.05 3.56
======= ======= =======
INTERNATIONAL
-------------
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999
---- ---- ----
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales $ 239 247 161
Production and operating expenses (82) (70) (61)
Depreciation, depletion and amortization (59) (58) (32)
Amortization of goodwill -- -- --
Reduction of carrying value of oil and gas properties (120) -- (12)
Income tax benefit (expense) 9 (46) (25)
------- ------- -------
Results of operations for oil and gas producing activities $ (13) 73 31
======= ======= =======
Depreciation, depletion and amortization per equivalent
barrel of production $ 5.08 5.38 3.06
======= ======= =======
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."
116
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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, 2001. Approximately 67%, 80% and 98%, of the respective
year-end 2001, 2000 and 1999 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. Approximately 43% of the year-end
2001 Canadian proved reserves were calculated by the independent petroleum
consultants of Paddock Lindstrom & Associates and Gilbert Laustsen Jung
Associates, Ltd. The remaining percentage of Canadian 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 international proved reserves other than
Canada as of December 31, 2001, 2000 and 1999 were calculated by the independent
petroleum consultants of Ryder Scott Company Petroleum Consultants.
TOTAL
-----
NATURAL
GAS
OIL GAS LIQUIDS
(MMBBLS) (BCF) (MMBBLS)
-------- ----- --------
Proved reserves as of December 31, 1998 235 1,477 33
Revisions of estimates 12 7 3
Extensions and discoveries 13 406 4
Purchase of reserves 273 1,418 33
Production (32) (304) (5)
Sale of reserves (5) (54) --
------ ------ ------
Proved reserves as of December 31, 1999 496 2,950 68
Revisions of estimates (4) 99 3
Extensions and discoveries 34 601 6
Purchase of reserves 24 301 --
Production (43) (426) (7)
Sale of reserves (48) (67) (8)
------ ------ ------
Proved reserves as of December 31, 2000 459 3,458 62
Revisions of estimates (14) (315) 6
Extensions and discoveries 31 579 9
Purchase of reserves 166 2,267 52
Production (44) (498) (8)
Sale of reserves (12) (14) --
------ ------ ------
Proved reserves as of December 31, 2001 586 5,477 121
====== ====== ======
Proved developed reserves as of:
December 31, 1998 180 1,282 19
December 31, 1999 301 2,501 52
December 31, 2000 261 2,631 46
December 31, 2001 324 3,948 88
117
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
DOMESTIC
--------
NATURAL
GAS
OIL GAS LIQUIDS
(MMBBLS) (BCF) (MMBBLS)
-------- ----- --------
Proved reserves as of December 31, 1998 101 838 16
Revisions of estimates 24 36 3
Extensions and discoveries 2 230 3
Purchase of reserves 143 1,400 33
Production (18) (221) (4)
Sale of reserves (3) (8) --
------ ------ ------
Proved reserves as of December 31, 1999 249 2,275 51
Revisions of estimates (3) 101 4
Extensions and discoveries 21 504 5
Purchase of reserves 21 53 --
Production (29) (355) (6)
Sale of reserves (33) (57) (8)
------ ------ ------
Proved reserves as of December 31, 2000 226 2,521 46
Revisions of estimates (25) (262) 7
Extensions and discoveries 12 360 5
Purchase of reserves 15 170 --
Production (26) (376) (6)
Sale of reserves (11) (14) --
------ ------ ------
Proved reserves as of December 31, 2001 191 2,399 52
====== ====== ======
Proved developed reserves as of:
December 31, 1998 93 664 15
December 31, 1999 214 1,960 48
December 31, 2000 192 2,087 42
December 31, 2001 167 1,988 48
118
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
CANADA
------
NATURAL
GAS
OIL GAS LIQUIDS
(MMBBLS) (BCF) (MMBBLS)
-------- ----- --------
Proved reserves as of December 31, 1998 39 602 5
Revisions of estimates (3) (41) --
Extensions and discoveries -- 53 --
Purchase of reserves 3 12 --
Production (5) (74) (1)
Sale of reserves (2) (46) --
------ ------ ------
Proved reserves as of December 31, 1999 32 506 4
Revisions of estimates 3 (6) --
Extensions and discoveries 3 65 1
Purchase of reserves 3 27 --
Production (5) (62) (1)
Sale of reserves -- (6) --
------ ------ ------
Proved reserves as of December 31, 2000 36 524 4
Revisions of estimates -- (22) --
Extensions and discoveries 5 139 2
Purchase of reserves 133 2,097 52
Production (8) (113) (2)
Sale of reserves -- -- --
------ ------ ------
Proved reserves as of December 31, 2001 166 2,625 56
====== ====== ======
Proved developed reserves as of:
December 31, 1998 33 583 4
December 31, 1999 29 501 4
December 31, 2000 30 508 4
December 31, 2001 124 1,923 40
INTERNATIONAL
-------------
NATURAL
GAS
OIL GAS LIQUIDS
(MMBBLS) (BCF) (MMBBLS)
-------- ----- --------
Proved reserves as of December 31, 1998 95 37 12
Revisions of estimates (9) 12 --
Extensions and discoveries 11 123 1
Purchase of reserves 127 6 --
Production (9) (9) --
Sale of reserves -- -- --
------ ------ ------
Proved reserves as of December 31, 1999 215 169 13
Revisions of estimates (4) 4 (1)
Extensions and discoveries 10 32 --
Purchase of reserves -- 221 --
Production (9) (9) --
Sale of reserves (15) (4) --
------ ------ ------
Proved reserves as of December 31, 2000 197 413 12
Revisions of estimates 11 (31) (1)
Extensions and discoveries 14 80 2
Purchase of reserves 18 -- --
Production (10) (9) --
Sale of reserves (1) -- --
------ ------ ------
Proved reserves as of December 31, 2001 229 453 13
====== ====== ======
Proved developed reserves as of:
December 31, 1998 54 35 --
December 31, 1999 58 40 --
December 31, 2000 39 36 --
December 31, 2001 33 37 --
119
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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:
TOTAL
-----
DECEMBER 31,
------------
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Future cash inflows $ 23,790 40,594 18,495
Future costs:
Development (2,228) (1,635) (1,507)
Production (8,424) (8,198) (6,271)
Future income tax expense (3,403) (9,088) (1,928)
-------- -------- --------
Future net cash flows 9,735 21,673 8,789
10% discount to reflect timing of
cash flows (4,421) (9,201) (4,021)
-------- -------- --------
Standardized measure of
discounted future net cash flows $ 5,314 12,472 4,768
======== ======== ========
DOMESTIC
--------
DECEMBER 31,
------------
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Future cash inflows $ 9,861 29,144 11,363
Future costs:
Development (793) (916) (751)
Production (3,774) (5,661) (3,894)
Future income tax expense (759) (6,346) (1,072)
-------- -------- --------
Future net cash flows 4,535 16,221 5,646
10% discount to reflect timing of
cash flows (1,734) (6,592) (2,335)
-------- -------- --------
Standardized measure of
discounted future net cash flows $ 2,801 9,629 3,311
======== ======== ========
CANADA
------
DECEMBER 31,
------------
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Future cash inflows $ 9,011 5,686 1,666
Future costs:
Development (922) (85) (66)
Production (3,292) (616) (515)
Future income tax expense (2,006) (1,967) (204)
-------- -------- --------
Future net cash flows 2,791 3,018 881
10% discount to reflect timing of
cash flows (1,195) (1,241) (321)
-------- -------- --------
Standardized measure of
discounted future net cash flows $ 1,596 1,777 560
======== ======== ========
120
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
INTERNATIONAL
-------------
DECEMBER 31,
------------
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Future cash inflows $ 4,918 5,764 5,466
Future costs:
Development (513) (634) (690)
Production (1,358) (1,921) (1,862)
Future income tax expense (638) (775) (652)
-------- -------- --------
Future net cash flows 2,409 2,434 2,262
10% discount to reflect timing of
cash flows (1,492) (1,368) (1,365)
-------- -------- --------
Standardized measure of
discounted future net cash flows $ 917 1,066 897
======== ======== ========
Future cash inflows are computed by applying year-end prices (averaging
$16.54 per barrel of oil, adjusted for transportation and other charges, $2.28
per Mcf of gas and $13.21 per barrel of natural gas liquids at December 31,
2001) 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.
