Devon 1998 annual report

Devon Energy
...Emerging Opportunities
1998 ANNUAL REPORT
Vanishing Barriers...
D E V O N E N E R G Y C O R P O R AT I O N
20 North Broadway, Suite 1500
Oklahoma City, Oklahoma 73102-8260
Telephone (405) 235-3611
Fax (405) 552-4667
DEVONENERGYCORPORATION—1998ANNUALREPORT

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 state-
ments 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.
Devon Energy Corporation is an oil and gas explo-
ration and production company with its headquarters
in Oklahoma City, Oklahoma. We produce and sell oil
and gas from wells located primarily in New Mexico,
Texas and Wyoming in the United States, and Alberta
and British Columbia in Canada.
We strive to build value per share by:
• Purchasing producing oil and gas properties,
• Exploring for undiscovered oil and gas reserves, and
• Optimizing production from our oil and gas properties.
Devon Energy Corporation 85
Common Stock Trading Data
Investor Information
CORPORATE HEADQUARTERS
Devon Energy Corporation
20 North Broadway, Suite 1500
Oklahoma City, OK 73102-8260
Telephone: (405) 235-3611
Fax: (405) 552-4667
WHOLLY-OWNED SUBSIDIARY
Northstar Energy 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 consolida-
tion, multiple mailings, lost certifi-
cates and Form 1099:
Devon Energy Common Shareholders
EquiServe
Client Administration
Mail Stop 45-02-62
P.O. Box 1865
Boston, MA 02105-1865
Toll Free: 1-800-733-5001
World Wide Web:
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: 1-800-387-0825
ANNUAL MEETING
Our annual stockholders’ meeting
will be held at 11:00 a.m. CST on
Wednesday, May 19, 1999, in the
20th Century Ballroom, The Westin
Hotel, One North Broadway,
Oklahoma City, Oklahoma.
INVESTOR RELATIONS CONTACTS
Analysts and Media:
Vince White, Director of
Investor Relations
Telephone: (405) 235-3611
E-mail: whitev@dvn.com
Individuals and Brokers:
Michael Prince
Telephone: (405) 552-4526
E-mail: princem@dvn.com
News By Fax:
Faxed copies of quarterly earnings
releases and other press releases can
be requested 24 hours a day by call-
ing 1-800-758-5804, Ext.118040.
Publications:
A copy of Devon’s Annual Report to
the Securities and Exchange
Commission (Form 10-K) and other
publications are available at no charge
upon request. Direct requests to:
Shareholder Services
Telephone: (405) 552-4570
Fax: (405) 552-4667
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) since it
became public in 1988. There are
approximately 840 shareholders of
record.
The Northstar exchangeable shares
have traded on The Toronto Stock
Exchange (symbol: NSX) since
December 15, 1998. 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, commonly asked questions,
stock quote information and more.
QUARTER HIGH LOW LAST VOLUME
1997
First 38 7⁄8 29 1⁄2 30 4,457,800
Second 38 1⁄2 27 3⁄8 36 3⁄4 5,619,200
Third 45 1⁄4 36 1⁄8 44 3,851,150
Fourth 49 1⁄8 35 38 1⁄2 4,460,400
1998
First 41 1⁄8 32 7⁄8 38 7⁄8 5,542,900
Second 40 1⁄2 32 5⁄8 34 15⁄16 6,144,200
Third 36 5⁄8 26 1⁄8 32 15⁄16 10,170,200
Fourth 36 11⁄16 27 3⁄4 30 11⁄16 9,016,800

Letter To Shareholders
Low oil and gas prices for 1998 were no barrier to Devon in its search
for emerging opportunities. President and Chief Executive Ofﬁcer Larry
Nichols discusses achievements and challenges of the year.
Five-Year Highlights
Financial Performance
Devon set an all-time production record in 1998, but low prices led
to a net loss.
CEO Interview
Larry Nichols answers your questions.
Portfolio of Oil and Gas Properties
An expanding property base yields growth opportunities. Devon gives
operating statistics by area and key property highlights.
Index to Financial Section
Biographies of Directors and Ofﬁcers
Glossary of Terms
Common Stock Trading Data
and Investor Information
Inside Devon Energy
3
6
7
9
13
25
81
84
85

2 1998 Annual Report
Over the last ﬁve years, Devon has more than doubled both proved oil and
gas reserves and annual oil and gas production.
* Presented in U.S. convention (net of royalties).
All data restated to reﬂect Devon and Northstar‘s combined results.
Proved Oil and Gas Reserves
(MMBoe*)
93 94 95 96 97 98
350
300
250
200
150
100
50
0
299
112
Annual Oil and Gas Production
(MMBoe*)
93 94 95 96 97 98
40
35
30
25
20
15
10
5
36
14

Dear Fellow Shareholders
The short-term outlook for oil prices was not promising.
Demand for oil was falling due to faltering economic growth
in Asia. Supply was increasing due primarily to higher OPEC
production. As a result, worldwide oil inventories were
growing. Indeed, during 1998 oil prices plummeted to levels
not seen since the early 1980’s. Falling by more than 60%
from the 1997 high of more than $23.00 per barrel, oil prices
plummeted to less than $9.00 per barrel in late 1998.
Simultaneously, North American natural gas prices softened
due to unseasonably warm winter weather. The impact on
Devon’s revenues and earnings was not subtle. In spite of setting our eleventh
consecutive record for total annual oil and gas production, low oil and gas prices
significantly reduced Devon’s 1998 revenues. Low prices also caused us to record an
$88 million, non-cash impairment charge to the book value of our oil and gas
properties. As a result, Devon reported a net loss for 1998 of $60 million, or $1.25
per share.
However, this environment also led to our most important achievement of the
year—our December 1998 merger with Northstar Energy Corporation. Low product
prices left this Canadian oil and gas producer without the financial resources to fully
realize the potential of its highly attractive oil and gas property base. Accordingly,
Northstar’s management began to look for a financially strong merger partner. Devon,
with its pristine balance sheet and strong desire to access growth opportunities in
Canada, was the ideal candidate.
In my letter to you of one year ago, I expressed
cautious optimism about Devon’s future. Caution
due to a weakening environment for oil prices.
Optimism because of the resulting opportunities
we anticipated for financially strong companies
such as Devon. Both the caution and the optimism
proved to be justified.
J. Larry Nichols

On December 10, 1998, following overwhelming approval by the shareholders of
both companies, Devon completed the largest transaction in its history. We issued 16.1
million Devon common equivalent shares to Northstar’s shareholders and assumed
approximately $307 million in long-term debt. The transaction brought us approximately
115 million equivalent barrels of proved oil and gas reserves and over 1.8 million net
exploration acres.
In addition, the merger brought us a proven, highly experienced management team
for our Canadian subsidiary. Further, John Hagg and Michael Kanovsky became new
members of Devon’s Board of Directors. Mr. Hagg, former Northstar CEO, and Mr.
Kanovsky, were both directors of Northstar prior to the merger. Their addition increases
the size of Devon’s Board to eleven members. More importantly, they bring many years of
experience in the Canadian oil and gas industry to Devon. The union of Devon and
Northstar creates a company uniquely positioned to pursue growth opportunities in both
the U.S. and Canada.
Devon’s decision to expand our Canadian operations was based on the opportunities
we see emerging. The Canadian oil and gas business is much less mature than its U.S.
counterpart. A shortage of natural gas pipeline capacity from Canada to lucrative U.S.
natural gas markets has suppressed Canadian natural gas prices. This has discouraged
additional exploration for oil and gas. In addition, many areas of Canada have
traditionally lacked such infrastructure as all-weather roads and gas gathering and
processing facilities to advance exploration for oil and gas. As a consequence, some of the
oil and gas prone areas of Canada are under-explored relative to the U.S.
Conditions, however, are changing in Canada. New natural gas pipelines are being
constructed and old ones are being expanded. This gives Canadian natural gas increased
access to major U.S. markets. As a result, natural gas prices are improving in Canada.
Furthermore, new Canadian infrastructure is opening never before explored regions to oil
and gas exploration. These vanishing barriers to oil and gas exploration translate into
emerging opportunities in Canada.
In addition to exploration and development opportunities, we see the Canadian oil
and gas industry as ripe for merger and acquisition opportunities. The low oil prices
experienced during 1998 and into 1999 have left many Canadian producers undercapi-
talized. As a result, high-quality Canadian oil and gas assets are becoming available for
purchase. Devon’s ﬁnancial strength, coupled with our Canadian-based management
team’s knowledge of the Canadian oil and gas industry, uniquely positions the combined
company to seize these opportunities.
Just a few years ago, a transaction the size of this merger would have been
unthinkable for Devon. However, as we have successfully executed our growth strategy,
the size of the opportunities available to Devon has also grown.
In 1998, Devon also seized an opportunity to signiﬁcantly expand our U.S. asset
base. Notably, we established the company as a dominant force in the development of an
untapped resource in the Powder River Basin of Wyoming. This vast resource, coalbed
methane gas, has become the subject of one of the most active exploration and
development efforts of this decade in the continental U.S.
Devon’s decision
to expand our
Canadian
operations was
based on the
opportunities
we see emerging.

Coalbed methane gas is found at shallow depths across a large portion of north
central Wyoming. As a major producer of oil in the Powder River Basin, Devon already
possessed a significant land position in the area. As we recognized the potential of the
coalbed methane, we decided to aggressively pursue development of this gas resource on
our properties. During 1998, we acquired additional producing properties and
undeveloped acreage in the Powder River, more than doubling our acreage position in the
area. We also drilled 86 coalbed methane wells during 1998. By year-end, we had over
200 coalbed methane wells and over 216,000 net acres of land in the prospective area.
One historic barrier to developing this resource has been the lack of gas gathering
facilities in the Powder River Basin. To overcome the barrier and unlock this opportunity,
we have begun construction of a major gas gathering system. We expect to invest
between $60 and $80 million and to complete this facility during the fourth quarter of
1999. We also plan to invest additional capital during 1999 to add to our acreage position
and drill over 200 additional wells in the Powder River area. We expect this project to be
a source of new gas reserves and production for years to come. A few years ago, the
capital requirements and lead-time required for this project would have represented an
insurmountable barrier for Devon. However, as we have grown, so have the projects we
are prepared to undertake. Barriers that once existed have begun to vanish.
Why has Devon been able to capture these opportunities at times when low oil and
gas prices left some of our competitors struggling to survive? We have structured our
company to take advantage of volatile oil and gas prices, rather than be battered by them.
Devon has maintained a stable, long-life property base that is less vulnerable to short-
term price changes. By concentrating high-quality oil and gas properties in areas where
we can be most competitive, we have kept our overall cost structure low. This allows us
to generate significant cash flow, even during periods of low oil and gas prices. With
dependable cash flow and modest debt levels, we maintain access to capital at reasonable
rates. This allows Devon to invest in oil and gas assets at times when the industry is
under duress—during periods of low oil and gas prices.
As I look forward into 1999, I am extremely optimistic about Devon’s future. The low
oil and gas prices we are currently experiencing may once again hamper our short-term
financial performance. But it is these very conditions that validate the long-term strategies
to which we have adhered for many years. Devon’s low cost structure and disciplined use
of its financial strength, continues to allow us to break down barriers and benefit from
emerging opportunities.
J. LARRY NICHOLS
President and Chief Executive Officer
Oklahoma City, Oklahoma
March 31, 1999
We have structured
our company
to take advantage
of volatile oil
and gas prices,
rather than be
battered by them.

