DevonEnergyCorporation

R O C K S O L I D .

1997 Annual Report

LETTER TO SHAREHOLDERS 3Devon’s President Discusses Major 1997Achievements and Challenges.

FIVE-YEAR FINANCIAL HIGHLIGHTS 6

ANOTHER RECORD YEAR 7Devon Extends Its Series of Record-BreakingFinancial Performances.

CEO INTERVIEW 9Larry Nichols Answers Your Questions.

A ROCK SOLID COMMITMENT 13TO EXPLORATION

Devon Augments Its Successful Acquisition andExploitation Strategies with Increased Emphasis on Exploratory Drilling.

A ROCK SOLID PORTFOLIO OF 18PRODUCING PROPERTIES

Devon Gives Key Property Highlights and Operating Statistics by Area.

FINANCIAL STATEMENTS AND 26MANAGEMENT’S DISCUSSION AND ANALYSIS

BOARD OF DIRECTORS 66

CORPORATE OFFICERS 67

GLOSSARY OF TERMS 68

INVESTOR INFORMATION AND 69COMMON STOCK TRADING DATA

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NC O N T E N T S

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This annual report includes “forward-looking statements” as defined by the Securities and ExchangeCommission. Such statements are those concerning Devon’s plans, expectations and objectives forfuture operations. These statements address future financial position, business strategy, future capitalexpenditures, projected oil and gas production and future costs. Devon believes that the expectationsreflected in such forward-looking statements are reasonable. However, important risk factors couldcause actual results to differ materially from the company’s expectations. A discussion of these riskfactors can be found in the “Management’s Discussion and 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.

ON THE COVER

GIANT GRANITE BOULDERS,

MANY MILLIONS OF YEARS OLD,

STAND THE TEST OF TIME

AT JOSHUA TREE NATIONAL

PARK IN CALIFORNIA.

DEVON’S FINANCIAL STABILITY

AND TIME-TESTED GROWTH

STRATEGIES FORM A

ROCK SOLID FOUNDATION

FOR THE FUTURE.

Devon Energy Corporation is an oil and gas exploration and

production company with its headquarters in Oklahoma City, Oklahoma.

We produce and sell oil and gas from wells located primarily in New

Mexico, Oklahoma, Texas, Wyoming and Alberta, 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.

expenditures went to higherrisk exploration projects.The results were more thansatisfactory. We drilled andcompleted 16 productiveexploratory wells whiledrilling only two exploratorydry holes. These resultshelped drive oil and gasreserve additions andrevisions to more than 20 million barrels of oilequivalent. These reserve additions exceeded thecompany’s 1997 record production.

We not only increased Devon’s drillingactivities in total, we increased the portion of theseactivities devoted to exploration. This shift reflectsDevon’s increasing commitment to exploration as ameans of future growth. During 1998, we plan tofurther expand our exploration activities. With $60to $70 million of our capital budget earmarked for1998 exploration projects, we are more than triplingthe resources devoted to exploration. In addition, werecently doubled the size of our exploration staff,added new 3-D seismic workstations and acquiredadditional seismic data. These measures support ourincreasing exploration focus.

THE CHALLENGES WERE CONSIDERABLE . . .

On December 31, 1996, the North Americanonshore oil and gas assets of Kerr-McGee

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No doubt, 1997 was simultaneously the mostrewarding and daunting year in Devon’s history.Rewarding in that virtually all of our operatingstatistics rose dramatically. Daunting in that we hadto grow organizationally into our new asset size andscope. It was a year of challenge and achievement.

THE ACHIEVEMENTS WERE MANY . . .

Once again, the company set all-time recordsin almost every area of financial and operationalperformance. We set our tenth consecutive recordfor year-end oil and gas reserves. We increased oiland gas production 88% from just one year ago tothe highest levels in the company’s history. Netearnings climbed 116% to a record $75 million in1997 — without the benefit of an increase in overalloil and gas prices. More importantly, earnings pershare rose to an all-time high of $2.34. Not only wasthis per share performance the best in the company’shistory, but 1997 earnings per share were 49% abovelast year’s record. By the traditional measures ofsuccess, 1997 was clearly a banner year for DevonEnergy Corporation. However, some of Devon’sother 1997 accomplishments may not be so obvious.

. . . INCLUDING DRILLING RESULTS

In 1997, Devon invested over $100 million —the largest drilling and facilities budget in thecompany’s history. We drilled 295 wells, of which284 were successfully completed as producers.

Over $19 million of our 1997 capital

D E A R FE L L O W S H A R E H O L D E R S

In 1997, Devon set its tenthconsecutive record for oil and

gas reserves...

92 93 94 95 96 97

6178

106 115

179 184

Proved Oil and Gas Reserves

(MMBoe)

92 93 94 95 96 97

6.38.7

9.5 10.010.7

20.2

Oil and Gas Production

(MMBoe)

...as well as oil and gas production...

J. Larry Nichols

92 93 94 95 96 97

7299 101

113

164

313

Total Revenues

($ Millions)

...increasing 1997 totalrevenues by more than 90%percent over 1996 revenues.

of 1996 and 1997, some in the industry began toinvest as if prices would never fall. The annualaverage price for oil and gas property acquisitionsjumped 14% to over $5.00 per Boe in 1997. Itappears from early returns that finding costs forexploration also rose. Companies making highpriced investments in energy assets based on 1997’shigh prices may be in for a rude awakening. In thefirst quarter of 1998, oil prices are some 45% belowthe highs of 1997.

At Devon, we try to look beyond short-termswings, positive or negative, in oil and gas prices.Though mergers and acquisitions have providedsubstantial growth for Devon in the past, weexecuted neither in 1997. We could not justify thehigh asking prices. Every acquisition we undertakemust provide an incremental return for ourshareholders by directly contributing to per shareresults. And prospective acquisitions are alwaysevaluated using conservative oil and gas priceassumptions. When high oil and gas pricestemporarily prevent us from achieving these goals,we withdraw from the acquisition market. We keepour balance sheet strong and wait for attractiveopportunities to reappear. This philosophy hasserved us well for many years. While numerousnames in our industry have come and gone, Devonhas not only weathered the effects of volatile oil andgas prices — we have prospered from them.

Corporation were merged into Devon. While thistransaction was negotiated and signed near the endof 1996, the work of merging these operations intoDevon had just begun. In 1997 we successfullyintegrated this new property base. This propertybase was larger than our entire company of just sixyears ago. We hired over 100 new employees,streamlined field operations, upgraded informationsystems and revamped large portions of Devon’sorganizational structure.

Rapid growth such as this does not occurwithout substantial challenges. Devon’s employees,old and new, faced these tests with extraordinaryoptimism, creativity and determination. The Devonteam was not satisfied to merely create the organiza-tional capacity to handle the growth in our propertybase from our December 1996 merger. We createdthe organizational foundation to facilitate continuedgrowth in the future.

. . . INCLUDING MAINTAINING DISCIPLINE

Perhaps Devon’s greatest achievement of 1997was what we did not do — invest unwisely. In ahighly motivated company like ours, the self-induced pressure to grow is intense. This has been amajor, positive factor in our merger and acquisitionrecord. However, at Devon, desire is balanced bydiscipline.

In a period of strong oil and gas prices, it iseasy to forget how quickly these prices can fall. Withrelatively high oil and gas prices prevailing for most

20

14 1515

35

75

Net Earnings

($ Millions)

Record oil and gas production droveDevon‘s 1997 net earnings up 116%

over 1996 net earnings...

92 93 94 95 96 97

...and almost doubled thecompany‘s cash margin.

92 93 94 95 96 97* Revenues less cash expenses.

3853 55 59

96

181

Cash Margin *

($ Millions)

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WE REMAIN “ROCK SOLID”

In an industry where commodity prices and,thus, revenues, can be very volatile, the phrase “rocksolid” is not often heard. Why would we choose toapply this to Devon?

First, our employees have exhibited thetechnical skills, motivation and loyalty to be thefoundation of our success. Our growth and trackrecord demonstrates this skill and motivation. Thefact that we rarely lose staff to competitors showsthe loyalty. This past year, when employee recruiting,if not raiding, was rampant, our staff remained loyal.

Second, our asset base is equally stable. Ouroil and gas reserve life index exceeds eight years.This gives us a consistency of operations and cashflow that is hard to match in our industry. Itprovides the stability that allows us to maintain ourinvestment discipline.

Third, our balance sheet is “bullet proof.”With no debt, substantial cash flow and sizeableassets, oil and gas price volatility has little impact onour endurance.

Fourth, our cost structure is low. This providesa significant competitive advantage in our industry.We can generate earnings and cash flow at even lowoil and gas prices . . . prices that would be genuinelypainful for many of our competitors.

Fifth, our prospects for growth are as good asever before.

THE OUTLOOK IS PROMISING

I am cautiously optimistic about Devon’sfuture as we enter 1998. The caution comes fromobserving current oil and gas prices. As indicated

previously, 1998 has opened with relatively low oilprices. This will hurt current revenues. But over thelong run, this may not prove so relevant. With ourlong-lived property base, a short-term decrease inprices will have minimal impact on these long-terminvestments.

The optimism comes from our prospects andfinancial strength. Our exploration and developmentprograms are better than ever. We have the largestportfolio of undeveloped acreage and seismic data inthe company’s history. The opportunities from ourproperty base are reflected in our 1998 drilling anddevelopment budget of some $150 million. Weanticipate funding this biggest-ever capital budgetentirely from working capital and operating cashflow. And should the right opportunity arise, webelieve we could fund a cash acquisition of morethan one-half billion dollars — without issuingadditional equity. Devon Energy Corporation istruly in a rock solid position for the future.

J. LARRY NICHOLS

President and Chief Executive Officer

Oklahoma City, OklahomaMarch 27, 1998

On May 31, 1997, H.R. Sanders, Jr. retired from his position as executive vice president of Devon. Over the last

16 years, H.R.’s business acumen and financial creativity have contributed immensely to Devon’s growth and

success. I speak for everyone at Devon when I say that we truly miss H.R.’s presence in our day-to-day

operations. However, we are continuing to take advantage of his many years of experience as he remains on

Devon’s board of directors.

92 93 94 95 96 97

Cash Margin Per Share

($)

2.762.54 2.56 2.68

4.33

5.63

...and drove 1997 cash margin pershare to an all-time record.

92 93 94 95 96 97

Earnings Per Share

($)

.94.98

.64 .66

1.57

2.34

Record production and revenuesincreased 1997 earnings per share

by 49%...

LASTYEAR

Year Ended December 31, 1993 1994 1995 1996 1997 CHANGE

FINANCIAL DATA (Thousands, except per share data)Total Revenues $ 98,757 100,773 113,303 164,017 313,140 91%Cash Expenses $ 45,864 45,699 54,086 68,066 131,695 93%

Cash Margin $ 52,893 55,074 59,217 95,951 181,445 89%

Non-cash Expenses $ 33,707 41,329 44,715 61,150 106,153 74%Unusual Gain(1) $ 1,300 — — — — NM

Net Earnings $ 20,486 13,745 14,502 34,801 75,292 116%

Net Earnings per Share:Basic $ 0.98 0.64 0.66 1.57 2.34 49%Diluted $ 0.98 0.63 0.65 1.52 2.17 43%

Cash Dividends per Common Share $ 0.09 0.12 0.12 0.14 0.20 43%LASTYEAR

December 31, 1993 1994 1995 1996 1997 CHANGE

Total Assets $ 285,553 351,448 421,564 746,251 846,403 13%Working Capital $ 15,140 8,305 9,316 19,734 62,416 216%Convertible Preferred Securities

of Subsidiary Trust (2) $ — — — 149,500 149,500 —Long-term Debt $ 80,000 98,000 143,000 8,000 — -100%

PROPERTY DATAReserves

Oil and Natural Gas Liquids (MBbls) 16,751 47,607 53,935 80,060 81,324 2%Gas (MMcf ) 369,254 347,560 363,846 595,519 616,004 3%Total (MBoe) 78,293 105,534 114,576 179,313 183,991 3%SEC @ 10% Present Value (Thousands)(3) $ 380,471 398,206 534,248 1,621,992 913,073 -44%

LASTYEAR

Year Ended December 31, 1993 1994 1995 1996 1997 CHANGE

ProductionOil and Natural Gas Liquids (MBbls) 2,748 2,968 3,900 4,768 8,631 81%Gas (MMcf ) 35,598 39,335 36,886 35,714 69,327 94%Total (MBoe) 8,681 9,524 10,047 10,720 20,185 88%

(1) One-time, non-cash gain of $1.3 million from the required adoption in 1993, of Statement of Financial Accounting Standards No.109.(2) Reflects the issuance of 2.99 million shares of convertible preferred securities on July 10, 1996.(3) Before income taxes.NM Not a meaningful figure.

F I V E -Y E A R H I G H L I G H T S

92 93 94 95 96 97

Dividends Per Common Share

($)

0.00

0.09

0.12 0.120.14

0.20

While Devon retains most of its earnings to fund growth, we have consis-

tently paid cash dividends since 1993.

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Another Record Year

Devon Energy Corporation delivered the best financial performance in the company’s history in 1997. Wereached all-time highs for oil and gas production, revenues, net earnings and earnings per share. We retiredour remaining long-term debt while driving year-end working capital and total assets to record levels.

For 1997, revenues increased 91%, to $313.1 million. Net earnings climbed 116% to $75.3 million.Earnings per common share advanced to $2.34 in 1997, compared to $1.57 in 1996. Earnings per share on adiluted basis also climbed dramatically, to $2.17 in 1997 versus $1.52 in 1996.

Production Increase Drives Record Revenues

Record production of oil, gas and natural gas liquids drove Devon‘s 1997 revenues and earningsachievements. The company’s 1997 total production of 20.2 million barrels of oil equivalent was an 88%increase over 1996 production. This marked Devon’s tenth consecutive record for annual oil and gasproduction. The primary contributors to this dramatic increase in production were: ■ The December 31, 1996 merger of Kerr-McGee’s North American onshore properties into Devon. Theseproperties increased our oil and gas reserve base by 62 million equivalent barrels, or some 50%. ■ Our aggressive drilling efforts in 1996 and 1997. This more than offset natural decline and increasedproduction on Devon’s historical properties. ■ A capital improvement program on our Northeast Blanco Unit (NEBU), Devon’s largest gas property,increased production in 1997. By improving the gas gathering system, production facilities and by addingcompression, we temporarily reversed natural decline.

Our 1997 revenues were not affected by changes in overall product prices. Although our average oil pricedecreased 9% from $21.00 per barrel in 1996 to $19.05 per barrel in 1997, this was offset by an increase innatural gas prices. The average price we received for our natural gas production climbed 14%, to $2.17 perthousand cubic feet during 1997. Consequently, our average price per barrel of oil equivalent produced in 1997was $15.15 versus $15.16 in 1996.

Higher Pre-tax Expenses Reflect Record Production

In addition to nearly doubling 1997 oil and gas production, Devon’s larger property base caused expensesto increase. Total pre-tax expenses rose $87.1 million, to $191.8 million in 1997. The largest contributors wereincreases in depreciation, depletion and amortization expense (DD&A) and lease operating expense.

Our DD&A expense increased $41.9 million, to $85.3 million for 1997. The change in this non-cashexpense was our largest expense increase for the year. Most of the increase in DD&A was caused by the risein overall oil and gas production.

Lease operating expense rose $34.1 million during 1997, to $65.7 million. This increase resulted from theadditional oil and gas wells we owned during 1997. The additional wells include those we obtained in theDecember 1996 merger and wells drilled during 1996 and 1997.

Income Taxes Rise With Higher Earnings

Income tax expense increased $21.6 million in 1997, to $46.0 million. A slight decrease in our financialincome tax rate in 1997 was overshadowed by a dramatic rise in pre-tax earnings. Some $20.8 million of 1997income tax was deferred and, therefore, did not require the use of cash.

Cash Margin and Balance Sheet Improves

Our cash margin (revenues less cash expenses) increased 89%, to $181.4 million in 1997. During the year,we funded over $120 million of oil and gas exploration, development and property acquisition costs withoperating cash flow and working capital. With a record $846.4 million in total assets, no long-term debt andincreased cash flow, we ended 1997 financially stronger than ever before. ■

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Devon has added significant oil and gas reserves through mergers or acquisitions in each of the last few years, yet in 1997 you did not complete a major transaction.What happened?

Devon is constantly searching for merger and acquisition opportunities that havegood intrinsic returns and can have a positive impact on per share performance. Our success in this area has beenone of the keys to our rapid growth. However, when executing an acquisition strategy, the single mostimportant element is discipline. Many companies that have grown through acquisitions have failed inthis regard. They go on a buying binge, making one acquisition after another. While such activity feels likegrowth at the time, it sometimes leads to disappointing long-term results. A company’s balance sheet becomesstretched. Financial flexibility is impaired. Newly acquired assets are not properly integrated into the previousproperty base. Costs no longer receive proper attention. Return on equity begins to suffer. Or worse yet, thecompany becomes enamored with building a large company and forgets the most important consideration inevaluating a potential acquisition: the impact on per share results. As major shareholders ourselves, themanagement team of Devon never forgets for whom we are working. The fact that we did not complete a majortransaction in 1997 reflects the fact that we did not uncover any opportunities that met our financial return and pershare criteria.

Have higher oil and gas prices or the industry’s increased access to debt and equitycapital made it impossible to make good acquisitions?

No. Absolutely not. While it’s true that readily available capital and 1996-1997 spikes in oil and gas pricestemporarily increased competition for acquisitions, the primary drivers behind industryconsolidation are alive and well. Oil and gas price volatility, an increasingly complex regulatory environment andcontinued industry consolidation are all forces that cause oil and gas properties to change hands. With anextremely solid balance sheet, enviable economies of scale in our five focus areas and more than 25 years ofexperience in making acquisitions, Devon is very well positioned for future acquisitions.

President & CEO, Larry Nichols,Answers Your Questions

D E V O N E N E R G Y S T E P S U P

T O M E E T 1 9 9 8 ’ s C H A L L E N G E S .

With your 1998 drilling and development budget at $140 to $160 million, it appearsthat Devon is putting increasing emphasis on the drill bit as a means of growth.Why is this?

Devon’s increasing profitability, cash flow and superior balance sheet have given us the financial firepowerto pursue somewhat higher risk/reward exploration. Devon has been gearing up its exploration efforts over thelast five years. Several of the larger projects we have been working on in the Gulf of Mexico and the PermianBasin will come to fruition in 1998. The Kerr-McGee transaction in late 1996 also gave us sizable acreagepositions in several attractive exploratory plays that we are now pursuing. Adding these to the explorationprojects we already had underway has given us a much larger inventory of exploratory prospectsthan ever before. Consequently, the exploration portion of our drilling and development budget is expectedto increase to $60 - $70 million in 1998.

This is not to imply that we are abandoning our historically successful exploitation and developmentactivities. For 1998, we expect the lower risk portion of our budget to total $80 to $100 million. This shouldprovide us a base of “bread and butter” drilling opportunities.

Speaking of exploration and development, your historical finding cost from discoveriesand revisions has been above industry averages. Why is this, and how can you correct it?

This result is an artifact of the normal method used in preparing historic finding cost data. When examiningoverall finding cost, including both acquisition and exploration activities, it’s apparent that Devon’sfinding costs are very low. That is why our DD&A rate of only $4.00 or so per barrel of oil equivalent isamong the lowest in the industry. However, when attempting to analyze our acquisition and exploration effortsseparately, it’s easy to arrive at an erroneous conclusion. The normal methodology makes our acquisition effortslook better than true economic reality and makes our exploration efforts look worse.

The normal method of segregating acquisition and exploration costs is subjectto distortion. In mergers and acquisitions, we often purchase properties that have “proved undevelopedreserves.” These reserves are “proven” by engineering standards but are associated with wells not yet drilled. Byaccounting rules, the initial costs of purchasing such reserves are recorded as “acquisition costs.” However, the coststo drill the associated wells are classified as “exploration and development costs.” This effectively transformscertain of our acquisition-oriented costs into “exploration costs.” Consequently, ourexploration costs are boosted above industry averages.

This transformation of costs is not problematic for most of the industry. A pure exploration and drillingcompany (i.e., never does acquisitions) obviously is not forced to deal with these distortions. There is no easysolution for this except for investors to realize the inherent flaws in attempting to bisect Devon’s integratedacquisition and drilling efforts.

How successful were your exploration efforts in 1997?

I would classify our 1997 exploration and development efforts as reasonably successful. We drilled 18exploratory wells during 1997, only two of which were dry holes. We drilled 277 development wells with a 97%success rate. We replaced 118% of 1997 production with drilling and revisions at a findingcost of only $4.84 per barrel of oil equivalent. Despite these successes, we also encountered somedisappointments along the way. A lack of rig availability and a lack of experienced drilling crews caused us topush into 1998 some wells that were originally scheduled for drilling in 1997.

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You have had the Kerr-McGee properties for a full year now.Have these properties met your expectations? What exploitation and explorationopportunities have you uncovered?

The Kerr-McGee properties have exceeded our initial expectations. Following integration with Devon’shistorical property base, the producing properties from the Kerr-McGee merger were less expensive tooperate than we had originally anticipated. Furthermore, we are finding upside through exploration andexploitation projects on these properties. An example of the exploration upside is in the PanhandleMorrow Play in Texas. Here we have assembled over 70,000 net undeveloped acres, almost 300 square miles of3-D seismic data and successfully completed several exploratory wells. We expect to be drilling here for severalyears to come. Our House Creek Unit in Wyoming is an example of the exploitation upside. In 1997 wepurchased an additional interest and initiated a twelve-well pilot infill program. As a result, production increasedby more than 500 barrels of oil per day. Based on the success of the pilot program, we plan to drill an additional60 to 80 wells in 1998. The 1996 merger also gave us an introduction into Canada. We spent some$8 million in capital expenditures in Canada during 1997 with very good results. We drilled 26 wells, all of whichwere completed as producers, and replaced almost 150% of 1997’s production with reserve additions. We arelooking forward to expanding our presence here again in 1998.

Will Devon continue to divest non-core properties in 1998 as you have done in the past?

To continue to improve the quality of our property base we constantly identify and sell thoseproperties that evolve as non-strategic or marginally economic. This includes properties that become tooexpensive to operate and those in areas where we lack critical mass. Our most active years for property sales havegenerally followed major acquisitions. However, the properties we obtained in the December 1996 merger are ofvery high quality and have good economic margins. They are also an excellent geographic fit for Devon. As aresult, very few of the merger properties were identified for sale. We will continue to regularly reviewour property base to identify those that no longer meet our criteria. However, the extent to which weengage in property sales in the future, will to a large degree, depend on future acquisitions.

Oil and gas prices tend to be both volatile and difficult to predict. Since your revenuesare generated almost entirely from the sales of these products, how does Devon cope withthis volatility?