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. Of the $2.2 billion of future
development costs, $532 million, $275 million and $183 million are estimated to
be spent in 2002, 2003 and 2004, respectively.
Future development costs include not only development costs, but also
future dismantlement, abandonment and rehabilitation costs. Included as part of
the $2.2 billion of future development costs are $276 million of future
dismantlement, abandonment and rehabilitation costs.
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.
121
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
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:
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000 1999
---- ---- ----
(IN MILLIONS)
Beginning balance $ 12,472 4,768 1,414
Sales of oil, gas and natural gas liquids, net of production costs (2,249) (2,121) (880)
Net changes in prices and production costs (12,130) 9,753 1,737
Extensions, discoveries, and improved recovery, net of future
development costs 693 2,742 316
Purchase of reserves, net of future development costs 2,483 618 2,882
Development costs incurred during the period which reduced
future development costs 364 183 234
Revisions of quantity estimates (360) 420 (63)
Sales of reserves in place (86) (818) (78)
Accretion of discount 1,774 581 147
Net change in income taxes 3,406 (4,221) (929)
Other, primarily changes in timing (1,053) 567 (12)
-------- -------- --------
Ending balance $ 5,314 12,472 4,768
======== ======== ========
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
2001, 2000 and 1999. The revenues reported are all from external customers.
122
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
U.S. CANADA INTERNATIONAL TOTAL
---- ------ ------------- -----
(IN MILLIONS)
AS OF DECEMBER 31, 2001:
Current assets $ 661 192 228 1,081
Property and equipment, net of
accumulated depreciation,
depletion and amortization 4,051 4,248 729 9,028
Goodwill, net of amortization 209 1,928 69 2,206
Other assets 826 33 10 869
-------- -------- -------- --------
Total assets $ 5,747 6,401 1,036 13,184
======== ======== ======== ========
Current liabilities 407 367 145 919
Long-term debt 1,987 4,602 -- 6,589
Deferred tax liabilities 775 1,316 51 2,142
Other liabilities 224 20 31 275
Stockholders' equity 2,354 96 809 3,259
-------- -------- -------- --------
Total liabilities and
stockholders' equity $ 5,747 6,401 1,036 13,184
======== ======== ======== ========
YEAR ENDED DECEMBER 31, 2001:
REVENUES
Oil sales $ 586 146 226 958
Gas sales 1,571 307 12 1,890
Natural gas liquids sales 103 28 1 132
Other 78 8 9 95
-------- -------- -------- --------
Total revenues 2,338 489 248 3,075
-------- -------- -------- --------
COSTS AND EXPENSES
Lease operating expenses 340 110 81 531
Transportation costs 59 24 -- 83
Production taxes 113 3 1 117
Depreciation, depletion and
amortization of property
and equipment 647 166 63 876
Amortization of goodwill 34 -- -- 34
General and administrative expenses 98 15 (2) 111
Expenses related to mergers -- 1 -- 1
Interest expense 139 81 -- 220
Effects of changes in foreign
currency exchange rates -- 11 2 13
Change in fair value of
financial instruments 1 1 -- 2
Reduction in carrying value of
oil and gas properties 449 434 120 1,003
-------- -------- -------- --------
Total costs and expenses 1,880 846 265 2,991
-------- -------- -------- --------
Earnings (loss) before income tax
expense (benefit) and
cumulative effect of change in
accounting principle 458 (357) (17) 84
INCOME TAX EXPENSE (BENEFIT)
Current 29 8 34 71
Deferred 92 (145) 12 (41)
-------- -------- -------- --------
Total income tax
expense (benefit) 121 (137) 46 30
-------- -------- -------- --------
Earnings (loss) before cumulative
effect of change in
accounting principle 337 (220) (63) 54
Cumulative effect of change in
accounting principle 49 -- -- 49
-------- -------- -------- --------
Net earnings (loss) $ 386 (220) (63) 103
======== ======== ======== ========
Capital expenditures $ 1,356 3,774 196 5,326
======== ======== ======== ========
123
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
U.S. CANADA INTERNATIONAL TOTAL
---- ------ ------------- -----
(IN MILLIONS)
AS OF DECEMBER 31, 2000:
Current assets $ 645 79 210 934
Property and equipment, net of
accumulated depreciation,
depletion and amortization 3,640 586 684 4,910
Other assets 964 -- 52 1,016
-------- -------- -------- --------
Total assets $ 5,249 665 946 6,860
======== ======== ======== ========
Current liabilities 449 74 106 629
Long-term debt 1,902 147 -- 2,049
Deferred tax liabilities 537 69 21 627
Other liabilities 259 1 18 278
Stockholders' equity 2,102 374 801 3,277
-------- -------- -------- --------
Total liabilities and
stockholders' equity $ 5,249 665 946 6,860
======== ======== ======== ========
YEAR ENDED DECEMBER 31, 2000:
REVENUES
Oil sales $ 727 116 236 1,079
Gas sales 1,305 169 11 1,485
Natural gas liquids sales 136 18 -- 154
Other 58 5 3 66
-------- -------- -------- --------
Total revenues 2,226 308 250 2,784
-------- -------- -------- --------
COSTS AND EXPENSES
Lease operating expenses 319 52 70 441
Transportation costs 42 11 -- 53
Production taxes 102 1 -- 103
Depreciation, depletion and
amortization of property
and equipment 565 65 63 693
Amortization of goodwill 41 -- -- 41
General and administrative expenses 81 10 2 93
Expenses related to mergers 60 -- -- 60
Interest expense 144 10 1 155
Effects of changes in foreign
currency exchange rates -- 3 -- 3
-------- -------- -------- --------
Total costs and expenses 1,354 152 136 1,642
-------- -------- -------- --------
Earnings before income tax expense 872 156 114 1,142
INCOME TAX EXPENSE
Current 113 2 16 131
Deferred 185 67 29 281
-------- -------- -------- --------
Total income tax expense 298 69 45 412
-------- -------- -------- --------
Net earnings $ 574 87 69 730
======== ======== ======== ========
Capital expenditures $ 893 203 184 1,280
======== ======== ======== ========
124
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
U.S. CANADA INTERNATIONAL TOTAL
---- ------ ------------- -----
(IN MILLIONS)
AS OF DECEMBER 31, 1999:
Current assets $ 391 69 130 590
Property and equipment, net of
accumulated depreciation, depletion
and amortization 3,425 468 531 4,424
