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Devon Energy Corporation
2001 ANNUAL REPORT
B a l a n c e d .
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1
C o n t e n t s
2
5
9
15
22
24
29
93
100
101
Five-Year Highlights and Comparisons
Letter to Shareholders
Chairman, President and CEO Larr y Nichols reflects upon a year of challenges
and accomplishments and shares his vision of Devon’s future.
Executive Q&A: A Balanced View
Senior Devon executives answer Wall Street’s questions.
Portfolio of Oil and Gas Properties
Devon provides a narrative summary of each of the company’s five exploration
and production divisions.
Operating Statistics by Area and Eleven-Year Property Data
Key Property Highlights
We pinpoint our signficant oil and gas properties, summarize recent activity
and share our plans for the future.
Financial Statements and Management’s Discussion and Analysis
Biographies of Directors and Officers
Glossary of Terms
Investor Information and Common Stock Trading Data
Devon Energy Corporation is engaged in oil and gas exploration, produc-
tion and property acquisitions. Devon ranks among the top-five U.S.-
based independent oil and gas producers and is one of the largest
independent processors of natural gas and natural gas liquids in North
America. The company also has operations in selected international
areas. Devon is included in the S&P 500 Index and its common shares
trade on the American Stock Exchange under the ticker symbol DVN.
Devon’s primary goal is to build value per share by:
• Exploring for undiscovered oil and gas reserves,
• Purchasing and exploiting producing oil and gas properties,
• Enhancing the value of our production through marketing
and midstream activities,
• Optimizing production operations to control costs, and
• Maintaining a strong balance sheet.
“Balanced,” the theme of this annual report, resulted from a suggestion by Rocky Mountain
Division employee Susan Gilbert. Gilbert's winning entry was one of nearly 300 suggestions
from employees in the company's annual report theme contest.
This annual report includes “forward-looking statements” as defined by the Securities and Exchange Commission. Such statements are those concerning Devon’s
plans, expectations and objectives for future operations. These statements address future financial position, business strategy, future capital expenditures,
projected oil and gas production and future costs. Devon believes that the expectations reflected in such forward-looking statements are reasonable. However,
important risk factors could cause actual results to differ materially from the company’s expectations. A discussion of these risk factors can be found in the
“Management’s Discussion & Analysis . . .” section of this report. Further information is available in the company’s Form 10-K and other publicly available
reports, which will be furnished upon request to the company.
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2
Fiv e -Y e a r H i g h l i g h t s
Devon's acquisition of Anderson Exploration on October 15, 2001 was recorded using the purchase method of accounting.
Therefore, the information presented below includes Anderson's results from October 15 through December 31, 2001 only.
Devon's acquisition of Mitchell Energy did not close until January 24, 2002. Therefore, Mitchell's results are not included for
any period reported.
(230)
(236)
93
(87%)
Year Ended December 31,
1 99 7
1 99 8
1 99 9
2 00 0
2 0 0 1
Financial Data (1) (Millions, except per share data)
Total revenues
Cash expenses (2)
Cash margin
Non-cash expenses
$ 1,014
457
$
557
$
Effects of changes in foreign currency exchange rates
Reduction of carr ying value of oil & gas properties
Change in accounting principle
Other non-cash expenses (including deferred taxes)
Net earnings (loss)
Net earnings (loss) applicable to common shareholders
Net earnings (loss) per share
$
$
$
$
$
$
6
641
–
128
(218)
706
382
324
16
423
–
121
(236)
Basic
Diluted
$ (3.35)
$ (3.35)
(3.32)
(3.32)
Weighted average common shares outstanding - basic
Weighted average common shares outstanding - diluted
69
75
71
77
1,278
615
663
(13)
476
–
354
(154)
(158)
(1.68)
(1.68)
94
99
2,784
1,036
1,748
3
–
–
1,015
730
720
5.66
5.50
127
132
Cash dividends per common share (3)
$
0.09
0.10
0.14
0.17
3,075
1,134
1,941
13
1,003
(49)
871
103
0.73
0.72
128
130
0.20
December 31,
Total assets
Debentures exchangeable into shares
of ChevronTexaco Corporation common stock (4)
Other long-term debt (5)
Stockholders’ equity
Working capital
Property Data (1)
Proved reserves (net of royalties)
Oil (MMBbls)
Gas (Bcf)
Natural gas liquids (MMBbls)
Total (MMBoe) (6)
10% present value (7) (Millions)
Year Ended December 31,
Production (net of royalties)
Oil (MMBbls)
Gas (Bcf)
Natural gas liquids (MMBbls)
Total (MMBoe) (6)
1 99 7
1 99 8
1 99 9
2 00 0
2 0 0 1
$ 1,965
1,931
6,096
6,860
13,184
–
$
$
576
$ 1,007
56
$
–
885
750
7
760
1,656
2,521
123
760
1,289
3,277
305
219
1,403
24
477
$ 2,100
235
1,477
33
514
1,528
496
2,950
68
1,056
5,812
459
3,458
62
1,097
17,737
649
5,940
3,259
162
586
5,477
121
1,620
7,174
1 99 7
1 99 8
1 99 9
2 00 0
2 0 0 1
32
186
3
66
26
198
3
62
32
304
5
88
43
426
7
121
44
498
8
135
Last Year
Change
10%
9%
11%
333%
NM
NM
(14%)
(86%)
(87%)
(87%)
1%
(2%)
18%
Last Year
Change
92%
(15%)
361%
(1%)
(47%)
28%
58%
95%
48%
(60%)
Last Year
Change
2%
17%
14%
12%
(1) Data has been restated to reflect the 1998 merger of Devon and Northstar and the 2000 merger of Devon and Santa Fe Snyder in accordance with the pooling-
of-interests method of accounting. The mergers of Santa Fe with Snyder Oil and Devon with PennzEnergy were recorded as purchases on May 5, 1999 and
August 17, 1999, respectively. Revenues, expenses and production in 2001 include two and one-half months attributable to the Anderson Exploration
acquisition and in 1999 include eight months activity attributable to the Snyder Oil transaction and four and one-half months activity attributable to the
PennzEnergy transaction.
Includes merger costs in 1998, 1999, 2000 and 2001 of $13 million, $17 million, $60 million and $1 million respectively.
(2)
(3) The cash dividends per share presented are not representative of the actual amounts paid by Devon on a historical basis because of mergers accounted for as
poolings. For the years 1997 through 2000, Devon's historical cash dividends per share were $0.20 in each year.
Includes preferred securities of subsidiary trust of $149 million in years 1997 and 1998.
(4) Debentures exchangeable into seven million shares of ChevronTexaco Corporation common stock beneficially owned by Devon.
(5)
(6) Gas converted to oil at the ratio of 6 Mcf:1 Bbl.
(7) Before income taxes.
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R e s e r v e s
(NET OF ROYALTIES) (MMBoe)
O i l a n d G a s P r o d u c t i o n
(NET OF ROYALTIES) (MMBoe)
A v e r a g e G a s P r i c e R e c e i v e d
($ per Mcf)
1,620
1,097
1,056
514
477
135
121
3.80
3.49
88
66
62
2.01
2.06
1.75
Drilling and acquisitions drove proved
reserves up almost 50%...
...and oil and gas production to
record levels.
Natural gas prices reached a new high...
A v e r a g e O i l P r i c e R e c e i v e d
($ per Bbl)
T o t a l R e v e n u e s
($ Millions)
C a s h M a r g i n *
($ Millions)
25.35
21.57
17.05
17.67
12.10
3,075
2,784
1,941
1,748
1,278
1,014
706
663
557
324
…while oil prices fell.
Total revenues topped $3 billion for
the first time in Devon’s histor y...
…driving our cash margin to nearly
$2 billion.
* Revenues less cash expenses
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L e t t e r t o S h a r e h o l d e r s
We have a
balanced
strategy
for
l o n g - t e r m
success .
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Dear Fellow Shareholder s
For Devon, 2001 was a year of great challenge and
achievement. Oil and gas production climbed to record
highs. Total revenues topped $3 billion, also an all-time
record. We successfully drilled over 1,400 oil and gas
wells and we completed the largest acquisition in our
history—driving oil and gas reserves to the highest levels
ever. More importantly, oil and gas reserves per share,
production per share and cash margin per share all rose
to record levels. The year was clearly one of great growth
and achievement for Devon. Yet lower oil and gas prices
at the end of 2001 led to a non-cash impairment charge
to the book value of our oil and gas properties.
As a result, net earnings for 2001 declined.
How can we make sense of all this?
J. Larry Nichols
We operate in a volatile external environ-
ment. Oil and gas prices rapidly rise and fall in
response to a myriad of psychological, meteo-
rological, political and economic forces. Our
short-term results reflect this volatility in oil
and gas prices. However, Devon has delivered
superior performance over the long run by
looking beyond short-term price trends. We
have focused our efforts on building concen-
trations of high quality oil and gas properties that can be
efficiently operated. We have strived to drill and acquire
properties that provide opportunities for future growth. We
have positioned our operations in areas with access to
strong and growing markets for our products. And we have
disposed of properties that fail to meet these criteria. In
2001, we made important progress in each of these
areas.
On August 14, 2001 we announced the first of two
major acquisitions—the purchase of Mitchell Energy. Just
three weeks later, on September 4, we announced a
second major transaction. After a year-long evaluation of
Canadian producer Anderson Exploration, we struck an
a g reement to acquire that company. Because the
Anderson acquisition was stru c t u red as an all-cash
tender, we were able to complete it very quickly. On
October 15, 2001, less than two months after the
announcement, we closed the acquisition of Anderson.
Because the Mitchell acquisition re q u i red a special
meeting of each company’s shareholders to approve the
deal, it was necessary to file a proxy with the Securities
and Exchange Commission. Following the Commission’s
review of the accounting treatment, reserve data and
compliance with other regulatory requirements related to
the two acquisitions, we held the shareholders’ meetings.
On January 24, 2002, the transaction was completed
following over whelming approval. These acquisitions
nearly doubled our proved oil and gas reserves, placing
Devon among the largest independent energy companies.
More importantly, the transactions provide Devon with an
outstanding array of internal growth opportunities.
Undertaking two major acquisitions simultaneously
was not a decision made lightly. Were it not for our exten-
sive experience in integrating major acquisitions, we
would not have had the confidence to proceed with both.
Their distinct geographic locations and tightly focused
operations made the concurrent integration of
Mitchell and Anderson possible. We dedicated
two separate integration teams to the effort.
D e v o n ’s Canadian management team in
Calgary, Alberta, is leading the integration of
Anderson. Our experienced U.S.-based team is
handling the integration of Mitchell.
The Mitchell acquisition would not have
been possible without the leadership and
support of Mitchell’s founder and CEO, George
Mitchell. Following
the acquisition, Mr.
Mitchell’s son, Todd, joined Devon’s board of
directors. We welcome the Mitchell family as Devon share-
holders and Todd Mitchell as a Devon director.
Balancing the Cost of Debt and Equity
In the acquisitions of Mitchell and Anderson, Devon
issued approximately 30 million new shares and took on
about $6.7 billion in incremental debt. Our decision to
fund the majority of the two transactions with debt rather
than equity was based in part on the relative cost of
capital. Because of the Federal Reserve’s efforts to
stimulate the U.S. economy, interest rates were at historic
lows. Further, with oil and gas prices entering a cyclical
downturn, the stock prices of independent producers were
well off their 52-week highs. This diminished the attrac-
tiveness of using Devon’s stock as acquisition currency.
We funded the cash portion of the acquisitions with
a combination of a $3 billion five-year term note and
$3 billion of 10- and 30-year debentures. Our average
interest rate on this new debt is only 5% and we have no
meaningful principal repayment obligations until 2004.
Furthermore, as of this writing, we have almost $1 billion
in cash and unused credit lines. Even though we doubled
the size of the company, we retained financial flexibility.
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Balanced for Growth
The Anderson acquisition provides Devon with an
abundance of drilling oppor tunities in the We s t e rn
Canadian Sedimentary Basin. Anderson spent decades
assembling its land positions and developing oil and gas
properties in western Canada. In recent years, Anderson
was also one of Canada’s most active acquirers of explo-
ration land and seismic data. Devon inherits that explo-
ration legacy. Over a third of our 2002 drilling and facili-
ties budget is planned for Canada, and we expect Canada
to be a major contributor to Devon’s growth far into the
future.
The Mitchell acquisition brings to Devon a major new
growth asset in north Texas, the Barnett Shale. With over
525,000 net acres in the play area, Devon has the
dominant position. We acquired 800 wells that are
producing 350 million cubic feet of gas per day. With
thousands of potential drilling locations and drilling
success rates of almost 100%, we expect the Barnett
Shale to become Devon’s fastest growing producing area.
In addition, Mitchell brings to Devon significant gas trans-
mission and processing facilities. These assets provide
us with ready access to several major natural gas markets
including the rapidly growing Dallas/Fort Worth Metroplex.
In addition to the Mitchell and Anderson acquisi-
tions, Devon added to its inventory of low-risk growth
opportunities with the launch of a significant new coalbed
methane project. The production of natural gas from
u n d e rg round coal deposits, or “coalbed methane,”
utilizes technology and expertise honed by Devon since
the 1980s. Devon’s drilling success rate approaches
100% in these low-risk gas projects. During 2001, Devon
established a dominant position in the Cherokee coalbed
methane play in Kansas and Oklahoma. We acquired over
400,000 net undeveloped acres, drilled more than 130
wells and began construction of a major gas transmission
system. We expect the Cherokee coalbed methane project
to provide Devon with a source of gas reserves and
production growth for years to come.
In addition to dramatically expanding Devon’s oil and
gas property base during 2001, we made significant
progress in bringing focus to our operations. The acquisi-
tions of PennzEnergy and Santa Fe Snyder in 1999 and
2000 brought us many assets outside North America.
Some of these assets were accompanied by drilling and
capital commitments. We said at that time that we would
honor these commitments, evaluate the results and
narrow the focus of our international operations. Our goal
was to keep a few select international areas that had
meaningful potential for a company Devon’s size. That
p rocess is nearing completion. This will leave Devon with
high-potential international assets in Azerbaijan, China and
West Africa. Also during 2001, we completed a thoro u g h
review of all of our North American assets. We identified
p ro p e rties that had high operating costs, limited gro w t h
potential or that were no longer significant to Devon. In
a g g regate, the domestic and international assets that we
have identified for sale re p resent approximately 15% of
D e v o n ’s proved oil and gas re s e r ves following the acquisi-
tion of Mitchell. The sale of these pro p e rties will leave
Devon with a high-margin oil and gas pro p e rty base with
significant growth potential. As an added benefit, we
expect to generate sales proceeds in excess of $1 billion
to be used primarily for debt repayment.
A Balanced Outlook
In my letter in last year’s annual report, I cautioned
that while the oil and gas price outlook for 2001 remained
strong, market conditions could change quickly. No one
could have known how true that warning would prove to
be. As of the writing of this letter, the natural gas price is
less than half of that just one year ago. However, when
the balance of supply and demand inevitably shifts again
in favor of the producer, Devon stands ready to reap the
rewards.
As I look ahead to the coming years I have every
reason to be optimistic about our future. The bold steps
taken during 2001 have positioned us with an oil and gas
p ro p e rty base of exceptional quality. We have an enviable
balance of low-risk development projects and high-impact
exploration opportunities. And, we have talented and
dedicated staff spanning the organization. We have the
right balance of re s o u rces to unlock for tomorrow the value
that lies within Devon today.
J. Larry Nichols
CHAIRMAN, PRESIDENT ANDCEO
March 18, 2002
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A balanced
vie w of the f u t u r e
requires l o o k i n g be yond
9
the obvious .
E X E C U T I V E Q & A
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Members of Devon(cid:213)s senior m a n a g e m e n t
a n s w e r Wall Street(cid:213)s q u e s t i o n s .
Devon appears to be shifting its resources away from acquisitions and more toward drill-bit oriented growth.
Why is that?
Larry Nichols, Chairman, President and CEO:
As Devon has grown, the likelihood of a single acquisition significantly impacting our overall operations has diminished.
At the same time, the dramatic expansion of our undeveloped property base through the Anderson and Mitchell acqui-
sitions has provided a bigger and better inventory of drilling prospects than ever before. Our acquisition of Mitchell
Energy early in 2002 brought a vast inventory of low-risk development drilling locations. The acreage that Mitchell held
in the Barnett Shale is expected to provide Devon with a source of drilling opportunities and production growth for years
to come. Anderson Exploration had a well-earned reputation as one of Canada’s most active exploration companies.
The eight million net undeveloped acres brought to Devon by Anderson includes some of the most attractive exploration
acreage in North America. Consequently, with more attractive internal growth opportunities and fewer potentially signif-
icant acquisitions, we are devoting more resources to drilling. However, we will continue to watch for the opportunity
to make value-added acquisitions when appropriate.
Devon has used oil and gas price swaps and costless collars to protect the prices on a significant portion
of its 2002 and 2003 oil and gas production. What is your hedging philosophy and has it changed?
Darryl Smette, Senior Vice President — Marketing:
Devon’s hedging philosophy has not changed. We believe that when properly used, oil and gas price hedges mitigate
risk. We have used hedging a number of times in the past to support a minimum rate of return from a specific project
or to capture value from an unsustainable spike in oil or gas prices.
Early in 2001, when gas prices were at all-time highs, we elected to take advantage of the situation and lock-in those
high prices. We protected a portion of our 2001 and 2002 gas production against a steep price decline.
While Devon’s hedging philosophy did not change, our circumstances did. In acquiring Anderson and Mitchell, we chose
to substantially increase long-term debt in a weakening oil and gas price environment. This increased the importance
of protecting a minimum level of cash flow from which to fund our capital requirements. In response, we chose to hedge
additional 2002 and 2003 volumes to provide a price floor for a larger portion of our oil and gas production. As we
entered 2002, we had hedges in place for nearly 40% of our expected 2002 gas production and for more than half of
our expected 2002 oil production. In addition, we are adding to our 2003 hedge positions as the opportunity arises.
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What is your exploration and development budget for 2002 and how do you plan to fund it?
Mike Lacey, Senior Vice President — Exploration and Production:
For 2002, we are deploying a relatively robust exploration and development budget in spite of weakening current oil
and gas prices. Our $1.3 billion exploration and development budget should allow us to participate in over 2,000 oil
and gas wells. About three-fourths of this budget will be directed toward lower-risk development projects intended to
contribute near-term production growth. By maintaining a strong production profile, we are positioning Devon to benefit
from stronger oil and gas prices when they inevitably recover. The remaining one-fourth of our capital budget, or a little
more than $300 million, will be invested in longer-term high potential projects. While these projects will not contribute
to Devon’s near-term production growth, they provide the opportunity to add significant reserves and production over
the longer term.
We expect oil and gas production to climb to record levels in 2002. This level of production and the price protection
that we have provided through hedging ensure that cash flow from operations will be our principle source of exploration
and development drilling capital. In the event the outlook for oil and gas prices improves or deteriorates significantly,
we will adjust our 2002 drilling budget commensurately.
Devon has historically carried very little debt on its balance sheet.
Why have you recently increased debt levels?
Bill Vaughn, Senior Vice President — Finance:
Devon typically maintains a very strong balance sheet. This provides ready access to capital at reasonable interest
rates allowing us to seize opportunities when they arise. Such was the case late last year when we had the chance to
simultaneously pursue the acquisitions of Mitchell Energy and Anderson Exploration. The opportunity to significantly
enhance the quality of Devon’s oil and gas property base and improve our growth profile justified the increase in indebt-
edness.
This is not the first time that we have temporarily increased our debt levels to capture an extraordinary opportunity.
When Devon acquired PennzEnergy in 1999, it was the largest acquisition in our history. Immediately after closing the
transaction, our debt relative to our size was just about the same as it is today. We quickly restored our balance sheet
by issuing new equity and requiring the conversion into equity of the convertible debt that we had outstanding. Just as
we did then, we now have a plan in place to reduce indebtedness and strengthen our balance sheet. We will accom-
plish this with the proceeds from the sale of non-core assets and cash flow generated from our oil and gas properties.
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What role do you see for the Canadian Division in Devon’s future?
John Richels, Senior Vice President — Canadian Division:
Canada re p resents an important component of Devon’s intermediate and long-term growth plans. In 1998, we estab-
lished a significant presence in Canada by merging with Nort h s t a r. Our decision was driven by the opportunities emerg i n g
in Canada. Historically, shortages of natural gas pipeline capacity from Canada to major North American gas markets
had suppressed gas prices in Canada. This discouraged additional exploration for oil and gas and the development of
the re q u i red pipeline and processing infrastru c t u re. As a consequence, many of the oil and gas prone areas of Canada
w e re under- e x p l o red relative to the U.S. However, conditions have been improving in Canada. New pipelines have been
c o n s t ructed and older ones have been expanded. As a result, Canadian natural gas prices have improved relative to
those in the U.S. Stronger relative gas prices are stimulating the development of infrastru c t u re into additional areas.
The Anderson acquisition leverages the operational expertise that we have established in Canada. The assets
strengthen our position in the major producing basins in western Canada and the Anderson staff bring a wealth of
human talent. The properties also included eight million net acres of undeveloped land, including two million net acres
in the vast, under-explored far north. This ensures that Canada will remain a significant focus area for Devon far into
the future.
In the acquisition of Mitchell Energy, you acquired significant gas transmission and processing assets.
What is Devon’s midstream strategy?
Darryl Smette:
Devon prefers to own midstream assets that support our exploration and production goals. When we produce a large
portion of the gas requiring transportation or processing in a midstream operation, we often find it desirable to both
own and operate the facilities. This allows us to control the cost of transporting and processing our gas and helps
ensure that we access the best available markets. Another benefit of owning midstream operations is the ability to add
capacity as we foresee the need. Furthermore, controlling the producing assets that support a midstream operation
reduces the risk of owning midstream assets.
In addition to moving Devon’s own gas and oil, the Marketing and Midstream Division also meets the needs of other
producers by providing reliable midstream services and market outlets for their products. Transporting and processing
natural gas for unrelated parties is an integral part of Devon’s midstream business.
Devon has acquired two large companies in the last six months. What gives you the confidence that you will
be able to integrate them successfully?
Marian Moon, Senior Vice President — Administration:
Devon has completed 10 major acquisitions since our birth as a public company in 1988. As a result, we have learned
a great deal about integrating people and operations. We have developed processes that are applied and improved
upon with each succeeding transaction. One of the first steps in a successful integration involves establishing a transi-
tion team. Our teams include employees from every functional area. The teams meet on a regular basis to discuss
transition issues, especially those that impact more than one functional area. They get to know their counterparts
within the acquired company and begin to understand how human resources, operations and management information
systems can be brought together. They are charged with selecting the best processes, systems and policies from each
organization.
Our employees are our most valuable assets, especially during the integration process. Without their creativity, flexi-
bility, energy and willingness to take on new challenges, Devon could not have successfully grown into the company we
are today.
