devon 1996 annual report

SPIRITDEVON

ENERGY CORPORATION’S

OF CREATIVITY

1 9 9 6 A N N U A L R E P O R T

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, Texas,

Oklahoma, Wyoming, and Alberta, Canada.

We strive to build value per share by:

PURCHASING PRODUCING OILAND GAS PROPERTIES,

EXPLORING FOR UNDISCOVERED OIL AND GAS RESERVES, and

OPTIMIZING PRODUCTION FROM OUR OIL AND GAS PROPERTIES.

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ON THE COVER

This photograph provides an unusual perspective on an ordinary object-a fluid storage tank. Devon finds unique opportunities by creatively viewing

its everyday business from unusual perspectives.

Contents

25 Financial Statements andManagement’s Discussion and Analysis

Board of Directors 64

65 Corporate Officers

Glossary 66

67 Investor Information andCommon Stock Trading Data

1D E V O N E N E R G Y C O R P O R AT I O N

11Pushingthe Envelope

7Outside the Box2Letter to Shareholders

4 Five-Year Highlights

Focus on Operations 1915

A DifferentPoint of View

2 D E V O N E N E R G Y C O R P O R A T I O N

evon Energy Corporation's

1996 will undoubtedly be

remembered as one of extra-

ordinary achievement.

Consider the following:

◆ Net earnings were $34.8

million, or $1.57 per

common share, up 140 per-

cent from 1995.

◆ Cash margins (revenues less cash expenses) climbed 62

percent to $96.0 million.

◆ Revenues were up 45 per-

cent to $164.0 million.

◆ Oil and natural gas pro-

duction grew to 10.7

million barrels of oil equiva-

lent, setting a new record

for the ninth year in a row.

◆ Estimated proven oil and

gas reserves reached 179

million barrels of oil equiva-

lent—also our ninth

consecutive record.

◆ We enhanced Devon's

financial flexibility by issuing $149.5 million of 6.5% Trust

Convertible Preferred Securities.

◆ Two nationally recognized credit rating agencies, Duff &

Phelps and Standard & Poor's, joined our commercial

banks in rating Devon as an "investment-grade" company.

◆ Mergers and acquisitions boosted reserves by some 65

million barrels of oil equivalent.

◆ We drilled 194 oil and gas wells, 190 of which were

successful.

◆ Through mergers, acquisitions and drilling, Devon

replaced more than 700 percent of the year's production.

◆ Quarterly dividends were increased to five cents per

common share. This represents a 66 percent increase over

the three-cent amount previously paid.

None of these accomplishments would have been

possible without creativity.

Many of our achievements were attained because we

approach problem solving from a different viewpoint than

many of our competitors. Inspired by the innovative pio-

neers who molded our industry, Devon recognizes that

unique opportunities can be created in our day-to-day busi-

ness. During 1996, for example, much of Devon's growth

in oil and gas reserves resulted from an innovative and

unique transaction with Kerr-McGee Corporation.

On December 31, 1996,

we merged Kerr-McGee's

North American onshore oil

and gas exploration and pro-

duction businesses into Devon

in exchange for 9.95 million

shares of Devon common

stock. Through the merger,

Kerr-McGee became a 31 per-

cent shareholder of Devon.

This allows Kerr-McGee to

maintain an investment in the

onshore oil and gas business in

North America. At the same

time, it eliminates the burden of the overhead, the direct

expenses and the capital requirements of those activities.

Devon, on the other hand, increased its proved reserves by

about 50 percent and strengthened core operating areas.

This provides additional economies of scale and increased

marketing leverage in our core areas. We also tripled our

inventory of undeveloped acreage—primarily in areas where

we already operate. Additionally, the transaction provides

Devon with critical mass in a new core area, western

Canada. Overall, greater operational efficiencies are now

possible than were ever feasible under separate ownership.

While the benefits of this merger are obvious, the

transaction is nonetheless unique. It requires the mutual

trust of the two companies. Kerr-McGee must trust Devon

DFellow Shareholders

D E A R

Inspired by the innovative pioneerswho molded ourindustry, Devon

recognizes that uniqueopportunities can be

created in our day-to-day business.

D E V O N E N E R G Y C O R P O R A T I O N 3

with the stewardship of a significant group of properties.

And Devon must trust Kerr-McGee, a large and powerful

company, with a very significant ownership position in

Devon's common stock. This mutual trust should result in

rewards for the shareholders of both companies.

In conjunction with the Kerr-McGee transaction,

Luke R. Corbett, Tom J. McDaniel and Lawrence H.

Towell became new members of Devon's Board of

Directors. This increases the size of Devon's Board to nine

members. Each of the three gentlemen is an officer or

director of Kerr-McGee or its subsidiaries. More impor-

tantly, these three directors bring a wealth of oil and gas

experience to our board.

In 1997, we will continue to expand Devon's asset

base by investing some $120 million in exploration and

development projects. A portion of this will be used to con-

tinue pursuing the drilling activities that we began in 1996.

Further, we expect to begin new development of the former

Kerr-McGee assets. We believe this activity will add incre-

mental value to these properties.

Although Devon completed

more than $250 million in mergers

and acquisitions during 1996, we

now have more liquidity than ever

before. As a company capitalized at

more than a billion dollars with

virtually no debt, we are positioned

to aggressively continue our

growth.

Devon has come a long way since its founding some

25 years ago. Yet, the essence of this company is the very

same as it was when we started. We are optimistic about

our future, creative in our problem solving, resourceful in

optimizing our opportunities, and, above all else, honest in

our dealings with everyone.

J. LARRY NICHOLS

President and Chief Executive Officer

Oklahoma City, Oklahoma

March 31, 1997

J. LARRY NICHOLS

91 92 93 94 95 96

30

72

99 101113

164

Devon has increased total oil andgas reserves by almost 400% over

the last five years...

91 92 93 94 95 96

36

6178

106115

179

Total Revenues($ Millions)

Proved Oil and Gas Reserves(MMBoe)

...resulting in 1996 revenuesof more than five times

those of 1991.

Higher oil and gas productionand prices led to record cash

margins in 1996...

91 92 93 94 95 96

* Revenues less cash expenses.

12

38

53 5559

96

Cash Margin *($ Millions)

-15.0

14.6

20.5

13.7 14.5

34.8

Net Income($ Millions)

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...and the highest net earningsin the company’s history.

91 92 93 94 95 96


Five-Year Highlights

LASTYEAR

Year Ended December 31, 1992 1993 1994 1995 1996 CHANGE

FINANCIAL DATA (Thousands, except per share data)

Total Revenues $ 71,564 98,757 100,773 113,303 164,017 45%Cash Expenses $ 33,424 45,864 45,699 54,086 68,066 26%

Cash Margin $ 38,140 52,893 55,074 59,217 95,951 62%

Non-cash Expenses $ 23,525 33,707 41,329 44,715 61,150 37%Unusual Gain(1) $ - 1,300 - - - NM

Net Earnings $ 14,615 20,486 13,745 14,502 34,801 140%

Net Earnings per Share:Assuming No Dilution $ 0.94 0.98 0.64 0.66 1.57 138%Assuming Full Dilution $ 0.90 0.98 0.64 0.66 1.52 130%

Cash Dividends: Per Preferred Share $ 1.46 - - - - NMPer Common Share $ - 0.09 0.12 0.12 0.14 17%

Total Assets $ 225,972 285,553 351,448 421,564 746,251 77%Working Capital $ 12,630 15,140 8,305 9,316 19,734 112%Trust Convertible Preferred Securities(2) $ - - - - 149,500 NMLong-term Debt $ 54,450 80,000 98,000 143,000 8,000 -94%

PROPERTY DATAProduction

Oil and Natural Gas Liquids (MBbls) 1,558 2,748 2,968 3,900 4,768 22%Gas (MMcf) 28,374 35,598 39,335 36,886 35,714 -3%Total (MBoe) 6,287 8,681 9,524 10,047 10,720 7%

ReservesOil and Natural Gas Liquids (MBbls) 17,360 16,751 47,607 53,935 80,060 48%Gas (MMcf) 263,598 369,254 347,560 363,846 595,519 64%Total (MBoe) 61,294 78,293 105,534 114,576 179,313 57%SEC @ 10% Present Value (Thousands)(3) $ 314,566 380,471 398,206 534,248 1,621,992 204%

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

Survey stakes used to plotthe paths of gas lines atDevon’s Northeast BlancoUnit. In 1996, we initiateda major expansion of thisgas-gathering system.

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91 92 93 94 95 96

3.1

6.3

8.79.5

10.010.7

Oil and Gas Production (MMBoe)

Total Assets ($ Millions)

Devon set its ninth consec-utive record for oil and gas

production in 1996...

Earnings Per Share ($)

-1.99

.94.98

.64 .66

1.57–

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–

–

–

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–

...and earnings per sharereached a new high.

91 92 93 94 95 96

Over the last five years,Devon increased total assets

more than seven-fold.

91 92 93 94 95 96

102

226286

351

422

746

Outside

We often find long-term value bylooking beyond short-term trends.

The philosophy of leaving thepack and going our own directionhas contributed substantially toDevon's merger and acquisitionsuccesses. During the past nineyears, we have completed 16

major transactions.

theBOX


Tank containingfresh water usedby a drilling rig at awell location.

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DEVON’S SPIRIT of CREATIVITY

First, some equate acquisitions with cash-market auc-tions. In those situations, the highest bidder wins theauction, yet also accepts the lowest rate of return. Devonbelieves this type of acquisition stifles profitability. Becauseour acquisition objective is to maximize profitability,Devon rarely goes to auctions.

Second is the notion that it is impossible to completea value-adding transaction when commodity prices arehigh. This year, we proved quite the opposite.

1996 Merger Boosts Reserves, Creates Opportunities

In the midst of 1996's high oil and gas prices, weconsummated a very significant merger. We exchanged 9.95million newly issued Devon common shares for all of Kerr-McGee's North American onshore oil and gas explorationand production business and properties. The transactioninvolved about 62 million barrels of oil equivalent reservesand 370,000 net undeveloped acres of leasehold and min-eral interests. How significant are those numbers? Themerger increased our oil and gas reserves by almost 50 per-cent. It also tripled our undevelopedproperty inventory. NOTE: Thisrather dramatic growthwas achievedwithout goingto an auc-tion.

Combining the merger properties into our opera-tions should result in substantial economies of scale,marketing synergy and increased drilling opportunities. Wegreatly enhanced our position in three of the areas in whichwe already owned significant interests—the Permian Basin,the Rocky Mountain Region and the Mid-Continent—pluswe stepped into a new growth area, the Western CanadaSedimentary Basin. We plan to strengthen our Canadianoperations in the future through both acquisitions andexploration.

Devon also gained approximately 100 experiencedemployees from Kerr-McGee as a result of the transaction.This affords us the opportunity to blend the best practicesof two successful corporations and makes Devon evenstronger than before.

Cash Purchase Completes Worland Unit Ownership

In 1992, Devon purchased a 6 percent interest in theWorland Unit located in central Wyoming. Three yearslater, the company gained critical mass in the Rocky

Mountain Region when we purchasedthe dominant interest in the

Unit for $50.3 mil-lion. In 1996,

Devonacquired


There are two misconceptions about acquisitions that generally confuse investors.

another $7 million ofinterests, bringing ourworking interest in thedeveloped portions ofthe property to 98 per-cent. Devon's interest inthe 14,000-plus undevel-oped acres and gas plantnow totals 100 percent. TheWorland Unit should contributeto Devon's total production effortswell into the next century.

Property Sales Share Importance Of Acquisitions

While acquisitions typically are the headline grab-bers, we consistently sell almost as many well bores as wepurchase. Since 1988, the company has sold approximately5,800 wells. When do we sell? Anytime a property limitsgrowth opportunities. For example, we sold our WestVirginia assets during 1996. Although these properties werestill profitable, Devon's growth dwarfed their impact on thecompany's operations as a whole. Devoting time to man-aging assets that cannot make a significant contribution tooverall results inhibits a company's potential for futuregrowth.

Defined Criteria Drive

Acquisition Success

Devon's growth overthe past decade underscoresthe importance of ouracquisition criteria. We are

not interested in simplybuilding mass. Each purchase

we make must provide an incre-mental return for Devon

shareholders. In order to fit Devon'sgrowth strategy, acquisitions must directly

contribute to per-share results. We prefer long-lived reserves in familiar areas. We value properties withsignificant exploration or development opportunities. Andthey must be available at attractive terms that will allow thecompany to retain sufficient liquidity and financial flexi-bility. Are Devon’s acquisition criteria too stringent? Quitethe opposite. They force us to be creative and seek out themost lucrative transactions. ■


ALTERNATIVE THINKINGWooden barrels loaded on wagons or boats

provided oil transportation in the 1800s. From this

inauspicious beginning, the barrel quickly became the

standard mode of transportation and the standard

volume measurement. Samuel Van Syckle was not con-

tent with the old way of doing things. He gave birth to

the idea of moving oil through underground pipes.

The innovative thinker was ridiculed, but he pushed

ahead and opened a 5-mile long pipeline in 1865. This

proved to be a profitable venture. Syckle's creative

spirit laid a foundation for the pipelines that now

crisscross the developed world.

Devon has consistentlyacquired oil and gas reservesat costs below industry norms.

Finding Costs from Acquisitions($/Boe)

Reserve Replacement from All Sources (%)

Our 710% reserve replacement ratioin 1996, marked the ninth consecu-tive year that ratio exceeded 200%.

SOURCE: Jeffries & Company, Inc.“Finding Cost and Economic

Efficiency Study.”

SOURCE: Jeffries & Company, Inc.“Finding Cost and Economic

Efficiency Study.”

DEVON

GROUP AVERAGE

95 92-95 96

3.06

4.06

3.263.07

4.19

DEVON

GROUP AVERAGE

95 92-95 96

208213

349

710

209

91 92 93 94 95 96

Proved Oil and Gas Reserves(MMBoe)

Mergers and Acquisitions($ Millions)

91 92 93 94 95 96

3

123

5684

52

257

Over the last six years, Devon hascompleted more than $575 million

in mergers and acquisitions.

In 1996, Devon set its ninth consecutive record for year-end

reserves.

36

6178

106115

179

D E V O N E N E R G Y C O R P O R A T I O N 1 1

PUSHING

THEENVELOPE

The standard solution isnot always the best solu-

tion. Challenging ourpeople to find new

answers to oldquestions is

one of thequalities

that sepa-rates Devon from

the crowd. Creativethinking allows us to arrive

at some very novel conclusions,even in the financial arena.

A valve at theNortheast Blanco Unitassumes a surrealimage in the harshNew Mexico sun.

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1 2 D E V O N E N E R G Y C O R P O R A T I O N

In 1995, the company began investigating methodsto match our debt maturities with our long-term asset base.The standard procedure would have been to arrange 10- to20- year fixed-rate debt. Devon, however, did not want tosimply match debt maturity with asset life. We wanted tomaximize future financial flexibility. Our solution? Wearranged a hybrid device that, short term, eliminated con-ventional debt from our balance sheet. Long term, thedevice will do one of two things: be converted into conven-

tional, perpetual common stock or provide30-year financing at a very low

interest rate.

Transaction Designed To Benefit All Parties Involved

Our new financing tool, trust convertible preferredsecurities (TCP Securities), is structurally complicated butworks to the benefit of all involved. Devon's newly formedaffiliate, Devon Financing Trust, issued $149.5 million of6.5% TCP Securities. The Trust then loaned the proceedsto Devon. We in turn, used those proceeds to substantiallyreduce our outstanding debt. Devon makes interest pay-ments to the Trust. The Trust then uses those payments topay dividends to TCP Security owners.

TCP Securities are difficult for many companies tooffer because only a limited number of investors, perhapsonly 60 or so worldwide, are likely to purchase them.Devon, however, was willing to push the financing enve-lope because of the many benefits to be gained.

How do investors benefit? First, the deviceprovides investors a dividend-yielding

security that pays an annualrate of $3.25 per TCP

Security. At the issue price of$50 per TCP Security, this divi-

dend represents a 6.5 percentindicated yield. Second, since

Devon had no material conventionaldebt upon the offering's completion,

the yield is relatively secure. Third, theinvestors in the TCP Securites partici-

pate in a portion of Devon's futuregrowth. They can convert each of their

TCP Securities into 1.64 shares of Devoncommon stock. The higher the price of

Devon common, the higher the inherent con-version value of the TCP Securities.

How does Devon benefit? TCP Securitiesallow Devon to maintain an important tax

attribute and gain financial flexibility. The interestpayments that Devon makes to the Trust are

deductible for income tax purposes. At a statutory rateof 34 percent, we save 34 cents in income taxes for each

$1.00 paid in interest expense.

Just as it is important to continually boost Devon's oil and gas production,we believe it also is critical to keep our liabilities and expense structure low.


Even more impor-tant to Devon is thefinancial flexibility that wegained. Our debt, with anaverage maturity of less thanfive years, was refinanced withthe issuance of TCP Securities.The TCP Securities do not matureuntil 2026, or never, if they areconverted into common stock beforematurity. With such a long maturity,banks and other lenders view TCPSecurities as equity, not debt. As a result,upon retiring our previously existing bankloans, almost all of Devon's credit lines were available. Webelieve we could access as much $500 million in credit linesif we so desired. Do we currently need additional capital?No. The offering was strategic financing to position Devonfor future opportunities. At Devon, we don't just think interms of drilling the next well. We drill the next well usingthe lowest cost and most flexible capital.

How do current common stockholders benefit? All ofthe benefits that Devon achieves corporately through theTCP Securities are shared by Devon common stockholders.

The offering also has two otherfavorable benefits for ourcommon stockholders.Unlike a conventional debtstructure which allows theholders to have a superiorclaim on Devon’s assets,TCP Security holders,

upon conversion of theirsecurities, have ownership equal to

that of common stockholders. Second, asopposed to conventional common stock offerings, the

TCP Securities offering did not have a negative impact onDevon's stock price.

Devon Earns Investment-Grade Status

In response to Devon's 1996 activity, including theTCP Securities offering and our Kerr-McGee merger,Standard & Poor's and Duff & Phelps assigned Devoninvestment-grade status. The implied senior debt rating ofBBB- identifies Devon as a lower-risk company and willenable us to borrow funds, if needed, at even more attrac-tive rates than in the past. ■

CREATIVE SOLUTIONCable-tool rigs were used in the oil industry's

infancy to punch shallow wells into solid rock

formations. Captain Anthony F. Lucas, however,

believed deeper oil reservoirs could be reached

by using a rotary-style grinding rig developed

for the salt industry. The rotary-style rig turns a

pipe with a drill-bit attached to its end. The tool

grinds a hole rather than of pounding it down

like the cable-tool rig. In 1899, Lucas took the

new tool and drilled the mammoth discovery

known as Spindletop. Captain Lucas' creative

solution transformed the industry. Drilling rigs

today use this rotary design.

91 92 93 94 95 96

Long-Term Debt ($ Millions)

Devon repaid amounts outstandingunder its credit lines with the proceedsfrom the issuance of TCP Securities...

32 54

80 98

143

8

91 92 93 94 95* 96

17

7895

135 126

272

Liquidity ($ Millions)

UNUSED CREDIT LINESWORKING CAPITAL

* Adjusted for an upward revision toDevon’s borrowing base in early 1996.

...and ended 1996 with more liquidity than ever before.

Weather patterns, economicactivity and politics are but a fewof the drivers behind the volatility

and uncertainty of oil and gas prices.Some in our industry view this

volatility as an almost insurmountableobstacle to success. From Devon's point

of view, it is a bridge to opportunity.

DIFFERENT

POINTOFVIEW

A


Tanks store the fluidsused to fracture a Devonwell. Fracture treatmentscreate additional pathsfor the flow of oil and gasthrough the reservoir.