Five-Year Highlights
LAST
YEAR
Year Ended December 31, 1994 1995 1996 1997 1998 CHANGE
FINANCIAL DATA (Thousands, Except Per Share Amounts)
Total Revenues $ 187,548 210,143 291,335 499,659 387,508 -22%
Cash Expenses (1) $ 72,112 89,859 109,974 199,867 204,139 2%
Cash Margin $ 115,436 120,284 181,361 299,792 183,369 -39%
Non-cash Expenses
Foreign Exchange Rate Changes on Long-term Debt $ — 307 199 5,860 16,104 175%
Reduction of Carrying Value of Oil & Gas Properties $ 21,679 97,061 — 625,514 126,900 -80%
Other Non-cash Expenses (including deferred taxes) $ 76,832 48,809 113,559 (31,591) 100,650 NM
Net Earnings (Loss) $ 16,925 (25,893) 67,603 (299,991) (60,285) -80%
Net Earnings (Loss) per Share:
Basic $ 0.54 (0.80) 2.06 (6.38) (1.25) -80%
Diluted $ 0.54 (0.80) 1.99 (6.38) (1.25) -80%
Weighted Average Common Shares Outstanding-Basic 31,114 32,473 32,812 47,040 48,376 3%
Cash Dividends per Common Share (2) $ 0.13 0.14 0.15 0.14 0.15 7%
LAST
YEAR
December 31, 1994 1995 1996 1997 1998 CHANGE
Total Assets $ 631,953 715,510 1,183,290 1,248,986 1,226,356 -2%
Long-term Debt $ 106,764 220,137 83,000 305,337 405,271 33%
Convertible Preferred Securities
of Subsidiary Trust (3) $ — — 149,500 149,500 149,500 —
Stockholders’ Equity $ 410,916 394,647 678,772 596,546 522,963 -12%
Working Capital $ 12,143 11,695 86,836 76,943 29,992 -62%
PROPERTY DATA
Proved Reserves (Net of Royalties)
Oil (MBbls) 57,944 58,999 80,155 97,041 83,457 -14%
Gas (MMcf) 539,160 649,746 898,319 1,150,604 1,198,894 4%
Natural Gas Liquids (MBbls) 7,665 11,550 14,190 17,178 16,079 -6%
Total (MBoe) (4) 155,469 178,840 244,065 305,986 299,351 -2%
SEC 10% Present Value (Thousands)(5) $ 590,400 730,800 1,999,800 1,340,600 1,009,000 -25%
LAST
YEAR
Year Ended December 31, 1994 1995 1996 1997 1998 CHANGE
Production (Net of Royalties)
Oil (MBbls) 6,501 7,130 6,780 11,783 11,903 1%
Gas (MMcf) 51,409 58,234 62,186 121,810 133,065 9%
Natural Gas Liquids (MBbls) 720 831 1,255 1,891 1,939 3%
Total (MBoe) (4) 15,789 17,666 18,399 33,976 36,020 6%
(1) Includes 1998 merger costs of $13.1 million related to the Devon and Northstar merger.
(2) The cash dividends per share presented are not representative of the actual amounts paid by Devon on a historical basis.
For the years 1998, 1997, 1996, 1995 and 1994, Devon’s historical cash dividends per share were $0.20, $0.20, $0.14, $0.12 and $0.12, respectively.
(3) Reflects the issuance of 2.99 million shares of preferred securities on July 10, 1996.
(4) Gas converted to oil at the ratio of 6 Mcf:1 Bbl.
(5) Before income taxes.
NM Not a meaningful figure.
The data presented below does not reflect Devon’s historical results. This data has been restated to
reflect the combined results of Devon and Northstar for all periods presented. This presentation conforms
with the accounting method used for the December 1998 merger, the pooling-of-interests method. The
restated data varies significantly from that reported for Devon on a stand-alone basis. For example, Devon
previously reported total revenues and net earnings of $313.1 million and $75.3 million, respectively, for
the year ended December 31, 1997. As restated below, the combined company had total revenues of
$499.7 million and a net loss of $300.0 million for the year ended December 31, 1997.

2 1998 Annual Report Devon Energy Corporation 7
1998 Financial Performance
Devon Energy Corporation reported a net loss for the
year ended December 31, 1998. Record oil and gas
production was offset by the impact of lower prices. In
addition to reducing total revenues, weaker oil, gas and
natural gas liquids prices also caused Devon to incur a
non-cash ceiling adjustment charge related to the
company’s U.S. oil and gas properties.
Devon’s net loss in 1998, was $60.3 million, or $1.25
per share. This compares to a net loss of $300 million, or
$6.38 per share in 1997. Excluding an $88 million after-
tax ceiling adjustment and certain unusual charges,
Devon had net earnings of $48.2 million, or $1.00 per
share for 1998. For 1997, Devon had net earnings of
$101.2 million, or $2.15 per share, excluding a $398
million after-tax ceiling adjustment and certain unusual
charges.
As a result of accounting for the 1998 merger as a
“pooling-of-interests,” financial statements for all periods
presented represent the financial results of Devon and
Northstar combined. The pooling-of-interests method of
accounting requires all historical financial statements to
be restated as if the combining companies had always
been merged.
PRODUCTION RECORD SET, BUT REVENUES DECLINE
Devon increased total 1998 production of oil, gas
and natural gas liquids by 6%, to 36.0 million barrels of
oil equivalent. This represents our eleventh consecutive
record for total annual production. The production
increase was driven by wells purchased and drilled during
1998. Devon drilled 555 wells in 1998, of which 90%
were completed as producers. Mechanical improvements
on certain gas-producing properties also contributed to
the production increase.
Despite record production, 1998 total oil, gas and
natural gas liquids revenues were down 18% due to lower
overall product prices. The average price Devon received
for 1998 oil production fell 32%, from $17.63 per barrel
in 1997 to $12.07 per barrel in 1998. The average price
received for our 1998 gas production decreased 13%,
from $1.80 per thousand cubic feet in 1997 to $1.57 per
thousand cubic feet in 1998. Devon’s natural gas liquids
price declined 35% in the most recent year, from $13.18
per barrel in 1997 to $8.61 per barrel in 1998.
OTHER PRE-TAX EXPENSES DECLINE
Pre-tax expenses other than the ceiling adjustments
decreased $11.6 million, to $336.4 million in 1998. A
decrease in depreciation, depletion and amortization
expense (DD&A) was partially offset by the effect of
changes in currency rates, the costs of the 1998 merger,
higher interest expense and an increase in production and
operating expenses.
Our DD&A expense decreased $45.3 million during
1998 to $123.8 million. The change in this non-cash
expense resulted from a lower DD&A rate in 1998,
partially offset by higher total production for the year.
The decline in Devon’s DD&A rate for 1998 was
primarily attributable to the full cost ceiling adjustment
incurred during late 1997.
Devon’s expense from the deferred effects of changes
in foreign currency rates on long-term debt increased
$10.2 million in 1998, to $16.1 million. This non-cash
expense reflects the increase in the amount of Canadian
dollars that would be required to repay Northstar’s U.S.
dollar denominated debt over the life of the loans, based
on the year-end exchange rate.
During 1998, we incurred $13.1 million of Northstar
combination costs. These costs represent non-recurring
expenses including professional and advisory fees,
registration and listing fees and printing costs related to
the December 1998 merger.
Devon’s total production and operating expenses
increased $7.3 million in 1998, to $127.4 million. This
increase was due to the costs associated with new wells
added during 1997 and 1998, partially offset by a
reduction in production taxes. Production taxes declined
due primarily to lower oil, gas and natural gas liquids
prices in 1998.
Interest expense increased $3.8 million in 1998, to
$22.6 million. This increase was due to higher average
outstanding debt balances and higher overall interest
rates in 1998.
INCOME TAX BENEFIT
Devon recognized a $15.5 million income tax benefit
during 1998. A $23.2 million deferred tax benefit was
partially offset by $7.7 million of currently payable
income taxes. The deferred tax benefit was a result of the
pre-tax loss reported for 1998.
FINANCIAL CONDITION REMAINS STRONG
Devon’s cash margin (revenues less cash expenses)
totaled $183.4 million in 1998. With significant cash
margins, over a billion dollars in total assets and modest
debt levels, Devon continues to maintain a high degree of
financial liquidity.

Devon constantly searches for growth opportunities.

With many independent oil and gas companies unable to generate a meaningful rate of
return and stock prices suffering across the industry, why should one invest in Devon?
Oil and natural gas are commodities. Prices rise and fall in response to a variety of forces:
weather patterns, levels of economic activity, the availability of capital, political winds and
other factors. Price volatility is one thing we count on in our business. When oil and gas
prices are high, many oil and gas producers invest as if prices will
never fall. They overpay for oil and gas properties and become highly leveraged in the
process. When oil and gas prices eventually fall, and they always do, these companies
are crushed by the weight of their debt. We have seen these cycles many
times.
But where there are losers, there are also winners. Devon has a track record of
maintaining discipline during periods of high prices and investing wisely during
periods of low prices. When oil and gas prices rise again, we reap the rewards.
While our short-term earnings performance rises and falls with the tide of oil and gas prices,
over the long-term asset values have grown. Consequently, our shareholders have been well
rewarded.
During 1998, Devon reported a charge of $88 million. This resulted in a net loss for 1998.
Why did Devon incur this charge?
The earnings charge reported during the third quarter was a non-cash accounting
requirement associated with lower oil and gas prices. Since Devon follows the full cost
method of accounting, the net book value of our oil and gas properties, less related deferred
income taxes, may not exceed a calculated “ceiling.” The ceiling is the estimated after-tax
future net revenues from proved oil and gas properties, discounted at 10%. Any excess is
written off as an expense. To calculate the ceiling value of reserves, prices in effect at the end
of each accounting quarter must be used. Future net revenues are calculated assuming prices
and costs in effect at the time of the calculation, except for changes that are ﬁxed and
determinable by existing contracts. Securities and Exchange Commission rules assume that
current energy prices in effect at the end of the quarter will remain constant through the
An Interview with the President &
CEO, J. Larry Nichols

entire productive life of the company’s oil and gas properties. However, just as we did not
believe the high oil and gas prices of late 1996 were indicative of long-term market
conditions, neither do we think the current low oil and gas prices
are indicative of the future. That is, though the low commodity prices of 1998 caused a
non-cash accounting charge, we do not believe this charge can be directly tied to the long-
term value of our assets.
Industry observers commonly believe that the full cost method of accounting is less
conservative than the other method of accounting available to oil and gas producers, the
successful efforts method. However, the full cost ceiling test is more stringent than the
successful efforts ceiling test. Companies that follow the successful efforts method compare
the book value of their proved oil and gas properties to the undiscounted after-tax future net
revenues from these properties. Since full cost companies compare the book value of their oil
and gas properties to discounted future net revenues, the full cost method often results in a
lower, more conservative, carrying value.
What were Devon’s major disappointments in 1998?
Low oil and gas prices resulted in several disappointments. Devon reported its first net
loss since 1991. Even though low commodity prices provided us with long-term opportu-
nities like the Northstar merger, we are proud of our track record of profitable growth. It is
disappointing to have that record interrupted. (Note that Devon’s financial results for
previous years were restated at the end of 1998 to account for the December 10, 1998
merger as a pooling-of-interests. This resulted in some losses in years where Devon had
previously reported positive earnings.)
Low oil prices also contributed to our disappointing finding and development costs for
the year. First, low year-end 1998 oil prices resulted in a negative revision to our oil reserves.
When estimating oil and gas reserves, producers must assume that the prices in effect at the
end of the year remain constant over the economic life of their oil and gas properties. The
unusually low oil price assumption used at the end of 1998 shortens the estimated economic
life of Devon’s oil properties. This simply means that if the oil prices we received at the end of
1998 continued indefinitely into the future, we would stop producing our oil properties
sooner than we would if oil prices were higher. We do not believe the very low average oil
price we were receiving at the end of 1998 ($9.89 per barrel) is representative of the price
we will receive for our oil production over the life of our properties. Nevertheless, this caused
us to reduce our estimated oil reserves. This downward revision offset some of the reserves
we discovered during 1998, thereby increasing our finding cost for the year. However, we
would recover the reserves lost due to low oil prices if oil prices
rise in the future.
Low oil prices in 1998 also led us to suspend drilling on some of our oil-prone properties
until prices recover. Accordingly, we discovered and produced less oil than we would have
had prices been higher. This likely increased Devon’s 1998 finding costs as well.