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Devon C r e a t e s
Marketing a n d Midstream Division
13
During 2001, Devon incorporated its U.S. midstream activities
with marketing, creating a sixth operating division. The Marketing
and Midstream Division operates more than 10,000 miles of pipeline
systems and 12 natural gas processing plants. These facilities
produce approximately 72,000 bar rels per day of natural gas liquids,
or NGLs, for Devon.
The division’s responsibilities include marketing natural gas,
crude oil and NGLs. The division is also responsible for the construc -
tion and operation of pipelines, storage and treating facilities and gas
processing plants. These services are performed for Devon as well
as for unrelated parties.
One of the division’s most profitable activities is the processing
of natural gas for the extraction of NGLs. NGLs include ethane,
propane, butane and natural gasoline. Approximately 85% of all NGLs
produced in the U.S. are consumed in the petrochemical industr y, in
the manufacture of motor gasoline and for residential and commercial
heating.
Devon’s Bridgeport, Texas gas plant
processes much of the gas supplying the
growing Dallas/Fort Worth Metroplex.
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Getting the m o s t from our
oil and gas properties
demands a
b a l a n c e
o f talent
a n d technology .
P o r t f o l i o o f O i l A n d G a s P r o p e r t i e s
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P ri m a ry E x p l o ra t i o n
a n d P ro d u c t i o n A re a s
A B a l a n c e o f O p p o r t u n i t y
The acquisitions of Anderson Exploration in October 2001 and Mitchell Energy in January 2002, dramatically
expanded our portfolio of oil and gas properties. Combined, the two transactions almost doubled Devon’s proved oil
and gas reserves. The acquired properties lie almost entirely within two of Devon’s historical core operating areas: the
Permian/Mid-Continent and Canada. They enhance these positions and tighten our focus on North America. Following
the divestitures of non-core properties planned for 2002, over 95% of Devon’s oil and gas production will be from North
America.
Devon’s North American oil and gas properties are concentrated in four geographic areas. Our Canadian opera -
tions are focused in the Western Canadian Sedimentary Basin in Alberta and British Columbia. In the U.S., we are
focused on the Permian/Mid-Continent, the Rocky Mountain and Gulf regions. The company has carefully selected
these areas based on access to oil and gas markets, growth potential and overall profitability. In each of these areas
Devon is among the largest producers. This concentration has allowed us to improve our operating and capital
efficiency in each of our major areas of operations.
Today, Devon has by far the biggest and best drilling inventory in our history. This inventory provides opportuni -
ties ranging from low-risk, near-term development projects to high-impact exploration ventures. Our low-risk growth
prospects include thousands of undrilled locations within our coalbed methane and Barnett Shale projects. In addition
to these non-conventional projects, we have hundreds of low- and moderate-risk conventional drilling opportunities
spanning all of our North American core areas. While the majority of our 2002 capital budget is devoted to these low-
and moderate-risk projects, we also have meaningful exposure to potential reserve additions through exploration.
These exploration opportunities range from the Mackenzie Delta of Canada’s far north to the deepwater offshore West
Africa. The following pages contain additional information about our areas of operations and our plans for 2002.
P r o p e r t i e s i n t h e U . S .
Rocky Mountain Division
The Rocky Mountain Division includes Devon’s
properties in Wyoming, Utah, Colorado and northern New
Mexico. While our 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, we have drilled almost
1,400 wells. We 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 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.
Permian/Mid-Continent Division
D e v o n ’s Permian/Mid-Continent Division includes
p o r tions of New Mexico, Texas, Oklahoma, Kansas,
Mississippi and Louisiana. This area encompasses a wide
continued on page 18
6994pg01_23_26mar02 6/21/04 11:23 AM Page 17
17
N O R T H A M E R I C A
Canada
Rocky Mountains
Permian/Mid-Continent
Gulf
I N T E R N AT I O N A L
Azerbaijan
China
West Africa
6994pg01_23_26mar02 6/21/04 11:23 AM Page 18
18
Rig hands conduct drilling
operations on a Devon
natural gas well. We plan
to drill over 2,000 wells
in 2002.
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. Our Permian/Mid-Continent produc-
tion has historically come from conventional oil and gas
properties. However, we recently established dominant
positions in two non-conventional gas plays in the
P e rmian/Mid-Continent: the Barnett Shale and the
Cherokee coalbed methane project.
The most significant asset brought to Devon in our
recent acquisition of Mitchell Energy was our 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. Our average working
interest is approximately 95%. The Barnett Shale is a
unique, unconventional gas re s o u rce
that off e r s
immediate low-risk production growth and the potential for
significant reserve additions.
The key to unlocking the gas trapped within the tight
shale is a recently perfected 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. Refrac-
tured wells often exceed their original flow rates, even
after years of production. In spite of recent improvements
in fracture technology, we currently recover less than 10%
of the gas in place. Further technological improvements
could unlock additional potential in the future.
In 2002, we plan to drill 300 new Barnett Shale
wells and refracture 144 wells. We also plan to drill eight
exploratory wells outside the core development area with
the hope of expanding the productive area. The potential
to expand the play outside the core area, to drill increased
density wells, to refracture existing wells and to recover
additional gas with improved technology all offer tremen-
dous upside potential. 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, gas produc-
tion increases as the water is removed from the reservoir
and the gas trapped within the coal is released.
During the first half of 2001, we acquired over
400,000 net acres within the Cherokee area of southeast
Kansas and northeast Oklahoma. We 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
f u r ther refine completion techniques. Aggregate gas
p roduction should begin to reach significant levels in the
second half of 2002 as drilling and de-watering pro g ress. If
the wells in this project perf o rm as we believe they will, we
expect to ultimately drill more than 1,000 wells in the play.
6994pg01_23_26mar02 6/21/04 11:23 AM Page 19
19
Mobile water tanks line up
in preparation for a fractur e
treatment. This process is
the key to unlocking the
gas potential of the Barnett
Shale in north Texas.
exploration exposure in the deepwater to participation in
a few wells each year. Furthermore, we generally share
the risk of deepwater exploration wells with industry
partners. One of the deepwater exploration wells we plan
to drill in 2002 will assess one of the largest untested
structures in the Gulf. The Cortes Prospect lies in 3,300
feet of water and covers most of four 5,000-acre blocks
in the Port Isabel area. The gross reserve potential of this
18,000 foot deep prospect exceeds one trillion cubic feet
of gas. Devon has a 25% working interest in Cortes.
Another of our 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 feet of water. Produc-
tion 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 feet of water.
Devon’s share of production is expected to exceed
10,000 barrels of oil per day.
A further source of oil and gas reserves and produc-
tion 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, we drilled five successful exploration
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.
Gulf Division
Devon
The Gulf Division manages our 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 pre s e n t
challenges to Gulf operators. Devon has responded to
those challenges by continually utilizing technological
advances in the search for new reserves.
is applying
four-component seismic
technology to identify prospects on large tracts of our
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 our geoscientists to more accurately
picture these unexplored formations. We have conducted
two large 4C seismic surveys offshore Louisiana. In early
2002, we began drilling and have achieved early success
on prospects resulting from a 300 square mile 4C survey
in the West Cameron area. We are currently interpreting
the results of our 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 undis-
covered oil and gas reserves in North America. Because
deepwater exploration is capital intensive, Devon’s
strategy is to move cautiously. Our main focus is on
prospects in water depths for which infrastructure and
production technology are well established. We limit our
6994pg01_23_26mar02 6/21/04 11:23 AM Page 20
20
One of the highest potential exploration assets we
acquired from Anderson was its 1.5 million net acres in
Canada’s most prospective exploratory region, the far
north. Our 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.
I n t e r n a t i o n a l P r o p e r t i e s
D e v o n ’s assets outside Nor th America were
acquired in the PennzEnergy and Santa Fe transactions.
Since acquiring these properties, we have critically evalu-
ated each one and have 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, we now are 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 multibil-
lion barrel oil field 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. Devel-
opment of our Panyu Project is underway and we expect
first oil production from two offshore platforms in late
2003. We expect Devon’s share of production to approxi-
mate 15,000 barrels per day.
Our 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, we plan to drill a test well on our
Rita Prospect located offshore Congo.
P r o p e r t i e s i n C a n a d a
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. We sought to expand our presence in
Canada because we believe that many of its oil and gas-
p rone areas are underdeveloped or undere x p l o re d .
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 British Columbia border. 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 is now a
leading Deep Basin operator and holds over 800,000 net
acres. Furthermore, the profitability of our operations is
enhanced by ownership in nine major gas processing
plants in the area.
During 2002, we plan to drill about 85 wells in the
Deep Basin. Reserve targets range in size from five to 15
billion cubic feet of gas. 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.
In 2003, Devon plans to bring several previous deep
gas discoveries on stream in the Grizzly Valley area of the
Foothills of northeastern British Columbia. Since our
initial discovery here in 1998, Devon has drilled 11
successful wells. We expect to commence initial produc-
tion at a combined rate of about 50 million cubic feet of
gas per day to Devon.
The Anderson acquisition significantly increased our
holdings in the Foothills. We have 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 reser-
voirs in this area, Anderson had achieved considerable
success in drilling for shallower formations. The Anderson
acquisition affords us the opportunity to extend that
c o m p a n y ’s shallow gas development onto Devon’s
acreage and to apply Devon’s deep gas exploration exper-
tise to the Anderson acreage.
6994pg01_23_26mar02 6/21/04 11:23 AM Page 21
21
N o r t h o f 60ß
North of 60˚ refers to the area of Canada north of the 60 degree
line of latitude.
It includes the Yukon Territor y, the Northwest Territories
and Nunavut. The Geological Survey of Canada estimates that the area
contains 65 trillion cubic feet of natural gas and seven billion bar
rels of
oil. Much of that potential lies in the Mackenzie Delta and under the
shallow waters of the Beaufort Sea.
Devon’s 2001 acquisition of Anderson Exploration established the
company as the largest holder of exploration licenses and concession
acreage in the Mackenzie Delta and Beaufort Sea regions.
This
exploratory acreage could provide Devon with oil and gas production
and reserve growth opportunities well into the future.
6994pg01_23_26mar02 6/21/04 11:56 AM Page 22
22
O P E R A T I N G S TAT I S T I C S B Y A R E A
Producing Wells at Year–End
2001 Production (Net of Royalties)
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Total (MMBoe)(1)
Average Prices
Oil Price (Per Bbl)
Gas Price (Per Mcf)
NGLs Price (Per Bbl)
Year–End Reserves (Net of Royalties)
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Total (MMBoe)(1)
P E R M I A N
M I D –
C O N T I N E N T
T O T A L
P E R M I A N /
M I D – C O N T I N E N T
R O C K Y
M O U N T A I N S
O N S H O R E
G U L F
O F F S H O R E
G U L F
8,437
3,707
12,144
3,742
1,098
850
11
67
2
24
2
55
2
13
13
122
4
37
$ 21.09
$
3.83
$ 16.77
23.29
4.26
17.63
21.34
4.02
17.24
117
346
15
189
9
562
18
121
126
908
33
310
2
112
1
22
24.64
3.72
17.32
24
1,114
9
219
1
24
–
5
10
118
1
31
22.49
4.10
2.88
23.12
4.78
16.73
4
102
2
23
37
275
8
91
Year–End Present Value of Reserves (Millions)(2)
Before Income Tax
After Income Tax
$
$
Year–End Leasehold (Net Acres in Thousands)
960
659
1,619
859
153
639
Producing
Undeveloped
Wells Drilled During 2001
2001 Exploration, Development
& Facilities Expenditures (Millions)(3)
Estimated 2002 Exploration, Development
& Facilities Expenditures (Millions)(4)
383
566
198
432
986
204
815
1,552
308
1,374
402
634
220
55
54
333
579
55
$
283
164
447
187
123
293
T O T A L
G U L F
1,948
11
142
1
36
23.06
4.67
16.87
41
377
10
114
792
553
634
109
416
$ 25 – 30 360 – 410
385 – 440
65 – 75
85 – 95
140 – 165
225 – 260
(1) Gas converted to oil at the ratio of 6 Mcf:1 Bbl.
(2) Estimated future revenue to be generated from the production of proved reserves, net of estimated future production and development costs, discounted at 10%.
(3) Excludes $31 million for construction of gas transmission systems.
(4) Excludes $135 to $165 million expected to be spent on gas services assets. Does not include the cost to acquire Mitchell Energy.
E L E V E N Y E A R P R O P E R T Y D A T A ( 1 )
Reserves (net of royalties)
Oil (MMBbls)
Gas (Bcf)
Natural Gas Liquids (MMBbls)
Total (MMBoe) (2)
10% Present Value (Millions) (3)
Production (net of royalties)
Oil (MMBbls)
Gas (Bcf)
Natural Gas Liquids (MMBbls)
Total (MMBoe) (2)
Average Prices
Oil (Per Bbl)
Gas (Per Mcf)
Natural Gas Liquids (Per Bbl)
Oil, Gas and Natural Gas Liquids (Per Boe) (2)
Production and Operating Expense per Boe (2)
199 1
199 2
199 3
199 4
199 5
236
410
4
308
812
22
52
–
31
16.04
1.41
16.39
13.93
5.86
$
$
$
$
$
$
280
645
7
394
1,376
26
80
1
40
14.94
1.63
12.57
13.18
5.35
274
736
7
404
1,098
30
106
1
49
13.12
1.77
11.75
12.18
5.04
312
782
12
454
1,561
30
101
1
48
13.12
1.69
10.41
12.00
4.95
334
895
16
499
1,986
31
113
1
51
15.14
1.43
10.06
12.58
4.85
(1) Data has been restated to reflect the 1998 merger of Devon and Northstar and the 2000 merger of Devon and Santa Fe Snyder in accordance with the pooling–of–interests method of accounting.
(2) Gas converted to oil at the ratio of 6 Mcf:1Bbl.
(3) Before income taxes.
199 6
375
1,158
19
587
4,095
33
123
2
56
17.62
1.79
13.97
14.95
5.31
6994pg01_23_26mar02 6/21/04 11:56 AM Page 23
T O T A L
G U L F
TOTAL
U . S .
C A N A D A
I N T E R N A T I O N A L
T O T A L
C O M P A N Y
1,948
17,834
13,997
1,468
33,299
2 0 0 2 E X P L O R A T I O N , D E V E L O P M E N T
& F A C I L I T I E S B U D G E T
23
11
142
1
36
23.06
4.67
16.87
41
377
10
114
792
553
634
109
26
376
6
95
22.36
4.17
17.15
191
2,399
52
643
3,270
2,801
1,676
3,560
1,145
8
113
2
29
17.84
2.73
16.43
166
2,625
56
659
10
9
–
11
22.57
1.41
16.15
229
453
13
318
2,744
1,596
1,160
917
44
498
8
135
21.57
3.80
16.98
586
5,477
121
1,620
7,174
5,314
2,486
10,233
209
7,838
4,371
21,631
292
108
1,545
416
1,050
318
149
1,517
P R O V E D O I L & G A S R E S E R V E S
B Y D I V I S I O N
O F F S H O R E
G U L F
850
10
118
1
31
23.12
4.78
16.73
37
275
8
91
639
333
579
55
293
– 165
225 – 260 675 – 775
420 – 500 65 – 105 1,160 – 1,380
199 5
334
895
16
499
1,986
31
113
1
51
15.14
1.43
10.06
12.58
4.85
accounting.
199 6
199 7
19 9 8
19 9 9
20 0 0
20 0 1
5–YEAR COMPOUND
GROWTH RATE
10–YEAR COMPOUND
GROWTH RATE
375
1,158
19
587
4,095
33
123
2
56
17.62
1.79
13.97
14.95
5.31
219
1,403
24
477
2,100
32
186
3
66
17.05
2.01
12.61
14.54
4.78
235
1,477
33
514
1,528
26
198
3
62
12.10
1.75
8.09
11.05
4.45
496
2,950
68
1,056
5,812
32
304
5
88
17.67
2.06
13.30
14.35
4.31
459
3,458
62
1,097
17,737
43
426
7
121
25.35
3.49
20.87
22.47
4.94
586
5,477
121
1,620
7,174
44
498
8
135
21.57
3.80
16.98
22.05
5.41
9%
36%
45%
23%
12%
6%
32%
32%
19%
4%
16%
4%
8%
–
10%
30%
41%
18%
24%
7%
25%
NM
16%
3%
10%
–
5%
(1%)
6994pg24_28_26mar02 6/21/04 11:31 AM Page 1
24
K E Y P R O P E R T Y H I G H L I G H T S
WYOMING
A
B
C
UTAH
ARIZONA
COLORADO
D
E
NEW MEXICO
Rocky Mountains
A
Powder River Coalbed Methane
Profile
• 200,000 net undeveloped and 50,000 net
developed acres in northeastern Wyoming.
• Initial position obtained in 1992 acquisition.
• Produces coalbed methane from the Fort Union
Coal formations at 300’ to 2,000’.
• 25.7 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled 435 coalbed methane wells (279
wells awaiting connection to pipeline system
at year-end).
• Connected 340 wells to gas sales.
• More than doubled annual net production.
• Acquired 8,000 net acres of Big George
coal seam acreage.
• First gas sales from a Big George pilot.
2002 Plans
• Connect remaining wells drilled in 2001 to
pipeline system.
• Drill 200 to 250 additional coalbed
methane wells.
• Expand infrastructure in the Pine Tree and
House Creek pilot areas.
• Establish gas sales from additional
Big George pilots.
B
Washakie
Profile
• 70% working interest in 228,000 acres in
southern Wyoming.
• Obtained in 2000 acquisition.
• Produces gas from multiple formations at
6,800’ to 10,300’.
• 61.5 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled and completed 21 gas wells.
• Executed successful recompletion program.
2002 Plans
• Drill and complete 3 gas wells.
• Conduct additional drilling and recompletion
operations as justified by market conditions.
C
Bluebell/Altamont
Profile
• 93% working interest in 37,000 acres in
northeast Utah.
• Obtained in 1999 acquisition.
• Produces premium priced yellow crude oil from
the Wasatch formation at 8,000’ to 15,000’.
• Developing oil potential in lower Green River
formation and gas potential in upper
Green River formation.
• 11.9 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled and completed 5 wells.
• Performed 23 recompletions.
2002 Plans
• Identify additional recompletion opportunities
and infill drilling locations.
• Resume drilling and recompletion activities
as justified by market conditions.
D
NEBU/32-9 Units
Profile
• 25% working interest in 50,000 acres in the
San Juan Basin of northwestern New Mexico.
• Initially developed in the late 1980s and
early 1990s.
• Includes 168 coalbed methane wells.
• Produces primarily coalbed methane from
the Fruitland Coal formation at 3,000’.
• 27.2 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Recavitated 16 wells.
• Installed wellhead compression.
• Installed 33 pumping units for water removal.
• Drilled and completed 4 conventional
Mesaverde/Dakota gas wells.
2002 Plans
• Drill and complete up to 20 conventional
Mesaverde/Dakota gas wells (pending partner
approval).
• Recavitate up to 23 wells.
E
Vermejo Park Ranch
Profile
• Located on the Colorado/New Mexico border in
the Raton Basin.
• Initial 25% working interest plus 25% royalty
interest in 280,000 prospective coalbed
methane acres.
• Working interest increases to 50% after
meeting economic hurdles.
• Obtained in 1999 acquistion.
• Produces coalbed methane from the Vermejo
and Raton Coal formations at 1,000’ to 2,300’.
• 30.5 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled and completed 103 of 104 coalbed
methane wells.
• Drilled 5 core holes and 4 stratigraphic test
wells to further delineate formation.
• Installed 26 pumping units for water removal.
• Restimulated 10 wells.
• Expanded production infrastru c t u re .
2002 Plans
• Drill and complete 108 coalbed methane wells.
• Expand water disposal facilities including the
drilling of 1 water disposal well and
deepening another.
• Install additional pumping units for water re m o v a l .
• Drill 2 conventional test wells.
• Further expand field infrastructure.
NM
B
KANSAS
A
OKLAHOMA
C
D
TEXAS
AR
LA
MS
Permian/Mid-Continent
A
Cherokee Coalbed Methane
Profile
• 400,000 net acres in southeast Kansas and
n o rtheast Oklahoma.
• 100% working interest.
• Initiated in 2001.
• Produces coalbed methane from multiple coal
seams at 600’ to 1,100’.
• Access to major gas pipelines.
• 18.1 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled 131 and completed 51 coalbed methane wells.
• Initiated construction of gas pipeline system
in Kansas.
• Acquired additional acreage.
2002 Plans
• Complete wells drilled in 2001.
• Drill 200 additional coalbed methane wells.
• Drill 9 salt-water disposal wells.
• Recomplete 29 wells.
• Complete construction of pipeline system.
B
Southeast New Mexico
Profile
• 358,000 net acres in southeast New Mexico.
• 60% average working interest.
• Key fields include Indian Basin, Catclaw Draw
and Outland/Gaucho.
• Produces oil and gas from multiple formations
at 2,000’ to 17,000’.
• 56.1 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Acquired 113,000 net acres.
• Drilled and completed 100 wells.
2002 Plans
• Drill up to 40 wells as justified by market conditions.
C
Barnett Shale
Profile
• 525,000 net acres in the Fort Worth Basin of
north Texas.
• 95% average working interest.
• Obtained in 2002 acquisition.
• Produces gas from the Barnett Shale formation
at 6,500’ to 8,500’.
• 800 wells producing 345 MMCFD.
• Approximately 300 million bar rels of
oil equivalent reserves at 1/24/02.
6994pg24_28_26mar02 6/21/04 11:31 AM Page 3
2002 Plans
• Drill and complete 300 gas wells.
• Refracture 144 wells.
• Continue pilot projects outside core area.
• Acquire additional seismic and acreage.
D
Carthage/Bethany Area
Profile
• 65% to 85% working interest in 77,000 acres
located in east Texas.
• Obtained in 1999 acquisition.
• Produces from the Cotton Valley, Travis Peak
and Pettit formations at 5,800’ to 9,500’.
• Includes 550 producing wells.
• 59.4 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled and completed 46 wells.
• P e rf o rmed 17 well recompletion/workover pro g r a m .
2002 Plans
• Complete 5 wells drilling in late 2001.
• Drill 19 wells.
• Continue recompletion/workover program.
25
• Located offshore Texas in 440’ of water.
• Produces primarily gas from sands at depths
of 4,000 to 12,000’.
• 6.1 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled 3 additional wells following the 2000
Cyrus discover y.
• Initiated construction on a new production
platform.
2002 Plans
• Complete construction and installation of
production facilities.
• Complete pipeline construction.
• Complete 4 wells and commence oil and gas
production in the second half of 2002.
MS
C
D
F
B
A
TEXAS
LOUISIANA
E
GULF
OF MEXICO
C
West Cameron 4C Area
Gulf – Deepwater
Profile
• Includes 17 offshore blocks where Devon is
applying 4 component (4C) seismic technology.