Other assets 944 -- 138 1,082
-------- -------- -------- --------
Total assets $ 4,760 537 799 6,096
======== ======== ======== ========
Current liabilities 357 45 65 467
Long-term debt 2,077 339 -- 2,416
Deferred tax liabilities (assets) 340 2 (18) 324
Other liabilities 318 3 47 368
Stockholders' equity 1,668 148 705 2,521
-------- -------- -------- --------
Total liabilities and
stockholders' equity $ 4,760 537 799 6,096
======== ======== ======== ========
YEAR ENDED DECEMBER 31, 1999:
REVENUES
Oil sales $ 332 80 149 561
Gas sales 502 114 12 628
Natural gas liquids sales 58 10 -- 68
Other 15 5 1 21
-------- -------- -------- --------
Total revenues 907 209 162 1,278
-------- -------- -------- --------
COSTS AND EXPENSES
Lease operating expenses 189 50 60 299
Transportation costs 22 12 -- 34
Production taxes 43 1 1 45
Depreciation, depletion and
amortization of property
and equipment 309 65 32 406
Amortization of goodwill 16 -- -- 16
General and administrative expenses 69 12 -- 81
Expenses related to mergers 17 -- -- 17
Interest expense 84 24 1 109
Effects of changes in foreign
currency exchange rates -- (13) -- (13)
Distributions on preferred
securities of subsidiary trust 7 -- -- 7
Reduction of carrying value of
oil and gas properties 464 -- 12 476
-------- -------- -------- --------
Total costs and expenses 1,220 151 106 1,477
-------- -------- -------- --------
Earnings (loss) before income tax
expense (benefit) and
extraordinary item (313) 58 56 (199)
INCOME TAX EXPENSE (BENEFIT)
Current 15 3 5 23
Deferred (119) 27 20 (72)
-------- -------- -------- --------
Total income tax expense
(benefit) (104) 30 25 (49)
-------- -------- -------- --------
Net earnings (loss) before
extraordinary item (209) 28 31 (150)
Extraordinary loss (4) -- -- (4)
-------- -------- -------- --------
Net earnings (loss) $ (213) 28 31 (154)
======== ======== ======== ========
Capital expenditures $ 686 92 105 883
======== ======== ======== ========
125
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Following is a summary of the unaudited interim results of operations for
the years ended December 31, 2001 and 2000.
2001
------------------------------------------------------------
FIRST SECOND THIRD FOURTH FULL
QUARTER QUARTER QUARTER QUARTER YEAR
------- ------- ------- ------- ----
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Oil, gas and natural gas liquids
sales $ 1,011 710 571 688 2,980
Total revenues $ 1,024 725 586 740 3,075
Net earnings (loss) $ 400 136 85 (518) 103
Net earnings (loss) per
common share:
Basic $ 3.08 1.03 0.65 (4.13) 0.73
Diluted $ 2.96 1.01 0.64 (4.13) 0.72
2000
------------------------------------------------------------
FIRST SECOND THIRD FOURTH FULL
QUARTER QUARTER QUARTER QUARTER YEAR
------- ------- ------- ------- ----
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Oil, gas and natural gas liquids
sales $ 548 636 695 839 2,718
Total revenues $ 560 649 725 850 2,784
Net earnings $ 105 153 165 307 730
Net earnings 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
The second, third and fourth quarters of 2001 include $77 million, $10
million and $916 million, respectively, of reductions of carrying value of oil
and gas properties. The after-tax effect of these expenses was $62 million, $7
million and $556 million, respectively. The per share effect of these quarterly
reductions was $0.48, $0.05 and $4.42, respectively.
The third and fourth quarters of 2000 include $57 million and $3 million,
respectively, of expenses incurred in connection with the Santa Fe Snyder
merger. The after-tax effect of these expenses was $35 million and $2 million,
respectively. The per share effect of these quarterly reductions was $0.28 and
$0.01, respectively.
126
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
19. SUBSEQUENT EVENT AND PRO FORMA FINANCIAL INFORMATION (UNAUDITED)
Mitchell Energy & Development Corp. Merger
On January 24, 2002, Devon completed its acquisition of Mitchell. Devon
acquired Mitchell for the significant development and exploitation projects in
each of Mitchell's core areas, increased gas services operations and increased
exposure to the North American natural gas market. Assuming the Mitchell merger
had closed on December 31, 2001, the calculation of the purchase price and the
preliminary allocation to assets and liabilities are shown below.
(IN MILLIONS,
EXCEPT SHARE PRICE)
-------------------
Calculation and preliminary allocation of purchase price:
Shares of Devon common stock issued to Mitchell stockholders 30
Average Devon stock price $ 50.95
--------
Fair value of common stock issued $ 1,507
Cash paid to Mitchell stockholders, calculated at $31 per outstanding
common share of Mitchell 1,567
--------
Fair value of Devon common stock and cash to be issued to Mitchell
Stockholders 3,074
Plus estimated acquisition costs incurred 90
Plus fair value of Mitchell employee stock options assumed by Devon 25
--------
Total purchase price 3,189
Plus fair value of liabilities assumed by Devon:
Current liabilities 305
Long-term debt 363
Other long-term liabilities 76
Deferred income taxes 802
--------
Total purchase price plus liabilities assumed $ 4,735
========
Fair value of assets acquired by Devon:
Current assets 193
Proved oil and gas properties 1,456
Unproved oil and gas properties 696
Gas services facilities and equipment 840
Other property and equipment 3
Other assets 57
Goodwill (none deductible for income tax purposes) 1,490
--------
Total fair value of assets acquired $ 4,735
========
Pro Forma Information
Set forth in the following tables are certain unaudited pro forma
financial information as of December 31, 2001, and for the years ended December
31, 2001 and 2000. The information as of December 31, 2001, assumes the Mitchell
merger had closed on such date. The information for
127
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
the years ended December 31, 2001 and 2000, has been prepared assuming the
Anderson acquisition and the Mitchell merger were consummated on January 1,
2000. All pro forma information 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, 2000. The pro forma information also should not be used
as an indication of the future results that Devon will achieve after the
transactions.
