DEVON ENERGY CORPORATION’S

SPIRITOF CREATIVITY

1996 ANNUAL REPORT 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 OIL AND GAS PROPERTIES,

▼ EXPLORING FOR UNDISCOVERED OIL AND GAS RESERVES, and

▼ OPTIMIZING PRODUCTION FROM OUR OIL AND GAS PROPERTIES.

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

7 Letter to Shareholders 2 Outside the Box Five-Year 4 Highlights Pushing 11 the Envelope

Focus on Operations 19 15 A Different Point of View

25 Financial Statements and Management’s Discussion and Analysis Board of Directors 64 65 Corporate Officers Glossary 66

67 Investor Information and Common Stock Trading Data

D EVON ENERGY CORPORATION 1 DEAR Fellow Shareholders

evon Energy Corporation's None of these accomplishments would have been 1996 will undoubtedly be possible without creativity. remembered as one of extra- Many of our achievements were attained because we ordinary achievement. approach problem solving from a different viewpoint than Consider the following: many of our competitors. Inspired by the innovative pio- ◆ Net earnings were $34.8 neers who molded our industry, Devon recognizes that million, or $1.57 per unique opportunities can be created in our day-to-day busi- common share, up 140 per- ness. During 1996, for example, much of Devon's growth cent from 1995. in oil and gas reserves resulted from an innovative and D◆ Cash margins (revenues less cash expenses) climbed 62 unique transaction with Kerr-McGee Corporation. percent to $96.0 million. On December 31, 1996, ◆ Revenues were up 45 per- Inspired by the we merged Kerr-McGee's cent to $164.0 million. North American onshore oil ◆ Oil and natural gas pro- innovative pioneers and gas exploration and pro- duction grew to 10.7 who molded our duction businesses into Devon million barrels of oil equiva- in exchange for 9.95 million lent, setting a new record industry, Devon shares of Devon common for the ninth year in a row. recognizes that unique stock. Through the merger, ◆ Estimated proven oil and Kerr-McGee became a 31 per- gas reserves reached 179 opportunities can be cent shareholder of Devon. million barrels of oil equiva- created in our This allows Kerr-McGee to lent—also our ninth maintain an investment in the consecutive record. day-to-day business. onshore oil and gas business in ◆ We enhanced Devon's North America. At the same financial flexibility by issuing $149.5 million of 6.5% Trust time, it eliminates the burden of the overhead, the direct Convertible Preferred Securities. expenses and the capital requirements of those activities. ◆ Two nationally recognized credit rating agencies, Duff & Devon, on the other hand, increased its proved reserves by Phelps and Standard & Poor's, joined our commercial about 50 percent and strengthened core operating areas. banks in rating Devon as an "investment-grade" company. This provides additional economies of scale and increased ◆ Mergers and acquisitions boosted reserves by some 65 marketing leverage in our core areas. We also tripled our million barrels of oil equivalent. inventory of undeveloped acreage—primarily in areas where ◆ We drilled 194 oil and gas wells, 190 of which were we already operate. Additionally, the transaction provides successful. Devon with critical mass in a new core area, western ◆ Through mergers, acquisitions and drilling, Devon Canada. Overall, greater operational efficiencies are now replaced more than 700 percent of the year's production. possible than were ever feasible under separate ownership. ◆ Quarterly dividends were increased to five cents per While the benefits of this merger are obvious, the common share. This represents a 66 percent increase over transaction is nonetheless unique. It requires the mutual the three-cent amount previously paid. trust of the two companies. Kerr-McGee must trust Devon

2 DEVON ENERGY CORPORATION with the stewardship of a significant group of properties. Although Devon completed And Devon must trust Kerr-McGee, a large and powerful more than $250 million in mergers company, with a very significant ownership position in and acquisitions during 1996, we Devon's common stock. This mutual trust should result in now have more liquidity than ever rewards for the shareholders of both companies. before. As a company capitalized at In conjunction with the Kerr-McGee transaction, more than a billion dollars with

Luke R. Corbett, Tom J. McDaniel and Lawrence H. virtually no debt, we are positioned J. LARRY NICHOLS Towell became new members of Devon's Board of to aggressively continue our Directors. This increases the size of Devon's Board to nine growth. members. Each of the three gentlemen is an officer or Devon has come a long way since its founding some director of Kerr-McGee or its subsidiaries. More impor- 25 years ago. Yet, the essence of this company is the very tantly, these three directors bring a wealth of oil and gas same as it was when we started. We are optimistic about experience to our board. our future, creative in our problem solving, resourceful in In 1997, we will continue to expand Devon's asset optimizing our opportunities, and, above all else, honest in base by investing some $120 million in exploration and our dealings with everyone. 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- J. LARRY NICHOLS mental value to these properties. President and Chief Executive Officer

Oklahoma City, Oklahoma March 31, 1997

Proved Oil and Gas Reserves Total Revenues Cash Margin * Net Income (MMBoe) ($ Millions) ($ Millions) ($ Millions)

34.8 96 – 179 164 –

– 113 59 20.5 115 101 53 55 – 106 99 14.6 14.5 38 13.7 78 – 72 61 – 36 12 30 – -15.0 – 91 92 93 94 95 96 91 92 93 94 95 96 91 92 93 94 95 96 91 92 93 94 95 96 * Revenues less cash expenses.

Devon has increased total oil and ...resulting in 1996 revenues Higher oil and gas production ...and the highest net earnings gas reserves by almost 400% over of more than five times and prices led to record cash in the company’s history. the last five years... those of 1991. margins in 1996...

DEVON ENERGY CORPORATION 3 Survey stakes used to plot the paths of gas lines at ▼ Five-Year Highlights Devon’s Northeast Blanco Unit. In 1996, we initiated a major expansion of this gas-gathering system.

LAST YEAR 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----NM Per 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 NM Long-term Debt $ 54,450 80,000 98,000 143,000 8,000 -94%

PROPERTY DATA Production 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%

Reserves Oil 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.

Oil and Gas Production Earnings Per Share Total Assets (MMBoe) ($) ($ Millions)

1.57 10.7 – 746 10.0 9.5 – 8.7 – .98 .94 422 6.3 – .66 351 – .64 286 226 3.1 – 102 – -1.99 – 91 92 93 94 95 96 91 92 93 94 95 96 91 92 93 94 95 96

Devon set its ninth consec- ...and earnings per share Over the last five years, utive record for oil and gas reached a new high. Devon increased total assets production in 1996... more than seven-fold.

4 DEVON ENERGY CORPORATION

DEVON’S SPIRIT of CREATIVITY

Tank containing ▼ fresh water used by a drilling rig at a well location.

We often find long-term value by looking beyond short-term trends. The philosophy of leaving the pack and going our own direction has contributed substantially to Devon's merger and acquisition successes. During the past nine years, we have completed 16 major transactions. utside the OBOX

DEVON ENERGY CORPORATION 7 There are two misconceptions about acquisitions that generally confuse investors.

First, some equate acquisitions with cash-market auc- Combining the merger properties into our opera- tions. In those situations, the highest bidder wins the tions should result in substantial economies of scale, auction, yet also accepts the lowest rate of return. Devon marketing synergy and increased drilling opportunities. We believes this type of acquisition stifles profitability. Because greatly enhanced our position in three of the areas in which our acquisition objective is to maximize profitability, we already owned significant interests—the Permian Basin, Devon rarely goes to auctions. the Rocky Mountain Region and the Mid-Continent—plus Second is the notion that it is impossible to complete we stepped into a new growth area, the Western Canada a value-adding transaction when commodity prices are Sedimentary Basin. We plan to strengthen our Canadian high. This year, we proved quite the opposite. operations in the future through both acquisitions and exploration. 1996 Merger Boosts Reserves, Creates Opportunities Devon also gained approximately 100 experienced In the midst of 1996's high oil and gas prices, we employees from Kerr-McGee as a result of the transaction. consummated a very significant merger. We exchanged 9.95 This affords us the opportunity to blend the best practices million newly issued Devon common shares for all of Kerr- of two successful corporations and makes Devon even McGee's North American onshore oil and gas exploration stronger than before. and production business and properties. The transaction involved about 62 million barrels of oil equivalent reserves Cash Purchase Completes Worland Unit Ownership and 370,000 net undeveloped acres of leasehold and min- In 1992, Devon purchased a 6 percent interest in the eral interests. How significant are those numbers? The Worland Unit located in central Wyoming. Three years merger increased our oil and gas reserves by almost 50 per- later, the company gained critical mass in the Rocky cent. It also tripled our undeveloped Mountain Region when we purchased property inventory. NOTE: This the dominant interest in the rather dramatic growth Unit for $50.3 mil- was achieved lion. In 1996, without going Devon to an auc- acquired tion.

8 DEVON ENERGY CORPORATION ALTERNATIVE THINKING Wooden barrels loaded on wagons or boats provided oil transportation in the 1800s. From this Defined Criteria Drive another $7 million of inauspicious beginning, the barrel quickly became the Acquisition Success interests, bringing our standard mode of transportation and the standard working interest in the volume measurement. Samuel Van Syckle was not con- Devon's growth over developed portions of tent with the old way of doing things. He gave birth to the past decade underscores the property to 98 per- the idea of moving oil through underground pipes. the importance of our The innovative thinker was ridiculed, but he pushed cent. Devon's interest in acquisition criteria. We are ahead and opened a 5-mile long pipeline in 1865. This not interested in simply the 14,000-plus undevel- proved to be a profitable venture. Syckle's creative building mass. Each purchase oped acres and gas plant spirit laid a foundation for the pipelines that now now totals 100 percent. The crisscross the developed world. we make must provide an incre- Worland Unit should contribute mental return for Devon to Devon's total production efforts shareholders. In order to fit Devon's well into the next century. growth strategy, acquisitions must directly contribute to per-share results. We prefer long- Property Sales Share Importance Of Acquisitions lived reserves in familiar areas. We value properties with While acquisitions typically are the headline grab- significant exploration or development opportunities. And bers, we consistently sell almost as many well bores as we they must be available at attractive terms that will allow the purchase. Since 1988, the company has sold approximately company to retain sufficient liquidity and financial flexi- 5,800 wells. When do we sell? Anytime a property limits bility. Are Devon’s acquisition criteria too stringent? Quite growth opportunities. For example, we sold our West the opposite. They force us to be creative and seek out the Virginia assets during 1996. Although these properties were most lucrative transactions. ■ still profitable, Devon's growth dwarfed their impact on the company's operations as a whole. Devoting time to man- aging assets that cannot make a significant contribution to overall results inhibits a company's potential for future growth.

Mergers and Acquisitions Proved Oil and Gas Reserves Reserve Replacement from Finding Costs from Acquisitions ($ Millions) (MMBoe) All Sources (%) ($/Boe)

DEVON DEVON GROUP AVERAGE GROUP AVERAGE

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

257 179 710 4.06 4.19

3.26 3.06 3.07 115 106 349 123 213 78 209 84 208 56 52 61 36 3

91 92 93 94 95 96 91 92 93 94 95 96 95 92-95 96 95 92-95 96

Over the last six years, Devon has In 1996, Devon set its ninth Our 710% reserve replacement ratio Devon has consistently completed more than $575 million consecutive record for year-end in 1996, marked the ninth consecu- acquired oil and gas reserves in mergers and acquisitions. reserves. tive year that ratio exceeded 200%. at costs below industry norms.

DEVON ENERGY CORPORATION 9

DEVON’S SPIRIT of CREATIVITY

A valve at the ▼ Northeast Blanco Unit assumes a surreal image in the harsh New Mexico sun.

The standard solution is not always the best solu- tion. Challenging our people to find new answers to old questions is one of the PUSHING qualities

that sepa- rates Devon from the crowd. Creative thinking allows us to arrive THEat some very novel conclusions, ENVELOPEeven in the financial arena.

DEVON ENERGY CORPORATION 11 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.

In 1995, the company began investigating methods Transaction Designed To Benefit All Parties Involved to match our debt maturities with our long-term asset base. Our new financing tool, trust convertible preferred The standard procedure would have been to arrange 10- to securities (TCP Securities), is structurally complicated but 20- year fixed-rate debt. Devon, however, did not want to works to the benefit of all involved. Devon's newly formed simply match debt maturity with asset life. We wanted to affiliate, Devon Financing Trust, issued $149.5 million of maximize future financial flexibility. Our solution? We 6.5% TCP Securities. The Trust then loaned the proceeds arranged a hybrid device that, short term, eliminated con- to Devon. We in turn, used those proceeds to substantially ventional debt from our balance sheet. Long term, the reduce our outstanding debt. Devon makes interest pay- device will do one of two things: be converted into conven- ments to the Trust. The Trust then uses those payments to tional, perpetual common stock or provide pay dividends to TCP Security owners. 30-year financing at a very low TCP Securities are difficult for many companies to interest rate. offer because only a limited number of investors, perhaps only 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 device provides investors a dividend-yielding security that pays an annual rate of $3.25 per TCP Security. At the issue price of $50 per TCP Security, this divi- dend represents a 6.5 percent indicated yield. Second, since Devon had no material conventional debt upon the offering's completion, the yield is relatively secure. Third, the investors in the TCP Securites partici- pate in a portion of Devon's future growth. They can convert each of their TCP Securities into 1.64 shares of Devon common stock. The higher the price of Devon common, the higher the inherent con- version value of the TCP Securities. How does Devon benefit? TCP Securities allow Devon to maintain an important tax attribute and gain financial flexibility. The interest payments that Devon makes to the Trust are deductible for income tax purposes. At a statutory rate of 34 percent, we save 34 cents in income taxes for each $1.00 paid in interest expense.

12 DEVON ENERGY CORPORATION CREATIVE SOLUTION Cable-tool rigs were used in the oil industry's infancy to punch shallow wells into solid rock formations. Captain Anthony F. Lucas, however, Even more impor- believed deeper oil reservoirs could be reached The offering also has two other tant to Devon is the by using a rotary-style grinding rig developed favorable benefits for our financial flexibility that we for the salt industry. The rotary-style rig turns a common stockholders. gained. Our debt, with an pipe with a drill-bit attached to its end. The tool Unlike a conventional debt grinds a hole rather than of pounding it down average maturity of less than structure which allows the like the cable-tool rig. In 1899, Lucas took the five years, was refinanced with new tool and drilled the mammoth discovery holders to have a superior the issuance of TCP Securities. known as Spindletop. Captain Lucas' creative claim on Devon’s assets, The TCP Securities do not mature solution transformed the industry. Drilling rigs TCP Security holders, until 2026, or never, if they are today use this rotary design. upon conversion of their converted into common stock before securities, have ownership equal to maturity. With such a long maturity, that of common stockholders. Second, as banks and other lenders view TCP opposed to conventional common stock offerings, the Securities as equity, not debt. As a result, TCP Securities offering did not have a negative impact on upon retiring our previously existing bank Devon's stock price. loans, almost all of Devon's credit lines were available. We believe we could access as much $500 million in credit lines Devon Earns Investment-Grade Status if we so desired. Do we currently need additional capital? In response to Devon's 1996 activity, including the No. The offering was strategic financing to position Devon TCP Securities offering and our Kerr-McGee merger, for future opportunities. At Devon, we don't just think in Standard & Poor's and Duff & Phelps assigned Devon terms of drilling the next well. We drill the next well using investment-grade status. The implied senior debt rating of the lowest cost and most flexible capital. BBB- identifies Devon as a lower-risk company and will How do current common stockholders benefit? All of enable us to borrow funds, if needed, at even more attrac- ■ the benefits that Devon achieves corporately through the tive rates than in the past. TCP Securities are shared by Devon common stockholders.

Long-Term Debt Liquidity ($ Millions) ($ Millions)

UNUSED CREDIT LINES WORKING CAPITAL

272

143

98 135 80 126 95 54 78 32

17 8

91 92 93 94 95 96 91 92 93 94 95* 96

Devon repaid amounts outstanding ...and ended 1996 with more under its credit lines with the proceeds liquidity than ever before. from the issuance of TCP Securities... * Adjusted for an upward revision to Devon’s borrowing base in early 1996.

DEVON ENERGY CORPORATION 13

DEVON’S SPIRIT of CREATIVITY

Tanks store the fluids ▼ used to fracture a Devon well. Fracture treatments create additional paths for the flow of oil and gas through the reservoir. A DIFFERENT POINT OF VIEW Weather patterns, economic activity and politics are but a few of the drivers behind the volatility and uncertainty of oil and gas prices. Some in our industry view this volatility as an almost insurmountable obstacle to success. From Devon's point of view, it is a bridge to opportunity.

DEVON ENERGY CORPORATION 15 Devon mitigates the impact of price volatility.