2001 Activity
• Acquired 1 additional lease block.
• Evaluated 300 square mile 4C survey.
• Identified 4 drilling opportunities.
2002 Plans/Activity
• Drilled successful well on West Cameron 536
TEXAS
LOUISIANA
(100% WI) in Q1.
• Initiate drilling of 3 additional wells.
• Evaluate additional prospects.
E
B
C
A
FD
GULF
OF MEXICO
D
Eugene Island 330 Area
Profile
• Includes 100% working interest in Eugene Island
blocks 316 and 329, 98% in Eugene Island
block 337, 50% in the south half of block 315
and 23% in block 330.
• Obtained in 1999 acquisition.
• Located offshore Louisiana in 250’ of water.
• Produces oil and gas from sands at 1,200’
to 9,000’.
A
Green Canyon Complex
Profile
• 48% working interest in Green Canyon 112 & 113
(Angus Field).
• 48% working interest in Green Canyon 155
(Manatee Field).
• Obtained in 2000 acquisition.
• 16.8 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Produced and monitored Angus.
• Evaluated possible T sand for sidetrack at Angus.
• Drilled 1 well at Manatee.
• Completed design of sub-sea system at Manatee.
2002 Plans
• Complete sub-sea development at Manatee.
• First production expected in late 2002.
B
Mississippi Canyon 661
Profile
• 25% working interest in Mississippi Canyon 661
Gulf – Shelf
A
South Marsh Island 23 Area
Profile
• 100% working interest in Eugene Island block 156;
South Marsh Island blocks 22, 23, 34, 47, 48;
50% working interest in South Marsh Island
blocks 21 and 32.
• Obtained in 1999 acquisition.
• Located offshore Louisiana in 100’ of water.
• 19 wells producing from the lower Pliocene/upper
Miocene formations at 3,900’ to 15,000’.
• 5.1 million bar rels of oil equivalent reserves at
12/31/01.
2001 Activity
• Drilled and completed 1 well.
• Performed 2 recompletes/workovers.
• Installed compression at South Marsh Island
23G and 48B.
2002 Plans
• Recomplete 4 wells.
• Interpret pulsed neutron logs.
• Continue well workover program.
• Reprocess and interpret 3D seismic.
• Develop drilling plans in the area.
B
High Island 582
Profile
• 37% working interest.
• Obtained in 1999 acquisition.
• 4.6 million barrels of oil equivalent reserves
(Firebird).
at 12/31/01.
2001 Activity
• Drilled and completed 5 wells at
Eugene Island 330.
• Obtained in 2000 acquisition.
• Located offshore Louisiana in 850’ of water.
• Produces oil and gas from multiple Pliocene
sands at 10,500’.
• 2.1 million barrels of oil equivalent reserves
• Performed 4 recompletes/workovers at
at 12/31/01.
Eugene Island 330.
• Drilled and completed 2 wells at
Eugene Island 337.
2002 Plans
• Drill and complete 3 wells.
• Perform 4 recompletes/workovers.
2001 Activity
• Drilled and completed 1 well.
• Brought Firebird on to production.
2002 Plans
• Produce and monitor.
Shelf Exploration Prospects
C
Mississippi Canyon 110
Grays
Profile
E
• Galveston 424
• Located offshore Texas in 100’ of water.
• Target formation: Miocene sands at 10,000’
to 15,000’.
• Net unrisked reserve potential: 6 MMBoe.
F
Thunder
• Eugene Island 342
• Located offshore Louisiana in 270’ of water.
• Target formation: Miocene Sub-Salt at 15,000’
to 18,000’.
• Net unrisked reserve potential: 6 MMBoe.
• Drill to earn interest in 5 additional blocks.
2002 Plans
• Finalize geophysical analysis.
• Bring in industry partners.
• Drill exploratory test wells.
Profile
• 25% working interest in Mississippi
Canyon 110 (Orion).
• Obtained in 2000 acquisition.
• Located offshore Louisiana in 1,200’ of water.
• Produces oil and gas from multiple Pliocene
sands at 6,000’ to 7,000’.
• 2.1 million bar rels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled and completed 1 well.
2002 Plans
• Commence limited production in Q1.
• Full production expected in Q3 pending
completion of compression facilities.
6994pg24_28_26mar02 6/21/04 11:31 AM Page 4
D
Viosca Knoll 738 & 739
B
Patterson Field
Profile
• 47% average working interest in Viosca Knoll
blocks 738 & 739 (Pecten/Maria).
• Located offshore Mississippi in 600’ to 900’
of water.
• Obtained in 2000 acquisition.
• 2.4 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Brought Pecten discovery well on production
in Q1.
• Brought Maria field on to production.
2002 Plans
• Produce and monitor.
Deepwater Exploration Prospects
Cortes
Profile
E
• Port Isabel 175
• Located offshore Texas in 3,300’ of water.
• Target formation: Oligocene Frio sands at
15,000’ to 18,000’.
• 25% working interest.
• Net unrisked reserve potential: 40 MMBoe.
Tuscany East
F
• Desoto Canyon 180/224
• Located offshore Louisiana 6,700’ of water.
• Target formation: Middle Miocene sands
at 13,500’ to 14,000’.
• 25% working interest.
• Net unrisked reserve potential: 33 MMBoe.
2002 Plans
• Finalize geophysical analysis.
• Drill exploratory test wells.
TEXAS
A
MS
LA
B
GULF
OF MEXICO
Gulf – Onshore
A
South Texas
Profile
• Up to 100% working interest in 449,000 acre s .
• Obtained in 1999 acquisition.
• Key areas include Zapata, Agua Dulce/
N. Brayton, Refugio and Pettus/Ray Ranch.
• Produces oil and gas from the Edwards, Wilcox
and Frio/Vi c k s b u rg trends at 1,500’ to 14,000’.
• 18 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled and completed 32 development wells.
• Drilled and completed 5 exploratory wells.
• Acquired additional acreage.
2002 Plans
• Drill 40 development wells.
• Drill 5 exploratory wells.
Profile
• 50% working interest in 5,000 acres in
southern Louisiana.
• Obtained in 1999 acquisition.
• Produces oil and gas from Miocene sands at
10,000’ to 19,000’.
• 1.2 million bar rels of oil equivalent reserves at
12/31/01.
2001 Activity
• Drilled and completed 1 well.
2002 Plans/Activity
• Drilled successful exploratory well in Q1.
• Drill 2 additional exploratory wells.
• Evaluate additional prospects.
A
BRITISH
COLUMBIA
B
D
F
E
C
G
F
Canada
(Includes Anderson’s activity for the
full year 2001)
26
2001 Activity
• Drilled and completed 5 Slave Point wells.
• Performed 6 3D seismic surveys.
• Secured pipeline capacity at Ladyfern.
2002 Plans
• Drill 8 exploratory Slave Point wells,
5 at Ladyfern.
• Shoot additional 3D seismic.
• Initiate infrastructure construction at Ladyfern.
C
N. Alberta Shallow Gas
Profile
• 73% average working interest in 3.8 million acres
in north central Alberta.
• Key areas include Springburn, Leismer/Kirby,
Cherpeta, Goodfish, Gift, Dawson, Marten Hills
and Woodenhouse.
• Primarily winter-only drilling.
• Produces shallow gas from multiple formations
at 1,000’ to 2,500’.
• Produces oil and gas from Devonian formations
at 6,000’ to 8,000’.
• 74.7 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Drilled and completed 180 of 220 shallow gas
wells in winter program.
• Drilled and completed 12 of 15 oil and gas wells
in summer program.
• Drilled and completed 15 of 17 Devonian oil wells.
• Expanded compression and dehydration facilities
at Hangingstone, Springburn, West Surmont
and Goodfish.
2002 Plans
• Drill 96 shallow gas wells.
• Drill 8 Devonian oil wells.
• Expand gas processing facilities at Goodfish.
A
Mackenzie Delta
D
Peace River Arch
Profile
• 46% working interest in 3.2 million exploratory
acres in the Mackenzie Delta and shallow waters
of the Beaufort Sea.
• Largest holder of exploration acreage in this area.
• Drilling limited to winter only.
2001 Activity
• Acquired acreage position through
Anderson acquisition.
• Conducted 275 square mile onshore 3D
seismic survey.
• Conducted 625 square mile offshore 3D
seismic survey.
• Drilled and suspended KURK M15 well.
• Participated in export pipeline discussions
with other operators.
2002 Plans
• Complete and test KURK M15 well.
• Drill 3 additional exploratory wells.
• Evaluate offshore seismic and pursue
farm-out opportunities.
• Continue export pipeline discussions.
B
Slave Point
Profile
• 63% average working interest in 300,000 acres
in northwestern Alberta and northeastern
British Columbia.
• Key areas include Hamburg, Chinchaga, Ladyfern
and Wildmint.
• Drilling is primarily winter-only access.
• Produces liquid-rich gas from the Slave Point
formation at 8,000’ to 10,000’.
• Gas processing plants at Chinchaga (100%
interest) and at Hamburg (60% interest).
• 6 million barrels of oil equivalent reserves
at 12/31/01.
Profile
• 76% average working interest in 1.6 million acres
in western Alberta.
• Key areas include Girouxville, Dunvegan and
Pouce Coupe.
• Produces liquids-rich gas and light gravity oil from
multiple formations.
• 110.7 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Acquired 778,000 net undeveloped acres through
the Anderson acquisition.
• Drilled and completed 126 wells.
• Significant discoveries made at Girouxville and
Pouce Coupe.
• Completed construction of Rycroft sour gas plant
(Devon WI 45%).
2002 Plans
• Drill 76 wells.
• Construct 5,000 BOD oil battery at Girouxville.
• Continue 3D seismic evaluation at Pouce Coupe.
E
Deep Basin
Profile
• 48% average working interest in 1.8 million
acres in western Alberta.
• Key areas include Wapiti, Elmworth, Bilbo
and Hiding.
• Produces liquids rich gas from Cretaceous and
Devonian formations at 3,000’ to 13,500’.
• 79.6 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Acquired acreage position through Anderson
acquisition.
6994pg24_28_26mar02 6/21/04 11:31 AM Page 5
• Drilled and completed 119 wells.
• Discoveries at Hiding.
• Significant field extensions at Wapiti, Bilbo
and Elmworth.
2002 Plans
• Drill 85 wells.
• Complete construction of the Elmworth pipeline
and associated facilities.
• Add additional compression at Bilbo.
• Continue field development at Wapiti, Bilbo
and Elmworth.
F
Foothills
Profile
• 52% working interest in 1.2 million acres in
western Alberta and eastern British Columbia.
• Key exploratory areas include Grizzly Valley in
northeastern British Columbia and Narraway,
Cabin Creek and Findley in west central Alberta.
• High-impact, long-lived reserves.
• Produces gas from multiple formations at 4,000’
to 15,000’.
• 84.7 million barrels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Acquired 350,000 net undeveloped acres
through the Anderson acquisition.
• Drilled and completed 5 exploratory wells in
the Grizzly Valley area.
• Drilled and completed 21 wells in the Narraway,
Cabin Creek and Findley areas.
• Completed construction of 134 MMCFD gas
facility at Narraway (Devon WI 42%).
2002 Plans
• Continue drilling 2 exploratory wells initiated in
2001 in Grizzly Valley.
• Drill 4 additional exploratory wells in the
Grizzly Valley area.
• Drill 11 wells in the Narraway, Cabin Creek
and Findley areas.
G
Heavy Oil
Profile
• 81% average working interest in 1 million acres
primarily in northeastern Alberta.
• Key areas include Manatokan, Lloydminster,
Surmont, Trout, Dover and Jackfish.
• Acreage contains prospects suitable for both
conventional and thermal recovery.
• 47 million barrels of conventional and 5 million
barrels of thermal reserves at 12/31/01.
2001 Activity
• Drilled and completed 51 of 57 conventional
heavy oil wells.
• Drilled 81 delineation wells at Surmont, Trout
and Jackfish.
• Converted royalty interest to 13% working
interest at Surmont.
2002 Plans
• Drill 50 conventional heavy oil wells.
• Drill 83 delineation wells at Surmont, Trout
and Jackfish.
27
B
A
C
International
A
Azerbaijan
C
Offshore West Africa
Profile
• 5.6% carried interest in 137,000 acres in the
Profile
• 4 licensed offshore blocks include:
Keta block offshore Ghana,
Agali and Kowe blocks offshore Gabon,
Marine IX block offshore Congo.
• Obtained in 2000 acquisition.
• Interest in 6 oil producing wells on the
Kowe block.
• 6.5 million bar rels of oil equivalent reserves
at 12/31/01.
2001 Activity
• Acquired 3D seismic data.
• Identified drilling locations for 2002
exploratory wells.
• Secured farmout agreement with partner to
participate in Keta block and pay for 3D
seismic program.
2002 Plans
• Drill exploration well on Marine IX block.
• Finalize plans for Agali well to be drilled in
early 2003.
Azeri-Chirag-Gunashli (ACG) oil fields
offshore Azerbaijan.
• Obtained in 1999 acquisition.
• Oil is exported by pipeline to the west and
north.
• Operating and capital cost currently paid by
partners under carried interest agreement.
• Anticipate significant production and revenue
to Devon commencing in 2005 to 2010.
• 145.8 million barrels of oil equivalent
reserves at 12/31/01.
2001 Activity
• Purchased 0.8% additional carried interest.
• Approved the first of 3 field development
phases.
2002 Plans
• Continue drilling of 4 extended reach wells on
the Chirag 1 platform.
• Convert 3 additional wells to injector wells.
• Begin construction on phase 1 development.
• Receive approval for the Main Export Pipeline
from Baku to Ceyhan, Turkey.
B
China
Profile
• 4 licensed blocks in the Pearl River
Mouth Basin offshore China.
• Obtained in 2000 acquisition.
• Anticipate first oil production in 2003.
• 18.4 million bar rels of oil equivalent
reserves at 12/31/01.
2001 Activity
• Received approval for development
program for Panyu project.
• Initiated fabrication of Panyu facilities.
2002 Plans
• Continue with construction of
Panyu facilities.
6994pg24_28_26mar02 6/21/04 11:31 AM Page 6
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 29
F I N A N C I A L S T A T E M E N T S A N D M A N A G E M E N T ’ S
D I S C U S S I O N & A N A L Y S I S
29
We
strive for the
h i g h e s t standards in
f i n a n c i a l
reporting.
30
32
53
53
54
55
56
57
58
Selected Eleven-Year Financial Data
Management’s Discussion & Analysis of Financial Condition and Results of Operations
Management’s Responsibility for Financial Statements
Independent Auditors’ Repor t
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
CAPITAL EXPENDITURES FOR
EXPLORATION AND DEVELOPMENT
($ MILLIONS)
TOTAL ASSETS
($ MILLIONS)
1,400
1,000
700
350
0
1,334
849
14,000
10,500
7,500
13,184
6,860
6,096
448 470 494
3,500
1 , 9 6 5 1 , 9 3 1
‘97
‘98
‘99
‘00
‘01
‘97
‘98
‘99
‘00
‘01
0
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 30
30
S E L E C T E D E L E V E N - Y E A R F I N A N C I A L D A T A
OPERATING RESULTS (IN MILLIONS, EXCEPT PER SHARE DATA)
Revenues (net of royalties):
Oil sales
Gas sales
Natural gas liquids sales
Other revenue
Total revenues
Production and operating expenses
Depreciation, depletion and amortization of
property and equipment
Amortization of goodwill (1)
General and administrative expenses
Expenses related to mergers
Interest expense (2)
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Reduction of carr ying value of oil and gas properties
Income tax expense (benefit)
Total expenses
Net earnings (loss) before minority interest, extraordinary
item and cumulative effect of change in accounting principle (3)
Net earnings (loss)
Preferred stock dividends
Net earnings (loss) to common shareholders
Net earnings (loss) per common share - basic
Net earnings (loss) per common share - diluted
Cash margin (4)
Weighted average shares outstanding - basic
Weighted average shares outstanding - diluted
BALANCE SHEET DATA (IN MILLIONS)
Total assets
Debentures exchangeable into shares of
ChevronTexaco Corporation common stock (5)
Other long-term debt (6)
Deferred income taxes
Stockholders' equity
Common shares outstanding
1991
1992
1993
1994
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
351
73
5
19
448
181
103
–
37
–
46
–
–
238
(52)
553
(105)
(105)
2
(107)
(3.66)
(3.66)
171
29
29
392
131
8
13
544
216
150
–
43
–
57
–
–
66
1
533
11
11
6
5
0.14
0.13
220
39
42
391
189
13
31
624
245
174
–
50
11
47
–
–
216
(65)
678
(54)
(55)
7
(62)
(1.27)
(1.27)
270
49
49
394
171
13
16
594
238
155
–
45
7
33
–
–
29
33
540
54
54
11
43
0.84
0.84
276
51
54
885
1,464
1,336
1,475
–
473
42
203
30
–
571
52
503
48
–
508
–
472
49
–
457
30
688
52
(1)
(2)
(3)
Amortization of goodwill in 1999, 2000 and 2001 resulted from Devon’s 1999 acquisition of PennzEnergy. Effective January 1, 2002, goodwill will no longer be amortized.
Includes distributions on prefer red securities of subsidiary trust of $5, $10, $10 and $7 million in 1996, 1997, 1998 and 1999, respectively.
Before minority interest in Monter rey Resources, Inc. of ($1) and ($5) million in 1996 and 1997, respectively: extraordinary item of ($6) and
($4) million in 1996 and 1999, respectively; and the cumulative effect of change in accounting principle of ($1) and $49 million in 1993 and 2001, respectively.
(4) Revenues less cash expenses.
(5) Devon beneficially owns approximately 7 million shares of ChevronTexaco Corporation common stock. These shares have been deposited with an exchange agent for possible
exchange for $760 million principal amount of exchangeable debentures. The ChevronTexaco shares and debentures were acquired through the 1999 acquisition of PennzEnergy.
Includes preferred securities of subsidiary trust of $149 million in years 1996, 1997 and 1998.
(6)
NM Not a meaningful number.
19
4
1
6
2
1
6
0.
0.
3
1,6
5
7
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 31
31
1995
1996
1997
1998
1999
2000
2001
5-YEAR
GROWTH RATE
10-YEAR
GROWTH RATE
464
162
15
37
678
248
171
–
43
–
41
–
–
97
23
623
55
55
15
40
0.76
0.76
339
52
53
584
221
29
36
555
375
36
48
310
347
25
24
561
628
68
21
1,079
1,485
154
66
958
1,890
132
95
870
1,014
706
1,278
2,784
3,075
297
192
–
47
–
54
–
–
33
89
317
286
–
53
–
51
6
–
641
(127)
275
243
–
45
13
53
16
–
423
(126)
378
406
16
81
17
116
(13)
–
476
(49)
597
693
41
93
60
155
3
–
–
412
731
876
34
111
1
220
13
2
1,003
30
712
1,227
942
1,428
2,054
3,021
158
151
47
104
1.97
1.92
(213)
(218)
12
(230)
(3.35)
(3.35)
(236)
(236)
–
(236)
(3.32)
(3.32)
(150)
(154)
4
(158)
(1.68)
(1.68)
730
730
10
720
5.66
5.50
54
103
10
93
0.73
0.72
442
557
324
663
1,748
1,941
53
56
69
75
71
77
94
99
127
132
128
130
1,639
2,242
1,965
1,931
6,096
6,860
13,184
–
565
48
739
52
–
511
136
1,160
63
–
576
43
1,007
71
–
885
–
750
71
760
1,656
324
2,521
126
760
1,289
627
3,277
129
649
5,940
2,142
3,259
126
10%
54%
35%
21%
29%
20%
36%
NM
19%
NM
32%
NM
NM
98%
(20%)
34%
(19%)
(7%)
(27%)
(2%)
(18%)
(18%)
34%
19%
18%
43%
NM
63%
74%
23%
15%
11%
39%
39%
18%
21%
15%
24%
NM
12%
NM
17%
NM
NM
16%
NM
19%
NM
NM
18%
NM
NM
NM
28%
16%
16%
31%
NM
29%
48%
32%
15%
94
94
71
13
16
94
38
55
–
45
7
33
–
–
29
33
40
54
54
11
43
84
84
76
51
54
75
–
57
30
88
52
gy.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 32
32
M A N A G E M E N T ’ S D I S C U S S I O N & A N A L Y S I S
O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S
O V E RV I E W
In August and September 2001, Devon announced two major acquisitions that eventually would almost double our total
proved reserves to over two billion Boe. On August 13, 2001, Devon announced an agreement to acquire Mitchell Energy &
Development Corp. (“Mitchell”). The terms of this agreement 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 acquisition did not affect our 2001 reported results.
Following the Mitchell announcement, we announced on September 4, 2001, that we 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. Therefore, Devon’s results include Anderson’s results for the last 2 1/2 months of the year.
Devon entered into long-term debt agreements in October 2001 that totaled $6 billion. The purpose of this debt was to
fund the cash portions of these two acquisitions, to pay related transaction costs and retire certain long-term debt assumed
from Mitchell and Anderson. 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 to be 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, we merged with Santa Fe Snyder Corporation. In August 1999 we acquired PennzEnergy Company. These two
transactions combined added approximately 782 million Boe to our 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, exploration and development efforts have also been significant contributors
to our growth. In 1999, before the merger with Santa Fe Snyder, Devon spent approximately $0.3 billion for exploration, drilling
and development. These costs included drilling 678 wells, of which 636 were completed as producers. In 2000, Devon and
Santa Fe Snyder combined spent $0.9 billion for exploration, drilling and development. These costs included drilling 1,328 wells,
of which 1,261 were completed as producers. In 2001, Devon spent $2.9 billion for exploration, drilling and development. These
costs included drilling 1,545 wells, of which 1,444 were completed as producers. We also acquired $1.4 billion of unproved
leasehold in the Anderson acquisition.
Our acquisitions of Anderson in 2001 and PennzEnergy in 1999 were accounted for using the purchase method of
accounting for business combinations. In May 1999, prior to its merger with Devon, 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 our reported results until after the closing dates of the acquisitions. Our 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. The restated results include 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.
The following statistics reflect the effects that our mergers and acquisitions and our drilling and development activities
have had on operations during the last three years. This data compares Devon's 2001 results to those of 1999 for Devon only,
without Santa Fe Snyder. This comparison yields the following:
• Combined oil, gas and NGL production increased 82 million Boe, or 155%.
• The average combined sales 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. We have consistently increased production over
this 13-year period. However, 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 a number of factors beyond our control such as regional and worldwide economic
growth and weather. Our future earnings and cash flows will continue to depend on market conditions.
Like all oil and gas production companies, Devon faces the challenge of natural production decline. As initial pressures
are depleted, oil and gas production from a given well naturally decreases. Thus, an oil and gas production company depletes
part of its asset base with each unit of oil or gas it produces. Historically, Devon has been able to overcome this natural decline
by adding, through drilling and acquisitions, more reserves than it produces. Devon's future growth, if any, will depend on its
ability to continue to add reserves in excess of production.