Another disappointment of 1998 was the outcome of our Gulf of Mexico exploration
program. In a joint venture with a major oil and gas company, Devon drilled three exploratory
wells in the Gulf during 1998. Two of these wells were dry holes and the third well resulted
in only a modest discovery. While this high risk/reward exploration effort represented a
relatively small portion of our total capital spending during 1998, we had hoped for better
results from these high potential wells. Based on our drilling results, Devon sold its interests
in the Gulf of Mexico during the second half of 1998.
As companies grow, many find that their larger size becomes an obstacle that impedes their
future growth. Will Devon’s larger size hamper your ability to grow in the future?
Devon’s larger size should promote rather than impede our growth in years to come.
As a larger company, we have many advantages. First, we have greater
financial strength and better access to capital at lower costs. A lower cost of capital gives us a
better rate of return on any given project. Second, our larger size has made Devon
more competitive. We enjoy greater economies of scale than ever before in the areas where we
operate. Our growth has increased our negotiating strength with the purchasers and
transporters of our oil and gas production as well as with providers of oil field goods and
services. This allows us to sell our production for higher prices while buying goods and
services at more attractive rates. Finally, as Devon has grown so has the size of projects we are
prepared to undertake. Our major projects of 1998, the Northstar transaction and the Powder
River coalbed methane project, would have been impossible just a few years ago. We are now
able to consider a broader range of growth opportunities than ever before.
Over the last two years, you have expanded your operations beyond the borders of the
United States into Canada. Does Devon plan to expand to areas outside of North America
in the future?
We believe that the North American oil and gas industry still holds many opportunities
for exploitation, exploration and consolidation. However, we are and always have been
opportunity driven. Therefore, when opportunities outside of North America present
themselves, we evaluate them in the context of all opportunities available to us. If we judge
an opportunity outside of North America to be our best alternative, we will not hesitate to
seize it. However, we choose to compete in areas where we have an
advantage. In order for an opportunity to draw Devon outside North America, it must
present an opportunity to gain a competitive advantage over the long run, similar to those we
enjoy in our current areas of operations.

Devon’s expanding property base yields growth opportunities.

Portfolio of Oil and Gas Properties
Throughout Devon’s history, the
foundation for growth has been our
portfolio of oil and gas properties. Our
property base has been managed to
maintain high operating margins, a long
reserve life and “critical mass” by
operating area. High operating margins
provide us with substantial cash flow,
even when oil and gas prices are low.
The long reserve life provides the
advantage of a lower rate of natural
decline. Critical mass in each of our
major operating areas allows us to
increase operating efficiency. We strive
to develop and acquire oil and gas
properties with these characteristics. In
addition, we regularly identify and sell
those properties that have become too
expensive to operate and those in areas
where we lack critical mass.
These strategies have served us
well. Our portfolio of properties has
provided us with a dependable source of
cash flow and financing capacity. We
have relied on this foundation to fund
our growth through acquisitions as well
as exploration and development
activities. As a result, over the last 10
years, Devon has grown oil and gas
reserves and production at compounded
annual rates in excess of 25%.

However, as Devon expands we
must pursue larger projects to sustain
this growth. Fortunately, we have the
size and the financial strength to
undertake these larger projects. As a
relatively small company in 1988, we
were generating and reinvesting cash
flow of less than $20 million annually.
With this cash flow and limited credit
capacity, we were restricted to projects
with relatively modest capital
requirements. And we needed projects
that would begin to return cash flow
quickly. Ten years later, our cash flow
has grown to more than $150 million annually. This cash flow, our expanded credit capacity
and the long reserve life of our existing property base, gives us access to a broader range of
opportunities. We have the ability to pursue larger, more capital-intensive projects and to
tolerate longer cycle-times. As we have grown, our natural niche, the one where we are most
highly competitive, has changed.
An example of such a project is our involvement in the development of coalbed methane
in the Powder River Basin of Wyoming. This project involves drilling hundreds of gas wells
and construction of a $100 million gathering system stretching over a span of 126 miles. We
have already invested over $40 million in this project and expect to invest an additional $100
to $120 million during 1999. While we began to inject capital in this project during early
1998, we do not expect a meaningful cash stream until the year 2000. However, we believe
this project has the potential to provide significant long-life gas reserves and production.
Smaller operators, i.e., Devon circa 1988,
do not have the financial capacity and
stability to engage and benefit from a large,
long-term project such as this.
As we seek larger growth opportu-
nities we are increasing our commitment
to exploration. Our 1999 exploration
budget of $80 to $90 million exceeds our
entire drilling and development budget of
just a few years ago. The chances of
drilling a successful exploratory well are
much lower than drilling a successful
development well. However, an
exploratory well also provides greater
potential rewards. As a larger company, we
have the ability to absorb the risks
Our 100% ownership of the Coleman gas plant gives us a
competitive advantage in the southern Foothills near the
Alberta/British Columbia border.
Casing lies ready for use in a Panhandle Morrow
exploratory well. Devon has 87,000 net acres in this deep
gas exploration project.

associated with high-potential exploration. Although our exploration budget has increased
significantly, the $80 to $90 million for 1999 is under 8% of our $1.2 billion balance sheet.
Even if all of our 1999 exploration wells were failures, our long-life property base would still
provide substantial cash flow far into the future. In the context of Devon’s otherwise relatively
low-risk activities, devoting this portion of our 1999 capital program to exploration enhances
our overall risk/reward profile.
The drilling program we are currently conducting in the Foothills region of northeast
British Columbia is a good example of our exploration philosophy. Along with an industry
partner, we are exploring on several hundred thousand acres of land. The targets are natural
gas reservoirs found as
deep as 15,000 feet. The
area is remote and the
terrain rugged. Wells in this
difficult operating
environment often cost $6
million or more to drill.
Furthermore, gas treating
and transportation facilities
must be constructed to
bring any significant
discoveries to market.
However, the potential of
this area justifies the risks.
Individual reservoirs often
contain over 100 billion
cubic feet of natural gas. In
late 1998 we made our first
significant discovery in this
area. The test well flowed at
a rate of over 20 million
cubic feet of gas per day. In
1999 we will continue to
drill high-potential
exploratory wells in this
area.
The Powder River
Basin and the British
Columbia Foothills are but two of the areas that hold growth potential for Devon. An
undeveloped acreage inventory of 2.8 million net acres provides the largest portfolio of
exploration opportunities in the company’s history. Our base of long-life, high-margin
producing properties provides the resources to pursue them.
The wind dances on the grassy meadow around this Gilby oil well.
We drilled and completed four wells during 1998 in this area of
southern Alberta.

Increasing exploration and development expenditures reﬂect the opportunities
in our growing property portfolio.
Exploration and
Development Expenditures
($ Millions)
93 94 95 96 97 98
250
200
150
100
50
0
238
91
Undeveloped Net Acres
(Millions)
93 94 95 96 97 98
3.0
2.5
2.0
1.5
1.0
.5
0
2.8
0.6

The shallow gas producing area of central northern Alberta is
commonly called the Smoky Bear area. The term “Smoky Bear” has
roots in two different episodes in the area’s recent history.
In the 1970’s and 1980’s, major oil and gas companies swept
through this region looking for commercially producible oil reserves
while bypassing the shallow gas zones. In the late 1970’s, Devonian
age oil was discovered which spurred a drilling boom that lasted
through the mid 1980’s. Activity eventually waned with the drop in
oil prices and the realization that the oil reservoirs were not as large
as previously believed.
With the improvement in gas prices in the early 1990’s, the oil
and gas industry recognized the vast natural gas potential of this
extensive area of undeveloped lands. A land bidding war quickly
ensued. As part of its strategy to draw would-be competitors away
from the key areas where signiﬁcant gas reservoirs had been
identiﬁed, Northstar would “post smoke,” i.e., place bids on large
parcels of less desirable land.
Throughout this area’s development, wellsite geologists and plant
operators would commonly complain about the number of bears
wandering around the well and plant sites during late winter and
spring. With the recurring mention of bears and posting smoke, the
term “Smoky Bear” was coined for this area.
What’s In a Name?

Proved Oil & Gas Reserves
by Area
Annual Oil & Gas Production
by Area
1999 Exploration, Development
& Facilities Budget
Eleven Year Property Data
Permian Rocky San Juan Other U.S. Northern Southern Foothills
Basin Mountain Basin Alberta Alberta
18%
14%
12%
8%
21%
20%
7%
10%
23%
24%
9%
1%
3%
10%
17%
8%
9%
9%
48%
22%
7%
1988 1989 1990 1991 1992
Reserves (Net of Royalties)
Oil (MBbls) 10,192 10,138 10,293 9,881 29,062
Gas (MMcf) 120,877 176,278 201,748 239,486 367,663
Natural Gas Liquids (MBbls) 106 93 156 298 2,121
Total (MBoe) (1) 30,444 39,611 44,074 50,093 92,460
SEC @ 10% Present Value (Thousands) (2) $125,200 204,200 262,000 210,600 461,200
Production (Net of Royalties)
Oil (MBbls) 1,202 1,644 1,759 1,987 3,635
Gas (MMcf) 6,239 8,381 10,691 16,937 34,260
Natural Gas Liquids (MBbls) 16 25 32 40 260
Total (MBoe) (1) 2,258 3,066 3,573 4,850 9,605
Average Prices
Oil (Per Bbl) $ 12.83 16.50 19.86 17.73 17.17
Gas (Per Mcf) $ 1.66 1.74 1.78 1.24 1.39
Natural Gas Liquids (Per Bbl) $ 11.19 15.12 18.66 6.75 11.89
Oil, Gas and Natural Gas Liquids (Per Boe) (1) $ 11.49 13.73 15.26 11.66 11.77
Production and Operating Expense per Boe (1) $ 4.72 5.00 4.60 3.56 3.43
(2) Before income taxes.