Oil and gas producers have limited control over the prices they receive for their products. Like all producers, Devon's revenues are impacted by oil and gas prices. However, we take steps to reduce our vulnerability to low product prices. By doing so, Devon has been able to prosper even when faced with 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 opposite directions. Having both products helps insu- late our earnings and cash flow from price swings in either commodity. We balance our exposure to nat- ural gas markets. Supply and demand, and therefore prices, vary from region to region within North America. Devon has oil and gas property con- centrations in several different regions. This reduces the impact on the company when consumer needs decline in one part of the country. We build production volumes. Rather than wait for higher oil and gas prices to increase revenues, Devon consistently increases oil and gas 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 and greater 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. By – aggregating volumes, we sell larger quantities to fewer – – purchasers. Fewer purchasers means fewer contracts and – – –

16 DEVON ENERGY CORPORATION lower administrative costs. Aggregating gas the same time, the likely buyers of such properties—oil and for transportation has the same gas producers—are experiencing a reduction in cash flow. effect: fewer contracts, less They are also experiencing a reduction in risk-capital avail- administration, lower costs. able, as lenders become more cautious. This is an ideal situation for Devon. With an investment-grade balance STRETCHING Seeing the Opportunity sheet and easy access to capital, Devon is poised to take THE BOUNDARIES Beyond advantage of the opportunities that inevitably result. Most people used to believe on-land It is true that We maximize financial flexibility. By building a drilling was the only way to obtain periods of low oil high-margin property base and keeping debt levels low, oil. T.F. Rowland was among those and gas prices put Devon reduces the risk to our lenders. As a result, we have who thought otherwise. The creative downward pres- thinker proposed that a rig posi- better access to capital at lower rates. This allows us to sure on Devon’s tioned above water could reach black invest in oil and gas properties when competition is low. gold. In 1869, he was issued a patent revenues and Such was the case in late 1995 and early 1996 when for an ingenious four-legged tower earnings. we increased our interest in the Worland Unit in Wyoming. that would prove his point. Anchored However, Gas prices were depressed in the Rocky Mountain region of in shallow water, Rowland’s rig periods of low the United States. As a result, there was little competitive helped set the stage for a significant oil and gas prices part of today’s oil industry – produc- interest in the area. Several of the larger players in the area can also bring tion achieved through offshore were already staggering under the weight of their debt. drilling. opportunity. Devon's ready access to capital allowed the company to When prices fall, move on the opportunity and significantly increase our weak and under- Worland gas reserves. ■ capitalized players are forced to sell quality properties. At

Oil and Gas Production Operating Expense per General and Administrative Long-Term Debt per (MMBoe) Boe Produced Expense per Boe Produced Boe of Reserves ($) ($) ($)

GAS OIL

– 10.7 9.5 10.0 – 8.7 – 6.3 3.04 2.85 2.93 2.94 – 2.57 2.71 1.91 – 3.1 1.25 1.04 1.02 0.88 0.88 0.84 0.85 0.90 0.89 0.93 – 0.04 – 91 92 93 94 95 96 91 92 93 94 95 96 91 92 93 94 95 96 91 92 93 94 95 96

Balancing oil and gas production...... keeping operating expenses ...general and administrative ...and debt levels low, positions low... expenses low... Devon to prosper—even in periods of low prices.

DEVON ENERGY CORPORATION 17

DEVON’S SPIRIT of CREATIVITY

The “goat’s foot” on ▼ this piece of heavy equipment compacts the soil, building a stable base for a drilling rig.

FOCUS ON OPERA TIONS

Creativity alone does not build a company–it also requires quality assets.

DEVON ENERGY CORPORATION 19 We concentrate our oil and gas reserves and production in core producing regions—achieving critical mass in each.

Building critical mass in each core area allows Devon to quantities of oil and gas in each area. It also enables us to establish efficient regional operating segments, resulting in negotiate more favorable terms with service and supply ven- a lower overall cost structure. We benefit from the level of dors because we have become an important customer with technical expertise we attain as a result of our experience in a high volume of business. the area. Concentrated production also increases our mar- keting clout, by allowing us to aggregate and sell large

Oil Reserves by Area Gas Reserves by Area (%) (%)

Canada 11%– Canada 7%– Other 1% Other 1%– – – San Juan Basin 27%– – – Permian Basin 69%– – – Permian Basin 26%– – – – Mid-Continent 21%– Mid-Continent 3%– – Rocky Mountain 16%– Rocky Mountain 18%– – –

Devon has concentrated 96% of its ...and 92% of its gas reserves in four core oil reserves in three core areas... areas. This concentration facilitates efficient operations and gives Devon marketing clout.

Eleven Year Property Data 1986 1987 1988 1989 Reserves Oil and Natural Gas Liquids (MBbls) 3,023 2,286 5,590 4,800 Gas (MMcf) 36,026 34,829 98,388 149,761 Total (MBoe) (1) 9,027 8,090 21,988 29,760 SEC @ 10% Present Value (Thousands) (2) $ 54,092 44,460 88,564 137,274 Production Oil and Natural Gas Liquids (MBbls) 406 359 568 681 Gas (MMcf) 3,930 4,522 5,919 7,776 Total (MBoe) (1) 1,061 1,112 1,554 1,977 Average Prices Oil and Natural Gas Liquids (Per Bbl) $ 14.96 18.15 14.62 18.15 Gas (Per Mcf) $ 2.25 1.92 1.69 1.79 Oil, 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.

20 DEVON ENERGY CORPORATION Operating Statistics by Core Area

PERMIAN 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 - 3,816 Gas (MMcf) 9,365 2,730 18,172 4,576 871 35,714 - 35,714 NGLs (MBbls) 602 259 11 78 2 952 - 952 Total (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 - 21.00 Gas Price ($/Mcf) $ 2.18 1.48 1.71 2.17 2.99 1.91 - 1.91 NGL 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 67,481 Gas (MMcf) 153,059 105,471 163,027 127,752 5,352 554,661 40,858 595,519 NGLs (MBbls) 6,808 4,257 63 538 29 11,695 884 12,579 Total (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 1,621,992 After 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 75,637 594,977 Undeveloped 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 - 76.2 Estimated 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.

5-YEAR 10-YEAR COMPOUND 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%

DEVON ENERGY CORPORATION 21 Permian Basin Profile Activity to

Grayburg-Jackson Field ◆ 100% working interest in 8,600 acres in Eddy County, New Mexico. ◆ Drilled 155 ◆ Purchased in 1994 property acquisition. ◆ Implemen ◆ Produces oil from the Grayburg and San Andres formations at 3,000’ to 4,000'. ◆ Increased ◆ Contracted

West Red Lake Area ◆ Initially obtained a 98% working interest in 1,200 acres and 50% to 100% interest ◆ Drilled 82 in 4,300 undeveloped acres in 1992 property acquisition. ◆ Increased ◆ Produces oil from the Grayburg and San Andres formations at about 2,500'. ◆ Contracted

Ozona and Davidson ◆ Initially obtained an interest in over 25,000 acres in 1992 property acquisition. ◆ Drilled 34 Ranch Fields ◆ 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'. Rocky Mountain Region

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

Northeast Blanco Unit (NEBU) ◆ 23% working interest in 33,000 acres in the central part of the basin. ◆ Recavitate ◆ Originally developed by Devon in the late 1980's and early 1990's. ◆ Initiated im ◆ Contains 102 producing wells, four water disposal wells, gas and water gathering systems – Will low and an automated production control system. – Will add

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

Western Canada Sedimentary 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'. Mid-Continent Area

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'.

23 ate 1997 Plans

s substantially completing infill drilling phase of $60-plus million development project. ◆ Implement final phase of water injection program on remainder of field: ll water injection on approximately one-half of project area. – Construct second water injection plant. uction by some 2,000 barrels of oil equivalent per day. – Install additional 40 miles of water lines. ell sour crude at above-market prices through year 2000. – Convert some 70 wells to injection wells.

ecutive successful wells including 61 during 1996. ◆ Drill over 70 additional wells. uction by some 3,600 barrels of oil equivalent per day. ◆ Initiate pilot waterflood program. ell sour crude at above-market prices through year 2000.

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.

million of additional interests in December 1995 and early 1996. ◆ Complete 3-D seismic survey. wells further developing established reservoirs. ◆ Drill new wells and recomplete and stimulate additional existing wells. existing well to another producing horizon. ◆ Install field compressors to increase gas gathering capacity. kovers or recompletions on 12 existing wells. ◆ Complete gas plant upgrade. 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.

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

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

uction by 16% with mechanical improvements on several wells. ◆ Continue to produce at gathering system capacity. e observation well to evaluate infill drilling potential.

◆ 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.

DEVON ENERGY CORPORATION 24 Financial Statements and Management’s Discussion and Analysis

26 Selected Eleven-Year Financial Data 28 Management’s Discussion and Analysis of Financial 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 Selected Eleven-Year Financial Data

1986 1987 1988 1989

OPERATING RESULTS (in thousands, except per share data) Revenues Oil and Natural Gas Liquids Revenue $ 6,078 6,509 8,302 12,370 Gas Revenue 8,846 8,693 9,983 13,906 Other 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 11,835 Depreciation, Depletion and Amortization(1) $ 11,532 7,697 7,429 7,350 General and Administrative Expenses $ 4,482 4,056 3,854 6,103 Interest Expense $ 1,318 1,141 2,132 2,140 Distributions on Trust Convertible Preferred Securities(2) $ ---- Adjusted Net Earnings (Loss)(3) $ (1,899) (1,066) (565) 876 Reported Net Earnings (Loss) $ (3,967) (1,066) 3,347 876 Preferred Stock Dividends(4) $ - - - 821 Net Earnings (Loss) to Common Shareholders $ (3,967) (1,066) 3,347 55 Net Earnings (Loss) per Common Share $ (0.64) (0.17) 0.48 0.01 Net Earnings (Loss) per Common Share - Fully Diluted $ (0.64) (0.17) 0.48 0.01 Cash Dividends per Common Share $ - - - -

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

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

26 DEVON ENERGY CORPORATION 5-YEAR 10-YEAR GROWTH 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 NM 2,554 (15,024) 14,615 19,186 13,745 14,502 34,801 NM NM 2,554 (15,024) 14,615 20,486 13,745 14,502 34,801 NM NM 2,324 2,270 1,703 ----NMNM 230 (17,294) 12,912 20,486 13,745 14,502 34,801 NM NM 0.03 (1.99) 0.94 0.98 0.64 0.66 1.57 NM NM 0.03 (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 NM 70,767 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%

DEVON ENERGY CORPORATION 27 Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW Devon concluded 1996 financially stronger and ◆ On December 31, 1996, we acquired all of Kerr-McGee larger than at any previous time in the company’s history. Corporation’s North American onshore oil and gas exploration Over the last three years our oil and gas reserves have grown and production business and properties (the “KMG-NAOS Prop- 129% to 179 million barrels of oil equivalent (“MMBoe”). erties”) in exchange for 9,954,000 shares of Devon common Our long-term credit lines have increased 63% over the same stock. This transaction added approximately 62 million Boe to period, to $260 million. Total assets have increased 161% to our year-end 1996 proved reserves (an increase of over 50%), as $746 million. During the same three years, we reduced our well as 370,000 net undeveloped acres of leasehold. long-term debt from $80 million to $8 million and signifi- ◆ We have been successful during the last three years in our cantly increased stockholders’ equity. drilling efforts. Devon has spent approximately $171 million to Our operating performance has also improved by most drill 476 wells, of which 462 were completed as producers. measures over the last three years. In 1996, oil and gas The following actions during the last three years production was 23% over that of 1993, at 10.7 MMBoe. improved Devon’s liquidity and financial resources while The 1996 production increase coupled with a 35% increase reducing its bank debt: in oil, gas and NGL prices over 1993 levels, led to revenues ◆ The issuance of $22 million of additional common equity and earnings gains. Net earnings for 1996 climbed 70% over capital in 1994 for the 1994 Alta Merger. those of 1993, to $34.8 million. Net cash provided by oper- ◆ Our production and revenue gains have given us a ating activities rose from $46.4 million in 1994 to $61.3 substantially larger cash flow and, thus, capital budget. million in 1995 and $86.8 million in 1996. The cash ◆ Our acquisition and drilling efforts during the last three margin1 (total revenues less cash expenses) during these same years have added 126.5 MMBoe of proved reserves to our asset three years has increased from $55.1 million in 1994 to base. Combined with 8.6 MMBoe of upward revisions to our $59.2 million in 1995 and $96.0 million in 1996. reserve estimates, Devon’s total reserve additions were 135.1 This growth in operations was driven primarily by the MMBoe during the past three years. This represents 446% of our following events: 30.3 MMBoe of production. ◆ We acquired $54 million of coal seam gas properties in ◆ In July, 1996, Devon, through a newly-formed affiliate the San Juan Basin in June, 1993. These properties added to trust, issued $149.5 million of 6.5% Trust Convertible Preferred Devon’s already significant coal seam gas properties, production Securities (the “TCP Securities”). and revenues in the San Juan Basin. ◆ Our oil and gas reserve additions, production gains, ◆ We acquired the properties of Alta Energy Corporation revenue increases and equity additions over the past three years through a $72 million cash and common stock merger in May have allowed us to increase our lines of credit. Since the end of 1994. The oil and gas properties acquired through the merger 1993, Devon’s long-term credit lines have increased by $100 (the “Alta Merger Properties”) added substantial oil and gas million to a total of $260 million at year-end 1996. reserves, production and revenues to our Permian Basin position. ◆ We acquired a gas processing plant and additional inter- The growth exhibited by Devon over the last three ests in certain Wyoming oil and natural gas properties (the years extends an eight-year expansion period for the “Worland Properties”). The acquisition costs were approximately company. This period started when we became a public $57 million from December, 1995 through April, 1996. company in 1988. Through our acquisitions and drilling and ◆ In 1995, we entered into a transaction covering substan- development efforts, we have significantly increased oil and tially all of our San Juan Basin coal seam gas properties (the gas reserves and production over this period. “San Juan Basin Transaction”). This transaction added approxi- While we have consistently increased production over mately $10 million to our annual revenues. this period of time, volatility in oil and gas prices has resulted in considerable variability in earnings and cash flows. Prices

28 DEVON ENERGY CORPORATION for oil, natural gas and NGLs are determined primarily by generally more expensive than producing gas. Also, secondary prevailing market conditions. Market conditions for these recovery projects are generally more expensive than primary products have been, and will continue to be, influenced by production.) Higher oil and gas prices in 1996 also resulted regional and world-wide economic growth, weather and other in higher production taxes, a component of production and factors that are beyond our control. Devon’s future earnings operating expenses. Our future earnings and cash flows are and cash flows will continue to be dependent on market dependent on our ability to continue to contain production conditions for the company’s production. and operating costs at levels that allow for profitable produc- Like all oil and gas production companies, we face the tion of oil and gas. challenge of natural decline. As virgin pressures are depleted, oil and gas production from a given well naturally decreases. RESULTS OF OPERATIONS Thus, an oil and gas production company consumes part of Devon’s total revenues have risen from $100.8 million its asset base with each unit of oil and gas it produces. in 1994 to $113.3 million in 1995 and $164.0 million in Historically, Devon has been able to overcome this natural 1996. In each of these years, oil, gas and NGL sales decline by adding more reserves through drilling and acquisi- accounted for 99% of total revenues. tions than the company produces. However, our future Changes in oil, gas and NGL production, prices and growth, if any, will depend on our ability to continue to add revenues from 1994 to 1996 are shown in the table on the reserves in excess of production. following page. Because we can only marginally influence oil and gas prices, we have focused our efforts on increasing oil and gas OIL REVENUES 1996 vs. 1995 Oil revenues increased reserves and production and on controlling expenses. Over by $24.9 million in 1996. An increase in the average price of our eight year history as a public company, we have been able $4.25 per barrel in 1996 added $16.2 million to revenues. to significantly reduce our production and operating costs per Production gains of 516,000 barrels added the remaining unit of production. However, over the last two years Devon’s $8.7 million of 1996’s increased oil revenues. per-unit operating costs have increased somewhat. An increase in our oil production as a portion of our total production and an increase in secondary recovery projects have contributed to this expense increase. (Producing oil is

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 net cashMD which is generated by a company’s operations during a given period, without regard& to the period such cash is actuallyA physically received or spent by the company. 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 or decreases 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, and not as a substitute for, net earnings and net cash provided by operating activities determined in accordance with generally accepted accounting principles in analyzing Devon’s results of operations and liquidity.