We have adopted a number of strategies to help reduce the negative effects of oil and gas price volatility.First, and most importantly, we keep our cost structure low. We do this by purchasing and developingproperties that can be operated economically, by carefully controlling our general and administrative expensesand by keeping debt levels; i.e., interest expense, low. Second, we balance oil and gas reservesand production so that our revenues are less vulnerable to low prices in either commodity. This is reflected in our1997 oil to gas production mix of roughly 40%/60%. Third, we pursue projects with long-lived reserves.The ultimate value of these projects is less vulnerable to short-term oil and gas price swings. All of these actionstend to give us more consistent, more sustainable margins than many of our competitors. Another way to be“rock solid” in a “quick sand” industry. ■

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Oil and gas exploration is nothing new for Devon. In 1973, as a virtually new company, wedrilled our first exploratory test. By the late 1970’s, we had one of the most extensive exploratory programs inOklahoma. In 1989, we discovered the coal seam gas reserves in our largest gas producing property — theNortheast Blanco Fruitland Coal Unit in New Mexico. In 1992, we made a wildcat discovery that we have sincedeveloped into one of our largest oil producing properties — Sand Dunes.

What is new for Devon is our level of commitment to high potential exploration.In the late 1980’s and early 1990’s Devon was a mid-size exploration and production company. We reinvestedmost of our cash flow in acquisitions and low risk development drilling. Due to the success of this strategy, wehave grown into a much larger company. We now have the size and financial strength to augment our traditionalgrowth strategies with large-scale high potential exploration.

In 1997, we ramped up our exploration activity to record levels. We made exploratorydiscoveries in the Permian Basin, the Mid-Continent and Canada. In all, we drilled 18 exploration wells with an89% success rate. We deployed the largest exploration budget in the company’s history — over $19 million. Andin spite of doubling our production in 1997 to over 20 million barrels of oil equivalent, we more than replacedproduction with discoveries and revisions.

More importantly we laid the foundation to dramatically expand our explorationefforts in 1998 and beyond. With the addition of seven geologists and geophysicists during 1997, wesignificantly increased the talent we have working on exploration projects. We acquired 263 square miles of 3-Dseismic data. To increase our capacity to process seismic data we added three 3-D seismic workstations, bringingour total to seven. And we acquired more than 40,000 net acres of undeveloped leasehold in five exploration plays.The opportunities generated by these activities are reflected in our 1998 exploration budget of $60 to $70 million— more than a 200% increase over 1997.

A Rock Solid Commitment to Exploration

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But isn’t this more risky? Yes and no. Certainly wildcat exploration wells have a lower chance ofsuccess than development wells. Then, too, the $60 million to $70 million for 1998 is a materially larger sumthan $10 to $20 million of earlier years.

But on a percentage basis, Devon is well within its historical risk tolerance. The $60 to $70million for 1998 is less than 10% of our $846 million balance sheet. All of our 1998 exploratory tests could bedry and we would not have “bet the farm.” Furthermore, our long reserve life would still provide substantialproduction and cash flow far into the future. So the risk is tolerable.

Fortunately, our upside is being expanded disproportionately. A successful test for one ofour exploratory wells could add 10, 20 or even 50 Bcfe to our reserves. In the context of Devon’s otherwiserelatively low risk profile, these operations have a highly favorable risk/reward profile for us.

Following are some of the more exciting exploratory projects we are pursuing for 1998and beyond:

Panhandle Morrow

At the end of 1996, we acquired a sizeable acreage position in this emerging exploration play in the TexasPanhandle and western Oklahoma. In 1997, we aggressively acquired additional acreage and conducted four3-D seismic surveys here. We now have over 70,000 net undeveloped acres on which we have delineated 13separate multi-well prospects. We drilled and completed four successful exploratory gas wells at depths ofbetween 14,000 and 17,000 feet. In 1998, we expect to drill an additional 15 to 20 Panhandle Morrow wells. In1998 we will also expand our presence here with the acquisition of additional acreage and seismic data.

Poker Lake/Cotton Draw

This 26,000-acre property located in the southeastern New Mexico portion of the Permian Basin was thesite of a significant Devon gas discovery in 1997. Devon and its partner, a major oil company, drilled this wellfollowing the interpretation of our 96 square mile 3-D seismic survey. This well currently produces some 16

92 93 94 95 96 97

59102 83

199

295

194

Drilling Results

DRYPRODUCTIVE

Devon drills mostly lower riskdevelopment wells. This has helped

our drilling success rate exceed95% over the past six years.

92 93 94 95 96 97

34

57

19

3

Exploration Expenditures

($ Millions)

...is reflected in our risingexploration budget.

92 93 94 95 96 97

220

167 164 162

494490

Net Undeveloped Acres

(Thousands)

Devon‘s increasing portfolio ofundeveloped acreage upon which

to explore...

92 93 94 95 96 97

4

16

8

5

24

11

Reserve Additions from

Drilling and Revisions

(MMBoe)

Devon‘s reserve additions fromdrilling and revisions more than

replaced our record 1997 production.

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We take pride in our ability to find better solutions to challenges big and small. Employees that

challenge the status quo with innovative thinking are an integral part of this process. A sterling example

of such an employee is Devon field foreman, Troy Settle. Troy has helped to pioneer a better way to

dispose of wastewater sometimes produced with oil and gas.

In addition to the primary products, oil and gas wells often produce water. This wastewater can be

environmentally sensitive. Disposing of it in a cost effective and environmentally sound way has long

posed a challenge to oil and gas producers. Typically, this wastewater is stored in on-site tanks and then

transported by truck to a disposal facility. Another method is to inject it into absorbent rock formations

deep below the surface. However, both of these methods are expensive.

Troy has been experimenting with a process known as phytoremediation. This process utilizes salt-

tolerant plants to reduce the volume of oilfield wastewater left for disposal. With phytoremediation the

produced water is first tested to ensure it contains nothing harmful to livestock. It then flows into a trough

where special salt-tolerant plants are growing. The plants consume the water and transpire it from their

leaves. The plants are then used onsite to sustain livestock. An oilfield waste product is transformed into

a useful commodity!

While more experimentation is needed, Troy’s initial field trial indicates that phytoremediation holds

promise. It appears that this emerging technology is a safe, environmentally friendly and less expensive

means of disposing oilfield wastewater. It holds the potential to save domestic oil and gas producers

millions of dollars each year. “Hats off” to innovative thinkers like Troy Settle. ■

Innovative Thinking: Phytoremediation

Devon foreman, Troy Settle, checks a

produced wastewater storage tank.

Grass grows in troughs of oilfield

wastewater at the site of Devon‘s

phytoremediation field trial.

Cordgrass, shown here, was selected due

to its saline tolerance and its suitability

for consumption by animals.

million cubic feet per day from the Devonian formation at a depth of 16,500 feet. The well also has significantpotential in the Morrow and Wolfcamp formations found at shallower depths in the same area. We are currentlydrilling our second Devonian well and plan to drill additional wells here later in 1998.

To capitalize on the knowledge gained from our Poker Lake/Cotton Draw exploration project, we areconducting a large regional study looking for similar opportunities. South of Poker Lake/Cotton Draw, Devonpurchased additional interests in properties in southeast New Mexico and Texas. With the acquisition of acreageand seismic data near completion, Devon and our partners expect to begin drilling during 1998.

Breton Sound/Main Pass

Devon owns an average 45% working interest in three deep gas prospects located in the shallow, statewaters off the Louisiana coast. Each of these prospects targets potential net reserves of 50 to 100 billion cubicfeet at depths of 16,000 to 18,000 feet. With wells on two of these prospects currently underway, we expect tocomplete tests of all three prospects during 1998.

Ouachita Overthrust

We are prospecting for Ordovician Age formations in three distinctly separate areas: the Black WarriorBasin in Mississippi, the Kerr Basin in south Texas and the Ardmore Basin in southern Oklahoma. In the BlackWarrior Basin, we are currently drilling the initial well and have identified 10 additional prospects. In the KerrBasin, we are acquiring acreage and are planning to acquire additional seismic data during 1998. In the ArdmoreBasin, we are acquiring acreage on several prospects and plan to conduct a 3-D seismic survey and drill the initialwildcat during 1998.

Pouce Coupe

This property is located in Alberta, Canada. When we acquired it, production was from wells completedin Jurassic Age sands. During 1997, we acquired 3-D seismic data and made new zone discoveries in two TriassicAge formations. Based on this success, we plan to drill several more wells on our acreage beginning in 1998. Weare also acquiring additional acreage and seismic data to expand this play into the surrounding area. ■

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Eleven Year Property Data

Gas Reserves by Area Total Oil And Gas Reservesby Area

Oil Reserves by Area

Rocky Mountain

24%

Mid-Continent

5%

Other 1%

Permian Basin 60%

Canada 10%

Canada 8%

Mid-Continent 18%

RockyMountain 14%

Other 1%

San Juan Basin

38%

Permian Basin

21%

Other 1%

Canada 9%

Mid-Continent

12%

Rocky Mountain 19%

San Juan Basin 21%

Permian Basin

38%

A Rock Solid Portfolio of Producing PropertiesExploration may provide upside potential, but the foundation of an oil and gas company is its producing

properties. Devon has built a concentrated base of profitable oil and gas properties with long-lived reserves.These properties provide us with a dependable source of cash flow with which to fund our future growth.

1987 1988 1989 1990 1991

Reserves

Oil and Natural Gas Liquids (MBbls) 2,286 5,590 4,800 4,058 3,798Gas (MMcf ) 34,829 98,388 149,761 169,473 191,642Total (MBoe) (1) 8,090 21,988 29,760 32,304 35,738SEC @ 10% Present Value (Thousands) (2) $ 44,460 88,564 137,274 162,084 154,745

Production

Oil and Natural Gas Liquids (MBbls) 359 568 681 545 484Gas (MMcf ) 4,522 5,919 7,776 9,314 15,398Total (MBoe) (1) 1,112 1,554 1,977 2,097 3,050

Average Prices

Oil and Natural Gas Liquids (Per Bbl) $ 18.15 14.62 18.15 22.79 19.49Gas (Per Mcf ) $ 1.92 1.69 1.79 1.85 1.24Oil, Gas and Natural Gas Liquids (Per Boe) (1) $ 13.68 11.76 13.29 14.12 9.35

Production and Operating Expense per Boe (1) $ 4.50 5.31 5.99 5.71 3.48

(1) Gas converted to oil at the ratio of 6 Mcf:1 Bbl (2) Before income taxes.

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Operating Statistics by Core Area

PERMIAN SAN JUAN ROCKY MID- TOTAL BASIN BASIN MOUNTAIN CONTINENT OTHER U.S. CANADA TOTAL

Producing Wells at Year-end 7,174 915 720 2,184 286 11,279 926 12,205

1997 Production:Oil (MBbls) 4,111 2 1,528 334 80 6,055 950 7,005Gas (MMcf ) 17,731 18,044 6,677 16,669 1,894 61,015 8,312 69,327NGLs (MBbls) 861 8 374 224 1 1,468 158 1,626Total (MBoe)(1) 7,927 3,017 3,015 3,336 397 17,692 2,493 20,185

Average Prices:Oil Price ($/Bbl) $ 19.24 18.28 18.60 19.42 18.55 19.08 18.89 19.05Gas Price ($/Mcf ) $ 2.38 2.13 1.99 2.41 2.57 2.28 1.39 2.17NGL Price ($/Bbl) $ 12.57 11.55 14.68 13.08 12.52 13.18 15.28 13.38

Year-End Reserves:Oil (MBbls) 41,604 7 16,873 2,119 299 60,902 7,541 68,443Gas (MMcf ) 130,718 229,481 87,245 112,815 7,565 567,824 48,180 616,004NGLs (MBbls) 7,291 50 2,953 1,778 0 12,072 809 12,881Total (MBoe)(1) 70,682 38,304 34,366 22,699 1,560 167,611 16,380 183,991

Year-End Present Value of Reserves ($ thousands):(2)

Before Federal Income Tax $ 344,388 181,760 149,736 134,360 10,204 820,448 92,625 913,073After Federal Income Tax $ 663,979 62,874 726,853

Year-End Leasehold (Net Acres)Producing 156,635 16,727 90,486 188,061 29,124 481,033 76,200 557,233Undeveloped 176,421 10,364 93,670 108,335 29,523 418,313 75,732 494,045

Wells Drilled During 1997 174 24 22 40 9 269 26 295

1997 Exploration & DevelopmentExpenditures ($ millions) $ 69.5 0.4 11.1 13.8 3.5 98.3 8.3 106.6

Estimated 1998 Capital Expenditures ($ millions) $ 39-44 4 26-29 26-29 36-43 131-149 9-11 140-160

(1) Gas converted to oil at the ratio of 6 Mcf:1 Bbl.(2) Estimated future revenue to be generated from the production of proved reserves, net of estimated future production and development costs,

discounted at 10% in accordance with Securities and Exchange Commission guidelines.

5-YEAR 10-YEARCOMPOUND COMPOUND

1992 1993 1994 1995 1996 1997 GROWTH RATE GROWTH RATE

17,360 16,751 47,607 53,935 80,060 81,324 36% 43%263,598 369,254 347,560 363,846 595,519 616,004 19% 33%61,294 78,293 105,534 114,576 179,313 183,991 25% 37%

314,566 380,471 398,206 534,248 1,621,992 913,073 24% 35%

1,558 2,748 2,968 3,900 4,768 8,631 41% 37%28,374 35,598 39,335 36,886 35,714 69,327 20% 31%6,287 8,681 9,524 10,047 10,720 20,185 26% 34%

18.42 15.63 14.48 15.82 19.82 17.98 — —1.41 1.54 1.43 1.38 1.91 2.17 9% 1%

10.92 11.27 10.43 11.19 15.16 15.15 7% 1%3.66 3.84 3.30 3.40 3.94 4.14 2% -1%

3. Rocky Mountain Region

2. San Juan Basin

4. Mid-Continent Area

5. Western Canada Sedimentary Basin

1. Permian Basin

Over a dozen oil and gas producing basins are

included in this region which stretches across eight

states in the western U.S. Devon’s most significant

Rocky Mountain properties are located in the

Bighorn and Powder River Basins of Wyoming.

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 (coal seam

gas) makes up almost all of

Devon’s San Juan Basin gas

production.

The region generally

designated as the Mid-

Continent Area includes three

notable oil and gas producing

provinces covering portions of

Texas, Oklahoma, Arkansas,

and Kansas: the Arkoma Basin,

the Anadarko Basin and North

Central Texas.

This prolific oil and gas producing region

encompasses about 66,000 square miles of

western Texas and southeastern New Mexico and

contains more than 500 major oil and gas fields.

Acreage held by production from existing wells

and large federal exploration units make leases

difficult to obtain. Most of Devon’s position here

was established through four major transactions.

This large geologic feature covers portions of British

Columbia, Alberta, Saskatchewan and Manitoba.

Within the feature are two troughs defined as the

Alberta and the Williston Basins. Devon’s Canadian

properties are in the Alberta Basin.

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Grayburg-Jackson Field

West Red Lake Area

Poker Lake/Cotton Draw

Profile 1997 Activity

◆ 50% to 100% working interest in 6,000 acres in southeastern New Mexico.◆ Initially obtained a 98% working interest in 1,200 acres in 1992 acquisition. ◆ Produces oil from the Grayburg and San Andres formations at 2,500’.

◆ Drilled and compl◆ Initiated pilot wat◆ Acquired over 750

◆ 50% working interest in 26,000 acres in southeastern New Mexico.◆ Purchased in 1992 acquisition.◆ Produces from multiple formations at 4,000’ to 17,000’. ◆ Principle reserve targets are the Morrow formation at 14,500’ and the Devonian formation

at 16,500’.

◆ Drilled and complfeet per day.

◆ Drilled 4 shallowe◆ Initiated drilling o

◆ 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 five properties with 21.9 million barrels of oil equivalent reserves

at 12/31/97.

◆ Implemented fina◆ Drilled and compl◆ Installed 10 miles ◆ Converted 31 prod◆ Increased water in

1. Permian Basin

Northeast Blanco Unit (NEBU) ◆ 23% working interest in 33,000 acres in northwestern New Mexico.◆ Originally 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 largest property with 24.8 million barrels of oil equivalent reserves at 12/31/97.

◆ Substantially com◆ Installed 20 field c

32-9 Unit ◆ 28% working interest in 15,400 acres in 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’.◆ One of Devon‘s top five properties with 13.4 million barrels of oil equivalent reserves

at 12/31/97.

◆ Recavitated 3 wel◆ Maintained produ

2. San Juan Basin

House Creek Area ◆ 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’.◆ One of Devon’s top five properties with 11.8 million barrels of oil equivalent reserves at 12/31/97.

◆ Acquired addition◆ Initiated a 12 well◆ Continued infill dr

Worland Unit ◆ 98% to 100% working interest in 25,000 acre federal unit in northwestern Wyoming.◆ Consists of three fields and over 13,000 undeveloped acres.◆ Small initial position obtained in 1992 acquisition.◆ Acquired additional interests in 1995 and 1996.◆ 100% interest in gas processing plant on the Unit.◆ Produces oil and gas from multiple formations at 7,000’ to 11,000’.

◆ Completed 2 wells◆ Increased plant ca◆ Completed a 60 sq◆ Increased gas gat

3. Rocky Mountain Region

Gift Field ◆ 70% working interest in 10,000 acres in northwestern Alberta.◆ Obtained in 1996 merger.◆ Produces oil from the Slave Point formation at 5,800’.

◆ Acquired 12 squa◆ Completed 3-D se◆ Drilled and compl

Pouce Coupe Field ◆ 65% working interest in 10,000 acres in west central Alberta.◆ Obtained in 1996 merger.◆ Produces gas from the Halfway and Kiskatinaw formations at 5,500’ and 7,500’, respectively.

◆ Drilled 2 wells.◆ Recompleted 4 we◆ Acquired 25 squa

5. Western Canada Sedimentary Basin

Panhandle Morrow Play ◆ 55% working interest in 129,000 acres in western Oklahoma and the Texas Panhandle.◆ Includes 13 separate multi-well prospects.◆ Obtained in 1996 merger.◆ Produces gas from the Upper Morrow Chert at 14,000’ to 17,000’.

◆ Drilled and compl◆ Initiated drilling o◆ Acquired and/or in◆ Acquired 31,000 n

4. Mid-Continent Area

Pinto Prospect ◆ 100% working interest in 14,000 acres in west central Alberta.◆ Obtained in 1996 merger.◆ Produces gas from the Cardium Sand formation at 10,000’.

◆ Acquired 6,400 ac◆ Acquired over 200

Key Property Highlights

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1998 Plans

65 producer wells.od program.ss acres.

◆ Drill 35 producer wells.◆ Acquire additional acreage.◆ Convert producer wells to injector wells to expand waterflood program.◆ Add additional water injection facilities.

a Devonian discovery well that is producing 16 million cubic

ective wells, including 1 dry hole.ond Devonian well.

◆ Complete second Devonian well.◆ Drill third Devonian well.◆ Perform 3-D seismic survey on additional acreage.

se of water injection program on interior of field.17 producer wells and 9 injector wells.ater lines.r wells to injector wells.on rate to over 40,000 barrels per day.

◆ Convert approximately 30 producer wells to injector wells.◆ Drill 5 to 10 producer wells and 5 injector wells.

d gathering system improvements.ressors resulting in a significant increase in production.

◆ Recavitate 10 to 15 wells.◆ Install 10 to 15 field compressors.◆ Finalize gathering system improvements.

at gas gathering system capacity. ◆ Perform recavitations and well workovers as needed to sustain production

at current levels.

orking interest in House Creek Unit.ng program on House Creek Unit. program on North House Creek Unit.

◆ Accelerate infill drilling program on House Creek Unit.- Drill 30 to 40 producer wells.- Drill 30 to 40 injector wells.

ated in late 1996.ty by one-third.e mile 3-D seismic survey.g capacity with the installation of 2 field compressors.

◆ Complete interpretation of 3-D seismic survey.◆ Initiate a multi-well drilling program.

les of 3-D seismic data.c data interpretation.9 wells.

◆ Drill 6 to 8 wells.

les of 3-D seismic data.

◆ Interpret 3-D seismic data.◆ Drill 3 to 6 wells.

4 exploratory wells.dditional wells.reted 3-D seismic data on 6 prospect areas.

ndeveloped acres.

◆ Drill 15 to 20 wells.◆ Interpret existing 3-D seismic data.◆ Conduct additional 3-D seismic surveys.◆ Continue to acquire additional acreage.

are miles of 3-D seismic data.◆ Drill first exploratory well.

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F I N A N C I A L S TAT E M E N T S A N D M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S

Selected Eleven-Year Financial Data 24Management’s Discussion and Analysis of Financial Condition

and Results of Operations 26Management’s Responsibility for Financial Statements 39Independent Auditors’ Report 39Consolidated Balance Sheets 40Consolidated Statements of Operations 41Consolidated Statements of Stockholders’ Equity 42Consolidated Statements of Cash Flows 43Notes to Consolidated Financial Statements 44

1987 1988 1989 1990

OPERATING RESULTS (in thousands, except per share data)

RevenuesOil Sales $ 6,509 8,302 12,370 12,412Gas Sales 8,693 9,983 13,906 17,204Natural Gas Liquids Sales — — — —Other Revenue 2,098 2,735 2,543 1,302

Total Revenues $ 17,300 21,020 28,819 30,918

Production and Operating Expenses $ 5,037 8,255 11,835 11,983Depreciation, Depletion and Amortization(1) $ 7,697 7,429 7,350 8,005General and Administrative Expenses $ 4,056 3,854 6,103 4,919Interest Expense $ 1,141 2,132 2,140 1,956Distributions on Preferred Securities of Subsidiary Trust(2) $ — — — —Adjusted Net Earnings (Loss)(3) $ (1,066) (565) 876 2,554Reported Net Earnings (Loss) $ (1,066) 3,347 876 2,554Preferred Stock Dividends(4) $ — — 821 2,324Net Earnings (Loss) to Common Shareholders $ (1,066) 3,347 55 230Net Earnings (Loss) per Common Share - Basic $ (0.17) 0.48 0.01 0.03Net Earnings (Loss) per Common Share - Diluted $ (0.17) 0.48 0.01 0.03Cash Dividends per Common Share $ — — — —

Cash Margin(5) $ 7,066 6,779 8,696 11,838Weighted Average Common Shares Outstanding - Basic 6,165 6,924 8,595 8,640

BALANCE SHEET DATA (in thousands)

Total Assets $ 60,715 89,116 97,916 123,547Long-term Debt $ 13,453 30,000 9,500 28,000Other Long-term Obligations $ 5,198 6,337 5,071 3,919Deferred Income Taxes $ 8,217 5,480 5,889 7,036Preferred Securities of Subsidiary Trust(2) $ — — — —Stockholders’ Equity $ 28,928 41,557 70,156 70,767Common Shares Outstanding 6,165 8,584 8,608 8,679

(1) Includes $25 million non-cash reduction in the carrying value of oil and gas properties in 1991.(2) 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.(3) Excludes an unrelated 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 gain of $1.3 million in 1993 from the required adoption of Statement of Financial Accounting Standards No.109.(4) 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.(5) Revenues less cash expenses.NM Not a meaningful figure.