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Oil and gas producers have limited control over the prices theyreceive for their products. Like all producers, Devon's revenues

are impacted by oil and gas prices. However, we take steps toreduce our vulnerability to low product prices. By doing

so, Devon has been able to prosper even when facedwith difficult pricing scenarios.

We balance oil and gas reserves and produc-tion. Because they trade in different markets, oil

and gas prices sometimes move in oppositedirections. Having both products helps insu-

late our earnings and cash flow from priceswings in either commodity.

We balance our exposure to nat-ural gas markets. Supply and demand,and therefore prices, vary from regionto region within North America.Devon has oil and gas property con-centrations in several differentregions. This reduces the impact onthe company when consumer needsdecline in one part of the country.

We build production volumes.Rather than wait for higher oil andgas prices to increase revenues,Devon consistently increases oil andgas production.

We build production quality.Devon looks to buy and develop prop-

erties that are inexpensive to operate.We concentrate our properties to achieve

critical mass—and efficient operations—in each of our core areas. Lower operating

expenses means higher profit margins andgreater stability in cash flow and earnings.

We minimize our marketing costs.Aggregating oil and natural gas supplies for sale is

one of the ways that we cut marketing expenses. Byaggregating volumes, we sell larger quantities to fewer

purchasers. Fewer purchasers means fewer contracts and


Devon mitigates the impact of price volatility.

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lower administrative costs. Aggregating gasfor transportation has the same

effect: fewer contracts, lessadministration, lower costs.

Seeing the Opportunity

Beyond

It is true thatperiods of low oiland gas prices putdownward pres-sure on Devon’srevenues andearnings.However,periods of lowoil and gas pricescan also bringopportunity.When prices fall,

weak and under-capitalized players

are forced to sellquality properties. At

the same time, the likely buyers of such properties—oil andgas producers—are experiencing a reduction in cash flow.They are also experiencing a reduction in risk-capital avail-able, as lenders become more cautious. This is an idealsituation for Devon. With an investment-grade balancesheet and easy access to capital, Devon is poised to takeadvantage of the opportunities that inevitably result.

We maximize financial flexibility. By building ahigh-margin property base and keeping debt levels low,Devon reduces the risk to our lenders. As a result, we havebetter access to capital at lower rates. This allows us toinvest in oil and gas properties when competition is low.

Such was the case in late 1995 and early 1996 whenwe increased our interest in the Worland Unit in Wyoming.Gas prices were depressed in the Rocky Mountain region ofthe United States. As a result, there was little competitiveinterest in the area. Several of the larger players in the areawere already staggering under the weight of their debt.Devon's ready access to capital allowed the company tomove on the opportunity and significantly increase ourWorland gas reserves. ■

STRETCHING THE BOUNDARIESMost people used to believe on-land

drilling was the only way to obtain

oil. T.F. Rowland was among those

who thought otherwise. The creative

thinker proposed that a rig posi-

tioned above water could reach black

gold. In 1869, he was issued a patent

for an ingenious four-legged tower

that would prove his point. Anchored

in shallow water, Rowland’s rig

helped set the stage for a significant

part of today’s oil industry – produc-

tion achieved through offshore

drilling.

...keeping operating expenseslow...

...general and administrativeexpenses low...

...and debt levels low, positionsDevon to prosper—even in

periods of low prices.

91 92 93 94 95 96

GASOIL

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–

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3.1

6.3

8.79.5 10.0 10.7

Balancing oil and gas production...

Oil and Gas Production(MMBoe)

91 92 93 94 95 96

Long-Term Debt perBoe of Reserves

($)

0.90 0.891.02 0.931.25

0.04

91 92 93 94 95 96

2.85 2.93 3.042.57 2.71

2.94

Operating Expense per Boe Produced

($)

91 92 93 94 95 96

1.91

1.04 0.88 0.88 0.84 0.85

General and AdministrativeExpense per Boe Produced

($)

AD E V O N E N E R G Y C O R P O R A T I O N 1 9

Creativity alone does notbuild a company–it alsorequires quality assets.

FOCUS ONOPER TIONS

The “goat’s foot” onthis piece of heavyequipment compactsthe soil, building astable base for adrilling rig.

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1986 1987 1988 1989

ReservesOil and Natural Gas Liquids (MBbls) 3,023 2,286 5,590 4,800Gas (MMcf) 36,026 34,829 98,388 149,761Total (MBoe) (1) 9,027 8,090 21,988 29,760SEC @ 10% Present Value (Thousands) (2) $ 54,092 44,460 88,564 137,274

ProductionOil and Natural Gas Liquids (MBbls) 406 359 568 681Gas (MMcf) 3,930 4,522 5,919 7,776Total (MBoe) (1) 1,061 1,112 1,554 1,977

Average PricesOil and Natural Gas Liquids (Per Bbl) $ 14.96 18.15 14.62 18.15Gas (Per Mcf ) $ 2.25 1.92 1.69 1.79Oil, Gas and Natural Gas Liquids (Per Boe) (1) $ 14.04 13.68 11.76 13.29

Production and Operating Expense per Boe (1) $ 4.74 4.50 5.31 5.99

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


Eleven Year Property Data

–––––––––––

Mid-Continent 21%

Canada 7%

Rocky Mountain 18%

Other 1%

San Juan Basin 27%

Permian Basin 26%

–––––––––––

Rocky Mountain 16% Mid-Continent 3%

Other 1%

Permian Basin 69%

Canada 11%

Gas Reserves by Area(%)

...and 92% of its gas reserves in four coreareas. This concentration facilitates efficientoperations and gives Devon marketing clout.

Oil Reserves by Area(%)

Devon has concentrated 96% of itsoil reserves in three core areas...

Building critical mass in each core area allows Devon to

establish efficient regional operating segments, resulting in

a lower overall cost structure. We benefit from the level of

technical expertise we attain as a result of our experience in

the area. Concentrated production also increases our mar-

keting clout, by allowing us to aggregate and sell large

quantities of oil and gas in each area. It also enables us to

negotiate more favorable terms with service and supply ven-

dors because we have become an important customer with

a high volume of business.

We concentrate our oil and gas reserves and production in coreproducing regions—achieving critical mass in each.

5-YEAR 10-YEARCOMPOUND COMPOUND

1990 1991 1992 1993 1994 1995 1996 GROWTH RATE GROWTH RATE

4,058 3,798 17,360 16,751 47,607 53,935 80,060 84% 39%169,473 191,642 263,598 369,254 347,560 363,846 595,519 25% 32%32,304 35,738 61,294 78,293 105,534 114,576 179,313 38% 35%

162,084 154,745 314,566 380,471 398,206 534,248 1,621,992 60% 41%

545 484 1,558 2,748 2,968 3,900 4,768 58% 28%9,314 15,398 28,374 35,598 39,335 36,886 35,714 18% 25%2,097 3,050 6,287 8,681 9,524 10,047 10,720 29% 26%

22.79 19.49 18.42 15.63 14.48 15.82 19.82 0% 3%1.85 1.24 1.41 1.54 1.43 1.38 1.91 9% -2%

14.12 9.35 10.92 11.27 10.43 11.19 15.16 10% 1%

5.71 3.48 3.66 3.84 3.30 3.40 3.94 3% -2%


Operating Statistics by Core AreaPERMIAN ROCKY SAN JUAN MID- TOTAL

BASIN MOUNTAIN BASIN CONTINENT OTHER U.S. CANADA TOTAL

Producing Wells at Year-end 8,973 864 830 2,230 488 13,385 607 13,992

1996 Production:(1)

Oil (MBbls) 3,335 248 1 121 111 3,816 - 3,816Gas (MMcf) 9,365 2,730 18,172 4,576 871 35,714 - 35,714NGLs (MBbls) 602 259 11 78 2 952 - 952Total (MBoe) 5,498 962 3,041 962 257 10,720 - 10,720

Average Prices:Oil Price ($/Bbl) $ 21.09 19.84 22.25 21.17 20.83 21.00 - 21.00Gas Price ($/Mcf ) $ 2.18 1.48 1.71 2.17 2.99 1.91 - 1.91NGL Price ($/Bbl) $ 14.38 17.35 8.23 13.97 17.87 15.09 - 15.09

Year-End Reserves:Oil (MBbls) 46,557 10,482 7 1,982 923 59,951 7,530 67,481Gas (MMcf) 153,059 105,471 163,027 127,752 5,352 554,661 40,858 595,519NGLs (MBbls) 6,808 4,257 63 538 29 11,695 884 12,579Total (MBoe) 78,876 32,317 27,242 23,812 1,843 164,090 15,223 179,313

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

Before Federal Income Tax $ 662,892 302,704 276,343 224,326 20,338 1,486,603 135,389 1,621,992After Federal Income Tax $ NA NA NA NA NA 1,085,786 90,431 1,176,217

Year-End Leasehold (Net Acres)Producing 161,488 115,545 20,376 184,600 37,331 519,340 75,637 594,977Undeveloped 173,003 120,756 6,916 65,193 49,276 415,144 75,262 490,406

Wells Drilled During 1996 176 4 - 12 2 194 - 194

1996 Exploration & Development (1)

Expenditures ($ millions) $ 56.5 13.1 0.7 2.1 3.8 76.2 - 76.2Estimated 1997 Capital Expenditures ($ millions) $ 64-71 19-22 3 6-8 18-21 110-125 10 120-135

(1) 1996 production and exploration & development amounts do not include the Kerr-McGee transaction as it occurred on December 31, 1996.

(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.

2 3

Grayburg-Jackson Field

West Red Lake Area

Ozona and DavidsonRanch Fields

Profile Activity to

◆ Initially obtained a 98% working interest in 1,200 acres and 50% to 100% interest in 4,300 undeveloped acres in 1992 property acquisition.

◆ Produces oil from the Grayburg and San Andres formations at about 2,500'.

◆ Drilled 82 ◆ Increased◆ Contracted

◆ Initially obtained an interest in over 25,000 acres in 1992 property acquisition. ◆ Acquired a 25% to 100% working interest in over 40,000 additional acres in

December 1996 merger.◆ Produces natural gas from Canyon and Strawn Formations at 6,000' to 10,000'.

◆ Drilled 34

◆ 100% working interest in 8,600 acres in Eddy County, New Mexico. ◆ Purchased in 1994 property acquisition.◆ Produces oil from the Grayburg and San Andres formations at 3,000’ to 4,000'.

◆ Drilled 155◆ Implemen◆ Increased◆ Contracted

Permian Basin

Worland Unit ◆ 98% to 100% working interest in 25,000 acre federal unit in the Bighorn Basin. ◆ 100% interest in gas processing plant on Unit. ◆ Small initial position obtained in 1992 property acquisition. ◆ Consists of three fields and over 13,000 undeveloped acres. ◆ Currently producing from seven separate horizons at depths of 7,100' to 10,900'.

◆ Acquired $◆ Drilled five◆ Deepened◆ Performed◆ Planned a

– Expecte– Will auto

◆ Began upg◆ Planned 3

House Creek Area ◆ 33,700 acres in two federal units in Campbell County, Wyoming. ◆ 45% working interest in 24,000 acre House Creek Unit. ◆ 26% working interest in 9,700 acre North House Creek Unit. ◆ Acquired in December 1996 merger.◆ Produces from the Sussex Sand at a depth of approximately 8,200'. ◆ House Creek Unit is responding to waterflood.

Rocky Mountain Region

Northeast Blanco Unit (NEBU) ◆ 23% working interest in 33,000 acres in the central part of the basin. ◆ Originally developed by Devon in the late 1980's and early 1990's. ◆ Contains 102 producing wells, four water disposal wells, gas and water gathering systems

and an automated production control system.

◆ Recavitate◆ Initiated im

– Will low– Will add

32-9 Unit ◆ 28% working interest in 15,400 acres in the central part of the basin. ◆ Purchased by Devon in 1993.◆ Contains 51 producing wells, water disposal facilities and gas and water gathering systems.

◆ Increased◆ Drilled pre

San Juan Basin

Gift Field ◆ Average 70% working interest in 10,000 acres in northwestern Alberta. ◆ Acquired in December 1996 merger.◆ Produces oil from the Slave Point formation found at about 5,800'.

Pouce Coupe Field ◆ Average 65% interest in 10,000 acres in west central Alberta. ◆ Acquired in December 1996 merger.◆ Produces natural gas from the Halfway formation at 5,500' and the Kiskatinaw

formation at 7,500'.

Western Canada Sedimentary Basin

Panhandle Morrow Play ◆ Average 60% working interest in 60,000 acres. ◆ Several concentrated acreage blocks in Wheeler and Hemphill Counties in the Texas Panhandle.◆ Acquired in December 1996 merger.◆ Produces from the Upper Morrow Chert at 14,000' to 16,000'.

Panhandle West Field ◆ Near 100% working interest in 29,000 acres in Moore and Sherman Counties in Texas Panhandle.

◆ Acquired in December 1996 merger.◆ Produces gas from the Brown Dolomite at about 3,000'.

Mid-Continent Area


ate 1997 Plans

ecutive successful wells including 61 during 1996. uction by some 3,600 barrels of oil equivalent per day. ell sour crude at above-market prices through year 2000.

◆ Drill over 70 additional wells.◆ Initiate pilot waterflood program.

on wells and 3 Strawn wells. ◆ Drill pilot horizontal wells in Strawn Formation. ◆ Evaluate acreage acquired in 1996 and identify locations for future Canyon wells.

s substantially completing infill drilling phase of $60-plus million development project.ll water injection on approximately one-half of project area.uction by some 2,000 barrels of oil equivalent per day. ell sour crude at above-market prices through year 2000.

◆ Implement final phase of water injection program on remainder of field: – Construct second water injection plant. – Install additional 40 miles of water lines. – Convert some 70 wells to injection wells.

million of additional interests in December 1995 and early 1996. wells further developing established reservoirs. existing well to another producing horizon.

kovers or recompletions on 12 existing wells. tiated upgrade of gas processing plant: ncrease plant capacity by about one-third.

e operations and reduce operating expenses. ng field gathering system.eismic survey.

◆ Complete 3-D seismic survey.◆ Drill new wells and recomplete and stimulate additional existing wells. ◆ Install field compressors to increase gas gathering capacity. ◆ Complete gas plant upgrade.

◆ Evaluate potential for infill drilling program. ◆ Optimize waterflood on House Creek Unit.

veral wells to increase production. ements to production facilities: pressure of the gathering system to sustain or increase production levels.compression to lower back-pressure on wells.

◆ Complete improvements to production facilities.◆ Recavitate additional wells.

uction by 16% with mechanical improvements on several wells. e observation well to evaluate infill drilling potential.

◆ Continue to produce at gathering system capacity.

◆ Drill additional Slave Point infill wells.

◆ Acquire and evaluate seismic data to identify additional drilling locations.

◆ Interpret existing 3-D seismic data.◆ Conduct multiple 3-D seismic surveys.◆ Drill exploratory and development wells on several acreage blocks.

◆ Drill numerous horizontal wells to increase production and recoverable reserves.

26 Selected Eleven-Year Financial Data

28 Management’s Discussion and Analysis ofFinancial Condition and Results of Operations

39 Management’s Responsibility for Financial Statements

39 Independent Auditors’ Report

40 Consolidated Balance Sheets

41 Consolidated Statement of Operations

42 Consolidated Statement of Stockholder’ Equity

43 Consolidated Statement of Cash Flows

44 Notes to Consolidated Financial Statements

Financial Statements andManagement’s Discussion and Analysis


1986 1987 1988 1989

OPERATING RESULTS (in thousands, except per share data)

RevenuesOil and Natural Gas Liquids Revenue $ 6,078 6,509 8,302 12,370Gas Revenue 8,846 8,693 9,983 13,906Other Revenue 834 2,098 2,735 2,543

Total $ 15,758 17,300 21,020 28,819

Production and Operating Expenses $ 5,006 5,037 8,255 11,835Depreciation, Depletion and Amortization(1) $ 11,532 7,697 7,429 7,350General and Administrative Expenses $ 4,482 4,056 3,854 6,103Interest Expense $ 1,318 1,141 2,132 2,140Distributions on Trust Convertible Preferred Securities(2) $ - - - -Adjusted Net Earnings (Loss)(3) $ (1,899) (1,066) (565) 876Reported Net Earnings (Loss) $ (3,967) (1,066) 3,347 876Preferred Stock Dividends(4) $ - - - 821Net Earnings (Loss) to Common Shareholders $ (3,967) (1,066) 3,347 55Net Earnings (Loss) per Common Share $ (0.64) (0.17) 0.48 0.01Net Earnings (Loss) per Common Share - Fully Diluted $ (0.64) (0.17) 0.48 0.01Cash Dividends per Common Share $ - - - -

Cash Margin(5) $ 4,952 7,066 6,779 8,696Weighted Average Shares Outstanding 6,165 6,165 6,924 8,595

BALANCE SHEET DATA (in thousands)

Total Assets $ 61,498 60,715 89,116 97,916Long-term Debt $ 14,298 13,453 30,000 9,500Other Long-term Obligations $ 4,710 5,198 6,337 5,071Deferred Income Taxes $ 8,367 8,217 5,480 5,889Trust Convertible Preferred Securities(2) $ - - - -Stockholders’ Equity $ 29,994 28,928 41,557 70,156Common Shares Outstanding 6,165 6,165 8,584 8,608

(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 one-time non-cash charge of $2.1 million in 1986 from the acquisition of an affiliate, 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


5-YEAR 10-YEARGROWTH GROWTH

1990 1991 1992 1993 1994 1995 1996 RATE RATE

12,412 9,436 28,699 42,939 42,994 61,694 94,509 59% 32%17,204 19,091 39,973 54,876 56,372 50,732 68,049 29% 23%

1,302 1,815 2,892 942 1,407 877 1,459 -4% 6%30,918 30,342 71,564 98,757 100,773 113,303 164,017 40% 26%

11,983 10,601 23,030 33,325 31,420 34,121 42,226 32% 24%8,005 32,844 19,894 28,409 34,132 38,090 43,361 6% 14%4,919 5,832 6,510 7,640 8,425 8,419 9,101 9% 7%1,956 2,209 2,644 3,422 5,439 7,051 5,277 19% 15%

- - - - - - 4,753 NM NM2,554 (15,024) 14,615 19,186 13,745 14,502 34,801 NM NM2,554 (15,024) 14,615 20,486 13,745 14,502 34,801 NM NM2,324 2,270 1,703 - - - - NM NM

230 (17,294) 12,912 20,486 13,745 14,502 34,801 NM NM0.03 (1.99) 0.94 0.98 0.64 0.66 1.57 NM NM0.03 (1.99) 0.90 0.98 0.64 0.66 1.52 NM NM

- - - 0.09 0.12 0.12 0.14 NM NM

11,838 11,650 38,140 52,893 55,074 59,217 95,951 52% 35%8,640 8,687 13,802 20,822 21,552 22,074 22,160 21% 14%

123,547 102,107 225,972 285,553 351,448 421,564 746,251 49% 28%28,000 32,000 54,450 80,000 98,000 143,000 8,000 -24% -6%

3,919 3,204 2,635 2,723 2,683 9,512 11,585 29% 9%7,036 908 4,151 8,643 27,340 34,452 81,121 146% 26%

- - - - - - 149,500 NM NM70,767 53,015 153,267 172,900 206,406 219,041 472,404 55% 32%

8,679 8,693 20,733 20,842 22,051 22,112 32,141 30% 18%

OVERVIEWDevon concluded 1996 financially stronger and

larger than at any previous time in the company’s history.Over the last three years our oil and gas reserves have grown129% to 179 million barrels of oil equivalent (“MMBoe”).Our long-term credit lines have increased 63% over the sameperiod, to $260 million. Total assets have increased 161% to$746 million. During the same three years, we reduced ourlong-term debt from $80 million to $8 million and signifi-cantly increased stockholders’ equity.