Operating Statistics by Area
PERMIAN ROCKY SAN JUAN TOTAL NORTHERN SOUTHERN TOTAL TOTAL
BASIN MOUNTAIN BASIN OTHER U.S. ALBERTA ALBERTA FOOTHILLS CANADA COMPANY
Producing Wells at Year-End 7,333 1,028 936 2,210 11,507 1,072 2,182 16 3,270 14,777
1998 Production (Net of Royalties):
Oil (MBbls) 3,690 1,620 2 334 5,646 1,587 4,670 — 6,257 11,903
Gas (MMcf) 20,057 7,275 20,552 18,023 65,907 39,704 20,110 7,344 67,158 133,065
NGLs (MBbls) 739 384 16 234 1,373 89 477 — 566 1,939
Total (MBoe)(1) 7,772 3,217 3,443 3,572 18,004 8,293 8,494 1,229 18,016 36,020
Average Prices:
Oil Price ($/Bbl) $ 12.60 12.03 10.67 12.87 12.45 11.10 11.93 12.80 11.72 12.07
Gas Price ($/Mcf) $ 2.00 1.88 1.72 2.06 1.92 1.22 1.30 1.14 1.24 1.57
NGLs Price ($/Bbl) $ 8.50 9.15 6.17 9.29 8.79 10.33 7.75 16.17 8.16 8.61
Year-End Reserves (Net of Royalties):
Oil (MBbls) 25,997 17,000 11 1,443 44,451 12,284 26,722 — 39,006 83,457
Gas (MMcf) 122,472 143,337 212,354 118,824 596,987 299,998 170,502 131,407 601,907 1,198,894
NGLs (MBbls) 6,966 2,552 129 1,847 11,494 944 3,641 — 4,585 16,079
Total (MBoe)(1) 53,375 43,441 35,532 23,095 155,443 63,228 58,780 21,900 143,908 299,351
Year-End Present Value of Reserves (Thousands):(2)
Before Income Tax $ 135,910 155,029 152,583 102,596 546,118 235,858 175,878 51,185 462,921 1,009,039
After Income Tax $ 493,682 437,906 931,588
Year-End Leasehold (Net Acres)
Producing 145,076 92,996 16,821 187,539 442,432 361,760 216,215 6,018 583,993 1,026,425
Undeveloped 178,421 242,668 10,339 177,014 608,442 1,387,576 500,611 286,534 2,174,721 2,783,163
Wells Drilled During 1998 136 133 26 51 346 148 57 4 209 555
1998 Exploration, Development & Facilities
Expenditures (Millions) $ 39.5 29.1 1.3 42.8 112.7 66.2 27.4 31.4 125.0 237.7
Estimated 1999 Exploration, Development &
Facilities Expenditures (Millions) (3) $ 14-19 100-120 2-4 19-27 135-170 35-43 16-19 19-23 70-85 205-255
(2) Estimated future revenue to be generated from the production of proved reserves, net of estimated future production and development costs,
discounted at 10% in accordance with Securities and Exchange Commission guidelines.
(3) Rocky Mountain includes $60 to $80 million for construction of a gas gathering system in the Powder River Basin.
5-YEAR 10-YEAR
COMPOUND COMPOUND
1993 1994 1995 1996 1997 1998 GROWTH RATE GROWTH RATE
29,797 57,944 58,999 80,155 97,041 83,457 23% 23%
473,381 539,160 649,746 898,319 1,150,604 1,198,894 20% 26%
2,886 7,665 11,550 14,190 17,178 16,079 41% 65%
111,580 155,469 178,840 244,065 305,986 299,351 22% 26%
530,600 590,400 730,800 1,999,800 1,340,600 1,009,000 14% 23%
5,982 6,501 7,130 6,780 11,783 11,903 15% 26%
46,078 51,409 58,234 62,186 121,810 133,065 24% 36%
615 720 831 1,255 1,891 1,939 26% 62%
14,277 15,789 17,666 18,399 33,976 36,020 20% 32%
14.71 14.21 16.21 20.06 17.63 12.07 -4% -1%
1.51 1.44 1.22 1.63 1.80 1.57 1% -1%
11.20 9.99 10.94 15.38 13.18 8.61 -5% -3%
11.52 10.99 11.09 13.96 13.31 10.26 -2% -1%
3.31 3.22 3.33 3.78 3.54 3.54 1% -3%

Permian Basin
Grayburg-Jackson Field
PROFILE
• Near 100% working interest in 8,600
acres in southeastern New Mexico.
• Purchased in 1994 acquisition.
• Produces oil from the Grayburg and San
Andres formations at 3,000’ to 4,000’.
• One of Devon’s top properties with 13.1
million barrels of oil equivalent reserves at
12/31/98.
1998 ACTIVITY
• Performed workovers on 52 wells.
• Converted 7 oil wells to injector wells.
• Recompleted 4 wells.
• Reactivated 3 wells.
• Redrilled 1 injector well.
1999 PLANS
• Convert 6 oil wells to injector wells.
• Recomplete 15 oil wells.
• Drill 4 injector wells.
• Drill 1 oil well.
Ozona/Sonora
PROFILE
• 36% working interest in 100,000 acres in
southwestern Texas.
• Purchased in 1992 and 1996 acquisitions.
• Produces gas from the Canyon and Strawn
formations at 6,000’ to 10,000’.
12/31/98.
1998 ACTIVITY
• Drilled and completed 13 wells.
1999 PLANS
• Install compression and additional lines for
gathering system.
Johnson Ranch
PROFILE
west Texas.
• Obtained initial position in area in 1998.
• Targets high-potential gas formations at
11,000’ to 16,000’.
1998 ACTIVITY
• Acquired 78 square miles of 3-D seismic data.
• Deﬁned two deep exploratory prospects.
1999 PLANS
• Drill initial exploratory well.
• Acquire additional acreage.
B
A
C
N E W M E X I C O
TEXAS
M
E
X
IC
O
B
C
A
Permian BasinPermian Basin
San Juan BasinSan Juan Basin
Rocky Mountain RegionRocky Mountain Region
Southern Alberta
Northern Alberta
Foothills
Southern Alberta
Northern Alberta
Foothills

M O N T A N A
W Y O M I N G
WYOMING
SOUTHDAKOTANEBRASKA
D
E
E
21
Other
Panhandle Morrow Play
PROFILE
western Oklahoma and the Texas Panhandle.
• Includes 13 separate multi-well prospects.
• Obtained initial position in 1996 merger.
• Produces gas from the Upper Morrow Chert at
14,000’ to 17,000’.
1998 ACTIVITY
• Drilled and completed 5 exploratory wells
and 1 development well.
• Drilled 1 exploratory dry hole.
• Initiated drilling on 4 other wells.
• Acquired 350 miles of 3-D seismic data
on 6 prospect areas.
• Acquired 16,000 net undeveloped acres.
1999 PLANS
• Drill 6 to 10 wells.
• Interpret existing 3-D seismic data.
• Identify additional prospects.
• Conduct 3-D seismic surveys on newly
developed prospects.
Ouachita Overthrust Play
PROFILE
northeastern Mississippi, southern
Oklahoma and southern Texas.
• Obtained initial position in 1996 merger.
• Targets gas from the Knox formation at
15,000’ in northeastern Mississippi, the
Simpson and Arbuckle formations at 6,000’
to 16,000’ in southern Oklahoma, and the
Ellenburger formation in Texas at 4,500’
to 20,000’.
1998 ACTIVITY
• Drilled and completed Knox exploratory well
in Mississippi.
• Initiated drilling of second Knox
exploratory well.
• Drilled exploratory dry hole in southern
Oklahoma.
• Acquired 600 miles of 2-D seismic data.
1999 PLANS
• Complete drilling of second Knox
exploratory well.
• Initiate drilling on a Knox development well.
• Acquire additional 2-D and 3-D seismic data.
Rocky Mountain Region
House Creek Area
PROFILE
• Two federal units in northeastern
Wyoming.
• 46% working interest in 24,000 acre
House Creek Unit.
• 26% working interest in 9,700 acre North
House Creek Unit.
• Obtained in 1996 merger.
• Produces oil from the Sussex Sand
formation at 8,200’.
12/31/98.
1998 ACTIVITY
• Drilled and completed 31 oil wells
and 36 injector wells.
• Converted 1 oil well to an injector well.
• Increased gross production at House Creek Unit
from 2,900 barrels of oil per day to 4,500
barrels of oil per day.
1999 PLANS
• Continue drilling program as oil prices improve.
• Perform waterﬂood program enhancements.
• Complete installation of electronic production
monitoring system.
Powder River Coalbed Methane
PROFILE
• Acreage position of 216,000 net acres
in northeastern Wyoming.
• Initial position in area obtained in 1992.
• Produces coalbed methane from the Fort
Union formation at 200’ to 1,000’.
12/31/98.
1998 ACTIVITY
• Acquired over 110,000 net acres.
• Acquired 7.6 million barrels of proved oil
equivalent reserves.
• Entered into a joint venture with a third party
to construct a 126-mile gas gathering system
and related CO2 removal facilities.
• Drilled and completed 86 wells.
• Drilled 8 stratigraphic test wells.
1999 PLANS
• Construct a 126-mile gas gathering system.
• Drill 200 to 300 wells.
San Juan Basin
Northeast Blanco Unit (NEBU)
PROFILE
northwestern New Mexico.
• Fruitland Coal developed by Devon in the late
1980’s and early 1990’s.
• Contains 102 producing wells, 4 water
disposal wells, gas and water gathering
systems and an automated production
control system.
• Produces gas primarily from the Fruitland
Coal formation at 3,000’.
• Devon’s top ﬁeld with 23.7 million barrels
of oil equivalent reserves at 12/31/98.
1998 ACTIVITY
• Installed booster compression at central
delivery points.
• Increased gross production to over 230 million
cubic feet of gas per day.
• Recavitated 12 wells.
• Completed looping of trunk lines.
• Installed 6 pumping units.
• Continued gathering system improvements.
1999 PLANS
• Recavitate up to 27 wells.
• Finalize gathering system improvements.
• Install 50 wellhead compressors.
• Install booster compression at remaining central
delivery point.
32-9 Unit
PROFILE
northwestern New Mexico.
• Purchased by Devon in 1993.
• Contains 51 producing wells, water disposal
facilities and gas and water gathering
systems.
• Produces gas from the Fruitland Coal
formation at 3,000’.
12/31/98.
1998 ACTIVITY
• Recavitated 4 wells.
• Installed compression on 8 wells.
1999 PLANS
• Perform recavitations and well workovers as
needed to maintain production at capacity of
gathering system.
C O L O R A D O
NEWMEXICO
A R I Z O N A
UTAH
G
D F H
H
I
I
I
I
G
E
F