Selected Eleven-Year Financial Data

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5-YEAR 10-YEARGROWTH GROWTH

1991 1992 1993 1994 1995 1996 1997 RATE RATE

9,436 27,329 38,395 38,086 55,290 80,142 133,445 37% 35%19,091 39,973 54,876 56,372 50,732 68,049 150,549 30% 33%

— 1,370 4,544 4,908 6,404 14,367 21,754 74% NM1,815 2,892 942 1,407 877 1,459 7,392 21% 13%

30,342 71,564 98,757 100,773 113,303 164,017 313,140 34% 34%

10,601 23,030 33,325 31,420 34,121 42,226 83,579 29% 32%32,844 19,894 28,409 34,132 38,090 43,361 85,307 34% 27%5,832 6,510 7,640 8,425 8,419 9,101 12,922 15% 12%2,209 2,644 3,422 5,439 7,051 5,277 — NM NM

— — — — — 4,753 9,718 NM NM(15,024) 14,615 19,186 13,745 14,502 34,801 75,292 39% NM(15,024) 14,615 20,486 13,745 14,502 34,801 75,292 39% NM

2,270 1,703 — — — — — NM NM(17,294) 12,912 20,486 13,745 14,502 34,801 75,292 42% NM

(1.99) 0.94 0.98 0.64 0.66 1.57 2.34 20% NM(1.99) 0.90 0.98 0.63 0.65 1.52 2.17 19% NM

— — 0.09 0.12 0.12 0.14 0.20 NM NM

11,650 38,140 52,893 55,074 59,217 95,951 181,445 37% 38%8,687 13,802 20,822 21,552 22,074 22,160 32,216 18% 18%

102,107 225,972 285,553 351,448 421,564 746,251 846,403 30% 30%32,000 54,450 80,000 98,000 143,000 8,000 — NM NM3,204 2,635 2,723 2,683 9,512 11,585 21,040 52% 15%

908 4,151 8,643 27,340 34,452 81,121 101,474 90% 29%— — — — — 149,500 149,500 NM NM

53,015 153,267 172,900 206,406 219,041 472,404 543,576 29% 34%8,693 20,733 20,842 22,051 22,112 32,141 32,319 9% 18%

OVERVIEWDevon concluded 1997 financially stronger and

larger than at any previous time in the company’shistory. Over the last three years Devon’s oil and gasreserves have grown 74% to 184 million barrels of oilequivalent (“MMBoe”). Our unused long-term creditlines have increased 64% over the same period, to $208million. Total assets have increased 141% to $846million. During the same three years we reduced ourlong-term debt from $98 million to zero and signifi-cantly increased stockholders’ equity.

Our operating performance has also improved bymost measures over the last three years. The 1997 oiland gas production of 20.2 MMBoe was 112% over thatof 1994. The 1997 production increase, coupled with a45% increase in oil, gas and NGL prices over 1994levels, led to revenues and earnings gains. Net earningsfor 1997 climbed 448% over those of 1994, to $75.3million. Net cash provided by operating activities rosefrom $46.4 million in 1994 to $168.7 million in 1997.

The cash margin1 (total revenues less cashexpenses) during these same three years has increasedfrom $55.1 million in 1994 to $181.4 million in 1997.

This growth in operations was driven primarilyby the following events:■ We acquired Alta Energy Corporation through a$72 million cash and common stock merger in May 1994.The merger added substantial oil and gas reserves,production and revenues to our Permian Basin position.■ In 1995, we entered into a transaction coveringsubstantially all of our San Juan Basin coal seam gasproperties (the “San Juan Basin Transaction”). Thistransaction added approximately $8 million, $10 millionand $12 million to our annual revenues in 1997, 1996 and1995, respectively. See Note 3 to the consolidated financialstatements included elsewhere in this report for a detaileddiscussion of the San Juan Basin Transaction.■ On December 31, 1996, Devon acquired all ofKerr-McGee Corporation’s North American onshore oil andgas exploration and production business and properties (the“KMG-NAOS Properties”) in exchange for 9,954,000shares of Devon common stock. This transaction addedapproximately 62 million Boe to our year-end 1996 provedreserves (an increase of over 50%), as well as 370,000 netundeveloped acres of leasehold.

■ We have been successful during the last three yearsin our drilling efforts. During such period, we have spentapproximately $246 million to drill 688 wells, of which667 were completed as producers.■ Prices received from oil, gas and NGL revenueshave risen (though with volatility) 45%, from $10.43 perBoe in 1994 to $15.15 per Boe in 1997.

The following actions during the last three yearsimproved our liquidity and financial resources whilereducing our bank debt:■ Our production and revenue gains have given us asubstantially larger cash flow and, thus, capital budget.■ Our acquisition and drilling efforts during the lastthree years have added 120.4 MMBoe of proved reserves toour asset base. Combined with 1.8 MMBoe of upwardrevisions to our reserve estimates, our total reserve additionsof 122.2 MMBoe during the past three years were 298% ofour production of 41.0 MMBoe.■ In July, 1996, Devon, through a newly-formedaffiliate trust, issued $149.5 million of 6.5% TrustConvertible Preferred Securities (the “TCP Securities”).Combined with cash flow from operations, this transactionhas eliminated Devon’s long-term debt.■ Our oil and gas reserve additions, production gains,revenue increases and equity additions over the past threeyears have allowed us to increase our unused lines of credit.Since the end of 1994, our available long-term credit lineshave increased by $81 million to a total of $208 million atyear-end 1997.

The growth exhibited by Devon over the lastthree years extends a nine-year expansion period for thecompany. This period began when we became a publiccompany in 1988.

Through our acquisitions and our drilling anddevelopment efforts, we have significantly increased oiland gas reserves and production over this period.

While we have consistently increased productionover this nine-year period, volatility in oil and gas priceshas resulted in considerable variability in earnings andcash flows. Prices for oil, natural gas and NGLs aredetermined primarily by market conditions. Marketconditions for these products have been, and willcontinue to be, influenced by regional and world-wideeconomic growth, weather and other factors that arebeyond our control. Devon’s future earnings and cashflows will continue to depend on market conditions.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Like all oil and gas production companies, weface the challenge of natural production decline. Asvirgin pressures are depleted, oil and gas productionfrom a given well naturally decrease. Thus, an oil andgas production company depletes part of its asset basewith each unit of oil and gas it produces. Historically,we have been able to overcome this natural decline byadding more reserves through drilling and acquisitionsthan we produce. However, our future growth, if any,will depend on our ability to continue to add reservesin excess of production.

Given the dependence of oil and gas prices onfactors outside of our control, our management hasfocused its efforts on increasing oil and gas reserves andproduction and on controlling expenses. Over its nineyear history as a public company, Devon has been ableto significantly reduce its production and operatingcosts per unit of production. However, over the lastthree years our per-unit operating costs have increasedby 25%. An increase in our oil production as a portionof our total production and an increase in secondaryrecovery projects have contributed to this expenseincrease. (Secondary recovery projects are generallymore expensive than primary production. In addition,

producing oil is generally more expensive thanproducing gas. However, oil also generally producesmore revenue per Boe than gas.) Higher oil, gas andNGL revenues in 1997 also resulted in higher produc-tion taxes, a component of production and operatingexpenses. Our future earnings and cash flows aredependent on our ability to continue to containproduction and operating costs at levels that allow forprofitable production of our oil and gas reserves.

RESULTS OF OPERATIONSDevon’s total revenues have risen from $113.3

million in 1995 to $164.0 million in 1996 and $313.1million in 1997. In each of these years, oil, gas andNGL sales accounted for over 97% of total revenues.

Changes in oil, gas and NGL production, pricesand revenues from 1995 to 1997 are shown in the tablebelow.

(Note: Unless otherwise stated, all references inthis discussion to dollar amounts regarding Devon’sCanadian operations are expressed in U.S. dollars.)

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TOTAL 1997 1996

Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995

PRODUCTION

Oil (MBbls) 7,005 +84% 3,816 +16% 3,300Gas (MMcf ) 69,327 +94% 35,714 -3% 36,886NGLs (MBbls) 1,626 +71% 952 +59% 600Oil, Gas and NGLs (MBoe) 20,185 +88% 10,720 +7% 10,047

REVENUES

Per Unit of Production:Oil (per Bbl) $ 19.05 -9% 21.00 +25% 16.75Gas (per Mcf ) $ 2.17 +14% 1.91 +38% 1.38NGLs (per Bbl) $ 13.38 -11% 15.09 +41% 10.68Oil, Gas and NGLs (per Boe) $ 15.15 — 15.16 +35% 11.19

Absolute (Thousands):Oil $ 133,445 +67% 80,142 +45% 55,290Gas $ 150,549 +121% 68,049 +34% 50,732NGLs $ 21,754 +51% 14,367 +124% 6,404Oil, Gas and NGLs $ 305,748 +88% 162,558 +45% 112,426

1 ”Cash margin“ equals Devon’s total revenues less cash expenses. Cash expenses are all expenses other than the non-cash expenses of deprecia-tion, depletion and amortization and deferred income tax expense. Cash margin is an indicator which is commonly used in the oil and gas industry.This margin measures the net cash which is generated by a company’s operations during a given period, without regard to the period such cash isactually physically received or spent by the company. This margin ignores the non-operational effects on a company’s activities as an operator of oiland gas wells. Such activities produce net increases or decreases in temporary cash funds held by the operator which have no effect on net earningsof the company. Cash margin should be used as a supplement to, and not as a substitute for, net earnings and net cash provided by operating activi-ties determined in accordance with generally accepted accounting principles in analyzing Devon’s results of operations and liquidity.

DOMESTIC 1997 1996

Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995

PRODUCTION

Oil (MBbls) 6,055 +59% 3,816 +16% 3,300Gas (MMcf ) 61,015 +71% 35,714 -3% 36,886NGLs (MBbls) 1,468 +54% 952 +59% 600Oil, Gas and NGLs (MBoe) 17,692 +65% 10,720 +7% 10,047

REVENUES

Per Unit of Production:Oil (per Bbl) $ 19.08 -9% 21.00 +25% 16.75Gas (per Mcf ) $ 2.28 +19% 1.91 +38% 1.38NGLs (per Bbl) $ 13.18 -13% 15.09 +41% 10.68Oil, Gas and NGLs (per Boe) $ 15.48 +2% 15.16 +35% 11.19

Absolute (Thousands):Oil $ 115,504 +44% 80,142 +45% 55,290Gas $ 139,018 +104% 68,049 +34% 50,732NGLs $ 19,338 +35% 14,367 +124% 6,404Oil, Gas and NGLs $ 273,860 +68% 162,558 +45% 112,426

CANADA 1997 1996

Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995

PRODUCTION

Oil (MBbls) 950 N/A — N/A —Gas (MMcf ) 8,312 N/A — N/A —NGLs (MBbls) 158 N/A — N/A —Oil, Gas and NGLs (MBoe) 2,493 N/A — N/A —

REVENUES

Per Unit of Production:Oil (per Bbl) $ 18.89 N/A — N/A —Gas (per Mcf ) $ 1.39 N/A — N/A —NGLs (per Bbl) $ 15.28 N/A — N/A —Oil, Gas and NGLs (per Boe) $ 12.79 N/A — N/A —

Absolute (Thousands):Oil $ 17,941 N/A — N/A —Gas $ 11,531 N/A — N/A —NGLs $ 2,416 N/A — N/A —Oil, Gas and NGLs $ 31,888 N/A — N/A —

OIL REVENUES 1997 vs. 1996 Oil revenuesincreased by $53.3 million in 1997. Production gains of3.2 million barrels added $67.0 million of oil revenuesin 1997. This increase was partially offset by a $13.7million reduction in oil revenues caused by a $1.95 perbarrel decrease in the average oil price in 1997.

The KMG-NAOS Properties acquired at the endof 1996 were the primary contributors to the increasedoil production in 1997. These properties’ 1997 produc-tion totaled 3.1 million barrels. Approximately 2.1million barrels of such production were in the U.S.,

while 1 million barrels were produced in Canada. Ourother domestic properties produced 3.9 million barrelsin 1997. This was an increase of 0.1 million barrels, or3%, over the 1996 production of 3.8 million barrels.

1996 vs. 1995 Oil revenues increased by $24.9million in 1996. An increase in the average price of$4.25 per barrel in 1996 added $16.2 million torevenues. Production gains of 516,000 barrels addedthe remaining $8.7 million of 1996’s increased oilrevenues.

MD&A

The Grayburg-Jackson Field acquired in 1994accounted for the majority of 1996’s increased produc-tion. This field produced 1.1 million barrels in 1996, a37% increase over the 807,000 barrels the fieldproduced in 1995. Production from our other oil prop-erties increased 9% in 1996 to 2.7 million barrels. Thisis compared to 2.5 million barrels in 1995.

GAS REVENUES 1997 vs. 1996 Gas revenuesincreased by $82.5 million in 1997. An increase inproduction of 33.6 Bcf added $64.0 million to 1997’sgas revenues. An increase of $0.26 per Mcf in theaverage price added $18.5 million to 1997’s gasrevenues.

The KMG-NAOS Properties were responsiblefor the majority of the increased gas production in1997. These properties produced 29.8 Bcf in 1997.Approximately 21.5 Bcf of such production was in theU.S., while 8.3 Bcf was produced in Canada. Our coalseam gas properties produced 17.6 Bcf in 1997compared to 17.4 Bcf in 1996. Devon’s other domesticproperties produced 21.9 Bcf in 1997 compared to 18.3Bcf in 1996.

Our coal seam properties averaged $2.13 perMcf in 1997 compared to $1.72 per Mcf in 1996. TheSan Juan Basin Transaction added $8.4 million to coalseam gas revenues in 1997 compared to $10.3 millionin 1996. The San Juan Basin Transaction increased theaverage coal seam gas price by $0.48 per Mcf in 1997and $0.59 per Mcf in 1996.

Devon’s domestic conventional gas propertiesaveraged $2.34 per Mcf in 1997 compared to $2.08 perMcf in 1996.

1996 vs. 1995 Gas revenues increased by $17.3million in 1996. An increase in the average gas price of$0.53 per Mcf in 1996 added $18.9 million to 1996’sgas revenues. This increase was partially offset by a$1.6 million reduction in gas revenues from a drop ingas production of 1.2 Bcf.

Coal seam gas production declined by 16%,from 20.8 Bcf in 1995 to 17.4 Bcf in 1996. However,the average realized coal seam gas price rose by 30%from $1.32 per Mcf in 1995 to $1.72 per Mcf in 1996.Coal seam gas revenues included $10.3 million in 1996and $12.8 million in 1995 attributable to the San JuanBasin Transaction. This transaction increased the

average coal seam gas price by $0.59 per Mcf in 1996and $0.61 per Mcf in 1995.

Total conventional gas production and revenuesfor 1996 were 18.3 Bcf and $37.9 million, respectively,versus 16.1 Bcf and $23.2 million in 1995. Prices forconventional gas averaged $2.08 per Mcf in 1996compared to 1995’s average of $1.44.

NGL REVENUES 1997 vs. 1996 NGL revenuesincreased by $7.4 million in 1997. An increase inproduction of 674,000 barrels added $10.2 million to1997’s revenues. This increase was partially offset by a$2.8 million reduction in NGL revenues caused by a$1.71 per barrel decrease in 1997’s average price.

The majority of the increased NGL productionin 1997 was attributable to the KMG-NAOS Proper-ties. These properties produced 339,000 barrels in theU.S. and 158,000 barrels in Canada in 1997.

1996 vs. 1995 NGL revenues increased by $8.0million in 1996. An increase in average prices of $4.41per barrel added $4.2 million to the 1996 NGLrevenues. The remaining $3.8 million of increasedrevenues was attributable to increased production of352,000 barrels in 1996.

Additional interests acquired in certainWyoming properties in December 1995 and the firsthalf of 1996 accounted for 214,000 barrels of theincreased production in 1996. These Wyoming proper-ties produced 226,000 barrels in 1996 compared to12,000 barrels in 1995. Additional drilling in the SandDunes area of the Permian Basin increased productionfrom that area from 69,000 barrels in 1995 to 95,000barrels in 1996.

OTHER REVENUES 1997 vs. 1996 Otherrevenues increased by $5.9 million in 1997. Revenuesfrom processing third party natural gas related to theKMG-NAOS Properties accounted for $3.3 million ofthe increase. An increase in interest income providedanother $1.7 million of the increase in 1997’s otherrevenues.

1996 vs. 1995 Other revenue increased by $0.6million in 1996. Increases in gains recognized from thedisposal of non-oil and gas fixed assets and from settle-ments of gas contract claims accounted for most of thisincrease.

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EXPENSES The details of the changes in pre-tax expenses between 1995 and 1997 are shown in the table below.

1997 1996

Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995

ABSOLUTE(Thousands):Production and operating expenses:

Lease operating expenses $ 65,655 +108% 31,568 +16% 27,289Production taxes 17,924 +68% 10,658 +56% 6,832

Depreciation, depletion and amortization ofoil and gas properties 82,413 +98% 41,538 +13% 36,640

Subtotal 165,992 +98% 83,764 +18% 70,761

Depreciation and amortization of non-oil andgas properties 2,894 +59% 1,823 +26% 1,450

General and administrative expenses 12,922 +42% 9,101 +8% 8,419Interest expense 274 -95% 5,277 - 25% 7,051Distributions on preferred securities of

subsidiary trust 9,717 +104% 4,753 N/A —

Total $ 191,799 +83% 104,718 +19% 87,681

PER BOE PRODUCED

Production and operating expenses:Lease operating expenses $ 3.25 +10% 2.95 +8% 2.72Production taxes 0.89 -10% 0.99 +46% 0.68

Depreciation, depletion and amortization ofoil and gas properties 4.08 +5% 3.88 +6% 3.65

Subtotal 8.22 +5% 7.82 +11% 7.05

Depreciation and amortization of non-oil andgas properties (1) 0.15 -12% 0.17 +21% 0.14

General and administrative expenses (1) 0.64 -25% 0.85 +1% 0.84Interest expense (1) 0.01 -98% 0.49 - 30% 0.70Distributions on preferred securities of

subsidiary trust (1) 0.48 +9% 0.44 N/A —

Total $ 9.50 -3% 9.77 +12% 8.73

(1) Though per Boe general and administrative expenses, interest expense, non-oil and gas property depreciation and distributions onpreferred securities of subsidiary trust may be helpful for profitability trend analysis, these expenses are not directly attributable to productionvolumes. Rather they are an artifact of corporate structure, capitalization and financing, and non-oil and gas property fixed assets, respectively.

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PRODUCTION AND OPERATING EXPENSES The details of the changes in production and operating expensesbetween 1995 and 1997 are shown in the table below.

TOTAL 1997 1996

Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995

ABSOLUTE(Thousands):Recurring lease operating expenses $ 61,658 +118% 28,270 +19% 23,842Well workover expenses 3,997 +21% 3,298 - 4% 3,447Production taxes 17,924 +68% 10,658 +56% 6,832

Total production and operating expenses $ 83,579 +98% 42,226 +24% 34,121

PER BOE:

Recurring lease operating expenses $ 3.05 +16% 2.64 +11% 2.37Well workover expenses 0.20 -35% 0.31 - 11% 0.35Production taxes 0.89 -10% 0.99 +46% 0.68

Total production and operating expenses $ 4.14 +5% 3.94 +16% 3.40

DOMESTIC 1997 1996

Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995

ABSOLUTE(Thousands):Recurring lease operating expenses $ 54,969 +94% 28,270 +19% 23,842Well workover expenses 3,143 -5% 3,298 - 4% 3,447Production taxes 17,646 +66% 10,658 +56% 6,832

Total production and operating expenses $ 75,758 +79% 42,226 +24% 34,121

PER BOE:

Recurring lease operating expenses $ 3.10 +17% 2.64 +11% 2.37Well workover expenses 0.18 -42% 0.31 - 11% 0.35Production taxes 1.00 +1% 0.99 +46% 0.68

Total production and operating expenses $ 4.28 +9% 3.94 +16% 3.40

CANADA 1997 1996

Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995

ABSOLUTE(Thousands):Recurring lease operating expenses $ 6,689 N/A — N/A —Well workover expenses 854 N/A — N/A —Production taxes 278 N/A — N/A —

Total production and operating expenses $ 7,821 N/A — N/A —

PER BOE:

Recurring lease operating expenses $ 2.68 N/A — N/A —Well workover expenses 0.35 N/A — N/A —Production taxes 0.11 N/A — N/A —

Total production and operating expenses $ 3.14 N/A — N/A —

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1997 vs. 1996 Recurring lease operatingexpenses increased by $33.4 million, or 118%, in 1997.The KMG-NAOS Properties accounted for $26.0million of the increased expenses. Most of theremaining $7.4 million of 1997’s increase was due towells which were drilled in 1997 and 1996.

Recurring expenses per Boe were up by $0.41per Boe, or 16%, in 1997. This increase was caused bythe reduction in the coal seam gas properties share oftotal production. The recurring operating costs per Boefor the coal seam gas properties are extremely low($0.43 per Boe in 1997 and $0.32 per Boe in 1996).However, production from these properties remainedrelatively flat and production from our other propertiesincreased in 1997. Therefore, the coal seam gas proper-ties percentage of overall production dropped from 27%in 1996 to only 15% in 1997. The result is that a largerpercentage of Devon’s production in 1997 was attribut-able to its conventional properties, which have a higheroperating cost per Boe than the low-cost coal seam gasproperties. The recurring operating costs per Boe forour conventional properties were $3.50 per Boe in 1997and 1996. Thus, the coal seam properties’ costs roseonly $0.11 per Boe in 1997 and the conventional prop-erties’ costs remained flat in 1997. However, since theconventional properties represented a larger percentageof our total production in 1997 compared to 1996 (85%in 1997 compared to 73% in 1996), the result was a$0.41 per Boe increase in the overall rate.

Most taxing authorities collect production taxeson a fixed percentage of revenue basis. Therefore, as ourrevenues have increased, so have production taxes.Production taxes increased 68% from $10.7 million in1996 to $17.9 million in 1997. This increase was due tothe 88% increase in combined oil, gas and NGLrevenues in 1997.