The following should be considered in connection with the pro forma
financial information presented:
- In 2000, Devon recognized $60 million of expenses related to its merger
with Santa Fe Snyder Corporation. Devon accounted for the Santa Fe Snyder merger
using the pooling-of-interests method of accounting and, therefore, the expenses
incurred related to the merger were expensed. The after-tax effect of these
expenses in 2000 was $37 million.
- In 2000, Mitchell realized income tax savings of $13 million related to
prior years' Section 29 tax credits and $6 million related to the reversal of
prior years' deferred income taxes.
- In 2000, Mitchell recognized a $5 million gain from the exchange of
certain gas services assets. Also in 2000, Mitchell recognized an $11 million
impairment expense related to other gas services assets. Net of tax, these two
events reduced Mitchell's 2000 net earnings by $4 million.
- On May 17, 2000, Anderson acquired all the outstanding shares of Ulster
Petroleums Ltd. The summary unaudited pro forma combined statements of
operations do not include any results from Ulster's operations prior to May 17,
2000.
- On February 12, 2001, Anderson acquired all of the outstanding shares of
Numac Energy Inc. The summary unaudited pro forma combined statements of
operations do not include any results from Numac's operations prior to February
12, 2001.
- In 2001, Devon elected to discontinue operations in Malaysia, Qatar,
Thailand and on certain properties in Brazil. Accordingly, in 2001, Devon
recorded an $87 million charge associated with the impairment of those
properties. The after-tax effect of this reduction was $69 million.
- In 2001, Devon reduced the carrying value of its oil and gas properties
by $916 million due to the full cost ceiling limitations. The after-tax effect
of this reduction was $556 million.
- Anderson had a compensation plan pursuant to which it periodically
issued awards referred to as share appreciation rights under which employees
could earn compensation based on increases in the market price of Anderson's
stock. Anderson awarded these rights in lieu of stock
128
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
option grants. Pro forma general and administrative expenses reported in the
accompanying unaudited pro forma statements of operations for the years ended
December 31, 2001 and 2000 include $6 million and $5 million, respectively, of
expenses related to these plans. After taxes, these plans had the effect of
decreasing unaudited pro forma net earnings in the 2001 and 2000 periods by $3
million and $3 million, respectively. Devon acquired all outstanding rights as
part of the Anderson acquisition. Accordingly, these rights will not affect
Devon's net earnings subsequent to the closing of the Anderson acquisition.
- Mitchell has incentive compensation plans pursuant to which it has
periodically issued awards referred to as bonus units under which employees can
earn compensation based on increases in the market price of Mitchell common
stock. Mitchell generally awards these bonus units in lieu of stock option
grants. Pro forma general and administrative expenses reported in the
accompanying unaudited pro forma statements of operations for the year 2000
include $21 million of expense related to these plans. After taxes, these plans
had the effect of decreasing unaudited pro forma net earnings in the 2000 period
by $14 million. Devon will not issue such bonus units after the merger.
- Devon's historical results of operations for the years 2001 and 2000
include $34 million and $41 million, respectively, of amortization expense for
goodwill related to previous mergers. As of January 1, 2002, in accordance with
new accounting pronouncements recently issued, such goodwill will cease to be
amortized and, instead, will be tested for impairment at least annually. No
goodwill amortization expense has been recognized in the pro forma statements of
operations for the goodwill related to the Anderson acquisition and the Mitchell
merger.
PRO FORMA
INFORMATION
AS OF
DECEMBER 31, 2001
-----------------
(DOLLARS IN
MILLIONS)
Balance sheet data:
Property and equipment, net $ 11,872
Investment in common stock of ChevronTexaco Corporation 636
Goodwill 3,698
Total assets 17,784
Debentures exchangeable into shares of ChevronTexaco
Corporation common stock 649
Other long-term debt 7,882
Stockholders' equity 4,694
Proved reserves:
Oil (MMBbls) 602
Gas (Bcf) 7,186
NGLs (MMBbls) 211
MMBoe 2,011
Standardized measure of discounted future net cash flows $ 6,185
129
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
PRO FORMA INFORMATION
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000
---- ----
(IN MILLIONS, EXCEPT PER SHARE
AMOUNTS AND PRODUCTION VOLUMES)
REVENUES
Oil sales $ 1,232 1,384
Gas sales 3,145 2,522
Natural gas liquids sales 308 342
Gas services revenue 1,169 1,202
Other 92 47
-------- --------
Total revenues 5,946 5,497
-------- --------
COSTS AND EXPENSES
Lease operating expenses 769 640
Transportation costs 155 119
Production taxes 149 129
Gas services costs and expenses 1,038 984
Depreciation, depletion and amortization
of property and equipment 1,393 1,192
Amortization of goodwill 34 41
General and administrative expenses 202 205
Expenses related to mergers 1 60
Interest expense 508 495
Effects of changes in foreign currency
exchange rates 21 3
Change in fair value of financial instruments 16 --
Reduction of carrying value of oil and
gas properties 1,155 --
-------- --------
Total costs and expenses 5,441 3,868
-------- --------
Earnings before income tax expense and
cumulative effect of
change in accounting principle 505 1,629
INCOME TAX EXPENSE
Current 108 173
Deferred 68 412
-------- --------
Total income tax expense 176 585
-------- --------
Earnings before cumulative effect of change
in accounting principle 329 1,044
Cumulative effect of change in accounting principle 49 --
-------- --------
Net earnings 378 1,044
Preferred stock dividends 10 10
-------- --------
Net earnings applicable to common stockholders $ 368 1,034
======== ========
Net earnings before cumulative effect of change
in accounting principle per
average common share outstanding:
Basic $ 2.03 6.62
======== ========
Diluted $ 2.00 6.45
======== ========
Net earnings per average common share outstanding:
Basic $ 2.35 6.62
======== ========
Diluted $ 2.30 6.45
======== ========
Weighted average common shares outstanding--basic 157 156
======== ========
Weighted average common shares outstanding--diluted 164 161
======== ========
Production volumes:
Oil (MMBbls) 58 54
Gas (Bcf) 810 708
NGLs (MMBbls) 17 16
MMBoe 210 188
130
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
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, 2002.
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, 2002.
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, 2002.
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, 2002.
131
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 69 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 Offer to Purchase for Cash and Directors' Circular dated
September 6, 2001 between Registrant and Anderson
Exploration Ltd. (incorporated by reference to
Registrant's and Devon Acquisition Corporation's
Schedule 14D-1F as filed September 6, 2001).