Northern Alberta
Smoky Bear/NE Shallow Gas
PROFILE
• 70% working interest in 2,100,000 acres
in north central Alberta.
• Obtained initial position in 1993.
• Drilling primarily limited to winter-only access.
• Produces gas from multiple formations at
1,000’ to 2,500’.
• One of Devon’s top areas with 39 million
barrels of oil equivalent reserves at 12/31/98.
1998 ACTIVITY
• Drilled 101 gas wells with 72 completions.
• Initiated drilling on 22 other wells.
• Acquired 317 miles of 2-D seismic data.
• Acquired 12 million barrels of proved oil
equivalent reserves.
1999 PLANS
• Drill 80 to 90 gas wells.
• Acquire additional acreage and 2-D seismic data.
• Implement summer drilling program on newly
acquired acreage.
• Pursue joint ventures, acquisitions and land
swaps to access additional acreage.
Chinchaga
PROFILE
northwestern Alberta.
• Drilling limited to winter-only access.
• 100% interest in gas processing plant.
• Produces oil and gas from the Bluesky
formation at 2,500’ to 3,000’.
1998 ACTIVITY
• Drilled and completed 6 gas wells.
• Drilled 1 dry hole.
• Accessed 3,000 net acres of exploratory
acreage to extend Bluesky trend to the south.
• Completed 3-D and 2-D seismic surveys of
15 square miles and 24 miles, respectively.
1999 PLANS
• Drill 2 exploratory wells.
• Drill 12 development Bluesky wells.
• Perform additional 2-D seismic surveys.
• Perform gas plant enhancements.
Hamburg
PROFILE
northwestern Alberta.
• Drilling limited to winter-only access.
• 60% interest in gas processing plant.
• Produces oil and gas from the Slave Point
formation at 8,000’ to 8,500’.
1998 ACTIVITY
• Completed a successful horizontal well reentry.
• Drilled 3 exploratory dry holes.
• Completed a 53 mile 2-D seismic survey.
• Developed 8 drillable Slave Point prospects.
• Installed additional inlet compressor; increased
gas production 2.5 million cubic feet per day.
1999 PLANS
• Drill 5 exploratory wells.
• Drill 2 development wells.
• Acquire additional 2-D and 3-D seismic data. Foothills
Southern Foothills
PROFILE
southwestern Alberta and southeastern British
Columbia.
• Acquired initial position in 1993.
• 100% interest in 100 million cubic feet per
day gas processing plant.
• Produces gas from multiple formations at
9,500’ to 11,500’.
• Includes the Coleman field, which is one of
Devon’s top properties with 15.2 million barrels
of oil equivalent reserves at 12/31/98.
1998 ACTIVITY
• Acquired 3-D seismic data covering the
Coleman field.
• Drilled and completed 2 exploratory gas wells.
1999 PLANS
• Interpret existing 3-D seismic data.
• Drill 1 exploratory well targeting the
Mississippian formation at 15,000’.
• Connect 2 exploratory gas wells drilled in
1998 to pipeline.
Northeastern B.C. Foothills
PROFILE
• Initial position obtained in late 1997 through a
strategic alliance with Amoco. Under the
agreement, Devon has the option to spend $10
million per year for a three-year period to earn
49% of Amoco‘s interest in 600,000 gross acres.
• Access to four separate geologic play types and
almost 4,000 miles of seismic data.
• Targets various formations at depths of 5,000’
to 15,000’.
1998 ACTIVITY
• Drilled and completed 1 exploratory well;
tested over 20 million cubic feet of gas per day.
1999 PLANS
• Drill 1 to 2 exploratory wells.
• Initiate drilling of development well.
• Acquire additional acreage and seismic data.
• Connect previously drilled well to pipeline.
Southern Alberta
Halkirk
PROFILE
• 60% working interest in over 50,000 acres
in south central Alberta.
• Produces oil and gas from the Lower
Cretaceous formation at 4,000’.
• One of Devon‘s top properties with 7.7 million
1998 ACTIVITY
• Drilled and completed 4 development oil wells.
• Drilled and completed 2 stepout exploratory wells
extending reservoir size and increasing reserves.
• Drilled 2 dry holes.
1999 PLANS
• Perform gas plant and pipeline enhancements.
• Acquire additional acreage and 2-D seismic data.
Gilby/Leduc/Woodbend
PROFILE
west central Alberta.
• Produces oil and gas from the Upper
Mannville formation at 6,100’.
• One of Devon‘s top properties with 10.1 million
1998 ACTIVITY
• Drilled and completed 4 oil wells.
• Conducted waterflood enhancements.
1999 PLANS
• Drill 3 to 6 exploratory wells.
• Evaluate unitization of oil properties.
• Perform facilities improvements and additional
waterflood enhancements.
J
M
K
N
L
O
M
P
N
J
O
K
P
L
SASKATCHEWAN
BRITISH
COLUMBIA
ALBERTA
SASKATCHEWAN
BRITISH
COLUM
BIA
ALBERTA
BRITISH
COLUM
BIAALBERTA

Permian Basin
The Permian Basin covers a 66,000 square mile area of west Texas and southeastern New
Mexico and has over 500 major oil and gas fields. It is characterized by prolific, long-life oil
and gas production from numerous formations found over a wide variety of depths. Many
formations respond to enhanced recovery techniques, such as waterflood projects. In addition,
the region is criss-crossed with multiple pipelines with easy access to many oil and gas
markets. Acreage held by production from existing wells and large federal exploration units
makes leases difficult to obtain. Most of Devon’s position here was established through four
major transactions.
Rocky Mountain Region
Over a dozen oil and gas producing basins are included in this region which stretches across
several states in the western U.S. Devon’s most significant Rocky Mountain properties are
located in the Bighorn and Powder River Basins of Wyoming. While this area is our second
largest area in terms of oil and gas reserves in the U.S., it is the focus of more than 70% of our
1999 U.S. capital budget.
San Juan Basin
The Basin covers a densely drilled 3,700 square mile area in northwest New Mexico and
southern Colorado. It has long been one of the largest gas-producing areas of the U.S. This
area historically produced from conventional sandstones found at a depth of about 5,500’.
Technology pioneered by Devon and a few other companies in the 1980’s and 1990’s resulted
in significant production from the Fruitland Coal at a depth of about 3,000’. Natural gas
produced from these coal deposits (coalbed methane) makes up almost all of Devon’s San Juan
Basin gas production.
Northern Alberta
This area, located in the Western Canada Sedimentary Basin, covers northern Alberta and a
portion of northeastern British Columbia. The area is primarily known for its prolific natural
gas-producing properties. These gas properties produce from shallow, lower risk formations as
well as from larger, higher risk, deep formations. In addition, the area is known for oil
production from multiple formations at varying depths. Most of the region is limited to
winter-only access.
Southern Alberta
A part of the Western Canada Sedimentary Basin, this region spans central and southern
Alberta and covers a small portion of Saskatchewan. This is generally a mature, oil-producing
area that provides approximately 75% of the company’s Canadian liquids production.
Although 1999 activity will be limited due to low oil prices, the region offers a mix of oil and
gas exploration and development opportunities. Core properties produce from formations
found at depths of 2,300’ to 13,200’. This area is accessible year-round.
Foothills
Perhaps the most underdeveloped exploration region in the Western Canada Sedimentary
Basin, the Foothills region contains some of western Canada’s most promising deep gas
prospects. Located in eastern British Columbia and southwestern Alberta, the Foothills
contain deep, high-potential gas reservoirs.
Primary Operating Areas
with Key Property Highlights

With the completion of our December 1998 merger, Devon dramat-
ically expanded its oil and gas property base in the Western Canada
Sedimentary Basin. A number of these properties lie in portions of
northern Alberta and northeastern British Columbia that are commonly
known as “winter-only access” areas.
Winter-only access refers to those areas in which a short window of
opportunity exists for drilling and certain other operational activities. This
period, which typically runs from December 15 through March 15, results
from muskeg terrain and wildlife restrictions in these areas. Muskeg
consists of wet bog areas of decaying vegetative material. Only during
freezing winter weather can these areas physically support the heavy
equipment required to drill wells. Additionally, winter-only access areas
are home to wildlife such as deer, moose and caribou. If conducted outside
of the specified time frame, drilling and other operational activities could
severely disturb wildlife feeding and reproduction.
While conducting operations in these areas clearly presents unique
challenges, overcoming this barrier has provided the reward of significant
gas reserves and production at an attractive price. In order to optimize our
drilling programs in the winter-only access areas, our operations must be
condensed and intensified. We begin detailed planning months in advance
of the freeze-up. This is a critical step in coordinating the activities of
employees and suppliers during this period of intense field activity.
What Is Winter-Only Access?

Financial Statements and
Management’s Discussion
& Analysis
Selected Eleven-Year Financial Data
Management’s Discussion & Analysis of Financial
Condition and Results of Operations
Management’s Responsibility for Financial Statements
Independent Auditors’ Report
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
26
28
45
45
46
47
48
49
50

1988 1989 1990 1991
OPERATING RESULTS (In Thousands, Except per Share Amounts)
Revenues (Net of Royalties)
Oil Sales $ 15,420 27,118 34,928 35,238
Gas Sales $ 10,351 14,611 19,013 21,039
Natural Gas Liquids Sales $ 179 378 597 270
Other Revenue $ 3,649 3,885 4,025 5,222
Total Revenues $ 29,599 45,992 58,563 61,769
Production and Operating Expenses $ 10,650 15,323 16,447 17,286
Depreciation, Depletion and Amortization $ 10,187 12,324 15,961 17,164
General and Administrative Expenses $ 4,577 7,527 7,094 7,759
Northstar Combination Expenses $ — — — —
Interest Expense $ 2,193 2,495 1,956 2,209
Deferred Effects of Change in Currency Rates
on Subsidiary’s Long-term Debt $ — — — —
Distributions on Preferred Securities of Subsidiary Trust(1) $ — — — —
Reduction of Carrying Value of Oil and Gas Properties $ — — — 25,000
Income Tax Expense (Benefit)(2) $ (3,532) 2,344 4,828 (1,211)
Total Expenses $ 24,075 40,013 46,286 68,207
Net Earnings (Loss) $ 5,524 5,979 12,277 (6,438)
Preferred Stock Dividends(3) $ — 821 2,324 2,270
Net Earnings (Loss) to Common Shareholders $ 5,524 5,158 9,953 (8,708)
Net Earnings (Loss) per Common Share - Basic $ 0.44 0.36 0.65 (0.57)
Net Earnings (Loss) per Common Share - Diluted $ 0.44 0.36 0.59 (0.57)
Cash Margin(4) $ 12,179 20,572 32,721 34,312
Weighted Average Common Shares Outstanding - Basic 12,480 14,237 15,211 15,362
BALANCE SHEET DATA (In Thousands)
Total Assets $ 133,767 167,394 209,447 199,375
Long-term Debt $ 31,318 9,500 28,000 32,000
Other Long-term Obligations $ 6,337 5,071 3,919 3,369
Deferred Income Taxes $ 12,161 14,523 18,877 17,511
Preferred Securities of Subsidiary Trust(1) $ — — — —
Stockholders’ Equity $ 73,498 122,591 133,693 123,788
Common Shares Outstanding 14,080 15,220 15,380 15,420
(1) Trust convertible preferred securities were issued on July 10, 1996. Due to the date of issuance, 1996 distributions represent less than two quarters of payments.
(2) Includes a one-time non-cash gain of $3.9 million in 1988 from the required adoption of Statement of Financial
Accounting Standards No. 96 and a one-time non-cash loss of $1.3 million in 1993 from the required adoption of Statement of
Financial Accounting Standards No.109.
(3) Shares of $1.94 convertible preferred stock were issued on August 23, 1989 and converted to common stock on November 2, 1992.
Thus preferred dividends were paid for approximately 38 months.
(4) Revenues less cash expenses.
NM Not a meaningful figure.
Selected Eleven-Year Financial Data