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33
Oil and gas prices are influenced by many factors outside of our control. Devon's management has focused its efforts,
therefore, on increasing oil and gas reserves and production and controlling expenses. Over our 13-year history as a public
company, we have been able to reduce controllable operating costs per unit of production. Devon's future earnings and cash
flows are dependent on our ability to continue to contain operating costs at levels that allow for profitable production.
R E S U L T S O F O P E R AT I O N S
The following discussion of Devon’s results of operations from 1999 through 2001 includes restatements required by the
2000 merger with Santa Fe Snyder. This was accounted for using the pooling-of-interests method.
Our 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.)
PRODUCTION
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe)
REVENUES
Per Unit of Production:
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)
Absolute (in millions):
Oil
Gas
NGLs
Oil, gas and NGLs
PRODUCTION
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe)
REVENUES
Per Unit of Production:
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)
Absolute (in millions):
Oil
Gas
NGLs
Oil, gas and NGLs
2001
44
498
8
135
$
$
$
$
$
$
$
$
21.57
3.80
16.98
22.05
958
1,890
132
2,980
2001
26
376
6
95
22.36
$
$
4.17
$ 17.15
23.80
$
$
586
$ 1,571
103
$
2,260
$
TOTAL
YEAR ENDED DECEMBER 31,
2000
2000 vs 1999
2001 vs 2000
+2%
+17%
+14%
+12%
-15%
+9%
-19%
-2%
-11%
+27%
-14%
+10%
43
426
7
121
25.35
3.49
20.87
22.47
1,079
1,485
154
2,718
+34%
+40%
+40%
+38%
+43%
+69%
+57%
+57%
+92%
+136%
+126%
+116%
DOMESTIC
YEAR ENDED DECEMBER 31,
2000
2000 vs 1999
2001 vs 2000
-10%
+6%
–
+1%
-12%
+14%
-16%
+4%
-19%
+20%
-24%
+4%
29
355
6
94
25.45
3.67
20.30
22.95
727
1,305
136
2,168
+61%
+61%
+50%
+59%
+37%
+62%
+55%
+52%
+119%
+160%
+134%
+143%
1999
32
304
5
88
17.67
2.06
13.30
14.35
561
628
68
1,257
1999
18
221
4
59
18.64
2.27
13.11
15.10
332
502
58
892
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 34
34
PRODUCTION
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe)
REVENUES
Per Unit of Production:
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)
Absolute (in millions):
Oil
Gas
NGLs
Oil, gas and NGLs
PRODUCTION
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe)
REVENUES
Per Unit of Production:
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)
Absolute (in millions):
Oil
Gas
NGLs
Oil, gas and NGLs
2001
8
113
2
29
$ 17.84
$
2.73
$ 16.43
$ 16.80
$
$
$
$
146
307
28
481
2001
10
9
–
11
$
$
$
$
$
$
$
$
22.57
1.41
16.15
20.76
226
12
1
239
CANADA
YEAR ENDED DECEMBER 31,
2000
2000 vs 1999
2001 vs 2000
+60%
+82%
+100%
+81%
-27%
+1%
-38%
-12%
+26%
+82%
+56%
+59%
5
62
1
16
24.46
2.71
26.51
19.18
116
169
18
303
–
-16%
–
-11%
+58%
+75%
+84%
+70%
+45%
+48%
+80%
+49%
INTERNATIONAL
YEAR ENDED DECEMBER 31,
2000
2001 vs 2000
2000 vs 1999
+11%
–
NM
–
-11%
+7%
-24%
-10%
-4%
+9%
NM
-3%
9
9
–
11
25.48
1.32
21.19
23.08
236
11
–
247
–
–
NM
–
+50%
+6%
+6%
+49%
+58%
-8%
NM
+53%
1999
5
74
1
18
15.51
1.55
14.39
11.27
80
114
10
204
1999
9
9
–
11
16.96
1.24
20.00
15.50
149
12
–
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.
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)
WITH HEDGES
2000
2001
1999
$
$
$
$
21.57
3.80
16.98
22.05
25.35
3.49
20.87
22.47
17.67
2.06
13.30
14.35
WITHOUT HEDGES
2000
1999
2001
$
$
$
$
21.41
3.94
16.98
22.53
26.20
3.57
20.87
23.05
17.75
2.07
13.30
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 bar rel 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 that were sold prior to 2001. Production from these properties was included in 2000 prior
to the sales.
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35
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 1999 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 PennzEnergy merger. The 1999
results included production for only 4 1/2 months following the August 17, 1999 merger closing. The remaining four million
barrel increase in 2000’s production was caused by drilling activity and other acquisitions. This was 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 acquisition accounted for 51 Bcf of the increase.
Production from Devon’s domestic properties increased 21 Bcf. This was due primarily to drilling and development in Devon’s
coalbed methane properties and to 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. This was 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 contributed to this 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 bar rel 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 acquisition 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. The
forward purchase contract 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 seven million shares of ChevronTexaco Corporation common stock owned by
Devon. This stock was 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.
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36
EXPENSES The details of the changes in pre-tax expenses between 1999 and 2001 are shown in the table below.
2001
2001 vs 2000
2000
2000 vs 1999
1999
YEAR ENDED DECEMBER 31,
Absolute (in millions):
Production and operating expenses:
Lease operating expenses
Transportation costs
Production taxes
Depreciation, depletion and amortization of oil and
gas properties
Amortization of goodwill
Subtotal
Depreciation and amortization of non-oil and
gas properties
General and administrative expenses
Expenses related to mergers
Interest expense
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Distributions on preferred securities of subsidiary trust
Reduction of carr ying value of oil and gas properties
Total
Per Boe:
Production and operating expenses:
Lease operating expenses
Transportation costs
Production taxes
Depreciation, depletion and amortization of oil and
gas properties
Amortization of goodwill
Subtotal
Depreciation and amortization of non-oil and
gas properties (1)
General and administrative expenses (1)
Expenses related to mergers (1)
Interest expense (1)
E ffects of changes in foreign currency exchange rates ( 1 )
Change in fair value of financial instru m e n t s ( 1 )
Distributions on pre f e rred securities of subsidiary tru s t ( 1 )
Reduction of carrying value of oil and gas pro p e rt i e s ( 1 )
Total
$
531
83
117
838
34
1,603
38
111
1
220
13
2
–
1,003
$ 2,991
$
3.93
0.61
0.87
6.20
0.25
11.86
0.28
0.82
0.01
1.63
0.09
0.02
–
7.43
$ 22.14
+20%
+57%
+14%
+26%
-17%
+23%
+27%
+19%
-98%
+42%
+333%
NM
NM
NM
+82%
+8%
+39%
+2%
+13%
-26%
+10%
+12%
+6%
-98%
+28%
+350%
NM
NM
NM
+63%
441
53
103
663
41
1,301
30
93
60
155
3
–
–
–
1,642
3.65
0.44
0.85
5.48
0.34
10.76
0.25
0.77
0.50
1.27
0.02
–
–
–
13.57
+47%
+56%
+129%
+70%
+156%
+66%
+88%
+15%
+253%
+42%
-123%
NM
-100%
-100%
+11%
+7%
+13%
+67%
+23%
+89%
+20%
+32%
-16%
+163%
+2%
NM
NM
-100%
-100%
-20%
299
34
45
390
16
784
16
81
17
109
(13)
–
7
476
1,477
3.41
0.39
0.51
4.46
0.18
8.95
0.19
0.92
0.19
1.25
(0.15)
–
0.08
5.44
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.
NM – Not meaningful.
PRODUCTION AND OPERATING EXPENSES
The details of the changes in production and operating expenses between
1999 and 2001 are shown in the table below.
Absolute (in millions):
Recurring lease operating expenses
Well workover expenses
Transportation costs
Production taxes
Total production and operating expenses
Per Boe:
Recurring lease operating expenses
Well workover expenses
Transportation costs
Production taxes
Total production and operating expenses
2001
513
18
83
117
731
3.79
0.14
0.61
0.87
5.41
$
$
$
$
2001 vs 2000
YEAR ENDED DECEMBER 31,
2000
2000 vs 1999
+21%
+0%
+57%
+14%
+22%
+8%
-7%
+39%
+2%
+10%
423
18
53
103
597
3.50
0.15
0.44
0.85
4.94
+45%
+125%
+56%
+129%
+58%
+5%
+67%
+13%
+67%
+15%
1999
291
8
34
45
378
3.32
0.09
0.39
0.51
4.31
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37
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 our 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 western U.S. The western U.S. has higher production tax rates than most other domestic areas.
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, our 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. This was primarily due to increased production.
As previously stated, most of our 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 ”) Our 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 “depletable base.” The depletable base is the net capitalized investment in those reserves including estimated future
development and dismantlement and abandonment costs. 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 our 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 our 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 contributed to the increase. Depreciation of Devon's Wyoming gas
pipeline and gathering systems also contributed to the 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 incur red 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 in properties we operate. 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.
Gross G&A
Capitalized G&A
Reimbursed G&A
Net G&A
2001
$
$
245
(77)
(57)
111
2001 vs 2000
2000 vs 1999
YEAR ENDED DECEMBER 31,
2000
(IN MILLIONS)
+19%
+24%
+12%
+19%
206
(62)
(51)
93
+36%
+114%
+24%
+15%
1999
151
(29)
(41)
81
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38
2001 vs. 2000 Net G&A increased $18 million in 2001. Gross G&A increased $39 million. This was 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. 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 and not 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 billion in 2001. The increase
in average debt outstanding was attributable primarily to the long-term debt issued in October 2001 to acquire Anderson.
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 were $22 million higher in 2001 compared to 2000. Other items include facility and agency fees,
amortization of costs and other miscellaneous items. 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 a result of 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 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, our 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.
Until mid-January 2000, Northstar 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.
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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 defer red 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 countr y. 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.
During 2001 and 1999, we reduced the carr ying value of our 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.
United States
Canada
Egypt
China
Total
2001
1999
YEAR ENDED DECEMBER 31,
GROSS
NET OF TAXES
GROSS
NET OF TAXES
(IN MILLIONS)
$
$
449
434
33
–
916
281
252
23
–
556
464
–
–
12
476
302
–
–
8
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 our 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, we elected to discontinue operations in Thailand, Malaysia, Qatar and on certain properties in
Brazil. After meeting the drilling and capital commitments on these properties, we determined that these properties did not meet
the company’s internal criteria to justify further investment. Accordingly, we 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 Our 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. This was offset in part by the recognition of a benefit from the disposition of our assets in Venezuela.
2000 vs. 1999 Our 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. This gain was 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.
C A P I T A L E X P E N D I T U R E S , C A P I TA L R E S O U R C E S A N D L I Q U I D I T Y
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 that amount $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).
OTHER CASH USES We paid common stock dividends of $25 million, $22 million and $13 million in 2001, 2000 and
1999, respectively. We also paid $10 million of preferred stock dividends in 2001 and 2000 and $4 million in the last 4 1/2
months of 1999 following the PennzEnergy merger.
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During 2001, we repurchased 3,754,000 shares of common stock at an aggregate cost of $190 million, or $50.71 per
share. We also repurchased common stock in 2001 under an odd-lot repurchase program. Pursuant to this program, Devon
purchased and retired 232,000 shares of our common stock for a total cost of $14 million, or $57.40 per share.
CAPITAL RESOURCES AND LIQUIDITY
Our 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.
Our operating cash flow is sensitive to many variables. The most volatile of these variables 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. These factors are
beyond our control and are difficult to predict.
To mitigate some of the risk inherent in oil and natural gas prices, we have entered into various fixed-price physical delivery
contracts and financial price swap contracts to fix the price to be received for a portion of our future oil and natural gas
production. Additionally, we have utilized price collars to set minimum and maximum prices on a portion of our production. The
table below provides the volumes associated with these various arrangements.
Oil production (MMBbls)
2002
Natural gas production (Bcf)
2002
2003
2004
FIXED-PRICE
PHYSICAL DELIVERY
CONTRACTS
PRICE SWAP
CONTRACTS
PRICE
COLLARS
TOTAL
2
53
26
19
10
88
36
2
7
162
126
–
19
303
188
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. We also have Canadian gas volumes subject to fixed-price contracts in the years from 2012
through 2016, but the yearly volumes are less than one Bcf.
By removing the price volatility from the above volumes of oil and natural gas production, we have mitigated, but not
eliminated, the potential negative effect of declining prices on our operating cash flow. 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, we announced that our 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 our control. Therefore, if oil and natural gas prices decline below acceptable levels, Devon
could choose to defer a portion of these planned 2002 capital expenditures.
Other sources of liquidity are our revolving lines of credit. As of December 31, 2001, these credit lines totaled $1.1 billion,
of which $884 million was available 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. We may borrow funds under the Tranche B facility until August 12, 2002 (the
“Tranche B Revolving Period”). We 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.
We 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. The final installment is 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, we have the right to reallocate up to $100 million of the unused Tranche
B facility maximum credit amount to the Canadian Facility. Conversely, we also have 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 we may elect for periods
up to six months. Devon has historically elected a rate that is based upon LIBOR, plus a margin dictated by our debt rating.
B o rrowings under the Canadian facility have also been made under a rate based upon the Bankers’ Acceptance rate, plus a marg i n
dictated by our debt rating. Based upon our current debt rating, we 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 our revolving credit facilities at December 31, 2001, at an average interest rate of 4.8%.
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We also have access to short-term credit under our 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 our 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 under certain conditions. Such conditions could include any condition or event that 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. Devon’s $1 billion revolving credit facilities and our $3 billion term loan credit facility include covenants
that require us to report a condition or event having a material adverse effect on the company. However, the obligation of the
banks to fund the revolving credit facilities is not expressly conditioned on the absence of a material adverse effect.
A portion of the 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 bor rowed upon the closing of the Mitchell acquisition on January 24, 2002, will mature as follows:
October 15, 2004
April 15, 2005
October 15, 2005
April 15, 2006
October 15, 2006
(MILLIONS)
232
$
600
$
600
$
800
$
800
$
3,032
$
B o rrowings 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. There a f t e r, the margin will be based
on our debt rating. Based on our current debt rating, the margin after June 17, 2002, would be 100 basis points. Following the
close of the Mitchell acquisition, we had $3 billion borrowed under this facility as of Januar y 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 we 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.
Devon’s $1 billion revolving credit facilities and our $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 non-cash 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%.
We intend to divest approximately $1 billion of oil and gas properties in 2002. We are currently in the early stages of the
property divestiture activities. Although we believe we 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 our indebtedness to the extent desired through these property divestitures or
other cash sources could result in unfavorable actions by the various credit rating agencies.
We receive debt ratings from the major ratings agencies in the United States. In determining our debt ratings, the agencies
consider a number of items. These include, but are 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 cur rent 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 our contractual obligations that would accelerate scheduled maturities should
our debt ratings 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, our 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 our debt rating would be subjected to downgrades to non-investment grade levels during such a period
of rising oil and natural gas prices.
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As summarized earlier in this section, our cost of borrowing under the $1 billion revolving credit facilities and the $3 billion
term loan credit facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not
accelerate scheduled maturities, it would adversely impact the interest rate on our 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 our
borrowing rates by 22.5 basis points and 25 basis points, respectively. A ratings downgrade could also adversely impact our
ability to economically access future debt markets. As of January 31, 2002, we are 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
2002
2003
2004
2005
(IN MILLIONS)
Long-term debt
Operating leases
Drilling obligations
Firm transportation agreements
Total
$
$
–
21
170
93
284
–
20
17
82
119
358
16
–
65
439
775
14
–
49
838
2006
689
11
–
42
742
AFTER
2006
4,886
14
–
219
5,119
TOTAL
6,708
96
187
550
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. If funded, the letters of credit would become borrowings under our revolving credit facility. Most of these letters of credit
have been granted by financial institutions to support our 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.
C R I T I C A L A C C O U N T I N G P O L I C I E S
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. Below is information on what we believe are our critical accounting policies.
Full cost ceiling calculations We follow the full cost method of accounting for our 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.
The discounted present value of our 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 our own
employees.
The passage of time provides more qualitative information regarding estimates of reserves. Revisions are made to prior
estimates to reflect updated information. In the past four years, our annual revisions to our 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 reduce previously estimated reserve quantities, it could result in a full
cost property writedown. Estimates of proved reserves are also a significant component in the calculation of DD&A.
While the estimated 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. Rather they 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
i n d e f i n i t e l y, the resulting value is not indicative of the true fair value of the re s e r ves. Oil and natural gas prices have historically
been cyclical. On any par ticular day at the end of a quar t e r, they can be either substantially higher or lower than Devon’s long-
t e rm price forecast that is a barometer for true fair value. There f o re, oil and gas pro p e rty writedowns that result from applying the
full cost ceiling limitation should not be viewed as absolute indicators of a reduction of the ultimate value of the related re s e rv e s .
This is because they are caused by fluctuations in price as opposed to reductions to the underlying quantities of re s e rv e s .
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We recorded writedowns to our 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 we reduce our estimates
of proved reserve quantities, further writedowns would likely occur. Also, in January 2002, we closed our Mitchell acquisition.
The oil and gas properties acquired in this transaction were recorded at their estimated fair value. The fair values were based
on our 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 our
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 our 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 our hedging derivatives require substantial judgment. We estimate the fair values of
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 necessar y, Devon adjusts the NYMEX prices to prices at other regional delivery points using our own estimates of future
differentials. The estimated future prices are compared to the prices fixed by the hedge agreements. The resulting estimated
future cash inflows or outflows over the lives of the hedges are discounted using Devon’s current bor rowing 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 our 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 We have 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. 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 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, we prepare estimates of oil, natural gas and
NGL reserves. These estimates are based on work performed by our 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. Our estimates of
future prices are based on our 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 our own pricing
estimates.
Our 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.
We also apply 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. This debt must be recorded at the estimated fair value as if Devon had issued it. However,
significant judgment by Devon is usually not required in these situations due to the existence of comparable market values of
debt issued by Devon’s peer companies.
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Effective January 1, 2002, we 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 our 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.
2 0 0 2 E S T I M A T E S
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. We caution that 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, 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 our 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, our 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 we operate. 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 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:
• United States
• Canada
• International, which encompasses all oil and gas properties that lie outside of the United States and Canada
Y E A R 2 0 0 2 P O T E N T I A L O P E R AT I N G I T E M S
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.
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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.
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:
United States
Canada
International
(MMBbls)
18.3 to 19.5
14.4 to 15.3
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 eight 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.
United States
Canada
International
EXPECTED RANGE OF OIL PRICES
LESS THAN NYMEX PRICE
($2.35) to ($1.35)
($6.05) to ($4.05)
($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:
United States
Canada
(Bcf)
473 to 502
274 to 291
Gas Prices – Fixed Through various price swaps and fixed-price physical delivery contracts, Devon has fixed the price we
will receive on a portion of our natural gas production. The following tables include information on this fixed-price production.
Where necessar y, 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
Canada
264,671
192,983
$
$
3.01
1.88
198,346
121,758
$
$
3.19
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.
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EXPECTED RANGE OF GAS PRICES
GREATER THAN (LESS THAN) NYMEX PRICE
United States
Canada
($0.45) to $0.05
($0.75) to ($0.25)
Devon has also entered into costless price collars that set a floor and ceiling price for a portion of our 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 our realized prices for the production volumes related to the collars.
We have entered into costless collars concerning our 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.
AREA (RANGE OF FLOOR PRICES)
United States ($3.35 - $3.65)
United States ($2.96 - $3.11)
United States ($2.75 - $2.79)
Canada ($3.54 - $3.72)
Canada ($3.19 - $3.32)
Canada ($2.72 - $2.99)
FIRST HALF OF 2002
FLOOR
PRICE PER
MMBtu
MMBtu/ DAY
285,000
130,000
35,000
23,705
9,481
34,481
$ 3.52
$ 3.01
$ 2.76
$ 3.64
$ 3.26
$ 2.79
CEILING
PRICE PER
MMBtu
$ 7.37
$ 4.53
$ 3.72
$ 6.82
$ 4.50
$ 3.88
SECOND HALF OF 2002
FLOOR
PRICE PER
MMBtu
CEILING
PRICE PER
MMBtu
MMBtu/ DAY
285,000
–
35,000
23,705
–
25,000
$ 3.52
$
. –
$ 2.76
$ 3.64
$
. –
$ 2.72
$ 7.37
$
. –
$ 3.72
$ 6.82
$
. –
$ 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:
United States
Canada
(MMBbls)
11.9 to 12.7
4.5 to 4.8
Gas Services Revenues and Expenses Devon’s gas services revenues and expenses are derived from our 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, we estimate 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 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.
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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 our 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. We can only marginally influence the prices we 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 predict accurately. (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%.
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 bor rowed 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 countr y. 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. On any particular day at the end of a quarter, they 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 should not be viewed as absolute indicators of a reduction of the ultimate
value of the related reserves. This is because they are caused by fluctuations in price as opposed to reductions to the underlying
quantities of 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 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
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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 subsidiar y, 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.
PRE-TAX EARNINGS
$100 - $225 million
$226 - $450 million
$451 - $675 million
CURRENT
65% to 40%
40% to 35%
35% to 30%
INCOME TAX EXPENSE (BENEFIT) RATE
DEFERRED
(130%) to (50%)
(50%) to (20%)
(20%) to (10%)
TOTAL
(65%) to (10%)
(10%) to 15%
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 Although we have completed several major property acquisitions in recent years,
these transactions are opportunity driven. Thus, Devon does not “budget,” nor can we reasonably predict, the timing or size of
such possible acquisitions, if any, other than the Mitchell acquisition, which 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 cur rent 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:
United States
Canada
International
Total
EXPECTED RANGE OF PRODUCTION
OIL
(MMBbls)
6.8 to 7.2
2.9 to 3.1
7.1 to 7.5
16.8 to 17.8
GAS
(Bcf)
45 to 48
13 to 14
10 to 11
68 to 73
NGL
(MMBbls)
0.6 to 0.7
0.3 to 0.4
0.1 to 0.2
1.0 to 1.3
TOTAL
(MMBoe)
14.9 to 15.9
5.4 to 5.8
8.9 to 9.5
29.2 to 31.2
EXPECTED RANGE OF EXPENSE
(IN MILLIONS)
Lease operating expenses
Transportation costs
DD&A
$178 to $189
$ 10 to $ 11
$195 to $207
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Y E A R 2 0 0 2 P O T E N T I A L C A P I T A L E X P E N D I T U R E S A N D O T H E R C A S H U S E S
Capital Expenditures Although we have completed several major property acquisitions in recent years, these transactions
are opportunity driven. Thus, Devon does not “budget,” nor can we 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
Lower Risk/Reward Projects
Higher Risk/Reward Projects
Total
$ 435 - $ 495
$ 170 - $ 200
$
70 - $ 80
$ 675 - $ 775
$
15 - $ 35
$ 195 - $ 225
$ 210 - $ 240
$ 420 - $ 500
$ 45 - $ 65
$
0 - $ 10
$ 20 - $ 30
$ 65 - $ 105
495 - $
365 - $
300 - $
595
$
435
$
$
350
$ 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 our gas services assets, which include gas processing plants and gas transport pipelines. Devon also expects
to capitalize between $85 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. We 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
Unproved oil and gas properties
Gas services facilities and equipment
$1.5 billion
$0.7 billion
$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 we 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.