Our operating performance has also improved by mostmeasures over the last three years. In 1996, oil and gasproduction was 23% over that of 1993, at 10.7 MMBoe.The 1996 production increase coupled with a 35% increasein oil, gas and NGL prices over 1993 levels, led to revenuesand earnings gains. Net earnings for 1996 climbed 70% overthose of 1993, to $34.8 million. Net cash provided by oper-ating activities rose from $46.4 million in 1994 to $61.3million in 1995 and $86.8 million in 1996. The cashmargin1 (total revenues less cash expenses) during these samethree years has increased from $55.1 million in 1994 to$59.2 million in 1995 and $96.0 million in 1996.

This growth in operations was driven primarily by thefollowing events: ◆ We acquired $54 million of coal seam gas properties inthe San Juan Basin in June, 1993. These properties added toDevon’s already significant coal seam gas properties, productionand revenues in the San Juan Basin.◆ We acquired the properties of Alta Energy Corporationthrough a $72 million cash and common stock merger in May1994. The oil and gas properties acquired through the merger(the “Alta Merger Properties”) added substantial oil and gasreserves, production and revenues to our Permian Basin position.◆ We acquired a gas processing plant and additional inter-ests in certain Wyoming oil and natural gas properties (the“Worland Properties”). The acquisition costs were approximately$57 million from December, 1995 through April, 1996.◆ In 1995, we entered into a transaction covering substan-tially all of our San Juan Basin coal seam gas properties (the“San Juan Basin Transaction”). This transaction added approxi-mately $10 million to our annual revenues.

◆ On December 31, 1996, we acquired all of Kerr-McGeeCorporation’s North American onshore oil and gas explorationand production business and properties (the “KMG-NAOS Prop-erties”) in exchange for 9,954,000 shares of Devon commonstock. This transaction added approximately 62 million Boe toour year-end 1996 proved reserves (an increase of over 50%), aswell as 370,000 net undeveloped acres of leasehold.◆ We have been successful during the last three years in ourdrilling efforts. Devon has spent approximately $171 million todrill 476 wells, of which 462 were completed as producers.

The following actions during the last three yearsimproved Devon’s liquidity and financial resources whilereducing its bank debt:◆ The issuance of $22 million of additional common equitycapital in 1994 for the 1994 Alta Merger.◆ Our production and revenue gains have given us asubstantially larger cash flow and, thus, capital budget.◆ Our acquisition and drilling efforts during the last threeyears have added 126.5 MMBoe of proved reserves to our assetbase. Combined with 8.6 MMBoe of upward revisions to ourreserve estimates, Devon’s total reserve additions were 135.1MMBoe during the past three years. This represents 446% of our30.3 MMBoe of production.◆ In July, 1996, Devon, through a newly-formed affiliatetrust, issued $149.5 million of 6.5% Trust Convertible PreferredSecurities (the “TCP Securities”).◆ Our oil and gas reserve additions, production gains,revenue increases and equity additions over the past three yearshave allowed us to increase our lines of credit. Since the end of1993, Devon’s long-term credit lines have increased by $100million to a total of $260 million at year-end 1996.

The growth exhibited by Devon over the last threeyears extends an eight-year expansion period for thecompany. This period started when we became a publiccompany in 1988. Through our acquisitions and drilling anddevelopment efforts, we have significantly increased oil andgas reserves and production over this period.

While we have consistently increased production overthis period of time, volatility in oil and gas prices has resultedin considerable variability in earnings and cash flows. Prices


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


for oil, natural gas and NGLs are determined primarily byprevailing market conditions. Market conditions for theseproducts have been, and will continue to be, influenced byregional and world-wide economic growth, weather and otherfactors that are beyond our control. Devon’s future earningsand cash flows will continue to be dependent on marketconditions for the company’s production.

Like all oil and gas production companies, we face thechallenge of natural decline. As virgin pressures are depleted,oil and gas production from a given well naturally decreases.Thus, an oil and gas production company consumes part ofits asset base with each unit of oil and gas it produces.Historically, Devon has been able to overcome this naturaldecline by adding more reserves through drilling and acquisi-tions than the company produces. However, our futuregrowth, if any, will depend on our ability to continue to addreserves in excess of production.

Because we can only marginally influence oil and gasprices, we have focused our efforts on increasing oil and gasreserves and production and on controlling expenses. Overour eight year history as a public company, we have been ableto significantly reduce our production and operating costs perunit of production. However, over the last two years Devon’sper-unit operating costs have increased somewhat. Anincrease in our oil production as a portion of our totalproduction and an increase in secondary recovery projectshave contributed to this expense increase. (Producing oil is

MD&A

generally more expensive than producing gas. Also, secondaryrecovery projects are generally more expensive than primaryproduction.) Higher oil and gas prices in 1996 also resultedin higher production taxes, a component of production andoperating expenses. Our future earnings and cash flows aredependent on our ability to continue to contain productionand operating costs at levels that allow for profitable produc-tion of oil and gas.

RESULTS OF OPERATIONS

Devon’s total revenues have risen from $100.8 millionin 1994 to $113.3 million in 1995 and $164.0 million in1996. In each of these years, oil, gas and NGL salesaccounted for 99% of total revenues.

Changes in oil, gas and NGL production, prices andrevenues from 1994 to 1996 are shown in the table on thefollowing page.

OIL REVENUES 1996 vs. 1995 Oil revenues increasedby $24.9 million in 1996. An increase in the average price of$4.25 per barrel in 1996 added $16.2 million to revenues.Production gains of 516,000 barrels added the remaining$8.7 million of 1996’s increased oil revenues.

1 “Cash margin” equals Devon’s total revenues less cash expenses. Cash expenses are all expenses other than the non-cash expenses of depreciation, deple-tion 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 netcash which is generated by a company’s operations during a given period, without regard to the period such cash is actually physically received or spent by thecompany. This margin ignores the non-operational effects on a company’s activities as an operator of oil and gas wells. Such activities produce net increases ordecreases in temporary cash funds held by the operator which have no effect on net earnings of the company. Cash margin should be used as a supplement to, andnot as a substitute for, net earnings and net cash provided by operating activities determined in accordance with generally accepted accounting principles inanalyzing Devon’s results of operations and liquidity.

The Grayburg-Jackson Field acquired in the 1994 AltaMerger accounted for the majority of 1996’s increasedproduction. This field produced 1,108,000 barrels in 1996, a37% increase over the 807,000 barrels the field produced in1995. Production from our other oil properties increased 9%in 1996 to 2,708,000 barrels. This is compared 2,493,000barrels in 1995.

1995 vs. 1994 Oil revenues rose $17.2 million in1995. Substantial gains in production added $12.9 million torevenues in 1995, while higher average prices added theremaining $4.3 million.

The Grayburg-Jackson Field produced 807,000 barrelsin 1995. This represents a 296% increase from the 204,000barrels which were produced during Devon’s ownership forthe last seven months of 1994. Production from our other oilproperties increased 10% in 1995, from 2,263,000 barrels in1994 to 2,493,000 barrels in 1995.

GAS REVENUES 1996 vs. 1995 Gas revenues increasedby $17.3 million in 1996. An increase in the average gasprice of $0.53 per Mcf in 1996 added $18.9 million to1996’s gas revenues. This increase was partially offset by a$1.6 million reduction in gas revenues from a 1.2 Bcf drop ingas production.


1996 1995Year Ended December 31, 1996 vs 1995 1995 vs 1994 1994

PRODUCTION

Oil (MBbls) 3,816 +16% 3,300 +34% 2,467Gas (MMcf) 35,714 -3% 36,886 -6% 39,335NGLs (MBbls) 952 +59% 600 +20% 501Oil, Gas and NGLs (MBoe) 10,720 +7% 10,047 +5% 9,524

REVENUES

Per Unit of Production:Oil (per Bbl) $ 21.00 +25% 16.75 +8% 15.44Gas (per Mcf ) $ 1.91 +38% 1.38 -3% 1.43NGLs (per Bbl) $ 15.09 +41% 10.68 +9% 9.79Oil, Gas and NGLs (per Boe) $ 15.16 +35% 11.19 +7% 10.43

Absolute (Thousands):

Oil $ 80,142 +45% 55,290 +45% 38,086Gas $ 68,049 +34% 50,732 -10% 56,372NGLs $ 14,367 +124% 6,404 +30% 4,908Oil, Gas and NGLs $ 162,558 +45% 112,426 +13% 99,366

Coal seam gas production declined by 16%, from 20.8Bcf in 1995 to 17.4 Bcf in 1996. However, the average real-ized coal seam gas price rose by 30% in 1996. Devon’saverage realized coal seam gas price was $1.72 per Mcf in1996, compared to $1.32 per Mcf in 1995. Total coal seamgas revenues were $30.1 million in 1996 compared to $27.5million in 1995. This includes $10.3 million in 1996 and$12.8 million in 1995 attributable to the San Juan BasinTransaction.

Total conventional gas production and revenues for1996 were 18.3 Bcf and $37.9 million, respectively. Thiscompares to 16.1 Bcf and $23.2 million, respectively, ofconventional gas production and revenues in 1995. Prices forconventional gas averaged $2.08 per Mcf in 1996 comparedto 1995’s average of $1.44. The additional interests in theWorland Properties added 2.2 Bcf to 1996’s conventionalproduction. Devon acquired these additional interests inDecember 1995 and the first half of 1996

1995 vs. 1994 Gas revenues decreased $5.6 million,or 10%, in 1995, due to a combination of lower productionand prices. Lower production accounted for $3.5 million ofthe revenue decrease. Lower gas prices accounted for theremaining revenue decrease of $2.1 million.

MD&A


Gas revenues in 1995 were downdespite the positive effect of the 1995San Juan Basin Transaction. This trans-action boosted 1995’s gas revenues by$11.4 million. It also raised the averageprices for 1995 coal seam gas and totalgas production by $0.61 and $0.35 perMcf, respectively. (See Note 3 to theconsolidated financial statementsincluded elsewhere in this report for adetailed discussion of the San JuanBasin Transaction.)

Coal seam gas productiondeclined by 5%, from 22.0 Bcf in 1994to 20.8 Bcf in 1995. This decline of1.2 Bcf was due to the San Juan BasinTransaction. In addition to significantlyincreasing our gas prices and revenues,the San Juan Basin Transactionincluded the sale of a small portion ofour coal seam gas properties.

Devon’s average realized coalseam gas price rose by 13%, from $1.17per Mcf in 1994 to $1.32 per Mcf in1995. The $0.61 per Mcf increase fromthe San Juan Basin Transaction morethan offset a $0.46 per Mcf price dropat the wellhead. Total coal seam gasrevenues were $27.5 million in 1995versus $25.7 million in 1994. Coalseam gas revenues in 1995 included$14.7 million of wellhead sales and$12.8 million of revenues attributableto the San Juan Basin Transaction. Thesale of the small portion of our coalseam gas properties was part of the SanJuan Basin Transaction. This sale hadthe effect of reducing 1995’s coal seamgas revenues by $1.4 million ascompared to 1994’s revenues. The$12.8 million of additional gas sales lessthis $1.4 million of wellhead salesreduction, nets to the $11.4 millionincrease in coal seam gas sales from theSan Juan Basin Transaction.

Total conventional gas produc-tion and revenues for 1995 were 16.1Bcf and $23.2 million, respectively.This compares to 17.4 Bcf and $30.7million respectively, in 1994. Prices forconventional gas averaged $1.44 perMcf in 1995 compared to 1994’saverage of $1.76 per Mcf.

Production for a full year fromthe Alta Merger Properties contributeda 0.6 Bcf increase in gas production in1995. However, this increase and othersfrom wells drilled in 1994 and 1995were more than offset by reducedproduction from other conventional gaswells. The primary contributors to theconventional production decline in1995 were the Ozona field, NEBU andmiscellaneous property sales. Highpipeline pressure and down time forrepairs contributed to a 0.6 Bcf reduc-tion in Ozona production in 1995.Out-of-period marketing adjustmentscaused the reduction in 1995 conven-tional gas production at NEBU.Various marginal wells sold in 1994and 1995 accounted for a 0.6 Bcfreduction in 1995’s conventionalproduction.

Although we do not have asignificant interest in conventional gasproduction in NEBU, we had beenselling more than our normal share ofproduction. This created an “imbal-ance” between Devon and the wells’other owners. This imbalance wasreversed in 1995 as the other ownerssold more than their normal share ofproduction. Also in 1994, we receivednonrecurring payments for inventorygas from NEBU. In 1995, the amountsof imbalance makeup and the lack ofinventory sales led to a 0.5 Bcf reduc-tion in conventional NEBU productioncompared to 1994.

NGL REVENUES 1996 vs. 1995NGL revenues increased by $8.0million in 1996. An increase in averageprices of $4.41 per barrel added $4.2million to the 1996 revenues. Theremaining $3.8 million of increasedrevenues was attributable to increasedproduction of 352,000 barrels in 1996.

Devon acquired additional inter-ests in the Worland Properties inDecember 1995 and the first half of1996. The acquired interests accountedfor 214,000 barrels of the increasedproduction in 1996. The WorlandProperties produced 226,000 barrels in1996 compared to 12,000 barrels in1995. Additional drilling in the SandDunes area of the Permian Basinincreased production from 69,000barrels in 1995, to 95,000 barrels in1996.

1995 vs. 1994 NGL revenuesincreased by $1.5 million in 1995.Higher production contributed $1.0million of the increase. The remaining$0.5 of increased revenues was attribut-able to higher average prices in 1995.

The Alta Merger Propertiesaccounted for 52,000 barrels of theincreased production. Such propertiesproduced 84,000 barrels in 1995,compared to 32,000 barrels during theseven months Devon owned the prop-erties in 1994. Additional drilling inthe Sand Dunes area increased produc-tion from 39,000 barrels in 1994 to69,000 barrels in 1995.


EXPENSES The details of the changes in pre-tax expenses between 1994 and 1996 are shown in the table below.


Absolute: (Thousands)Production and operating expenses:

Lease operating expenses $ 31,568 +16% 27,289 +11% 24,521Production taxes 10,658 +56% 6,832 -1% 6,899

Depreciation, depletion and amortizationattributable to:

Oil and gas production 41,538 +13% 36,640 +11% 32,861Non-oil and gas properties 1,823 +26% 1,450 +14% 1,271

General and administrative expenses 9,101 +8% 8,419 - 8,425Interest expense 5,277 -25% 7,051 +30% 5,439Distributions on preferred securities of subsidiary trust 4,753 N/A - - -

Total $ 104,718 +19% 87,681 +10% 79,416

Per Boe(1):Production and operating expenses:

Lease operating expenses $ 2.95 +8% 2.72 +6% 2.57Production taxes 0.99 +46% 0.68 -7% 0.73

Depreciation, depletion and amortizationattributable to:

Oil and gas production 3.88 +6% 3.65 +6% 3.45Non-oil and gas properties 0.17 +21% 0.14 +8% 0.13

General and administrative expenses 0.85 +1% 0.84 -6% 0.89Interest expense 0.49 -30% 0.70 +23% 0.57Distributions on preferred securities of subsidiary trust 0.44 N/A - - -

Total $ 9.77 +12% 8.73 +5% 8.34

(1) Though per Boe general and administrative expenses, interest expense, nonoil and gas property depreciation and distributions on preferred securities of subsidiary trust

may be helpful for profitability trend analysis, these expenses are not directly attributable to production volumes. Rather they are an artifact of corporate structure, capitalization and

financing, and non-oil and gas property fixed assets, respectively.

PRODUCTION AND OPERATING EXPENSES The details of the changes in production and operating expenses between1994 and 1996 are shown in the table below.


Absolute: (Thousands)Recurring lease operating expenses $ 28,270 +19% 23,842 +10% 21,583Well workover expenses 3,298 -4% 3,447 +17% 2,938Production taxes 10,658 +56% 6,832 -1% 6,899

Total production and operating expenses $ 42,226 +24% 34,121 +9% 31,420

Per Boe:Recurring lease operating expenses $ 2.64 +11% 2.37 +4% 2.27Well workover expenses 0.31 -11% 0.35 +17% 0.30Production taxes 0.99 +46% 0.68 -7% 0.73

Total production and operating expenses $ 3.94 +16% 3.40 +3% 3.30

MD&A


1996 vs. 1995 Recurring leaseoperating expenses increased by $4.4million, or 19%, in 1996. Approxi-mately $2.7 million of the increase wasrelated to the additional interestsacquired in the Worland Properties.Devon acquired these additional inter-ests in December 1995 and the first halfof 1996. Recurring lease operatingexpenses for the Worland Propertiesincreased from $0.1 million in 1995 to$2.8 million in 1996. The Alta MergerProperties’ recurring lease operatingexpenses increased from $3.5 million in1995 to $4.6 million in 1996. Thisincrease was predominantly due to thehigher number of producing wells in theGrayburg-Jackson Field in 1996compared to 1995.

Recurring expenses per Boe wereup by $0.27, or 11%, in 1996 comparedto 1995. This increase was primarilycaused by the reduction in the coal seamgas properties’ share of total production.The recurring operating costs per Boefor these coal seam gas properties areextremely low ($0.32 per Boe in 1996and $0.24 per Boe in 1995). However,the coal seam gas properties’ percentageof overall production dropped from 35%in 1995 to 27% in 1996. The result isthat more of our production in 1996was attributable to conventional oil andgas properties. Our conventional oil andgas properties have a higher recurringoperating cost per Boe than the low-costcoal seam gas properties. The recurringcosts per Boe on these conventionalproperties were $3.50 per Boe in 1996and 1995. However, since these proper-ties represented a larger percentage ofDevon’s total production, the result wasa $0.27 per Boe increase in the overallrate in 1996.

Production taxes are collected bymost taxing authorities on a fixedpercentage of revenue basis. Therefore,as our revenues have increased, so haveproduction taxes. Production taxesincreased 56% from $6.8 million in1995 to $10.7 million in 1996. Thisincrease was due almost exclusively tohigher oil, gas and NGL revenues.Excluding revenues generated from theSan Juan Basin Transaction, 1996 oil,gas and NGL revenues increased 53%compared to 1995. Revenues generatedfrom the San Juan Basin Transaction arenot subject to production taxes.

Production taxes per Boeincreased by $0.31 per Boe, or 46% in1996. This was primarily caused by theincrease in the average price per Boereceived in 1996. Excluding the effecton average prices from the San JuanBasin Transaction, Devon’s total revenuesper Boe increased by 43% from $9.92 in1995, to $14.21 in 1996.

1995 vs. 1994 Recurring leaseoperating expenses increased by $2.2million, or 10%, in 1995. Approxi-mately $1.6 million of the increase wasrelated to the Alta Merger Properties.Costs for these properties increased from$1.9 million in 1994 (for the last sevenmonths of the year during which theywere owned by Devon) to $3.5 millionin 1995. However, on a cost per unit ofproduction basis, the Alta Merger Prop-erties’ recurring lease operating expensesdropped from $4.96 per Boe in 1994 to$3.16 per Boe in 1995. These per unitcosts compare to averages for our otherproperties of $2.15 per Boe in 1994 and$2.28 per Boe in 1995.

DEPRECIATION, DEPLETION AND

AMORTIZATION Devon’s largest non-cashexpense is depreciation, depletion andamortization (“DD&A”). DD&A of oiland gas properties is calculated as thepercentage of total proved reservevolumes produced during the year,multiplied by the net capitalized invest-ment in those reserves including esti-mated future development costs (the“depletable base”). Generally, if reservevolumes are revised up or down, thenthe DD&A rate per unit of productionwill change inversely. However, if capi-talized costs change, then the DD&Arate moves in the same direction. Theper unit DD&A rate is not affected byproduction volumes. Absolute or totalDD&A, as opposed to the rate per unitof production, generally moves in thesame direction as production volumes.

1996 vs. 1995 Oil and gas prop-erty related DD&A increased by $4.9million, or 13%, in 1996. Approxi-mately $2.5 million of this increase wascaused by a 7% increase in total oil, gasand NGL production in 1996. Theremaining $2.4 million increase wascaused by a 6% increase in the DD&Arate. Devon’s DD&A rate increased from$3.65 per Boe in 1995 to $3.88 per Boein 1996.