5-YEAR 10-YEAR
GROWTH GROWTH
1992 1993 1994 1995 1996 1997 1998 RATE RATE
62,425 88,004 92,352 115,606 136,023 207,725 143,624 10% 25%
47,510 69,574 74,048 71,194 101,443 219,459 209,344 25% 35%
3,091 6,891 7,195 9,091 19,299 24,920 16,692 19% 57%
6,477 9,718 13,953 14,252 34,570 47,555 17,848 13% 17%
119,503 174,187 187,548 210,143 291,335 499,659 387,508 17% 29%
32,981 47,208 50,864 58,776 69,614 120,124 127,400 22% 28%
45,745 53,967 67,392 73,440 70,307 169,108 123,844 18% 28%
8,972 13,013 13,908 14,906 15,111 24,381 23,554 13% 18%
— — — — — — 13,149 NM NM
4,416 4,807 6,384 10,885 12,662 18,788 22,632 36% 26%
— — — 307 199 5,860 16,104 NM NM
— — — — 4,753 9,717 9,717 NM NM
— — 21,679 97,061 — 625,514 126,900 NM NM
7,214 19,367 10,396 (19,339) 51,086 (173,842) (15,507) NM NM
99,328 138,362 170,623 236,036 223,732 799,650 447,793 26% 34%
20,175 35,825 16,925 (25,893) 67,603 (299,991) (60,285) NM NM
1,703 — — — — — — NM NM
18,472 35,825 16,925 (25,893) 67,603 (299,991) (60,285) NM NM
0.87 1.23 0.54 (0.80) 2.06 (6.38) (1.25) NM NM
0.78 1.23 0.54 (0.80) 1.99 (6.38) (1.25) NM NM
71,643 107,248 115,436 120,284 181,361 299,792 183,369 11% 31%
21,220 29,074 31,114 32,473 32,812 47,040 48,376 11% 15%
367,614 507,883 631,953 715,510 1,183,290 1,248,986 1,226,356 19% 25%
78,057 102,240 106,764 220,137 83,000 305,337 405,271 32% 29%
2,851 3,826 8,380 19,792 18,208 29,464 34,747 55% 19%
20,925 36,972 55,018 32,933 107,003 31,825 33,219 -2% 11%
— — — — 149,500 149,500 149,500 NM NM
239,183 315,861 410,916 394,647 678,772 596,546 522,963 11% 22%
28,490 29,450 32,360 32,580 42,880 48,290 48,425 10% 13%

OVERVIEW
On June 29, 1998, Devon and Northstar
Energy Corporation (“Northstar”) announced
their intent to merge. The combination of the two
companies (the “Northstar Combination”) was
closed on December 10, 1998. As a result of this
transaction, Devon issued the equivalent of 16.1
million common shares and assumed $307
million of long-term debt. The Northstar
Combination increased Devon’s proved oil and
gas reserves by 115 MMBoe, or 62%, and its
undeveloped acreage by 1.8 million acres, or
193%.
The merger with Northstar was the largest
transaction in Devon’s history. All of Northstar’s
operations are located in Canada, principally in
the province of Alberta. The Northstar
Combination established critical mass for Devon
in Canada. The company believes that it now has
sufficient size to enjoy a fuller range of opportu-
nities of doing business in Canada.
The Northstar Combination significantly
expanded Devon’s operations. However, another
significant contributing factor to Devon’s growth
over the last three years was Devon’s December
31, 1996, acquisition of all of Kerr-McGee
Corporation’s North American onshore oil and
gas exploration and production business and
properties (the “KMG-NAOS Properties”). Devon
acquired the KMG-NAOS Properties in exchange
for approximately 10 million shares of Devon
common stock. At that time, this transaction
increased Devon’s proved reserves by 62 MMBoe,
or 50%.
Devon’s drilling and development efforts
have also helped fuel the company’s growth over
the last three years. Excluding Northstar, Devon
spent approximately $309 million on exploration
and development efforts from 1996 through
1998. These costs included drilling 765 wells, of
which 742 were completed as producers.
The Northstar Combination was accounted
for under the pooling-of-interests method of
accounting for business combinations.
Accordingly, Devon’s prior years’ results have
been restated to combine the company’s results
with those of Northstar 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
Northstar had been combined for all such
periods. Although this is consistent with the
financial presentation of the Northstar
Combination, it disguises the substantial changes
in Devon’s operations that have occurred as a
result of the Northstar Combination.
To present the effects that the Northstar
Combination, the KMG-NAOS Properties acquisi-
tion and Devon’s drilling and development efforts
have had on operations during the last three
years, the following statistics have been
developed. This data assumes that the Northstar
Combination was closed at the beginning of
1998, but that prior year results were not
restated. Thus, it compares Devon’s 1998 results,
including Northstar, to those of 1996 for Devon
only, without Northstar. Such comparison yields
the following fluctuations:
• Combined oil, gas and NGLs production
increased 25.3 million Boe, or 236%.
• Despite a 32% decrease in the combined average
price of oil, gas and NGLs, total revenues increased
$223.5 million, or 136%.
• Net cash provided by operating activities
increased $104.8 million, or 121%. Cash margin
increased $87.4 million, or 91%.
• Net earnings dropped from $34.8 million in
1996 to a net loss of $60.3 million in 1998.
However, 1998’s net loss included approximately
$108.5 million of after-tax charges from a full cost
ceiling writedown, non-cash foreign currency
charges and merger costs. Excluding these charges,
1998’s net earnings as compared to 1996 would have
increased $13.4 million, or 39%.
• Operating expenses per Boe of production
decreased $0.40 per Boe, or 10%.
• Depreciation, depletion and amortization of oil
and gas properties per Boe decreased $0.56 per Boe,
or 14%.
• General and administrative expenses per Boe
decreased $0.20 per Boe, or 24%.
During 1998, Devon marked its tenth
anniversary as a public company. While Devon
has consistently increased production over this
ten-year period, volatility in oil and gas prices has
resulted in considerable variability in earnings
and cash flows. Prices for oil, natural gas and
NGLs are determined primarily by market
conditions. Market conditions for these products
have been, and will continue to be, influenced by
regional and world-wide economic growth,
weather and other factors that are beyond Devon’s
control. Devon’s future earnings and cash flows
will continue to depend on market conditions.
Like all oil and gas production companies,
Management’s Discussion & Analysis of
Financial Condition and Results of Operations

Devon faces the challenge of natural production
decline. As virgin pressures are depleted, oil and
gas production from a given well naturally
decrease. Thus, an oil and gas production
company depletes part of its asset base with each
unit of oil and gas it produces. Over time, Devon
has historically been able to overcome this
natural decline by adding more reserves through
drilling and acquisitions than it produces.
However, Devon’s future growth, if any, will
depend on its ability to continue to add reserves
in excess of production.
Because oil and gas prices are influenced by
many factors which are outside of its control,
Devon’s management has focused its efforts on
increasing oil and gas reserves and production
and on controlling expenses. Over its ten year
history as a public company, Devon has been able
to significantly reduce its operating costs per unit
of production. While Devon’s per-unit operating
costs had been increasing since 1994, the
Northstar Combination reduced 1998’s per-unit
operating costs on a consolidated basis by
approximately $0.65 per Boe. Devon’s future
earnings and cash flows are dependent on its
ability to continue to contain operating costs at
levels that allow for profitable production of its
oil and gas reserves. This is especially important
considering the current depressed market for oil
and gas prices.
RESULTS OF OPERATIONS
Devon’s total revenues have risen from
$291.3 million in 1996 to $499.7 million in 1997
and $387.5 million in 1998. In each of these
years, oil, gas and NGLs sales accounted for over
88% of total revenues.
Changes in oil, gas and NGLs production,
prices and revenues from 1996 to 1998 are shown
in the table below. (Unless otherwise stated, all
references in this discussion to dollar amounts
regarding Devon’s Canadian operations are
expressed in U.S. dollars.)
TOTAL 1998 1997
Year Ended December 31, 1998 vs 1997 1997 vs 1996 1996
(Absolute Amounts in Thousands)
Production
Oil (MBbls) 11,903 +1% 11,783 +74% 6,780
Gas (MMcf) 133,065 +9% 121,810 +96% 62,186
NGLs (MBbls) 1,939 +3% 1,891 +51% 1,255
Oil, Gas and NGLs (MBoe) 36,020 +6% 33,976 +85% 18,399
Revenues
Per Unit of Production:
Oil (per Bbl) $ 12.07 -32% 17.63 -12% 20.06
Gas (per Mcf) $ 1.57 -13% 1.80 +10% 1.63
NGLs (per Bbl) $ 8.61 -35% 13.18 -14% 15.38
Oil, Gas and NGLs (per Boe) $ 10.26 -23% 13.31 -5% 13.96
Absolute:
Oil $ 143,624 -31% 207,725 +53% 136,023
Gas $ 209,344 -5% 219,459 +116% 101,443
NGLs $ 16,692 -33% 24,920 +29% 19,299
Oil, Gas and NGLs $ 369,660 -18% 452,104 +76% 256,765

DOMESTIC 1998 1997
Production
Oil (MBbls) 5,646 -7% 6,055 +59% 3,816
Gas (MMcf) 65,907 +8% 61,015 +71% 35,714
NGLs (MBbls) 1,373 -6% 1,468 +54% 952
Revenues
Oil (per Bbl) $ 12.45 -35% 19.08 -9% 21.00
Gas (per Mcf) $ 1.92 -16% 2.28 +19% 1.91
NGLs (per Bbl) $ 8.79 -33% 13.18 -13% 15.09
Oil, Gas and NGLs (per Boe) $ 11.59 -25% 15.48 +2% 15.16
Absolute:
Oil $ 70,286 -39% 115,504 +44% 80,142
Gas $ 126,273 -9% 139,018 +104% 68,049
NGLs $ 12,071 -38% 19,338 +35% 14,367
Oil, Gas and NGLs $ 208,630 -24% 273,860 +68% 162,558
CANADA 1998 1997
Production
Oil (MBbls) 6,257 +9% 5,728 +93% 2,964
Gas (MMcf) 67,158 +10% 60,795 +130% 26,472
NGLs (MBbls) 566 +34% 423 +40% 303
Revenues
Oil (per Bbl) $ 11.72 -27% 16.10 -15% 18.85
Gas (per Mcf) $ 1.24 -6% 1.32 +5% 1.26
NGLs (per Bbl) $ 8.16 -38% 13.20 -19% 16.28
Oil, Gas and NGLs (per Boe) $ 8.94 -18% 10.95 -11% 12.27
Absolute:
Oil $ 73,338 -20% 92,221 +65% 55,881
Gas $ 83,071 +3% 80,441 +141% 33,394
NGLs $ 4,621 -17% 5,582 +13% 4,932
Oil, Gas and NGLs $ 161,030 -10% 178,244 +89% 94,207
OIL REVENUES 1998 vs. 1997 Oil revenues
decreased $64.1 million in 1998. An average price
decline of $5.56 per barrel reduced revenues by
$66.2 million. This was slightly offset by $2.1
million of revenues added by production gains of
120,000 barrels.
1997 vs. 1996 Oil revenues increased $71.7
million in 1997. Production gains of 5.0 million
barrels added $100.4 million of oil revenues in
1997. This increase was partially offset by a $28.7
million reduction in oil revenues due to price
declines in 1997. The average oil price decreased
$2.43 per barrel in 1997.
In March 1997, Northstar acquired all the
outstanding common shares of Morrison
Petroleums Ltd., an independent oil and gas
producer also located in Alberta, Canada.
Northstar acquired the Morrison Petroleums Ltd.
shares by issuing additional shares of Northstar
(the “Morrison Transaction”). The March 1997