DEVON ENERGY CORPORATION 29 MD&A

The Grayburg-Jackson Field acquired in the 1994 Alta Coal seam gas production declined by 16%, from 20.8 Merger accounted for the majority of 1996’s increased Bcf in 1995 to 17.4 Bcf in 1996. However, the average real- production. This field produced 1,108,000 barrels in 1996, a ized coal seam gas price rose by 30% in 1996. Devon’s 37% increase over the 807,000 barrels the field produced in average realized coal seam gas price was $1.72 per Mcf in 1995. Production from our other oil properties increased 9% 1996, compared to $1.32 per Mcf in 1995. Total coal seam in 1996 to 2,708,000 barrels. This is compared 2,493,000 gas revenues were $30.1 million in 1996 compared to $27.5 barrels in 1995. million in 1995. This includes $10.3 million in 1996 and 1995 vs. 1994 Oil revenues rose $17.2 million in $12.8 million in 1995 attributable to the San Juan Basin 1995. Substantial gains in production added $12.9 million to Transaction. revenues in 1995, while higher average prices added the Total conventional gas production and revenues for remaining $4.3 million. 1996 were 18.3 Bcf and $37.9 million, respectively. This The Grayburg-Jackson Field produced 807,000 barrels compares to 16.1 Bcf and $23.2 million, respectively, of in 1995. This represents a 296% increase from the 204,000 conventional gas production and revenues in 1995. Prices for barrels which were produced during Devon’s ownership for conventional gas averaged $2.08 per Mcf in 1996 compared the last seven months of 1994. Production from our other oil to 1995’s average of $1.44. The additional interests in the properties increased 10% in 1995, from 2,263,000 barrels in Worland Properties added 2.2 Bcf to 1996’s conventional 1994 to 2,493,000 barrels in 1995. production. Devon acquired these additional interests in December 1995 and the first half of 1996 GAS REVENUES 1996 vs. 1995 Gas revenues increased 1995 vs. 1994 Gas revenues decreased $5.6 million, by $17.3 million in 1996. An increase in the average gas or 10%, in 1995, due to a combination of lower production price of $0.53 per Mcf in 1996 added $18.9 million to and prices. Lower production accounted for $3.5 million of 1996’s gas revenues. This increase was partially offset by a the revenue decrease. Lower gas prices accounted for the $1.6 million reduction in gas revenues from a 1.2 Bcf drop in remaining revenue decrease of $2.1 million. gas production.

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

PRODUCTION Oil (MBbls) 3,816 +16% 3,300 +34% 2,467 Gas (MMcf) 35,714 -3% 36,886 -6% 39,335 NGLs (MBbls) 952 +59% 600 +20% 501 Oil, 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% 15.44 Gas (per Mcf) $ 1.91 +38% 1.38 -3% 1.43 NGLs (per Bbl) $ 15.09 +41% 10.68 +9% 9.79 Oil, Gas and NGLs (per Boe) $ 15.16 +35% 11.19 +7% 10.43

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

30 DEVON ENERGY CORPORATION Gas revenues in 1995 were down Total conventional gas produc- NGL REVENUES 1996 vs. 1995 despite the positive effect of the 1995 tion and revenues for 1995 were 16.1 NGL revenues increased by $8.0 San Juan Basin Transaction. This trans- Bcf and $23.2 million, respectively. million in 1996. An increase in average action boosted 1995’s gas revenues by This compares to 17.4 Bcf and $30.7 prices of $4.41 per barrel added $4.2 $11.4 million. It also raised the average million respectively, in 1994. Prices for million to the 1996 revenues. The prices for 1995 coal seam gas and total conventional gas averaged $1.44 per remaining $3.8 million of increased gas production by $0.61 and $0.35 per Mcf in 1995 compared to 1994’s revenues was attributable to increased Mcf, respectively. (See Note 3 to the average of $1.76 per Mcf. production of 352,000 barrels in 1996. consolidated financial statements Production for a full year from Devon acquired additional inter- included elsewhere in this report for a the Alta Merger Properties contributed ests in the Worland Properties in detailed discussion of the San Juan a 0.6 Bcf increase in gas production in December 1995 and the first half of Basin Transaction.) 1995. However, this increase and others 1996. The acquired interests accounted Coal seam gas production from wells drilled in 1994 and 1995 for 214,000 barrels of the increased declined by 5%, from 22.0 Bcf in 1994 were more than offset by reduced production in 1996. The Worland to 20.8 Bcf in 1995. This decline of production from other conventional gas Properties produced 226,000 barrels in 1.2 Bcf was due to the San Juan Basin wells. The primary contributors to the 1996 compared to 12,000 barrels in Transaction. In addition to significantly conventional production decline in 1995. Additional drilling in the Sand increasing our gas prices and revenues, 1995 were the Ozona field, NEBU and Dunes area of the Permian Basin the San Juan Basin Transaction miscellaneous property sales. High increased production from 69,000 included the sale of a small portion of pipeline pressure and down time for barrels in 1995, to 95,000 barrels in our coal seam gas properties. repairs contributed to a 0.6 Bcf reduc- 1996. Devon’s average realized coal tion in Ozona production in 1995. 1995 vs. 1994 NGL revenues seam gas price rose by 13%, from $1.17 Out-of-period marketing adjustments increased by $1.5 million in 1995. per Mcf in 1994 to $1.32 per Mcf in caused the reduction in 1995 conven- Higher production contributed $1.0 1995. The $0.61 per Mcf increase from tional gas production at NEBU. million of the increase. The remaining the San Juan Basin Transaction more Various marginal wells sold in 1994 $0.5 of increased revenues was attribut- than offset a $0.46 per Mcf price drop and 1995 accounted for a 0.6 Bcf able to higher average prices in 1995. at the wellhead. Total coal seam gas reduction in 1995’s conventional The Alta Merger Properties revenues were $27.5 million in 1995 production. accounted for 52,000 barrels of the versus $25.7 million in 1994. Coal Although we do not have a increased production. Such properties seam gas revenues in 1995 included significant interest in conventional gas produced 84,000 barrels in 1995, $14.7 million of wellhead sales and production in NEBU, we had been compared to 32,000 barrels during the $12.8 million of revenues attributable selling more than our normal share of seven months Devon owned the prop- to the San Juan Basin Transaction. The production. This created an “imbal- erties in 1994. Additional drilling in sale of the small portion of our coal ance” between Devon and the wells’ the Sand Dunes area increased produc- seam gas properties was part of the San other owners. This imbalance was tion from 39,000 barrels in 1994 to Juan Basin Transaction. This sale had reversed in 1995 as the other owners 69,000 barrels in 1995. the effect of reducing 1995’s coal seam sold more than their normal share of gas revenues by $1.4 million as production. Also in 1994, we received compared to 1994’s revenues. The nonrecurring payments for inventory $12.8 million of additional gas sales less gas from NEBU. In 1995, the amounts this $1.4 million of wellhead sales of imbalance makeup and the lack of reduction, nets to the $11.4 million inventory sales led to a 0.5 Bcf reduc- increase in coal seam gas sales from the tion in conventional NEBU production San Juan Basin Transaction. compared to 1994.

DEVON ENERGY CORPORATION 31 MD&A

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

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

Absolute: (Thousands) Production and operating expenses: Lease operating expenses $ 31,568 +16% 27,289 +11% 24,521 Production taxes 10,658 +56% 6,832 -1% 6,899 Depreciation, depletion and amortization attributable to: Oil and gas production 41,538 +13% 36,640 +11% 32,861 Non-oil and gas properties 1,823 +26% 1,450 +14% 1,271 General and administrative expenses 9,101 +8% 8,419 - 8,425 Interest expense 5,277 -25% 7,051 +30% 5,439 Distributions 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% 2.57 Production taxes 0.99 +46% 0.68 -7% 0.73 Depreciation, depletion and amortization attributable to: Oil and gas production 3.88 +6% 3.65 +6% 3.45 Non-oil and gas properties 0.17 +21% 0.14 +8% 0.13 General and administrative expenses 0.85 +1% 0.84 -6% 0.89 Interest expense 0.49 -30% 0.70 +23% 0.57 Distributions 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 between 1994 and 1996 are shown in the table below.

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

Absolute: (Thousands) Recurring lease operating expenses $ 28,270 +19% 23,842 +10% 21,583 Well workover expenses 3,298 -4% 3,447 +17% 2,938 Production 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% 2.27 Well workover expenses 0.31 -11% 0.35 +17% 0.30 Production taxes 0.99 +46% 0.68 -7% 0.73 Total production and operating expenses $ 3.94 +16% 3.40 +3% 3.30

32 DEVON ENERGY CORPORATION 1996 vs. 1995 Recurring lease Production taxes are collected by DEPRECIATION, DEPLETION AND operating expenses increased by $4.4 most taxing authorities on a fixed AMORTIZATION Devon’s largest non-cash million, or 19%, in 1996. Approxi- percentage of revenue basis. Therefore, expense is depreciation, depletion and mately $2.7 million of the increase was as our revenues have increased, so have amortization (“DD&A”). DD&A of oil related to the additional interests production taxes. Production taxes and gas properties is calculated as the acquired in the Worland Properties. increased 56% from $6.8 million in percentage of total proved reserve Devon acquired these additional inter- 1995 to $10.7 million in 1996. This volumes produced during the year, ests in December 1995 and the first half increase was due almost exclusively to multiplied by the net capitalized invest- of 1996. Recurring lease operating higher oil, gas and NGL revenues. ment in those reserves including esti- expenses for the Worland Properties Excluding revenues generated from the mated future development costs (the increased from $0.1 million in 1995 to San Juan Basin Transaction, 1996 oil, “depletable base”). Generally, if reserve $2.8 million in 1996. The Alta Merger gas and NGL revenues increased 53% volumes are revised up or down, then Properties’ recurring lease operating compared to 1995. Revenues generated the DD&A rate per unit of production expenses increased from $3.5 million in from the San Juan Basin Transaction are will change inversely. However, if capi- 1995 to $4.6 million in 1996. This not subject to production taxes. talized costs change, then the DD&A increase was predominantly due to the Production taxes per Boe rate moves in the same direction. The higher number of producing wells in the increased by $0.31 per Boe, or 46% in per unit DD&A rate is not affected by Grayburg-Jackson Field in 1996 1996. This was primarily caused by the production volumes. Absolute or total compared to 1995. increase in the average price per Boe DD&A, as opposed to the rate per unit Recurring expenses per Boe were received in 1996. Excluding the effect of production, generally moves in the up by $0.27, or 11%, in 1996 compared on average prices from the San Juan same direction as production volumes. to 1995. This increase was primarily Basin Transaction, Devon’s total revenues 1996 vs. 1995 Oil and gas prop- caused by the reduction in the coal seam per Boe increased by 43% from $9.92 in erty related DD&A increased by $4.9 gas properties’ share of total production. 1995, to $14.21 in 1996. million, or 13%, in 1996. Approxi- The recurring operating costs per Boe 1995 vs. 1994 Recurring lease mately $2.5 million of this increase was for these coal seam gas properties are operating expenses increased by $2.2 caused by a 7% increase in total oil, gas extremely low ($0.32 per Boe in 1996 million, or 10%, in 1995. Approxi- and NGL production in 1996. The and $0.24 per Boe in 1995). However, mately $1.6 million of the increase was remaining $2.4 million increase was the coal seam gas properties’ percentage related to the Alta Merger Properties. caused by a 6% increase in the DD&A of overall production dropped from 35% Costs for these properties increased from rate. Devon’s DD&A rate increased from in 1995 to 27% in 1996. The result is $1.9 million in 1994 (for the last seven $3.65 per Boe in 1995 to $3.88 per Boe that more of our production in 1996 months of the year during which they in 1996. was attributable to conventional oil and were owned by Devon) to $3.5 million 1995 vs. 1994 Oil and gas prop- gas properties. Our conventional oil and in 1995. However, on a cost per unit of erty related DD&A increased by $3.8 gas properties have a higher recurring production basis, the Alta Merger Prop- million, or 11%, in 1995. Approxi- operating cost per Boe than the low-cost erties’ recurring lease operating expenses mately $2.0 million of this increase was coal seam gas properties. The recurring dropped from $4.96 per Boe in 1994 to caused by an increase in the DD&A costs per Boe on these conventional $3.16 per Boe in 1995. These per unit rate. Devon’s DD&A rate increased from properties were $3.50 per Boe in 1996 costs compare to averages for our other $3.45 per Boe in 1994 to $3.65 per Boe and 1995. However, since these proper- properties of $2.15 per Boe in 1994 and in 1995. The increased DD&A rate was ties represented a larger percentage of $2.28 per Boe in 1995. primarily caused by the inclusion of the Devon’s total production, the result was Alta Merger Properties for a full year in a $0.27 per Boe increase in the overall 1995. The Alta Merger Properties were rate in 1996.

DEVON ENERGY CORPORATION 33 MD&A

included for seven months in 1994. INTEREST EXPENSE 1996 vs. 1995 vs. 1994 Interest expense The remaining $1.8 million of the 1995 Interest expense decreased by increased by $1.6 million, or 30%, in increase in oil and gas property related $1.8 million, or 25%, in 1996. Approx- 1995. This increase was due almost DD&A was caused by the increase in imately $1.5 million of the lower exclusively to higher rates in 1995. total production in 1995. interest expense was due to a lower Higher rates accounted for $1.3 million average debt balance in 1996. The of the increased interest expense in GENERAL AND ADMINISTRATIVE average debt balance dropped from 1995. The interest rate on the debt EXPENSES (“G&A”) 1996 vs. 1995 $97.1 million in 1995 to $77.0 million outstanding during 1995 was 6.5%, G&A increased by $0.7 million, or 8%, in 1996. This decrease in average debt compared to 1994’s rate of 5.2%. The in 1996. Employee salaries and related outstanding was primarily the result of overall interest rate averaged 7.3% in benefits were $1.1 million higher in the issuance of the TCP Securities in 1995, compared to the 1994 overall 1996. Legal expenses and abandoned July 1996. rate of 5.9%. acquisition expenses were each $0.2 The remaining $0.3 million of The remaining $0.3 million of million higher in 1996. These increases interest expense reduction in 1996 interest expense increase in 1995 was were partially offset by a $0.1 million resulted from lower interest rates. The caused by a higher average balance reduction in franchise tax expense due interest rates on the debt outstanding outstanding. The average debt balance to Devon’s 1995 change of incorpora- during 1996 averaged 6.3%, compared during 1995 was $97.1 million, tion from Delaware to Oklahoma. to 1995’s rate of 6.5%. The overall compared to 1994’s average balance of Also, G&A reimbursements received interest rate averaged 6.9% in 1996 and $92.5 million. from other joint interest owners in 7.3% in 1995. This includes the effect DISTRIBUTIONS ON PREFERRED Devon-operated properties increased of the interest rate swap discussed SECURITIES OF SUBSIDIARY TRUST 1996 $0.7 million in 1996. below, various fees paid to the banks vs. 1995 Devon, through its newly- 1995 vs. 1994 G&A was and the amortization of certain loan formed affiliate Devon Financing Trust, constant between 1995 and 1994. costs. issued $149.5 million of 6.5% TCP Employee salaries and related overhead Devon entered into an interest Securities. This issuance occurred in a burdens increased by $0.3 million. rate swap agreement in the second private placement during July 1996. Legal fees increased by $0.3 million quarter of 1995. The company termi- The distributions accrue at the rate of while abandoned acquisition costs rose nated the agreement on July 1, 1996 1.625% per quarter. The 1996 distribu- by $0.1 million. These increases were for a gain of $0.8 million. This gain tions of $4.8 million represented offset by a $0.1 million reduction in will be recognized ratably in our oper- slightly less than two quarters’ distribu- franchise taxes and a $0.6 million ating results during the period from tions. This resulted from the issuance increase in G&A reimbursements. Such July 1, 1996 to June 16, 1998 (the orig- date occurring in July. For a complete reimbursements are received from joint inal expiration date of the swap agree- discussion of these matters, see Note 9 interest owners in Devon-operated ment). The recognition of this gain to the consolidated financial statements properties. Approximately $0.2 million reduces interest expense. Approximately contained elsewhere in this report. of the increase in G&A reimbursements $0.2 million of the gain was included in related to a change in the method used the last half of 1996 as an offset to INCOME TAXES 1996 vs. 1995 to calculate the reimbursements on interest expense. During the time when Our effective financial tax rate in 1996 certain properties. This change was the agreement was still in effect, it was 41%, compared to 1995’s rate of retroactive to the prior two years. The resulted in $0.1 million of reduced 43%. Both rates were above the statu- reduction in franchise taxes resulted interest expense in the year 1995, and tory federal tax rate of 35%. This from Devon’s reincorporation from had no effect on interest expense for the resulted from state income taxes, and Delaware to Oklahoma in June 1995. first six months of 1996. certain tax aspects of the San Juan Basin Transaction and the 1994 Alta Merger.