1995 vs. 1994 Oil and gas prop-erty related DD&A increased by $3.8million, or 11%, in 1995. Approxi-mately $2.0 million of this increase wascaused by an increase in the DD&Arate. Devon’s DD&A rate increased from$3.45 per Boe in 1994 to $3.65 per Boein 1995. The increased DD&A rate wasprimarily caused by the inclusion of theAlta Merger Properties for a full year in1995. The Alta Merger Properties were


MD&A

included for seven months in 1994.The remaining $1.8 million of theincrease in oil and gas property relatedDD&A was caused by the increase intotal production in 1995.

GENERAL AND ADMINISTRATIVE

EXPENSES (“G&A”) 1996 vs. 1995G&A increased by $0.7 million, or 8%,in 1996. Employee salaries and relatedbenefits were $1.1 million higher in1996. Legal expenses and abandonedacquisition expenses were each $0.2million higher in 1996. These increaseswere partially offset by a $0.1 millionreduction in franchise tax expense dueto Devon’s 1995 change of incorpora-tion from Delaware to Oklahoma.Also, G&A reimbursements receivedfrom other joint interest owners inDevon-operated properties increased$0.7 million in 1996.

1995 vs. 1994 G&A wasconstant between 1995 and 1994.Employee salaries and related overheadburdens increased by $0.3 million.Legal fees increased by $0.3 millionwhile abandoned acquisition costs roseby $0.1 million. These increases wereoffset by a $0.1 million reduction infranchise taxes and a $0.6 millionincrease in G&A reimbursements. Suchreimbursements are received from jointinterest owners in Devon-operatedproperties. Approximately $0.2 millionof the increase in G&A reimbursementsrelated to a change in the method usedto calculate the reimbursements oncertain properties. This change wasretroactive to the prior two years. Thereduction in franchise taxes resultedfrom Devon’s reincorporation fromDelaware to Oklahoma in June 1995.

INTEREST EXPENSE 1996 vs.1995 Interest expense decreased by$1.8 million, or 25%, in 1996. Approx-imately $1.5 million of the lowerinterest expense was due to a loweraverage debt balance in 1996. Theaverage debt balance dropped from$97.1 million in 1995 to $77.0 millionin 1996. This decrease in average debtoutstanding was primarily the result ofthe issuance of the TCP Securities inJuly 1996.

The remaining $0.3 million ofinterest expense reduction in 1996resulted from lower interest rates. Theinterest rates on the debt outstandingduring 1996 averaged 6.3%, comparedto 1995’s rate of 6.5%. The overallinterest rate averaged 6.9% in 1996 and7.3% in 1995. This includes the effectof the interest rate swap discussedbelow, various fees paid to the banksand the amortization of certain loancosts.

Devon entered into an interestrate swap agreement in the secondquarter of 1995. The company termi-nated the agreement on July 1, 1996for a gain of $0.8 million. This gainwill be recognized ratably in our oper-ating results during the period fromJuly 1, 1996 to June 16, 1998 (the orig-inal expiration date of the swap agree-ment). The recognition of this gainreduces interest expense. Approximately$0.2 million of the gain was included inthe last half of 1996 as an offset tointerest expense. During the time whenthe agreement was still in effect, itresulted in $0.1 million of reducedinterest expense in the year 1995, andhad no effect on interest expense for thefirst six months of 1996.

1995 vs. 1994 Interest expenseincreased by $1.6 million, or 30%, in1995. This increase was due almostexclusively to higher rates in 1995.Higher rates accounted for $1.3 millionof the increased interest expense in1995. The interest rate on the debtoutstanding during 1995 was 6.5%,compared to 1994’s rate of 5.2%. Theoverall interest rate averaged 7.3% in1995, compared to the 1994 overallrate of 5.9%.

The remaining $0.3 million ofinterest expense increase in 1995 wascaused by a higher average balanceoutstanding. The average debt balanceduring 1995 was $97.1 million,compared to 1994’s average balance of$92.5 million.

DISTRIBUTIONS ON PREFERRED

SECURITIES OF SUBSIDIARY TRUST 1996vs. 1995 Devon, through its newly-formed affiliate Devon Financing Trust,issued $149.5 million of 6.5% TCPSecurities. This issuance occurred in aprivate placement during July 1996.The distributions accrue at the rate of1.625% per quarter. The 1996 distribu-tions of $4.8 million representedslightly less than two quarters’ distribu-tions. This resulted from the issuancedate occurring in July. For a completediscussion of these matters, see Note 9to the consolidated financial statementscontained elsewhere in this report.

INCOME TAXES 1996 vs. 1995Our effective financial tax rate in 1996was 41%, compared to 1995’s rate of43%. Both rates were above the statu-tory federal tax rate of 35%. Thisresulted from state income taxes, andcertain tax aspects of the San Juan BasinTransaction and the 1994 Alta Merger.

1995 vs 1994 Our effective financial tax rate in 1995was 43%, compared to 1994’s rate of 36%. State incometaxes and certain tax aspects of the San Juan Basin Transac-tion were the primary factors which increased Devon’s finan-cial tax rate. The San Juan Basin Transaction also had asignificant effect on the portion of income taxes which arecurrent versus deferred.

CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY

The following discussion of capital expenditures,capital resources and liquidity should be read in conjunctionwith the consolidated statements of cash flows included inthis report.

CAPITAL EXPENDITURES Approximately $98.9million of cash was spent in 1996 for capital expenditures.Of this, $85.0 million was related to the acquisition, drillingor development of oil and gas properties. Most of the drillingand development efforts in 1996 centered in the PermianBasin. This included 176 of the 194 oil and gas wells whichDevon drilled during 1996. Most of Devon’s 1996 non-oiland gas property related capital expenditures involved the$12.5 million purchase of the office building in which itsOklahoma City offices are located. This purchase was closedon December 31, 1996.

OTHER CASH USES We began paying quarterly divi-dends on common stock in the second quarter of 1993 at therate of $0.03 per share. In the fourth quarter of 1996, thequarterly dividend rate was increased to $0.05 per share.

CAPITAL RESOURCES AND LIQUIDITY Net cashprovided by operating activities (“operating cash flow”) wasthe primary source of capital and short-term liquidity in1996. Operating cash flow in 1996 totaled $86.2 millioncompared to $61.3 million in 1995. This resulted in anincrease of 41%.

In addition to operating cash flow, Devon’s credit lineshave been an important source of capital and liquidity. Atyear-end 1996, long-term credit lines totaled $260 million,of which $252 million was available for future use. At theend of 1996, in connection with the KMG-NAOS acquisi-tion, we also established a demand revolving credit line for

our new Canadian operations. This credit line totals $12.5million Canadian dollars, all of which was available at year-end. (See Note 7 to the consolidated financial statementsincluded elsewhere in this report for a detailed discussion ofthe credit lines.) The proceeds from the TCP Securitiesoffering in July 1996 mentioned earlier, were used to retirelong-term debt. This reduction in debt increased the amountof our credit lines available for future borrowings.

Devon’s San Juan Basin coal seam gas production issubject to uncertainties regarding additional royalties andtaxes. If such uncertainties are resolved in 1997, the resolu-tions are likely to require the use of operating cash flow.However, we do not expect such amount to be material toour overall liquidity, capital resources or net earnings. For acomplete discussion of these matters, see Note 12 to theconsolidated financial statements contained elsewhere in thisreport.

1997 ESTIMATES

The forward-looking statements provided in thisdiscussion are based on management’s examination of histor-ical operating trends, the December 31, 1996 reserve reportsof LaRoche Petroleum Consultants, Ltd. and AMH GroupLtd., data in Devon’s files and other data available from thirdparties. We caution that our future oil, gas and NGL produc-tion, revenues and expenses are subject to all of the risks anduncertainties normally incident to the exploration for anddevelopment and production of oil and gas. These risksinclude, but are not limited to, environmental risks, drillingrisks, regulatory changes, the uncertainty inherent in esti-mating future oil and gas production or reserves, and otherrisks as outlined below. The scope of our operations increasedsignificantly with the KMG-NAOS transaction. Thisincreases the margin of error inherent in estimating our 1997production volumes, prices and expenses. Also, the financialresults for Devon’s new Canadian operations, obtained in theKMG-NAOS transaction, are subject to currency exchangerate risks.


ASSUMPTIONS AND RISKS FOR PRICE AND PRODUCTION

ESTIMATES Prices for oil, natural gas and NGLs are deter-mined primarily by prevailing market conditions. Marketconditions for these products are influenced by regional andworld-wide economic growth, weather and other substantiallyvariable factors. These factors are beyond our control and aredifficult to predict. Over 90% of Devon’s revenues are attrib-utable to sales of these three commodities. Consequently, ourfinancial results and resources are highly influenced by thisprice volatility.

Estimates for Devon’s future production of oil, naturalgas and NGLs are based on the assumption that marketdemand and prices for oil and gas will continue at levels thatallow for profitable production of these products. Althoughour management believes these assumptions to be reasonable,there can be no assurance of such stability.

Certain of Devon’s individual oil and gas properties aresufficiently significant as to have a material impact on thecompany’s overall financial results. With respect to oilproduction, these properties include the West Red Lake Fieldand the Grayburg-Jackson Unit, both in southeast NewMexico. In addition, our interest in NEBU and the 32-9Unit can have a substantive effect on overall gas production.

The production, transportation and marketing of oil,natural gas and NGLs are complex processes which aresubject to disruption. This is caused by transportation andprocessing availability, mechanical failure, human error, mete-orological events and numerous other factors. The followingforward-looking statements were prepared assuming demand,curtailment, producibility and general market conditions forour oil, natural gas and NGLs for 1997 will be substantiallysimilar to those of 1996, unless otherwise noted. Given thegeneral limitations expressed herein, our forward-lookingstatements for 1997 are set forth below.

OIL PRODUCTION AND RELATIVE PRICES Devon expectsits oil production in 1997 to total between 5.9 millionbarrels and 6.9 million barrels. We expect our net oil priceswill average from between $0.05 below to $0.20 above WestTexas Intermediate posted prices in 1997.

GAS PRODUCTION AND RELATIVE PRICES We expect ourtotal gas production in 1997 will be between 64.0 Bcf and75.0 Bcf. It is expected that coal seam gas production will be16.5 Bcf to 19.5 Bcf. Canadian production in 1997 is esti-mated to be between 7.0 Bcf and 8.0 Bcf. We expect produc-tion from the remainder of our gas properties to totalbetween 40.5 Bcf and 47.5 Bcf.

Devon expects its 1997 coal seam average price will bebetween $0.25 and $0.55 less than Texas Gulf Coast spotaverages. This includes an expected $0.55 per Mcf from theSan Juan Basin Transaction. Our Canadian gas production isexpected to average from between $0.85 to $1.20 less thanTexas Gulf Coast spot prices. (These Canadian differentialsare expressed in U.S. dollars, using the year-end 1996exchange rate of $0.73 U.S. dollar to $1.00 Canadian dollar.)Devon’s remaining gas production is expected to average$0.05 to $0.25 less than Texas Gulf Coast spot prices during1997.

NGL PRODUCTION We expect our production of NGLsin 1997 to total between 1.1 million barrels and 1.3 millionbarrels.

PRODUCTION AND OPERATING EXPENSES Devon’sproduction and operating expenses vary in response to severalfactors. Among the most significant of these factors are addi-tions or deletions to our property base and changes inproduction taxes. Other significant factors are generalchanges in the prices of services and materials that are used inthe operation of our properties and the amount of repair andworkover activity required on those properties.

The addition of the KMG-NAOS Properties isexpected to be the largest contributor to an increase in recur-ring lease operating expenses in 1997. The additionalrevenues contributed by these properties should also causeproduction taxes to rise. In addition, well workover expensesare anticipated to increase in 1997.

Oil, gas and NGL prices will have a direct effect onproduction taxes to be incurred in 1997. Future prices couldalso have an effect on whether proposed workover projectsare economically feasible. These factors coupled with theuncertainty of future oil, gas and NGL prices, increase the


MD&A

margin of error inherent in estimating future production andoperating costs. Given these uncertainties, we estimate that1997’s total production and operating costs will be between$75 million and $87 million.

DEPRECIATION, DEPLETION AND AMORTIZATION The1997 DD&A rate will depend on various factors. Mostnotable among such factors is the amount of proved reservesthat could be added from drilling or acquisition efforts in1997 compared to costs incurred for such efforts. Anothernotable factor is the revisions to Devon’s year-end 1996reserve estimates which will be made during 1997.

The DD&A rate as of the beginning of 1997 was$3.76 per Boe. This rate includes the effect of the December31, 1996, acquisition of the KMG-NAOS Properties.Conversely, the 1996 yearly rate of $3.88 per Boe did notreflect the effect of these properties. Assuming a 1997 rate ofbetween $3.80 per Boe and $4.20 per Boe, 1997 DD&Aexpense (including approximately $2.5 million of non-oil andgas property related DD&A) is expected to be $76 million to$84 million.

GENERAL AND ADMINISTRATIVE EXPENSES Devon’sgeneral and administrative expenses include the costs of manydifferent goods and services used in support of the company’sbusiness. These goods and services are subject to general pricelevel increases or decreases. In addition, our G&A expensesvary with our level of activity and the related staffing needs.G&A expenses are also affected by the amount of profes-sional services required during any given period. The addi-tion of the KMG-NAOS Properties will increase Devon’sgeneral level of activity as well as its staffing requirementsduring 1997. Should our anticipated needs or the prices ofthe required goods and services differ significantly from ourexpectations, actual G&A expenses could vary materiallyfrom the estimate. Given these limitations, G&A expensesare expected to be between $12 million and $14 million in1997.

INTEREST EXPENSE We expect to fund substantially allof our anticipated expenditures during 1997 with workingcapital and internally generated cash flow. Should our actualcapital expenditures or internally generated cash flow varysignificantly from expectations, interest expense could differmaterially from the following estimate. Given this limitation,interest expense is expected to be less than $1 million in1997.

DISTRIBUTIONS ON TCP SECURITIES TCP Securitiesare convertible into common shares of Devon at the holder’soption. Should any of the holders of the TCP Securities electto convert during 1997, it would reduce the amount ofrequired distributions. Assuming all $149.5 million of TCPSecurities are outstanding for the entire year, we will make$9.7 million of distributions in 1997.

INCOME TAXES Devon expects its financial income taxrate in 1997 to be between 38% and 42%. Regardless of thelevel of pre-tax earnings reported for financial purposes, wewill have a minimum of approximately $2.5 million of finan-cial income tax expense. This results from various tax aspectsof the 1994 Alta Merger, the San Juan Basin Transaction andthe KMG-NAOS acquisition. Therefore, if the actual amountof 1997 pre-tax earnings differs materially from what Devoncurrently expects, the actual financial income tax rate for1997 could fall outside the 38% to 42% expected rate. Also,based on our current expectations of 1997 taxable income,we anticipate our current portion of 1997 income taxes willbe between $9 million and $13 million. However, revenueand earnings fluctuations could easily make these tax esti-mates obsolete.

CAPITAL EXPENDITURES Our capital expendituresbudget is based on an expected range of future oil, naturalgas and NGL prices as well as the expected costs of thecapital additions. Should our price expectations for ourfuture production change significantly, we may accelerate ordefer some projects. Thus, Devon would increase or decreasetotal 1997 capital expenditures. In addition, if the actual costof the budgeted items varies significantly from the amountanticipated, actual capital expenditures could vary materiallyfrom our estimate.



MD&A

Though Devon has completed atleast one major acquisition in each ofthe last several years, these transactionsare opportunity driven. Thus, we do not“budget”, nor can we reasonably predict,the timing or size of such possible acqui-sitions, if any.

Given these limitations, Devonexpects its 1997 capital expenditures fordrilling and development efforts to totalbetween $120 million and $135 million.This includes $8 million to $11 millionin Canada. (Canadian amounts areexpressed in U.S. dollars, using the year-end 1996 exchange rate of $0.73 U.S.dollar to $1.00 Canadian dollar.) Weexpect to spend $50 million to $65million in 1997 for drilling, facilitiesand waterflood costs related to reservesclassified as proved as of year-end 1996.We also plan to spend another $15million to $20 million on new, higherrisk/reward projects.

OTHER CASH USES Devon’smanagement expects the policy ofpaying a quarterly dividend to continue.With the current $0.05 per share quar-terly dividend rate and 32.1 millionshares of common stock outstanding,1997 dividends are expected to approxi-mate $6.4 million.

CAPITAL RESOURCES AND

LIQUIDITY The estimated future drillingand development activities are expectedto be funded through a combination ofworking capital and net cash providedby operations. The amount of net cashto be provided by operating activities in1997 is uncertain due to the factorsaffecting revenues and expenses cited

above. However, we consider our capitalresources to be more than adequate tofund our anticipated capital expendi-tures.

Based on the expected level of1997’s capital expenditures and net cashprovided by operations, Devon does notexpect to rely on its credit lines to funda material portion of its capital expendi-tures. However, if significant acquisi-tions or other unplanned capitalrequirements arise during the year, wecould utilize our credit lines. Theunused portion of these credit lines atthe end of 1996 consisted of $252million of long-term credit facilities. Inaddition, we had a $12.5 million (Cana-dian dollars) demand facility for ournew Canadian operations. If so desired,we believe our lenders would increaseour credit lines to at least $450 millionto $500 million. However, we do notdesire nor anticipate a need to increaseour credit lines above their currentlevels. In fact, to lower its borrowingcosts, Devon may reduce its credit linesin 1997 until a need for significantcapital arises.

IMPACT OF RECENTLY ISSUED

ACCOUNTING STANDARDS NOT YET

ADOPTED In June, 1996, the FinancialAccounting Standards Board issuedStatement of Financial Accounting Stan-dard No. 125, “Accounting for Transfersand Servicing of Financial Assets andExtinguishments of Liabilities.” SFASNo. 125 is effective for certain transfersand servicing of financial assets andextinguishment of liabilities occurringafter December 31, 1996. It is effectivefor other transfers of financial assetsoccurring after December 31, 1997. It isto be applied prospectively. SFAS No.125 provides accounting and reporting

standards for transfers and servicing offinancial assets and extinguishment ofliabilities. This is based on a consistentapplication of a financial-componentsapproach that focuses on control. Itdistinguishes transfers of financial assetsthat are sales from transfers that aresecured borrowings. We do not expectthat adoption of SFAS No. 125 willhave a material impact on our financialposition or results of operations.

In October, 1996, the AmericanInstitute of Certified Public Accountantsissued Statement of Position (SOP) 96-1, “Environmental Remediation Liabili-ties.” SOP 96-1 was adopted by Devonon January 1, 1997. It requires, amongother things, that environmental remedi-ation liabilities be accrued when thecriteria of SFAS No. 5, “Accounting forContingencies,” have been met. SOP96-1 also provides guidance with respectto the measurement of the remediationliabilities. Such accounting is consistentwith our current method of accountingfor environmental remediation costs.Therefore, adoption of SOP 96-1 willnot have a material impact on our finan-cial position or results of operations. ■

Devon Energy Corporation’s management takesresponsibility for the accompanying consolidated financialstatements which have been prepared in conformity withgenerally accepted accounting principles appropriate in thecircumstances. They are based on our best estimate and judg-ment. Financial information elsewhere in this annual report isconsistent with the data presented in these statements.

In order to carry out our responsibility concerning theintegrity and objectivity of published financial data, we main-tain an accounting system and related internal controls. Webelieve the system is sufficient in all material respects toprovide reasonable assurance that financial records are reliablefor preparing financial statements and that assets are safe-guarded from loss or unauthorized use.