We will perform an assessment of whether there is an indication that goodwill is impaired as of January 1, 2002. We will
identify our reporting units and determine the carr ying 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 carr ying amount. To the extent a reporting unit’s
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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 carr ying
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, we do 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. These include 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. This is 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.” We expect to 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, we
expect 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, 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. We do 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. This is 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.
Q U A N T I T AT I V E A N D Q U A L I T AT I V E D I S C L O S U R E S A B O U T M A R K E T R I S K
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 we view and manage our 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
p roduction 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 counterpart y, and
costless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 51
of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterpar ty to the collars will settle the
d i ff e rence. These financial hedging activities are intended to support oil and natural gas prices at targeted levels and to manage
our exposure to oil and gas price fluctuations. We do not hold or issue derivative instruments for trading purposes.
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 our 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.
51
United States
Canada
United States
Canada
United States
Canada
United States
Canada
OIL PRODUCTION
FIRST HALF OF 2002
SECOND HALF OF 2002
Bbls/ DAY
22,000
4,350
PRICE/Bbl
$ 23.85
$ 20.33
Bbls/ DAY
22,000
4,350
PRICE/Bbl
$ 23.85
$ 20.33
GAS PRODUCTION
FIRST HALF OF 2002
SECOND HALF OF 2002
Mcf/ DAY
211,936
40,673
PRICE/Mcf
3.11
$
2.13
$
Mcf/ DAY
198,346
33,472
PRICE/Mcf
3.19
$
2.12
$
FIRST HALF OF 2003
SECOND HALF OF 2003
Mcf/ DAY
89,726
5,000
PRICE/Mcf
3.50
$
2.49
$
Mcf/ DAY
100,000
5,000
PRICE/Mcf
3.32
$
2.03
$
FIRST HALF OF 2004
SECOND HALF OF 2004
Mcf/ DAY
–
5,000
PRICE/Mcf
.0–-
$
2.58
$
Mcf/ DAY
–
3,342
PRICE/Mcf
.0–
$
2.03
$
Costless Price Collars Devon has also entered into costless price collars that set a floor and ceiling price for a portion
of our 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 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 our
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
United States
United States
Canada
United States
Canada
FIRST HALF OF 2002
FLOOR
PRICE PER
Bbl
$ 23.00
CEILING
PRICE PER
Bbl
$ 28.19
Bbls/ DAY
20,000
SECOND HALF OF 2002
FLOOR
PRICE PER
Bbl
$ 23.00
CEILING
PRICE PER
Bbl
$ 28.19
Bbls/ DAY
20,000
GAS PRODUCTION
FIRST HALF OF 2002
FLOOR
PRICE PER
MMBtu
$ 3.32
$ 3.15
MMBtu/ DAY
450,000
67,667
FIRST HALF OF 2003
FLOOR
PRICE PER
MMBtu
$ 3.18
$ 3.27
MMBtu/ DAY
265,000
80,000
CEILING
PRICE PER
MMBtu
$ 6.27
$ 5.00
CEILING
PRICE PER
MMBtu
$ 4.22
$ 4.07
SECOND HALF OF 2002
FLOOR
PRICE PER
MMBtu
MMBtu/ DAY
320,000
48,705
$
$
3.44
3.17
SECOND HALF OF 2003
FLOOR
PRICE PER
MMBtu
MMBtu/ DAY
265,000
80,000
$
$
3.18
3.27
CEILING
PRICE PER
MMBtu
$ 6.97
$ 5.20
CEILING
PRICE PER
MMBtu
$ 4.22
$ 4.07
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 52
52
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 our commodity hedging instruments. At January 31, 2002, a 10% increase in the underlying
commodities' prices would have reduced the fair value of our commodity hedging instruments by $118 million.
Fixed-Price Physical Delivery Contracts In addition to the commodity hedging instruments described above, we also
manage our 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 7.0%. The remaining $1.2 billion of debt outstanding bears interest
at floating rates which averaged 3.0%. 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. This assumes 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 our 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 cur rency. Assets and liabilities of the
Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period.
Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.
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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 53
53
M A N A G E M E N T ’ S R E S P O N S I B I L I T Y F O R F I N A N C I A L S T A T E M E N T S
Devon Energy Corporation’s management takes responsibility for the accompanying consolidated financial
statements which have been prepared in conformity with accounting principles generally accepted in the United States
of America. They are based on our best estimate and judgment. Financial information elsewhere in this annual report is
consistent with the data presented in these statements.
In order to carry out our responsibility concerning the integrity and objectivity of published financial data, we
maintain an accounting system and related internal controls. We believe the system is sufficient in all material respects
to provide reasonable assurance that financial records are reliable for preparing financial statements and that assets
are safeguarded from loss or unauthorized use.
Our independent accounting firm, KPMG LLP, provides objective consideration of Devon Energy management’s
discharge of its responsibilities as it relates to the fairness of reported operating results and the financial position of
the company. This firm obtains and maintains an understanding of our accounting and financial controls to the extent
necessary to audit our financial statements, and employs all testing and verification procedures it considers necessary
to arrive at an opinion on the fairness of financial statements.
The Board of Directors pursues its responsibilities for the accompanying consolidated financial statements
through its Audit Committee. The Committee meets periodically with management and the independent auditors to
assure that they are carr ying out their responsibilities. The independent auditors have full and free access to the
Committee members and meet with them to discuss auditing and financial reporting matters.
DEVON ENERGY CORPORATION EXECUTIVE COMMITTEE
J. Larry Nichols
Chairman, President & CEO
Brian J. Jennings
Senior Vice President
J. Michael Lacey
Senior Vice President
Duke R. Ligon
Senior Vice President
Marian J. Moon
Senior Vice President
John Richels
Senior Vice President
Darryl G. Smette
Senior Vice President
William T. Vaughn
Senior Vice President
I N D E P E N D E N T A U D I T O R S ’ R E P O R T
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 subsidiar y, 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.
Oklahoma City, Oklahoma
February 5, 2002
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 54
54
DEVON ENERGY CORPORATION AND SUBSIDIARIES
C O N S O L I D AT E D B A L A N C E S H E E T S
DECEMBER 31, (IN MILLIONS, EXCEPT SHARE DATA)
2001
2000
1999
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable
Inventories
Deferred income taxes
Fair value of financial instruments
Income taxes receivable
Investments and other cur rent assets
Total current assets
P ro p e rty and equipment, at cost, based on the full cost method of
accounting for oil and gas pro p e rties ($1,939, $315 and $301 excluded from
a m o rtization in 2001, 2000 and 1999, re s p e c t i v e l y )
Less accumulated depreciation, depletion and amortization
Investment in ChevronTexaco Corporation common stock, at fair value
Fair value of financial instruments
Goodwill
Other assets
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade
Revenues and royalties due to others
Income taxes payable
Accrued interest payable
Merger related expenses payable
Fair value of financial instruments
Deferred income taxes
Accrued expenses
Total current liabilities
Other liabilities
Debentures exchangeable into shares of ChevronTexaco Corporation
common stock
Other long-term debt
Deferred revenue
Fair value of financial instruments
Deferred income taxes
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
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
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Unamortized restricted stock awards
Treasury stock, at cost: 3,754,000 shares in 2001 and
330,000 shares in 1999
Total stockholders' equity
Commitments and contingencies (Notes 12 and 13)
Total liabilities and stockholders' equity
See accompanying notes to consolidated financial statements
$
$
193
537
41
–
195
68
47
1,081
15,598
6,570
9,028
636
31
2,206
202
13,184
465
170
30
102
7
15
57
73
919
179
649
5,940
51
45
2,142
228
598
47
9
–
–
52
934
9,709
4,799
4,910
599
–
289
128
6,860
321
116
66
23
52
–
–
51
629
164
173
316
39
5
–
–
57
590
8,592
4,168
4,424
614
–
323
145
6,096
267
67
13
28
36
–
–
56
467
263
760
1,289
114
–
627
760
1,656
105
–
324
1
1
1
13
3,610
(147)
(28)
–
(190)
3,259
13
3,564
(215)
(85)
(1)
–
3,277
13
3,492
(909)
(65)
–
(11)
2,521
$
13,184
6,860
6,096
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 55
DEVON ENERGY COR PORATION AND SUBSIDIARIES
C O N S O L I D AT E D S TA T E M E N T S O F O P E R A T I O N S
55
YEAR ENDED D ECEMBER 31, (IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
2001
2000
1999
REVENUES
Oil sales
Gas sales
Natural gas liquids sales
Other
Total revenues
COSTS AND EXPENSES
Lease operating expenses
Transportation costs
Production taxes
Depreciation, depletion and amortization of property and equipment
Amortization of goodwill
General and administrative expenses
Expenses related to mergers
Interest expense
Effects of changes in foreign currency exchange rates
Distributions on preferred securities of subsidiary trust
Change in fair value of financial instruments
Reduction of carr ying value of oil and gas properties
Total costs and expenses
Earnings (loss) before income taxes, extraordinary item and cumulative
effect of change in accounting principle
INCOME TAX EXPENSE (BENEFIT)
Current
Deferred
Total income tax expense (benefit)
Earnings (loss) before extraordinary item and cumulative effect of change
in accounting principle
Extraordinary loss
Earnings (loss) before cumulative effect of change in accounting principle
Cumulative effect of change in accounting principle
Net earnings (loss)
Preferred stock dividends
Net earnings (loss) applicable to common shareholders
Net earnings (loss) per average common share outstanding:
Before extraordinary loss and cumulative effect of change in accounting
principle:
Basic
Diluted
Before cumulative effect of change in accounting principle:
Basic
Diluted
Applicable to common shareholders:
Basic
Diluted
Weighted average common shares outstanding:
Basic
Diluted
See accompanying notes to consolidated financial statements
$
$
$
$
$
$
$
$
958
1,890
132
95
3,075
531
83
117
876
34
111
1
220
13
–
2
1,003
2,991
1,079
1,485
154
66
2,784
441
53
103
693
41
93
60
155
3
–
–
–
1,642
561
628
68
21
1,278
299
34
45
406
16
81
17
109
(13)
7
–
476
1,477
84
1,142
(199)
71
(41)
30
54
–
54
49
103
10
93
0.34
0.34
0.34
0.34
0.73
0.72
128
130
131
281
412
730
–
730
–
730
10
720
5.66
5.50
5.66
5.50
5.66
5.50
127
132
23
(72)
(49)
(150)
(4)
(154)
–
(154)
4
(158)
(1.64)
(1.64)
(1.68)
(1.68)
(1.68)
(1.68)
94
99
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 56
56
DEVON ENERGY CORPORATION AND SUBSIDIARIES
C O N S O L I D A T E D S TAT E M E N T S O F S T O C K H O L D E R S ’ E Q U I T Y
PREFERRED
STOCK
COMMON
STOCK
ADDITIONAL
PAID-IN
CAPITAL
ACCUMULATED
DEFICIT
ACCUMULATED
OTHER
COMPRE-
HENSIVE
LOSS
UNAMORTIZED
RESTRICTED
STOCK
AW ARDS
TOTAL
STOCK-
HOLDERS’
EQUITY
TREASUR Y
STOCK
1,524
(737)
(36)
(1)
(7)
750
(IN MILLIONS)
BALANCE AS OF DECEMBER 31, 1998
$
Comprehensive loss:
Net loss
Other comprehensive earnings (loss), net of tax:
Foreign currency translation adjustments
Unrealized loss on marketable securities
Other comprehensive loss
Comprehensive loss
Stock issued
Stock repurchased
Tax benefit related to employee stock options
Dividends on common stock
Dividends on preferred stock
Amortization of restricted stock awards
BALANCE AS OF DECEMBER 31, 1999
Comprehensive loss:
Net earnings
Other comprehensive earnings (loss), net of tax:
Foreign currency translation adjustments
Minimum pension liability adjustment
Unrealized loss on marketable securities
Other comprehensive loss
Comprehensive earnings
Stock issued
Stock repurchased
Tax benefit related to employee stock options
Dividends on common stock
Dividends on preferred stock
Grant of restricted stock awards
Amortization of restricted stock awards
BALANCE AS OF DECEMBER 31, 2000
Comprehensive earnings:
Net earnings
Other comprehensive earnings (loss), net of tax:
Foreign currency translation adjustments
Cumulative effect of change in
accounting principle
Reclassification adjustment for derivative (gains)
losses reclassified into oil and gas sales
Change in fair value of financial instruments
Minimum pension liability adjustment
Unrealized gain on marketable securities
Other comprehensive earnings
Comprehensive earnings
Stock issued
Stock repurchased
Tax benefit related to employee stock options
Dividends on common stock
Dividends on preferred stock
Amortization of restricted stock awards
–
–
–
–
–
1
–
–
–
–
–
1
–
–
–
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
–
–
–
–
–
–
–
–
–
7
–
–
–
–
6
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1,967
–
1
–
–
–
(154)
–
–
–
(1)
–
–
(13)
(4)
–
–
7
(36)
–
–
–
–
–
–
–
13
3,492
(909)
(65)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
69
–
3
–
–
–
–
730
–
–
–
–
(4)
–
–
(22)
(10)
–
–
–
(10)
1
(11)
–
–
–
–
–
–
–
–
13
3,564
(215)
(85)
103
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
48
(14)
12
–
–
–
–
–
–
(25)
(10)
–
(107)
(37)
(20)
216
(17)
22
–
–
–
–
–
–
–
BALANCE AS OF DECEMBER 31, 2001
$
1
13
3,610
(147)
(28)
See accompanying notes to consolidated financial statements
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
–
–
–
–
–
–
(5)
4
(1)
–
–
–
–
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
8
(12)
–
–
–
–
(154)
7
(36)
(29)
(183)
1,981
(12)
1
(13)
(4)
1
(11)
2,521
–
–
–
–
–
21
(10)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(190)
–
–
–
–
730
(10)
1
(11)
(20)
710
86
(10)
3
(22)
(10)
(5)
4
3,277
103
(107)
(37)
(20)
216
(17)
22
57
160
48
(204)
12
(25)
(10)
1
(190)
3,259
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 57
DEVON ENERGY CORPORATION AND SUBSIDIARIES
C O N S O L I D AT E D S TA T E M E N T S O F C A S H F L O W S
57
YEAR ENDED DECEMBER 31,
(IN MILLIONS)
2001
2000
1999
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings (loss)
Adjustments to reconcile net earnings (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization of property and equipment
Amortization of goodwill
Accretion (amortization) of discounts (premiums) on
long-term debt, net
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Reduction of carr ying value of oil and gas properties
Loss (gain) on sale of assets
Deferred income tax expense (benefit)
Cumulative effect of change in accounting principle
Other
Changes in assets and liabilities, net of effects of acquisitions of
businesses:
Decrease (increase) in:
Accounts receivable
Inventories
Income tax receivable
Investments and other cur rent assets
(Decrease) increase in:
Accounts payable
Income taxes payable
Accrued interest and expenses
Deferred revenue
Long-term other liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property and equipment
Proceeds from sale of investments
Capital expenditures, including acquisitions of businesses
(Increase) decrease in other assets
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings of long-term debt, net of issuance costs
Principal payments on long-term debt
Issuance of common stock, net of issuance costs
Repurchase of common stock
Issuance of treasury stock
Dividends paid on common stock
Dividends paid on prefer red stock
(Decrease) increase in long-term other liabilities
Net cash provided by (used in) financing activities
Effect of exchange rate changes on cash
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
See accompanying notes to consolidated financial statements
$
103
730
(154)
876
34
26
13
2
1,003
2
(41)
(49)
(3)
191
15
(68)
2
29
(117)
(46)
(63)
(23)
1,886
41
–
(5,326)
–
(5,285)
6,199
(2,638)
48
(204)
–
(25)
(10)
–
3,370
(6)
(35)
228
193
$
693
41
3
3
–
–
(1)
281
–
4
(284)
(8)
–
10
99
61
3
8
(24)
1,619
101
13
(1,280)
(7)
(1,173)
2,580
(2,952)
51
(10)
25
(22)
(10)
(52)
(390)
(1)
55
173
228
406
16
(1)
(13)
–
476
5
(72)
–
2
(93)
(9)
–
(41)
(23)
(19)
(38)
91
(1)
532
114
–
(883)
1
(768)
1,945
(2,089)
530
(12)
6
(13)
(4)
14
377
1
142
31
173
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 58
58
DEVON ENERGY CORPORATION AND SUBSIDIARIES
N O T E S T O C O N S O L I D AT E D F I N A N C I A L S T A T E M E N T S
DECEMB ER 31, 2001, 2000 AND 1999
1 . S U M M A R Y O F S I G N I F I C A N T A C C O U N T I N G P O L I C I E S
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. 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.
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 3 to 39 years.
Marketable Securities and Other Investments
Devon accounts for certain investments in debt and equity securities by following the requirements of Statement of
Financial Accounting Standards (“SFAS”) No. 115, Accounting for Certain Investments in Debt and Equity Securities. This
standard requires that, except for debt securities classified as “held-to-maturity,” investments in debt and equity securities must
be reported at fair value. As a result, Devon’s investment in 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.”
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59
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 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 carr ying amount. To the extent a reporting
unit’s carr ying 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 car rying
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 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.
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60
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.
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 re p o rted 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 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 Corporation and certain of its subsidiaries filed voluntary petitions for re o rganization 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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 61
61
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. Defer red tax assets and liabilities are measured using enacted
tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected
to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date. U.S. deferred income taxes have not been provided on Canadian earnings which are
being permanently reinvested.
General and Administrative Expenses
General and administrative expenses are reported net of amounts allocated to working interest owners of the oil and gas
properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Net Earnings Per Common Share
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number
of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if Devon’s
dilutive outstanding stock options were exercised (calculated using the treasury stock method) and if Devon’s zero-coupon
convertible senior debentures were converted to common stock.
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.
YEAR ENDED DECEMBER 31, 2001:
Basic earnings per share
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options
Diluted earnings per share
YEAR ENDED DECEMBER 31, 2000:
Basic earnings per share
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)
Potential common shares issuable upon the exercise
of outstanding stock options
NET EARNINGS
APPLICABLE
TO COMMON
STOCKHOLDERS
WEIGHTED
AVERAGE
COMMON SHARES
OUTSTANDING
NET
EARNINGS
PER SHARE
(IN MILLIONS)
$0.73
$0.72
$5.66
$93
—
$93
$720
5
—
128
2
130
127
3
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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 62
62
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 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.
Balance as of December 31, 1998
1999 activity
Deferred taxes
1999 activity, net of deferred taxes
Balance as of December 31, 1999
2000 activity
Deferred taxes
2000 activity, net of deferred taxes
Balance as of December 31, 2000
2001 activity
Deferred taxes
2001 activity, net of deferred taxes
FOREIGN
CURRENCY
TRANSLATION
ADJUSTMENTS
CHANGE IN
FAIR VALUE OF
FINANCIAL
MINIMUM
PENSION
LIABILITY
INSTRUMENTS ADJUSTMENTS
UNREALIZED
GAIN (LOSS) ON
MARKETABLE
SECURITIES
TOTAL
(IN MILLIONS)
$
$ —
—
—
—
—
—
—
—
—
243
(84)
159
(1)
—
—
—
(1)
1
—
1
—
(28)
11
(17)
$
$ —
(60)
24
(36)
(36)
(18)
7
(11)
(47)
36
(14)
22
(36)
(53)
24
(29)
(65)
(27)
7
(20)
(85)
144
(87)
57
$
(35)
7
—
7
(28)
(10)
—
(10)
(38)
(107)
—
(107)
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.
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 . B U S I N E S S C O M B I N A T I O N S A N D P R O F O R M A I N F O R M A T I O N
Mitchell Acquisition
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 acquisition and the October 2001 acquisition
of Anderson Exploration Ltd. (“Anderson”).
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 63
63
Anderson Acquisition
On October 15, 2001, Devon accepted all of the Anderson common shares tendered by Anderson stockholders in the tender
o ff e r, which re p resented 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 billion of debt securities and borrowings under the $3 billion senior unsecured term loan credit facility (see Note 7).
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
Acquisition price per share
Cash paid to Anderson stockholders
Cash paid to settle Anderson employees’ stock options and
appreciation rights
Plus estimated acquisition costs incur red
Total purchase price
Plus fair value of liabilities assumed by Devon:
Current liabilities
Long-term debt
Other long-term liabilities
Fair value of financial instruments
Deferred income taxes
Total purchase price plus liabilities assumed
Fair value of assets acquired by Devon:
Current assets
Proved oil and gas properties
Unproved oil and gas properties
Other property and equipment
Goodwill (none deductible for income tax purposes)
Total fair value of assets acquired
132
25.68
3,386
92
3,478
35
3,513
249
1,017
7
30
1,427
6,243
214
2,605
1,432
21
1,971
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.
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 re c o rded a pre-tax charge of $60 million ($37 million net of tax) for direct costs related to the Santa
Fe Snyder merg e r.
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.
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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.
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 merg e r. 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 . S A N J U A N B A S I N T R A N S A C T I O N
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 . S U P P L E M E N T A L C A S H F L O W I N F O R M A T I O N
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.
The 2001 Anderson acquisition and the 1999 PennzEnergy merger and Snyder merger involved non-cash consideration as
p resented below:
2001
1999
(IN MILLIONS)
Value of common stock issued
Value of preferred stock issued
Employee stock options assumed
Liabilities assumed
Deferred tax liability created
$
—
—
—
1,303
1,427
Fair value of assets acquired with non-cash consideration
$
2,730
1,130
150
18
2,259
475
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).