34 DEVON ENERGY CORPORATION 1995 vs 1994 Our effective financial tax rate in 1995 our new Canadian operations. This credit line totals $12.5 was 43%, compared to 1994’s rate of 36%. State income million Canadian dollars, all of which was available at year- taxes and certain tax aspects of the San Juan Basin Transac- end. (See Note 7 to the consolidated financial statements tion were the primary factors which increased Devon’s finan- included elsewhere in this report for a detailed discussion of cial tax rate. The San Juan Basin Transaction also had a the credit lines.) The proceeds from the TCP Securities significant effect on the portion of income taxes which are offering in July 1996 mentioned earlier, were used to retire current versus deferred. long-term debt. This reduction in debt increased the amount of our credit lines available for future borrowings. CAPITAL EXPENDITURES, Devon’s San Juan Basin coal seam gas production is CAPITAL RESOURCES AND LIQUIDITY subject to uncertainties regarding additional royalties and The following discussion of capital expenditures, taxes. If such uncertainties are resolved in 1997, the resolu- capital resources and liquidity should be read in conjunction tions are likely to require the use of operating cash flow. with the consolidated statements of cash flows included in However, we do not expect such amount to be material to this report. our overall liquidity, capital resources or net earnings. For a complete discussion of these matters, see Note 12 to the CAPITAL EXPENDITURES Approximately $98.9 consolidated financial statements contained elsewhere in this million of cash was spent in 1996 for capital expenditures. report. Of this, $85.0 million was related to the acquisition, drilling or development of oil and gas properties. Most of the drilling 1997 ESTIMATES and development efforts in 1996 centered in the Permian Basin. This included 176 of the 194 oil and gas wells which The forward-looking statements provided in this Devon drilled during 1996. Most of Devon’s 1996 non-oil discussion are based on management’s examination of histor- and gas property related capital expenditures involved the ical operating trends, the December 31, 1996 reserve reports $12.5 million purchase of the office building in which its of LaRoche Petroleum Consultants, Ltd. and AMH Group Oklahoma City offices are located. This purchase was closed Ltd., data in Devon’s files and other data available from third on December 31, 1996. parties. We caution that our future oil, gas and NGL produc- tion, revenues and expenses are subject to all of the risks and

OTHER CASH USES We began paying quarterly divi- uncertainties normally incident to the exploration for and dends on common stock in the second quarter of 1993 at the development and production of oil and gas. These risks rate of $0.03 per share. In the fourth quarter of 1996, the include, but are not limited to, environmental risks, drilling quarterly dividend rate was increased to $0.05 per share. risks, regulatory changes, the uncertainty inherent in esti- mating future oil and gas production or reserves, and other

CAPITAL RESOURCES AND LIQUIDITY Net cash risks as outlined below. The scope of our operations increased provided by operating activities (“operating cash flow”) was significantly with the KMG-NAOS transaction. This the primary source of capital and short-term liquidity in increases the margin of error inherent in estimating our 1997 1996. Operating cash flow in 1996 totaled $86.2 million production volumes, prices and expenses. Also, the financial compared to $61.3 million in 1995. This resulted in an results for Devon’s new Canadian operations, obtained in the increase of 41%. KMG-NAOS transaction, are subject to currency exchange In addition to operating cash flow, Devon’s credit lines rate risks. have been an important source of capital and liquidity. At year-end 1996, long-term credit lines totaled $260 million, of which $252 million was available for future use. At the end of 1996, in connection with the KMG-NAOS acquisi- tion, we also established a demand revolving credit line for

DEVON ENERGY CORPORATION 35 MD&A

ASSUMPTIONS AND RISKS FOR PRICE AND PRODUCTION GAS PRODUCTION AND RELATIVE PRICES We expect our ESTIMATES Prices for oil, natural gas and NGLs are deter- total gas production in 1997 will be between 64.0 Bcf and mined primarily by prevailing market conditions. Market 75.0 Bcf. It is expected that coal seam gas production will be conditions for these products are influenced by regional and 16.5 Bcf to 19.5 Bcf. Canadian production in 1997 is esti- world-wide economic growth, weather and other substantially mated to be between 7.0 Bcf and 8.0 Bcf. We expect produc- variable factors. These factors are beyond our control and are tion from the remainder of our gas properties to total difficult to predict. Over 90% of Devon’s revenues are attrib- between 40.5 Bcf and 47.5 Bcf. utable to sales of these three commodities. Consequently, our Devon expects its 1997 coal seam average price will be financial results and resources are highly influenced by this between $0.25 and $0.55 less than Texas Gulf Coast spot price volatility. averages. This includes an expected $0.55 per Mcf from the Estimates for Devon’s future production of oil, natural San Juan Basin Transaction. Our Canadian gas production is gas and NGLs are based on the assumption that market expected to average from between $0.85 to $1.20 less than demand and prices for oil and gas will continue at levels that Texas Gulf Coast spot prices. (These Canadian differentials allow for profitable production of these products. Although are expressed in U.S. dollars, using the year-end 1996 our management believes these assumptions to be reasonable, exchange rate of $0.73 U.S. dollar to $1.00 Canadian dollar.) there can be no assurance of such stability. Devon’s remaining gas production is expected to average Certain of Devon’s individual oil and gas properties are $0.05 to $0.25 less than Texas Gulf Coast spot prices during sufficiently significant as to have a material impact on the 1997. company’s overall financial results. With respect to oil production, these properties include the West Red Lake Field NGL PRODUCTION We expect our production of NGLs and the Grayburg-Jackson Unit, both in southeast New in 1997 to total between 1.1 million barrels and 1.3 million Mexico. In addition, our interest in NEBU and the 32-9 barrels. Unit can have a substantive effect on overall gas production. The production, transportation and marketing of oil, PRODUCTION AND OPERATING EXPENSES Devon’s natural gas and NGLs are complex processes which are production and operating expenses vary in response to several subject to disruption. This is caused by transportation and factors. Among the most significant of these factors are addi- processing availability, mechanical failure, human error, mete- tions or deletions to our property base and changes in orological events and numerous other factors. The following production taxes. Other significant factors are general forward-looking statements were prepared assuming demand, changes in the prices of services and materials that are used in curtailment, producibility and general market conditions for the operation of our properties and the amount of repair and our oil, natural gas and NGLs for 1997 will be substantially workover activity required on those properties. similar to those of 1996, unless otherwise noted. Given the The addition of the KMG-NAOS Properties is general limitations expressed herein, our forward-looking expected to be the largest contributor to an increase in recur- statements for 1997 are set forth below. ring lease operating expenses in 1997. The additional revenues contributed by these properties should also cause OIL PRODUCTION AND RELATIVE PRICES Devon expects production taxes to rise. In addition, well workover expenses its oil production in 1997 to total between 5.9 million are anticipated to increase in 1997. barrels and 6.9 million barrels. We expect our net oil prices Oil, gas and NGL prices will have a direct effect on will average from between $0.05 below to $0.20 above West production taxes to be incurred in 1997. Future prices could Texas Intermediate posted prices in 1997. also have an effect on whether proposed workover projects are economically feasible. These factors coupled with the uncertainty of future oil, gas and NGL prices, increase the

36 DEVON ENERGY CORPORATION margin of error inherent in estimating future production and INTEREST EXPENSE We expect to fund substantially all operating costs. Given these uncertainties, we estimate that of our anticipated expenditures during 1997 with working 1997’s total production and operating costs will be between capital and internally generated cash flow. Should our actual $75 million and $87 million. capital expenditures or internally generated cash flow vary significantly from expectations, interest expense could differ DEPRECIATION, DEPLETION AND AMORTIZATION The materially from the following estimate. Given this limitation, 1997 DD&A rate will depend on various factors. Most interest expense is expected to be less than $1 million in notable among such factors is the amount of proved reserves 1997. that could be added from drilling or acquisition efforts in 1997 compared to costs incurred for such efforts. Another DISTRIBUTIONS ON TCP SECURITIES TCP Securities notable factor is the revisions to Devon’s year-end 1996 are convertible into common shares of Devon at the holder’s reserve estimates which will be made during 1997. option. Should any of the holders of the TCP Securities elect The DD&A rate as of the beginning of 1997 was to convert during 1997, it would reduce the amount of $3.76 per Boe. This rate includes the effect of the December required distributions. Assuming all $149.5 million of TCP 31, 1996, acquisition of the KMG-NAOS Properties. Securities are outstanding for the entire year, we will make Conversely, the 1996 yearly rate of $3.88 per Boe did not $9.7 million of distributions in 1997. reflect the effect of these properties. Assuming a 1997 rate of between $3.80 per Boe and $4.20 per Boe, 1997 DD&A INCOME TAXES Devon expects its financial income tax expense (including approximately $2.5 million of non-oil and rate in 1997 to be between 38% and 42%. Regardless of the gas property related DD&A) is expected to be $76 million to level of pre-tax earnings reported for financial purposes, we $84 million. will have a minimum of approximately $2.5 million of finan- cial income tax expense. This results from various tax aspects GENERAL AND ADMINISTRATIVE EXPENSES Devon’s of the 1994 Alta Merger, the San Juan Basin Transaction and general and administrative expenses include the costs of many the KMG-NAOS acquisition. Therefore, if the actual amount different goods and services used in support of the company’s of 1997 pre-tax earnings differs materially from what Devon business. These goods and services are subject to general price currently expects, the actual financial income tax rate for level increases or decreases. In addition, our G&A expenses 1997 could fall outside the 38% to 42% expected rate. Also, vary with our level of activity and the related staffing needs. based on our current expectations of 1997 taxable income, G&A expenses are also affected by the amount of profes- we anticipate our current portion of 1997 income taxes will sional services required during any given period. The addi- be between $9 million and $13 million. However, revenue tion of the KMG-NAOS Properties will increase Devon’s and earnings fluctuations could easily make these tax esti- general level of activity as well as its staffing requirements mates obsolete. during 1997. Should our anticipated needs or the prices of the required goods and services differ significantly from our CAPITAL EXPENDITURES Our capital expenditures expectations, actual G&A expenses could vary materially budget is based on an expected range of future oil, natural from the estimate. Given these limitations, G&A expenses gas and NGL prices as well as the expected costs of the are expected to be between $12 million and $14 million in capital additions. Should our price expectations for our 1997. future production change significantly, we may accelerate or defer some projects. Thus, Devon would increase or decrease total 1997 capital expenditures. In addition, if the actual cost of the budgeted items varies significantly from the amount anticipated, actual capital expenditures could vary materially from our estimate.

DEVON ENERGY CORPORATION 37 MD&A

Though Devon has completed at above. However, we consider our capital standards for transfers and servicing of least one major acquisition in each of resources to be more than adequate to financial assets and extinguishment of the last several years, these transactions fund our anticipated capital expendi- liabilities. This is based on a consistent are opportunity driven. Thus, we do not tures. application of a financial-components “budget”, nor can we reasonably predict, Based on the expected level of approach that focuses on control. It the timing or size of such possible acqui- 1997’s capital expenditures and net cash distinguishes transfers of financial assets sitions, if any. provided by operations, Devon does not that are sales from transfers that are Given these limitations, Devon expect to rely on its credit lines to fund secured borrowings. We do not expect expects its 1997 capital expenditures for a material portion of its capital expendi- that adoption of SFAS No. 125 will drilling and development efforts to total tures. However, if significant acquisi- have a material impact on our financial between $120 million and $135 million. tions or other unplanned capital position or results of operations. This includes $8 million to $11 million requirements arise during the year, we In October, 1996, the American in Canada. (Canadian amounts are could utilize our credit lines. The Institute of Certified Public Accountants expressed in U.S. dollars, using the year- unused portion of these credit lines at issued Statement of Position (SOP) 96- end 1996 exchange rate of $0.73 U.S. the end of 1996 consisted of $252 1, “Environmental Remediation Liabili- dollar to $1.00 Canadian dollar.) We million of long-term credit facilities. In ties.” SOP 96-1 was adopted by Devon expect to spend $50 million to $65 addition, we had a $12.5 million (Cana- on January 1, 1997. It requires, among million in 1997 for drilling, facilities dian dollars) demand facility for our other things, that environmental remedi- and waterflood costs related to reserves new Canadian operations. If so desired, ation liabilities be accrued when the classified as proved as of year-end 1996. we believe our lenders would increase criteria of SFAS No. 5, “Accounting for We also plan to spend another $15 our credit lines to at least $450 million Contingencies,” have been met. SOP million to $20 million on new, higher to $500 million. However, we do not 96-1 also provides guidance with respect risk/reward projects. desire nor anticipate a need to increase to the measurement of the remediation our credit lines above their current liabilities. Such accounting is consistent OTHER CASH USES Devon’s levels. In fact, to lower its borrowing with our current method of accounting management expects the policy of costs, Devon may reduce its credit lines for environmental remediation costs. paying a quarterly dividend to continue. in 1997 until a need for significant Therefore, adoption of SOP 96-1 will With the current $0.05 per share quar- capital arises. not have a material impact on our finan- terly dividend rate and 32.1 million cial position or results of operations. ■ shares of common stock outstanding, IMPACT OF RECENTLY ISSUED 1997 dividends are expected to approxi- ACCOUNTING STANDARDS NOT YET mate $6.4 million. ADOPTED In June, 1996, the Financial Accounting Standards Board issued CAPITAL RESOURCES AND Statement of Financial Accounting Stan- LIQUIDITY The estimated future drilling dard No. 125, “Accounting for Transfers and development activities are expected and Servicing of Financial Assets and to be funded through a combination of Extinguishments of Liabilities.” SFAS working capital and net cash provided No. 125 is effective for certain transfers by operations. The amount of net cash and servicing of financial assets and to be provided by operating activities in extinguishment of liabilities occurring 1997 is uncertain due to the factors after December 31, 1996. It is effective affecting revenues and expenses cited for other transfers of financial assets occurring after December 31, 1997. It is to be applied prospectively. SFAS No. 125 provides accounting and reporting

38 DEVON ENERGY CORPORATION Management’s Responsibility for Financial Statements

Devon Energy Corporation’s management takes ments, and employs all testing and verification procedures as responsibility for the accompanying consolidated financial it considers necessary to arrive at an opinion on the fairness statements which have been prepared in conformity with of financial statements. generally accepted accounting principles appropriate in the The Board of Directors pursues its responsibilities for circumstances. They are based on our best estimate and judg- the accompanying consolidated financial statements through ment. Financial information elsewhere in this annual report is its Audit Committee. The Committee meets periodically with consistent with the data presented in these statements. management and the independent auditors to assure that they In order to carry out our responsibility concerning the are carrying out their responsibilities. The independent audi- integrity and objectivity of published financial data, we main- tors have full and free access to the Committee members and tain an accounting system and related internal controls. We meet with them to discuss auditing and financial reporting believe the system is sufficient in all material respects to matters. ■ provide reasonable assurance that financial records are reliable for preparing financial statements and that assets are safe- Devon Energy Corporation guarded from loss or unauthorized use. Executive Committee Our independent accounting firm, KPMG Peat J. Larry Nichols Darryl G. Smette Marwick LLP, provides objective consideration of Devon President Vice President Energy management’s discharge of its responsibilities as it relates to the fairness of reported operating results and the H. R. Sanders, Jr. H. Allen Turner Executive Vice President Vice President financial position of the company. This firm obtains and maintains an understanding of our accounting and financial J. Michael Lacey William T. Vaughn controls to the extent necessary to audit our financial state- Vice President Vice President

Independent Auditors’ Report

The Board of Directors and Stockholders financial statements. An audit also includes assessing the Devon Energy Corporation: accounting principles used and significant estimates made by management, as well as evaluating the overall financial state- We have audited the consolidated balance sheets of ment presentation. We believe that our audits provide a Devon Energy Corporation and subsidiaries as of December reasonable basis for our opinion. 31, 1996, 1995 and 1994, and the related consolidated state- In our opinion, the consolidated financial statements ments of operations, stockholders’ equity and cash flows for referred to above present fairly, in all material respects, the each of the years then ended. These consolidated financial financial position of Devon Energy Corporation and statements are the responsibility of the Company’s manage- subsidiaries as of December 31, 1996, 1995 and 1994, and ment. Our responsibility is to express an opinion on these the results of their operations and their cash flows for the consolidated financial statements based on our audits. years then ended, in conformity with generally accepted We conducted our audits in accordance with generally accounting principles. ■ accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance KPMG Peat Marwick LLP about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, Oklahoma City, Oklahoma evidence supporting the amounts and disclosures in the February 7, 1997

DEVON ENERGY CORPORATION 39 Consolidated Balance Sheets

DEVON ENERGY CORPORATION AND SUBSIDIARIES

December 31, 1996 1995 1994 ASSETS Current assets: Cash and cash equivalents $ 9,401,350 8,897,891 8,336,371 Accounts receivable (Note 5) 29,580,306 14,400,295 15,626,799 Inventories 2,103,486 605,263 534,326 Prepaid expenses 688,752 222,135 564,371 Deferred income taxes (Note 8) 1,600,000 749,000 262,000 Total current assets 43,373,894 24,874,584 25,323,867 Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties (Note 6) 974,805,756 631,437,904 523,941,141 Less accumulated depreciation, depletion and amortization 281,959,410 239,619,167 202,634,961 692,846,346 391,818,737 321,306,180 Other 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 6,394,897 Revenues 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 17,018,589 Revenues and royalties due to others 1,053,270 816,412 1,383,135 Other liabilities (Notes 3 and 11) 10,325,999 8,623,057 – Long-term debt (Note 7) 8,000,000 143,000,000 98,000,000 Deferred revenue 205,859 72,761 1,299,947 Deferred income taxes (Note 8) 81,121,000 34,452,000 27,340,000

Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trust holding solely 6.5% convertible junior subordinated debentures 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 1995 and 22,050,996 in 1994 3,214,130 2,211,190 2,205,100 Additional paid-in capital 388,090,930 167,430,347 166,654,305 Retained earnings 81,099,357 49,399,461 37,546,460 Total stockholders’ equity 472,404,417 219,040,998 206,405,865 Commitments and contingencies (Notes 11 and 12) Total liabilities and stockholders’ equity $ 746,250,800 421,564,117 351,447,536 See accompanying notes to consolidated financial statements.