2.2 Pre-Acquisition Agreement, dated as of August 31, 2001,
between Registrant and Anderson Exploration Ltd.
(incorporated by reference to Exhibit 2.2 to
Registrant's Registration Statement on Form S-4, File
No. 333-68694 as filed September 14, 2001).
2.3 Amended and Restated Agreement and Plan of Merger, dated
as of August 13, 2001, by and among Registrant, Devon
NewCo Corporation, Devon Holdco Corporation, Devon
Merger Corporation, Mitchell Merger Corporation and
Mitchell Energy & Development Corp. (incorporated by
reference to Annex A to Registrant's Joint Proxy
Statement/Prospectus of Form S-4 Registration Statement
No. 333-68694 as filed August 30, 2001).
2.4 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).
2.5 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).
132
2.6 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).
2.7 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).
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 of Registrant
(incorporated by reference to Exhibit 4.1 to
Registrant's Form 8-K filed on August 18, 1999).
4.2 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).
4.3 Amendment to Rights Agreement, dated as of May 25, 2000,
by and 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 on July 21, 2000).
4.4 Amendment to Rights Agreement, dated as of October 4,
2001, by and between Registrant and Fleet National Bank
(f/k/a Bank Boston, N.A.) (incorporated by reference to
Exhibit 99.1 to Registrant's Form 8-K filed on October
11, 2001).
4.5 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).
4.6 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).
133
4.7 Registration Rights Agreement dated as of October 3,
2001 by and among Devon Financing Corporation, U.L.C.,
as Issuer, Registrant, as Guarantor and UBS Warburg LLC,
Banc of America Securities LLC, ABN AMRO Incorporated,
BMO Nesbitt Burns Corp., Credit Suisse First Boston
Corporation, Deutsche Banc Alex. Brown Inc., First Union
Securities, Inc., J.P. Morgan Securities Inc., RBC
Dominion Securities Corporation, Salomon Smith Barney
Inc., as Initial Purchasers (6.875% Notes due 2011,
7.875% Debentures due 2031) (incorporated by reference
to Exhibit 4.8 to Registrant's Registration Statement on
Form S-4, File No. 333-68694 as filed October 31, 2001).
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 Indenture, dated as of October 3, 2001, by and among
Devon Financing Corporation, U.L.C. (as issuer),
Registrant (as guarantor) and The Chase Manhattan Bank
(as trustee) 6.875% Notes due 2011 and 7.875% Debentures
due 2031 (incorporated by reference to Exhibit 4.7 to
Registrant's Registration Statement on Form S-4, File
No. 333-68694 as filed October 31, 2001).
4.10 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).
4.11 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).
4.12 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 as filed November
16, 2000).
4.13 Form of Zero Coupon Convertible Senior Subordinated
Debenture Due 2020 (incorporated by reference to Exhibit
A of Exhibit 4.2 to Registrant's Form 8-K filed July 12,
2000).
4.14 Indenture dated as of June 27, 2000 between Registrant
and The Bank of New York, setting forth the terms of the
Zero Coupon Convertible Senior Debentures due 2020
(incorporated by reference to Exhibit 4.2 to
Registrant's Form 8-K filed July 12, 2000).
134
4.15 Form of Indenture relating to senior debt securities of
Registrant (incorporated by reference to Exhibit 4.10 to
Registrant's Registration Statement on Form S-3, File
No. 333-83156 as filed February 21, 2002).
4.16 Form of Indenture relating to subordinated debt
securities of Registrant (incorporated by reference to
Exhibit 4.11 to Registrant's Registration Statement on
Form S-3, File No. 333-83156 as filed February 21,
2002).
4.17 Form of Indenture relating to debt securities of Devon
Financing Corporation, U.L.C. (as Issuer) and Registrant
(as Guarantor) (incorporated by reference to Exhibit
4.12 to Registrant's Registration Statement on Form S-3,
File No. 333-83156 as filed February 21, 2002).
4.18 Form of Amended and Restated Declaration of Trust of
Devon Financing Trust II (incorporated by reference to
Exhibit 4.14 to Registrant's Registration Statement on
Form S-3, File No. 333-83156 as filed February 21,
2002).
4.19 Form of Trust Preferred Securities Guaranty Agreement
for Devon Financing Trust II (incorporated by reference
to Exhibit 4.13 to Registrant's Registration Statement
on Form S-3, File No. 333-83156 as filed February 21,
2002).
4.20 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).
4.21 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).
4.22 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).
135
4.23 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).
4.24 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).
4.25 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)).
4.26 Third 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 4.90% 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).
4.27 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).
4.28 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).
136
4.29 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).
4.30 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).
4.31 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).
4.32 Amending Support Agreement dated August 17, 1999,
between the Registrant and Northstar Energy Corporation
(incorporated by reference to Exhibit 4.5 to
Registrant's Form 8-K filed on August 18, 1999).
4.33 Exchangeable Share Provisions (incorporated by reference
to Exhibit 4.2 to Registrant's Form 8-K filed December
23, 1998).
4.34 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 Amended and Restated Principal Shareholders Agreement
Containing a Voting Agreement and an Irrevocable Proxy,
dated as of August 13, 2001, by and among Devon Energy
Corporation, George P. Mitchell and Cynthia Woods
Mitchell (attached as Annex B to the Joint Proxy
Statement/Prospectus of Form S-4 Registration Statement
No. 333-68694 as filed August 30, 2001).
137
10.2 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 (incorporated by reference to Exhibit 10.1 to
Registrant's Form 10-K filed on March 15, 2001).
10.3 First Amendment to U.S. Credit Agreement dated March 1,
2001, among Registrant, Bank of America N.A.,
individually and as administrative agent, and the U.S.
Lenders party to the Original Agreement (incorporated by
reference to Exhibit 10.1.1 to Registrant's Form 10-Q
filed on May 14, 2001).
10.4 Second Amendment to U.S. Credit Agreement dated as of
June 27, 2001, among Registrant, Bank of America, N.A.,
individually and as administrative agent, and the U.S.
Lenders party to the Original Agreement (incorporated by
reference to Exhibit 10.1.2 to Registrant's Form 10-Q
filed on August 14, 2001).
10.5 Third Amendment to U.S. Credit Agreement dated as of
July 31, 2001, among Registrant, Bank of America, N.A.,
individually and as administrative agent, and the U.S.
Lenders party to the Original Agreement (incorporated by
reference to Exhibit 10.4 to Registrant's Registration
Statement on Form S-4, File No. 333-68694 as filed
October 31, 2001).
10.6 Fourth Amendment to U.S. Credit Agreement dated as of
August 13, 2001, among Registrant, Bank of America,
N.A., individually and as administrative agent, and the
U.S. Lenders party to the Original Agreement
(incorporated by reference to Exhibit 10.5 to
Registrant's Registration Statement on Form S-4, File
No. 333-68694 as filed October 31, 2001).