1996 vs. 1995 Recurring lease operatingexpenses increased by $4.4 million, or 19%, in 1996.Approximately $2.7 million of the increase was relatedto the additional interests acquired in the WorlandProperties. We acquired these additional interests inDecember 1995 and the first half of 1996. Recurringlease operating expenses for the Worland Propertiesincreased from $0.1 million in 1995 to $2.8 million in1996 after Devon increased its ownership in such prop-

erties. Most of the remaining $1.7 million increase wasdue to the higher number of producing wells in theGrayburg-Jackson Field in 1996 compared to 1995.

Recurring expenses per Boe were up by $0.27, or11%, in 1996 compared to 1995. As explained above inthe 1997 vs. 1996 discussion, the increase in thepercentage of production attributable to conventionalproperties is also the cause of the increase in per Boecosts in 1996 compared to 1995. The recurring costsfor the coal seam gas properties averaged $0.32 per Boein 1996 and $0.24 per Boe in 1995. The recurringexpenses of our conventional oil and gas propertieswere $3.50 per Boe in 1996 and 1995. Thus, the coalseam properties’ costs rose only $0.08 per Boe in 1996and the conventional properties’ costs per Boeremained flat in 1996. However, since the conventionalproperties represented a larger percentage of our totalproduction in 1996 compared to 1995 (73% in 1996compared to 65% in 1995), the result was a $0.27 perBoe increase in the overall rate.

Production taxes increased 56% from $6.8million in 1995 to $10.7 million in 1996. This increasewas primarily due to the 45% increase in combined oil,gas and NGL revenues.

Production taxes per Boe increased by $0.31 perBoe, or 46%, in 1996. This was primarily caused by theincrease in the average price per Boe received in 1996.

DEPRECIATION, DEPLETION AND AMORTIZATION

Devon’s largest non-cash expense is depreciation,depletion and amortization (“DD&A”). DD&A of oiland gas properties is calculated as the percentage oftotal proved reserve volumes produced during the year,multiplied by the net capitalized investment in thosereserves including estimated future development costs(the “depletable base”). Generally, if reserve volumes arerevised up or down, then the DD&A rate per unit ofproduction will change inversely. However, if capital-ized costs change, then the DD&A rate moves in thesame direction. The per unit DD&A rate is notaffected by production volumes. Absolute or totalDD&A, as opposed to the rate per unit of production,generally moves in the same direction as productionvolumes.

MD&A

1997 vs. 1996 Oil and gas property relatedDD&A increased $40.9 million, or 98%, in 1997.Approximately $36.7 million of this increase was causedby the 88% increase in combined oil, gas and NGLproduction in 1997. The remaining $4.2 million ofincrease was caused by a 5% increase in the DD&A ratefrom $3.88 per Boe in 1996 to $4.08 per Boe in 1997.

1996 vs. 1995 Oil and gas property relatedDD&A increased by $4.9 million, or 13%, in 1996.Approximately $2.5 million of this increase was causedby a 7% increase in total oil, gas and NGL productionin 1996. The remaining $2.4 million increase wascaused by a 6% increase in the DD&A rate from $3.65per Boe in 1995 to $3.88 per Boe in 1996.

GENERAL AND ADMINISTRATIVE EXPENSES

(“G&A”) 1997 vs. 1996 G&A increased by $3.8million, or 42%, in 1997. Employee salaries and relatedoverhead costs, including insurance and pension expense,increased by $4.9 million. This increase was primarilyrelated to the additional permanent and temporarypersonnel added at our Oklahoma City and Calgaryoffices as a result of the addition of the KMG-NAOSProperties. The expansion in personnel also causedoffice-related costs such as rent, dues, travel, supplies,telephone, etc., to increase by $1.8 million in 1997.

The higher salary, overhead and office costs werepartially offset by an increase in Devon’s overheadreimbursements. As the operator of a property, wereceive these reimbursements from the property’sworking interest owners. Devon records the reimburse-ments as reductions to G&A. Due to the addition ofthe KMG-NAOS Properties, many of which weoperate, our overhead reimbursements increased by$3.7 million in 1997.

1996 vs. 1995 G&A increased by $0.7 million,or 8%, in 1996. Employee salaries and related benefitswere $1.1 million higher in 1996. Legal expenses andabandoned acquisition expenses were each $0.2 millionhigher in 1996. These increases were partially offset bya $0.1 million reduction in franchise tax expense due toour 1995 change of incorporation from Delaware toOklahoma. Also, Devon saw a $0.7 million increase inG&A reimbursements received from joint interestowners in Devon-operated properties.

INTEREST EXPENSE 1997 vs. 1996 Interestexpense decreased $5.0 million, or 95%, in 1997. Thisdecrease was caused by a drop in the average debtbalance outstanding from $77.0 million in 1996 to $0.7million in 1997. We issued $149.5 million of 6.5%Trust Convertible Preferred Securities (“TCP Securi-ties”) in July, 1996. The proceeds from this issuance,along with cash flow from operations, were used toretire our long-term bank debt early in 1997. (TheTCP Securities are discussed further below.)

1996 vs. 1995 Interest expense decreased by$1.8 million, or 25%, in 1996. Approximately $1.5million of the lower interest expense was due to a loweraverage debt balance in 1996. The average debt balancedropped from $97.1 million in 1995 to $77.0 million in1996. This decrease in average debt outstanding wasprimarily the result of the issuance of the TCP Securi-ties in July 1996.

The remaining $0.3 million of interest expensereduction in 1996 resulted from lower interest rates.The interest rates on the debt outstanding during 1996averaged 6.3%, compared to 1995’s average rate of 6.5%.

The overall interest rate (including the effect ofthe interest rate swap discussed below, various fees paidto the banks and the amortization of certain loan costs)averaged 6.9% in 1996 and 7.3% in 1995.

We entered into an interest rate swap agreementin the second quarter of 1995. We terminated theagreement on July 1, 1996 for a gain of $0.8 million.This gain is being recognized ratably in Devon’s oper-ating results as a reduction to interest expense duringthe period from July 1, 1996 to June 16, 1998 (theoriginal expiration date of the swap agreement).Approximately $0.2 million of the gain was included inthe last half of 1996 as a reduction to interest expense.During the time when the agreement was still in effect,it resulted in $0.1 million of reduced interest expense inthe year 1995 and had no effect on interest expense forthe first six months of 1996.

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DISTRIBUTIONS ON PREFERRED SECURITIES OF

SUBSIDIARY TRUST 1997 vs. 1996 Devon, through itsaffiliate Devon Financing Trust, completed the issuanceof $149.5 million of 6.5% TCP Securities in a privateplacement in July, 1996. The distributions on the TCPSecurities accrue at the rate of 1.625% per quarter.Distributions in 1997 were $9.7 million compared to$4.8 million in 1996. The 1996 distribution total repre-sented slightly less than two quarters’ distributions dueto the issuance date occurring in July. (See Note 9 tothe consolidated financial statements included else-where in this report for a detailed discussion of Devon’sTCP Securities.)

1996 vs. 1995 The TCP Securities were issuedin July, 1996. The 1996 distributions of $4.8 millionrepresented slightly less than two quarters’ distributionsdue to the issuance date occurring in July.

INCOME TAXES 1997 vs. 1996 Our effectivefinancial tax rate in 1997 was 38% compared to 41% in1996. Both rates were above the statutory federal taxrate of 35% due to state income taxes, and certain taxaspects of the San Juan Basin Transaction and a 1994merger. Also, the 1997 rate was affected by certain taxaspects of the KMG-NAOS transaction and by Cana-dian income taxes which accrue at rates higher than theU.S. statutory rate of 35%. (The effective financialincome tax rate for our Canadian operations was 43%in 1997.)

1996 vs. 1995 Our effective financial tax rate in1996 was 41% compared to 1995’s rate of 43%. Bothrates were above the federal statutory rate of 35% due tothe effect of the state taxes, San Juan Basin Transactionand 1994 merger noted in the above paragraph.

CAPITAL EXPENDITURES, CAPITALRESOURCES AND LIQUIDITY

The following discussion of capital expenditures,capital resources and liquidity should be read inconjunction with the consolidated statements of cashflows included in this report.

CAPITAL EXPENDITURES Approximately $130.5million of cash was spent in 1997 for capital expendi-tures, of which $124.6 million was related to the acqui-sition, drilling or development of oil and gas properties.Most of the drilling and development efforts in 1997centered in the Permian Basin, which included 174 ofthe 295 oil and gas wells that we drilled during theyear.

OTHER CASH USES We began paying a quarterlydividend on our common stock in the second quarter of1993 at the rate of $0.03 per share. In the fourthquarter of 1996, the quarterly dividend rate wasincreased to $0.05 per share. Quarterly dividends in1997 were also paid at the rate of $0.05 per share.

CAPITAL RESOURCES AND LIQUIDITY Net cashprovided by operating activities (“operating cash flow”)was the primary source of capital and short-termliquidity in 1997. Operating cash flow in 1997 totaled$168.7 million compared to $86.8 million in 1996.This resulted in a 94% increase.

In addition to operating cash flow, our creditlines have historically been an important source ofcapital and liquidity. However, 1997’s increased oper-ating cash flow allowed Devon to fund its 1997 capitalexpenditures and other cash uses without borrowingagainst its credit lines. At the end of 1997, we had$208 million of long-term credit lines, all of which wasavailable for future use. Also, we have a $12.5 millionCanadian dollars demand facility for our Canadianoperations. All of this Canadian facility was also avail-able at the end of 1997 for future use. (See Note 7 tothe consolidated financial statements included else-where in this report for a detailed discussion of Devon’scredit lines.)

MD&A

1998 ESTIMATESThe forward-looking statements provided in this

discussion are based on management’s examination ofhistorical operating trends, the December 31, 1997reserve reports of independent petroleum engineers andother data in Devon’s possession or available from thirdparties. We caution that our future oil, gas and NGLproduction, revenues and expenses are subject to all ofthe risks and uncertainties normally incident to theexploration for and development and production andsale of oil and gas. These risks include, but are notlimited to, price volatility, inflation or lack of avail-ability of goods and services, environmental risks,drilling risks, regulatory changes, the uncertaintyinherent in estimating future oil and gas production orreserves, and other risks as outlined below. Also, thefinancial results for our Canadian operations, obtainedin the KMG-NAOS transaction, are subject tocurrency exchange rate risks. Additional risks arediscussed below in the context of line items mostaffected by such risks.

Specific Assumptions and Risks Related to Price andProduction Estimates Prices for oil, natural gas andNGLs are determined primarily by prevailing marketconditions. Market conditions for these products areinfluenced by regional and world-wide economicgrowth, weather and other substantially variable factors.These factors are beyond our control and are difficult topredict. In addition to volatility in general, Devon’s oil,gas and NGL prices may vary considerably due todifferences between regional markets and demand fordifferent grades of oil, gas and NGLs. Over 90% ofDevon’s revenues are attributable to sales of these threecommodities. Consequently, our financial results andresources are highly influenced by this price volatility.

Estimates for Devon’s future production of oil,natural gas and NGLs are based on the assumption thatmarket demand and prices for oil and gas will continueat levels that allow for profitable production of theseproducts. There can be no assurance of such stability.

Certain of Devon’s individual oil and gas proper-ties are sufficiently significant as to have a materialimpact on the company’s overall financial results. Withrespect to oil production, these properties include theWest Red Lake Field and the Grayburg-Jackson Unit,both in southeast New Mexico. Our interest in NEBUand the 32-9 Unit can have a significant effect onoverall gas production.

The production, transportation and marketingof oil, natural gas and NGLs are complex processeswhich are subject to disruption due to transportationand processing availability, mechanical failure, humanerror, meteorological events and numerous otherfactors. The following forward-looking statements wereprepared assuming demand, curtailment, producibilityand general market conditions for our oil, natural gasand NGLs for 1998 will be substantially similar tothose of 1997, unless otherwise noted. Given thegeneral limitations expressed herein, our forward-looking statements for 1998 are set forth below.

OIL PRODUCTION AND RELATIVE PRICES Devonexpects its oil production in 1998 to total between 6.3million barrels and 7.3 million barrels. We expect ournet oil prices per barrel will average from between$0.20 to $0.45 above West Texas Intermediate postedprices in 1998.

GAS PRODUCTION AND RELATIVE PRICES Weexpect our total gas production in 1998 will be between67.0 Bcf and 78.5 Bcf. It is expected that coal seam gasproduction will be between 19.0 Bcf and 22.2 Bcf.Canadian production in 1998 is estimated to bebetween 6.8 Bcf and 8.0 Bcf. We expect productionfrom the remainder of our gas properties to totalbetween 41.2 Bcf and 48.3 Bcf.

Devon expects its 1998 coal seam average pricewill be between $0.25 and $0.55 per Mcf less thanTexas Gulf Coast spot averages. This includes anexpected $0.40 to $0.45 per Mcf from the San JuanBasin Transaction. Our Canadian gas production isexpected to average from between $0.80 to $1.05 lessthan Texas Gulf Coast spot averages. (These Canadiandifferentials are expressed in U.S. dollars, using theyear-end 1997 exchange rate of $0.70 U.S. dollar to$1.00 Canadian dollar.) Devon’s remaining gas produc-tion is expected to average $0.05 to $0.25 less thanTexas Gulf Coast spot averages during 1998.

We had made firm commitments to sell approxi-mately 12,700 Mcf per day of our coal seam gasproduction throughout 1998 at a fixed price of approxi-mately $1.45 per Mcf, which equates to a price ofapproximately $2.04 per MMBtu. (The $1.45 per Mcfprice includes the effect of adjusting for Btu content

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and is net of costs for transportation and removingcarbon dioxide. This price excludes the expected $0.40to $0.45 per Mcf benefit from the San Juan BasinTransaction.) The effect of these fixed price commit-ments has been included in the expected differential forcoal seam gas discussed in the above paragraph. Wehave also made other commitments to sell certain quan-tities of our 1998 domestic conventional and Canadiangas production at fixed prices. However, such commit-ments to date are not expected to have a material effecton our 1998 gas price differentials due to the limitedquantities of gas per day involved.

NGL PRODUCTION We expect our production ofNGLs in 1998 to total between 1.3 million barrels and1.5 million barrels.

PRODUCTION AND OPERATING EXPENSES Ourproduction and operating expenses vary in response toseveral factors. Among the most significant of thesefactors are additions or deletions to our property baseand changes in production taxes. Other significantfactors are general changes in the prices of services andmaterials that are used in the operation of our proper-ties and the amount of repair and workover activityrequired on those properties.

Oil, gas and NGL prices will have a direct effecton production taxes to be incurred in 1998. Futureprices could also have an effect on whether proposedworkover projects are economically feasible. Thesefactors, coupled with the uncertainty of future oil, gasand NGL prices, increase the uncertainty inherent inestimating future production and operating costs.Given these uncertainties, Devon estimates that 1998’stotal production and operating costs will be between$78.0 million and $90.5 million.

DEPRECIATION, DEPLETION AND AMORTIZATION

The 1998 DD&A rate will depend on various factors.Most notable among such factors are the amount ofproved reserves that could be added from drilling oracquisition efforts in 1998 compared to the costsincurred for such efforts. Another notable factor is therevisions to our year-end 1997 reserve estimates whichwill be made during 1998.

The DD&A rate as of the beginning of 1998was $4.08 per Boe. Assuming a 1998 rate of between$4.10 per Boe and $4.45 per Boe, 1998 oil and gasproperty related DD&A expense is expected to be $85million to $93 million. Additionally, we expect ournon-oil and gas property related DD&A to totalbetween $3 million and $4 million in 1998.

GENERAL AND ADMINISTRATIVE EXPENSES

Devon’s general and administrative expenses includethe costs of many different goods and services used insupport of the company’s business. These goods andservices are subject to general price level increases ordecreases. In addition, our G&A expenses vary withour level of activity and the related staffing needs.G&A expenses are also affected by the amount ofprofessional services required during any given period.Should our anticipated needs or the prices of therequired goods and services differ significantly from ourexpectations, actual G&A expenses could vary materi-ally from the estimate. Given these limitations, G&Aexpenses are expected to be between $13 million and$15 million in 1998.

INTEREST EXPENSE Devon’s managementexpects to fund substantially all of its anticipatedexpenditures during 1998 with working capital andinternally generated cash flow. Should our actual capitalexpenditures or internally generated cash flow varysignificantly from expectations, interest expense coulddiffer materially from the following estimate. Giventhis limitation, interest expense is expected to be lessthan $1 million in 1998.

DISTRIBUTIONS ON TCP SECURITIES TCP Secu-rities are convertible into common shares of Devon atthe option of the holder. Any conversions of the TCPSecurities would reduce the amount of required distrib-utions. Assuming all $149.5 million of TCP Securitiesare outstanding for the entire year, we will make $9.7million of distributions in 1998.

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INCOME TAXES We expect our financial incometax rate in 1998 to be between 34% and 38%. Regard-less of the level of pre-tax earnings reported forfinancial purposes, we will have a minimum of approxi-mately $2.0 million of financial income tax expense.This results from various aspects of the 1994 Altamerger, the San Juan Basin Transaction and the KMG-NAOS acquisition. Therefore, if the actual amount of1998 pre-tax earnings differs materially from whatDevon currently expects, the actual financial income taxrate for 1998 could differ from the expected rate of34% to 38%. Also, based on our current expectations of1998 taxable income, we anticipate our current portionof 1998 income taxes will be between $12 million and$17 million. However, unanticipated revenue and earn-ings fluctuations could easily make these tax estimatesinaccurate.

CAPITAL EXPENDITURES Our capital expendi-tures budget is based on an expected range of future oil,natural gas and NGL prices as well as the expectedcosts of the capital additions. Should our price expecta-tions for our future production change significantly, wemay accelerate or defer some projects. Thus, we mayincrease or decrease total 1998 capital expenditures. Inaddition, if the actual cost of the budgeted items variessignificantly from the amount anticipated, actual capitalexpenditures could vary materially from our estimate.

Though Devon has completed several majorproperty transactions in recent years, these transactionsare opportunity driven. Thus, we do not “budget,” norcan we reasonably predict, the timing or size of suchpossible acquisitions, if any.

Given these limitations, we expect our 1998capital expenditures for drilling and developmentefforts to total between $140 million and $160 million,including $8 million to $12 million in Canada. (Cana-dian amounts are expressed in U.S. dollars, using theyear-end 1997 exchange rate of $0.70 U.S. dollar to$1.00 Canadian dollar.) We expect to spend $45million to $60 million in 1998 for drilling, facilities andwaterflood costs related to reserves classified as provedas of year-end 1997. Devon also plans to spend another$60 million to $70 million on new, higher risk/rewardprojects.

OTHER CASH USES Devon’s managementexpects the policy of paying a quarterly dividend tocontinue. With the current $0.05 per share quarterlydividend rate and 32.3 million shares of common stockoutstanding, 1998 dividends are expected to approxi-mate $6.5 million.

CAPITAL RESOURCES AND LIQUIDITY Theestimated future drilling and development activities areexpected to be funded through a combination ofworking capital and net cash provided by operations.The amount of net cash to be provided by operatingactivities in 1998 is uncertain due to the factorsaffecting revenues and expenses cited above. However,we expect that our capital resources will be more thanadequate to fund our anticipated capital expenditures.

Based on the expected level of 1998’s capitalexpenditures and net cash provided by operations, wedo not expect to rely on our existing credit lines to funda material portion of our capital expenditures.However, if significant acquisitions or other unplannedcapital requirements arise during the year, we couldutilize our existing credit lines and/or seek to establishand utilize other sources of financing. The unusedportion of existing credit lines at the end of 1997consisted of $208 million of long-term credit facilities,and a $12.5 million Canadian dollars demand facilityfor our Canadian operations. If so desired, we believethat our lenders would increase our credit lines to atleast $450 million to $500 million. However, Devondoes not desire nor anticipate a need to increase itscredit lines above their current levels.

POTENTIAL REDUCTION IN CARRYING VALUE OF

OIL AND GAS PROPERTIES Under the full cost methodof accounting, the net book value of oil and gas proper-ties, less related deferred income taxes, may not exceeda calculated “ceiling.” The ceiling limitation is thediscounted estimated after-tax future net revenues fromproved oil and gas properties. The ceiling is imposedseparately by country. In calculating future netrevenues, current prices and costs are generally heldconstant indefinitely. The net book value is comparedto the ceiling on a quarterly and annual basis. Anyexcess of the net book value above the ceiling is writtenoff as an expense.

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At December 31, 1997, the Company’s net bookvalue of oil and gas properties less deferred taxes waswell below the calculated ceiling. The excess “cushion”was $146 million for the Company’s U.S. properties and$18 million for its Canadian properties. By March 11,1998 oil prices had declined significantly from year-end1997 levels. There had also been a moderate decline innatural gas prices. Based on these decreases, Devon esti-mated that its ceiling value on March 11, 1998 wassignificantly lower than at year-end 1997. However, theestimated ceiling value was still greater than the bookvalue of the Company’s oil and gas properties lessdeferred taxes. Oil or gas price declines after March 11,1998 could cause the ceiling value to fall below therecorded net book value. The result would be a reduc-tion in the carrying value of the Company’s oil and gasproperties. Should this occur, the Company also wouldrecognize a corresponding expense.

IMPACT OF RECENTLY ISSUED ACCOUNTING

STANDARDS NOT YET ADOPTED In June, 1997, theFinancial Accounting Standards Board issued State-ment of Financial Accounting Standards No. 130,Reporting Comprehensive Income. SFAS No. 130 iseffective for fiscal years beginning after December 15,1997. SFAS No. 130 establishes standards for reportingand displaying comprehensive income and its compo-nents in a set of financial statements. It requires that allitems that are required to be recognized underaccounting standards as components of comprehensiveincome be reported in a financial statement that isdisplayed with the same prominence as other financialstatements. The only component of comprehensiveincome that is not currently included in Devon’sconsolidated statements of operations is the currencytranslation adjustment reported as part of stockholders’equity as of December 31, 1997. Devon will adoptSFAS No. 130 in 1998.

Also in June, 1997, Statement of FinancialAccounting Standards No. 131, Disclosures aboutSegments of an Enterprise and Related Information,was issued. SFAS No. 131 is effective for periodsbeginning after December 15, 1997. SFAS No. 131requires that publicly-traded entities report financialand descriptive information about reportable operatingsegments. Operating segments are components of anenterprise about which separate financial information isavailable. This information is evaluated regularly by thechief operating decision maker in deciding how to

allocate resources and in assessing performance. Devonwill adopt SFAS No. 131 in 1998. However, suchadoption is not expected to have a material impact onour current financial disclosures because our oil and gasoperations are expected to be the only reportableoperating segment under SFAS No. 131’s definitions.