Morrison Transaction and the KMG-NAOS
Properties acquired at the end of 1996 were the
primary contributors to the increased oil produc-
tion in 1997. The KMG-NAOS Properties added
3.1 million barrels of 1997 production. The
Morrison Transaction added 2.7 million barrels
during the last nine months of 1997.
GAS REVENUES 1998 vs. 1997 Gas revenues
decreased $10.1 million in 1998. An average price
decline of $0.23 per Mcf reduced revenues by
$30.4 million. This was partially offset by higher
production in 1998. A production increase of
11.3 Bcf in 1998 added gas revenues of $20.3
million.
Our coal seam gas properties produced 19.9
Bcf in 1998 compared to 17.6 Bcf in 1997. During
the last two years, the company conducted a
program of mechanical improvements at the
Northeast Blanco Unit coal seam gas property.
The majority of the production gains realized in
1998 were the result of these improvements.
The coal seam properties averaged $1.72 per
Mcf in 1998 compared to $2.13 per Mcf in 1997.
In 1995, we entered into a transaction covering
substantially all of our San Juan Basin coal seam
gas properties (the “San Juan Basin Transaction”).
This transaction is described in detail in Note 3
to our consolidated financial statements included
later in this report. The San Juan Basin
Transaction added $8.4 million to coal seam gas
revenues in both 1998 and 1997. The San Juan
Basin Transaction’s effect on the coal seam gas
properties’ average price was an increase of $0.42
per Mcf in 1998 and $0.48 per Mcf in 1997.
1997 vs. 1996 Gas revenues increased
$118.0 million in 1997. A 59.6 Bcf increase in
production added $97.3 million to 1997’s gas
revenues. A $0.17 per Mcf increase in 1997’s
average gas price added the remaining $20.7
million of increased revenues.
The KMG-NAOS Properties and the
Morrison Transaction were responsible for the
majority of the increased gas production in 1997.
The KMG-NAOS Properties produced 29.8 Bcf in
1997. The Morrison Transaction added 26.4 Bcf
in the last nine months of the year. Our coal seam
gas properties produced 17.6 Bcf in 1997
compared to 17.4 Bcf in 1996.
The coal seam properties averaged $2.13 per
Mcf in 1997 compared to $1.72 per Mcf in 1996.
The San Juan Basin Transaction added $8.4
million to coal seam gas revenues in 1997
compared to $10.3 million in 1996. The San Juan
Basin Transaction increased the average coal seam
gas price by $0.48 per Mcf in 1997 and $0.59 per
Mcf in 1996.
NGLs REVENUES 1998 vs. 1997 NGLs
revenues decreased $8.2 million in 1998. An
average price decline of $4.57 per barrel caused
revenues to drop by $8.9 million. This decline
was only slightly offset by production increases of
48,000 barrels. The production gains added $0.7
million of revenues in 1998.
1997 vs. 1996 NGLs revenues increased $5.6
million in 1997. A production increase of
636,000 barrels added $9.8 million to 1997’s
revenues. This was partially offset by a $4.2
million reduction in revenues caused by lower
prices in 1997. The average NGLs price dropped
$2.20 per barrel in 1997.
The majority of the increased production in
1997 was attributable to the KMG-NAOS
Properties and the Morrison Transaction. The
KMG-NAOS Properties added 339,000 barrels to
1997’s production. The Morrison Transaction
added 161,000 barrels during the last nine
months of 1997.
OTHER REVENUES 1998 vs. 1997 Other
revenues decreased $29.7 million in 1998. This
decrease was primarily due to Northstar’s $29.4
million of gains from asset sales in 1997 which
did not recur in 1998.
1997 vs. 1996 Other revenues increased
$13.0 million in 1997. Northstar’s gains from
sales of assets increased $18.8 million in 1997.
Northstar’s pipeline revenues decreased $3.5
million and its equity earnings from unconsoli-
dated subsidiaries decreased $3.2 million in 1997.

EXPENSES The details of the changes in pre-tax expenses between 1996 and 1998 are shown in the
table below.
1998 1997
Absolute:
Production and operating expenses:
Lease operating expenses $ 113,484 +12% 100,897 +72% 58,734
Production taxes 13,916 -28% 19,227 +77% 10,880
Depreciation, depletion and amortization
of oil and gas properties 119,719 -27% 164,977 +143% 67,832
Subtotal 247,119 -13% 285,101 +107% 137,446
Depreciation and amortization of
non-oil and gas properties 4,125 - 4,131 +67% 2,475
General and administrative expenses 23,554 -3% 24,381 +61% 15,111
Northstar Combination expenses 13,149 N/A - N/A -
Interest expense 22,632 +20% 18,788 +48% 12,662
Deferred effect of changes in foreign currency
exchange rate on subsidiary’s long-term debt 16,104 +175% 5,860 N/A 199
Distributions on preferred securities of
subsidiary trust 9,717 - 9,717 +104% 4,753
Reduction of carrying value of oil and gas
properties 126,900 -80% 625,514 N/A -
Total $ 463,300 -52% 973,492 464% 172,646
Per Boe Produced:
Production and operating expenses:
Lease operating expenses $ 3.15 +6% 2.97 -7% 3.19
Production taxes 0.39 -32% 0.57 -3% 0.59
Depreciation, depletion and amortization
of oil and gas properties 3.32 -32% 4.86 +32% 3.69
Subtotal 6.86 -18% 8.40 +12% 7.47
Depreciation and amortization of non-oil and
gas properties (1) 0.12 - 0.12 -8% 0.13
General and administrative expenses (1) 0.65 -10% 0.72 -12% 0.82
Northstar Combination expenses (1) 0.36 N/A - N/A -
Interest expense (1) 0.63 +15% 0.55 -20% 0.69
Deferred effect of changes in foreign currency
exchange rate on subsidiary’s long-term debt (1) 0.45 +165% 0.17 N/A 0.01
Distributions on preferred securities of
subsidiary trust (1) 0.27 -4% 0.28 +8% 0.26
Reduction of carrying value of oil and gas
properties (1) 3.52 -81% 18.41 N/A -
Total $ 12.86 -55% 28.65 +205% 9.38
(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.

PRODUCTION AND OPERATING EXPENSES The details of the changes in production and operating
expenses between 1996 and 1998 are shown in the table below.
TOTAL 1998 1997
Absolute:
Recurring lease operating expenses $ 107,554 +11% 96,738 +79% 54,171
Well workover expenses 5,930 +43% 4,159 -9% 4,563
Total production and operating expenses $ 127,400 +6% 120,124 +73% 69,614
Per Boe:
Recurring lease operating expenses $ 2.99 +5% 2.85 -3% 2.94
Well workover expenses 0.16 +33% 0.12 -52% 0.25
Production taxes 0.39 -32% 0.57 -3% 0.59
Total production and operating expenses $ 3.54 - 3.54 -6% 3.78
DOMESTIC 1998 1997
Absolute:
Per Boe:
Recurring lease operating expenses $ 3.38 +9% 3.10 +17% 2.64
Production taxes 0.68 -32% 1.00 +1% 0.99
Total production and operating expenses $ 4.32 +1% 4.28 +9% 3.94
CANADA 1998 1997
Absolute:
Production taxes 1,661 +5% 1,581 +612% 222
Per Boe:
Recurring lease operating expenses $ 2.59 +1% 2.56 -24% 3.37
Production taxes 0.09 -10% 0.10 +233% 0.03
Total production and operating expenses $ 2.75 +1% 2.72 -24% 3.57
1998 vs. 1997 Recurring lease operating expenses increased $10.8 million, or 11%, in 1998. The
primary cause of this increase was the addition of wells drilled or acquired during the year, plus the
effect of having a full year of operations from the Morrison Transaction properties in 1998 compared to
only nine months in 1997.

The recurring expenses per Boe increased
$0.14 per Boe, or 5%, in 1998. This increase was
predominantly caused by the 9% increase in our
domestic properties’ costs per Boe. The operating
expenses of the additional domestic wells drilled
during the year raised the overall average costs
per Boe in the U.S.
The majority of Devon’s production taxes are
assessed on its domestic properties. In the U.S.,
most of the production taxes paid are based on a
fixed percentage of revenues. Therefore, the 24%
drop in domestic oil, gas and NGLs revenues was
the primary cause of the 31% decrease in
domestic production taxes.
1997 vs. 1996 Recurring lease operating
expenses increased $42.6 million, or 79%, in
1997. The KMG-NAOS Properties accounted for
$26.0 million of the increased expenses. The
Morrison Transaction added $16.5 million during
the last nine months of 1997.
Recurring expenses per Boe were down $0.09
per Boe, or 3%, in 1997. The addition of the
properties acquired in the Morrison Transaction
accounted for the majority of this decrease in per
unit costs. These properties’ costs per Boe for the
last nine months of 1997 were $2.28 per Boe.
This compares to $3.00 per Boe for all other
properties during the year 1997.
Domestic production taxes increased 66% in
1997. This increase was mostly due to the 68%
increase in the U.S. combined oil, gas and NGLs
revenues.
DEPRECIATION, DEPLETION AND
AMORTIZATION (“DD&A”) Devon’s largest
recurring non-cash expense is DD&A. DD&A of
oil and gas properties is calculated as the
percentage of total proved reserve volumes
produced during the year, multiplied by the net
capitalized investment in those reserves including
estimated future development costs (the
“depletable base”). Generally, if reserve volumes
are revised up or down, then the DD&A rate per
unit of production will change inversely.
However, if capitalized costs change, 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
for the domestic and Canadian properties.
1998 vs. 1997 Oil and gas property related
DD&A decreased $45.3 million, or 27%, in 1998.
A 32% drop in the consolidated DD&A rate per
Boe from $4.86 in 1997 to $3.32 in 1998 reduced
1998’s DD&A expense by $55.2 million. This
decrease was partially offset by $9.9 million of
increased expense caused by the 6% increase in
combined oil, gas and NGLs production in 1998.
The domestic DD&A rate per Boe increased from
$4.13 in 1997 to $4.24 in 1998. However, the
Canadian DD&A rate per Boe decreased from
$5.64 in 1997 to $2.41 in 1998. The $625.5
million reduction in the carrying value of
Canadian oil and gas properties recorded at the
end of 1997 caused the drop in the Canadian
DD&A rate in 1998.
1997 vs. 1996 Oil and gas property related
DD&A increased $97.1 million, or 143%, in
1997. Approximately $57.4 million of the
increase was caused by the 85% increase in
combined oil, gas and NGLs production in 1997.
The remaining $39.7 million was caused by a
32% increase in the combined domestic and
Canadian DD&A rate. The combined rate
increased from $3.69 per Boe in 1996 to $4.86
per Boe in 1997. The domestic rate increased
from $3.88 per Boe in 1996 to $4.13 per Boe in
1997. The Canadian rate increased from $3.42
per Boe in 1996 to $5.64 per Boe in 1997. The
increase in 1997’s Canadian rate was caused by
the cost per Boe of the properties acquired in the
Morrison Transaction.
GENERAL AND ADMINISTRATIVE EXPENSES
(“G&A”) 1998 vs. 1997 G&A decreased $0.8
million, or 3%, in 1998. Employee salaries and
related overhead costs, including insurance and
pension expense, increased $3.0 million in 1998
due to a combination of compensation increases
and an increase in the number of personnel
employed.
The higher salary and overhead costs were
partially offset by an increase in the amount of
such costs that were capitalized pursuant to the
full cost method of accounting. Approximately
$9.6 million of costs were capitalized in 1998,
compared to $7.6 million in 1997.
The higher salary and overhead costs were
also partially offset by an increase in Devon’s
overhead reimbursements. As the operator of a
property, the company receives these reimburse-
ments from the property’s working interest
owners and records them as reductions to G&A.
These reimbursements increased $1.9 million in
1998.