10.7 Fifth Amendment to U.S. Credit Agreement dated as of
September 21, 2001, among Registrant, Bank of America,
N.A., individually and as administrative agent, and the
U.S. Lenders party to the Original Agreement
(incorporated by reference to Exhibit 10.6 to
Registrant's Registration Statement on Form S-4, File
No. 333-68694 as filed October 31, 2001).
10.8 Sixth Amendment to U.S. Credit Agreement dated as of
October 5, 2001, among Registrant, Bank of America,
N.A., individually and as administrative agent, and the
U.S. Lenders party to the Original Agreement
(incorporated by reference to Exhibit 10.7 to
Registrant's Registration Statement on Form S-4, File
No. 333-68694 as filed October 31, 2001).
138
10.9 Amended and Restated Investor Rights Agreement, dated as
of August 13, 2001, by and among Devon Energy
Corporation, Devon Holdco Corporation, George P.
Mitchell and Cynthia Woods Mitchell (attached as Annex C
to the Joint Proxy Statement/Prospectus of Form S-4
Registration Statement No. 333-68694 as filed August 30,
2001).
10.10 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 (incorporated by reference to Exhibit 10.2 to
Registrant's Form 10-K filed on March 15, 2001).
10.11 First Amendment to Canadian Credit Agreement dated March
1, 2001, among Northstar Energy Corporation, Bank of
America Canada, individually and as administrative agent
and the Canadian Lenders party to the Original Agreement
(incorporated by reference to Exhibit 10.2.1 to
Registrant's Form 10-Q filed on May 14, 2001).
10.12 Second Amendment to Canadian Credit Agreement dated as
of June 27, 2001, among Northstar Energy Corporation,
Bank of America Canada, individually and as
administrative agent, and the Canadian Lenders party to
the Original Agreement (incorporated by reference to
Exhibit 10.2.2 to Registrant's Form 10-Q filed on August
14, 2001).
10.13 Third Amendment to Canadian Credit Agreement dated as of
July 31, 2001, among Northstar Energy Corporation, Bank
of America Canada, individually and as administrative
agent, and the Canadian Lenders party to the Original
Agreement (incorporated by reference to Exhibit 10.8 to
Registrant's Registration Statement on Form S-4, File
No. 333-68694 as filed October 31, 2001).
10.14 Fourth Amendment to Canadian Credit Agreement dated as
of August 13, 2001, among Northstar Energy Corporation,
Bank of America Canada, individually and as
administrative agent, and the Canadian Lenders party to
the Original Agreement (incorporated by reference to
Exhibit 10.9 to Registrant's Registration Statement on
Form S-4, File No. 333-68694 as filed October 31, 2001).
10.15 Fifth Amendment to Canadian Credit Agreement dated as of
September 21, 2001, among Northstar Energy Corporation,
Bank of America Canada, individually and as
administrative agent, and the Canadian Lenders party to
the Original Agreement (incorporated by reference to
Exhibit 10.10 to Registrant's Registration Statement on
Form S-4, File No. 333-68694 as filed October 31, 2001).
139
10.16 Sixth Amendment to Canadian Credit Agreement dated as of
October 5, 2001, among Northstar Energy Corporation,
Bank of America Canada, individually and as
administrative agent, and the Canadian Lenders party to
the Original Agreement (incorporated by reference to
Exhibit 10.11 to Registrant's Registration Statement on
Form S-4, File No. 333-68694 as filed October 31, 2001).
10.17 Credit Agreement, dated as of October 12, 2001, by and
among Devon Energy Corporation, Devon Financing
Corporation, U.L.C., UBS AG, Stamford Branch (as
Administrative Agent), and the lenders signatory thereto
(incorporated by reference to Exhibit 10.3 to
Registrant's Registration Statement on Form S-4, File
No. 333-68694 as filed October 31, 2001).
10.18 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).*
10.19 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).*
10.20 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).*
140
10.21 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).*
10.22 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).*
10.23 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).*
10.24 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).*
10.25 Supplemental Retirement Income Plan of Devon Energy
Corporation among Registrant and Brian J. Jennings, J.
Michael Lacey, Duke R. Ligon, Marian J. Moon, J. Larry
Nichols, Darryl G. Smette and William T. Vaughn, dated
August 1, 2001.*
10.26 Form of Employment Agreement between Registrant and
Brian J. Jennings, J. Michael Lacey, Duke R. Ligon,
Marian J. Moon, J. Larry Nichols, Darryl G. Smette and
William T. Vaughn, dated January 1, 2002.*
10.27 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
141
21 Significant Subsidiaries of Registrant
23.1 Consent of LaRoche Petroleum Consultants
23.2 Consent of Paddock Lindstrom & Associates Ltd.
23.3 Consent of Ryder Scott Company, L.P.
23.4 Consent of Gilbert Laustsen Jung Associates Ltd.
23.5 Consent of KPMG LLP
23.6 Consent of PricewaterhouseCoopers LLP
(b) Reports on Form 8-K
October 3, 2001, the Company announced that Devon Financing Corporation,
U.L.C. completed a private placement of 10-year notes and 30-year
debentures.
October 11, 2001, the Company and Mitchell announced that the board of
directors of each company approved an amendment to the merger agreement.
October 12, 2001, the Company announced it received all necessary
regulatory approvals concerning the acquisition of Anderson.
October 26, 2001, the Company announced the completion of the Anderson
acquisition.
October 31, 2001, the Company announced that it had entered into various
financial transactions.
November 1, 2001, the Company reported third quarter and year-to-date
2001 financial results.
November 1, 2001, the Company filed its financial statements and notes as
of September 30, 2001, and for the three-month and nine-month periods ended
September 30, 2001 and 2000.
November 28, 2001, the Company filed Rule 425 filings in a Form 8-K in
connection with the Mitchell acquisition.
December 3, 2001, the Company filed Anderson's historical consolidated
financial statements and unaudited pro forma financial information.
December 12, 2001, the Company filed forward looking statements in
connection with its December 31, 2001 reserve reports of independent
petroleum engineers.
December 21, 2001, the Company announced that it entered into additional
hedging transactions and summarized the aggregate effects of its 2002 oil
and gas hedges in place.