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5 . A C C O U N T S R E C E I V A B L E
The components of accounts receivable included the following:
Oil, gas and natural gas liquids revenue accruals
Joint interest billings
Other
Allowance for doubtful accounts
Net accounts receivable
6 . P R O P E R T Y A N D E Q U I P M E N T
Property and equipment included the following:
Oil and gas properties:
Subject to amortization
Not subject to amortization:
Acquired in 2001
Acquired in 2000
Acquired in 1999
Acquired prior to 1999
Accumulated depreciation, depletion
and amortization
2001
323
108
110
541
(4)
537
$
$
DECEMBER 31,
2000
(IN MILLIONS)
438
123
41
602
(4)
598
1999
218
67
35
320
(4)
316
2001
DECEMBER 31,
2000
(IN MILLIONS)
1999
$ 13,266
9,170
8,126
1,638
74
116
111
—
74
122
119
—
—
135
167
(6,481)
(4,752)
(4,130)
Net oil and gas properties
8,724
4,733
4,298
Other property and equipment
Accumulated depreciation and amortization
Net other property and equipment
Property and equipment, net of accumulated
depreciation, depletion and amortization
393
(89)
304
224
(47)
177
165
(39)
126
$
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:
Depreciation, depletion and amortization of oil and gas properties
Depreciation and amortization of other property and equipment
Amortization of other assets
Total
$
$
YEAR ENDED DECEMBER 31,
2000
(IN MILLIONS)
663
23
7
693
2001
838
30
8
876
1999
390
14
2
406
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66
7 . L O N G - T E R M D E B T A N D R E L AT E D E X P E N S E S
A summary of Devon’s long-term debt is as follows:
Borrowings under credit facilities with banks
Commercial paper borrowings
$3 billion term loan credit facility
Debentures exchangeable into shares of
ChevronTexaco Corporation common stock:
4.90% due August 15, 2008
4.95% due August 15, 2008
Discount on exchangeable debentures
Zero coupon convertible senior debentures
exchangeable into shares of Devon Energy Corp.
common stock, 3.875% due June 27, 2020
Other debentures:
10.25% due November 1, 2005
10.125% due November 15, 2009
7.875% due September 30, 2031
Net premium on debentures
Senior notes:
8.05% due June 15, 2004
7.25% due July 18, 2005
6.76% due July 19, 2005
7.42% due October 1, 2005
7.57% due October 4, 2005
6.55% due August 2, 2006
8.75% due June 15, 2007
6.79% due March 2, 2009
6.75% due March 15, 2011
6.875% due September 30, 2011
Net discount on notes
Less amount classified as cur rent
2001
DECEMBER 31,
2000
(IN MILLIONS)
$
50
75
1,046
444
316
(111)
374
236
177
1,250
6
125
110
—
23
31
126
175
—
400
1,750
(14)
6,589
—
147
—
—
444
316
—
360
250
200
—
33
125
—
—
—
—
—
175
—
—
—
(1)
2,049
—
1999
645
—
—
444
316
—
—
250
200
—
37
125
—
75
—
—
—
175
150
—
—
(1)
2,416
—
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
2005
2006
2007 and thereafter
Total
$
—
—
358
775
689
4,886
$
6,708
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 bor row 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.
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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.
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 bor rowings 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.
The terms of this facility require repayment of the debt during the following years:
YEAR
2002
2003
2004
2005
2006
Total
(IN MILLIONS)
—
$
—
232
1,200
1,600
$ 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.
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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 merg e r. The fair values of the exchangeable
d e b e n t u res 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 re c o rded on these exchangeable debentures. However,
pursuant to the adoption of SFAS No. 133 effective Januar y 1, 2001, these debentures were 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 Chevro n Texaco Corporation common stock that is embedded in the debentures. Accord i n g l y, the debt portion of the
d e b e n t u res was reduced by $140 million as of August 17, 1999. This discount is being accreted using the effective intere s t
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.
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.
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DEBT ASSUMED
6.75% senior notes due 2011
6.55% senior notes due 2006
7.25% senior notes due 2005
7.57% senior notes due 2005
7.42% senior notes due 2005
FAIR VALUE OF
DEBT ASSUMED
(IN MILLIONS)
$ 400
129
116
33
24
EFFECTIVE RATE OF DEBT ASSUMED
6.8%
6.5%
6.3%
5.7%
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.
Interest Expense
Following are the components of interest expense for the years 2001, 2000 and 1999:
Interest based on debt outstanding
Accretion (amortization) of debt discount (premium), net
Facility and agency fees
Amortization of capitalized loan costs
Capitalized interest
Loss on debt retirement
Other
$
Total interest expense
$
220
155
2001
YEAR ENDED DECEMBER 31,
2000
(IN MILLIONS)
157
(4)
3
2
(3)
—
—
200
10
1
3
(3)
7
2
1999
108
(1)
2
2
(2)
—
—
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 . I N C O M E T A X E S
At December 31, 2001, Devon had the following carryforwards available to reduce future income taxes:
TYPES OF CARRYFOR WARD
Net operating loss - U.S. federal
Net operating loss - various states
Net operating loss - Canada
Net operating loss - international
Minimum tax credits
YEARS OF
EXPIRATION
2008 - 2021
2002 - 2014
2002 - 2008
Indefinite
Indefinite
CARRYFOR WARD
AMOUNTS
(IN MILLIONS)
22
$
60
$
3
$
$ 91
$ 118
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All of the carr yforward amounts shown above have been utilized for financial purposes to reduce the deferred tax liability.
The earnings (loss) before income taxes and the components of income tax expense (benefit) for the years 2001, 2000
and 1999 were as follows:
2001
YEAR ENDED DECEMBER 31,
2000
(IN MILLIONS)
1999
Earnings (loss) before income taxes:
U.S
Canada
International
Total
Current income tax expense:
U.S. federal
Various states
Canada
Other
Total current tax expense
Deferred income tax expense (benefit):
U.S. federal
Various states
Canada
Other
Total deferred tax expense (benefit)
Total income tax expense (benefit)
$
$
$
$
458
(357)
(17)
84
23
6
8
34
71
124
(32)
(145)
12
(41)
30
872
156
114
1,142
107
6
2
16
131
152
33
67
29
281
412
(313)
58
56
(199)
12
3
3
5
23
(119)
—
27
20
(72)
(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:
U.S. statutory tax (benefit) rate
Benefit from disposition of certain foreign assets
Financial expenses not deductible for income tax purposes
Nonconventional fuel source credits
State income taxes
Taxation on foreign operations
Other
Effective income tax (benefit) rate
YEARENDED DECEMBER 31,
2000
1999
2001
35%
—
14
(23)
5
12
(7)
36%
35%
(4)
1
(1)
1
2
2
36%
(35)%
—
3
(3)
1
7
2
(25)%
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:
Deferred tax assets:
Net operating loss car ryforwards
Minimum tax credit car ryforwards
Production payments
Long-term debt
Fair value of financial instruments
Other
Total deferred tax assets
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
ChevronTexaco Corporation common stock
Other
Total deferred tax liabilities
Net deferred tax liability
$
2001
39
118
—
6
7
37
207
(2,182)
(213)
(11)
(2,406)
$ (2,199)
DECEMBER 31,
2000
(IN MILLIONS)
123
85
—
17
—
95
320
(687)
(167)
(84)
(938)
(618)
1999
207
88
21
18
—
51
385
(500)
(172)
(32)
(704)
(319)
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71
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 carr y f o rw a rds available to offset future income taxes. The carry f o rw a rds include federal
net operating loss carry f o rw a rds, the majority of which do not begin to expire until 2008, state net operating loss carry f o rw a rds which
e x p i re primarily between 2002 and 2014, Canadian carr y f o rw a rds which expire primarily between 2002 and 2008, intern a t i o n a l
c a rry f o rw a rds which have no expiration and minimum tax credit carry f o rw a rds which have no expiration. The tax benefits of
c a rry f o rw a rds are re c o rded as an asset to the extent that management assesses the utilization of such carry f o rw a rds to be “more
likely than not.” When the future utilization of some portion of the carry f o rw a rds is determined not to be “more likely than not,” a
valuation allowance is provided to reduce the re c o rded tax benefits from such assets.
Devon expects the tax benefits from the net operating loss carr yforwards 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 car r yforwards.
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.
9 . T R U S T C O N V E R T I B L E P R E F E R R E D S E C U R I T I E S
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.
1 0 . S T O C K H O L D E R S ’ E Q U I T Y
The authorized capital stock of Devon consists of 400 million shares of common stock, par value $.10 per share (the
“Common Stock”), and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in
one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Effective August 17, 1999, Devon issued 1.5 million shares of 6.49% cumulative preferred stock, Series A, to holders of
PennzEnergy 6.49% cumulative preferred stock, Series A. Dividends on the preferred stock are cumulative from the date of
original issue and are payable quarterly, in cash, when declared by the Board of Directors. The preferred stock is redeemable
at the option of Devon at any time on or after June 2, 2008, in whole or in part, at a redemption price of $100 per share, plus
accrued and unpaid dividends to the redemption date.
In late September and early October 1999, Devon received $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.
D e v o n ’s Board of Directors has designated a cer tain number of shares of the pre f e rred stock as Series A Junior Part i c i p a t i n g
P re f e rred Stock (the “Series A Junior Pre f e rred Stock”) in connection with the adoption of the shareholder rights plan described
later in this note. Effective Januar y 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 Pre f e rred Stock issued or outstanding. The Series A Junior
P re f e rred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $10 or 100 times the
a g g regate per share amount of all dividends (other than stock dividends) declared on Common Stock since the immediately
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 72
72
p receding quar terly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior
P re f e rred Stock. Holders of the Series A Junior Pre f e rred Stock are entitled to 100 votes per share (subject to adjustment to pre v e n t
dilution) on all matters submitted to a vote of the stockholders. The Series A Junior Pre f e rred Stock is neither redeemable nor
c o n v e r tible. The Series A Junior Pre f e rred Stock ranks prior to the Common Stock but junior to all other classes of Pre f e rred 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.
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
NUMBER
OUTSTANDING
EXERCISE
PRICE
NUMBER
EXERCISABLE
WEIGHTED
AVERAGE
EXERCISE
PRICE
BALANCE AT DECEMBER 31, 1998
Options granted
Options assumed in the PennzEnergy merger
Options assumed in the Snyder merger
Options exercised
Options forfeited
BALANCE AT DECEMBER 31, 1999
Options granted
Options exercised
Options forfeited
BALANCE AT DECEMBER 31, 2000
Options granted
Options exercised
Options forfeited
5,520,656
1,564,108
2,081,894
979,220
(1,139,231)
(452,746)
8,553,901
1,624,800
(2,488,756)
(333,991)
7,355,954
2,600,650
(1,504,691)
(267,583)
$ 31.768
$ 31.736
$ 55.643
$ 35.182
$ 28.509
$ 36.369
$ 38.202
$ 51.430
$ 33.106
$ 60.354
$ 41.843
$ 62.808
$ 31.133
$ 62.774
4,079,125
$ 30.479
7,063,983
$ 39.547
6,024,796
$ 40.718
BALANCE AT DECEMBER 31, 2001
8,184,330
$ 41.089
5,515,958
$ 41.934
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% and 35.2%.
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73
The following table summarizes information about Devon’s stock options which were outstanding, and those which were
exercisable, as of December 31, 2001:
RANGE OF
EXERCISE
PRICES
$ 8.375-$26.501
$28.830-$33.381
$34.375-$39.773
$40.190-$49.950
$50.142-$59.813
$60.150-$89.660
NUMBER
OUTSTANDING
442,204
1,314,346
3,445,957
454,980
2,028,308
498,535
8,184,330
OPTIONS OUTSTANDING
WEIGHTED
AVERAGE
REMAINING
LIFE
2.38 Years
5.29 Years
7.04 Years
4.01 Years
6.66 Years
5.36 Years
6.15 Years
WEIGHTED
AVERAGE
EXERCISE
PRICE
$ 23.014
$ 30.726
$ 35.308
$ 45.941
$ 53.177
$ 70.788
$ 41.089
OPTIONS EXERCISABLE
NUMBER
EXERCISABLE
442,204
1,239,114
1,569,779
444,996
1,329,064
490,801
5,515,958
WEIGHTED
AVERAGE
EXERCISE
PRICE
$ 23.014
$ 30.713
$ 35.818
$ 45.916
$ 53.865
$ 70.954
$ 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,
2000
2001
1999
Net earnings (loss) available to common shareholders:
As reported
Pro forma
Net earnings (loss) per share available to common shareholders:
As reported:
Basic
Diluted
Pro forma:
Basic
Diluted
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
$
$
$
$
$
$
93
79
0.73
0.72
0.62
0.61
720
702
5.66
5.50
5.51
5.36
(158)
(173)
(1.68)
(1.68)
(1.85)
(1.85)
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.
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74
1 1 . F I N A N C I A L I N S T R U M E N T S
The following table presents the carr ying amounts and estimated fair values of Devon’s financial instruments at December
31, 2001, 2000 and 1999.
2001
2000
1999
CARRYING
AMOUNT
FAIR
VALUE
CARRYING
AMOUNT
FAIR
VALUE
CARRYING
AMOUNT
Investments
Oil and gas price hedge agreements
Interest rate swap agreements
Electricity hedge agreements
Foreign exchange hedge agreements
Embedded option in exchangeable debenture s
Long-term debt (including cur rent portion)
644
$
225
$
(9)
$
(12)
$
(4)
$
$
(34)
$ (6,589)
644
225
(9)
(12)
(4)
(34)
(6,699)
(IN MILLIONS)
606
—
—
—
—
—
(2,049)
606
(58)
—
—
(1)
—
(2,050)
634
—
—
—
—
—
(2,416)
FAIR
VALUE
634
(10)
—
—
(3)
—
(2,400)
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 carr ying 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.
YEAR
2002
YEAR
2002
2003
2004
OIL PRODUCTION
BBLS/DAY
26,350
PRICE/BBL
$ 23.27
GAS PRODUCTION
MCF/DAY
242,128
99,905
4,164
PRICE/MCF
2.99
$
3.35
$
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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 75
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.
75
OIL PRODUCTION
YEAR
2002
BBLS/DAY
20,000
FLOOR PRICE CEILING PRICE
PER
BBL
$ 23.00
PER
BBL
$ 28.19
GAS PRODUCTION
YEAR
2002
2003
MMBTU/DAY
442,574
345,000
FLOOR PRICE CEILING PRICE
PER
MMBTU
$ 3.34
$ 3.20
PER
MMBTU
$ 6.37
$ 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 Cur rency 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.
1 2 . R E T I R E M E N T P L A N S
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 Supplementar y
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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 76
76
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.
PENSION BENEFITS
2000
2001
1999
OTHER POSTRETIREMENT
BENEFITS
2000
2001
1999
Change in benefit obligation:
Benefit obligation at beginning of year
Service cost
Interest cost
Participant contributions
Amendments
Mergers and acquisitions
Special termination benefits
Settlement payments
Curtailment gain
Actuarial (gain) loss
Benefits paid
Benefit obligation at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Mergers and acquisitions
Employer contributions
Participant contributions
Settlement payments
Administrative expenses
Benefits paid
Fair value of plan assets at end of year
$ 165
5
13
–
5
16
3
(4)
(1)
17
(9)
210
155
(9)
17
6
–
(4)
–
(9)
156
156
7
11
–
4
–
–
–
(3)
(3)
(7)
165
158
3
–
1
–
–
–
(7)
155
Funded status
(54)
(10)
Unrecognized net actuarial (gain) loss
Unrecognized prior service cost
Unrecognized net transition (asset) obligation
Net amount recognized
The net amounts recognized in the consolidated
balance sheets consist of:
(Accrued) prepaid benefit cost
Additional minimum liability
Intangible asset
Accumulated other comprehensive loss
Net amount recognized
Assumptions:
Discount rate
Expected return on plan assets
Rate of compensation increase
35
6
–
$ (13)
$ (13)
(33)
5
28
$ (13)
10
1
(6)
(5)
(5)
(1)
1
–
(5)
(IN MILLIONS)
$
32
–
2
1
(1)
–
–
–
–
4
(5)
33
–
–
–
4
1
–
–
(5)
–
38
1
2
–
(2)
–
–
–
–
(3)
(4)
32
–
–
–
4
–
–
–
(4)
–
8
1
1
–
–
29
–
–
–
1
(2)
38
–
–
–
2
–
–
–
(2)
–
(33)
(32)
(38)
2
(1)
–
$ (32)
$ (32)
–
–
–
$ (32)
(2)
(1)
1
(34)
(34)
–
–
–
(34)
1
–
2
(35)
(35)
–
–
–
(35)
64
5
6
–
–
88
–
–
–
(3)
(4)
156
42
15
104
1
–
–
–
(4)
158
2
(3)
2
–
1
1
(3)
1
2
1
7.10%
8.27%
4.88%
7.65%
8.50%
5.00%
7.34%
8.37%
4.88%
7.15%
N/A
5.00%
7.65%
N/A
5.00%
7.32%
N/A
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:
PENSION BENEFITS
2000
2001
1999
OTHER POSTRETIREMENT
BENEFITS
2000
2001
1999
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Recognized net actuarial (gain) loss
Net periodic benefit cost
(IN MILLIONS)
$
$
5
13
(13)
1
1
7
7
11
(13)
–
–
5
5
6
(7)
–
–
4
$
$
–
2
–
–
–
2
1
2
–
–
–
3
1
1
–
–
–
2
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 77
77
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
POINT INCREASE
ONE-PERCENTAGE
POINT DECREASE
(IN MILLIONS)
Effect on total of service and interest cost components for 2001
Effect on year-end 2001 post-retirement benefit obligation
$
$
–
1
$
$
–
(1)
Devon has incurred certain post-employment 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 Post-Employment Benefits. The accrued post-employment 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.
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.
1 3 . C O M M I T M E N T S A N D C O N T I N G E N C I E S
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.
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78
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 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
2003
2004
2005
2006
Thereafter
Total minimum lease payments required
$
$
21
20
16
14
11
14
96
Total rental expense for all operating leases is as follows for the years ended December 31:
2001
2000
1999
(IN MILLIONS)
$
$
$
17
19
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 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.
1 4 . R E D U C T I O N O F C A R R Y I N G VA L U E O F O I L A N D G A S P R O P E R
T I E S
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 carr ying 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,
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 79
79
United States
Canada
Egypt
China
Total
2001
NET OF
TAXES
GROSS
GROSS
(IN MILLIONS)
1999
NET OF
TAXES
$
$
449
434
33
–
916
281
252
23
–
556
464
–
–
12
476
302
–
–
8
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
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.
1 5 . O I L A N D G A S O P E R A T I O N S
Costs Incurred
The following tables reflect the costs incur red in oil and gas property acquisition, exploration, and development activities:
Property acquisition costs:
Proved, excluding deferred income taxes
Deferred income taxes
Total proved, including deferred income taxes
Unproved, excluding deferred income taxes:
Business combinations
Other acquisitions
Deferred income taxes
Total unproved, including defer red income taxes
Exploration costs
Development costs
Property acquisition costs:
Proved, excluding deferred income taxes
Deferred income taxes
Total proved, including deferred income taxes
Unproved, excluding deferred income taxes:
Business combinations
Other acquisitions
Deferred income taxes
Total unproved, including defer red income taxes
Exploration costs
Development costs
TOTAL
YEAR ENDED DECEMBER 31,
2001
2000
(IN MILLIONS)
$ 2,975
84
$ 3,059
1,433
183
27
1,643
356
978
291
–
291
–
55
–
55
213
636
DOMESTIC
YEAR ENDED DECEMBER 31,
2001
2000
(IN MILLIONS)
292
79
371
–
158
27
185
166
726
177
–
177
–
35
–
35
117
466
CANADA
$
$
$
$
$
$
$
$
1999
3,002
132
3,134
84
40
–
124
158
336
1999
2,670
132
2,802
82
28
–
110
88
228
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 80
80
Property acquisition costs:
Proved, excluding defer red income taxes
Deferred income taxes
Total proved, including deferred income taxes
Unproved, excluding deferred income taxes:
Business combinations
Other acquisitions
Deferred income taxes
Total unproved, including defer red income taxes
Exploration costs
Development costs
Property acquisition costs:
Proved, excluding defer red income taxes
Deferred income taxes
Total proved, including deferred income taxes
Unproved, excluding deferred income taxes:
Business combinations
Other acquisitions
Deferred income taxes
Total unproved, including defer red income taxes
Exploration costs
Development costs
YEAR ENDED DECEMBER 31,
2001
2000
(IN MILLIONS)
1999
$
$
2,621
5
2,626
1,433
24
–
$ 1,457
126
$
168
$
70
–
70
–
17
–
17
55
57
29
–
29
–
9
–
9
37
30
INTERNATIONAL
YEAR ENDED DECEMBER 31,
2001
2000
(IN MILLIONS)
1999
$
$
$
$
$
62
–
62
–
1
–
1
64
84
44
–
44
–
3
–
3
41
113
303
–
303
2
3
–
5
33
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 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.
Oil, gas and natural gas liquids sales
Production and operating expenses
Depreciation, depletion and amortization
Amortization of goodwill
Reduction of carr ying value of oil and gas properties
Income tax expense
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent
barrel of production
Oil, gas and natural gas liquids sales
Production and operating expenses
Depreciation, depletion and amortization
Amortization of goodwill
Reduction of carr ying value of oil and gas properties
Income tax (expense) benefit
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent
barrel of production
TOTAL
YEAR ENDED DECEMBER 31,
2001
2000
1999
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
$
$
$
2,980
(731)
(838)
(34)
(1,003)
(159)
215
2,718
(597)
(663)
(41)
–
(572)
845
1,257
(378)
(390)
(16)
(476)
(25)
(28)
6.20
5.48
4.46
DOMESTIC
YEAR ENDED DECEMBER 31,
2001
2000
1999
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
$
$
$
2,260
(512)
(615)
(34)
(449)
(267)
383
2,168
(463)
(541)
(41)
–
(446)
677
6.47
5.73
CANADA
892
(254)
(294)
(16)
(464)
38
(98)
4.98
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 81
Oil, gas and natural gas liquids sales
Production and operating expenses
Depreciation, depletion and amortization
Reduction of carrying value of oil and gas properties
Income tax benefit (expense)
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent
barrel of production
Oil, gas and natural gas liquids sales
Production and operating expenses
Depreciation, depletion and amortization
Amortization of goodwill
Reduction of carr ying value of oil and gas properties
Income tax benefit (expense)
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent
barrel of production
81
YEAR ENDED DECEMBER 31,
2001
2000
1999
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
$
$
$
481
(137)
(164)
(434)
99
(155)
5.74
303
(64)
(64)
–
(80)
95
204
(63)
(64)
–
(38)
39
4.05
3.56
INTERNATIONAL
YEAR ENDED DECEMBER 31,
2001
2000
1999
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
$
$
$
239
(82)
(59)
–
(120)
9
(13)
5.08
247
(70)
(58)
–
–
(46)
73
161
(61)
(32)
–
(12)
(25)
31
5.38
3.06
1 6 . S U P P L E M E N T A L I N F O R M A T I O N O N O I L A N D G A S O P E R A T I O N S ( U N A U D I T E D )
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.”