In January, 1997, the Securities and ExchangeCommission issued Release #33-7386. This releaserequires enhanced description of accounting policies forderivative financial instruments and derivativecommodity instruments in the footnotes to thefinancial statements. The release also requires quantita-tive and qualitative disclosures outside the financialstatements about market risks inherent in market risksensitive instruments. These instruments includederivative financial instruments, derivative commodityinstruments and other financial instruments. Therequirements regarding accounting policy descriptionswere effective for any fiscal period ending after June 15,1997. However, because derivative financial orcommodity instruments have not materially affectedDevon’s financial position, cash flows or results ofoperations, this part of the release did not affectDevon’s 1997 disclosures. The quantitative and qualita-tive disclosures set forth in the release will be initiallyrequired in Devon’s annual report on Form 10-K forthe year ending December 31, 1998.

IMPACT OF THE YEAR 2000 ISSUE An issueexists for all companies that rely on computers as theyear 2000 approaches. This is because historically manycomputer programs used only two digits to representthe year in dates. Therefore, without adequate modifi-cations, many programs will not correctly identify theyear 2000. Devon plans to install a “Year 2000 Release”of its commercial software during 1998. In-housemodifications that have been previously made to thecommercial software will also be upgraded at that timeto be year 2000 compliant. We anticipate that we willbe able to install the new commercial software release,upgrade its modifications and test the entire systemwith our existing internal programming staff. There-fore, future incremental expenses, if any, incurred todeal with the year 2000 issue are expected to be imma-terial to our future operating results.

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The Board of Directors and StockholdersDevon Energy Corporation:

We have audited the consolidated balance sheetsof Devon Energy Corporation and subsidiaries as ofDecember 31, 1997, 1996 and 1995, and the relatedconsolidated statements of operations, stockholders’equity and cash flows for the years then ended. Theseconsolidated financial statements are the responsibilityof the Company’s management. Our responsibility is toexpress an opinion on these consolidated financialstatements based on our audits.

We conducted our audits in accordance withgenerally accepted auditing standards. Those standardsrequire that we plan and perform the audit to obtainreasonable assurance about whether the financial state-ments are free of material misstatement. An auditincludes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements.An audit also includes assessing the accounting princi-ples used and significant estimates made by manage-ment, as well as evaluating the overall financial state-ment presentation. We believe that our audits provide areasonable basis for our opinion.

In our opinion, the consolidated financial state-ments referred to above present fairly, in all materialrespects, the financial position of Devon EnergyCorporation and subsidiaries as of December 31, 1997,1996 and 1995, and the results of their operations andtheir cash flows for the years then ended, in conformitywith generally accepted accounting principles.

KPMG Peat Marwick LLP

Oklahoma City, OklahomaJanuary 26, 1998

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Independent Auditors’ ReportManagement’s Responsibility for Financial Statements

Devon Energy Corporation’s management takesresponsibility for the accompanying consolidated finan-cial statements which have been prepared in conformitywith generally accepted accounting principles appro-priate in the circumstances. They are based on our bestestimate and judgment. Financial information else-where in this annual report is consistent with the datapresented in these statements.

In order to carry out our responsibilityconcerning the integrity and objectivity of publishedfinancial data, we maintain an accounting system andrelated internal controls. We believe the system is suffi-cient in all material respects to provide reasonableassurance that financial records are reliable forpreparing financial statements and that assets are safe-guarded from loss or unauthorized use.

Our independent accounting firm, KPMG PeatMarwick LLP, provides objective consideration ofDevon Energy management’s discharge of its responsi-bilities as it relates to the fairness of reported operatingresults and the financial position of the company. Thisfirm obtains and maintains an understanding of ouraccounting and financial controls to the extent neces-sary to audit our financial statements, and employs alltesting and verification procedures as it considersnecessary to arrive at an opinion on the fairness offinancial statements.

The Board of Directors pursues its responsibili-ties for the accompanying consolidated financial state-ments through its Audit Committee. The Committeemeets periodically with management and the indepen-dent auditors to assure that they are carrying out theirresponsibilities. The independent auditors have full andfree access to the Committee members and meet withthem to discuss auditing and financial reportingmatters.

DEVON ENERGY CORPORATION

EXECUTIVE COMMITTEE

J. Larry NicholsPresident

J. Michael LaceyVice President

Duke R. LigonVice President

Darryl G. SmetteVice President

H. Allen TurnerVice President

William T. VaughnVice President

December 31, 1997 1996 1995

ASSETS

Current assets:Cash and cash equivalents $ 42,064,344 9,401,350 8,897,891Accounts receivable (Note 5) 47,507,805 29,580,306 14,400,295Inventories 2,422,822 2,103,486 605,263Prepaid expenses 799,923 688,752 222,135Deferred income taxes (Note 8) 434,000 1,600,000 749,000

Total current assets 93,228,894 43,373,894 24,874,584Property and equipment, at cost, based onthe full cost method of accounting for oiland gas properties (Note 6) 1,103,320,502 974,805,756 631,437,904

Less accumulated depreciation,depletion and amortization 365,517,722 281,959,410 239,619,167

737,802,780 692,846,346 391,818,737Other assets 15,371,368 10,030,560 4,870,796

Total assets $ 846,403,042 746,250,800 421,564,117

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:Accounts payable:

Trade $ 9,628,890 4,861,428 3,868,458Revenues and royalties due to others 11,531,296 10,569,960 7,322,418

Income taxes payable 4,901,940 4,705,447 1,364,070Accrued expenses 4,750,699 3,503,420 3,003,943

Total current liabilities 30,812,825 23,640,255 15,558,889Revenues and royalties due to others 2,862,794 1,259,129 889,173Other liabilities (Notes 3 and 11) 18,177,130 10,325,999 8,623,057Long-term debt (Note 7) — 8,000,000 143,000,000Deferred income taxes (Note 8) 101,474,000 81,121,000 34,452,000

Company-obligated mandatorily redeemable convertiblepreferred securities of subsidiary trust holdingsolely 6.5% convertible junior subordinateddebentures of Devon Energy Corporation (Note 9) 149,500,000 149,500,000 —

Stockholders’ equity (Note 10):Preferred stock of $1.00 par value.

Authorized 3,000,000 shares;none issued — — —

Common stock of $.10 par value.Authorized 400,000,000 shares; issued 32,318,895 in 1997, 32,141,295 in 1996,and 22,111,896 in 1995 3,231,890 3,214,130 2,211,190

Additional paid-in capital 392,919,170 388,090,930 167,430,347Retained earnings 149,946,232 81,099,357 49,399,461Cumulative currency translation adjustment (2,520,999) — —

Total stockholders’ equity 543,576,293 472,404,417 219,040,998Commitments and contingencies (Notes 11 and 12)

Total liabilities and stockholders’ equity $ 846,403,042 746,250,800 421,564,117See accompanying notes to consolidated financial statements.

Consolidated Balance SheetsDevon Energy Corporation and Subsidiaries

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Year Ended December 31, 1997 1996 1995

REVENUES

Oil sales $ 133,445,231 80,142,073 55,289,819Gas sales 150,548,871 68,049,478 50,732,158Natural gas liquids sales 21,754,033 14,366,771 6,403,663Other 7,391,733 1,458,562 877,185

Total revenues 313,139,868 164,016,884 113,302,825

COSTS AND EXPENSES

Lease operating expenses 65,655,074 31,568,428 27,288,755Production taxes 17,923,815 10,657,814 6,832,507Depreciation, depletion and amortization (Note 6) 85,306,868 43,361,029 38,089,783General and administrative expenses 12,922,259 9,101,429 8,418,739Interest expense 273,821 5,276,527 7,051,142Distributions on preferred securities of

subsidiary trust (Note 9) 9,717,502 4,753,125 —Total costs and expenses 191,799,339 104,718,352 87,680,926

Earnings before income taxes 121,340,529 59,298,532 25,621,899

INCOME TAX EXPENSE (Note 8)Current 25,202,000 6,709,000 4,495,000Deferred 20,847,000 17,789,000 6,625,000

Total income tax expense 46,049,000 24,498,000 11,120,000

Net earnings $ 75,291,529 34,800,532 14,501,899

Net earnings per average commonshare outstanding (Note 1):

Basic $ 2.34 1.57 $ 0.66Diluted $ 2.17 1.52 $ 0.65

Weighted average common shares outstanding - basic (Note 1) 32,215,745 22,159,507 22,073,550See accompanying notes to consolidated financial statements.

Consolidated Statements of OperationsDevon Energy Corporation and Subsidiaries

Year Ended December 31, 1997 1996 1995

COMMON STOCK

Balance, beginning of year $ 3,214,130 2,211,190 2,205,100Par value of common shares issued 17,760 1,002,940 6,090

Balance, end of year 3,231,890 3,214,130 2,211,190

ADDITIONAL PAID-IN CAPITAL

Balance, beginning of year 388,090,930 167,430,347 166,654,305Common shares issued, net

of issuance costs 3,628,240 220,660,583 776,042Tax benefit related to employee

stock options 1,200,000 — —

Balance, end of year 392,919,170 388,090,930 167,430,347

RETAINED EARNINGS

Balance, beginning of year 81,099,357 49,399,461 37,546,460Dividends (6,444,654) (3,100,636) (2,648,898)Net earnings 75,291,529 34,800,532 14,501,899

Balance, end of year 149,946,232 81,099,357 49,399,461

CUMULATIVE CURRENCY TRANSLATION ADJUSTMENT

Balance, beginning of year — — —Net change (2,250,999) — —

Balance, end of year (2,250,999) — —

TOTAL STOCKHOLDERS’ EQUITY, END OF YEAR $ 543,576,293 472,404,417 219,040,998See accompanying notes to consolidated financial statements.

Consolidated Statements of Stockholders’ EquityDevon Energy Corporation and Subsidiaries

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Year Ended December 31, 1997 1996 1995

CASH FLOWS FROM OPERATING ACTIVITIES

Net earnings $ 75,291,529 34,800,532 14,501,899Adjustments to reconcile net earnings to net

cash provided by operating activities:Depreciation, depletion and amortization 85,306,868 43,361,029 38,089,783(Gain) loss on sale of assets (192,278) (3,930) 273,238Deferred income taxes 20,847,000 17,789,000 6,625,000Changes in assets and liabilities net of effects

of acquisitions of businesses (Note 2):(Increase) decrease in:

Accounts receivable (17,835,233) (15,470,528) 1,213,877Inventories (344,286) (176,286) (70,937)Prepaid expenses (116,932) (466,617) 342,236Other assets (874,496) (1,032,653) 677,238

Increase (decrease) in:Accounts payable 3,394,868 3,370,474 (430,736)Income taxes payable 445,493 3,341,377 1,364,070Accrued expenses 1,078,012 399,477 (221,550)Revenues and royalties due to others 1,603,665 369,956 (1,793,909)Long-term other liabilities 117,700 519,978 705,636

Net cash provided by operating activities 168,721,910 86,801,809 61,275,845

CASH FLOWS FROM INVESTING ACTIVITIES

Proceeds from sale of property and equipment 1,711,769 4,037,480 9,427,401Capital expenditures (130,468,542) (98,854,846) (117,593,897)Payments made for acquisition of business (Note 2) — — (2,391,484)Increase in other assets (2,583,920) — —

Net cash used in investing activities (131,340,693) (94,817,366) (110,557,980)

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from borrowings on revolving line of credit 1,847,750 29,000,000 52,000,000Principal payments on revolving line of credit (9,843,750) (164,000,000) (7,000,000)Issuance of common stock, net of issuance costs 3,646,000 577,483 782,132Issuance of preferred securities of subsidiary trust,

net of issuance costs — 144,665,205 —Dividends paid on common stock (6,444,654) (3,100,636) (2,648,898)Increase in long-term other liabilities (Note 3) 6,268,085 1,376,964 6,710,421

Net cash provided (used) by financing activities (4,526,569) 8,519,016 49,843,655

Effect of exchange rate changes on cash (191,654) — —

Net increase in cash and cash equivalents 32,662,994 503,459 561,520

Cash and cash equivalents at beginning of year 9,401,350 8,897,891 8,336,371

Cash and cash equivalents at end of year $ 42,064,344 9,401,350 8,897,891See accompanying notes to consolidated financial statements.

Consolidated Statements of Cash FlowsDevon Energy Corporation and Subsidiaries

SUMMARY OF SIGNIFICANTACCOUNTING POLICIES

Accounting policies used by Devon EnergyCorporation and subsidiaries (“Devon”) reflect industrypractices and conform to generally accepted accountingprinciples. The more significant of such policies arebriefly discussed below.

BASIS OF PRESENTATION AND PRINCIPLES OF

CONSOLIDATION Devon is engaged primarily in oiland gas exploration, development and production, andthe acquisition of producing properties. Such activitiesare primarily in the states of New Mexico, Texas, Okla-homa, Wyoming and Louisiana. Effective December31, 1996, Devon began operations in Alberta, Canada.Devon’s share of the assets, liabilities, revenues andexpenses of affiliated partnerships and the accounts ofits wholly-owned subsidiaries are included in theaccompanying consolidated financial statements. Allsignificant intercompany accounts and transactionshave been eliminated in consolidation.

USE OF ESTIMATES IN THE PREPARATION OF

FINANCIAL STATEMENTS The preparation of financialstatements in conformity with generally acceptedaccounting principles requires management to makeestimates and assumptions that affect the reportedamounts of assets and liabilities and disclosure ofcontingent assets and liabilities at the date of the finan-cial statements, and the reported amounts of revenuesand expenses during the reporting period. Actualamounts could differ from those estimates.

INVENTORIES Inventories, which consistprimarily of tubular goods, parts and supplies, arestated at cost, determined principally by the averagecost method, which is not in excess of net realizablevalue.

PROPERTY AND EQUIPMENT Devon follows thefull cost method of accounting for its oil and gasproperties. Accordingly, all costs incidental to theacquisition, exploration and development of oil and gasproperties, including costs of undeveloped leasehold,dry holes and leasehold equipment, are capitalized. Netcapitalized costs are limited to the estimated future net

revenues, discounted at 10% per annum, from provedoil, natural gas and natural gas liquids reserves. Suchlimitations are imposed separately for Devon’s oil andgas properties in the United States and Canada.Capitalized costs are depleted by an equivalent unit-of-production method, converting gas and natural gasliquids to oil at the ratio of one barrel (“Bbl”) of oil tosix thousand cubic feet (“Mcf ”) of natural gas and onebarrel of oil to 42 gallons of natural gas liquids. Nogain or loss is recognized upon disposal of oil and gasproperties unless such disposal significantly alters therelationship between capitalized costs and provedreserves.

Devon adopted the provisions of SFAS No. 121,“Accounting for the Impairment of Long-Lived Assetsand for Long-Lived Assets to be Disposed Of,” onJanuary 1, 1996. SFAS No. 121 requires that long-livedassets and certain identifiable intangibles be reviewedfor impairment whenever events or changes in circum-stances indicate that the carrying amount of an assetmay not be recoverable. Due to Devon’s use of the fullcost method of accounting for its oil and gas properties,SFAS No. 121 does not apply to Devon’s oil and gasproperty assets which comprise approximately 97% ofDevon’s net property and equipment. Accordingly, theadoption of SFAS No. 121 did not have an impact onDevon’s financial position or results of operations in1996.

Depreciation and amortization of other propertyand equipment, including leasehold improvements, areprovided using the straight-line method based on esti-mated useful lives from 3 to 39 years.

GAS BALANCING During the course of normaloperations, Devon and other joint interest owners ofnatural gas reservoirs will take more or less than theirrespective ownership share of the natural gas volumesproduced. These volumetric imbalances are monitoredover the lives of the wells’ production capability. If animbalance exists at the time the wells’ reserves aredepleted, cash settlements are made among the jointinterest owners under a variety of arrangements.

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Notes to Consolidated Financial StatementsDevon Energy Corporation and Subsidiaries

Devon follows the sales method of accountingfor gas imbalances. A liability is recorded only ifDevon’s excess takes of natural gas volumes exceed itsestimated remaining recoverable reserves. No receiv-ables are recorded for those wells where Devon hastaken less than its ownership share of gas production.

STOCK OPTIONS On January 1, 1996, Devonadopted SFAS No. 123, “Accounting for Stock-BasedCompensation,” which permits entities to recognizeover the vesting period the fair value of all stock-basedawards on the date of grant. Alternatively, SFAS No.123 also allows entities to continue to apply provisionsof APB No. 25, “Accounting for Stock Issued toEmployees,” whereby compensation expense is recordedon the date of grant only if the current market price ofthe underlying stock exceeds the exercise price.Companies which continue to apply the provisions ofAPB No. 25 are required by SFAS No. 123 to disclosepro forma net earnings and net earnings per share foremployee stock option grants made in 1995 and futureyears as if the fair-value-based method defined inSFAS No. 123 had been applied. Devon has elected tocontinue to apply the provisions of APB No. 25, andhas provided the pro forma disclosures required bySFAS No. 123 in Note 10.

MAJOR PURCHASERS During 1997 and 1996,there was one purchaser, Aquila Energy MarketingCorporation (“Aquila”), who accounted for over 10% ofDevon’s gas sales. Aquila accounted for 46% of Devon’s1997 gas sales and 45% of 1996 gas sales. During 1995,there were two purchasers who accounted for over 10%of Devon’s gas sales. These two purchasers and theirrespective share of gas sales were: Aquila - 31%; andEnron Gas Marketing, Inc. - 16%.

INCOME TAXES Devon accounts for incometaxes using the asset and liability method, wherebydeferred tax assets and liabilities are recognized for thefuture tax consequences attributable to differencesbetween the financial statement carrying amounts ofassets and liabilities and their respective tax bases, aswell as the future tax consequences attributable to thefuture utilization of existing tax net operating loss andother types of carryforwards. Deferred tax assets andliabilities are measured using enacted tax rates expectedto apply to taxable income in the years in which thosetemporary differences and carryforwards are expectedto be recovered or settled. The effect on deferred taxassets and liabilities of a change in tax rates is recog-nized in income in the period that includes the enact-ment date.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses are reported net ofamounts allocated to working interest owners of the oiland gas properties operated by Devon, net of amountscharged to affiliated partnerships for administrative andoverhead costs, and net of amounts capitalized pursuantto the full cost method of accounting.

NET EARNINGS PER COMMON SHARE InFebruary, 1997, the Financial Accounting StandardsBoard issued Statement of Financial Accounting Stan-dards No. 128, “Earnings Per Share.” SFAS No. 128revised the previous calculation methods and presenta-tions of earnings per share. The statement required thatall prior-period earnings per share data be restated.Devon adopted SFAS No. 128 in the fourth quarter of1997 as permitted by the statement. The effect ofadopting SFAS No. 128 was not material to Devon’sprior-period earnings per share data. The previouslyreported amounts for earnings per share assuming nodilution (now replaced by “basic earnings per share”under SFAS No. 128) were not affected for any priorperiods. Restated “diluted” earnings per share were $0.01per share less than the previously reported “earnings pershare assuming full dilution” for each of the followingperiods: the years 1995 and 1994 and the second andthird quarters of 1996 (as disclosed in Note 15).

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Under the provisions of SFAS No. 128, basicearnings per share is computed by dividing incomeavailable to common stockholders by the weightedaverage number of common shares outstanding for theperiod. Diluted earnings per share reflects the potentialdilution that could occur if Devon’s outstanding stockoptions were exercised (calculated using the treasury

stock method) or if Devon’s Trust ConvertiblePreferred Securities were converted to common stock.

The following tables reconcile the net earningsand common shares outstanding used in the calcula-tions of basic and diluted net earnings per share for theyears 1997, 1996 and 1995.

Common NetNet Shares Earnings

Earnings Outstanding Per Share

YEAR ENDED DECEMBER 31, 1997:

Basic earnings per share $ 75,291,529 32,215,745 2.34

Dilutive effect of:Potential common shares issuable upon the conversion of Trust Convertible Preferred Securities (the increase in net earnings is net of income tax expense of $3,853,000) 6,025,955 4,901,507

Potential common shares issuable upon the exercise of employee stock options — 408,477

Diluted earnings per share $ 81,317,484 37,525,729 2.17

YEAR ENDED DECEMBER 31, 1996:

Basic earnings per share 34,800,532 22,159,507 1.57

Dilutive effect of:Potential common shares issuable upon theconversion of Trust Convertible Preferred Securities (the increase in net earnings is net of income tax expense of $1,837,000) 2,997,779 2,383,793

Potential common shares issuable upon the exercise of employee stock options — 254,352

Diluted earnings per share $ 37,798,311 24,797,652 1.52

YEAR ENDED DECEMBER 31, 1995:

Basic earnings per share 14,501,899 22,073,550 0.66

Dilutive effect of potential common shares issuable upon the exercise of employee stock options — 130,621

Diluted earnings per share $ 14,501,899 22,204,171 0.65

DIVIDENDS Dividends on common stock werepaid in 1995 and the first three quarters of 1996 at aper share rate of $0.03 per quarter. The dividend ratewas increased to $0.05 per share for the fourth quarterof 1996 and all four quarters of 1997.

FAIR VALUE OF FINANCIAL INSTRUMENTS

Devon’s only financial instruments for which the fairvalue differs materially from the carrying value are theinterest rate swap discussed in Note 7 and the TrustConvertible Preferred Securities discussed in Note 9.The fair value and the carrying value for all otherfinancial instruments (cash and equivalents, accountsreceivable, accounts payable and long-term debt) areapproximately equal. Such equality is due to the short-term nature of the current assets and liabilities and thefact that the interest rates paid on Devon’s long-termdebt are set for periods of three months or less.

STATEMENTS OF CASH FLOWS For purposes ofthe consolidated statements of cash flows, Devonconsiders all highly liquid investments with originalmaturities of three months or less to be cash equivalents.

COMMITMENTS AND CONTINGENCIES Liabili-ties for loss contingencies arising from claims, assess-ments, litigation or other sources are recorded when itis probable that a liability has been incurred and theamount can be reasonably estimated.

In October, 1996, the American Institute ofCertified Public Accountants issued Statement of Posi-tion (SOP) 96-1, “Environmental Remediation Liabili-ties.” SOP 96-1 was adopted by Devon on January 1,1997. It requires, among other things, that environ-mental remediation liabilities be accrued when thecriteria of SFAS No. 5, “Accounting for Contingen-cies,” have been met. SOP 96-1 also provides guidancewith respect to the measurement of the remediationliabilities. Such accounting is consistent with Devon’smethod of accounting for environmental remediationcosts. Therefore, adoption of SOP 96-1 did not have amaterial impact on Devon’s financial position or resultsof operations.

RECLASSIFICATIONS Certain items in the 1996and 1995 consolidated balance sheets and statements ofcash flows have been reclassified to correspond with the1997 presentation.

ACQUISITIONS AND PRO FORMAINFORMATION

On December 31, 1996, Devon acquired allof Kerr-McGee Corporation’s (“Kerr-McGee”) NorthAmerican onshore oil and gas exploration and produc-tion business and properties (the “KMG-NAOSProperties”). As consideration, Devon issued 9,954,000shares of its common stock to Kerr-McGee. The acqui-sition was made pursuant to an October 17, 1996,agreement and plan of merger among Devon, Kerr-McGee and certain of their subsidiaries.