142
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 18, 2002 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 18, 2002 By /s/ J. Larry Nichols
-------------------------------------
J. Larry Nichols
Chairman of the Board, President and
Chief Executive Officer
March 18, 2002 By /s/ William T. Vaughn
-------------------------------------
William T. Vaughn
Senior Vice President -- Finance
March 18, 2002 By /s/ Danny J. Heatly
-------------------------------------
Danny J. Heatly
Vice President - Accounting
143
March 18, 2002 By /s/ Thomas F. Ferguson
-------------------------------------
Thomas F. Ferguson, Director
March 18, 2002 By /s/ David M. Gavrin
-------------------------------------
David M. Gavrin, Director
March 18, 2002 By /s/ Michael E. Gellert
-------------------------------------
Michael E. Gellert, Director
March 18, 2002 By /s/ John A. Hill
-------------------------------------
John A. Hill, Director
March 18, 2002 By /s/ William J. Johnson
-------------------------------------
William J. Johnson, Director
March 18, 2002 By /s/ Michael M. Kanovsky
-------------------------------------
Michael M. Kanovsky, Director
March 18, 2002 By /s/ J. Todd Mitchell
-------------------------------------
J. Todd Mitchell, Director
March 18, 2002 By /s/ Robert Mosbacher, Jr.
-------------------------------------
Robert A. Mosbacher, Jr., Director
March 18, 2002 By /s/ Robert B. Weaver
-------------------------------------
Robert B. Weaver, Director
144
INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION
--------------- -----------
2.1 Offer to Purchase for Cash and Directors' Circular dated
September 6, 2001 between Registrant and Anderson Exploration
Ltd. (incorporated by reference to Registrant's and Devon
Acquisition Corporation's Schedule 14D-1F as filed
September 6, 2001).
2.2 Pre-Acquisition Agreement, dated as of August 31, 2001,
between Registrant and Anderson Exploration Ltd.
(incorporated by reference to Exhibit 2.2 to Registrant's
Registration Statement on Form S-4, File No. 333-68694 as
filed September 14, 2001).
2.3 Amended and Restated Agreement and Plan of Merger, dated as of
August 13, 2001, by and among Registrant, Devon NewCo
Corporation, Devon Holdco Corporation, Devon Merger
Corporation, Mitchell Merger Corporation and Mitchell Energy
& Development Corp. (incorporated by reference to Annex A to
Registrant's Joint Proxy Statement/Prospectus of Form S-4
Registration Statement No. 333-68694 as filed August 30,
2001).
2.4 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).
2.5 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).
2.6 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).
2.7 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).
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).
EXHIBIT
NUMBER DESCRIPTION
------ -----------
4.1 Form of Common Stock Certificate of Registrant (incorporated
by reference to Exhibit 4.1 to Registrant's Form 8-K filed on
August 18, 1999).
4.2 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).
4.3 Amendment to Rights Agreement, dated as of May 25, 2000, by
and 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 on July 21, 2000).
4.4 Amendment to Rights Agreement, dated as of October 4, 2001, by
and between Registrant and Fleet National Bank (f/k/a Bank
Boston, N.A.) (incorporated by reference to Exhibit 99.1 to
Registrant's Form 8-K filed on October 11, 2001).
4.5 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).
4.6 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).
4.7 Registration Rights Agreement dated as of October 3, 2001 by
and among Devon Financing Corporation, U.L.C., as Issuer,
Registrant, as Guarantor and UBS Warburg LLC, Banc of America
Securities LLC, ABN AMRO Incorporated, BMO Nesbitt Burns
Corp., Credit Suisse First Boston Corporation, Deutsche Banc
Alex. Brown Inc., First Union Securities, Inc., J.P. Morgan
Securities Inc., RBC Dominion Securities Corporation, Salomon
Smith Barney Inc., as Initial Purchasers (6.875% Notes due
2011, 7.875% Debentures due 2031) (incorporated by reference
to Exhibit 4.8 to Registrant's Registration Statement on Form
S-4, File No. 333-68694 as filed October 31, 2001).
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 Indenture, dated as of October 3, 2001, by and among Devon
Financing Corporation, U.L.C. (as issuer), Registrant (as
guarantor) and The Chase Manhattan Bank (as trustee) 6.875%
Notes due 2011 and 7.875% Debentures due 2031 (incorporated by
reference to Exhibit 4.7 to Registrant's Registration
Statement on Form S-4, File No. 333-68694 as filed October 31,
2001).
EXHIBIT
NUMBER DESCRIPTION
------ -----------
4.10 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).
4.11 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).
4.12 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 as filed November 16, 2000).
4.13 Form of Zero Coupon Convertible Senior Subordinated Debenture
Due 2020 (incorporated by reference to Exhibit A of Exhibit
4.2 to Registrant's Form 8-K filed July 12, 2000).
4.14 Indenture dated as of June 27, 2000 between Registrant and The
Bank of New York, setting forth the terms of the Zero Coupon
Convertible Senior Debentures due 2020 (incorporated by
reference to Exhibit 4.2 to Registrant's Form 8-K filed July
12, 2000).
4.15 Form of Indenture relating to senior debt securities of Devon
(incorporated by reference to Exhibit 4.10 to Registrant's
Registration Statement on Form S-3, File No. 333-83156 as
filed February 21, 2002).
4.16 Form of Indenture relating to subordinated debt securities of
Registrant (incorporated by reference to Exhibit 4.11 to
Registrant's Registration Statement on Form S-3, File No.
333-83156 as filed February 21, 2002).
4.17 Form of Indenture relating to debt securities of Devon
Financing Corporation, U.L.C. (as Issuer) and Registrant (as
Guarantor) (incorporated by reference to Exhibit 4.12 to
Registrant's Registration Statement on Form S-3, File No.
333-83156 as filed February 21, 2002).
4.18 Form of Amended and Restated Declaration of Trust of Devon
Financing Trust II (incorporated by reference to Exhibit 4.14
to Registrant's Registration Statement on Form S-3, File No.
333-83156 as filed February 21, 2002).
4.19 Form of Trust Preferred Securities Guaranty Agreement for
Devon Financing Trust II (incorporated by reference to Exhibit
4.13 to Registrant's Registration Statement on Form S-3, File
No. 333-83156 as filed February 21, 2002).
EXHIBIT
NUMBER DESCRIPTION
------ -----------
4.20 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).
4.21 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).
4.22 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).
4.23 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).
4.24 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).
4.25 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)).
4.26 Third 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 4.90% 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).
EXHIBIT
NUMBER DESCRIPTION
------ -----------
4.27 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).
4.28 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).
4.29 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).
4.30 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).
4.31 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).
4.32 Amending Support Agreement dated August 17, 1999, between the
Registrant and Northstar Energy Corporation (incorporated by
reference to Exhibit 4.5 to Registrant's Form 8-K filed on
August 18, 1999).
4.33 Exchangeable Share Provisions (incorporated by reference to
Exhibit 4.2 to Registrant's Form 8-K filed December 23, 1998).
EXHIBIT
NUMBER DESCRIPTION
------ -----------
4.34 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 Amended and Restated Principal Shareholders Agreement
Containing a Voting Agreement and an Irrevocable Proxy, dated
as of August 13, 2001, by and among Devon Energy Corporation,
George P. Mitchell and Cynthia Woods Mitchell (attached as
Annex B to the Joint Proxy Statement/Prospectus of Form S-4
Registration Statement No. 333-68694 as filed August 30, 2001).