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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 82
82
Proved reserves as of December 31, 1998
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 1999
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 2000
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 2001
Proved developed reserves as of:
December 31, 1998
December 31, 1999
December 31, 2000
December 31, 2001
Proved reserves as of December 31, 1998
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 1999
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 2000
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 2001
Proved developed reserves as of:
December 31, 1998
December 31, 1999
December 31, 2000
December 31, 2001
TOTAL
GAS
(BCF)
1,477
7
406
1,418
(304)
(54)
2,950
99
601
301
(426)
(67)
3,458
(315)
579
2,267
(498)
(14)
5,477
1,282
2,501
2,631
3,948
DOMESTIC
GAS
(BCF)
838
36
230
1,400
(221)
(8)
2,275
101
504
53
(355)
(57)
2,521
(262)
360
170
(376)
(14)
2,399
664
1,960
2,087
1,988
NATURAL
GAS
LIQUIDS
(MMBBLS)
33
3
4
33
(5)
–
68
3
6
–
(7)
(8)
62
6
9
52
(8)
–
121
19
52
46
88
NATURAL
GAS
LIQUIDS
(MMBBLS)
16
3
3
33
(4)
–
51
4
5
–
(6)
(8)
46
7
5
–
(6)
–
52
15
48
42
48
OIL
(MMBBLS)
235
12
13
273
(32)
(5)
496
(4)
34
24
(43)
(48)
459
(14)
31
166
(44)
(12)
586
180
301
261
324
OIL
(MMBBLS)
101
24
2
143
(18)
(3)
249
(3)
21
21
(29)
(33)
226
(25)
12
15
(26)
(11)
191
93
214
192
167
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 83
83
Proved reserves as of December 31, 1998
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 1999
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 2000
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 2001
Proved developed reserves as of:
December 31, 1998
December 31, 1999
December 31, 2000
December 31, 2001
Proved reserves as of December 31, 1998
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 1999
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 2000
Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
Proved reserves as of December 31, 2001
Proved developed reserves as of:
December 31, 1998
December 31, 1999
December 31, 2000
December 31, 2001
CANADA
GAS
(BCF)
602
(41)
53
12
(74)
(46)
506
(6)
65
27
(62)
(6)
524
(22)
139
2,097
(113)
–
2,625
583
501
508
1,923
NATURAL
GAS
LIQUIDS
(MMBBLS)
5
–
–
–
(1)
–
4
–
1
–
(1)
–
4
–
2
52
(2)
–
56
4
4
4
40
OIL
(MMBBLS)
39
(3)
–
3
(5)
(2)
32
3
3
3
(5)
–
36
–
5
133
(8)
–
166
33
29
30
124
INTERNATIONAL
OIL
(MMBBLS)
GAS
(BCF)
NATURAL
GAS
LIQUIDS
(MMBBLS)
95
(9)
11
127
(9)
–
215
(4)
10
–
(9)
(15)
197
11
14
18
(10)
(1)
229
54
58
39
33
37
12
123
6
(9)
–
169
4
32
221
(9)
(4)
413
(31)
80
–
(9)
–
453
35
40
36
37
12
–
1
–
–
–
13
(1)
–
–
–
–
12
(1)
2
–
–
–
13
–
–
–
–
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 84
84
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:
Future cash inflows
Future costs:
Development
Production
Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows
Future cash inflows
Future costs:
Development
Production
Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows
Future cash inflows
Future costs:
Development
Production
Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows
Future cash inflows
Future costs:
Development
Production
Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows
2001
TOTAL
DECEMBER 31,
2000
(IN MILLIONS)
1999
$
23,790
40,594
18,495
(2,228)
(8,424)
(3,403)
9,735
(4,421)
5,314
2001
(1,635)
(8,198)
(9,088)
21,673
(9,201)
12,472
DOMESTIC
DECEMBER 31,
2000
(IN MILLIONS)
$
(1,507)
(6,271)
(1,928)
8,789
(4,021)
4,768
1999
$
9,861
29,144
11,363
(793)
(3,774)
(759)
4,535
(1,734)
2,801
2001
(916)
(5,661)
(6,346)
16,221
(6,592)
9,629
CANADA
DECEMBER 31,
2000
(IN MILLIONS)
$
(751)
(3,894)
(1,072)
5,646
(2,335)
3,311
1999
$
9,011
5,686
1,666
(922)
(3,292)
(2,006)
2,791
(1,195)
1,596
2001
(85)
(616)
(1,967)
3,018
(1,241)
1,777
INTERNATIONAL
DECEMBER 31,
2000
(IN MILLIONS)
$
(66)
(515)
(204)
881
(321)
560
1999
$
4,918
5,764
5,466
(513)
(1,358)
(638)
2,409
(1,492)
917
$
(634)
(1,921)
(775)
2,434
(1,368)
1,066
(690)
(1,862)
(652)
2,262
(1,365)
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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 85
85
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.
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:
Beginning balance
Sales of oil, gas and natural gas liquids, net of production costs
Net changes in prices and production costs
Extensions, discoveries, and improved recovery, net of future
development costs
Purchase of reserves, net of future development costs
Development costs incurred during the period which reduced
future development costs
Revisions of quantity estimates
Sales of reserves in place
Accretion of discount
Net change in income taxes
Other, primarily changes in timing
Ending balance
1 7 . S E G M E N T I N F O R M A T I O N
YEAR ENDED DECEMBER 31,
2001
2000
(IN MILLIONS)
1999
$
12,472
(2,249)
(12,130)
693
2,483
364
(360)
(86)
1,774
3,406
(1,053)
5,314
$
4,768
(2,121)
9,753
2,742
618
183
420
(818)
581
(4,221)
567
12,472
1,414
(880)
1,737
316
2,882
234
(63)
(78)
147
(929)
(12)
4,768
Devon manages its business by countr y. 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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 86
86
1 7 . S E G M E N T I N F O R M A T I O N ( C O N T I N U E D )
Following is certain financial information regarding Devon's segments for 2001, 2000 and 1999. The revenues reported
are all from external customers.
AS OF DECEMBER 31, 2001:
Current assets
Property and equipment, net of accumulated depreciation,
depletion and amortization
Goodwill, net of amortization
Other assets
Total assets
Current liabilities
Long-term debt
Deferred tax liabilities
Other liabilities
Stockholders' equity
Total liabilities and stockholders' equity
YEAR ENDED DECEMBER 31, 2001:
REVENUES
Oil sales
Gas sales
Natural gas liquids sales
Other
Total revenues
COSTS AND EXPENSES
Lease operating expenses
Transportation costs
Production taxes
Depreciation, depletion and amortization of property
and equipment
Amortization of goodwill
General and administrative expenses
Expenses related to mergers
Interest expense
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Reduction in carr ying value of oil and gas properties
Total costs and expenses
U.S.
CANADA
INTERNATIONAL
TOTAL
(IN MILLIONS)
$
661
192
228
1,081
$
$
$
4,051
209
826
5,747
407
1,987
775
224
2,354
5,747
586
1,571
103
78
2,338
340
59
113
647
34
98
–
139
–
1
449
1,880
4,248
1,928
33
6,401
367
4,602
1,316
20
96
6,401
146
307
28
8
489
110
24
3
166
–
15
1
81
11
1
434
846
729
69
10
1,036
145
–
51
31
809
1,036
226
12
1
9
248
81
–
1
63
–
(2)
–
–
2
–
120
265
9,028
2,206
869
13,184
919
6,589
2,142
275
3,259
13,184
958
1,890
132
95
3,075
531
83
117
876
34
111
1
220
13
2
1,003
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
Deferred
Total income tax expense (benefit)
Earnings (loss) before cumulative effect of change in
accounting principle
Cumulative effect of change in accounting principle
Net earnings (loss)
Capital expenditures
29
92
121
337
49
386
8
(145)
(137)
(220)
–
(220)
34
12
46
(63)
–
(63)
71
(41)
30
54
49
103
1,356
3,774
196
5,326
$
$
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 87
87
U.S.
CANADA
INTERNATIONAL
TOTAL
(IN MILLIONS)
AS OF DECEMBER 31, 2000:
Current assets
Property and equipment, net of accumulated depreciation,
$
645
depletion and amortization
Other assets
Total assets
Current liabilities
Long-term debt
Deferred tax liabilities
Other liabilities
Stockholders' equity
Total liabilities and stockholders' equity
YEAR ENDED DECEMBER 31, 2000:
REVENUES
Oil sales
Gas sales
Natural gas liquids sales
Other
Total revenues
COSTS AND EXPENSES
Lease operating expenses
Transportation costs
Production taxes
Depreciation, depletion and amortization of property
and equipment
Amortization of goodwill
General and administrative expenses
Expenses related to mergers
Interest expense
Effects of changes in foreign currency exchange rates
Total costs and expenses
Earnings before income tax expense
INCOME TAX EXPENSE
Current
Deferred
Total income tax expense
Net earnings
Capital expenditures
3,640
964
5,249
449
1,902
537
259
2,102
5,249
727
1,305
136
58
2,226
319
42
102
565
41
81
60
144
–
1,354
872
113
185
298
574
893
$
$
$
$
$
79
586
–
665
74
147
69
1
374
665
116
169
18
5
308
52
11
1
65
–
10
–
10
3
152
156
2
67
69
87
210
684
52
946
106
–
21
18
801
946
236
11
–
3
250
70
–
–
63
–
2
–
1
–
136
114
16
29
45
69
934
4,910
1,016
6,860
629
2,049
627
278
3,277
6,860
1,079
1,485
154
66
2,784
441
53
103
693
41
93
60
155
3
1,642
1,142
131
281
412
730
203
184
1,280
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 88
88
1 7 . S E G M E N T I N F O R M A T I O N ( C O N T I N U E D )
U.S.
CANADA
INTERNATIONAL
TOTAL
(IN MILLIONS)
AS OF DECEMBER 31, 1999:
Current assets
Property and equipment, net of accumulated depreciation,
$
391
depletion and amortization
Other assets
Total assets
Current liabilities
Long-term debt
Deferred tax liabilities (assets)
Other liabilities
Stockholders' equity
Total liabilities and stockholders' equity
YEAR ENDED DECEMBER 31, 1999:
REVENUES
Oil sales
Gas sales
Natural gas liquids sales
Other
Total revenues
COSTS AND EXPENSES
Lease operating expenses
Transportation costs
Production taxes
Depreciation, depletion and amortization of property
and equipment
Amortization of goodwill
General and administrative expenses
Expenses related to mergers
Interest expense
Effects of changes in foreign currency exchange rates
Distributions on preferred securities of subsidiary trust
Reduction of carrying value of oil and gas properties
Total costs and expenses
Earnings (loss) before income tax expense (benefit) and
extraordinary item
INCOME TAX EXPENSE (BENEFIT)
Current
Deferred
Total income tax expense (benefit)
Net earnings (loss) before extraordinary item
Extraordinary loss
Net earnings (loss)
Capital expenditures
3,425
944
4,760
357
2,077
340
318
1,668
4,760
332
502
58
15
907
189
22
43
309
16
69
17
84
–
7
464
1,220
(313)
15
(119)
(104)
(209)
(4)
(213)
686
$
$
$
$
$
69
468
–
537
45
339
2
3
148
537
80
114
10
5
209
50
12
1
65
–
12
–
24
(13)
–
–
151
58
3
27
30
28
–
28
92
130
531
138
799
65
–
(18)
47
705
799
149
12
–
1
162
60
–
1
32
–
–
–
1
–
–
12
106
56
5
20
25
31
–
31
105
590
4,424
1,082
6,096
467
2,416
324
368
2,521
6,096
561
628
68
21
1,278
299
34
45
406
16
81
17
109
(13)
7
476
1,477
(199)
23
(72)
(49)
(150)
(4)
(154)
883
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 89
89
1 8 . S U P P L E M E N TA L Q U A R T E R L Y F I N A N C I A L I N F O R M AT I O N ( U N A U D I T E D )
Following is a summary of the unaudited interim results of operations for the years ended December 31, 2001 and 2000.
Oil, gas and natural gas liquids sales
Total revenues
Net earnings (loss)
Net earnings (loss) per common share:
Basic
Diluted
Oil, gas and natural gas liquids sales
Total revenues
Net earnings
Net earnings per common share:
Basic
Diluted
FIRST
QUARTER
SECOND
QUARTER
2001
THIRD
QUARTER
FOURTH
QUARTER
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
1,011
1,024
400
3.08
2.96
710
725
136
1.03
1.01
571
586
85
0.65
0.64
688
740
(518)
(4.13)
(4.13)
FIRST
QUARTER
SECOND
QUARTER
2000
THIRD
QUARTER
FOURTH
QUARTER
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
548
560
105
0.81
0.80
636
649
153
1.19
1.17
695
725
165
1.27
1.22
839
850
307
2.37
2.27
$
$
$
$
$
$
$
$
$
$
FULL
YEAR
2,980
3,075
103
0.73
0.72
FULL
YEAR
2,718
2,784
730
5.66
5.50
The second, third and fourth quarters of 2001 include $77 million, $10 million and $916 million, respectively, of
reductions of carr ying 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 incur red 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.
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1 9 . S U B S E Q U E N T E V E N T A N D P R O F O R M A F I N A N C I A L I N F O R M AT I O N ( U N A U D I T E D )
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.
Calculation and preliminary allocation of purchase price:
Shares of Devon common stock issued to Mitchell stockholders
Average Devon stock price
Fair value of common stock issued
Cash paid to Mitchell stockholders, calculated at $31 per outstanding
common share of Mitchell
Fair value of Devon common stock and cash to be issued to Mitchell
stockholders
Plus estimated acquisition costs incur red
Plus fair value of Mitchell employee stock options assumed by Devon
Total purchase price
Plus fair value of liabilities assumed by Devon:
Current liabilities
Long-term debt
Other long-term liabilities
Deferred income taxes
Total purchase price plus liabilities assumed
Fair value of assets acquired by Devon:
Current assets
Proved oil and gas properties
Unproved oil and gas properties
Gas services facilities and equipment
Other property and equipment
Other assets
Goodwill (none deductible for income tax purposes)
Total fair value of assets acquired
(IN MILLIONS,
EXCEPT SHARE PRICE)
30
50.95
1,507
1,567
3,074
90
25
3,189
305
363
76
802
4,735
193
1,456
696
840
3
57
1,490
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 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.
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 91
91
- 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 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.
Balance sheet data:
Property and equipment, net
Investment in common stock of ChevronTexaco Corporation
Goodwill
Total assets
Debentures exchangeable into shares of ChevronTexaco Corporation common stock
Other long-term debt
Stockholders’ equity
Proved reserves:
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
MMBoe
Standardized measure of discounted future net cash flows
PRO FORMA
INFORMATION
AS OF
DECEMBER 31, 2001
(DOLLARS IN MILLIONS)
$ 11,872
636
3,698
17,784
649
7,882
4,694
602
7,186
211
2,011
6,185
$
6994Pg29_92_26mar02 6/21/04 11:44 AM Page 92
92
PRO FORMA INFORMATION
YEAR ENDED DECEMBER 31,
2001
2000
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS AND PRODUCTION VOLUMES)
REVENUES
Oil sales
Gas sales
Natural gas liquids sales
Gas services revenue
Other
Total revenues
COSTS AND EXPENSES
Lease operating expenses
Transportation costs
Production taxes
Gas services costs and expenses
Depreciation, depletion and amortization of property and equipment
Amortization of goodwill
General and administrative expenses
Expenses related to mergers
Interest expense
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Reduction of carr ying value of oil and gas properties
Total costs and expenses
Earnings before income tax expense and cumulative effect of change in accounting
principle
INCOME TAX EXPENSE
Current
Deferred
Total income tax expense
Earnings before cumulative effect of change in accounting principle
Cumulative effect of change in accounting principle
Net earnings
Preferred stock dividends
Net earnings applicable to common stockholders
Net earnings before cumulative effect of change in accounting principle per
average common share outstanding:
Basic
Diluted
Net earnings per average common share outstanding:
Basic
Diluted
Weighted average common shares outstanding - basic
Weighted average common shares outstanding - diluted
Production volumes:
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
MMBoe
$
$
$
$
$
$
1,232
3,145
308
1,169
92
5,946
769
155
149
1,038
1,393
34
202
1
508
21
16
1,155
5,441
505
108
68
176
329
49
378
10
368
2.03
2.00
2.35
2.30
157
164
58
810
17
210
1,384
2,522
342
1,202
47
5,497
640
119
129
984
1,192
41
205
60
495
3
–
–
3,868
1,629
173
412
585
1,044
–
1,044
10
1,034
6.62
6.45
6.62
6.45
156
161
54
708
16
188
6994pg93_100_26mar02 6/21/04 11:46 AM Page 93
B O A R D O F D I R E C T O R S
93
John W. Nichols, 87, as a co-founder of
Devon, he was named Chairman Emeritus
in 1999. Nichols was Chairman of the
Board of Directors since Devon began
operations in 1971 until 1999. He is a
founding partner of Blackwood & Nichols
Co., which put together the first public oil
and gas drilling fund ever registered with
the Securities and Exchange Commission. Nichols is a non-
practicing Certified Public Accountant.
David M. Gavrin, 67, has been a Dire c t o r
of Devon since 1979 and serves as the
C h a i rman of the Compensation and Stock
Option Committee. He has been a Dire c t o r
of United American Energy Corp., an
independent power pro d u c e r, since 1992,
and MetBank Holding Corporation since
1998. From 1978 to 1988, Gavrin serv e d
as a General Partner of Wi n d c rest Partners. He previously was
an officer of Drexel Burnham Lambert Incorporated.
J. Larry Nichols, 59, a co-founder of
Devon, was named Chairman of the
Board of Directors in 2000. He has been
a Director since 1971, President since
1976 and Chief Executive Officer since
1980. Nichols is a Director of the
Domestic Petroleum Council, National
Association of Manufacturers, Indepen-
dent Petroleum Association of America, Natural Gas Supply
Association, Independent Petroleum Association of New
Mexico, Oklahoma Independent Petroleum Association and
the National Petroleum Council. He serves on the Board of
Governors of the American Stock Exchange. Nichols also
serves on the boards of BOK Financial Corporation, Smedvig
asa and Baker Hughes Incorporated. He has a degree in
geology from Princeton University and a law degree from the
University of Michigan.
Thomas F. Ferguson, 65, has been a
member of Devon’s board since 1982
and is Chairman of the Audit Committee.
He is the Managing Director of United Gulf
Management Ltd., a wholly-owned
subsidiary of Kuwait Investment Projects
Company KSC. Ferguson re p re s e n t s
Kuwait Investment Projects Company on
the boards of various companies in which it invests, including
Baltic Transit Bank in Latvia and Tunis International Bank in
Tunisia. Ferguson is a Canadian qualified Certified General
Accountant and was formerly employed by the Economist
Intelligence Unit of London as a financial consultant.
Michael E. Gellert, 70, has been a board
member since 1971 and ser ves as
Chairman of the Nominating Committee.
Gellert is a General Partner of Windcrest
Partners, a private investment partner-
ship in New York City, having held that
position since 1967. From 1958 until his
retirement in 1989, Gellert served in
executive capacities with Drexel Burnham Lambert Incorpo-
rated and its predecessors in New York City. In addition to
serving as a Director of Devon, Gellert also serves on the
boards of High Speed Access Corporation, Humana Inc.,
Seacor Smit Inc., Six Flags Inc., Travelers Series Fund, Inc.,
Dalet Technologies and Smith Barney World Funds. He is
also a member of the Putnam Trust Company Advisory Board
to the Bank of New York.
John A. Hill, 60, was elected to the
Board of Directors in 2000. Prior to that,
he served as a Director of Santa Fe
Snyder Corporation. Hill has been with
First Reserve Corporation, an oil and gas
investment management company, since
1983 and currently serves as the Vice
Chairman and Managing Director. Prior to
joining First Reserve, he was President, Chief Executive
Officer and Director of Marsh & McLennan Asset Manage-
ment Company and served as the Deputy Administrator of the
Federal Energy Administration during the Ford administration.
Hill is Chairman of the Board of Trustees of the Putnam Funds
in Boston, a Trustee of Sarah Lawrence College, a Director of
TransMontaigne Inc., and various companies controlled by
First Reserve Corporation and Continuum Health Partners.
6994pg93_100_26mar02 6/21/04 11:46 AM Page 94
94
B O A R D O F D I R E C T O R S
William J. Johnson, 67, was elected to
the Board of Directors in 1999. Johnson
has been a private consultant for the oil
and gas industry for the past five years.
He is President and a Director of JonLoc
Inc., an oil and gas company, which he
and his family are sole shareholders.
Johnson has served as a Director of
Tesoro Petroleum Corp. since 1996. From 1991 to 1994,
Johnson was President, Chief Operating Officer and a Director
of Apache Corporation.
Robert A. Mosbacher, Jr., 50, was
elected to the Board of Directors in 1999.
Since 1986, he has served as President
and Chief Executive Officer of Mosbacher
Energy Company and, since 1995, as
Vice Chairman of Mosbacher Power
G roup. Mosbacher was previously a
Director of PennzEnergy Company and
served on the Executive Committee. He currently serves as a
Director of JPMorgan Chase and Company and is on the
Executive Committee of the U.S. Oil & Gas Association.
Robert B. Weaver, 63, was elected to
the Board of Directors in 1999. He
served as an Energy Finance Specialist at
Chase Manhattan Bank, N.A., where he
was in charge of its worldwide energy
group from 1981 until his retirement in
1994. Weaver was previously a Director
of PennzEnergy Company beginning in
1998, where he served as Chairman of the Audit Committee
and was a member of the Compensation Committee.
Michael M. Kanovsky, 53, was elected
to the Board of Directors in 1998.
Kanovsky was a co-founder of Nor t h s t a r
E n e rgy Corporation, acquired by Devon in
1998, and ser ved on its Board of
D i rectors since 1982. Kanovsky
is
P resident of Sky Energy Corporation, a
privately held energy corporation. He
continues to be active in the Canadian energy industry and is
c u rrently a Director of ARC Resources Ltd. and Bonavista
P e t roleum Corporation.
J. Todd Mitchell, 43, was elected to the
Board of Directors in January 2002. He
previously was a member of the Board of
Directors of Mitchell Energy & Develop-
ment Corp. from 1993 to 2002. Mitchell
has served as President of GPM, Inc., a
family-owned investment company, since
1998 and as President and Geologist to
Dolomite Resources, Inc., a privately owned mineral
exploration and investments company, since 1987. He has
been Chairman of Rock Solid Images, a privately owned
seismic data analysis software company, since 1998.
6994pg93_100_26mar02 6/21/04 11:46 AM Page 95
95
C O R P O R A T E O F F I C E R S
Group
Brian J. Jennings, 41, was elected
Senior Vice President – Corporate
Development in 2001. He joined Devon in
2000 as Vice President – Corporate
Finance. Prior to joining Devon, Jennings
was a Managing Director in the Energy
of
Banking
Investment
PaineWebber, Inc. He began his banking
career at Kidder, Peabody in 1989, before moving to Lehman
Brothers in 1992, and later to PaineWebber in 1995.
Jennings specialized in providing strategic advisory and
corporate finance services to public and private companies in
the E&P and oilfield service sectors. He began his energy
career with ARCO International Oil & Gas, a subsidiary of
Atlantic Richfield Company. Jennings received his bachelor’s
of science degree in petroleum engineering from the Univer-
sity of Texas at Austin and his master’s of business adminis-
tration from the University of Chicago’s Graduate School of
Business.