Devon recorded the KMG-NAOS Properties atapproximately $221.6 million. Such value was based onthe value of the shares of Devon common stock issuedas determined pursuant to generally acceptedaccounting principles. An additional $30.3 million wasallocated to the KMG-NAOS Properties for thedeferred income tax liability created as a result of thesubstantially tax-free nature of the transaction to Kerr-McGee. Excluding the additional deferred tax liability,the amount recorded for the KMG-NAOS Propertiesincludes approximately $195.1 million allocated toproved oil and gas reserves, $29.0 million allocated toundeveloped leasehold acquired, $0.6 million allocatedto inventories and other assets acquired and $3.1million allocated to certain assumed liabilities.Including the additional $30.3 million of deferred taxliability, $220.0 million was allocated to proved reservesand $34.4 million to undeveloped leasehold.

Estimated proved reserves associated with theKMG-NAOS Properties as of December 31, 1996,were 47 million barrels of oil equivalent (“MMBoe”) inthe United States and 15 MMBoe in Canada. Thesereserves were approximately 36% oil and natural gasliquids and 64% natural gas. Included in the acquiredreserves were certain proved undeveloped reserves, forwhich Devon expected to incur approximately $6million of future capital costs. The United States assetsacquired are located predominantly in the Rocky

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Mountain, Permian Basin and Mid-Continent areas ofthe country. All of these areas were already core areas ofDevon’s operations. (The quantities of proved reservesand the estimated development costs stated in thisparagraph are unaudited.)

On December 18, 1995, Devon acquired addi-tional interests in certain of its Wyoming oil andnatural gas properties and a gas processing plant (the“Worland Properties”) for approximately $50.3 million.The acquisition was primarily funded with $46.0million of borrowings from Devon’s credit lines.Approximately $46.3 million of the purchase price wasallocated to proved oil, gas and natural gas liquidsreserves and the plant. The remaining $4.0 million ofthe purchase price was allocated to undeveloped lease-hold.

PRO FORMA INFORMATION (UNAUDITED) The1996 acquisition of the KMG-NAOS Properties asdescribed above was accounted for by the purchasemethod of accounting for business combinations.Accordingly, the accompanying 1996 consolidatedstatement of operations does not include any revenuesor expenses associated with the KMG-NAOS Proper-ties. Following are Devon’s pro forma results for 1996assuming the acquisition of the KMG-NAOS Proper-ties occurred on January 1, 1996:

1996

REVENUES

Oil sales $ 148,337,000Gas sales 125,092,000Natural gas liquids sales 19,081,000Other 4,674,000

Total revenues 297,184,000

COSTS AND EXPENSES

Lease operating expenses 58,384,000Production taxes 20,167,000Depreciation, depletion and amortization 78,310,000General and administrative expenses 14,101,000Interest expense 5,277,000Distributions on preferred

securities of subsidiary trust 4,753,000Total costs and expenses 180,992,000

Earnings before income taxes 116,192,000

INCOME TAX EXPENSE

Current 14,023,000Deferred 32,721,000

Total income tax expense 46,744,000

Net earnings $ 69,448,000

Net earnings per average common share outstanding:Basic $2.16Diluted $2.09

Weighted average common sharesoutstanding - basic 32,086,310

PRODUCTION DATA

Oil (Barrels) 7,241,000Gas (Mcf ) 70,925,000Natural gas liquids (Barrels) 1,304,000

The 1995 acquisition of the Worland Propertiesdescribed above was accounted for by the purchasemethod of accounting for business combinations.Accordingly, the accompanying consolidated statementsof operations do not include any revenues or expensesrelated to the Worland Properties prior to the closingdate of December 18, 1995. Following are Devon’s proforma 1995 results assuming the acquisition of KMG-NAOS Properties and the Worland Properties bothoccurred on January 1, 1995:

SAN JUAN BASIN TRANSACTION

Effective January 1, 1995, Devon and anunrelated company entered into a transac-

tion covering substantially all of Devon’s San JuanBasin coal seam gas properties (the “San Juan BasinTransaction”). These coal seam gas properties repre-sented Devon’s largest oil and gas reserve position as ofDecember 31, 1994. The properties’ estimated reservesas of year-end 1994 were 199.2 billion cubic feet(“Bcf ”) of natural gas, or 31% of Devon’s 633.2 equiva-lent Bcf of combined oil and natural gas reserves. Inaddition to the cash flow and earnings impact normallyassociated with oil and gas production, these propertiesalso qualify as a “nonconventional fuel source” underthe Internal Revenue Code of 1986. Consequently, gasproduced from these properties through the year 2002qualifies for Section 29 tax credits, which as of year-end 1997 were equal to approximately $1.05 permillion Btu (“MMBtu”).

The San Juan Basin Transaction involvesapproximately 186.2 Bcf, or 93%, of the year-end 1994coal seam gas reserves, and has four major parts associ-ated with it. First, Devon conveyed to the unrelatedparty 179 Bcf of the properties’ reserves. However, forfinancial reporting purposes, Devon retained all of suchreserves and their future production and cash flowthrough a volumetric production payment and a repur-chase option. Second, Devon conveyed outright to theunrelated party 7.2 Bcf of reserves for a sales price of$5.2 million. The reserves and future cash flow associ-ated with this conveyance were not retained by Devon.Third, and the source of the most significant impact ofthe transaction, Devon receives payments equal to 75%of the Section 29 tax credits generated by the proper-ties. And fourth, Devon retained a 75% reversionary

interest in any reserves in excess of the 186.2 Bcf esti-mated to exist as of December 31, 1994. Each of theseparts of the San Juan Basin Transaction, and theireffects on Devon’s operations, are described in moredetail in the following paragraphs.

The production payment retained by Devon isequal to 94.05% of the first 143.4 Bcf of gas producedfrom the properties, or 134.9 Bcf. As such, Devoncontinues to record gas sales and associated productionand operating expenses and reserves associated with theproduction payment. Production from the retainedproduction payment is currently estimated to occurover a period of nine years.

The conveyance of the properties which are notsubject to the retained production payment or therepurchase option was accounted for as a sale of oil andgas properties. Accordingly, 7.2 Bcf of gas reserves wereremoved from total proved reserves, and the $5.2million of proceeds reduced the book value of oil andgas properties. The conveyance to the third party islimited exclusively to the existing wells drilled as ofJanuary 1, 1995. Wells to be drilled in the future, if any,are not included in this transaction.

In addition to receiving 94.05% of the proper-ties’ net cash flow through the retained productionpayment, Devon receives quarterly payments from thethird party equal to 75% of the value of the Section 29tax credits which are generated by production fromsuch properties until the earlier of December 31, 2002,or until the option to repurchase is exercised. For theyears ended December 31, 1997, 1996 and 1995,Devon received $11.4 million, $11.5 million and $13.9million, respectively, related to the credits. Of theseamounts, $8.5 million, $10.3 million and $12.8 million

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1995

Pro Forma Effect of

Devon KMG-NAOS Worland DevonHistorical Properties Properties Pro Forma

Total revenues $ 113,303,000 108,279,000 5,349,000 226,931,000Net earnings $ 14,502,000 14,335,000 (1,405,000) 27,432,000Net earnings per share:

Basic $ 0.66 0.86Diluted $ 0.65 0.85

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were recorded as additional gas sales in 1997, 1996 and1995, respectively, and $2.9 million, $1.2 million and$1.1 million were recorded as an addition to liabilitiesin 1997, 1996 and 1995, respectively, as discussed inthe following paragraph. Based on the reserves esti-mated at December 31, 1997, and an assumed annualinflation factor of 2%, Devon estimates it will receivetotal tax credit payments of approximately $49 millionfrom 1998 through 2002.

Devon has an option to repurchase the proper-ties at any time. The purchase price of such option isequal to the fair market value of the properties at thetime the option is exercised, as defined in the transac-tion agreement, less the production payment balance.At closing, Devon received $5.6 million associated withreserves to be produced subsequent to the term of theproduction payment. Such amount is included in long-term “other liabilities” on the accompanying balancesheet. Since Devon expects to eventually exercise itsoption to repurchase the properties, the liability isbeing increased over time to reflect the expected optionpurchase price. As the purchase price increases, aportion of the tax credit payments received by Devon isadded to the liability. As stated above, for the yearsended December 31, 1997, 1996 and 1995, $2.9million, $1.2 million and $1.1 million, respectively, ofthe total amount received for tax credit payments wereadded to the liability. On December 31, 1997, Devonexercised its option to reacquire approximately 20% ofthe properties for approximately $1.9 million. Theother party to the production payment paid Devon$5.3 million in 1997 in return for Devon agreeing notto exercise its option on the remaining 80% of theproperties through the end of 1997. (This agreementdoes not limit Devon’s right to exercise its option in1998 or beyond.) The $5.3 million that Devonreceived, net of the $1.9 million paid for the partialrepurchase, was added to the repurchase liability in1997. The repurchase liability totaled $14.2 million atthe end of 1997.

Devon has retained a 75% reversionary interestin the properties’ reserves in excess, if any, of the 186.2Bcf of reserves estimated to exist at December 31,1994. The terms of the transaction provide that thethird party will pay 100% of the capital necessary todevelop any such incremental reserves for its 25%interest in such reserves. Devon’s repurchase option alsoincludes the right to purchase this incremental 25%.However, the $14.2 million of other liabilities recordedas of year-end 1997, does not include any amountrelated to such reserves.

SUPPLEMENTAL CASH FLOWINFORMATION

Cash payments for interest in 1997, 1996and 1995 were approximately $0.6 million, $5.5 millionand $6.7 million, respectively. Cash payments forfederal, state and foreign income taxes in 1997, 1996and 1995 were approximately $25.0 million, $3.4million and $2.2 million, respectively.

The 1996 acquisition of the KMG-NAOS Prop-erties involved non-cash consideration as presentedbelow:

Value of common stock issued $ 221,576,040 Liabilities assumed 3,098,691 Deferred tax liability created 30,308,000

Fair value of assets acquired $ 254,982,731

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ACCOUNTS RECEIVABLE

The components of accounts receivable included the following:

December 31, 1997 1996 1995

Oil, gas and natural gas liquids revenue accruals $ 32,643,633 24,200,047 11,169,313Joint interest billings 11,742,554 4,318,764 2,962,037 Other 3,521,618 1,461,495 493,945

47,907,805 29,980,306 14,625,295Allowance for doubtful accounts (400,000) (400,000) (225,000)

Net accounts receivable $ 47,507,805 29,580,306 14,400,295

PROPERTY AND EQUIPMENT

Property and equipment included the following:

December 31, 1997 1996 1995

Oil and gas properties:Subject to amortization $ 1,024,624,931 899,827,749 604,227,702Not subject to amortization:

Acquired in 1997 9,476,111 — —Acquired in 1996 27,906,918 35,141,800 —Acquired in 1995 3,916,088 5,034,942 5,635,170Acquired in 1994 870,664 1,001,291 1,001,427Acquired in 1993 4,026,995 5,204,995 5,556,977Acquired in 1992 7,814,255 8,113,899 8,257,985

Accumulated depreciation, depletion and amortization (361,055,425) (278,923,340) (237,385,785)

Net oil and gas properties 717,580,537 675,401,336 387,293,476

Other property and equipment 24,684,540 20,481,080 6,758,643

Accumulated depreciation and amortization (4,462,297) (3,036,070) (2,233,382)

Net other property and equipment 20,222,243 17,445,010 4,525,261

Property and equipment, net of accumulated depreciation,depletion and amortization $ 737,802,780 692,846,346 391,818,737

Depreciation, depletion and amortization expense consisted of the following components:

Year Ended December 31, 1997 1996 1995

Depreciation, depletion and amortizationof oil and gas properties $ 82,413,245 41,537,555 36,639,753

Depreciation and amortization of otherproperty and equipment 2,328,461 1,337,420 1,045,978

Amortization of other assets 565,162 486,054 404,052

Total expense $ 85,306,868 43,361,029 38,089,783

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LONG-TERM DEBT

Devon has long-term lines of creditpursuant to which it can borrow up to an

amount determined by the banks based on their evalua-tion of the assets and cash flow (the “Borrowing Base”)of Devon. The established Borrowing Base atDecember 31, 1997, was $208 million. Amountsborrowed under the credit lines bear interest at variousfixed rate options which Devon may elect for periodsup to 90 days. Such rates are generally less than theprime rate. Devon may also elect to borrow at theprime rate. No amounts were borrowed under thecredit lines at the end of 1997. The average interestrates on the outstanding debt at the end of 1996 and1995 were 6.19% and 6.64%, respectively. The loanagreements also provide for a quarterly facility fee equalto .25% per annum.

Debt borrowed under the credit lines is unse-cured. No principal payments are required until matu-rity unless the unpaid balance exceeds the maximumloan amount. The maximum loan amount is equal tothe Borrowing Base until August 31, 2000. Thereafter,the maximum loan amount will be reduced by 8.33%every three months until August 31, 2003. The loanagreements contain certain covenants and restrictions,among which are limitations on additional borrowingsand annual sales of properties valued at more than $25million, and working capital and net worth mainte-nance requirements. At December 31, 1997, Devonwas in compliance with such covenants and restrictions.

Devon also has a demand revolving operatingcredit facility with a Canadian bank. This facility isunsecured and is utilized for general corporate purposesrelated to Devon’s Canadian operations. The credit linetotals $12.5 million Canadian dollars, and interest ischarged at the bank’s prime rate for loans to Canadiancustomers. Amounts borrowed are due on demand.However, due to Devon’s sources of long-term debtdescribed above, amounts borrowed pursuant to theCanadian credit line are expected to be classified aslong-term debt. No amounts were borrowed against theCanadian credit line at year-end 1997 or 1996.

Devon entered into an interest rate swap agree-ment in June, 1995, to hedge the impact of interest ratechanges on a portion of its long-term debt. Thenotional amount of the swap agreement was $75million, and the other party to the agreement was oneof Devon’s lenders. The swap agreement was accountedfor as a hedge. On July 1, 1996, Devon terminated theinterest rate swap agreement for a gain of $0.8 million.This gain is being recognized ratably as a reduction tointerest expense during the period from July 1, 1996 toJune 16, 1998 (the original expiration date of theagreement). Approximately $0.4 million of the gainwas recognized in 1997, and $0.2 million was recog-nized in 1996. The fair value of the interest rate swapas of December 31, 1995 was a liability of approxi-mately $1.4 million. The interest rate swap had nocarrying value in the accompanying consolidated finan-cial statements.

See Note 9 for a description of certain convert-ible debentures issued in 1996 to a Devon affiliate.

INCOME TAXES

At December 31, 1997, Devon had thefollowing carryforwards available to reduce

future federal and state income taxes:

YEARS OF CARRYFORWARD

TYPES OF CARRYFORWARD EXPIRATION AMOUNTS

Net operating loss - federal 2007-2008 $ 7,300,000Net operating loss - various states 1998-2011 $10,200,000

All of the carryforward amounts shown abovehave been utilized for financial purposes to reducedeferred taxes.

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The earnings before income taxes and the components of income tax expense for the years 1997, 1996 and1995 were as follows:

Year Ended December 31, 1997 1996 1995

Earnings before income taxes:United States $ 106,905,365 59,298,532 25,621,899 Canada 14,435,164 — —Total $ 121,340,529 59,298,532 25,621,899

Current income tax expense:Federal $ 18,659,000 6,147,000 4,155,000 State 2,521,000 562,000 340,000Canada 4,022,000 — —Total current tax expense 25,202,000 6,709,000 4,495,000

Deferred income tax expense:Federal 17,025,000 14,185,000 5,463,000 State 1,578,000 3,604,000 1,162,000Canada 2,244,000 — —Total deferred tax expense 20,847,000 17,789,000 6,625,000

Total income tax expense $ 46,049,000 24,498,000 11,120,000

Total income tax expense differed from the amounts computed by applying the federal income tax rate to netearnings before income taxes as a result of the following:

Year Ended December 31, 1997 1996 1995

Federal statutory tax rate 35% 35% 35%Nonconventional fuel source credits (1) — (1)State income taxes 3 5 4Taxation on foreign operations 1 — —Effect of San Juan Basin Transaction — 2 4Other — (1) 1Effective income tax rate 38% 41% 43%

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets andliabilities at December 31, 1997, 1996 and 1995 are presented below:

December 31, 1997 1996 1995

Deferred tax assets:Net operating loss carryforwards $ 2,909,000 5,314,000 6,082,000Statutory depletion carryforwards — 412,000 2,287,000Investment tax credit carryforwards 19,000 42,000 85,000Minimum tax credit carryforwards — 5,624,000 5,576,000Production payments 18,504,000 19,685,000 24,770,000Other 2,932,000 2,613,000 1,966,000

Total gross deferred tax assets 24,364,000 33,690,000 40,766,000Less valuation allowance 100,000 100,000 100,000Net deferred tax assets 24,264,000 33,590,000 40,666,000

Deferred tax liabilities:Property and equipment, principally due

to differences in depreciation, andthe expensing of intangible drillingcosts for tax purposes (123,783,000) (113,111,000) (74,369,000)

Other (1,521,000) — —

Total deferred tax liabilities (125,304,000) (113,111,000) (74,369,000)

Net deferred tax liability $ (101,040,000) (79,521,000) (33,703,000)

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As shown in the above schedule, Devon hasrecognized $24.3 million of net deferred tax assets as ofDecember 31, 1997. Such amount consists almostentirely of $2.9 million of various carryforwards avail-able to offset future income taxes, and $18.5 million ofnet tax basis in production payments. The carryfor-wards include federal net operating loss carryforwards,the majority of which do not begin to expire until2007, and state net operating loss carryforwards whichexpire primarily between 1999 and 2011. The tax bene-fits of carryforwards are recorded as an asset to theextent that management assesses the utilization of suchcarryforwards to be “more likely than not.” When thefuture utilization of some portion of the carryforwardsis determined not to be “more likely than not,” a valua-tion allowance is provided to reduce the recorded taxbenefits from such assets.

Devon expects the tax benefits from the netoperating loss carryforwards to be utilized between1998 and 2001. Such expectation is based upon currentestimates of taxable income during this period,considering limitations on the annual utilization ofthese benefits as set forth by federal tax regulations.Significant changes in such estimates caused byvariables such as future oil and gas prices or capitalexpenditures could alter the timing of the eventualutilization of such carryforwards. There can be noassurance that Devon will generate any specific level ofcontinuing taxable earnings. However, managementbelieves that Devon’s future taxable income will morelikely than not be sufficient to utilize substantially allits tax carryforwards prior to their expiration. A$100,000 valuation allowance has been recorded atDecember 31, 1997, related to depletion carryforwardsacquired in a 1994 merger.

The $18.5 million of deferred tax assets relatedto production payments is offset by a portion of thedeferred tax liability related to the excess financial basisof property and equipment. The income tax accountingfor the San Juan Basin Transaction described in Note 3differs from the financial accounting treatment which isdescribed in such note. For income tax purposes, a gain

from the conveyance of the properties was realized, andthe present value of the production payments to bereceived was recorded as a note receivable. For presen-tation purposes, the $18.5 million represents the taxeffect of the difference in accounting for the productionpayment, less the effect of the taxable gain from thetransaction which is being deferred and recognized onthe installment basis for income tax purposes.

TRUST CONVERTIBLE PREFERREDSECURITIES

On July 10, 1996, Devon, through itsnewly-formed affiliate Devon Financing Trust,completed the issuance of $149.5 million of 6.5% trustconvertible preferred securities (the “TCP Securities”)in a private placement. Devon Financing Trust issued2,990,000 shares of the TCP Securities at $50 pershare. Each TCP Security is convertible at the holder’soption into 1.6393 shares of Devon common stock,which equates to a conversion price of $30.50 per shareof Devon common stock.

Devon Financing Trust invested the $149.5million of proceeds in 6.5% convertible junior subordi-nated debentures issued by Devon (the “ConvertibleDebentures”). In turn, Devon used the net proceedsfrom the issuance of the Convertible Debentures toretire debt outstanding under its credit lines.

The sole assets of Devon Financing Trust are theConvertible Debentures. The Convertible Debenturesand the related TCP Securities mature on June 15,2026. However, Devon and Devon Financing Trustmay redeem the Convertible Debentures and the TCPSecurities, respectively, in whole or in part, on or afterJune 18, 1999. For the first twelve months thereafter,redemptions may be made at 104.55% of the principalamount. This premium declines proportionally everytwelve months until June 15, 2006, when the redemp-tion price becomes fixed at 100% of the principalamount. If Devon redeems any Convertible Debenturesprior to the scheduled maturity date, Devon FinancingTrust must redeem TCP Securities having an aggregateliquidation amount equal to the aggregate principalamount of Convertible Debentures so redeemed.

Devon has guaranteed the payments of distribu-tions and other payments on the TCP Securities only ifand to the extent that Devon Financing Trust hasfunds available therefor. Such guarantee, when taken

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together with Devon’s obligations under the Convert-ible Debentures and related indenture and declarationof trust, provide a full and unconditional guarantee ofamounts due on the TCP Securities.

Devon owns all the common securities of DevonFinancing Trust. As such, the accounts of DevonFinancing Trust are included in Devon’s consolidatedfinancial statements after appropriate eliminations ofintercompany balances. The distributions on the TCPSecurities are recorded as a charge to pre-tax earningson Devon’s consolidated statements of operations, andsuch distributions are deductible by Devon for incometax purposes.

Devon estimates that the fair value of the TCPSecurities as of December 31, 1997 and 1996 wasapproximately $218.8 million and $196.6 million,respectively, as compared to the book value of $149.5million. These fair values were based on quoted pricesat which TCP Securities were purchased and sold onDecember 31, 1997 and 1996.

STOCKHOLDERS’ EQUITY

The authorized capital stock of Devonconsists of 400 million shares of common

stock, par value $.10 per share (the “Common Stock”),and three million shares of preferred stock, par value$1.00 per share (the “Preferred Stock”). The PreferredStock may be issued in one or more series, and theterms and rights of such stock will be determined bythe Board of Directors.

Devon’s Board of Directors has designated150,000 shares of the Preferred Stock as Series AJunior Participating Preferred Stock (the “Series APreferred Stock”) in connection with the adoption ofthe share rights plan described later in this note. AtDecember 31, 1997, there were no shares of Series APreferred Stock issued or outstanding. The Series APreferred Stock is entitled to receive cumulative quar-terly dividends per share equal to the greater of $10 or100 times the aggregate per share amount of all divi-dends (other than stock dividends) declared onCommon Stock since the immediately preceding quar-terly dividend payment date or, with respect to the firstpayment date, since the first issuance of Series APreferred Stock. Holders of the Series A Preferred

Stock are entitled to 100 votes per share (subject toadjustment to prevent dilution) on all matterssubmitted to a vote of the stockholders. The Series APreferred Stock is neither redeemable nor convertible.The Series A Preferred Stock ranks prior to theCommon Stock but junior to all other classes ofPreferred Stock.