40 DEVON ENERGY CORPORATION Consolidated Statements of Operations

DEVON ENERGY CORPORATION AND SUBSIDIARIES

Year Ended December 31, 1996 1995 1994 REVENUES Oil sales $ 80,142,073 55,289,819 38,086,076 Gas sales 68,049,478 50,732,158 56,371,452 Natural gas liquids sales 14,366,771 6,403,663 4,908,126 Other 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 24,520,757 Production taxes 10,657,814 6,832,507 6,899,743 Depreciation, depletion and amortization (Note 6) 43,361,029 38,089,783 34,132,150 General and administrative expenses 9,101,429 8,418,739 8,424,687 Interest expense 5,276,527 7,051,142 5,438,911 Distributions 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 4,495,000 415,000 Deferred 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 common share outstanding (Note 1): Assuming no dilution $ 1.57 $ 0.66 0.64 Assuming full dilution $ 1.52 $ 0.66 0.64

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

DEVON ENERGY CORPORATION 41 Consolidated Statements of Stockholders’ Equity

DEVON ENERGY CORPORATION AND SUBSIDIARIES

Year Ended December 31, 1996 1995 1994

COMMON STOCK Balance, beginning of year $ 2,211,190 2,205,100 2,084,232 Par 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 167,430,347 166,654,305 144,403,743 Common shares issued, net of issuance costs 220,660,583 776,042 22,250,562

Balance, end of year 388,090,930 167,430,347 166,654,305

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

Balance, end of year 81,099,357 49,399,461 37,546,460

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

42 DEVON ENERGY CORPORATION Consolidated Statements of Cash Flows

DEVON ENERGY CORPORATION AND SUBSIDIARIES

Year Ended December 31, 1996 1995 1994

CASH FLOWS FROM OPERATING ACTIVITIES Net earnings $ 34,800,532 14,501,899 13,744,711 Adjustments 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 7,197,000 Changes in assets and liabilities net of effects of acquisitions of businesses (Note 2): (Increase) decrease in: Accounts receivable (15,470,528) 1,213,877 123,388 Inventories (176,286) (70,937) 181,475 Prepaid expenses (466,617) 342,236 712 Other 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) 997,645 Revenues 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 4,649,257 Capital 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 32,500,000 Principal payments on revolving line of credit (164,000,000) (7,000,000) (14,500,000) Issuance of common stock, net of issuance costs 577,483 782,132 380,244 Issuance 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 8,336,371 See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION 43 Notes to Consolidated Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

1 Summary of Significant Accounting Policies PROPERTY AND EQUIPMENT Devon follows the full cost method of accounting for Accounting policies used by Devon Energy Corpora- its oil and gas properties. Accordingly, all costs incidental to tion and subsidiaries (“Devon”) reflect industry practices and the acquisition, exploration and development of oil and gas conform to generally accepted accounting principles. The properties, including costs of undeveloped leasehold, dry more significant of such policies are briefly discussed below. holes and leasehold equipment, are capitalized. Net capital- ized costs are limited to the estimated future net revenues, BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION discounted at 10% per annum, from proved oil, natural gas Devon is engaged primarily in oil and gas exploration, and natural gas liquids reserves. Such limitations are imposed development and production, and the acquisition of separately for Devon’s oil and gas properties in the United producing properties. Such activities are primarily in the States and Canada. Capitalized costs are depleted by an states of New Mexico, Texas, Oklahoma, Wyoming and equivalent unit-of-production method, converting gas and Louisiana. Effective December 31, 1996, Devon began oper- natural gas liquids to oil at the ratio of one barrel (“Bbl”) of ations in Alberta, Canada. Devon’s share of the assets, liabili- oil to six thousand cubic feet (“Mcf”) of natural gas and one ties, revenues and expenses of affiliated partnerships and the barrel of oil to 42 gallons of natural gas liquids. No gain or accounts of its wholly-owned subsidiaries are included in the loss is recognized upon disposal of oil and gas properties accompanying consolidated financial statements. All signifi- unless such disposal significantly alters the relationship cant intercompany accounts and transactions have been elim- between capitalized costs and proved reserves. inated in consolidation. Devon adopted the provisions of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and USE OF ESTIMATES IN THE PREPARATION for Long-Lived Assets to be Disposed Of,” on January 1, OF FINANCIAL STATEMENTS 1996. SFAS No. 121 requires that long-lived assets and The preparation of financial statements in conformity certain identifiable intangibles be reviewed for impairment with generally accepted accounting principles requires whenever events or changes in circumstances indicate that the management to make estimates and assumptions that affect carrying amount of an asset may not be recoverable. Due to the reported amounts of assets and liabilities and disclosure Devon’s use of the full cost method of accounting for its oil of contingent assets and liabilities at the date of the financial and gas properties, SFAS No. 121 does not apply to Devon’s statements, and the reported amounts of revenues and oil and gas property assets which comprise approximately expenses during the reporting period. Actual amounts could 97% of Devon’s net property and equipment. Accordingly, differ from those estimates. the adoption of SFAS No. 121 did not have an impact on

INVENTORIES Devon’s financial position or results of operations in 1996. Inventories, which consist primarily of tubular goods, Depreciation and amortization of other property and parts and supplies, are stated at cost, determined principally equipment, including leasehold improvements, are provided by the average cost method, which is not in excess of net real- using the straight-line method based on estimated useful lives izable value. from 3 to 39 years.

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

44 DEVON ENERGY CORPORATION GAS BALANCING During the course of normal operations, Devon and who accounted for over 10% of Devon’s gas sales. These three other joint interest owners of natural gas reservoirs will take purchasers and their respective share of gas sales were: Aquila more or less than their respective ownership share of the - 21%; Enron - 19%; and Meridian Oil Trading, Inc. - 18%. natural gas volumes produced. These volumetric imbalances INCOME TAXES are monitored over the lives of the wells’ production capa- Devon accounts for income taxes using the asset and bility. If an imbalance exists at the time the wells’ reserves are liability method, whereby deferred tax assets and liabilities are depleted, cash settlements are made among the joint interest recognized for the future tax consequences attributable to owners under a variety of arrangements. differences between the financial statement carrying amounts Devon follows the sales method of accounting for gas of assets and liabilities and their respective tax bases, as well imbalances. A liability is recorded only if Devon’s excess takes as the future tax consequences attributable to the future of natural gas volumes exceed its estimated remaining recov- utilization of existing net operating loss and other types of erable reserves. No receivables are recorded for those wells carryforwards. Deferred tax assets and liabilities are measured where Devon has taken less than its ownership share of gas using enacted tax rates expected to apply to taxable income in production. the years in which those temporary differences and carryfor-

STOCK OPTIONS wards are expected to be recovered or settled. The effect on On January 1, 1996, Devon adopted SFAS No. 123, deferred tax assets and liabilities of a change in tax rates is “Accounting for Stock-Based Compensation,” which permits recognized in income in the period that includes the enact- entities to recognize over the vesting period the fair value of ment date. all stock-based awards on the date of grant. Alternatively, GENERAL AND ADMINISTRATIVE EXPENSES SFAS No. 123 also allows entities to continue to apply provi- General and administrative expenses are reported net sions of APB No. 25, “Accounting for Stock Issued to of amounts allocated to working interest owners of the oil Employees,” whereby compensation expense is recorded on and gas properties operated by Devon, net of amounts the date of grant only if the current market price of the charged to affiliated partnerships for administrative and over- underlying stock exceeds the exercise price. Companies which head costs, and net of amounts capitalized pursuant to the continue to apply the provisions of APB No. 25 are required full cost method of accounting. by SFAS No. 123 to disclose pro forma net earnings and net earnings per share for employee stock option grants made in NET EARNINGS PER COMMON SHARE 1995 and future years as if the fair-value-based method Net earnings per common share assuming no dilution defined in SFAS No. 123 had been applied. Devon has are based upon the weighted average number of shares of elected to continue to apply the provisions of APB No. 25, common stock outstanding during the year. Stock options and has provided the pro forma disclosures required by SFAS have been excluded since they would not have had a signifi- No. 123 in Note 10. cant dilutive effect, and the Trust Convertible Preferred Secu- rities issued in 1996 are excluded as they are not common MAJOR PURCHASERS stock equivalents. During 1996, there was one purchaser, Aquila Energy Marketing Corporation (“Aquila”), who accounted for over 10% of Devon’s gas sales. Aquila accounted for 45% of Devon’s 1996 gas sales. During 1995, there were two purchasers who accounted for over 10% of Devon’s gas sales. These two purchasers and their respective share of gas sales were: Aquila - 31%; and Enron Gas Marketing, Inc. (“Enron”) - 16%. During 1994, there were three purchasers

DEVON ENERGY CORPORATION 45 For 1996, net earnings per common share assuming In October, 1996, the American Institute of Certified full dilution is based upon the adjusted amount of net earn- Public Accountants issued Statement of Position (SOP) 96-1, ings and the adjusted number of common shares outstanding “Environmental Remediation Liabilities.” SOP 96-1 was assuming the Trust Convertible Preferred Securities had been adopted by Devon on January 1, 1997. It requires, among converted to common stock as of their issuance date in July other things, that environmental remediation liabilities be 1996. The fully diluted per share amount in 1996 also accrued when the criteria of SFAS No. 5, “Accounting for includes the effect of Devon’s outstanding stock options as Contingencies,” have been met. SOP 96-1 also provides calculated using the treasury stock method. The 1996 guidance with respect to the measurement of the remediation adjusted net earnings used for the fully diluted calculation liabilities. Such accounting is consistent with Devon’s method was $37.8 million, and the adjusted number of common of accounting for environmental remediation costs. There- shares was 24,860,910. fore, adoption of SOP 96-1 will not have a material impact No fully diluted per share amounts are presented for on Devon’s financial position or results of operations. 1995 and 1994 due to the insignificant dilutive effect of the stock options outstanding. 2 Acquisitions and Pro Forma Information DIVIDENDS Dividends on common stock were paid in 1994, 1995 On December 31, 1996, Devon acquired all of Kerr- and the first three quarters of 1996 at a per share rate of McGee Corporation’s (“Kerr-McGee”) North American $0.03 per quarter. The dividend rate was increased to $0.05 onshore oil and gas exploration and production business and per share for the fourth quarter of 1996. properties (the “KMG-NAOS Properties”). As consideration, Devon issued 9,954,000 shares of its common stock to Kerr- FAIR VALUE OF FINANCIAL INSTRUMENTS McGee. The acquisition was made pursuant to an October Devon’s only financial instruments for which the fair 17, 1996, agreement and plan of merger among Devon, value differs materially from the carrying value are the Kerr-McGee and certain of their subsidiaries. interest rate swap discussed in Note 7 and the Trust Convert- Devon recorded the KMG-NAOS Properties at ible Preferred Securities discussed in Note 9. The fair value approximately $221.6 million. Such value was based on the and the carrying value for all other financial instruments value of the shares of Devon common stock issued as deter- (cash and equivalents, accounts receivable, accounts payable mined pursuant to generally accepted accounting principles. and long-term debt) are approximately equal. Such equality is An additional $28.0 million was allocated to the KMG- due to the short-term nature of the current assets and liabili- NAOS Properties for the deferred income tax liability created ties and the fact that the interest rates paid on Devon’s long- as a result of the substantially tax-free nature of the transac- term debt are set for periods of three months or less. tion to Kerr-McGee. Excluding the additional deferred tax liability, the amount recorded for the KMG-NAOS Proper- STATEMENTS OF CASH FLOWS ties includes approximately $191.7 million allocated to For purposes of the consolidated statements of cash proved oil and gas reserves, $29.0 million allocated to unde- flows, Devon considers all highly liquid investments with veloped leasehold acquired and $0.9 million allocated to original maturities of three months or less to be cash equiva- inventories and other assets acquired. Including the addi- lents. tional $28.0 million of deferred tax liability, $214.2 million

COMMITMENTS AND CONTINGENCIES was allocated to proved reserves and $34.5 million to unde- Liabilities for loss contingencies arising from claims, veloped leasehold. assessments, litigation or other sources are recorded when it is Estimated proved reserves associated with the KMG- probable that a liability has been incurred and the amount NAOS Properties as of December 31, 1996, were 47 million can be reasonably estimated. barrels of oil equivalent (“MMBoe”) in the United States and 15 MMBoe in Canada. These reserves are approximately 36% oil and natural gas liquids and 64% natural gas.

46 DEVON ENERGY CORPORATION Included in the acquired reserves were certain proved unde- accounted for by the purchase method of accounting for veloped reserves, for which Devon expects to incur approxi- business combinations. Accordingly, the accompanying 1994 mately $6 million of future capital costs. The United States consolidated statement of operations does not include any assets acquired are located predominantly in the Rocky revenue or expenses associated with Alta prior to the May 18, Mountain, Permian Basin and Mid-Continent areas of the 1994 closing date. country. All of these areas were already core areas of Devon’s operations. (The quantities of proved reserves and the esti- PRO FORMA INFORMATION (UNAUDITED) mated development costs stated in this paragraph are unau- The 1996 acquisition of the KMG-NAOS Properties dited.) as described above was accounted for by the purchase method On December 18, 1995, Devon acquired additional of accounting for business combinations. Accordingly, the interests in certain of its Wyoming oil and natural gas proper- accompanying 1996 consolidated statement of operations ties and a gas processing plant (the “Worland Properties”) for does not include any revenues or expenses associated with the approximately $50.3 million. The acquisition was primarily KMG-NAOS Properties. Following are Devon’s pro forma funded with $46.0 million of borrowings from Devon’s credit results for 1996 assuming the acquisition of the KMG- lines. Approximately $46.3 million of the purchase price was NAOS Properties occurred on January 1, 1996: allocated to proved oil, gas and natural gas liquids reserves 1996 and the plant. The remaining $4.0 million of the purchase REVENUES price was allocated to undeveloped leasehold. Oil sales $ 148,337,000 On February 18, 1994, Devon and Alta Energy Gas sales 125,092,000 Natural gas liquids sales 19,081,000 Corporation (“Alta”) entered into an Agreement and Plan of Other 4,674,000 Merger, as amended on April 13, 1994, whereby Alta was Total revenues 297,184,000 merged into a wholly-owned subsidiary of Devon (the “Alta COSTS AND EXPENSES Merger”). The Alta Merger was consummated on May 18, Lease operating expenses 58,384,000 Production taxes 20,167,000 1994, at which date the separate existence of Alta ceased. Depreciation, depletion and amortization 78,310,000 Alta’s common stockholders received approximately General and administrative expenses 14,101,000 Interest expense 5,277,000 1,168,000 shares of Devon common stock and $1.5 million Distributions on preferred securities in cash upon consummation of the Alta Merger. Subse- of subsidiary trust 4,753,000 quently, in February 1995, former Alta stockholders received Total costs and expenses 180,992,000 an additional cash payment of $2.4 million based upon the Earnings before income taxes 116,192,000 post-closing evaluation of the Camille Adams #1 well in INCOME TAX EXPENSE Louisiana. Devon also incurred $41.4 million of other costs Current 14,023,000 related to the Alta Merger. This included $31.7 million to Deferred 32,721,000 acquire Alta’s debt from its creditors, $3.0 million to acquire Total income tax expense 46,744,000 shares of Alta preferred and common stock, $3.8 million Net earnings $ 69,448,000 loaned to Alta for operating funds, $1.5 million to acquire Net earnings per average common share outstanding: certain net profits interests from Alta creditors, and $1.4 Assuming no dilution $2.16 million for third party costs related to the Alta Merger. Assuming full dilution $2.08 Devon recorded additional deferred tax liabilities of Weighted average common shares outstanding 32,086,310 $11.5 million due to the substantially tax-free nature of the PRODUCTION DATA Alta Merger to the former Alta stockholders. Excluding the Oil (Barrels) 7,241,000 $11.5 million of additional deferred tax liabilities, approxi- Gas (Mcf) 70,925,000 Natural gas liquids (Barrels) 1,304,000 mately $69.4 million of the total consideration involved in the 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

DEVON ENERGY CORPORATION 47 The 1995 acquisition of the Worland Properties Properties prior to the closing date of December 18, 1995. described above was accounted for by the purchase method of Following are Devon’s pro forma 1995 results assuming the accounting for business combinations. Accordingly, the acquisition of KMG-NAOS Properties and the Worland accompanying consolidated statements of operations do not Properties both occurred on January 1, 1995: include any revenues or expenses related to the Worland

1995 Pro Forma Effect of Devon KMG-NAOS Worland Devon Historical Properties Properties Pro Forma

Total revenues $ 113,303,000 108,279,000 5,349,000 226,931,000 Net earnings $ 14,502,000 14,335,000 (1,405,000) 27,432,000 Net earnings per share $ 0.66 0.86