Our independent accounting firm, KPMG PeatMarwick LLP, provides objective consideration of DevonEnergy management’s discharge of its responsibilities as itrelates to the fairness of reported operating results and thefinancial position of the company. This firm obtains andmaintains an understanding of our accounting and financialcontrols to the extent necessary to audit our financial state-

ments, and employs all testing and verification procedures asit considers necessary to arrive at an opinion on the fairnessof financial statements.

The Board of Directors pursues its responsibilities forthe accompanying consolidated financial statements throughits Audit Committee. The Committee meets periodically withmanagement and the independent auditors to assure that theyare carrying out their responsibilities. The independent audi-tors have full and free access to the Committee members andmeet with them to discuss auditing and financial reportingmatters. ■


Management’s Responsibility for Financial Statements

Independent Auditors’ Report

J. Larry NicholsPresident

H. R. Sanders, Jr.Executive Vice President

J. Michael LaceyVice President

Darryl G. SmetteVice President

H. Allen TurnerVice President

William T. VaughnVice President

Devon Energy Corporation Executive Committee

The Board of Directors and Stockholders Devon Energy Corporation:

We have audited the consolidated balance sheets ofDevon Energy Corporation and subsidiaries as of December31, 1996, 1995 and 1994, and the related consolidated state-ments of operations, stockholders’ equity and cash flows foreach of the years then ended. These consolidated financialstatements are the responsibility of the Company’s manage-ment. Our responsibility is to express an opinion on theseconsolidated financial statements based on our audits.

We conducted our audits in accordance with generallyaccepted auditing standards. Those standards require that weplan and perform the audit to obtain reasonable assuranceabout whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the

financial statements. An audit also includes assessing theaccounting principles used and significant estimates made bymanagement, 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 statementsreferred to above present fairly, in all material respects, thefinancial position of Devon Energy Corporation andsubsidiaries as of December 31, 1996, 1995 and 1994, andthe results of their operations and their cash flows for theyears then ended, in conformity with generally acceptedaccounting principles. ■

KPMG Peat Marwick LLP

Oklahoma City, OklahomaFebruary 7, 1997

Consolidated Balance Sheets


D E V O N E N E R G Y C O R P O R A T I O N A N D S U B S I D I A R I E S

December 31, 1996 1995 1994

ASSETS

Current assets:Cash and cash equivalents $ 9,401,350 8,897,891 8,336,371Accounts receivable (Note 5) 29,580,306 14,400,295 15,626,799Inventories 2,103,486 605,263 534,326Prepaid expenses 688,752 222,135 564,371Deferred income taxes (Note 8) 1,600,000 749,000 262,000

Total current assets 43,373,894 24,874,584 25,323,867Property and equipment, at cost, based onthe full cost method of accounting for oiland gas properties (Note 6) 974,805,756 631,437,904 523,941,141

Less accumulated depreciation,depletion and amortization 281,959,410 239,619,167 202,634,961

692,846,346 391,818,737 321,306,180Other assets 10,030,560 4,870,796 4,817,489

Total assets $ 746,250,800 421,564,117 351,447,536

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:Accounts payable:

Trade $ 4,861,428 3,868,458 6,394,897Revenues and royalties due to others 10,569,960 7,322,418 7,398,199

Income taxes payable 4,705,447 1,364,070 –Accrued expenses 3,503,420 3,003,943 3,225,493

Total current liabilities 23,640,255 15,558,889 17,018,589Revenues and royalties due to others 1,053,270 816,412 1,383,135Other liabilities (Notes 3 and 11) 10,325,999 8,623,057 –Long-term debt (Note 7) 8,000,000 143,000,000 98,000,000Deferred revenue 205,859 72,761 1,299,947Deferred income taxes (Note 8) 81,121,000 34,452,000 27,340,000

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

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 32,141,295 in 1996, 22,111,896 in 1995and 22,050,996 in 1994 3,214,130 2,211,190 2,205,100

Additional paid-in capital 388,090,930 167,430,347 166,654,305Retained earnings 81,099,357 49,399,461 37,546,460

Total stockholders’ equity 472,404,417 219,040,998 206,405,865Commitments and contingencies (Notes 11 and 12)

Total liabilities and stockholders’ equity $ 746,250,800 421,564,117 351,447,536See accompanying notes to consolidated financial statements.


D E V O N E N E R G Y C O R P O R A T I O N A N D S U B S I D I A R I E S

Year Ended December 31, 1996 1995 1994

REVENUES

Oil sales $ 80,142,073 55,289,819 38,086,076Gas sales 68,049,478 50,732,158 56,371,452Natural gas liquids sales 14,366,771 6,403,663 4,908,126Other 1,458,562 877,185 1,407,305

Total revenues 164,016,884 113,302,825 100,772,959

COSTS AND EXPENSES

Lease operating expenses 31,568,428 27,288,755 24,520,757Production taxes 10,657,814 6,832,507 6,899,743Depreciation, depletion and amortization (Note 6) 43,361,029 38,089,783 34,132,150General and administrative expenses 9,101,429 8,418,739 8,424,687Interest expense 5,276,527 7,051,142 5,438,911Distributions on preferred securities of

subsidary trust (Note 9) 4,753,125 – –Total costs and expenses 104,718,352 87,680,926 79,416,248

Earnings before income taxes 59,298,532 25,621,899 21,356,711

INCOME TAX EXPENSE (Note 8)Current 6,709,000 4,495,000 415,000Deferred 17,789,000 6,625,000 7,197,000

Total income tax expense 24,498,000 11,120,000 7,612,000

Net earnings $ 34,800,532 14,501,899 13,744,711

Net earnings per average commonshare outstanding (Note 1):

Assuming no dilution $ 1.57 $ 0.66 0.64Assuming full dilution $ 1.52 $ 0.66 0.64

Weighted average common shares outstanding 22,159,507 22,073,550 21,551,581See accompanying notes to consolidated financial statements.

Consolidated Statements of Operations



COMMON STOCK

Balance, beginning of year $ 2,211,190 2,205,100 2,084,232Par value of common shares issued 1,002,940 6,090 120,868

Balance, end of year 3,214,130 2,211,190 2,205,100

ADDITIONAL PAID-IN CAPITAL

Balance, beginning of year 167,430,347 166,654,305 144,403,743Common shares issued, net

of issuance costs 220,660,583 776,042 22,250,562


RETAINED EARNINGS

Balance, beginning of year 49,399,461 37,546,460 26,411,572Dividends (3,100,636) (2,648,898) (2,609,823)Net earnings 34,800,532 14,501,899 13,744,711


TOTAL STOCKHOLDERS’ EQUITY, END OF YEAR $ 472,404,417 219,040,998 206,405,865See accompanying notes to consolidated financial statements.

Consolidated Statements of Stockholders’ EquityD E V O N E N E R G Y C O R P O R A T I O N

A N D S U B S I D I A R I E S



CASH FLOWS FROM OPERATING ACTIVITIES

Net earnings $ 34,800,532 14,501,899 13,744,711Adjustments to reconcile net earnings to net

cash provided by operating activities:Depreciation, depletion and amortization 43,361,029 38,089,783 34,132,150(Gain) loss on sale of assets (3,930) 273,238 (27,086)Deferred income taxes 17,789,000 6,625,000 7,197,000Changes in assets and liabilities net of effects

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

Accounts receivable (15,470,528) 1,213,877 123,388Inventories (176,286) (70,937) 181,475Prepaid expenses (466,617) 342,236 712Other assets (1,032,653) 677,238 (489,648)

Increase (decrease) in:Accounts payable 3,370,474 (430,736) (8,896,674)Income taxes payable 3,341,377 1,364,070 (467,962)Accrued expenses 399,477 (221,550) 997,645Revenues and royalties due to others 236,858 (566,723) (62,748)Long-term other liabilities 519,978 705,636 –Deferred revenue 133,098 (1,227,186) (49,127)

Net cash provided by operating activities 86,801,809 61,275,845 46,383,836

CASH FLOWS FROM INVESTING ACTIVITIES

Proceeds from sale of property and equipment 4,037,480 9,427,401 4,649,257Capital expenditures (98,854,846) (117,593,897) (35,619,968)Payments made for acquisition of business (Note 2) – (2,391,484) (42,397,463)

Net cash used in investing activities (94,817,366) (110,557,980) (73,368,174)

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from borrowings on revolving line of credit 29,000,000 52,000,000 32,500,000Principal payments on revolving line of credit (164,000,000) (7,000,000) (14,500,000)Issuance of common stock, net of issuance costs 577,483 782,132 380,244Issuance of preferred securities of subsidiary trust,

net of issuance costs 144,665,205 – –Dividends paid on common stock (3,100,636) (2,648,898) (2,609,823)Increase in long-term other liabilities (Note 3) 1,376,964 6,710,421 –

Net cash provided by financing activities 8,519,016 49,843,655 15,770,421

Net increase (decrease) in cash and cash equivalents 503,459 561,520 (11,213,917)

Cash and cash equivalents at beginning of year 8,897,891 8,336,371 19,550,288

Cash and cash equivalents at end of year $ 9,401,350 8,897,891 8,336,371See accompanying notes to consolidated financial statements.

Consolidated Statements of Cash FlowsD E V O N E N E R G Y C O R P O R A T I O N


1 Summary of Significant Accounting Policies

Accounting policies used by Devon Energy Corpora-tion and subsidiaries (“Devon”) reflect industry practices andconform to generally accepted accounting principles. Themore significant of such policies are briefly discussed below.

BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Devon is engaged primarily in oil and gas exploration,development and production, and the acquisition ofproducing properties. Such activities are primarily in thestates of New Mexico, Texas, Oklahoma, Wyoming andLouisiana. Effective December 31, 1996, Devon began oper-ations in Alberta, Canada. Devon’s share of the assets, liabili-ties, revenues and expenses of affiliated partnerships and theaccounts of its wholly-owned subsidiaries are included in theaccompanying consolidated financial statements. All signifi-cant intercompany accounts and transactions have been elim-inated in consolidation.

USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS

The preparation of financial statements in conformitywith generally accepted accounting principles requiresmanagement to make estimates and assumptions that affectthe reported amounts of assets and liabilities and disclosureof contingent assets and liabilities at the date of the financialstatements, and the reported amounts of revenues andexpenses during the reporting period. Actual amounts coulddiffer from those estimates.

INVENTORIES

Inventories, which consist primarily of tubular goods,parts and supplies, are stated at cost, determined principallyby the average cost method, which is not in excess of net real-izable value.

PROPERTY AND EQUIPMENT

Devon follows the full cost method of accounting forits oil and gas properties. Accordingly, all costs incidental tothe acquisition, exploration and development of oil and gasproperties, including costs of undeveloped leasehold, dryholes and leasehold equipment, are capitalized. Net capital-ized costs are limited to the estimated future net revenues,discounted at 10% per annum, from proved oil, natural gasand natural gas liquids reserves. Such limitations are imposedseparately for Devon’s oil and gas properties in the UnitedStates and Canada. Capitalized costs are depleted by anequivalent unit-of-production method, converting gas andnatural gas liquids to oil at the ratio of one barrel (“Bbl”) ofoil to six thousand cubic feet (“Mcf”) of natural gas and onebarrel of oil to 42 gallons of natural gas liquids. No gain orloss is recognized upon disposal of oil and gas propertiesunless such disposal significantly alters the relationshipbetween capitalized costs and proved reserves.

Devon adopted the provisions of SFAS No. 121,“Accounting for the Impairment of Long-Lived Assets andfor Long-Lived Assets to be Disposed Of,” on January 1,1996. SFAS No. 121 requires that long-lived assets andcertain identifiable intangibles be reviewed for impairmentwhenever events or changes in circumstances indicate that thecarrying amount of an asset may not be recoverable. Due toDevon’s use of the full cost method of accounting for its oiland gas properties, SFAS No. 121 does not apply to Devon’soil and gas property assets which comprise approximately97% of Devon’s net property and equipment. Accordingly,the adoption of SFAS No. 121 did not have an impact onDevon’s financial position or results of operations in 1996.

Depreciation and amortization of other property andequipment, including leasehold improvements, are providedusing the straight-line method based on estimated useful livesfrom 3 to 39 years.

DEFERRED REVENUE

Deferred revenue at the end of 1996 consists primarilyof the unrecognized gain from the termination of an interestrate swap agreement. In prior years, deferred revenueincluded primarily funds received under take-or-pay provi-sions of certain gas contracts, which provided for recovery bythe paying party of certain volumes of gas.


Notes to Consolidated Financial StatementsD E V O N E N E R G Y C O R P O R A T I O N


GAS BALANCING

During the course of normal operations, Devon andother joint interest owners of natural gas reservoirs will takemore or less than their respective ownership share of thenatural gas volumes produced. These volumetric imbalancesare monitored over the lives of the wells’ production capa-bility. If an imbalance exists at the time the wells’ reserves aredepleted, cash settlements are made among the joint interestowners under a variety of arrangements.

Devon follows the sales method of accounting for gasimbalances. A liability is recorded only if Devon’s excess takesof natural gas volumes exceed its estimated remaining recov-erable reserves. No receivables are recorded for those wellswhere Devon has taken less than its ownership share of gasproduction.

STOCK OPTIONS

On January 1, 1996, Devon adopted SFAS No. 123,“Accounting for Stock-Based Compensation,” which permitsentities to recognize over the vesting period the fair value ofall stock-based awards on the date of grant. Alternatively,SFAS No. 123 also allows entities to continue to apply provi-sions of APB No. 25, “Accounting for Stock Issued toEmployees,” whereby compensation expense is recorded onthe date of grant only if the current market price of theunderlying stock exceeds the exercise price. Companies whichcontinue to apply the provisions of APB No. 25 are requiredby SFAS No. 123 to disclose pro forma net earnings and netearnings per share for employee stock option grants made in1995 and future years as if the fair-value-based methoddefined in SFAS No. 123 had been applied. Devon haselected to continue to apply the provisions of APB No. 25,and has provided the pro forma disclosures required by SFASNo. 123 in Note 10.

MAJOR PURCHASERS

During 1996, there was one purchaser, Aquila EnergyMarketing Corporation (“Aquila”), who accounted for over10% of Devon’s gas sales. Aquila accounted for 45% ofDevon’s 1996 gas sales. During 1995, there were twopurchasers who accounted for over 10% of Devon’s gas sales.These two purchasers and their respective share of gas saleswere: Aquila - 31%; and Enron Gas Marketing, Inc.(“Enron”) - 16%. During 1994, there were three purchasers

who accounted for over 10% of Devon’s gas sales. These threepurchasers and their respective share of gas sales were: Aquila- 21%; Enron - 19%; and Meridian Oil Trading, Inc. - 18%.

INCOME TAXES

Devon accounts for income taxes using the asset andliability method, whereby deferred tax assets and liabilities arerecognized for the future tax consequences attributable todifferences between the financial statement carrying amountsof assets and liabilities and their respective tax bases, as wellas the future tax consequences attributable to the futureutilization of existing net operating loss and other types ofcarryforwards. Deferred tax assets and liabilities are measuredusing enacted tax rates expected to apply to taxable income inthe years in which those temporary differences and carryfor-wards are expected to be recovered or settled. The effect ondeferred tax assets and liabilities of a change in tax rates isrecognized in income in the period that includes the enact-ment date.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses are reported netof amounts allocated to working interest owners of the oiland gas properties operated by Devon, net of amountscharged to affiliated partnerships for administrative and over-head costs, and net of amounts capitalized pursuant to thefull cost method of accounting.

NET EARNINGS PER COMMON SHARE

Net earnings per common share assuming no dilutionare based upon the weighted average number of shares ofcommon stock outstanding during the year. Stock optionshave been excluded since they would not have had a signifi-cant dilutive effect, and the Trust Convertible Preferred Secu-rities issued in 1996 are excluded as they are not commonstock equivalents.


For 1996, net earnings per common share assumingfull dilution is based upon the adjusted amount of net earn-ings and the adjusted number of common shares outstandingassuming the Trust Convertible Preferred Securities had beenconverted to common stock as of their issuance date in July1996. The fully diluted per share amount in 1996 alsoincludes the effect of Devon’s outstanding stock options ascalculated using the treasury stock method. The 1996adjusted net earnings used for the fully diluted calculationwas $37.8 million, and the adjusted number of commonshares was 24,860,910.

No fully diluted per share amounts are presented for1995 and 1994 due to the insignificant dilutive effect of thestock options outstanding.

DIVIDENDS

Dividends on common stock were paid in 1994, 1995and the first three quarters of 1996 at a per share rate of$0.03 per quarter. The dividend rate was increased to $0.05per share for the fourth quarter of 1996.

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 Trust Convert-ible Preferred Securities discussed in Note 9. The fair valueand the carrying value for all other financial instruments(cash and equivalents, accounts receivable, accounts payableand long-term debt) are approximately equal. Such equality isdue to the short-term nature of the current assets and liabili-ties and the fact that the interest rates paid on Devon’s long-term debt are set for periods of three months or less.

STATEMENTS OF CASH FLOWS

For purposes of the consolidated statements of cashflows, Devon considers all highly liquid investments withoriginal maturities of three months or less to be cash equiva-lents.

COMMITMENTS AND CONTINGENCIES

Liabilities for loss contingencies arising from claims,assessments, litigation or other sources are recorded when it isprobable that a liability has been incurred and the amountcan be reasonably estimated.

In October, 1996, the American Institute of CertifiedPublic Accountants issued Statement of Position (SOP) 96-1,“Environmental Remediation Liabilities.” SOP 96-1 wasadopted by Devon on January 1, 1997. It requires, amongother things, that environmental remediation liabilities beaccrued when the criteria of SFAS No. 5, “Accounting forContingencies,” have been met. SOP 96-1 also providesguidance with respect to the measurement of the remediationliabilities. Such accounting is consistent with Devon’s methodof accounting for environmental remediation costs. There-fore, adoption of SOP 96-1 will not have a material impacton Devon’s financial position or results of operations.

2 Acquisitions and Pro Forma Information

On December 31, 1996, Devon acquired all of Kerr-McGee Corporation’s (“Kerr-McGee”) North Americanonshore oil and gas exploration and production business andproperties (the “KMG-NAOS Properties”). As consideration,Devon issued 9,954,000 shares of its common stock to Kerr-McGee. The acquisition was made pursuant to an October17, 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 on thevalue of the shares of Devon common stock issued as deter-mined pursuant to generally accepted accounting principles.An additional $28.0 million was allocated to the KMG-NAOS Properties for the deferred income tax liability createdas a result of the substantially tax-free nature of the transac-tion to Kerr-McGee. Excluding the additional deferred taxliability, the amount recorded for the KMG-NAOS Proper-ties includes approximately $191.7 million allocated toproved oil and gas reserves, $29.0 million allocated to unde-veloped leasehold acquired and $0.9 million allocated toinventories and other assets acquired. Including the addi-tional $28.0 million of deferred tax liability, $214.2 millionwas allocated to proved reserves and $34.5 million to unde-veloped leasehold.

Estimated proved reserves associated with the KMG-NAOS Properties as of December 31, 1996, were 47 millionbarrels of oil equivalent (“MMBoe”) in the United States and15 MMBoe in Canada. These reserves are approximately36% oil and natural gas liquids and 64% natural gas.


Included in the acquired reserves were certain proved unde-veloped reserves, for which Devon expects to incur approxi-mately $6 million of future capital costs. The United Statesassets acquired are located predominantly in the RockyMountain, Permian Basin and Mid-Continent areas of thecountry. All of these areas were already core areas of Devon’soperations. (The quantities of proved reserves and the esti-mated development costs stated in this paragraph are unau-dited.)

On December 18, 1995, Devon acquired additionalinterests in certain of its Wyoming oil and natural gas proper-ties and a gas processing plant (the “Worland Properties”) forapproximately $50.3 million. The acquisition was primarilyfunded with $46.0 million of borrowings from Devon’s creditlines. Approximately $46.3 million of the purchase price wasallocated to proved oil, gas and natural gas liquids reservesand the plant. The remaining $4.0 million of the purchaseprice was allocated to undeveloped leasehold.