STOCK OPTION PLANS Devon has outstandingstock options issued to key management and profes-sional employees under three stock option plansadopted in 1988, 1993 and 1997 (“the 1988 Plan”, “the1993 Plan” and “the 1997 Plan”). Options grantedunder the 1988 Plan and 1993 Plan remain exercisableby the employees owning such options, but no newoptions will be granted under these plans. AtDecember 31, 1997, 12 participants held the 251,100options outstanding under the 1988 Plan, and 23participants held the 806,300 options outstandingunder the 1993 Plan.

On May 21, 1997, Devon’s stockholders adoptedthe 1997 Plan and reserved two million shares ofCommon Stock for issuance thereunder. Approximately30 employees and eight members of the board of direc-tors were eligible to participate in the 1997 Plan atyear-end 1997.

The exercise price of stock options grantedunder the 1997 Plan may not be less than the esti-mated fair market value of the stock at the date ofgrant, plus 10% if the grantee owns or controls morethan 10% of the total voting stock of Devon prior tothe grant. Options granted are exercisable during aperiod established for each grant, which period maynot exceed 10 years from the date of grant. Under the1997 Plan, the grantee must pay the exercise price incash or in Common Stock, or a combination thereof, atthe time that the option is exercised. The 1997 Plan isadministered by a committee comprised of non-management members of the Board of Directors. The1997 Plan expires on April 25, 2007. As of December31, 1997, seven participants (all of whom are non-management members of the Board of Directors) heldthe 21,000 options outstanding under the 1997 Plan.There were 1,979,000 options available for futuregrants as of December 31, 1997.

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A summary of the status of Devon’s stock option plans as of December 31, 1995, 1996 and 1997, and changesduring each of the years then ended, is presented below:

Options Outstanding Options Exercisable WEIGHTED WEIGHTED

AVERAGE AVERAGE

NUMBER EXERCISE NUMBER EXERCISE

OUTSTANDING PRICE EXERCISABLE PRICE

BALANCE AT DECEMBER 31, 1994 877,900 $ 18.947 485,000 $ 17.423

Options granted 219,000 $ 23.875Options exercised (60,900) $ 12.843Options forfeited (7,100) $ 20.105

BALANCE AT DECEMBER 31, 1995 1,028,900 $ 20.349 688,800 $ 19.744

Options granted 248,500 $ 32.358Options exercised (75,400) $ 12.909

BALANCE AT DECEMBER 31, 1996 1,202,000 $ 23.299 823,500 $ 21.783

Options granted 54,000 $ 34.584Options exercised (177,600) $ 20.529

BALANCE AT DECEMBER 31, 1997 1,078,400 $ 24.320 824,500 $ 23.257

The weighted average fair values of optionsgranted during 1997, 1996 and 1995 were $13.74,$12.97 and $9.89, respectively. The fair value of eachoption grant was estimated for disclosure purposes onlyon the date of grant using the Black-Scholes OptionPricing Model with the following assumptions for1997, 1996 and 1995, respectively: risk-free interestrates of 6.3%, 6.3% and 5.5%; dividend yields of 0.6%,

0.6% and 0.5%; expected lives of five years for eachperiod; and volatility of the price of the underlyingcommon stock of 33.8%, 33.9% and 38.1%.

The following table summarizes informationabout Devon’s stock options which were outstanding,and those which were exercisable, as of December 31,1997:

Options Outstanding Options Exercisable WEIGHTED WEIGHTED WEIGHTED

RANGE OF AVERAGE AVERAGE AVERAGE

EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE

PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE

$8 to $14 90,800 3.7 years $ 9.677 90,800 $ 9.677$18 to $21 150,300 6.9 years $ 18.098 120,900 $ 18.106$23 to $26 539,800 6.8 years $ 23.799 451,000 $ 23.826$32 to $37 297,500 9.0 years $ 32.878 161,800 $ 33.138

1,078,400 7.2 years $ 24.320 824,500 $ 23.257

Had Devon elected the fair value provisions ofSFAS No. 123 and recognized compensation expensebased on the fair value of the stock options granted asof their grant date, Devon’s 1997, 1996 and 1995 proforma net earnings and pro forma net earnings pershare would have differed from the amounts actually

reported as shown in the table below. The pro formaamounts shown below do not include the effects ofstock options granted prior to January 1, 1995. The proforma effects shown below may not be representative ofthe effects reported in future years.

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Year Ended December 31, 1997 1996 1995

Net earnings:As reported $ 75,291,529 34,800,532 14,501,899Pro forma $ 74,564,309 34,016,571 13,540,052

Net earnings per share:As reported:

Basic $ 2.34 1.57 0.66 Diluted $ 2.17 1.52 0.65

Pro forma:Basic $ 2.31 1.54 0.61 Diluted $ 2.15 1.49 0.61

SHARE RIGHTS PLAN Under Devon’s sharerights plan, stockholders have one right for each shareof Common Stock held. The rights become exercisableand separately transferable ten business days after a) anannouncement that a person has acquired, or obtainedthe right to acquire, 15% or more of the voting sharesoutstanding, or b) commencement of a tender orexchange offer that could result in a person owning15% or more of the voting shares outstanding.

Each right entitles its holder (except a holderwho is the acquiring person) to purchase either a)1/100 of a share of Series A Preferred Stock for$75.00, subject to adjustment or b) Devon CommonStock with a value equal to twice the exercise price ofthe right, subject to adjustment to prevent dilution. Inthe event of certain merger or asset sale transactionswith another party or transactions which wouldincrease the equity ownership of a shareholder whothen owned 15% or more of Devon, each Devon rightwill entitle its holder to purchase securities of themerging or acquiring party with a value equal to twicethe exercise price of the right.

The rights, which have no voting power, expireon April 16, 2005. The rights may be redeemed byDevon for $.01 per right until the rights become exer-cisable.

RETIREMENT PLANS

Devon has a defined benefit retirement plan(the “Basic Plan”) which is non-contributory

and includes employees meeting certain age and servicerequirements. The benefits are based on the employee’syears of service and compensation. Devon’s fundingpolicy is to contribute annually the maximum amountthat can be deducted for federal income tax purposes.Rights to amend or terminate the Basic Plan areretained by Devon.

Effective January 1, 1995, Devon has a separatedefined benefit retirement plan (the “SupplementaryPlan”) which is non-contributory and includes onlycertain employees whose benefits under the Basic Planare limited by federal income tax regulations. TheSupplementary Plan’s benefits are based on theemployee’s years of service and compensation. Devon’sfunding policy for the Supplementary Plan is to fundthe benefits as they become payable. Rights to amendor terminate the Supplementary Plan are retained byDevon.

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The following table sets forth the aggregate funded status of the Basic Plan and related amounts recognizedin Devon’s balance sheets:

December 31, 1997 1996 1995

Actuarial present value of benefit obligations:Accumulated benefit obligation:

Vested $ (4,630,000) (3,619,000) (3,500,000)Nonvested (1,021,000) (741,000) (654,000)Total $ (5,651,000) (4,360,000) (4,154,000)

Projected benefit obligation for servicerendered to date (6,690,000) (5,122,000) (4,782,000)

Plan assets at fair value, primarily investmentsin mutual funds 6,036,000 5,022,000 4,227,000

Plan assets less than projected benefit obligation (654,000) (100,000) (555,000)Unrecognized prior service cost (benefit) (105,000) (131,000) (154,000)Unrecognized net loss from past experience

different from that assumed, and effectsof changes in assumptions 1,276,000 519,000 921,000

Prepaid pension expense $ 517,000 288,000 212,000

The following table sets forth the aggregate funded status of the Supplementary Plan and related amountsrecognized in Devon’s balance sheets:

December 31, 1997 1996 1995

Actuarial present value of benefit obligations:Accumulated benefit obligation:

Vested $ (4,039,000) (1,960,000) (1,658,000)Nonvested (237,000) (279,000) (255,000)Total (4,276,000) (2,239,000) (1,913,000)

Projected benefit obligation for servicerendered to date (4,969,000) (2,907,000) (2,245,000)

Plan assets at fair value — — —Plan assets less than projected benefit obligation (4,969,000) (2,907,000) (2,245,000)Unrecognized prior service cost 2,078,000 1,235,000 1,354,000Unrecognized net loss from past experience

different from that assumed, and effectsof changes in assumptions 1,172,000 446,000 185,000

Accrued pension expense (1,719,000) (1,226,000) (706,000)Additional minimum liability (2,557,000) (1,013,000) (1,207,000)

Total pension liability $ (4,276,000) (2,239,000) (1,913,000)

The $4.3 million, $2.2 million and $1.9 milliontotal pension liability of the Supplementary Plan as ofDecember 31, 1997, 1996 and 1995, respectively, areincluded in long-term other liabilities on the accompa-nying consolidated balance sheets. The additionalminimum liabilities of $2.6 million, $1.0 million and

$1.2 million at year-end 1997, 1996 and 1995, respec-tively, are offset by intangible assets of the sameamount. These intangible assets are included in otherassets on the balance sheets.

Net pension expense for Devon’s two defined benefit plans included the following components:

Year Ended December 31, 1997 1996 1995

Service cost - benefits earned during the period $ 706,000 557,000 362,000Interest cost on projected benefit obligation 747,000 569,000 446,000 Actual return on plan assets (369,000) (453,000) (536,000)Net amortization and deferral 177,000 231,000 345,000 Net periodic pension expense $ 1,261,000 904,000 617,000

years, so that it could begin the necessary procedures ofapplying for a refund. This tax historically was paid bythe owners of natural gas processing plants, not the gasproducers, and was assessed for the privilege ofprocessing natural gas. While Devon’s nonconventionalgas is purified through a plant prior to the actual salespoint, such purification is only for the purpose ofremoving CO2. Also, Devon does not own an interestin such plant. For these and other reasons, Devon doesnot believe the assessment of the additional tax and therelated penalties and interest is valid. The State of NewMexico in 1997 denied Devon’s initial refund applica-tion made through the normal administrative processes.Subsequently, in late 1997, Devon filed a suit askingthat the assessments be reversed. At this time, it is notpossible to determine the eventual outcome of thismatter. Devon has not expensed in its financial state-ments the taxes, penalties and interest paid, but ratherhas recorded the $1.3 million total as a receivable.

The following is a schedule by year of futureminimum rental payments required under operatingleases that have initial or remaining noncancelable leaseterms in excess of one year as of December 31, 1997:

Year Ending December 31,

1998 $ 555,0001999 402,0002000 326,0002001 88,0002002 40,000Total minimum lease payments required $ 1,411,000

Total rental expense for all operating leases is asfollows for the years ended December 31:

1997 $ 1,130,8961996 $ 572,1771995 $ 546,388

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The weighted average discount rate used indetermining the actuarial present value of the projectedbenefit obligation in 1997, 1996 and 1995 was 7.0%,7.5% and 7.25%, respectively. The rate of increase infuture compensation levels was 5% for all three years.The expected long-term rate of return on assets was8.5% for all three years.

Devon has a 401(k) Incentive Savings Planwhich covers all employees. At its discretion, Devonmay match a certain percentage of the employees’contributions to the plan. The matching percentage isdetermined annually by the Board of Directors.Devon’s matching contributions to the plan were$451,000, $188,000 and $170,000 for the years endedDecember 31, 1997, 1996 and 1995, respectively.

COMMITMENTS AND CONTINGENCIES

Devon is party to various legal actionsarising in the normal course of business. Matters thatare probable of unfavorable outcome to Devon andwhich can be reasonably estimated are accrued. Suchaccruals are based on information known about thematters, Devon’s estimates of the outcomes of suchmatters and its experience in contesting, litigating andsettling similar matters. None of the actions arebelieved by management to involve future amounts thatwould be material after consideration of recordedaccruals.

The State of New Mexico on December 29,1995, assessed Devon and other producers of gas fromthe San Juan Basin a “natural gas processors tax.”Devon’s tax assessment for the years 1990 through1995 was approximately $0.6 million, and the state alsoassessed another $0.3 million of penalties and interest.All of the assessment relates to nonconventional gas.Devon paid these assessments in January 1996, as wellas an additional $0.2 million each year for 1997 and1996 taxes which were paid monthly throughout such

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OIL AND GAS OPERATIONS

COSTS INCURRED The following tables reflect the costs incurred in oil and gas property acquisition,exploration, and development activities:

TOTAL Year Ended December 31, 1997 1996 1995

Property acquisition costs:Proved, excluding deferred income taxes $ 10,997,000 199,655,000 47,316,000Deferred income taxes 2,379,000 22,557,000 —Total proved, including deferred income taxes $ 13,376,000 222,212,000 47,316,000

Unproved, excluding deferred income taxes $ 8,734,000 29,673,000 4,529,000Deferred income taxes (100,000) 5,472,000 —Total unproved, including deferred income taxes 8,634,000 35,145,000 4,529,000

Exploration costs $ 19,169,000 2,708,000 7,174,000Development costs $ 87,394,000 73,468,000 56,253,000

DOMESTIC Year Ended December 31, 1997 1996 1995

Property acquisition costs:Proved, excluding deferred income taxes $ 10,891,000 150,546,000 47,316,000Deferred income taxes 2,084,000 15,257,000 —Total proved, including deferred income taxes $ 12,975,000 165,803,000 47,316,000

Unproved, excluding deferred income taxes $ 7,582,000 26,073,000 4,529,000Deferred income taxes (100,000) 5,472,000 —Total unproved, including deferred income taxes 7,482,000 31,545,000 4,529,000

Exploration costs $ 18,326,000 2,708,000 7,174,000Development costs $ 79,943,000 73,468,000 56,253,000

CANADA Year Ended December 31, 1997 1996 1995

Property acquisition costs:Proved, excluding deferred income taxes $ 106,000 49,109,000 —Deferred income taxes 295,000 7,300,000 —Total proved, including deferred income taxes $ 401,000 56,409,000 —

Unproved $ 1,152,000 3,600,000 —

Exploration costs $ 843,000 — —Development costs $ 7,451,000 — —

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Pursuant to the full cost method of accounting,Devon capitalizes certain of its general and administra-tive expenses which are related to property acquisition,exploration and development activities. Such capital-ized expenses, which are included in the costs shown inthe above tables, were $4.1 million, $2.9 million and$2.7 million in the years 1997, 1996 and 1995, respec-tively.

Due to the substantially tax-free nature of theacquisition of the KMG-NAOS Properties to Kerr-McGee, Devon recorded additional deferred tax liabili-

ties of $28.0 million in 1996. As shown in the above1996 tables, the deferred tax liabilities caused an addi-tional $22.5 million to be allocated to proved oil andgas reserves and an additional $5.5 million to be allo-cated to unproved properties.

During 1997, various uncertainties that existedat year-end 1996 regarding the tax basis and liabilitiesassumed in the KMG-NAOS transaction wereresolved. This resulted in an additional $5.5 millionbeing allocated in 1997 to the proved propertiesacquired in the 1996 KMG-NAOS transaction.

Of this amount, $3.1 million was for liabilitiesassumed and $2.4 million was for additional deferredtax liabilities created. This additional $5.5 million isincluded in the above table of costs incurred in 1997.The resolution of the uncertainties also resulted in areduction of $0.1 million in 1997 to the deferred taxliabilities originally allocated in 1996 to the KMG-NAOS unproved properties.

RESULTS OF OPERATIONS FOR OIL AND GAS

PRODUCING ACTIVITIES The following tables includerevenues and expenses associated directly with Devon’s

oil and gas producing activities. They do not includeany allocation of Devon’s interest costs or generalcorporate overhead and, therefore, are not necessarilyindicative of the contribution to net earnings ofDevon’s oil and gas operations. Income tax expense hasbeen calculated by applying statutory income tax ratesto oil and gas sales after deducting costs, includingdepreciation, depletion and amortization and aftergiving effect to permanent differences.

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TOTAL Year Ended December 31, 1997 1996 1995

Oil, gas and natural gas liquids sales $ 305,748,000 162,558,000 112,425,000Production and operating expenses (83,579,000) (42,226,000) (34,121,000)Depreciation, depletion and amortization (82,413,000) (41,538,000) (36,640,000)Income tax expense (51,050,000) (27,796,000) (15,536,000)Results of operations for oil and gas

producing activities $ 88,706,000 50,998,000 26,128,000Depreciation, depletion and amortization

per equivalent barrel of production $ 4.08 3.88 3.65

DOMESTIC Year Ended December 31, 1997 1996 1995

Oil, gas and natural gas liquids sales $ 273,860,000 162,558,000 112,425,000Production and operating expenses (75,758,000) (42,226,000) (34,121,000)Depreciation, depletion and amortization (73,091,000) (41,538,000) (36,640,000)Income tax expense (44,648,000) (27,796,000) (15,536,000)Results of operations for oil and gas

producing activities $ 80,363,000 50,998,000 26,128,000Depreciation, depletion and amortization

per equivalent barrel of production $ 4.13 3.88 3.65

CANADA Year Ended December 31, 1997 1996 1995

Oil, gas and natural gas liquids sales $ 31,888,000 — —Production and operating expenses (7,821,000) — —Depreciation, depletion and amortization (9,322,000) — —Income tax expense (6,402,000) — —Results of operations for oil and gas

producing activities $ 8,343,000 — —Depreciation, depletion and amortization

per equivalent barrel of production $ 3.74 — —

As previously discussed, the above tables do notinclude any allocation of Devon’s interest costs orgeneral corporate overhead and, therefore, are notnecessarily indicative of the contribution to net earn-ings of Devon’s oil and gas operations. Shown beloware 1997 domestic and Canadian total revenues and netearnings, including all revenues and all costs andexpenses, as well as total assets.

As of or for the Year Ended December 31, 1997: DOMESTIC CANADA TOTAL

Total revenues $ 278,834,000 34,306,000 313,140,000

Net earnings $ 67,123,000 8,169,000 75,292,000

Total assets $ 776,134,000 70,269,000 846,403,000

SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS(Unaudited)

The following supplemental unaudited informa-tion regarding the oil and gas activities of Devon ispresented pursuant to the disclosure requirementspromulgated by the Securities and Exchange Commis-sion and Statement of Financial Accounting StandardsNo. 69, “Disclosures About Oil and Gas ProducingActivities.”

QUANTITIES OF OIL AND GAS RESERVES Setforth below is a summary of the changes in the net

quantities of crude oil, natural gas and natural gasliquids reserves for each of the three years endedDecember 31, 1997. Approximately 92%, 94% and92%, of the respective year-end 1997, 1996 and 1995domestic proved reserves were calculated by the inde-pendent petroleum consultants of LaRoche PetroleumConsultants, Ltd. The remaining percentages ofdomestic reserves are based on Devon’s own estimates.All of the 1997 and 1996 Canadian proved reserveswere calculated by the independent petroleum consul-tants of AMH Group Ltd.

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NATURALOIL GAS GAS LIQUIDS

TOTAL (Bbls) (Mcf) (Bbls)

Proved reserves as of December 31, 1994 42,165,000 347,560,000 5,442,000Revisions of estimates 1,127,000 (7,431,000) 535,000Extensions and discoveries 2,959,000 9,645,000 472,000Purchase of reserves 1,852,000 59,585,000 3,665,000Production (3,300,000) (36,886,000) (600,000)Sale of reserves (337,000) (8,627,000) (45,000)

Proved reserves as of December 31, 1995 44,466,000 363,846,000 9,469,000Revisions of estimates 2,365,000 4,359,000 1,096,000Extensions and discoveries 3,680,000 14,849,000 852,000Purchase of reserves 21,189,000 249,922,000 2,130,000Production (3,816,000) (35,714,000) (952,000)Sale of reserves (403,000) (1,743,000) (16,000)

Proved reserves as of December 31, 1996 67,481,000 595,519,000 12,579,000Revisions of estimates (1,520,000) (17,173,000) 1,614,000Extensions and discoveries 8,517,000 106,608,000 301,000Purchase of reserves 1,126,000 992,000 16,000Production (7,005,000) (69,327,000) (1,626,000)Sale of reserves (156,000) (615,000) (3,000)

Proved reserves as of December 31, 1997 68,443,000 616,004,000 12,881,000Proved developed reserves as of:

December 31, 1994 18,718,000 324,302,000 3,123,000December 31, 1995 28,703,000 311,664,000 6,149,000December 31, 1996 60,202,000 570,265,000 11,212,000December 31, 1997 60,165,000 506,374,000 12,098,000

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NATURALOIL GAS GAS LIQUIDS

DOMESTIC (Bbls) (Mcf) (Bbls)

Proved reserves as of December 31, 1994 42,165,000 347,560,000 5,442,000Revisions of estimates 1,127,000 (7,431,000) 535,000Extensions and discoveries 2,959,000 9,645,000 472,000Purchase of reserves 1,852,000 59,585,000 3,665,000Production (3,300,000) (36,886,000) (600,000)Sale of reserves (337,000) (8,627,000) (45,000)

Proved reserves as of December 31, 1995 44,466,000 363,846,000 9,469,000Revisions of estimates 2,365,000 4,359,000 1,096,000Extensions and discoveries 3,680,000 14,849,000 852,000Purchase of reserves 13,659,000 209,064,000 1,246,000Production (3,816,000) (35,714,000) (952,000)Sale of reserves (403,000) (1,743,000) (16,000)

Proved reserves as of December 31, 1996 59,951,000 554,661,000 11,695,000Revisions of estimates (1,358,000) (21,124,000) 1,531,000Extensions and discoveries 7,394,000 94,925,000 301,000Purchase of reserves 1,126,000 992,000 16,000Production (6,055,000) (61,015,000) (1,468,000)Sale of reserves (156,000) (615,000) (3,000)

Proved reserves as of December 31, 1997 60,902,000 567,824,000 12,072,000Proved developed reserves as of:

December 31, 1994 18,718,000 324,302,000 3,123,000December 31, 1995 28,703,000 311,664,000 6,149,000December 31, 1996 52,672,000 529,407,000 10,328,000December 31, 1997 53,059,000 462,082,000 11,289,000

NATURALOIL GAS GAS LIQUIDS

CANADA (Bbls) (Mcf) (Bbls)

Proved reserves as of December 31, 1995 — — —Revisions of estimates — — —Extensions and discoveries — — —Purchase of reserves 7,530,000 40,858,000 884,000Production — — —Sale of reserves — — —

Proved reserves as of December 31, 1996 7,530,000 40,858,000 884,000Revisions of estimates (162,000) 3,951,000 83,000Extensions and discoveries 1,123,000 11,683,000 —Purchase of reserves — — —Production (950,000) (8,312,000) (158,000)Sale of reserves — — —

Proved reserves as of December 31, 1997 7,541,000 48,180,000 809,000Proved developed reserves as of:

December 31, 1996 7,530,000 40,858,000 884,000December 31, 1997 7,106,000 44,292,000 809,000

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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The accompanying tables reflect thestandardized measure of discounted future net cash flows relating to Devon’s interest in proved reserves:

TOTAL December 31, 1997 1996 1995

Future cash inflows $ 2,516,923,000 3,989,582,000 1,476,418,000Future costs:

Development (88,292,000) (54,133,000) (52,327,000)Production (866,609,000) (1,071,913,000) (496,279,000)

Future income tax expense (317,064,000) (785,702,000) (153,431,000)

Future net cash flows 1,244,958,000 2,077,834,000 774,381,00010% discount to reflect timing of cash flows (518,105,000) (901,617,000) (328,481,000)

Standardized measure of discounted future net cash flows $ 726,853,000 1,176,217,000 445,900,000

Discounted future net cash flows before income taxes $ 913,073,000 1,621,992,000 534,248,000

DOMESTIC December 31, 1997 1996 1995

Future cash inflows $ 2,304,602,000 3,712,956,000 1,476,418,000Future costs:

Development (83,350,000) (54,064,000) (52,327,000) Production (806,130,000) (1,013,750,000) (496,279,000)

Future income tax expense (269,880,000) (713,182,000) (153,431,000)

Future net cash flows 1,145,242,000 1,931,960,000 774,381,00010% discount to reflect timing of cash flows (481,263,000) (846,174,000) (328,481,000)

Standardized measure of discounted future net cash flows $ 663,979,000 1,085,786,000 445,900,000

Discounted future net cash flows before income taxes $ 820,448,000 1,486,603,000 534,248,000

CANADA December 31, 1997 1996 1995

Future cash inflows $ 212,321,000 276,626,000 —Future costs:

Development (4,942,000) (69,000) — Production (60,479,000) (58,163,000) —

Future income tax expense (47,184,000) (72,520,000) —

Future net cash flows 99,716,000 145,874,000 —10% discount to reflect timing of cash flows (36,842,000) (55,443,000) —

Standardized measure of discounted future net cash flows $ 62,874,000 90,431,000 —

Discounted future net cash flows before income taxes $ 92,625,000 135,389,000 —

Future cash inflows are computed by applyingyear-end prices (averaging $16.93 per barrel of oil,adjusted for transportation and other charges, $1.89 perMcf of gas and $12.42 per barrel of natural gas liquidsat December 31, 1997) to the year-end quantities ofproved reserves, except in those instances where fixedand determinable price changes are provided bycontractual arrangements in existence at year-end. Inaddition to the future gas revenues calculated at $1.89per Mcf, Devon’s total future gas revenues also include

the future tax credit payments to be received andrecorded as gas revenues pursuant to the San JuanBasin Transaction described in Note 3. Devon’s futuretotal and domestic cash inflows shown in the tablesabove include $35.2 million related to these tax creditpayments from 1998 through 2002. This amount hasbeen calculated using the assumption that the year-end1997 tax credit rate of $1.05 per MMBtu remainsconstant.