3 San Juan Basin Transaction Effective January 1, 1995, Devon and an unrelated the source of the most significant impact of the transaction, company entered into a transaction covering substantially all Devon receives payments equal to 75% of the Section 29 tax of Devon’s San Juan Basin coal seam gas properties (the “San credits generated by the properties. And fourth, Devon Juan Basin Transaction”). These coal seam gas properties retained a 75% reversionary interest in any reserves in excess represented Devon’s largest oil and gas reserve position as of of the 186.2 Bcf estimated to exist as of December 31, 1994. December 31, 1994. The properties’ estimated reserves as of Each of these parts of the San Juan Basin Transaction, and year-end 1994 were 199.2 billion cubic feet (“Bcf”) of their effects on Devon’s operations, are described in more natural gas, or 31% of Devon’s 633.2 equivalent Bcf of detail in the following paragraphs. combined oil and natural gas reserves. In addition to the cash The production payment retained by Devon is equal flow and earnings impact normally associated with oil and to 94.05% of the first 143.4 Bcf of gas produced from the gas production, these properties also qualify as a “nonconven- properties, or 134.9 Bcf. As such, Devon continues to record tional fuel source” under the Internal Revenue Code of 1986. gas sales and associated production and operating expenses Consequently, gas produced from these properties through and reserves associated with the production payment. the year 2002 qualifies for Section 29 tax credits, which as of Production from the retained production payment is year-end 1996 were equal to approximately $1.02 per million currently estimated to occur over a period of 12 years. Btu (“MMBtu”). The conveyance of the properties which are not The San Juan Basin Transaction involves approxi- subject to the retained production payment or the repurchase mately 186.2 Bcf, or 93%, of the year-end 1994 coal seam option was accounted for as a sale of oil and gas properties. gas reserves, and has four major parts associated with it. First, Accordingly, 7.2 Bcf of gas reserves were removed from total Devon conveyed to the unrelated party 179 Bcf of the prop- proved reserves, and the $5.2 million of proceeds reduced the erties’ reserves. However, for financial reporting purposes, book value of oil and gas properties. The conveyance to the Devon retained all of such reserves and their future produc- third party is limited exclusively to the existing wells drilled tion and cash flow through a volumetric production payment as of January 1, 1995. Wells to be drilled in the future, if any, and a repurchase option. Second, Devon conveyed outright are not included in this transaction. to the unrelated party 7.2 Bcf of reserves for a sales price of In addition to receiving 94.05% of the properties’ net $5.2 million. The reserves and future cash flow associated cash flow through the retained production payment, Devon with this conveyance were not retained by Devon. Third, and receives quarterly payments from the third party equal to

48 DEVON ENERGY CORPORATION 75% of the value of the Section 29 tax credits which are generated by production from such properties until the 4 Supplemental Cash Flow Information earlier of December 31, 2002, or until the option to repur- Cash payments for interest in 1996, 1995, and 1994 chase is exercised. For the years ended December 31, 1996 were approximately $5.5 million, $6.7 million and $5.1 and 1995, Devon received $11.5 million and $13.9 million, million, respectively. Cash payments for federal and state respectively, related to the credits. Of these amounts, $10.3 income taxes in 1996, 1995, and 1994 were approximately million and $12.8 million were recorded as additional gas $3.4 million, $2.2 million and $1.8 million, respectively. sales in 1996 and 1995, respectively, and $1.2 million and The 1996 acquisition of the KMG-NAOS Properties $1.1 million were recorded as an addition to liabilities in and the 1994 Alta Merger involved cash and non-cash 1996 and 1995, respectively, as discussed in the following consideration as presented below: paragraph. Based on the reserves estimated at December 31, 1996, and an assumed annual inflation factor of 2%, Devon 1996 1994 estimates it will receive total tax credit payments of approxi- Cash payments made $ – 42,915,845 mately $58 million from 1997 through 2002. Value of common stock issued 221,576,040 21,991,084 Liabilities assumed – 7,192,671 Devon has an option to repurchase the properties at Deferred tax liability created 28,029,000 11,500,000 any time. The purchase price of such option is equal to the Fair value of assets acquired $ 249,605,040 83,599,600 fair market value of the properties at the time the option is exercised, as defined in the transaction agreement, less the The above cash payments of $42.9 million in 1994 production payment balance. At closing, Devon received include approximately $1.4 million of direct costs paid to $5.6 million associated with reserves to be produced subse- third parties which were capitalized and allocated to quent to the term of the production payment. Such amount producing oil and gas properties. The cash payments made is included in long-term “other liabilities” on the accompa- are reduced in the accompanying 1994 consolidated state- nying balance sheet. Since Devon expects to eventually exer- ment of cash flows by $518,382 of cash acquired in the Alta cise its option to repurchase the properties, the liability will Merger. be increased over time to reflect the option purchase price. As the purchase price increases, a portion of the tax credit payments received by Devon will be added to the liability. As stated above, for the years ended December 31, 1996 and 1995, $1.2 million and $1.1 million, respectively, of the total amount received for tax credit payments were added to the liability, which raised the liability balance to $7.9 million as of December 31, 1996. Devon has retained a 75% reversionary interest in the properties’ reserves in excess, if any, of the 186.2 Bcf of reserves estimated to exist at December 31, 1994. The terms of the transaction provide that the third party will pay 100% of the capital necessary to develop any such incremental reserves 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 liabilities recorded as of year-end 1996, does not include any amount related to such reserves.

DEVON ENERGY CORPORATION 49 5 Accounts Receivable The 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 10,973,589 Joint interest billings 4,318,764 2,962,037 3,367,493 Income tax refunds due - - 959,085 Other 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 Equipment Property and equipment included the following:

December 31, 1996 1995 1994

Oil and gas properties: Subject to amortization $ 899,827,749 604,227,702 503,174,488 Not 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 1,451,109 Acquired in 1993 5,204,995 5,556,977 5,556,977 Acquired in 1992 8,113,899 8,257,985 8,561,031

Accumulated depreciation, depletion and 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 and amortization (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 of accumulated depreciation, depletion and amortization $ 692,846,346 391,818,737 321,306,180

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

Year Ended December 31, 1996 1995 1994

Depreciation, depletion and amortization of oil and gas properties $ 41,537,555 36,639,753 32,861,174 Depreciation and amortization of other property 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

50 DEVON ENERGY CORPORATION Devon entered into an interest rate swap agreement in 7Long-term Debt June, 1995, to hedge the impact of interest rate changes on a Devon has long-term lines of credit pursuant to which portion of its long-term debt. The notional amount of the it can borrow up to an amount determined by the banks swap agreement was $75 million, and the other party to the based on their evaluation of the assets and cash flow (the agreement was one of Devon’s lenders. The swap agreement “Borrowing Base”) of Devon. The established Borrowing Base was accounted for as a hedge. On July 1, 1996, Devon termi- at December 31, 1996, was $260 million. Amounts nated the interest rate swap agreement for a gain of $0.8 borrowed under the credit lines bear interest at various fixed million. This gain is being recognized ratably as a reduction rate options which Devon may elect for periods up to 90 to interest expense during the period from July 1, 1996 to days. Such rates are generally less than the prime rate. Devon June 16, 1998 (the original expiration date of the agreement). may also elect to borrow at the prime rate. The average Approximately $0.2 million of the gain was recognized in interest rates on the outstanding debt at the end of 1996, 1996. The fair value of the interest rate swap as of December 1995 and 1994, were 6.19%, 6.64% and 6.83%, respectively. 31, 1995 was a liability of approximately $1.4 million. The The loan agreements also provide for a quarterly facility fee interest rate swap had no carrying value in the accompanying equal to .25% per annum. consolidated financial statements. Debt borrowed under the credit lines is unsecured. No See Note 9 for a description of certain convertible principal payments are required until maturity unless the debentures issued in 1996 to a Devon affiliate. unpaid balance exceeds the maximum loan amount. The maximum loan amount is equal to the Borrowing Base until 8 Income Taxes August 31, 1999. Thereafter, the maximum loan amount will be reduced by 8.33% every three months until August 31, At December 31, 1996, Devon had the following 2002. The loan agreements contain certain covenants and carryforwards available to reduce future federal and state income taxes: restrictions, among which are limitations on additional YEARS OF CARRYFORWARD borrowings and annual sales of properties valued at more TYPES OF CARRYFORWARD EXPIRATION AMOUNTS than $25 million, and working capital and net worth mainte- Net operating loss - federal 1998-2008 $ 14,100,000 nance requirements. At December 31, 1996, Devon was in Net operating loss - various states 1997-2010 $ 10,000,000 Statutory depletion N/A $ 1,200,000 compliance with such covenants and restrictions. Minimum tax credit N/A $ 5,600,000 On December 31, 1996, Devon established a demand revolving operating credit facility with a Canadian bank. This facility is unsecured and will be utilized for general corporate All of the carryforward amounts shown above have purposes related to Devon’s new Canadian operations. The been utilized for financial purposes to reduce deferred taxes. credit line totals $12.5 million Canadian dollars, and interest Total income tax expense differed from the amounts is charged at the bank’s prime rate for loans to Canadian computed by applying the federal income tax rate to net customers. Amounts borrowed are due on demand. However, earnings before income taxes as a result of the following: due to Devon’s sources of long-term debt described above, Year Ended December 31, 1996 1995 1994 amounts borrowed pursuant to the Canadian credit line are Federal statutory tax rate 35% 35% 35% expected to be classified as long-term debt. No amounts were Nonconventional fuel source credits - (1) - borrowed against the Canadian credit line at year-end 1996. State income taxes 5 4 3 Effect of San Juan Basin Transaction 2 4 - Other (1) 1 (2) Effective income tax rate 41% 43% 36%

DEVON ENERGY CORPORATION 51 The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 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 6,127,000 Statutory depletion carryforwards 412,000 2,287,000 3,087,000 Investment tax credit carryforwards 42,000 85,000 813,000 Minimum tax credit carryforwards 5,624,000 5,576,000 2,195,000 Production 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 13,119,000 Less valuation allowance 100,000 100,000 100,000 Net deferred tax assets 33,590,000 40,666,000 13,019,000 Deferred tax liabilities: Property and equipment, principally due to differences in depreciation, and the expensing of intangible drilling costs 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 generate any specific level of continuing taxable earnings. $33.6 million of net deferred tax assets as of December 31, However, management believes that Devon’s future taxable 1996. Such amount consists almost entirely of $11.4 million income will more likely than not be sufficient to utilize of various carryforwards available to offset future income substantially all its tax carryforwards prior to their expiration. taxes, and $19.7 million of net tax basis in production A $100,000 valuation allowance has been recorded at payments. The carryforwards include federal net operating December 31, 1996, related to depletion carryforwards loss carryforwards, the majority of which do not begin to acquired in the Alta Merger. expire until 2006, state net operating loss carryforwards The $19.7 million of deferred tax assets related to which expire primarily between 1999 and 2003, and the production payments is offset by a portion of the deferred tax statutory depletion and minimum tax credit carryforwards liability related to the excess financial basis of property and which have no expiration dates. The tax benefits of carryfor- equipment. The income tax accounting for the San Juan wards are recorded as an asset to the extent that management Basin Transaction described in Note 3 differs from the finan- assesses the utilization of such carryforwards to be “more cial accounting treatment which is described in such note. likely than not.” When the future utilization of some portion For income tax purposes, a gain from the conveyance of the of the carryforwards is determined not to be “more likely properties was realized, and the present value of the produc- than not”, a valuation allowance is provided to reduce the tion payments to be received was recorded as a note receiv- recorded tax benefits from such assets. able. For presentation purposes, the $19.7 million represents Devon expects the tax benefits from the net operating the tax effect of the difference in accounting for the produc- loss carryforwards to be utilized between 1997 and 1999. tion payment, less the effect of the taxable gain from the Such expectation is based upon current estimates of taxable transaction which is being deferred and recognized on the income during this period, considering limitations on the installment basis for income tax purposes. annual utilization of these benefits as set forth by federal tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expendi- tures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will

52 DEVON ENERGY CORPORATION balances. The distributions on the TCP Securities are 9 Trust Convertible Preferred Securities recorded as a charge to pre-tax earnings on Devon’s consoli- On July 10, 1996, Devon, through its newly-formed dated statements of operations, and such distributions are affiliate Devon Financing Trust, completed the issuance of deductible by Devon for income tax purposes. $149.5 million of 6.5% trust convertible preferred securities Devon estimates that the fair value of the TCP Securi- (the “TCP Securities”) in a private placement. Devon ties as of December 31, 1996 was approximately $196.6 Financing Trust issued 2,990,000 shares of the TCP Securi- million, as compared to the book value of $149.5 million. ties at $50 per share. Each TCP Security is convertible at the This fair value was based on quoted prices at which TCP holder’s option into 1.6393 shares of Devon common stock, Securities were purchased and sold on December 31, 1996. which equates to a conversion price of $30.50 per share of Devon common stock. 10 Stockholders’ Equity Devon Financing Trust invested the $149.5 million of proceeds in 6.5% convertible junior subordinated debentures The authorized capital stock of Devon consists of 400 issued by Devon (the “Convertible Debentures”). In turn, million shares of common stock, par value $.10 per share Devon used the net proceeds from the issuance of the (the “Common Stock”), and three million shares of preferred Convertible Debentures to retire debt outstanding under its stock, par value $1.00 per share (the “Preferred Stock”). The credit lines. Preferred Stock may be issued in one or more series, and the The sole assets of Devon Financing Trust are the terms and rights of such stock will be determined by the Convertible Debentures. The Convertible Debentures and Board of Directors. the related TCP Securities mature on June 15, 2026. Devon’s Board of Directors has designated 150,000 However, Devon and Devon Financing Trust may redeem the shares of the Preferred Stock as Series A Junior Participating Convertible Debentures and the TCP Securities, respectively, Preferred Stock (the “Series A Preferred Stock”) in connection in whole or in part, on or after June 18, 1999. For the first with the adoption of the share rights plan described later in twelve months thereafter, redemptions may be made at this note. At December 31, 1996, there were no shares of 104.55% of the principal amount. This premium declines Series A Preferred Stock issued or outstanding. The Series A proportionally every twelve months until June 15, 2006, Preferred Stock is entitled to receive cumulative quarterly when the redemption price becomes fixed at 100% of the dividends per share equal to the greater of $10 or 100 times principal amount. If Devon redeems any Convertible Deben- the aggregate per share amount of all dividends (other than tures prior to the scheduled maturity date, Devon Financing stock dividends) declared on Common Stock since the imme- Trust must redeem TCP Securities having an aggregate liqui- diately preceding quarterly dividend payment date or, with dation amount equal to the aggregate principal amount of respect to the first payment date, since the first issuance of Convertible Debentures so redeemed. Series A Preferred Stock. Holders of the Series A Preferred Devon has guaranteed the payments of distributions Stock are entitled to 100 votes per share (subject to adjust- and other payments on the TCP Securities only if and to the ment to prevent dilution) on all matters submitted to a vote extent that Devon Financing Trust has funds available of the stockholders. The Series A Preferred Stock is neither therefor. Such guarantee, when taken together with Devon’s redeemable nor convertible. The Series A Preferred Stock obligations under the Convertible Debentures and related ranks prior to the Common Stock but junior to all other indenture and declaration of trust, provide a full and uncon- classes of Preferred Stock. ditional guarantee of amounts due on the TCP Securities. Devon owns all the common securities of Devon Financing Trust. As such, the accounts of Devon Financing Trust are included in Devon’s consolidated financial state- ments after appropriate eliminations of intercompany

DEVON ENERGY CORPORATION 53 STOCK OPTION PLANS of nonqualified options granted under the 1993 Plan may Devon has outstanding stock options issued to key not be less than 75% of the fair market value of the stock on management and professional employees under two stock the date of grant. Options granted are exercisable during a option plans adopted in 1988 and 1993 (“the 1988 Plan” period established for each grant, which period may not and “the 1993 Plan”). Options granted under the 1988 Plan exceed 10 years from the date of grant. Under the 1993 Plan, remain exercisable by the employees owning such options, the grantee must pay the exercise price in cash or in but no new options will be granted under the 1988 Plan. At Common Stock, or a combination thereof, at the time that December 31, 1996, 15 participants held the 303,400 the option is exercised. The 1993 Plan is administered by a options outstanding under the 1988 Plan. committee comprised of non-management members of the Effective June 7, 1993, Devon adopted the 1993 Plan Board of Directors. The 1993 Plan expires on April 25, and reserved one million shares of Common Stock for 2003. As of December 31, 1996, 23 participants held the issuance thereunder. Twenty-two employees were eligible to 898,600 options outstanding under the 1993 Plan. There participate in the 1993 Plan at year-end 1996. were 88,700 options available for future grants as of The exercise price of incentive stock options granted December 31, 1996. under the 1993 Plan may not be less than the estimated fair A summary of the status of Devon’s stock option plans market value of the stock at the date of grant, plus 10% if as of December 31, 1994, 1995 and 1996, and changes the grantee owns or controls more than 10% of the total during each of the years then ended, is presented below: voting stock of Devon prior to the grant. The exercise price

Options Outstanding Options Exercisable WEIGHTED WEIGHTED AVERAGE 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 $ 20.736 Options exercised (40,800) $ 9.355

Balance at December 31, 1994 877,900 $ 18.947 485,000 $ 17.423

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

Balance at December 31, 1995 1,028,900 $ 20.349 688,800 $ 19.744

Options granted 248,500 $ 32.358 Options 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 fair value of each option grant was estimated for disclosure purposes only on the date of grant using the Binomial Option Pricing Model with the following assumptions for 1996 and 1995, respectively: risk-free interest rates of 6.3% and 5.5%; dividend yields 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%.