J. Michael Lacey, 56, was elected
Senior Vice President – Exploration and
Production in 1999. Lacey had previously
joined Devon as Vice President of
Operations and Exploration in 1989. Prior
to his employment with Devon, Lacey
served as General Manager in Tenneco
Oil Company’s Mid–Continent and Rocky Mountain Divisions.
He is a registered professional engineer, and a member of
the Society of Petroleum Engineers and the American Associ-
ation of Petroleum Geologists. Lacey holds both undergrad-
uate and graduate degrees in petroleum engineering from the
Colorado School of Mines.
Duke R. Ligon, 60, was elected Senior
Vice President – General Counsel in
1999. He had previously joined Devon as
Vice President – General Counsel in
1997. In addition to Ligon’s primary role
of managing the company’s corporate
legal matters (including litigation), he has
direct involvement with governmental affairs, purchasing and
Devon’s merger and acquisition activities. Prior to joining
Devon, Ligon practiced energy law for 12 years, most recently
as a partner at the law firm of Mayer, Brown & Platt in New
York City. In addition, he was a Senior Vice President and
Managing Director for investment banking at Bankers Trust
Company in New York City for 10 years. Ligon also served for
three years in various positions with the U. S. Departments
of the Interior and Treasur y, as well as the Department of
Energy. He holds an undergraduate degree in chemistry from
Westminister College and a law degree from the University of
Texas School of Law.
Marian J. Moon, 51, was elected Senior
Vice President – Administration in 1999.
She is responsible for Human Resourc e s ,
O ffice Administration, Information Te c h -
n o l o g y, Process Development and Corporate
G o v e rnance. Moon has been with Devon for
17 years, serving in various capacities,
including Manager of Corporate Finance. Prior to joining Devon,
she was employed by Amarex, Inc., for 11 years, where she
s e rved most recently as Tre a s u re r. Moon is a member of the
American Society of Corporate Secretaries. She is a graduate of
Valparaiso University.
6994pg93_100_26mar02 6/21/04 11:46 AM Page 96
96
C O R P O R A T E O F F I C E R S
John Richels, 50, was elected Senior
Vice President – Canadian Division in
2001. Richels was previously Chief
Executive Officer of Northstar Energ y
Corporation, acquired by Devon in 1998.
He ser ved as Nor t h s t a r ’s Executive Vi c e
P resident and Chief Financial Officer fro m
1996 to 1998 and was on the Board of Directors from 1993
to 1996. Prior to joining Nort h s t a r, Richels was Managing
P a rt n e r, Chief Operating Partner and a member of the
Executive Committee of the Canadian–based national law firm ,
Bennett Jones. He also ser ved, on a secondment fro m
Bennett Jones, as General Counsel of the XV Olympic Wi n t e r
Games Organizing Committee in Calgary, Alberta. Richels
p reviously served as a Director of a number of publicly traded
companies and is a member of the Board of Governors of the
Canadian Association of Petroleum Producers and the Mount
Royal College Foundation. He holds a bachelor’s degree in
economics from York University and a law degree from the
University of Wi n d s o r.
Darryl G. Smette, 54, was elected Senior
Vice President – Marketing in 1999.
Smette previously held the position of
Vice President – Marketing and Adminis-
trative Planning since 1989. He joined
Devon in 1986 as Manager of Gas
marketing
Smette’s
Marketing.
b a c k g round includes 15 years with Energy Reser ves Gro u p ,
Inc./BHP Petroleum (Americas), Inc., most recently as Dire c t o r
of Marketing. He is also an oil and gas industry instru c t o r,
a p p roved by the University of Texas Department of Continuing
Education. Smette is a member of the Oklahoma Independent
P roducers Association, Natural Gas Association of Oklahoma
and the American Gas Association. He holds an underg r a d-
uate degree from Minot State College and a master’s degre e
f rom Wichita State University.
William T. Vaughn, 55, was elected
Senior Vice President – Finance in 1999.
He previously served as Vice President of
Finance in charge of commercial banking
functions, accounting, tax and informa-
tion services since 1987. Prior to that, he
was Controller from 1983 to 1987.
Vaughn’s previous experience includes serving as Controller
of Marion Corporation for two years and employment with
Arthur Young & Co. for seven years, most recently as Audit
Manager. He is a Certified Public Accountant and a member
of the American Institute of Certified Public Accountants.
Vaughn graduated from the University of Arkansas with a
bachelor’s of science degree.
Rick D. Clark, 54, was elected Vice
P resident and General Manager –
Permian/Mid–Continent Division in 1999.
He previously ser ved as Pro d u c t i o n /
Operations Manager since joining Devon
in 1995, where he was responsible for
the company’s drilling and production
activities. Prior to joining Devon, Clark was employed by
Patrick Petroleum Company where he served as Executive
Vice President, Operations and Corporate Development since
1988. Prior to that, Clark worked in various production
engineering, reservoir engineering, financial and managerial
capacities for Ladd Petroleum Corporation and Conoco Inc.
He is a member of the Society of Petroleum Engineers. Clark
holds a degree in petroleum engineering from the Colorado
School of Mines.
Don D. DeCarlo, 45, was elected Vice
President and General Manager – Rocky
Mountain Division in 2000. He previously
served as Vice President and General
Manager, Rocky Mountain Division, for
Santa Fe Snyder Corporation. DeCarlo
began his professional career in 1978
with Tenneco Oil Company in Oklahoma City. In 1989 he
joined Santa Fe Energy Resources as an Engineering
Manager in Tulsa, Oklahoma. During his 11–year tenure with
Santa Fe, DeCarlo held management positions of increasing
responsibilities in Bakersfield, California, Midland, Texas and
most recently in Denver. He received a bachelor’s of science
degree in petroleum engineering from West Virginia Univer-
sity. DeCarlo is a member of the Society of Petroleum
Engineers and currently holds the position of Vice President
for the Independent Petroleum Association of the Mountain
States.
6994pg93_100_26mar02 6/21/04 11:46 AM Page 97
C O R P O R A T E O F F I C E R S
Janice A. Dobbs , 53, was elected
Corporate Secretary in 2001. She joined
Devon in 1999 as Manager of Corporate
G o v e rnance and Assistant Corporate
Secretary. From 1993 to 1999, Dobbs
served as the Corporate Secretary and
Compliance Manager of Chesapeake
Energy Corporation. From 1975 until her association with
Chesapeake, Dobbs was the Corporate/ Securities Legal
Assistant with the law firm of Andrews Davis Legg Bixler
Milsten & Price, Inc. in Oklahoma City. Prior to that, she was
the Corporate/Securities Legal Assistant with Texas Interna-
tional Petroleum Company. Dobbs is a Certified Legal
Assistant, an associate member of the American Bar Associ-
ation and a member of the American Society of Corporate
Secretaries.
Danny J. Heatly, 46, was elected Vice
President – Accounting in 1999. He had
p reviously ser ved as Controller since
1989. Prior to joining Devon, Heatly was
associated with Peat Marwick Main & Co.
(now KPMG LLP) in Oklahoma City for 10
years with various duties, including Senior
Audit Manager. He is a Certified Public Accountant and a
member of the American Institute of Certified Public Accoun-
tants and the Oklahoma Society of Certified Public Accoun-
tants. Heatly graduated with a bachelor’s of accountancy
degree from the University of Oklahoma.
97
Richard E. Manner, 55, was elected Vice
President – Information Services in 2000.
Inform a t i o n
Manner has been an
Technology professional for 25 years.
Prior to joining Devon, he was employed
by Unisys in Houston. There he served for
14 years in various positions, including
Director of Information Systems. Prior to
his tenure with Unisys, Manner spent two years with a
National Aeronautics and Space Administration contractor as
a software engineer, and eight years with AMF Tuboscope
where he supervised the design of oilfield inspection instru-
mentation and facilities. He is a registered professional
engineer and a member of the Society of Professional
Engineers. Manner received an electrical engineering degree
from the University of Oklahoma.
R. Alan Marcum , 35, was elected
Controller in 1999. Marcum has been
with Devon since 1995, most recently as
Assistant Controller. He is responsible for
international and operations accounting
for Devon. Prior to joining Devon, Marcum
was employed by KPMG Peat Marwick
(now KPMG LLP) as a Senior Auditor, with
responsibilities including special engagements involving due
diligence work, agreed upon procedures and SEC filings. He
holds a bachelor’s of science degree from East Central
University, where he majored in accounting and finance.
Marcum is a Certified Public Accountant and a member of the
Oklahoma State Society of Certified Public Accountants.
Gary L. McGee, 52, was elected Vice
P resident – Government Relations in
1999. He had previously ser ved as
Devon’s Treasurer and Controller. Prior to
joining Devon, McGee served as Vice
President of Finance with KSA Industries,
Inc., a private holding company with
various interests, including oil and gas
exploration. McGee also held various accounting positions
with Adams Resources and Energy Company and Mesa
Petroleum Company. McGee is a member of the Petroleum
Association of Wyoming and the New Mexico Oil & Gas
Association. He is a graduate of the University of Oklahoma,
where he received a degree in accounting.
6994pg93_100_26mar02 6/21/04 11:46 AM Page 98
98
C O R P O R A T E O F F I C E R S
Paul R. Poley, 48, was elected Vi c e
P resident – Human Resources in 2000.
Poley was previously employed by Fleming
Companies
in Oklahoma City, most
recently as Director of Human Resourc e s
Planning and Development. At Fleming, his
responsibilities included human re s o u rc e s
development, management succession,
strategic planning, perf o rmance management and training for
39,000 employees. Prior to his 11 years at Fleming, Poley was
Regional Personnel Manager for International Mill Service, Inc.
He is a member of the board of the Southwest Benefits
Association. Poley received his bachelor’s of arts degree in
sociology from Bucknell University.
Terrence L. Ruder, 49, was elected Vice
P resident and General Manager –
Marketing and Midstream Division in
2001. Ruder has been with Devon since
1999, most recently as President of
Thunder Creek Gas Ser vices, a gas
pipeline subsidiary located in Wyoming.
He has more than 25 years of energy
i n d u s t ry experience in both domestic and intern a t i o n a l
capacities. Prior to joining Devon, Ruder held a variety of
marketing and business development positions with BHP
Petroleum and BHP Power, most recently as Senior Vice
President and General Manager of BHP Power in Brazil. He
graduated with a bachelor’s of business administration
degree in finance from Wichita State University.
David J. Sambrooks, 43, was elected
Vice President and General Manager –
in 2001. He
I n t e rnational Division
previously served as Production Manager,
South America. Prior to the merger with
Devon, he served as General Manager of
International Business Development and
for
We s t e rn Hemisphere Production
Santa Fe Snyder Corporation. Sambrooks began his profes-
sional career in 1980 with Sun Exploration and Production
Company (later Oryx Energy) and held positions of increasing
responsibility in Houston, Corpus Christi, Texas and Midland,
Texas before joining Santa Fe Energy Resources in 1990.
During his 10–year tenure with Santa Fe, Sambrooks held
p ro g ressive positions in engineering and management
covering south Texas, offshore Gulf of Mexico, and beginning
in 1993, international. He received a bachelor’s of science
degree in mechanical engineering from the University of Texas
at Austin and a master’s of business administration from the
University of Houston.
William A. Van Wie, 56, was elected to
Vice President and General Manager – Gulf
Division in 1999. Van Wie previously ser v e d
as Senior Vice President and General
Manager – Off s h o re for PennzEnerg y. He
began his career as a Geologist for
Tenneco Oil Company’s Frontier Projects
Group in 1974. Following the sale of
Tenneco’s Gulf of Mexico properties to Chevron in 1988, he
joined that company as Division Geologist. In 1992, he
moved to Pennzoil Exploration and Production Company as
Vice President/Exploitation Manager. He then served as
Manager of Offshore Exploration for Amerada Hess Corpora-
tion, before rejoining Pennzoil in 1997. He is an active
member of
the American Association of Petro l e u m
Geologists, serves as a Trustee for the American Geological
Institute Foundation, is a Vice Chairman of Independent
Petroleum Association of America’s Offshore Committee and
is also a member of the National Ocean Industries Associa-
tion. Van Wie received his bachelor’s of science degree in
geology from St. Lawrence University in Canton, New York and
a master’s degree and Ph.D. in geology from the University of
Cincinnati.
6994pg93_100_26mar02 6/21/04 11:46 AM Page 99
99
C O R P O R A T E O F F I C E R S
for Devon’s
Vincent W. White, 44, was elected Vice
President – Communications and Investor
Relations in 1999. He has primar y
responsibility
investor
communications, media relations and
communications. White
employee
previously served as Director of Investor
Relations since 1993. Prior to joining Devon, he served as
Controller of Arch Petroleum Inc. and was an auditor with
KPMG Peat Marwick (now KPMG LLP). White is a Certified
Public Accountant and a member of the Petroleum Investor
Relations Association, the National Investor Relations
Institute and the American Institute of Cer tified Public
Accountants. He received his bachelor of accounting degree
from the University of Texas at Arlington.
Dale T. Wilson , 42, was elected
Treasurer of Devon in 1999. He has
primary responsibility for the company’s
treasury and risk management functions.
Prior to joining Devon, Wilson was
employed in the banking industry for 17
years, including Bank of America for 15
years as a Managing Director of the Energy Finance Group. He
has been active in oil and gas trade associations and is
currently a member of the Association for Financial Profes-
sionals. Wilson graduated from Baylor University with a
bachelor’s degree in finance and accounting.
6994pg93_100_26mar02 6/21/04 11:46 AM Page 100
100
G L O S S A R Y
British thermal unit (Btu): A measure of
heat value. An Mcf of natural gas is roughly
equal to one million Btu.
Block: Refers to a contiguous leasehold
position. In federal offshore waters, a block
is typically 5,000 acres.
Coalbed methane: An unconventional gas
resource that is present in certain coal
deposits.
Deepwater: In offshore areas, water depths
of greater than 600 feet.
Development well: A well drilled within the
area of an oil or gas reservoir known to be
productive. Development wells are relatively
low risk.
Net acres: Gross acres multiplied by one’s
fractional working interest in the property.
Pilot program: A small-scale test project
used to assess the viability of a concept
prior to committing significant capital to a
large-scale project.
Production: Natural resources, such as oil
or gas, taken out of the ground.
- Gross production: Total production before
deducting royalties.
- Net production: Gross production, minus
royalties, multiplied by one’s fractional
working interest.
Prospect: An area designated for the
potential drilling of development or
exploratory wells.
Dry hole: A well found to be incapable of
producing oil or gas in sufficient quantities to
justify completion.
Exploitation: Various methods of optimizing
oil and gas production or establishing
additional reserves from producing proper-
ties through additional drilling or the applica-
tion of new technology.
Exploratory well: A well drilled in an
unproved area, either to find a new oil or gas
reservoir or to extend a known reservoir.
Sometimes referred to as a wildcat.
Proved reserves: Estimates of oil, gas, and
natural gas liquids quantities thought to be
recoverable from known reservoirs under
existing economic and operating conditions.
Recavitate: The process of applying
pressure surges on the coal formation at the
bottom of a well in order to increase
fracturing, enlarge the bottomhole cavity and
thereby increase gas production.
Recompletion: The modification of an
existing well for the purpose of producing oil
or gas from a different producing formation.
Field: A geographical area under which one
or more oil or gas reservoirs lie.
Reservoir: A rock formation or trap
containing oil and/or natural gas.
Formation: An identifiable layer of rocks
named after its geographical location and
dominant rock type.
Royalty: The landowner’s share of the value
of minerals (oil and gas) produced on the
property.
Fracture, refracture: The process of
applying hydraulic pressure to an oil or gas
bearing geological formation to crack the
formation and stimulate the release of oil
and gas.
Gross acres: The total number of acres in
which one owns a working interest.
Increased density/infill: A well drilled in
addition to the number of wells permitted
under initial spacing regulations, used to
enhance or accelerate recover y, or prevent
the loss of proved reserves.
Independent producer: A non-integrated oil
and gas producer with no refining or retail
marketing operations.
Lease: A legal contract that specifies the
terms of the business relationship between
an energy company and a landowner or
mineral rights holder on a particular tract.
Natural gas liquids (NGLs): Liquid hydrocar-
bons that are extracted and separated from
the natural gas stream. NGLs products
include ethane, propane, butane and natural
gasoline.
SEC Case: The method for calculating future
net revenues from proved reserves as
established by the Securities and Exchange
Commission (SEC). Future oil and gas
revenues are estimated using essentially
fixed or unescalated prices. Future produc-
tion and development costs also are unesca-
lated and are subtracted from future
revenues.
SEC @ 10% or SEC 10% present value:
The future net revenue anticipated from
proved reserves using the SEC Case,
discounted at 10%.
Section 29 tax credit: A tax credit
prescribed by Section 29 of the Internal
Revenue Code. The credit is available for
certain types of gas production from a non-
conventional source, such as coal deposits.
Seismic: A tool for identifying underground
accumulations of oil or gas by sending
energy waves or sound waves into the earth
and recording the wave reflections. Results
indicate the type, size, shape and depth of
subsurface rock formations. 2D seismic
provides two-dimensional information while
3D creates three-dimensional pictures. 4C,
or four-component, seismic is a developing
technology that utilizes measurement and
i n t e r p retation of shear wave data. 4 C
seismic improves the resolution of seismic
images below shallow gas deposits.
Stepout well: A well drilled just outside the
proved area of an oil or gas reservoir in an
attempt to extend the known boundaries of
the reservoir.
Undeveloped acreage: Lease acreage on
which wells have not been drilled or
completed to a point that would permit the
production of commercial quantities of oil or
gas.
Unit: A contiguous parcel of land deemed to
cover one or more common reservoirs, as
determined by state or federal regulations.
Unit interest owners generally share propor-
tionately in costs and revenues.
Waterflood: A method of increasing oil
recoveries from an existing reservoir. Water
is injected through a special “water injection
well” into an oil producing formation to force
additional oil out of the reservoir rock and
into nearby oil wells.
Working interest: The cost-bearing
ownership share of an oil or gas lease.
Workover: The process of conducting
remedial work, such as cleaning out a well
bore, to increase or restore production.
VOLUME ACRONYMS
Bbl: A standard oil measurement that equals
one barrel (42 U.S. gallons)
- MBbl: One thousand bar rels
- MMBbl: One million bar rels
Mcf: A standard measurement unit for
volumes of natural gas that equals one
thousand cubic feet.
- MMcf: One million cubic feet
- Bcf: One billion cubic feet
BOD: Barrels of oil per day
Boe: A method of equating oil, gas and
natural gas liquids. Gas is converted to oil
based on its relative energy content at the
rate of six Mcf of gas to one barrel of oil.
Natural gas liquids are converted based
upon volume: one bar rel of natural gas
liquids equals one bar rel of oil.
- MBoe: One thousand bar rels of oil
equivalent
- MMBoe: One million bar rels of oil
equivalent
6994pgcvr 6/21/04 11:28 AM Page 3
I n v e s t o r I n f o r m a t i o n
Corporate Headquarters
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102-8260
Telephone: (405) 235-3611
Fax: (405) 552-4550
Permian/Mid-Continent,
Rocky Mountain and
MARKETING ANDMIDSTREAMDivisions
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102-8260
Gulf Division
Devon Energy Corporation
Devon Energy Tower
1200 Smith Street, Suite 3300
Houston, TX 77002
International Division
Devon Energy Corporation
840 Gessner, Suite 1100
Houston, TX 77024
Canadian Division
Devon Canada Corporation
3000, 400 - 3rd Avenue S.W.
Calgary, Alberta T2P 4H2
Shareholder Assistance
For information about transfer or exchange
of shares, dividends, address changes,
account consolidation, multiple mailings,
lost certificates and Form 1099:
Devon Energy Common Shareholders
EquiServe
Client Administration
150 Royall Street
Clinton, MA 02021
Toll Free: (800) 733-5001
http://www.equiserve.com
Northstar Exchangeable Shareholders
CIBC Mellon Trust Company
P.O. Box 1036
Adelaide Street Postal Station
Toronto, Ontario M5C 2K4
Toll Free: (800) 387-0825
Annual Meeting
Our annual stockholders’ meeting will be held
at 10:00 a.m. central time on Thursday,
May 16, 2002, in the Egbert Room at the
Renaissance Hotel, 10 North Broadway,
Oklahoma City, Oklahoma.
Independent Auditors
KPMG LLP
Oklahoma City, Oklahoma
Stock Trading Data
Devon Energy Corporation’s common stock
is traded on the American Stock Exchange
(symbol: DVN). There are approximately
31,000 shareholders of record.
The Northstar exchangeable shares are
traded on The Toronto Stock Exchange
(symbol: NSX). They are exchangeable on a
one-for-one basis for Devon common stock.
The exchangeable shares also qualify as a
domestic Canadian investment for Canadian
institutional holders and have the same
rights as Devon common stock.
Devon’s Website
To learn more about Devon Energy, visit our
website at:
http://www.devonenergy.com
Devon’s website contains press releases,
SEC filings, answers to commonly asked
questions, stock quote information and
more.
Investor Relations Contacts
Vince White, Vice President
Communications and Investor Relations
Telephone: (405) 552-4505
E-mail: vince.white@dvn.com
Analysts:
Zack Hager
Manager Investor Relations
Telephone: (405) 552-4526
E-mail: zack.hager@dvn.com
Media:
Brian Engel
Manager Public Affairs
Telephone: (405) 228-7750
E-mail: brian.engel@dvn.com
Individuals and Brokers:
Shea Snyder
Investor Relations Analyst
Telephone: (405) 552-4782
E-mail: shea.snyder@dvn.com
Publications
A copy of Devon’s Annual Report to the
Securities and Exchange Commission (For m
10-K) and other publications are available at
no charge upon request. Direct requests to:
Judy Roberts
Telephone: (405) 552-4570
Fax: (405) 552-7818
E-mail: judy.roberts@dvn.com
C o m m o n S t o c k T r a d i n g D a t a
Quarter
High
Low
Last
Volume
2000
First
Second
Third
Fourth
2001
First
Second
Third
Fourth
$ 48.56
$ 60.94
$ 62.56
$ 64.74
$ 65.75
$ 62.65
$ 55.25
$ 41.25
31.38
43.75
42.56
48.00
52.30
48.50
30.55
31.45
48.56
56.19
60.15
60.97
58.20
52.50
34.40
38.65
23,705,600
38,676,300
62,874,500
52,239,500
60,614,200
66,350,200
93,386,100
81,883,800
6994pgcvr 6/21/04 11:28 AM Page 4
D e v o n E n e r g y C o r p o r a t i o n
20 North Bro a d w a y
Oklahoma City, OK 73102-8260
(405) 235-3611 Fax (405) 552-4550
w w w. d e v o n e n e rg y. c o m