1997 vs. 1996 G&A increased $9.3 million,
or 61% in 1997. Employee salaries and related
overhead costs, including insurance and pension
expense, increased $11.7 million. This increase
was primarily related to the additional permanent
and temporary personnel added at our Oklahoma
City and Calgary offices as a result of the acquisi-
tion of the KMG-NAOS Properties and the
Morrison Transaction. The personnel expansion
also caused office-related costs such as rent, dues,
travel, supplies, telephone, etc., to increase $3.3
million in 1997.
The higher salary, overhead and office costs
were partially offset by an increase in the amount
of such costs that were capitalized pursuant to
the full cost method of accounting.
Approximately $7.6 million of costs were capital-
ized in 1997, compared to $4.9 million capital-
ized in 1996.
The higher salary, overhead and office costs
were also partially offset by an increase in Devon’s
overhead reimbursements. Due largely to the
acquisition of the KMG-NAOS Properties and the
Morrison Transaction, overhead reimbursements
increased $4.4 million in 1997.
NORTHSTAR COMBINATION EXPENSES
Approximately $13.1 million of expenses were
incurred in 1998 in connection with the
Northstar Combination. These expenses
consisted primarily of investment bankers’ fees,
legal fees and costs of printing and distributing
the proxy statement to shareholders. The
pooling-of-interests method of accounting for
business combinations requires such costs to be
expensed as opposed to capitalized as costs of the
transaction.
INTEREST EXPENSE 1998 vs. 1997 Interest
expense increased $3.8 million, or 20%, in 1998.
The average interest rate increased from 5.4% in
1997 to 6.7% in 1998. The increase in the average
rate was primarily due to the fact that Northstar
replaced a large portion of its floating rate debt
with longer term, fixed rate debt early in 1998.
The increase in 1998’s average rate caused a $4.4
million increase in interest expense. The average
debt balance increased from $267.0 million in
1997 to $324.7 million in 1998. This increase in
the debt outstanding caused interest expense to
increase $3.1 million. The increases caused by
higher rates and higher balances outstanding were
partially offset by the fact that 1997’s interest
expense included a $3.3 million “make-whole”
payment related to the early retirement of debt.
Other items included in interest expense that are
not related to the balance of debt outstanding,
such as facility and agency fees, amortization of
costs and other miscellaneous items were $0.4
million lower in 1998 compared to 1997.
1997 vs. 1996 Interest expense increased
$6.1 million, or 48%, in 1997. The average long-
term debt balance increased from $183.8 million
in 1996 to $267.0 million in 1997. This increase
in the average balance caused interest expense to
increase $5.1 million. The average interest rate
decreased from 6.1% in 1996 to 5.4% in 1997.
The interest rate decrease reduced interest
expense $2.0 million in 1997. Interest expense in
1997 also included the $3.3 million make-whole
payment discussed in the above paragraph. Other
items included in interest expense that are not
related to the balance of debt outstanding were
$0.3 million lower in 1997 compared to 1996.
Devon’s average domestic long-term debt
balance was almost eliminated in 1997, as it
dropped from an average of $77.0 million in 1996
to only $0.7 million in 1997. Devon issued
$149.5 million of 6.5% Trust Convertible
Preferred Securities (“TCP Securities”) in July,
1996. The proceeds from this issuance, along
with cash flow from operations, were used to
retire all domestic long-term debt by the end of
the first quarter of 1997. (The TCP Securities are
discussed further in this section.)
However, the drop in Devon’s average
domestic debt balance was more than offset by an
increase in the Canadian average balance in 1997.
Following the Morrison Transaction, Northstar
repurchased $217 million of common shares
which was financed with long-term debt. As a
result, the Canadian average long-term debt
balance increased from $106.8 million in 1996 to
$266.3 million in 1997.
DEFERRED EFFECT OF CHANGES IN FOREIGN
CURRENCY EXCHANGE RATE ON SUBSIDIARY’S
LONG-TERM DEBT Northstar has 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 issued to the dates of
repayment will 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.
1998 vs. 1997 The principal balance of
Northstar’s U.S. dollar denominated notes
increased from $135 million at the end of 1997 to
$225 million at the end of 1998. The rate of
converting Canadian dollars to U.S. dollars
decreased from $0.6997 at the end of 1997 to
$0.6535 at the end of 1998. The combination of
these factors caused $16.1 million to be recorded
as an expense in 1998.
1997 vs. 1996 The principal balance of
Northstar’s U.S. dollar denominated notes
increased from $75 million at the end of 1996 to
$135 million at the end of 1997. The rate of
converting Canadian dollars to U.S. dollars
decreased from $0.7301 at the end of 1996 to
$0.6997 at the end of 1997. The combination of
these factors caused $5.9 million to be recorded
as an expense in 1997.
DISTRIBUTIONS ON PREFERRED SECURITIES
OF SUBSIDIARY TRUST 1998 vs. 1997 As
mentioned earlier in this discussion, and as
discussed in Note 9 to the consolidated financial
statements, Devon, through its affiliate Devon
Financing Trust, completed the issuance of
$149.5 million of 6.5% TCP Securities in a
private placement in July, 1996. The distributions
accrue and are paid at the rate of 1.625% per
quarter.
1997 vs. 1996 The TCP Securities distribu-
tions in 1997 were $9.7 million compared to $4.8
million in 1996. The 1996 distribution total
represented slightly less than two quarters’ distri-
butions due to the issuance date occurring in July
of that year.
REDUCTION OF CARRYING VALUE OF OIL
AND GAS PROPERTIES Under the full cost
method of accounting, the net book value of oil
and gas properties, less related deferred income
taxes, may not exceed a calculated “ceiling.” The
ceiling limitation is the discounted estimated
after-tax future net revenues from proved oil and
gas properties. The ceiling is imposed separately
by country. In calculating future net revenues,
current prices and costs are generally held
constant indefinitely. The net book value, less
deferred tax liabilities, is compared to the ceiling
on a quarterly and annual basis. Any excess of
the net book value, less deferred taxes, is written
off as an expense.
1998 Reduction As of September 30, 1998,
the carrying value of Devon’s domestic properties,
less deferred income taxes, exceeded the full cost
ceiling by $88 million. Accordingly, a $126.9
million pre-tax reduction of the carrying value of
such properties was recorded in the third quarter
of 1998. This reduction was partially offset by a
related $38.9 million deferred income tax benefit,
resulting in an after-tax charge of $88 million.
1997 Reduction As of December 31, 1997,
the carrying value of Northstar’s oil and gas
properties, less deferred income taxes, exceeded
the full cost ceiling by $397.9 million.
Accordingly, a $625.5 million pre-tax reduction of
the carrying value of such properties was
recorded in the fourth quarter of 1997. This
reduction was partially offset by a related $227.6
million deferred income tax benefit, resulting in
an after-tax charge of $397.9 million.
INCOME TAXES 1998 vs. 1997 Devon’s
effective financial income tax benefit rate in 1998
was 20% compared to a benefit rate in 1997 of
37%. The benefit rate in 1998 was lower than in
1997 due to a combination of a smaller pre-tax
loss in 1998 and certain 1998 financial expenses
that are not deductible for income tax purposes.
Approximately $27.2 million of the $126.9
million reduction of carrying value of oil and gas
properties related to costs which are not
deductible for income taxes. Also, approximately
$5.6 million of the Northstar Combination
expenses and $4.0 million of the deferred effect
of changes in foreign currency exchange rate on
the subsidiary’s long-term debt are not deductible
for income tax purposes.
1997 vs. 1996 Devon’s effective financial
income tax (benefit) rate in 1997 was (37%)
compared to 43% in 1996. The benefit rate in
1997, as an absolute percentage, was lower than
1996’s tax rate due to the financial deduction of
costs in 1997 that were not deductible for income
tax purposes. As previously discussed, Northstar
recorded in 1997 a $625.5 million reduction of
carrying value of oil and gas properties.
Approximately $115.3 million of the reduction
related to costs which are not deductible for
income tax purposes. These non-deductible costs
were the primary reason for the low benefit rate
in 1997.

CAPITAL EXPENDITURES, CAPITAL
RESOURCES AND LIQUIDITY
The following discussion of capital expendi-
tures, capital resources and liquidity should be
read in conjunction with the consolidated
statements of cash flows included in this report.
CAPITAL EXPENDITURES Approximately
$375.5 million was spent in 1998 for capital
expenditures, of which $371.3 million was
related to the acquisition, drilling or development
of oil and gas properties. These amounts compare
to 1997 total expenditures of $288.0 million
($279.9 million of which was related to oil and
gas properties) and 1996 total expenditures of
$268.7 million ($254.5 million of which was
related to oil and gas properties).
OTHER CASH USES Devon’s common stock
dividends were $7.3 million, $6.4 million and
$5.0 million in 1998, 1997 and 1996, respec-
tively.
CAPITAL RESOURCES AND LIQUIDITY Net
cash provided by operating activities (“operating
cash flow”) has historically been the primary
source of Devon’s capital and short-term liquidity.
Operating cash flow was $191.6 million, $253.1
million and $144.2 million in 1998, 1997 and
1996, respectively. The trends in operating cash
flow during these periods have generally followed
those of the various revenue and expense items
previously discussed in this section.
In addition to operating cash flow, Devon’s
credit lines and the private placement of long-
term debt have been an important source of
capital and liquidity. During the years 1998 and
1997, long-term debt borrowings, net of
repayments, totaled $55.3 million and $127.2
million, respectively. In 1996, due to the applica-
tion of the TCP Securities’ proceeds against
outstanding debt, repayments of debt exceeded
borrowings by $47.9 million.
Following the closing of the Northstar
Combination in December 1998, Devon entered
into new unsecured long-term credit facilities
aggregating $400 million (the “Credit Facilities”).
The Credit Facilities include a U.S. facility of
$205 million (the “U.S. Facility”) and a Canadian
facility of $195 million (the “Canadian Facility”).
The Credit Facilities replaced Devon’s and
Northstar’s separate credit facilities that were in
place prior to the Northstar Combination. Of the
$180.3 million borrowed against the Credit
Facilities at December 31, 1998, $35 million was
borrowed under the U.S. Facility and $145.3
million was borrowed under the Canadian
Facility. 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. Devon may also elect to borrow at the
prime rate. The average interest rate on the
$180.3 million of debt outstanding at December
31, 1998, was 5.9%. The Credit Facilities also
provide for an annual facility fee of $0.4 million
that is payable quarterly.
The $205 million U.S. Facility consists of a
Tranche A facility of $130 million and a Tranche
B facility of $75 million. The Tranche A facility
matures on December 10, 2003. Devon may
borrow funds under the Tranche B facility until
December 10, 1999 (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
not more than 60 days prior to the end of the
Tranche B Revolving Period. Debt borrowed
under the Tranche B facility matures two years
following the end of the Tranche B Revolving
Period. All $35 million of debt outstanding under
the U.S. Facility at December 31, 1998, was
borrowed under the Tranche A facility.
Devon may borrow funds under the $195
million Canadian Facility until December 10,
1999 (the “Canadian Facility Revolving Period”).
The company may request that the Canadian
Facility Revolving Period be extended an
additional 364 days by notifying the agent bank
of such request not more than 90 days prior to
the end of the Canadian Facility Revolving
Period. Debt borrowed under the Canadian
Facility matures five years and one day following
the end of the Canadian Facility Revolving
Period.
YEAR 2000 STATUS Devon’s company-wide
Year 2000 Project (“the Project”) is proceeding on
schedule. The Project is addressing the Year 2000
issue caused by computer programs being written
utilizing two digits rather than four to define an
applicable year. As a result, Devon’s computer
equipment, software (all of which is externally
developed), and devices with embedded

Devon 1998 annual report

Recommended

Recommended

More Related Content

What's hot

What's hot (18)

Similar to Devon 1998 annual report

Similar to Devon 1998 annual report (20)

Recently uploaded

Recently uploaded (20)

Devon 1998 annual report