On February 18, 1994, Devon and Alta EnergyCorporation (“Alta”) entered into an Agreement and Plan ofMerger, as amended on April 13, 1994, whereby Alta wasmerged into a wholly-owned subsidiary of Devon (the “AltaMerger”). The Alta Merger was consummated on May 18,1994, at which date the separate existence of Alta ceased.Alta’s common stockholders received approximately1,168,000 shares of Devon common stock and $1.5 millionin cash upon consummation of the Alta Merger. Subse-quently, in February 1995, former Alta stockholders receivedan additional cash payment of $2.4 million based upon thepost-closing evaluation of the Camille Adams #1 well inLouisiana. Devon also incurred $41.4 million of other costsrelated to the Alta Merger. This included $31.7 million toacquire Alta’s debt from its creditors, $3.0 million to acquireshares of Alta preferred and common stock, $3.8 millionloaned to Alta for operating funds, $1.5 million to acquirecertain net profits interests from Alta creditors, and $1.4million for third party costs related to the Alta Merger.

Devon recorded additional deferred tax liabilities of$11.5 million due to the substantially tax-free nature of theAlta Merger to the former Alta stockholders. Excluding the$11.5 million of additional deferred tax liabilities, approxi-mately $69.4 million of the total consideration involved inthe Alta Merger was allocated to proved oil and gas reserves.Including the deferred tax liabilities, $80.9 million was allo-cated to proved oil and gas reserves. The Alta Merger was

accounted for by the purchase method of accounting forbusiness combinations. Accordingly, the accompanying 1994consolidated statement of operations does not include anyrevenue or expenses associated with Alta prior to the May 18,1994 closing date.

PRO FORMA INFORMATION (UNAUDITED)

The 1996 acquisition of the KMG-NAOS Propertiesas described above was accounted for by the purchase methodof accounting for business combinations. Accordingly, theaccompanying 1996 consolidated statement of operationsdoes not include any revenues or expenses associated with theKMG-NAOS Properties. Following are Devon’s pro formaresults for 1996 assuming the acquisition of the KMG-NAOS Properties occurred on January 1, 1996:

1996

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

Total revenues 297,184,000

COSTS AND EXPENSESLease 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 EXPENSECurrent 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:Assuming no dilution $2.16Assuming full dilution $2.08

Weighted average common shares outstanding 32,086,310

PRODUCTION DATAOil (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 purchase method ofaccounting for business combinations. Accordingly, theaccompanying consolidated statements of operations do notinclude any revenues or expenses related to the Worland

Properties prior to the closing date of December 18, 1995.Following are Devon’s pro forma 1995 results assuming theacquisition of KMG-NAOS Properties and the WorlandProperties both occurred on January 1, 1995:

3 San Juan Basin Transaction

Effective January 1, 1995, Devon and an unrelatedcompany entered into a transaction covering substantially allof Devon’s San Juan Basin coal seam gas properties (the “SanJuan Basin Transaction”). These coal seam gas propertiesrepresented Devon’s largest oil and gas reserve position as ofDecember 31, 1994. The properties’ estimated reserves as ofyear-end 1994 were 199.2 billion cubic feet (“Bcf”) ofnatural gas, or 31% of Devon’s 633.2 equivalent Bcf ofcombined oil and natural gas reserves. In addition to the cashflow and earnings impact normally associated with oil andgas production, these properties also qualify as a “nonconven-tional fuel source” under the Internal Revenue Code of 1986.Consequently, gas produced from these properties throughthe year 2002 qualifies for Section 29 tax credits, which as ofyear-end 1996 were equal to approximately $1.02 per millionBtu (“MMBtu”).

The San Juan Basin Transaction involves approxi-mately 186.2 Bcf, or 93%, of the year-end 1994 coal seamgas reserves, and has four major parts associated with it. First,Devon conveyed to the unrelated party 179 Bcf of the prop-erties’ reserves. However, for financial reporting purposes,Devon retained all of such reserves and their future produc-tion and cash flow through a volumetric production paymentand a repurchase option. Second, Devon conveyed outrightto the unrelated party 7.2 Bcf of reserves for a sales price of$5.2 million. The reserves and future cash flow associatedwith this conveyance were not retained by Devon. Third, and


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 $ 0.66 0.86

the source of the most significant impact of the transaction,Devon receives payments equal to 75% of the Section 29 taxcredits generated by the properties. And fourth, Devonretained a 75% reversionary interest in any reserves in excessof the 186.2 Bcf estimated to exist as of December 31, 1994.Each of these parts of the San Juan Basin Transaction, andtheir effects on Devon’s operations, are described in moredetail in the following paragraphs.

The production payment retained by Devon is equalto 94.05% of the first 143.4 Bcf of gas produced from theproperties, or 134.9 Bcf. As such, Devon continues to recordgas sales and associated production and operating expensesand reserves associated with the production payment.Production from the retained production payment iscurrently estimated to occur over a period of 12 years.

The conveyance of the properties which are notsubject to the retained production payment or the repurchaseoption was accounted for as a sale of oil and gas properties.Accordingly, 7.2 Bcf of gas reserves were removed from totalproved reserves, and the $5.2 million of proceeds reduced thebook value of oil and gas properties. The conveyance to thethird party is limited exclusively to the existing wells drilledas of January 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 properties’ netcash flow through the retained production payment, Devonreceives quarterly payments from the third party equal to


75% of the value of the Section 29 tax credits which aregenerated by production from such properties until theearlier of December 31, 2002, or until the option to repur-chase is exercised. For the years ended December 31, 1996and 1995, Devon received $11.5 million and $13.9 million,respectively, related to the credits. Of these amounts, $10.3million and $12.8 million were recorded as additional gassales in 1996 and 1995, respectively, and $1.2 million and$1.1 million were recorded as an addition to liabilities in1996 and 1995, respectively, as discussed in the followingparagraph. Based on the reserves estimated at December 31,1996, and an assumed annual inflation factor of 2%, Devonestimates it will receive total tax credit payments of approxi-mately $58 million from 1997 through 2002.

Devon has an option to repurchase the properties atany time. The purchase price of such option is equal to thefair market value of the properties at the time the option isexercised, as defined in the transaction agreement, less theproduction payment balance. At closing, Devon received$5.6 million associated with reserves to be produced subse-quent to the term of the production payment. Such amountis included in long-term “other liabilities” on the accompa-nying balance sheet. Since Devon expects to eventually exer-cise its option to repurchase the properties, the liability willbe increased over time to reflect the option purchase price. Asthe purchase price increases, a portion of the tax creditpayments received by Devon will be added to the liability. Asstated above, for the years ended December 31, 1996 and1995, $1.2 million and $1.1 million, respectively, of the totalamount received for tax credit payments were added to theliability, which raised the liability balance to $7.9 million asof December 31, 1996.

Devon has retained a 75% reversionary interest in theproperties’ reserves in excess, if any, of the 186.2 Bcf ofreserves estimated to exist at December 31, 1994. The termsof the transaction provide that the third party will pay 100%of the capital necessary to develop any such incrementalreserves for its 25% interest in such reserves. Devon’s repur-chase option also includes the right to purchase this incre-mental 25%. However, the $7.9 million of other liabilitiesrecorded as of year-end 1996, does not include any amountrelated to such reserves.

4 Supplemental Cash Flow Information

Cash payments for interest in 1996, 1995, and 1994were approximately $5.5 million, $6.7 million and $5.1million, respectively. Cash payments for federal and stateincome taxes in 1996, 1995, and 1994 were approximately$3.4 million, $2.2 million and $1.8 million, respectively.

The 1996 acquisition of the KMG-NAOS Propertiesand the 1994 Alta Merger involved cash and non-cashconsideration as presented below:

1996 1994

Cash payments made $ – 42,915,845Value of common stock issued 221,576,040 21,991,084Liabilities assumed – 7,192,671Deferred tax liability created 28,029,000 11,500,000

Fair value of assets acquired $ 249,605,040 83,599,600

The above cash payments of $42.9 million in 1994include approximately $1.4 million of direct costs paid tothird parties which were capitalized and allocated toproducing oil and gas properties. The cash payments madeare reduced in the accompanying 1994 consolidated state-ment of cash flows by $518,382 of cash acquired in the AltaMerger.


5 Accounts ReceivableThe components of accounts receivable included the following:

December 31, 1996 1995 1994

Oil, gas and natural gas liquids revenue accruals $ 24,200,047 11,169,313 10,973,589Joint interest billings 4,318,764 2,962,037 3,367,493 Income tax refunds due - - 959,085Other 1,461,495 493,945 551,632

29,980,306 14,625,295 15,851,799 Allowance for doubtful accounts (400,000) (225,000) (225,000)

Net accounts receivable $ 29,580,306 14,400,295 15,626,799

6 Property and EquipmentProperty and equipment included the following:

December 31, 1996 1995 1994

Oil and gas properties:Subject to amortization $ 899,827,749 604,227,702 503,174,488Not subject to amortization:

Acquired in 1996 35,141,800 - -Acquired in 1995 5,034,942 5,635,170 -Acquired in 1994 1,001,291 1,001,427 1,451,109Acquired in 1993 5,204,995 5,556,977 5,556,977Acquired in 1992 8,113,899 8,257,985 8,561,031

Accumulated depreciation, depletionand amortization (278,923,340) (237,385,785) (200,746,032)

Net oil and gas properties 675,401,336 387,293,476 317,997,573

Other property and equipment: 20,481,080 6,758,643 5,197,536

Accumulated depreciation andamortization (3,036,070) (2,233,382) (1,888,929)

Net other property and equipment 17,445,010 4,525,261 3,308,607

Property and equipment, net ofaccumulated depreciation,depletion and amortization $ 692,846,346 391,818,737 321,306,180

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


Depreciation, depletion and amortizationof oil and gas properties $ 41,537,555 36,639,753 32,861,174

Depreciation and amortization of otherproperty and equipment 1,337,420 1,045,978 865,092

Amortization of other assets 486,054 404,052 405,884

Total expense $ 43,361,029 38,089,783 34,132,150

7Long-term Debt

Devon has long-term lines of credit pursuant to whichit can borrow up to an amount determined by the banksbased on their evaluation of the assets and cash flow (the“Borrowing Base”) of Devon. The established Borrowing Baseat December 31, 1996, was $260 million. Amountsborrowed under the credit lines bear interest at various fixedrate options which Devon may elect for periods up to 90days. Such rates are generally less than the prime rate. Devonmay also elect to borrow at the prime rate. The averageinterest rates on the outstanding debt at the end of 1996,1995 and 1994, were 6.19%, 6.64% and 6.83%, respectively.The loan agreements also provide for a quarterly facility feeequal to .25% per annum.

Debt borrowed under the credit lines is unsecured. Noprincipal payments are required until maturity unless theunpaid balance exceeds the maximum loan amount. Themaximum loan amount is equal to the Borrowing Base untilAugust 31, 1999. Thereafter, the maximum loan amount willbe reduced by 8.33% every three months until August 31,2002. The loan agreements contain certain covenants andrestrictions, among which are limitations on additionalborrowings and annual sales of properties valued at morethan $25 million, and working capital and net worth mainte-nance requirements. At December 31, 1996, Devon was incompliance with such covenants and restrictions.

On December 31, 1996, Devon established a demandrevolving operating credit facility with a Canadian bank. Thisfacility is unsecured and will be utilized for general corporatepurposes related to Devon’s new Canadian operations. Thecredit line totals $12.5 million Canadian dollars, and interestis charged 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 debt described above,amounts borrowed pursuant to the Canadian credit line areexpected to be classified as long-term debt. No amounts wereborrowed against the Canadian credit line at year-end 1996.

Devon entered into an interest rate swap agreement inJune, 1995, to hedge the impact of interest rate changes on aportion of its long-term debt. The notional amount of theswap agreement was $75 million, and the other party to theagreement was one of Devon’s lenders. The swap agreementwas accounted for as a hedge. On July 1, 1996, Devon termi-nated the interest rate swap agreement for a gain of $0.8million. This gain is being recognized ratably as a reductionto interest expense during the period from July 1, 1996 toJune 16, 1998 (the original expiration date of the agreement).Approximately $0.2 million of the gain was recognized in1996. The fair value of the interest rate swap as of December31, 1995 was a liability of approximately $1.4 million. Theinterest rate swap had no carrying value in the accompanyingconsolidated financial statements.

See Note 9 for a description of certain convertibledebentures issued in 1996 to a Devon affiliate.

8 Income Taxes

At December 31, 1996, Devon had the followingcarryforwards available to reduce future federal and stateincome taxes:

YEARS OF CARRYFORWARDTYPES OF CARRYFORWARD EXPIRATION AMOUNTS

Net operating loss - federal 1998-2008 $ 14,100,000Net operating loss - various states 1997-2010 $ 10,000,000Statutory depletion N/A $ 1,200,000Minimum tax credit N/A $ 5,600,000

All of the carryforward amounts shown above havebeen utilized for financial purposes to reduce deferred taxes.

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


Federal statutory tax rate 35% 35% 35% Nonconventional fuel source credits - (1) -State income taxes 5 4 3Effect of San Juan Basin Transaction 2 4 -Other (1) 1 (2)Effective income tax rate 41% 43% 36%



The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities atDecember 31, 1996, 1995 and 1994 are presented below:

December 31, 1996 1995 1994

Deferred tax assets:Net operating loss carryforwards $ 5,314,000 6,082,000 6,127,000Statutory depletion carryforwards 412,000 2,287,000 3,087,000Investment tax credit carryforwards 42,000 85,000 813,000Minimum tax credit carryforwards 5,624,000 5,576,000 2,195,000Production payments 19,685,000 24,770,000 -Other 2,613,000 1,966,000 897,000

Total gross deferred tax assets 33,690,000 40,766,000 13,119,000Less valuation allowance 100,000 100,000 100,000Net deferred tax assets 33,590,000 40,666,000 13,019,000

Deferred tax liabilities:Property and equipment, principally due

to differences in depreciation, andthe expensing of intangible drillingcosts for tax purposes (113,111,000) (74,369,000) (40,097,000)

Net deferred tax liability $ (79,521,000) (33,703,000) (27,078,000)

As shown in the above schedule, Devon has recognized$33.6 million of net deferred tax assets as of December 31,1996. Such amount consists almost entirely of $11.4 millionof various carryforwards available to offset future incometaxes, and $19.7 million of net tax basis in productionpayments. The carryforwards include federal net operatingloss carryforwards, the majority of which do not begin toexpire until 2006, state net operating loss carryforwardswhich expire primarily between 1999 and 2003, and thestatutory depletion and minimum tax credit carryforwardswhich have no expiration dates. The tax benefits of carryfor-wards are recorded as an asset to the extent that managementassesses the utilization of such carryforwards to be “morelikely than not.” When the future utilization of some portionof the carryforwards is determined not to be “more likelythan not”, a valuation allowance is provided to reduce therecorded tax benefits from such assets.

Devon expects the tax benefits from the net operatingloss carryforwards to be utilized between 1997 and 1999.Such expectation is based upon current estimates of taxableincome during this period, considering limitations on theannual utilization of these benefits as set forth by federal taxregulations. Significant changes in such estimates caused byvariables such as future oil and gas prices or capital expendi-tures could alter the timing of the eventual utilization of suchcarryforwards. There can be no assurance that Devon will

generate any specific level of continuing taxable earnings.However, management believes that Devon’s future taxableincome will more likely than not be sufficient to utilizesubstantially all its tax carryforwards prior to their expiration.A $100,000 valuation allowance has been recorded atDecember 31, 1996, related to depletion carryforwardsacquired in the Alta Merger.

The $19.7 million of deferred tax assets related toproduction payments is offset by a portion of the deferred taxliability related to the excess financial basis of property andequipment. The income tax accounting for the San JuanBasin Transaction described in Note 3 differs from the finan-cial accounting treatment which is described in such note.For income tax purposes, a gain from the conveyance of theproperties was realized, and the present value of the produc-tion payments to be received was recorded as a note receiv-able. For presentation purposes, the $19.7 million representsthe tax effect of the difference in accounting for the produc-tion payment, less the effect of the taxable gain from thetransaction which is being deferred and recognized on theinstallment basis for income tax purposes.


9 Trust Convertible Preferred Securities

On July 10, 1996, Devon, through its newly-formedaffiliate Devon Financing Trust, completed the issuance of$149.5 million of 6.5% trust convertible preferred securities(the “TCP Securities”) in a private placement. DevonFinancing Trust issued 2,990,000 shares of the TCP Securi-ties at $50 per share. Each TCP Security is convertible at theholder’s option into 1.6393 shares of Devon common stock,which equates to a conversion price of $30.50 per share ofDevon common stock.

Devon Financing Trust invested the $149.5 million ofproceeds in 6.5% convertible junior subordinated debenturesissued by Devon (the “Convertible Debentures”). In turn,Devon used the net proceeds from the issuance of theConvertible Debentures to retire debt outstanding under itscredit lines.

The sole assets of Devon Financing Trust are theConvertible Debentures. The Convertible Debentures andthe related TCP Securities mature on June 15, 2026.However, Devon and Devon Financing Trust may redeem theConvertible Debentures and the TCP Securities, respectively,in whole or in part, on or after June 18, 1999. For the firsttwelve months thereafter, redemptions may be made at104.55% of the principal amount. This premium declinesproportionally every twelve months until June 15, 2006,when the redemption price becomes fixed at 100% of theprincipal amount. If Devon redeems any Convertible Deben-tures prior to the scheduled maturity date, Devon FinancingTrust must redeem TCP Securities having an aggregate liqui-dation amount equal to the aggregate principal amount ofConvertible Debentures so redeemed.

Devon has guaranteed the payments of distributionsand other payments on the TCP Securities only if and to theextent that Devon Financing Trust has funds availabletherefor. Such guarantee, when taken together with Devon’sobligations under the Convertible Debentures and relatedindenture and declaration of trust, provide a full and uncon-ditional guarantee of amounts due on the TCP Securities.

Devon owns all the common securities of DevonFinancing Trust. As such, the accounts of Devon FinancingTrust are included in Devon’s consolidated financial state-ments after appropriate eliminations of intercompany

balances. The distributions on the TCP Securities arerecorded as a charge to pre-tax earnings on Devon’s consoli-dated statements of operations, and such distributions aredeductible by Devon for income tax purposes.

Devon estimates that the fair value of the TCP Securi-ties as of December 31, 1996 was approximately $196.6million, as compared to the book value of $149.5 million.This fair value was based on quoted prices at which TCPSecurities were purchased and sold on December 31, 1996.

10 Stockholders’ Equity

The authorized capital stock of Devon consists of 400million shares of common stock, par value $.10 per share(the “Common Stock”), and three million shares of preferredstock, par value $1.00 per share (the “Preferred Stock”). ThePreferred Stock may be issued in one or more series, and theterms and rights of such stock will be determined by theBoard of Directors.

Devon’s Board of Directors has designated 150,000shares of the Preferred Stock as Series A Junior ParticipatingPreferred Stock (the “Series A Preferred Stock”) in connectionwith the adoption of the share rights plan described later inthis note. At December 31, 1996, there were no shares ofSeries A Preferred Stock issued or outstanding. The Series APreferred Stock is entitled to receive cumulative quarterlydividends per share equal to the greater of $10 or 100 timesthe aggregate per share amount of all dividends (other thanstock dividends) declared on Common Stock since the imme-diately preceding quarterly dividend payment date or, withrespect to the first payment date, since the first issuance ofSeries A Preferred Stock. Holders of the Series A PreferredStock are entitled to 100 votes per share (subject to adjust-ment to prevent dilution) on all matters submitted to a voteof the stockholders. The Series A Preferred Stock is neitherredeemable nor convertible. The Series A Preferred Stockranks prior to the Common Stock but junior to all otherclasses of Preferred Stock.