10.2 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 (incorporated by reference to Exhibit 10.1 to
Registrant's Form 10-K filed on March 15, 2001).
10.3 First Amendment to U.S. Credit Agreement dated March 1, 2001,
among Registrant, Bank of America N.A., individually and as
administrative agent, and the U.S. Lenders party to the
Original Agreement (incorporated by reference to Exhibit
10.1.1 to Registrant's Form 10-Q filed on May 14, 2001).
10.4 Second Amendment to U.S. Credit Agreement dated as of June 27,
2001, among Registrant, Bank of America, N.A., individually
and as administrative agent, and the U.S. Lenders party to the
Original Agreement (incorporated by reference to Exhibit
10.1.2 to Registrant's Form 10-Q filed on August 14, 2001).
10.5 Third Amendment to U.S. Credit Agreement dated as of July 31,
2001, among Registrant, Bank of America, N.A., individually
and as administrative agent, and the U.S. Lenders party to the
Original Agreement (incorporated by reference to Exhibit 10.4
to Registrant's Registration Statement on Form S-4, File No.
333-68694 as filed October 31, 2001).
EXHIBIT
NUMBER DESCRIPTION
------ -----------
10.6 Fourth Amendment to U.S. Credit Agreement dated as of August
13, 2001, among Registrant, Bank of America, N.A.,
individually and as administrative agent, and the U.S. Lenders
party to the Original Agreement (incorporated by reference to
Exhibit 10.5 to Registrant's Registration Statement on Form
S-4, File No. 333-68694 as filed October 31, 2001).
10.7 Fifth Amendment to U.S. Credit Agreement dated as of September
21, 2001, among Registrant, Bank of America, N.A.,
individually and as administrative agent, and the U.S. Lenders
party to the Original Agreement (incorporated by reference to
Exhibit 10.6 to Registrant's Registration Statement on Form
S-4, File No. 333-68694 as filed October 31, 2001).
10.8 Sixth Amendment to U.S. Credit Agreement dated as of October
5, 2001, among Registrant, Bank of America, N.A., individually
and as administrative agent, and the U.S. Lenders party to the
Original Agreement (incorporated by reference to Exhibit 10.7
to Registrant's Registration Statement on Form S-4, File No.
333-68694 as filed October 31, 2001).
10.9 Amended and Restated Investor Rights Agreement, dated as of
August 13, 2001, by and among Devon Energy Corporation, Devon
Holdco Corporation, George P. Mitchell and Cynthia Woods
Mitchell (attached as Annex C to the Joint Proxy
Statement/Prospectus of Form S-4 Registration Statement No.
333-68694 as filed August 30, 2001).
10.10 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 (incorporated by reference to Exhibit 10.2 to
Registrant's Form 10-K filed on March 15, 2001).
10.11 First Amendment to Canadian Credit Agreement dated March 1,
2001, among Northstar Energy Corporation, Bank of America
Canada, individually and as administrative agent and the
Canadian Lenders party to the Original Agreement (incorporated
by reference to Exhibit 10.2.1 to Registrant's Form 10-Q filed
on May 14, 2001).
10.12 Second Amendment to Canadian Credit Agreement dated as of June
27, 2001, among Northstar Energy Corporation, Bank of America
Canada, individually and as administrative agent, and the
Canadian Lenders party to the Original Agreement (incorporated
by reference to Exhibit 10.2.2 to Registrant's Form 10-Q filed
on August 14, 2001).
EXHIBIT
NUMBER DESCRIPTION
------ -----------
10.13 Third Amendment to Canadian Credit Agreement dated as of July
31, 2001, among Northstar Energy Corporation, Bank of America
Canada, individually and as administrative agent, and the
Canadian Lenders party to the Original Agreement (incorporated
by reference to Exhibit 10.8 to Registrant's Registration
Statement on Form S-4, File No. 333-68694 as filed October 31,
2001).
10.14 Fourth Amendment to Canadian Credit Agreement dated as of
August 13, 2001, among Northstar Energy Corporation, Bank of
America Canada, individually and as administrative agent, and
the Canadian Lenders party to the Original Agreement
(incorporated by reference to Exhibit 10.9 to Registrant's
Registration Statement on Form S-4, File No. 333-68694 as
filed October 31, 2001).
10.15 Fifth Amendment to Canadian Credit Agreement dated as of
September 21, 2001, among Northstar Energy Corporation, Bank
of America Canada, individually and as administrative agent,
and the Canadian Lenders party to the Original Agreement
(incorporated by reference to Exhibit 10.10 to Registrant's
Registration Statement on Form S-4, File No. 333-68694 as
filed October 31, 2001).
10.16 Sixth Amendment to Canadian Credit Agreement dated as of
October 5, 2001, among Northstar Energy Corporation, Bank of
America Canada, individually and as administrative agent, and
the Canadian Lenders party to the Original Agreement
(incorporated by reference to Exhibit 10.11 to Registrant's
Registration Statement on Form S-4, File No. 333-68694 as
filed October 31, 2001).
10.17 Credit Agreement, dated as of October 12, 2001, by and among
Devon Energy Corporation, Devon Financing Corporation, U.L.C.,
UBS AG, Stamford Branch (as Administrative Agent), and the
lenders signatory thereto (incorporated by reference to
Exhibit 10.3 to Registrant's Registration Statement on Form
S-4, File No. 333-68694 as filed October 31, 2001).
10.18 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).*
EXHIBIT
NUMBER DESCRIPTION
------ -----------
10.19 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).*
10.20 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).*
10.21 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).*
EXHIBIT
NUMBER DESCRIPTION
------ -----------
10.22 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).*
10.23 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).*
10.24 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).*
10.25 Supplemental Retirement Income Plan of Devon Energy
Corporation among Registrant and Brian J. Jennings, J. Michael
Lacey, Duke R. Ligon, Marian J. Moon, J. Larry Nichols, Darryl
G. Smette and William T. Vaughn, dated August 1, 2001.*
10.26 Form of Employment Agreement between Registrant and Brian J.
Jennings, J. Michael Lacey, Duke R. Ligon, Marian J. Moon, J.
Larry Nichols, Darryl G. Smette and William T. Vaughn, dated
January 1, 2002.*
10.27 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 Significant Subsidiaries of Registrant
23.1 Consent of LaRoche Petroleum Consultants
23.2 Consent of Paddock Lindstrom & Associates Ltd.
23.3 Consent of Ryder Scott Company, L.P.
23.4 Consent of Gilbert Laustsen Jung Associates Ltd.
23.5 Consent of KPMG LLP
23.6 Consent of PricewaterhouseCoopers LLP
*Compensatory plans or arrangements