54 DEVON ENERGY CORPORATION The following table summarizes information about Devon’s stock options which were outstanding, and those which were exercisable, as of December 31, 1996: Options Outstanding Options Exercisable WEIGHTED WEIGHTED WEIGHTED RANGE OF AVERAGE AVERAGE AVERAGE EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE

$8 to $14 108,600 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 SFAS or b) Devon Common Stock with a value equal to twice the No. 123 and recognized compensation expense based on the exercise price of the right, subject to adjustment to prevent fair value of the stock options granted as of their grant date, dilution. In the event of certain merger or asset sale transac- Devon’s 1996 and 1995 pro forma net earnings and pro tions with another party or transactions which would increase forma net earnings per share would have differed from the the equity ownership of a shareholder who then owned 15% amounts actually reported as shown in the table below. The or more of Devon, each Devon right will entitle its holder to pro forma amounts shown below do not include the effects purchase securities of the merging or acquiring party with a of stock options granted prior to January 1, 1995. The pro value equal to twice the exercise price of the right. forma effects shown below may not be representative of the The rights, which have no voting power, expire on effects reported in future years. April 16, 2005. The rights may be redeemed by Devon for $.01 per right until the rights become exercisable. Year Ended December 31, 1996 1995

Net earnings: As reported $ 34,800,532 14,501,899 11 Retirement Plans Pro forma $ 34,016,571 13,540,052 Devon has a defined benefit retirement plan (the Net earnings per share: “Basic Plan”) which is non-contributory and includes As reported: employees meeting certain age and service requirements. The Assuming no dilution $1.57 0.66 Assuming full dilution $1.52 0.66 benefits are based on the employee’s years of service and Pro forma: compensation. Devon’s funding policy is to contribute annu- Assuming no dilution $1.54 0.61 ally the maximum amount that can be deducted for federal Assuming full dilution $1.49 0.61 income tax purposes. Rights to amend or terminate the Basic Plan are retained by Devon. SHARE RIGHTS PLAN Effective January 1, 1995, Devon has a separate Under Devon’s share rights plan, stockholders have defined benefit retirement plan (the “Supplementary Plan”) one right for each share of Common Stock held. The rights which is non-contributory and includes only certain become exercisable and separately transferable ten business employees whose benefits under the Basic Plan are limited by days after a) an announcement that a person has acquired, or federal income tax regulations. The Supplementary Plan’s obtained the right to acquire, 15% or more of the voting benefits are based on the employee’s years of service and shares outstanding, or b) commencement of a tender or compensation. Devon’s funding policy for the Supplementary exchange offer that could result in a person owning 15% or Plan is to fund the benefits as they become payable. Rights to more of the voting shares outstanding. amend or terminate the Supplementary Plan are retained by Each right entitles its holder (except a holder who is Devon. the acquiring person) to purchase either a) 1/100 of a share of Series A Preferred Stock for $75.00, subject to adjustment

DEVON ENERGY CORPORATION 55 The following table sets forth the aggregate funded status of the Basic Plan and related amounts recognized in Devon’s balance 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 service rendered 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 effects of 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 funded intangible assets of $1.0 million in 1996 and $1.2 million in status of the Supplementary Plan and related amounts recog- 1995. These intangible assets are included in other assets on nized in Devon’s balance sheet as of December 31, 1996 and the balance sheets. 1995: Net pension expense for Devon’s two defined benefit plans included the following components: December 31, 1996 1995

Actuarial present value of benefit obligations: Year Ended December 31, 1996 1995 1994 Accumulated benefit obligation: Vested $ (1,960,000) (1,658,000) Service cost - benefits earned Nonvested (279,000) (255,000) during the period $ 557,000 362,000 277,000 Total $ (2,239,000) (1,913,000) Interest cost on projected benefit obligation 569,000 446,000 284,000 Projected benefit obligation for Actual return on plan assets (453,000) (536,000) (20,000) service rendered to date $ (2,907,000) (2,245,000) Net amortization and deferral 231,000 345,000 (231,000) Plan assets at fair value - - Net periodic pension expense $ 904,000 617,000 310,000 Plan assets less than projected benefit obligation (2,907,000) (2,245,000) Unrecognized prior service cost 1,235,000 1,354,000 The weighted average discount rate used in deter- Unrecognized net loss from past mining the actuarial present value of the projected benefit experience different from that assumed, and effects of changes obligation in 1996, 1995 and 1994 was 7.5%, 7.25% and in assumptions 446,000 185,000 8.5%, respectively. The rate of increase in future compensa- Accrued pension expense (1,226,000) (706,000) tion levels was 5% for all three years. The expected long-term Additional minimum liability (1,013,000) (1,207,000) rate of return on assets was 8.5%, 8.5% and 8% in 1996, Total pension liability $ (2,239,000) (1,913,000) 1995 and 1994, respectively. Devon has a 401(k) Incentive Savings Plan which The $2.2 million and $1.9 million total pension covers all employees. At its discretion, Devon may match a liability of the Supplementary Plan as of December 31, 1996 certain percentage of the employees’ contributions to the and 1995, respectively, are included in long-term other liabil- plan. The matching percentage is determined annually by the ities on the accompanying consolidated balance sheets. The Board of Directors. Devon’s matching contributions to the additional minimum liabilities of $1.0 million and $1.2 plan were $188,000, $170,000 and $158,000 for the years million at year-end 1996 and 1995, respectively, are offset by ended December 31, 1996, 1995 and 1994, respectively.

56 DEVON ENERGY CORPORATION 12 Commitments and Contingencies Devon is party to various legal actions arising in the However, Devon’s management does not believe that the normal course of business. Matters that are probable of unfa- amount of possible assessments above that already accrued vorable outcome to Devon and which can be reasonably esti- would be material. mated are accrued. Such accruals are based on information In a matter unrelated to the MMS issue discussed known about the matters, Devon’s estimates of the outcomes above, the State of New Mexico on December 29, 1995, of such matters and its experience in contesting, litigating assessed Devon and other producers of gas from the San Juan and settling similar matters. None of the actions are believed Basin a “natural gas processors tax.” Devon’s tax assessment by management to involve future amounts that would be for the years 1990 through 1995 was approximately $0.6 material after consideration of recorded accruals. million, and the state also assessed another $0.3 million of The majority of Devon’s sales of nonconventional gas penalties and interest. All of the assessment relates to from the San Juan Basin are subject to federal royalties nonconventional gas. Devon paid these assessments in administered and collected by the Minerals Management January 1996, as well as an additional $0.2 million for 1996 Service (“MMS”). In determining royalties payable to the taxes which were paid monthly throughout the year, so that it MMS, Devon has followed the industry practice of reducing could begin the necessary procedures of applying for a the gas sales price for certain permitted costs related to the refund. This tax historically was paid by the owners of transportation of gas produced and CO2 removal. In 1995, natural gas processing plants, not the gas producers, and was the MMS issued new policies which would increase Devon’s assessed for the privilege of processing natural gas. While share of federal royalties for nonconventional gas produced Devon’s nonconventional gas is purified through a plant prior and sold in the San Juan Basin for the years 1990 through to the actual sales point, such purification is only for the 1996, and for future years as well. In early 1997, the MMS purpose of removing CO2. Also, Devon does not own an asserted a claim for additional royalties. While the specific interest in such plant. For these and other reasons, Devon claim only covers 17 months of the seven-year period in does not believe the assessment of the additional tax and the question, the MMS has requested Devon to calculate and pay related penalties and interest is valid. If the amount paid is additional royalties for the entire seven-year period using not refunded through the normal administrative processes methods and procedures consistent with the calculation for available, Devon intends to file a suit asking that the assess- the 17 months. Devon has not determined whether it agrees ments be reversed. At this time, it is not possible to deter- with the methods and procedures used by the MMS in its mine the eventual outcome of this matter. Devon has not calculations, and Devon intends to vigorously contest any expensed in its financial statements the taxes, penalties and claim for excessive additional federal royalties through avail- interest paid, but rather has recorded the $1.1 million total as able administrative and judicial processes. However, Devon a receivable. has accrued an estimate of additional federal royalties related to 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 additional federal royalties due and related interest. The amount accrued represents 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 different interpretation of the policies and related facts could result in an assessment higher than what Devon has accrued.

DEVON ENERGY CORPORATION 57 The following is a schedule by year of future Total rental expense for all operating leases is as minimum rental payments required under operating leases follows for the years ended December 31: that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 1996: 1996 $ 572,177 1995 $ 546,388 Year Ending December 31, 1994 $ 521,769

1997 $ 233,000 1998 183,000 1999 138,000 2000 123,000 Total minimum lease payments required $ 677,000

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

TOTAL Year Ended December 31, 1996 1995 1994 Property acquisition costs: Proved, excluding deferred income taxes $ 199,655,000 47,316,000 70,376,000 Deferred income taxes 22,557,000 - 11,500,000 Total 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 1,797,000 Deferred 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 5,194,000 Development 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 70,376,000 Deferred income taxes 15,257,000 - 11,500,000 Total 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 1,797,000 Deferred 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 5,194,000 Development 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 $ - - -

58 DEVON ENERGY CORPORATION Pursuant to the full cost method of accounting, Devon RESULTS OF OPERATIONS FOR OIL capitalizes certain of its general and administrative expenses AND GAS PRODUCING ACTIVITIES which are related to property acquisition, exploration and The following tables include revenues and expenses development activities. Such capitalized expenses, which are associated directly with Devon’s oil and gas producing activi- included in the costs shown in the above tables, were $2.9 ties. They do not include any allocation of Devon’s interest million, $2.7 million and $2.3 million in the years 1996, costs or general corporate overhead and, therefore, are not 1995 and 1994, respectively. necessarily indicative of the contribution to net earnings of Due to the substantially tax-free nature of the acquisi- Devon’s oil and gas operations. Income tax expense has been tion of the KMG-NAOS properties to Kerr-McGee, and of calculated by applying statutory income tax rates to oil and the 1994 Alta Merger to the former Alta stockholders, Devon gas sales after deducting costs, including depreciation, deple- recorded additional deferred tax liabilities of $28.0 million tion and amortization and after giving effect to permanent related to the KMG-NAOS acquisition and $11.5 million differences. For the three year period ended December 31, related to the Alta Merger. As shown in the above tables, the 1996, Devon had no oil and gas producing activities outside deferred tax liabilities caused an additional $22.5 million and the United States. $11.5 million to be allocated to proved oil and gas reserves in 1996 and 1994, respectively, and an additional $5.5 million to be allocated to unproved properties in 1996.

Year Ended December 31, 1996 1995 1994

Oil, gas and natural gas liquids sales $ 162,558,000 112,425,000 99,366,000 Production 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 22,673,000 Depreciation, depletion and amortization per equivalent barrel of production $3.88 3.65 3.45

14 Supplemental Information on Oil QUANTITIES OF OIL AND GAS RESERVES and Gas Operations (Unaudited) Set forth below is a summary of the changes in the net The following supplemental unaudited information quantities of crude oil, natural gas and natural gas liquids regarding the oil and gas activities of Devon is presented reserves for each of the three years ended December 31, pursuant to the disclosure requirements promulgated by the 1996. Approximately 94%, 92% and 91%, of the respective Securities and Exchange Commission and Statement of year-end 1996, 1995 and 1994 domestic proved reserves were Financial Accounting Standards No. 69, “Disclosures About calculated by the independent petroleum consultants Oil and Gas Producing Activities”. LaRoche Petroleum Consultants, Ltd. The remaining percentages of domestic reserves are based on Devon’s own estimates. All of the 1996 Canadian proved reserves were calculated by the independent petroleum consultants AMH Group Ltd.

DEVON ENERGY CORPORATION 59 NATURAL OIL GAS GAS LIQUIDS TOTAL (BBLS) (MCF) (BBLS)

Proved reserves as of December 31, 1993 14,897,000 369,254,000 1,854,000 Revisions of estimates 3,157,000 (5,540,000) 1,733,000 Extensions and discoveries 2,008,000 13,206,000 183,000 Purchase of reserves 25,201,000 13,492,000 2,181,000 Production (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 5,442,000 Revisions of estimates 1,127,000 (7,431,000) 535,000 Extensions and discoveries 2,959,000 9,645,000 472,000 Purchase of reserves 1,852,000 59,585,000 3,665,000 Production (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 9,469,000 Revisions of estimates 2,365,000 4,359,000 1,096,000 Extensions and discoveries 3,680,000 14,849,000 852,000 Purchase of reserves 21,189,000 249,922,000 2,130,000 Production (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 12,579,000 Proved developed reserves as of: December 31, 1993 11,548,000 355,536,000 1,751,000 December 31, 1994 18,718,000 324,302,000 3,123,000 December 31, 1995 28,703,000 311,664,000 6,149,000 December 31, 1996 60,202,000 570,265,000 11,212,000

NATURAL OIL GAS GAS LIQUIDS DOMESTIC (BBLS) (MCF) (BBLS)

Proved reserves as of December 31, 1993 14,897,000 369,254,000 1,854,000 Revisions of estimates 3,157,000 (5,540,000) 1,733,000 Extensions and discoveries 2,008,000 13,206,000 183,000 Purchase of reserves 25,201,000 13,492,000 2,181,000 Production (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 5,442,000 Revisions of estimates 1,127,000 (7,431,000) 535,000 Extensions and discoveries 2,959,000 9,645,000 472,000 Purchase of reserves 1,852,000 59,585,000 3,665,000 Production (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 9,469,000 Revisions of estimates 2,365,000 4,359,000 1,096,000 Extensions and discoveries 3,680,000 14,849,000 852,000 Purchase of reserves 13,659,000 209,064,000 1,246,000 Production (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 11,695,000 Proved developed reserves as of: December 31, 1993 11,548,000 355,536,000 1,751,000 December 31, 1994 18,718,000 324,302,000 3,123,000 December 31, 1995 28,703,000 311,664,000 6,149,000 December 31, 1996 52,672,000 529,407,000 10,328,000

60 DEVON ENERGY CORPORATION NATURAL OIL GAS GAS LIQUIDS CANADA (BBLS) (MCF) (BBLS)

Proved reserves as of December 31, 1995 --- Revisions of estimates --- Extensions and discoveries --- Purchase of reserves 7,530,000 40,858,000 884,000 Production --- Sale of reserves --- Proved reserves as of December 31, 1996 7,530,000 40,858,000 884,000 Proved 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 interest in proved reserves:

TOTAL December 31, 1996 1995 1994

Future cash inflows $ 3,989,582,000 1,476,418,000 1,186,845,000 Future 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 2,077,834,000 774,381,000 639,627,000 10% 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 1,186,845,000 Future 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 1,931,960,000 774,381,000 639,627,000 10% 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 - -

DEVON ENERGY CORPORATION 61 Future cash inflows are computed by applying year- reflect the impact of future operations. Prior to the San Juan end prices (averaging $24.52 per barrel of oil, adjusted for Basin Transaction as described in Note 3, the future income transportation and other charges, $3.35 per Mcf of gas and tax expenses estimated at December 31, 1994 were reduced $23.34 per barrel of natural gas liquids at December 31, by the estimated future Section 29 tax credits to be generated 1996) to the year-end quantities of proved reserves, except in by the San Juan Basin coal seam gas properties. It was esti- those instances where fixed and determinable price changes mated at year-end 1994 that undiscounted amounts of are provided by contractual arrangements in existence at year- approximately $113 million of Section 29 tax credits could end. In addition to the future gas revenues calculated at be generated in future years to Devon’s interest. However, $3.35 per Mcf, Devon’s total future gas revenues also include because of limitations on the amount of Section 29 tax the future tax credit payments to be received and recorded as credits which can actually be utilized for income tax gas revenues pursuant to the San Juan Basin Transaction purposes, the undiscounted amounts included as reductions described in Note 3. Devon’s future total and domestic cash to future income tax expense for purposes of calculating the inflows shown in the tables above include $48.7 million standardized measure of discounted future net cash flows related to these tax credit payments from 1997 through were only $41 million at year-end 1994. As a result of the 2002. This amount has been calculated using the assumption San Juan Basin Transaction, substantially all of the value of that the year-end 1996 tax credit rate of $1.02 per MMBtu the Section 29 tax credits at year-end 1996 and 1995 is now remains constant. included in “future cash inflows,” instead of a reduction to Future development and production costs are income tax expense, in Devon’s standardized measure of computed by estimating the expenditures to be incurred in discounted future net cash flows. developing and producing proved oil and gas reserves at the end of the year, based on year-end costs and assuming CHANGES RELATING TO THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS continuation of existing economic conditions. Principal changes in the standardized measure of Future income tax expenses are computed by applying discounted future net cash flows attributable to Devon’s the appropriate statutory tax rates to the future pretax net proved reserves are as follows: cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not