Future development and production costs arecomputed by estimating the expenditures to be incurredin developing and producing proved oil and gasreserves at the end of the year, based on year-end costsand assuming continuation of existing economic condi-tions. Future income tax expenses are computed byapplying the appropriate statutory tax rates to thefuture pretax net cash flows relating to proved reserves,net of the tax basis of the properties involved. The

future income tax expenses give effect to permanentdifferences and tax credits, but do not reflect theimpact of future operations.

CHANGES RELATING TO THE STANDARDIZED

MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

Principal changes in the standardized measure ofdiscounted future net cash flows attributable to Devon’sproved reserves are as follows:

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TOTAL Year Ended December 31, 1997 1996 1995

Beginning balance $ 1,176,217,000 445,900,000 358,206,000Sales of oil, gas and natural gas liquids, net of production costs (222,169,000) (120,332,000) (78,304,000)Net changes in prices and production costs (723,385,000) 519,456,000 60,498,000Extensions, discoveries, and improved recovery, net of future

development costs 52,566,000 42,522,000 22,308,000 Purchase of reserves, net of future development costs 7,696,000 576,234,000 50,000,000Development costs incurred during the period which

reduced future development costs 27,883,000 44,332,000 43,810,000 Revisions of quantity estimates (10,044,000) 40,905,000 7,397,000Sales of reserves in place (1,395,000) (6,499,000) (7,933,000)Accretion of discount 162,199,000 53,425,000 39,821,000 Net change in income taxes 259,555,000 (357,427,000) (48,347,000)Other, primarily changes in timing (2,270,000) (62,299,000) (1,556,000)Ending balance $ 726,853,000 1,176,217,000 445,900,000

SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (Unaudited)

Following is a summary of the unaudited interim results of operations for the years endedDecember 31, 1997 and 1996:

FIRST SECOND THIRD FOURTH FULL1997 QUARTER QUARTER QUARTER QUARTER YEAR

Oil, gas and natural gas liquids sales $ 86,572,042 67,759,826 70,517,534 80,898,733 305,748,135Total revenues $ 87,899,646 69,651,782 72,860,503 82,727,937 313,139,868Net earnings $ 25,225,546 14,829,990 16,305,960 18,930,033 75,291,529Net earnings per share:

Basic $ 0.78 0.46 0.51 0.59 2.34Diluted $ 0.71 0.44 0.47 0.54 2.17

FIRST SECOND THIRD FOURTH FULL1996 QUARTER QUARTER QUARTER QUARTER YEAR

Oil, gas and natural gas liquids sales $ 33,734,229 36,743,221 39,007,410 53,073,462 162,558,322Total revenues $ 34,048,060 37,298,613 39,473,680 53,196,531 164,016,884Net earnings $ 5,553,926 6,775,388 7,707,673 14,763,545 34,800,532Net earnings per share:

Basic $ 0.25 0.31 0.35 0.66 1.57Diluted $ 0.25 0.30 0.34 0.59 1.52

The above amounts for diluted net earnings per share for the second and third quarters of 1996 have beenrestated from the amounts previously reported as “net earnings per share assuming full dilution” due to the adoptionof SFAS No. 128 as discussed in Note 1.

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JOHN W. NICHOLS, 83, a co-founder of Devon,has been chairman of the board of directors sinceDevon began operations in 1971. He is afounding partner of Blackwood & Nichols Co.,which developed the conventional reserves in theNortheast Blanco Unit of the San Juan Basin.Mr. Nichols is a non-practicing certified publicaccountant.

J. LARRY NICHOLS, 55, is a co-founder of Devon.He has been a director since 1971, president since1976 and chief executive officer since 1980. Mr.Nichols serves as a vice president of theIndependent Petroleum Association of America,president of the Domestic Petroleum Council,president-elect of the Natural Gas SupplyAssociation and president-elect of the Oklahoma

Nature Conservancy. In addition, Mr. Nichols is a director of theIndependent Petroleum Association of New Mexico, the OklahomaIndependent Petroleum Association, the National Petroleum Council andthe National Association of Manufacturers. Mr. Nichols serves on theBoard of Governors of the American Stock Exchange. He also serves as adirector of Smedvig asa, and CMI Corporation, New York StockExchange listed companies. Mr. Nichols holds a geology degree fromPrinceton University and a law degree from the University of Michigan.He served as a law clerk to Mr. Chief Justice Earl Warren and Mr. JusticeTom Clark of the U.S. Supreme Court. Mr. Nichols is a member of theOklahoma Bar Association.

LUKE R. CORBETT, 50, was elected to the board of directors in 1996. Mr. Corbett is chairman of the board and chief executive officer of Kerr-McGee Corporation. He joined Kerr-McGee in1985 and held various executive positions prior to being elected to his present position in 1997.He is a director of OGE Energy Corporation and the American Petroleum Institute. He is a

member of the American Association of Petroleum Geologists, the Societyof Exploration Geophysicists, and the Domestic Petroleum Council.He is also a trustee for the American Geological Institute Foundation.Mr. Corbett holds a bachelor’s degree in mathematics from the Universityof Georgia.

THOMAS F. FERGUSON, 61, has been a director ofDevon since 1982, and is the chair of the AuditCommittee. He is managing director ofEnglewood, N.V., a wholly owned subsidiary ofKuwait-based Al-Futtooh Investments WLL.Mr. Ferguson represents them on the board ofdirectors of various companies including BalticTransit Bank in Latvia and Tunis International

Bank in Tunisia. Mr. Ferguson is a Canadian qualified Certified GeneralAccountant and was formerly employed by the Economist IntelligenceUnit of London as a financial consultant.

DAVID M. GAVRIN, 63, has been a director ofDevon since 1979, and serves as the chair of theCompensation and Stock Option Committee.He serves as a director of Arcadis, N.V., aworldwide infrastructure and environmentalservices company; and United American EnergyCorp., an independent power producer. Inaddition, Mr. Gavrin was associated with Drexel

Burnham Lambert Incorporated for 14 years as first vice president, and hewas a general partner of Windcrest Partners, an investment partnership,for 10 years.

MICHAEL E. GELLERT, 66, has been a director ofDevon since 1971 and is a member of theCompensation and Stock Option Committee. Mr.Gellert is a general partner of Windcrest Partners.He serves as a director of Humana, Inc., PremierParks, Inc., Seacor Smit, Inc., Regal Cinemas, Inc.and numerous private companies. Mr. Gellert isalso a member of the Putnam Trust Company

Advisory Board to The Bank of New York. He was associated with theDrexel Burnham Lambert Group and its predecessors for 31 years,including 17 years as a director.

TOM J. MCDANIEL, 59, was elected to the boardof directors in 1996. Mr. McDaniel has beenKerr-McGee’s vice chairman of the board sinceFebruary 1, 1997. He served as senior vicepresident and corporate secretary of Kerr-McGeesince 1989. He joined Kerr-McGee as associategeneral counsel in 1984. Mr. McDaniel serves asa director of the National Association of Manu-

facturers and UMB Oklahoma Bank. A member of the Oklahoma andAmerican Bar Associations, Mr. McDaniel holds degrees from NorthwesternOklahoma State University and the University of Oklahoma.

H. R. SANDERS, JR., 65, has been a director ofDevon since 1981. In May 1997, Mr. Sandersretired as executive vice president of Devon afterserving for 16 years. Mr. Sanders was previouslyassociated with Republic Bank Dallas, N.A.,serving as its senior vice president withresponsibility for independent oil and gasproducer and mining loans. Mr. Sanders is a

member of the Independent Petroleum Association of America, TexasIndependent Producers and Royalty Owners Association and theOklahoma Independent Petroleum Association.

LAWRENCE H. TOWELL, 54, was elected to theboard of directors in 1996. Mr. Towell has, since1984, been vice president of acquisitions in Kerr-McGee’s Strategic Planning/BusinessDevelopment Division. He has served Kerr-McGee in various executive positions since 1975.Mr. Towell holds a bachelor’s degree inmechanical engineering from Yale University. He

is a member of the Society of Petroleum Engineers, the IndependentPetroleum Association of America, and the Yale University Science andEngineering Association.

B O A R D O F D I R E C T O R S

J. MICHAEL LACEY, 52, joined Devon as vicepresident of operations and exploration in 1989.Prior to his employment with Devon, Mr. Laceyserved as general manager in Tenneco OilCompany’s Mid-Continent and Rocky MountainDivisions. He holds both undergraduate andgraduate degrees in petroleum engineering fromthe Colorado School of Mines. Mr. Lacey is a

registered professional engineer, and he is a member of the Society ofPetroleum Engineers and the American Association of PetroleumGeologists.

DUKE R. LIGON, 56, joined Devon as vicepresident - general counsel in 1997. He practicedenergy law for 12 years, most recently as apartner of the New York City law firm, Mayer,Brown & Platt. In addition, he was aninvestment banker at Bankers Trust Company ofNew York for 10 years. Mr. Ligon also served forthree years in various positions with the Federal

Energy Administration, U. S. Department of the Interior andDepartment of Energy. Mr. Ligon’s primary responsibilities includeassisting the company in its acquisition efforts and representing Devon invarious legal matters including litigation. Mr. Ligon holds anundergraduate degree in business from Westminster College and a lawdegree from University of Texas School of Law.

DARRYL G. SMETTE, 50, vice president ofmarketing and administrative planning since1989, joined Devon in 1986 as manager of gasmarketing. Mr. Smette’s educational backgroundincludes an undergraduate degree from MinotState College and a master’s degree fromWichita State University. His marketingbackground includes 15 years with Energy

Reserves Group, Inc./BHP Petroleum (Americas), Inc., the last positionbeing director of marketing. He is also an oil and gas industry instructor,approved by the University of Texas Department of ContinuingEducation. Mr. Smette is a member of the Oklahoma IndependentProducers Association, Natural Gas Association of Oklahoma, and theAmerican Gas Association.

H. ALLEN TURNER, 45, vice president ofcorporate development, has been responsible forDevon’s corporate finance and capital formationactivities since 1982. In 1981, he served asexecutive vice president of Palo Pinto/HarkenDrilling Programs. For the six prior years, he wasassociated with Merrill Lynch with variousresponsibilities including regional tax investments

manager. He is a member of the Petroleum Investor RelationsAssociation and serves on the Independent Petroleum Association ofAmerica (IPAA) Capital Markets Committee. He is past chairman ofthe IPAA Oil and Gas Investment Symposium. Mr. Turner received hisbachelor’s degree from Duke University.

WILLIAM T. VAUGHN, 51, is Devon’s vicepresident of finance in charge of commercialbanking functions, accounting, tax andinformation services. Mr. Vaughn was elected in1987 to his present position. Prior to that, hewas controller of Devon from 1983 to 1987. Mr.Vaughn’s prior experience includes serving ascontroller with Marion Corporation for two

years and employment with Arthur Young & Co. for seven years withvarious duties including audit manager. He is a certified publicaccountant, and he is a member of the American Institute of CertifiedPublic Accountants and the Oklahoma Society of Certified PublicAccountants. Mr. Vaughn is a graduate of the University of Arkansaswith a bachelor of science degree.

DANNY J. HEATLY, 42, has been Devon’scontroller since 1989. Prior to joining Devon,Mr. Heatly was associated with Peat MarwickMain and Co. in Oklahoma City for 10 yearswith various duties including senior auditmanager. He is a certified public accountant, andis a member of the American Institute ofCertified Public Accountants and the Oklahoma

Society of Certified Public Accountants. Mr. Heatly graduated with abachelor of accountancy degree from the University of Oklahoma.

GARY L. MCGEE, 48, was elected treasurer in1983, having first served as Devon’s controller.He is an executive committee member of theRocky Mountain Oil & Gas Association, thePetroleum Association of Wyoming and theMid-continent Oil & Gas Association ofOklahoma. He served as vice president offinance with KSA Industries, Inc., a private

holding company with diverse interests including oil and gas production.Mr. McGee also held various accounting positions with AdamsResources and Energy Co. and Mesa Petroleum Company. He receivedhis accounting degree from the University of Oklahoma.

MARIAN J. MOON, 47, was elected corporatesecretary in 1994. Ms. Moon has served Devonin various capacities since 1984, including hercurrent position as manager of corporate finance.She previously served as assistant secretary withresponsibilities including compliance with SECand stock exchange regulations. Prior to joiningDevon, Ms. Moon was employed for 11 years by

Amarex, Inc., an Oklahoma City based oil and gas production andexploration firm, where she most recently served as treasurer. Ms. Moonis a member of the Petroleum Investor Relations Association and theAmerican Society of Corporate Secretaries. She is a graduate ofValparaiso University.

C O R P O R AT E O F F I C E R S

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Blowdown: The production and sale ofnatural gas following the termination of gasinjection. Gas is often injected into an oil-producing formation to maintain pressure inthe reservoir and to increase oil recovery.

British thermal unit (Btu): A measure ofheat value. An Mcf of natural gas is roughlyequal to one million Btu.

Development well: A well drilled withinthe area of an oil or gas reservoir known tobe productive. Development wells arerelatively low risk.

Exploratory well: A well drilled in anunproved area, either to find a new oil or gasreservoir or to extend a known reservoir.Sometimes referred to as a wildcat.

Field: A geographical area under which oneor more oil or gas reservoirs lie.

Formation: An identifiable layer of rocksnamed after its geographical location anddominant rock type.

Gross acres: The total number of acres inwhich one owns a working interest.

Increased density/infill: A well drilled inaddition to the number of wells permittedunder initial spacing regulations, used toenhance or accelerate recovery, or preventthe loss of proved reserves.

Independent producer: A non-integratedoil and gas producer with no refining orretail marketing operations.

Lease: A legal contract that specifies theterms of the business relationship betweenan energy company and a landowner ormineral rights holder on a particular tract.

Natural gas liquids (NGLs): Liquidhydrocarbons that are extracted andseparated from the natural gas stream.NGLs products include ethane, propane,butane and natural gasoline.

Net acres: Gross acres multiplied by one’sfractional working interest in the property.

Production: Natural resources, such as oil orgas, taken out of the ground.- Gross production: Total production beforededucting royalties.- Net production: Gross production, minusroyalties, multiplied by one’s fractionalworking interest.

Prospect: An area designated for thepotential drilling of development orexploratory wells.

Proved reserves: Estimates of oil, gas, andgas liquids quantities thought to berecoverable from known reservoirs underexisting economic and operating conditions.

Recavitate: The process of applying pressuresurges on the coal formation at the bottomof a well in order to increase fracturing,enlarge the bottomhole cavity and therebyincrease gas production.

Recompletion: The modification of anexisting well for the purpose of producing oilor gas from a different producing formation.

Reservoir: A rock formation or trapcontaining oil and/or natural gas.

SEC Case: The method for calculatingfuture net revenues from proved reserves asestablished by the Securities and ExchangeCommission (SEC). Future oil and gasrevenues are estimated using essentially fixedor unescalated prices. Future production anddevelopment costs also are unescalated andare subtracted from future revenues.

SEC @ 10% or SEC 10% present value:The future net revenue anticipated fromproved reserves using the SEC Case,discounted at 10%.

Section 29 tax credit: A tax creditprescribed by Section 29 of the InternalRevenue Code. The credit is available forcertain types of gas production from a non-conventional source, such as coal deposits.The credit for 1997 was about $1.05 permillion Btu, and is adjusted for inflation.

Three-dimensional seismic (3-D seismic):Technology to create three-dimensionalimages created by bouncing sound waves offof underground rock formations. Used tolook for underground accumulations of oiland gas.

Undeveloped acreage: Lease acreage onwhich wells have not been drilled orcompleted to a point that would permit theproduction of commercial quantities of oilor gas.

Unit: A contiguous parcel of land deemed tocover one or more common reservoirs for oilor natural gas, as determined by state orfederal regulations. Unit interest ownersgenerally share in costs and revenuesaccording to their proportion of ownershipin the unit.

Waterflood: A method of increasing oilrecoveries from an existing reservoir. Wateris injected through a special “water injectionwell” into an oil producing formation toforce additional oil out of the reservoir rockand into nearby oil wells.

Working interest: The cost-bearingownership share of an oil or gas lease.

VOLUME ACRONYMS

Bbl: A standard oil measurement that equalsone barrel (42 U.S. gallons).- MBbl: One thousand barrels.- MMBbl: Million barrels.

Mcf: A standard measurement unit forvolumes of natural gas that equals onethousand cubic feet.- MMcf: Million cubic feet- Bcf: Billion cubic feet

Boe: A method of equating oil, natural gasliquids and natural gas. Natural gas isconverted to oil based on its relative energycontent at the rate of six Mcf of gas to onebarrel of oil. Natural gas liquids areconverted based upon volume: one barrel ofnatural gas liquids equals one barrel of oil.- MBoe: Thousand barrels of oil equivalent- MMBoe: Million barrels of oil equivalent

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To Our Friends and Shareholders

C O M M O N S T O C K T R A D I N G D ATA

QUARTER HIGH LOW LAST VOLUME DIVIDENDS

1996

First 25 3⁄4 19 7⁄8 23 1⁄2 2,825,300 $.03Second 26 1⁄8 22 3⁄4 24 1⁄2 2,473,900 $.03Third 27 1⁄2 22 3⁄4 25 1⁄2 4,715,400 $.03Fourth 36 7⁄8 25 1⁄4 34 3⁄4 6,010,800 $.05

1997

First 38 7⁄8 29 1⁄2 30 3⁄4 4,457,800 $.05Second 38 1⁄2 27 3⁄8 36 3⁄4 5,619,200 $.05Third 45 1⁄4 36 1⁄8 44 3⁄4 3,851,150 $.05Fourth 49 1⁄8 35 3⁄4 38 1⁄2 4,460,400 $.05

I N V E S T O R I N F O R M AT I O N

CORPORATE HEADQUARTERS

Devon Energy Corporation20 North Broadway, Suite 1500Oklahoma City, OK 73102-8260Telephone: (405) 235-3611Fax: (405) 552-4667

ANNUAL MEETING

Our annual stockholders’ meetingwill be held at 11:00 a.m., centraltime, on Wednesday, May 20,1998, at the Bank of Oklahoma,Robinson Avenue at Robert S.Kerr, Oklahoma City, Oklahoma.

SHAREHOLDER ASSISTANCE

For information about stock trans-fer, address changes, dividends,account consolidation, multiplemailings, registration changes, loststock certificates and Form 1099:

Boston EquiServeClient Administration,Mail Stop 45-02-62P.O. Box 1865Boston, MA 02105-1865

Toll Free: 1-800-733-5001World Wide Web:http://www.equiserve.com

INVESTOR RELATIONS CONTACTS

Analysts and Media:Vince White, Director of Investor RelationsTelephone: (405) 235-3611E-mail: whitev@dvn.com

Individuals and Brokers:Michael PrinceTelephone: (405) 552-4526E-mail: princem@dvn.com

Publications:A copy of Devon’s Annual Reportto the Securities and ExchangeCommission (Form 10-K) andother publications are available atno charge upon request. Directrequests to:

Ms. Pat DouglasTelephone: (405) 552-4506Fax: (405) 552-4667E-mail: douglasp@dvn.com

INDEPENDENT AUDITORS

KPMG Peat Marwick LLP,Oklahoma City, Oklahoma

STOCK TRADING DATA

Devon Energy Corporation’s com-mon stock is traded on theAmerican Stock Exchange underthe symbol DVN. As of February24, 1998, there were 859 commonstockholders of record.

DEVON’S WEBSITE

To learn more about DevonEnergy, visit our website at:http://www.devonenergy.com.Devon’s website contains pressreleases, SEC filings, commonlyasked questions, stock quote infor-mation and more.

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D E V O N E N E R G Y C O R P O R AT I O N20 North Broadway, Suite 1500

Oklahoma City, Oklahoma 73102-8260Telephone (405) 235-3611

Fax (405) 552-4667