STOCK OPTION PLANS

Devon has outstanding stock options issued to keymanagement and professional employees under two stockoption plans adopted in 1988 and 1993 (“the 1988 Plan”and “the 1993 Plan”). Options granted under the 1988 Planremain exercisable by the employees owning such options,but no new options will be granted under the 1988 Plan. AtDecember 31, 1996, 15 participants held the 303,400options outstanding under the 1988 Plan.

Effective June 7, 1993, Devon adopted the 1993 Planand reserved one million shares of Common Stock forissuance thereunder. Twenty-two employees were eligible toparticipate in the 1993 Plan at year-end 1996.

The exercise price of incentive stock options grantedunder the 1993 Plan may not be less than the estimated fairmarket value of the stock at the date of grant, plus 10% ifthe grantee owns or controls more than 10% of the totalvoting stock of Devon prior to the grant. The exercise price

of nonqualified options granted under the 1993 Plan maynot be less than 75% of the fair market value of the stock onthe date of grant. Options granted are exercisable during aperiod established for each grant, which period may notexceed 10 years from the date of grant. Under the 1993 Plan,the grantee must pay the exercise price in cash or inCommon Stock, or a combination thereof, at the time thatthe option is exercised. The 1993 Plan is administered by acommittee comprised of non-management members of theBoard of Directors. The 1993 Plan expires on April 25,2003. As of December 31, 1996, 23 participants held the898,600 options outstanding under the 1993 Plan. Therewere 88,700 options available for future grants as ofDecember 31, 1996.

A summary of the status of Devon’s stock option plansas of December 31, 1994, 1995 and 1996, and changesduring each of the years then ended, is presented below:


Options Outstanding Options Exercisable WEIGHTED WEIGHTEDAVERAGE AVERAGE

NUMBER EXERCISE NUMBER EXERCISE OUTSTANDING PRICE EXERCISABLE PRICE

Balance at December 31, 1993 482,700 $ 16.521 300,000 $ 14.848

Options granted 436,000 $ 20.736Options exercised (40,800) $ 9.355

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

The weighted average fair values of options granted during 1996 and 1995 were $12.97 and $9.89, respectively. The fairvalue of each option grant was estimated for disclosure purposes only on the date of grant using the Binomial Option PricingModel with the following assumptions for 1996 and 1995, respectively: risk-free interest rates of 6.3% and 5.5%; dividendyields of 0.6% and 0.5%; expected lives of 5 and 5 years; and volatility of the price of the underlying common stock of 33.9%and 38.1%.


The following table summarizes information about Devon’s stock options which were outstanding, and those which wereexercisable, as of December 31, 1996:

Options Outstanding Options Exercisable WEIGHTED WEIGHTED WEIGHTED

RANGE OF AVERAGE AVERAGE AVERAGEEXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE

$8 to $14 108,600 4.6 years $ 9.662 108,600 $ 9.662$18 to $21 205,700 7.9 years $ 18.088 146,400 $ 18.092$23 to $26 644,200 7.7 years $ 23.784 487,800 $ 23.816$32 to $33 243,500 10.0 years $ 32.500 80,700 $ 32.500

1,202,000 7.9 years $ 23.299 823,500 $ 21.783

Had Devon elected the fair value provisions of SFASNo. 123 and recognized compensation expense based on thefair value of the stock options granted as of their grant date,Devon’s 1996 and 1995 pro forma net earnings and proforma net earnings per share would have differed from theamounts actually reported as shown in the table below. Thepro forma amounts shown below do not include the effectsof stock options granted prior to January 1, 1995. The proforma effects shown below may not be representative of theeffects reported in future years.

Year Ended December 31, 1996 1995

Net earnings:As reported $ 34,800,532 14,501,899Pro forma $ 34,016,571 13,540,052

Net earnings per share:As reported:

Assuming no dilution $1.57 0.66Assuming full dilution $1.52 0.66

Pro forma:Assuming no dilution $1.54 0.61Assuming full dilution $1.49 0.61

SHARE RIGHTS PLAN

Under Devon’s share rights plan, stockholders haveone right for each share of Common Stock held. The rightsbecome exercisable and separately transferable ten businessdays after a) an announcement that a person has acquired, orobtained the right to acquire, 15% or more of the votingshares outstanding, or b) commencement of a tender orexchange offer that could result in a person owning 15% ormore of the voting shares outstanding.

Each right entitles its holder (except a holder who isthe acquiring person) to purchase either a) 1/100 of a shareof Series A Preferred Stock for $75.00, subject to adjustment

or b) Devon Common Stock with a value equal to twice theexercise price of the right, subject to adjustment to preventdilution. In the event of certain merger or asset sale transac-tions with another party or transactions which would increasethe equity ownership of a shareholder who then owned 15%or more of Devon, each Devon right will entitle its holder topurchase securities of the merging or acquiring party with avalue equal to twice the exercise price of the right.

The rights, which have no voting power, expire onApril 16, 2005. The rights may be redeemed by Devon for$.01 per right until the rights become exercisable.

11 Retirement Plans

Devon has a defined benefit retirement plan (the“Basic Plan”) which is non-contributory and includesemployees meeting certain age and service requirements. Thebenefits are based on the employee’s years of service andcompensation. Devon’s funding policy is to contribute annu-ally the maximum amount that can be deducted for federalincome tax purposes. Rights to amend or terminate the BasicPlan are retained by Devon.

Effective January 1, 1995, Devon has a separatedefined benefit retirement plan (the “Supplementary Plan”)which is non-contributory and includes only certainemployees whose benefits under the Basic Plan are limited byfederal income tax regulations. The Supplementary Plan’sbenefits are based on the employee’s years of service andcompensation. Devon’s funding policy for the SupplementaryPlan is to fund the benefits as they become payable. Rights toamend or terminate the Supplementary Plan are retained byDevon.


The following table sets forth the aggregate funded status of the Basic Plan and related amounts recognized in Devon’sbalance sheets:

December 31, 1996 1995 1994

Actuarial present value of benefit obligations:Accumulated benefit obligation:

Vested $ (3,619,000) (3,500,000) (2,648,000)Nonvested (741,000) (654,000) (282,000)Total $ (4,360,000) (4,154,000) (2,930,000)

Projected benefit obligation for servicerendered to date $ (5,122,000) (4,782,000) (3,378,000)

Plan assets at fair value, primarily investments in mutual funds 5,022,000 4,227,000 3,252,000

Plan assets less than projected benefit obligation (100,000) (555,000) (126,000)Unrecognized prior service cost (benefit) (131,000) (154,000) (176,000)Unrecognized net loss from past experience

different from that assumed, and effectsof changes in assumptions 519,000 921,000 225,000

Prepaid (accrued) pension expense $ 288,000 212,000 (77,000)

The following table sets forth the aggregate fundedstatus of the Supplementary Plan and related amounts recog-nized in Devon’s balance sheet as of December 31, 1996 and1995:

December 31, 1996 1995

Actuarial present value of benefit obligations:Accumulated benefit obligation:

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

Projected benefit obligation for service rendered to date $ (2,907,000) (2,245,000)

Plan assets at fair value - -Plan assets less than projected

benefit obligation (2,907,000) (2,245,000)Unrecognized prior service cost 1,235,000 1,354,000Unrecognized net loss from past

experience different from that assumed, and effects of changesin assumptions 446,000 185,000

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

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

The $2.2 million and $1.9 million total pensionliability of the Supplementary Plan as of December 31, 1996and 1995, respectively, are included in long-term other liabil-ities on the accompanying consolidated balance sheets. Theadditional minimum liabilities of $1.0 million and $1.2million at year-end 1996 and 1995, respectively, are offset by

intangible assets of $1.0 million in 1996 and $1.2 million in1995. These intangible assets are included in other assets onthe balance sheets.

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


Service cost - benefits earned during the period $ 557,000 362,000 277,000

Interest cost on projected benefit obligation 569,000 446,000 284,000

Actual return on plan assets (453,000) (536,000) (20,000)Net amortization and deferral 231,000 345,000 (231,000)Net periodic pension expense $ 904,000 617,000 310,000

The weighted average discount rate used in deter-mining the actuarial present value of the projected benefitobligation in 1996, 1995 and 1994 was 7.5%, 7.25% and8.5%, respectively. The rate of increase in future compensa-tion levels was 5% for all three years. The expected long-termrate of return on assets was 8.5%, 8.5% and 8% in 1996,1995 and 1994, respectively.

Devon has a 401(k) Incentive Savings Plan whichcovers all employees. At its discretion, Devon may match acertain percentage of the employees’ contributions to theplan. The matching percentage is determined annually by theBoard of Directors. Devon’s matching contributions to theplan were $188,000, $170,000 and $158,000 for the yearsended December 31, 1996, 1995 and 1994, respectively.


12 Commitments and Contingencies

Devon is party to various legal actions arising in thenormal course of business. Matters that are probable of unfa-vorable outcome to Devon and which can be reasonably esti-mated are accrued. Such accruals are based on informationknown about the matters, Devon’s estimates of the outcomesof such matters and its experience in contesting, litigatingand settling similar matters. None of the actions are believedby management to involve future amounts that would bematerial after consideration of recorded accruals.

The majority of Devon’s sales of nonconventional gasfrom the San Juan Basin are subject to federal royaltiesadministered and collected by the Minerals ManagementService (“MMS”). In determining royalties payable to theMMS, Devon has followed the industry practice of reducingthe gas sales price for certain permitted costs related to thetransportation of gas produced and CO2 removal. In 1995,the MMS issued new policies which would increase Devon’sshare of federal royalties for nonconventional gas producedand sold in the San Juan Basin for the years 1990 through1996, and for future years as well. In early 1997, the MMSasserted a claim for additional royalties. While the specificclaim only covers 17 months of the seven-year period inquestion, the MMS has requested Devon to calculate and payadditional royalties for the entire seven-year period usingmethods and procedures consistent with the calculation forthe 17 months. Devon has not determined whether it agreeswith the methods and procedures used by the MMS in itscalculations, and Devon intends to vigorously contest anyclaim for excessive additional federal royalties through avail-able administrative and judicial processes. However, Devonhas accrued an estimate of additional federal royalties relatedto its share of gas produced from 1990 through 1996.Devon’s management, in consultation with legal counsel,believes adequate provision has been made for any additionalfederal royalties due and related interest. The amount accruedrepresents Devon’s best estimate based on Devon’s interpreta-tion of the new policies issued and all other related informa-tion available to Devon. It is possible that a differentinterpretation of the policies and related facts could result inan assessment higher than what Devon has accrued.

However, Devon’s management does not believe that theamount of possible assessments above that already accruedwould be material.

In a matter unrelated to the MMS issue discussedabove, the State of New Mexico on December 29, 1995,assessed Devon and other producers of gas from the San JuanBasin a “natural gas processors tax.” Devon’s tax assessmentfor the years 1990 through 1995 was approximately $0.6million, and the state also assessed another $0.3 million ofpenalties and interest. All of the assessment relates tononconventional gas. Devon paid these assessments inJanuary 1996, as well as an additional $0.2 million for 1996taxes which were paid monthly throughout the year, so that itcould begin the necessary procedures of applying for arefund. This tax historically was paid by the owners ofnatural gas processing plants, not the gas producers, and wasassessed for the privilege of processing natural gas. WhileDevon’s nonconventional gas is purified through a plant priorto the actual sales point, such purification is only for thepurpose of removing CO2. Also, Devon does not own aninterest in such plant. For these and other reasons, Devondoes not believe the assessment of the additional tax and therelated penalties and interest is valid. If the amount paid isnot refunded through the normal administrative processesavailable, Devon intends to file a suit asking that the assess-ments be reversed. At this time, it is not possible to deter-mine the eventual outcome of this matter. Devon has notexpensed in its financial statements the taxes, penalties andinterest paid, but rather has recorded the $1.1 million total asa receivable.

The following is a schedule by year of futureminimum rental payments required under operating leasesthat have initial or remaining noncancelable lease terms inexcess of one year as of December 31, 1996:

Year Ending December 31,

1997 $ 233,0001998 183,0001999 138,0002000 123,000

Total minimum lease payments required $ 677,000

13 Oil and Gas OperationsCOSTS INCURRED

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

TOTAL Year Ended December 31, 1996 1995 1994

Property acquisition costs:Proved, excluding deferred income taxes $ 199,655,000 47,316,000 70,376,000Deferred income taxes 22,557,000 - 11,500,000Total proved, including deferred income taxes $ 222,212,000 47,316,000 81,876,000

Unproved, excluding deferred income taxes $ 29,673,000 4,529,000 1,797,000Deferred income taxes 5,472,000 - -Total unproved, including deferred income taxes $ 35,145,000 4,529,000 1,797,000

Exploration costs $ 2,708,000 7,174,000 5,194,000Development costs $ 73,468,000 56,253,000 26,268,000

DOMESTIC Year Ended December 31, 1996 1995 1994

Property acquisition costs:Proved, excluding deferred income taxes $ 150,546,000 47,316,000 70,376,000Deferred income taxes 15,257,000 - 11,500,000Total proved, including deferred income taxes $ 165,803,000 47,316,000 81,876,000

Unproved, excluding deferred income taxes $ 26,073,000 4,529,000 1,797,000Deferred income taxes 5,472,000 - -Total unproved, including deferred income taxes $ 31,545,000 4,529,000 1,797,000

Exploration costs $ 2,708,000 7,174,000 5,194,000Development costs $ 73,468,000 56,253,000 26,268,000

CANADA Year Ended December 31, 1996 1995 1994

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

Unproved $ 3,600,000 - -Exploration costs $ - - -Development costs $ - - -


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

1996 $ 572,1771995 $ 546,3881994 $ 521,769


Pursuant to the full cost method of accounting, Devoncapitalizes certain of its general and administrative expenseswhich are related to property acquisition, exploration anddevelopment activities. Such capitalized expenses, which areincluded in the costs shown in the above tables, were $2.9million, $2.7 million and $2.3 million in the years 1996,1995 and 1994, respectively.

Due to the substantially tax-free nature of the acquisi-tion of the KMG-NAOS properties to Kerr-McGee, and ofthe 1994 Alta Merger to the former Alta stockholders, Devonrecorded additional deferred tax liabilities of $28.0 millionrelated to the KMG-NAOS acquisition and $11.5 millionrelated to the Alta Merger. As shown in the above tables, thedeferred tax liabilities caused an additional $22.5 million and$11.5 million to be allocated to proved oil and gas reserves in1996 and 1994, respectively, and an additional $5.5 millionto be allocated to unproved properties in 1996.

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

The following tables include revenues and expensesassociated directly with Devon’s oil and gas producing activi-ties. They do not include any allocation of Devon’s interestcosts or general corporate overhead and, therefore, are notnecessarily indicative of the contribution to net earnings ofDevon’s oil and gas operations. Income tax expense has beencalculated by applying statutory income tax rates to oil andgas sales after deducting costs, including depreciation, deple-tion and amortization and after giving effect to permanentdifferences. For the three year period ended December 31,1996, Devon had no oil and gas producing activities outsidethe United States.


Oil, gas and natural gas liquids sales $ 162,558,000 112,425,000 99,366,000Production and operating expenses (42,226,000) (34,121,000) (31,421,000)Depreciation, depletion and amortization (41,538,000) (36,640,000) (32,861,000)Income tax expense (27,796,000) (15,536,000) (12,411,000)Results of operations for oil and gas

producing activities $ 50,998,000 26,128,000 22,673,000Depreciation, depletion and amortization

per equivalent barrel of production $3.88 3.65 3.45

14 Supplemental Information on Oil and Gas Operations (Unaudited)

The following supplemental unaudited informationregarding the oil and gas activities of Devon is presentedpursuant to the disclosure requirements promulgated by theSecurities and Exchange Commission and Statement ofFinancial Accounting Standards No. 69, “Disclosures AboutOil and Gas Producing Activities”.

QUANTITIES OF OIL AND GAS RESERVES

Set forth below is a summary of the changes in the netquantities of crude oil, natural gas and natural gas liquidsreserves for each of the three years ended December 31,1996. Approximately 94%, 92% and 91%, of the respectiveyear-end 1996, 1995 and 1994 domestic proved reserves werecalculated by the independent petroleum consultantsLaRoche Petroleum Consultants, Ltd. The remainingpercentages of domestic reserves are based on Devon’s ownestimates. All of the 1996 Canadian proved reserves werecalculated by the independent petroleum consultants AMHGroup Ltd.


NATURALOIL GAS GAS LIQUIDS

TOTAL (BBLS) (MCF) (BBLS)

Proved reserves as of December 31, 1993 14,897,000 369,254,000 1,854,000Revisions of estimates 3,157,000 (5,540,000) 1,733,000Extensions and discoveries 2,008,000 13,206,000 183,000Purchase of reserves 25,201,000 13,492,000 2,181,000Production (2,467,000) (39,335,000) (501,000)Sale of reserves (631,000) (3,517,000) (8,000)

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 12,579,000Proved developed reserves as of:

December 31, 1993 11,548,000 355,536,000 1,751,000December 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 11,212,000


DOMESTIC (BBLS) (MCF) (BBLS)

Proved reserves as of December 31, 1993 14,897,000 369,254,000 1,854,000Revisions of estimates 3,157,000 (5,540,000) 1,733,000Extensions and discoveries 2,008,000 13,206,000 183,000Purchase of reserves 25,201,000 13,492,000 2,181,000Production (2,467,000) (39,335,000) (501,000)Sale of reserves (631,000) (3,517,000) (8,000)

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 11,695,000Proved developed reserves as of:

December 31, 1993 11,548,000 355,536,000 1,751,000December 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 10,328,000



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 40,858,000 884,000Proved developed reserves as of

December 31, 1996 7,530,000 40,858,000 884,000

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The accompanying tables reflect the standardized measure of discounted future net cash flows relating to Devon’s interestin proved reserves:

TOTAL December 31, 1996 1995 1994

Future cash inflows $ 3,989,582,000 1,476,418,000 1,186,845,000Future costs:

Development (54,133,000) (52,327,000) (75,115,000)Production (1,071,913,000) (496,279,000) (400,676,000)

Future income tax expense (785,702,000) (153,431,000) (71,427,000)

Future net cash flows 2,077,834,000 774,381,000 639,627,00010% discount to reflect timing of cash flows (901,617,000) (328,481,000) (281,421,000)

Standardized measure of discounted future net cash flows $ 1,176,217,000 445,900,000 358,206,000

Discounted future net cash flows before income taxes $ 1,621,992,000 534,248,000 398,206,000

DOMESTIC December 31, 1996 1995 1994

Future cash inflows $ 3,712,956,000 1,476,418,000 1,186,845,000Future costs:

Development (54,064,000) (52,327,000) (75,115,000)Production (1,013,750,000) (496,279,000) (400,676,000)

Future income tax expense (713,182,000) (153,431,000) (71,427,000)

Future net cash flows 1,931,960,000 774,381,000 639,627,00010% discount to reflect timing of cash flows (846,174,000) (328,481,000) (281,421,000)

Standardized measure of discounted future net cash flows $ 1,085,786,000 445,900,000 358,206,000

Discounted future net cash flows before income taxes $ 1,486,603,000 534,248,000 398,206,000

CANADA December 31, 1996 1995 1994

Future cash inflows $ 276,626,000 - -Future costs:

Development (69,000) - -Production (58,163,000) - -

Future income tax expense (72,520,000) - -

Future net cash flows 145,874,000 - -10% discount to reflect timing of cash flows (55,443,000) - -

Standardized measure of discounted future net cash flows $ 90,431,000 - -

Discounted future net cash flows before income taxes $ 135,389,000 - -

Future cash inflows are computed by applying year-end prices (averaging $24.52 per barrel of oil, adjusted fortransportation and other charges, $3.35 per Mcf of gas and$23.34 per barrel of natural gas liquids at December 31,1996) to the year-end quantities of proved reserves, except inthose instances where fixed and determinable price changesare provided by contractual arrangements in existence at year-end. In addition to the future gas revenues calculated at$3.35 per Mcf, Devon’s total future gas revenues also includethe future tax credit payments to be received and recorded asgas revenues pursuant to the San Juan Basin Transactiondescribed in Note 3. Devon’s future total and domestic cashinflows shown in the tables above include $48.7 millionrelated to these tax credit payments from 1997 through2002. This amount has been calculated using the assumptionthat the year-end 1996 tax credit rate of $1.02 per MMBturemains constant.

Future development and production costs arecomputed by estimating the expenditures to be incurred indeveloping and producing proved oil and gas reserves at theend of the year, based on year-end costs and assumingcontinuation of existing economic conditions.

Future income tax expenses are computed by applyingthe appropriate statutory tax rates to the future pretax netcash flows relating to proved reserves, net of the tax basis ofthe properties involved. The future income tax expenses giveeffect to permanent differences and tax credits, but do not

reflect the impact of future operations. Prior to the San JuanBasin Transaction as described in Note 3, the future incometax expenses estimated at December 31, 1994 were reducedby the estimated future Section 29 tax credits to be generatedby the San Juan Basin coal seam gas properties. It was esti-mated at year-end 1994 that undiscounted amounts ofapproximately $113 million of Section 29 tax credits couldbe generated in future years to Devon’s interest. However,because of limitations on the amount of Section 29 taxcredits which can actually be utilized for income taxpurposes, the undiscounted amounts included as reductionsto future income tax expense for purposes of calculating thestandardized measure of discounted future net cash flowswere only $41 million at year-end 1994. As a result of theSan Juan Basin Transaction, substantially all of the value ofthe Section 29 tax credits at year-end 1996 and 1995 is nowincluded in “future cash inflows,” instead of a reduction toincome tax expense, in Devon’s standardized measure ofdiscounted future net cash flows.

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:



Beginning balance $ 445,900,000 358,206,000 343,550,000Sales of oil, gas and natural gas liquids, net of production costs (120,332,000) (78,304,000) (67,945,000)Net changes in prices and production costs 519,456,000 60,498,000 (107,210,000)Extensions, discoveries, and improved recovery, net of future

development costs 42,522,000 22,308,000 14,629,000Purchase of reserves, net of future development costs 576,234,000 50,000,000 133,103,000Development costs incurred during the period which

reduced future development costs 44,332,000 43,810,000 16,519,000Revisions of quantity estimates 40,905,000 7,397,000 26,167,000Sales of reserves in place (6,499,000) (7,933,000) (5,281,000)Accretion of discount 53,425,000 39,821,000 38,047,000Net change in income taxes (357,427,000) (48,347,000) (3,080,000)Other, primarily changes in timing (62,299,000) (1,556,000) (30,293,000)Ending balance $ 1,176,217,000 445,900,000 358,206,000

15 Supplemental Quarterly Financial Information (Unaudited)

Following is a summary of the unaudited interim results of operations for the years ended December 31, 1996 and 1995:

FIRST SECOND THIRD FOURTH1996 QUARTER QUARTER QUARTER QUARTER TOTAL

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

Assuming no dilution $0.25 0.31 0.35 0.66 1.57Assuming full dilution $0.25 0.31 0.35 0.59 1.52

FIRST SECOND THIRD FOURTH1995 - ACTUAL REPORTED RESULTS (a) QUARTER QUARTER QUARTER QUARTER TOTAL

Oil, gas and natural gas liquids sales $ 23,519,568 25,331,966 33,589,019 29,985,087 112,425,640Total revenues $ 23,762,327 25,650,334 33,770,864 30,119,300 113,302,825Net earnings $ 1,026,802 2,444,422 6,645,531 4,385,144 14,501,899Net earnings per share $0.05 0.11 0.30 0.20 0.66

FIRST SECOND THIRD FOURTH1995 - ADJUSTED RESULTS (a) QUARTER QUARTER QUARTER QUARTER TOTAL

Oil, gas and natural gas liquids sales $ 26,478,770 28,293,715 27,668,068 29,985,087 112,425,640Total revenues $ 26,796,579 28,612,083 27,774,863 30,119,300 113,302,825Net earnings $ 2,864,127 4,181,531 3,071,097 4,385,144 14,501,899Net earnings per share $0.13 0.19 0.14 0.20 0.66

(a) The San Juan Basin Transaction described in Note 3 was effective January 1, 1995. However, it was initially subject to a material contingency, and thusthe transaction’s impact on Devon’s statement of operations was deferred pending the contingency’s resolution. When the contingency was favorably resolved, thecumulative nine-month effect of the transaction was recorded in the third quarter. The second table above includes the 1995 quarterly results as reported, includingthe six-month out-of-period effect on the third quarter. The third table above presents the 1995 quarterly results as they would have been reported had the contingencynot existed and had the San Juan Basin Transaction’s effect on earnings been reported from the inception of the transaction on January 1, 1995. ■


JOHN W. NICHOLS , co-founder of Devon, hasbeen chairman of the board of directors sinceDevon began operations in 1971. He is afounding partner of Blackwood & NicholsCo., which developed the conventionalreserves in the Northeast Blanco Unit of theSan Juan Basin. Mr. Nichols is a non-prac-ticing certified public accountant.

J. LARRY NICHOLS is a co-founder of Devon.He has been a director since 1971, presidentsince 1976 and chief executive officer since1980. Mr. Nichols serves as a director of theIndependent Petroleum Association of Americaand chairs its Public Lands Committee. He ispresident of the Domestic Petroleum Counciland is also a director of the Independent Petro-

leum Association of New Mexico, the Oklahoma Independent Petro-leum Association and the National Petroleum Council. He also servesas a director of the National Association of Manufacturers and of theOklahoma Nature Conservancy. Mr. Nichols holds a geology degreefrom Princeton University and a law degree from the University ofMichigan. He served as a law clerk to Mr. Chief Justice Earl Warrenand Mr. Justice Tom Clark of the U.S. Supreme Court.

LUKE R. CORBETT was elected to the board ofdirectors in December 1996. Mr. Corbett ischairman of the board and chief executiveofficer of Kerr-McGee Corporation. He joinedKerr-McGee in 1985 and held various execu-tive positions prior to being elected to hispresent position in 1997. He is a director ofOGE Energy Corporation and the American

Petroleum Institute. He is a member of the American Association ofPetroleum Geologists, the Society of Exploration Geophysicists, andthe Domestic Petroleum Council. He is trustee for the AmericanGeological Institute Foundation and is chairman of the advisoryboard of the Energy & Geoscience Institute at the University of Utah.

THOMAS F. FERGUSON has been a director ofDevon since 1982, and is the chair of theAudit Committee. He is managing director ofEnglewood, N.V., a wholly owned subsidiaryof Kuwait-based Al-Futtooh InvestmentsWLL. Mr. Ferguson represents them on theboard of directors of Devon and other compa-nies. Mr. Ferguson is a Canadian qualified

certified general accountant and was formerly employed by the Econ-omist Intelligence Unit of London.

DAVID M. GAVRIN has been a director of Devonsince 1979, and serves as the chair of theCompensation and Stock Option Committee.He serves as a director of Heidemij, N.V., aworldwide environmental services company;New York Federal Savings Bank; and UnitedAmerican Energy Corp., an independent

power producer. In addition, Mr. Gavrin was associated with DrexelBurnham Lambert Incorporated for 14 years as first vice president,and he was a general partner of Windcrest Partners, an investmentpartnership, for 10 years.

MICHAEL E. GELLERT has been a director ofDevon since 1971 and is a member of theCompensation and Stock Option Committee.Mr. Gellert serves as a director of Humana,Inc., Premier Parks, Inc., Seacor Holdings,Inc., and Regal Cinemas, Inc. Mr. Gellert isalso a member of the Putnam Trust CompanyAdvisory Board to The Bank of New York. He

was associated with the Drexel Burnham Lambert Group and itspredecessors for 31 years, including 17 years as a director, and servedin various executive capacities for its wholly owned subsidiary, DrexelBurnham Lambert Incorporated.

TOM J. MCDANIEL was elected to the board ofdirectors in December 1996. Mr. McDanielhas been Kerr-McGee’s vice chairman of theboard since February 1, 1997. He has servedas a senior vice president and corporate secre-tary of Kerr-McGee since 1989. He joinedKerr-McGee as associate general counsel in1984. In 1981, he was appointed administra-

tive director of State Courts by the Oklahoma Supreme Court. Mr.McDaniel serves on the board of directors of the National Associationof Manufacturers. A member of the Oklahoma and American BarAssociations, Mr. McDaniel holds degrees from Northwestern Okla-homa State University and the University of Oklahoma.

H. R. SANDERS, JR. has been a director andexecutive vice president of Devon since 1981.Prior to joining Devon, Mr. Sanders was asso-ciated with Republic Bank Dallas, N.A.,serving as its senior vice president with respon-sibility for independent oil and gas producerand mining loans. Mr. Sanders is a member ofthe Independent Petroleum Association of

America, Texas Independent Producers and Royalty Owners Associa-tion and the Oklahoma Independent Petroleum Association.

LAWRENCE H. TOWELL was elected to theboard of directors in December 1996. Mr.Towell has, since 1984, been vice president ofacquisitions in Kerr-McGee’s Exploration andProduction Division. He has served Kerr-McGee in various executive positions since1975. Mr. Towell holds a bachelor’s degree inmechanical engineering from Yale University.

He is a member of the Society of Petroleum Engineers, the Indepen-dent Petroleum Association of America, and the Yale UniversityScience and Engineering Association.


Board of Directors


J. MICHAEL LACEY joined Devon as vice presi-dent of operations and exploration in 1989.Prior to his employment with Devon, Mr.Lacey served as general manager in TennecoOil Company’s Mid-Continent and RockyMountain Divisions. He holds both under-graduate and graduate degrees in petroleumengineering from the Colorado School of

Mines. Mr. Lacey is a registered professional engineer, and he is amember of the Society of Petroleum Engineers and the AmericanAssociation of Petroleum Geologists.

DARRYL G. SMETTE, vice president of market-ing and administrative planning since 1989,joined Devon in 1986 as manager of gas mar-keting. Mr. Smette’s educational backgroundincludes an undergraduate degree from MinotState College and a master’s degree fromWichita State University. His marketing back-ground includes 15 years with Energy Reserves

Group, Inc./BHP Petroleum (Americas), Inc., the last position beingdirector 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, vice president of corporatedevelopment, has been responsible for Devon’scorporate finance and capital formation activi-ties since 1982. In 1981, he served as execu-tive vice president of Palo Pinto/HarkenDrilling Programs. For the six prior years, hewas associated with Merrill Lynch with vari-ous responsibilities including regional tax

investments manager. He is a member of the Petroleum InvestorRelations Association and serves on the Independent PetroleumAssociation of America (IPAA) Capital Markets Committee. He is thecurrent chairman of the IPAA Oil and Gas Investment Symposium.Mr. Turner received his bachelor’s degree from Duke University.

WILLIAM T. VAUGHN is Devon’s vice presidentof finance in charge of commercial bankingfunctions, accounting, tax and informationservices. Mr. Vaughn was elected in 1987 tohis present position. Prior to that, he was con-troller 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 ofCertified Public Accountants and the Oklahoma Society of CertifiedPublic Accountants. Mr. Vaughn is a graduate of the University ofArkansas with a bachelor of science degree.

DANNY J. HEATLY has been Devon’s controllersince 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,and is a member of the American Institute ofCertified Public Accountants and the

Oklahoma Society of Certified Public Accountants. Mr. Heatly grad-uated with a bachelor of accountancy degree from the University ofOklahoma.

GARY L. MCGEE was elected treasurer in 1983,having first served as Devon’s controller. He isa member of the Petroleum AccountingSociety of Oklahoma City. He also is a mem-ber of the Rocky Mountain Oil & GasAssociation executive committee and thePetroleum Association of Wyoming. Mr.McGee has been active in varied accounting

functions with several companies in the industry. He served as vicepresident of finance with KSA Industries, Inc., a private holding com-pany with diverse interests including oil and gas production. Mr.McGee also held various accounting positions with Adams Resourcesand Energy Co. and Mesa Petroleum Company. He received hisaccounting degree from the University of Oklahoma.

MARIAN J. MOON was elected corporate secre-tary in 1994. Ms. Moon has served Devon invarious capacities since 1984, including hercurrent position as manager of corporatefinance. She previously served as assistant sec-retary with responsibilities including compli-ance with SEC and stock exchange regula-tions. Prior to joining Devon, Ms. Moon was

employed for 11 years by Amarex, Inc., an Oklahoma City based oiland gas production and exploration firm, where she most recentlyserved as treasurer. Ms. Moon is a member of the Petroleum InvestorRelations Association and the American Society of CorporateSecretaries. She is a graduate of Valparaiso University.

Corporate Officers


Glossary of Terms

BRITISH THERMAL UNIT (BTU): Ameasure of heat value. An Mcf ofnatural gas contains roughly onemillion Btu of heat value.

DEVELOPMENT WELL: A welldrilled within the area of an oilor gas reservoir known to beproductive. Development wellsare relatively low risk.

EXPLORATORY WELL: A welldrilled in an unproved area,either to find a new oil or gasreservoir or to extend a knownreservoir. Sometimes referred toas a wildcat.

FIELD: A geographical area underwhich one or more oil or gasreservoirs lie.

FORMATION: An identifiablelayer of rocks named after itsgeographical location and domi-nant rock type.

GROSS ACRES: The totalnumber of acres in which oneowns a working interest.

INCREASED DENSITY/INFILL: Awell drilled in addition to thenumber of wells permitted underinitial spacing regulations, usedto enhance or accelerate recovery,or prevent the loss of provedreserves.

INDEPENDENT PRODUCER: Anon-integrated oil and gasproducer with no refining orretail marketing operations.

LEASE: A legal contract thatspecifies the terms of the businessrelationship between an energycompany and a landowner ormineral rights holder on a partic-ular tract of land.

LIFTING COSTS: Costs associatedwith bringing oil or gas from theproductive formation to thepoint of sale.

NATURAL GAS LIQUIDS (NGLs):

Liquid hydrocarbons that areextracted and separated from thenatural gas stream. NGLs prod-ucts include ethane, propane,butane and natural gasoline.

NET ACRES: Gross acres multi-plied by one’s fractional workinginterest in the property.

PERMEABILITY: A measure of theease with which fluids (such asoil or gas) flow through a forma-tion’s pore spaces.

PRODUCTION: Natural resources,such as oil or gas, taken out ofthe ground. - GROSS PRODUCTION: Totalproduction before deductingroyalties. - NET PRODUCTION: Grossproduction, minus royalties.

PROVED RESERVES: Estimates ofoil, gas, and gas liquids quantitiesthought to be recoverable fromknown reservoirs under existingeconomic and operating condi-tions.

RESERVOIR: A rock formation ortrap containing oil and/or naturalgas.

SEC @ 10% OR SEC 10%

PRESENT VALUE: The future netrevenue anticipated from provedreserves using the SEC Case,discounted at 10 percent.

SEC CASE: The method forcalculating future net revenuesfrom proved reserves as estab-lished by the Securities andExchange Commission (SEC).Future oil and gas revenues areestimated using essentially fixedor unescalated prices. Futureproduction and developmentcosts also are unescalated and aresubtracted from future revenues.

SECTION 29 TAX CREDIT: A taxcredit prescribed by Section 29 ofthe Internal Revenue Code. Thecredit is available for certaintypes of gas production from anon-conventional source, such ascoal deposits. The credit for 1996was about $1.02 per million Btu,and is adjusted for inflation.

STEPOUT WELL: A well drilledjust outside the proved area of anoil or gas reservoir in an attemptto extend the known boundariesof the reservoir.

THREE-DIMENSIONAL SEISMIC

(3-D SEISMIC): Technology tocreate three-dimensional imagesby bouncing sound waves off ofunderground rock formations.Used to look for undergroundaccumulations of oil and gas.

UNDEVELOPED ACREAGE: Leaseacreage on which wells have notbeen drilled or completed to apoint that would permit theproduction of commercial quan-tities of oil or gas.

UNIT: A contiguous parcel of landdeemed to cover one or morecommon reservoirs for oil ornatural gas, as determined bystate or federal regulations. Unitinterest owners generally share incosts and revenues according totheir proportion of ownership inthe unit.

WATERFLOOD: A method ofincreasing oil recoveries from anexisting reservoir. Water isinjected through a special “waterinjection well” into an oilproducing formation to forceadditional oil out of the reservoirrock and into nearby oil wells.

WORKING INTEREST: The cost-bearing ownership share of an oilor gas lease.

Volume Acronyms

Bbl: A standard oil measurementthat equals one barrel (42 U.S.gallons). - MBbl: Thousand barrels.- MMBbl: Million barrels.

Boe: A method of equating oil,natural gas liquids and naturalgas. Natural gas is converted tooil based on its relative energycontent at the rate of six Mcf ofgas to one barrel of oil. Naturalgas liquids are converted basedupon volume: one barrel ofnatural gas liquids equals onebarrel of oil.- MBoe: Thousand barrels of oilequivalent.- MMBoe: Million barrels of oilequivalent.

EMcf: Thousand cubic feet ofnatural gas equivalent. Six EMcfequals one barrel of oil. OneEMcf equals one Mcf or sevengallons of natural gas liquids. - EMMcf: Million cubic feet ofnatural gas equivalent.- EBcf: Billion cubic feet ofnatural gas equivalent.

Mcf: A standard measurementunit for volumes of natural gasthat equals one thousand cubicfeet. - MMcf: Million cubic feet.- Bcf: Billion cubic feet.

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Common Stock Trading Data

HIGH LOW LAST VOLUME DIVIDENDS

1995First Quarter 21 3/8 16 3/4 21 2,558,600 $.03Second Quarter 23 1/4 20 21 1/2 2,610,500 $.03Third Quarter 23 7/8 18 21 7/8 2,486,100 $.03Fourth Quarter 26 21 1/2 25 1/2 1,407,000 $.03

1996First Quarter 25 3/4 19 7/8 23 1/2 2,825,300 $.03Second Quarter 26 1/8 22 24 1/2 2,473,900 $.03Third Quarter 27 1/2 22 3/4 25 1/2 4,715,400 $.03Fourth Quarter 36 7/8 25 1/4 34 3/4 6,010,800 $.05


Investor Information

CORPORATE HEADQUARTERS

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

ANNUAL MEETING

Our annual stockholders’ meeting will be held at 11:00 a.m.,local time, on Wednesday, May 21, 1997, in the CommunityRoom, Mezzanine Floor, Bank of Oklahoma, RobinsonAvenue at Robert S. Kerr, Oklahoma City, Oklahoma.

PUBLICATIONS

A copy of Devon’s Annual Report to the Securities andExchange Commission (Form 10-K) is available at no chargeupon request.

Direct requests for corporate information to:Ms. Pat DouglasDevon Energy Corporation20 North Broadway, Suite 1500Oklahoma City, OK 73102-8260Telephone: (405) 552-4506Fax: (405) 552-4667E-mail: [email protected]

STOCK TRANSFER AGENT AND REGISTRAR

Boston EquiServeClient Administration, Mail Stop 45-02-62P.O. Box 1865Boston, MA 02105-1865Toll Free: 1-800-733-5001World Wide Web: http://www.equiserve.com

INDEPENDENT AUDITORS

KPMG Peat Marwick LLP, Oklahoma City, Oklahoma

INVESTOR RELATIONS CONTACT

Mr. Vince WhiteTelephone: (405) 235-3611 E-mail: [email protected]

STOCK TRADING DATA

Devon Energy Corporation’s common stock is traded on theAmerican Stock Exchange under the symbol DVN. As ofFebruary 28, 1997, there were approximately 900 commonstockholders of record.

DEVON ENERGY CORPORATION20 North Broadway, Suite 1500

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

Fax (405) 552-4667

devon 1996 annual report

Economy & Finance