Year Ended December 31, 1996 1995 1994

Beginning balance $ 445,900,000 358,206,000 343,550,000 Sales 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 14,629,000 Purchase of reserves, net of future development costs 576,234,000 50,000,000 133,103,000 Development costs incurred during the period which reduced future development costs 44,332,000 43,810,000 16,519,000 Revisions of quantity estimates 40,905,000 7,397,000 26,167,000 Sales of reserves in place (6,499,000) (7,933,000) (5,281,000) Accretion of discount 53,425,000 39,821,000 38,047,000 Net 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

62 DEVON ENERGY CORPORATION 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 FOURTH 1996 QUARTER QUARTER QUARTER QUARTER TOTAL

Oil, gas and natural gas liquids sales $ 33,734,229 36,743,221 39,007,410 53,073,462 162,558,322 Total revenues $ 34,048,060 37,298,613 39,473,680 53,196,531 164,016,884 Net earnings $ 5,553,926 6,775,388 7,707,673 14,763,545 34,800,532 Net earnings per share Assuming no dilution $0.25 0.31 0.35 0.66 1.57 Assuming full dilution $0.25 0.31 0.35 0.59 1.52

FIRST SECOND THIRD FOURTH 1995 - 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 29,985,087 112,425,640 Total revenues $ 23,762,327 25,650,334 33,770,864 30,119,300 113,302,825 Net earnings $ 1,026,802 2,444,422 6,645,531 4,385,144 14,501,899 Net earnings per share $0.05 0.11 0.30 0.20 0.66

FIRST SECOND THIRD FOURTH 1995 - ADJUSTED RESULTS (a) QUARTER QUARTER QUARTER QUARTER TOTAL

Oil, gas and natural gas liquids sales $ 26,478,770 28,293,715 27,668,068 29,985,087 112,425,640 Total revenues $ 26,796,579 28,612,083 27,774,863 30,119,300 113,302,825 Net earnings $ 2,864,127 4,181,531 3,071,097 4,385,144 14,501,899 Net 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 thus the transaction’s impact on Devon’s statement of operations was deferred pending the contingency’s resolution. When the contingency was favorably resolved, the cumulative nine-month effect of the transaction was recorded in the third quarter. The second table above includes the 1995 quarterly results as reported, including the 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 contingency not existed and had the San Juan Basin Transaction’s effect on earnings been reported from the inception of the transaction on January 1, 1995. ■

DEVON ENERGY CORPORATION 63 Board of Directors

JOHN W. NICHOLS , co-founder of Devon, has power producer. In addition, Mr. Gavrin was associated with Drexel been chairman of the board of directors since Burnham Lambert Incorporated for 14 years as first vice president, Devon began operations in 1971. He is a and he was a general partner of Windcrest Partners, an investment founding partner of Blackwood & Nichols partnership, for 10 years. Co., which developed the conventional reserves in the Northeast Blanco Unit of the MICHAEL E. GELLERT has been a director of San Juan Basin. Mr. Nichols is a non-prac- Devon since 1971 and is a member of the ticing certified public accountant. Compensation and Stock Option Committee. Mr. Gellert serves as a director of Humana, J. LARRY NICHOLS is a co-founder of Devon. Inc., Premier Parks, Inc., Seacor Holdings, He has been a director since 1971, president Inc., and Regal Cinemas, Inc. Mr. Gellert is since 1976 and chief executive officer since also a member of the Putnam Trust Company 1980. Mr. Nichols serves as a director of the Advisory Board to The Bank of New York. He Independent Petroleum Association of America was associated with the Drexel Burnham Lambert Group and its and chairs its Public Lands Committee. He is predecessors for 31 years, including 17 years as a director, and served president of the Domestic Petroleum Council in various executive capacities for its wholly owned subsidiary, Drexel and is also a director of the Independent Petro- Burnham Lambert Incorporated. leum Association of New Mexico, the Oklahoma Independent Petro- leum Association and the National Petroleum Council. He also serves TOM J. MCDANIEL was elected to the board of as a director of the National Association of Manufacturers and of the directors in December 1996. Mr. McDaniel Oklahoma Nature Conservancy. Mr. Nichols holds a geology degree has been Kerr-McGee’s vice chairman of the from Princeton University and a law degree from the University of board since February 1, 1997. He has served Michigan. He served as a law clerk to Mr. Chief Justice Earl Warren as a senior vice president and corporate secre- and Mr. Justice Tom Clark of the U.S. Supreme Court. tary of Kerr-McGee since 1989. He joined Kerr-McGee as associate general counsel in LUKE R. CORBETT was elected to the board of 1984. In 1981, he was appointed administra- directors in December 1996. Mr. Corbett is tive director of State Courts by the Oklahoma Supreme Court. Mr. chairman of the board and chief executive McDaniel serves on the board of directors of the National Association officer of Kerr-McGee Corporation. He joined of Manufacturers. A member of the Oklahoma and American Bar Kerr-McGee in 1985 and held various execu- Associations, Mr. McDaniel holds degrees from Northwestern Okla- tive positions prior to being elected to his homa State University and the University of Oklahoma. present position in 1997. He is a director of OGE Energy Corporation and the American H. R. SANDERS, JR. has been a director and Petroleum Institute. He is a member of the American Association of executive vice president of Devon since 1981. Petroleum Geologists, the Society of Exploration Geophysicists, and Prior to joining Devon, Mr. Sanders was asso- the Domestic Petroleum Council. He is trustee for the American ciated with Republic Bank Dallas, N.A., Geological Institute Foundation and is chairman of the advisory serving as its senior vice president with respon- board of the Energy & Geoscience Institute at the University of Utah. sibility for independent oil and gas producer and mining loans. Mr. Sanders is a member of THOMAS F. FERGUSON has been a director of the Independent Petroleum Association of Devon since 1982, and is the chair of the America, Texas Independent Producers and Royalty Owners Associa- Audit Committee. He is managing director of tion and the Oklahoma Independent Petroleum Association. Englewood, N.V., a wholly owned subsidiary of Kuwait-based Al-Futtooh Investments LAWRENCE H. TOWELL was elected to the WLL. Mr. Ferguson represents them on the board of directors in December 1996. Mr. board of directors of Devon and other compa- Towell has, since 1984, been vice president of nies. Mr. Ferguson is a Canadian qualified acquisitions in Kerr-McGee’s Exploration and certified general accountant and was formerly employed by the Econ- Production Division. He has served Kerr- omist Intelligence Unit of London. McGee in various executive positions since 1975. Mr. Towell holds a bachelor’s degree in DAVID M. GAVRIN has been a director of Devon mechanical engineering from Yale University. since 1979, and serves as the chair of the He is a member of the Society of Petroleum Engineers, the Indepen- Compensation and Stock Option Committee. dent Petroleum Association of America, and the Yale University He serves as a director of Heidemij, N.V., a Science and Engineering Association. worldwide environmental services company; New York Federal Savings Bank; and United American Energy Corp., an independent

64 DEVON ENERGY CORPORATION Corporate Officers

J. MICHAEL LACEY joined Devon as vice presi- DANNY J. HEATLY has been Devon’s controller dent of operations and exploration in 1989. since 1989. Prior to joining Devon, Mr. Prior to his employment with Devon, Mr. Heatly was associated with Peat Marwick Lacey served as general manager in Tenneco Main and Co. in Oklahoma City for 10 years Oil Company’s Mid-Continent and Rocky with various duties including senior audit Mountain Divisions. He holds both under- manager. He is a certified public accountant, graduate and graduate degrees in petroleum and is a member of the American Institute of engineering from the Colorado School of Certified Public Accountants and the Mines. Mr. Lacey is a registered professional engineer, and he is a Oklahoma Society of Certified Public Accountants. Mr. Heatly grad- member of the Society of Petroleum Engineers and the American uated with a bachelor of accountancy degree from the University of Association of Petroleum Geologists. Oklahoma.

DARRYL G. SMETTE, vice president of market- GARY L. MCGEE was elected treasurer in 1983, ing and administrative planning since 1989, having first served as Devon’s controller. He is joined Devon in 1986 as manager of gas mar- a member of the Petroleum Accounting keting. Mr. Smette’s educational background Society of Oklahoma City. He also is a mem- includes an undergraduate degree from Minot ber of the Rocky Mountain Oil & Gas State College and a master’s degree from Association executive committee and the Wichita State University. His marketing back- Petroleum Association of Wyoming. Mr. ground includes 15 years with Energy Reserves McGee has been active in varied accounting Group, Inc./BHP Petroleum (Americas), Inc., the last position being functions with several companies in the industry. He served as vice director of marketing. He is also an oil and gas industry instructor, president of finance with KSA Industries, Inc., a private holding com- approved by the University of Texas Department of Continuing pany with diverse interests including oil and gas production. Mr. Education. Mr. Smette is a member of the Oklahoma Independent McGee also held various accounting positions with Adams Resources Producers Association, Natural Gas Association of Oklahoma, and the and Energy Co. and Mesa Petroleum Company. He received his American Gas Association. accounting degree from the University of Oklahoma.

H. ALLEN TURNER, vice president of corporate MARIAN J. MOON was elected corporate secre- development, has been responsible for Devon’s tary in 1994. Ms. Moon has served Devon in corporate finance and capital formation activi- various capacities since 1984, including her ties since 1982. In 1981, he served as execu- current position as manager of corporate tive vice president of Palo Pinto/Harken finance. She previously served as assistant sec- Drilling Programs. For the six prior years, he retary with responsibilities including compli- was associated with Merrill Lynch with vari- ance with SEC and stock exchange regula- ous responsibilities including regional tax tions. Prior to joining Devon, Ms. Moon was investments manager. He is a member of the Petroleum Investor employed for 11 years by Amarex, Inc., an Oklahoma City based oil Relations Association and serves on the Independent Petroleum and gas production and exploration firm, where she most recently Association of America (IPAA) Capital Markets Committee. He is the served as treasurer. Ms. Moon is a member of the Petroleum Investor current chairman of the IPAA Oil and Gas Investment Symposium. Relations Association and the American Society of Corporate Mr. Turner received his bachelor’s degree from Duke University. Secretaries. She is a graduate of Valparaiso University.

WILLIAM T. VAUGHN is Devon’s vice president of finance in charge of commercial banking functions, accounting, tax and information services. Mr. Vaughn was elected in 1987 to his present position. Prior to that, he was con- troller of Devon from 1983 to 1987. Mr. Vaughn’s prior experience includes serving as controller with Marion Corporation for two years and employment with Arthur Young & Co. for seven years with various duties including audit manager. He is a certified public accountant, and he is a member of the American Institute of Certified Public Accountants and the Oklahoma Society of Certified Public Accountants. Mr. Vaughn is a graduate of the University of Arkansas with a bachelor of science degree.

DEVON ENERGY CORPORATION 65 Glossary of Terms

BRITISH THERMAL UNIT (BTU): A NATURAL GAS LIQUIDS (NGLs): SECTION 29 TAX CREDIT: A tax Volume Acronyms measure of heat value. An Mcf of Liquid hydrocarbons that are credit prescribed by Section 29 of natural gas contains roughly one extracted and separated from the the Internal Revenue Code. The Bbl: A standard oil measurement million Btu of heat value. natural gas stream. NGLs prod- credit is available for certain that equals one barrel (42 U.S. ucts include ethane, propane, types of gas production from a gallons). DEVELOPMENT WELL: A well butane and natural gasoline. non-conventional source, such as - MBbl: Thousand barrels. drilled within the area of an oil coal deposits. The credit for 1996 - MMBbl: Million barrels. or gas reservoir known to be NET ACRES: Gross acres multi- was about $1.02 per million Btu, productive. Development wells plied by one’s fractional working and is adjusted for inflation. Boe: A method of equating oil, are relatively low risk. interest in the property. natural gas liquids and natural STEPOUT WELL: A well drilled gas. Natural gas is converted to EXPLORATORY WELL: A well PERMEABILITY: A measure of the just outside the proved area of an oil based on its relative energy drilled in an unproved area, ease with which fluids (such as oil or gas reservoir in an attempt content at the rate of six Mcf of either to find a new oil or gas oil or gas) flow through a forma- to extend the known boundaries gas to one barrel of oil. Natural reservoir or to extend a known tion’s pore spaces. of the reservoir. gas liquids are converted based reservoir. Sometimes referred to upon volume: one barrel of as a wildcat. PRODUCTION: Natural resources, THREE-DIMENSIONAL SEISMIC natural gas liquids equals one such as oil or gas, taken out of (3-D SEISMIC): Technology to barrel of oil. FIELD: A geographical area under the ground. create three-dimensional images - MBoe: Thousand barrels of oil which one or more oil or gas - GROSS PRODUCTION: Total by bouncing sound waves off of equivalent. reservoirs lie. production before deducting underground rock formations. - MMBoe: Million barrels of oil royalties. Used to look for underground equivalent. FORMATION: An identifiable - NET PRODUCTION: Gross accumulations of oil and gas. layer of rocks named after its production, minus royalties. EMcf: Thousand cubic feet of geographical location and domi- UNDEVELOPED ACREAGE: Lease natural gas equivalent. Six EMcf nant rock type. PROVED RESERVES: Estimates of acreage on which wells have not equals one barrel of oil. One oil, gas, and gas liquids quantities been drilled or completed to a EMcf equals one Mcf or seven GROSS ACRES: The total thought to be recoverable from point that would permit the gallons of natural gas liquids. number of acres in which one known reservoirs under existing production of commercial quan- - EMMcf: Million cubic feet of owns a working interest. economic and operating condi- tities of oil or gas. natural gas equivalent. tions. - EBcf: Billion cubic feet of INCREASED DENSITY/INFILL: A UNIT: A contiguous parcel of land natural gas equivalent. well drilled in addition to the RESERVOIR: A rock formation or deemed to cover one or more number of wells permitted under trap containing oil and/or natural common reservoirs for oil or Mcf: A standard measurement initial spacing regulations, used gas. natural gas, as determined by unit for volumes of natural gas to enhance or accelerate recovery, state or federal regulations. Unit that equals one thousand cubic or prevent the loss of proved SEC @ 10% OR SEC 10% interest owners generally share in feet. reserves. PRESENT VALUE: The future net costs and revenues according to - MMcf: Million cubic feet. revenue anticipated from proved their proportion of ownership in - Bcf: Billion cubic feet. INDEPENDENT PRODUCER: A reserves using the SEC Case, the unit. non-integrated oil and gas discounted at 10 percent. producer with no refining or WATERFLOOD: A method of retail marketing operations. SEC CASE: The method for increasing oil recoveries from an calculating future net revenues existing reservoir. Water is LEASE: A legal contract that from proved reserves as estab- injected through a special “water specifies the terms of the business lished by the Securities and injection well” into an oil relationship between an energy Exchange Commission (SEC). producing formation to force company and a landowner or Future oil and gas revenues are additional oil out of the reservoir mineral rights holder on a partic- estimated using essentially fixed rock and into nearby oil wells. ular tract of land. or unescalated prices. Future production and development WORKING INTEREST: The cost- LIFTING COSTS: Costs associated costs also are unescalated and are bearing ownership share of an oil with bringing oil or gas from the subtracted from future revenues. or gas lease. productive formation to the point of sale.

66 DEVON ENERGY CORPORATION Important Notice to our Friends and Shareholders

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HIGH LOW LAST VOLUME DIVIDENDS

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

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

Investor Information

CORPORATE HEADQUARTERS STOCK TRANSFER AGENT AND REGISTRAR Devon Energy Corporation Boston EquiServe 20 North Broadway, Suite 1500 Client Administration, Mail Stop 45-02-62 Oklahoma City, OK 73102-8260 P.O. Box 1865 Telephone: (405) 235-3611 Boston, MA 02105-1865 Fax: (405) 552-4667 Toll Free: 1-800-733-5001 World Wide Web: http://www.equiserve.com ANNUAL MEETING Our annual stockholders’ meeting will be held at 11:00 a.m., INDEPENDENT AUDITORS local time, on Wednesday, May 21, 1997, in the Community KPMG Peat Marwick LLP, Oklahoma City, Oklahoma Room, Mezzanine Floor, Bank of Oklahoma, Robinson Avenue at Robert S. Kerr, Oklahoma City, Oklahoma. INVESTOR RELATIONS CONTACT Mr. Vince White PUBLICATIONS Telephone: (405) 235-3611 A copy of Devon’s Annual Report to the Securities and E-mail: [email protected] Exchange Commission (Form 10-K) is available at no charge upon request. STOCK TRADING DATA Devon Energy Corporation’s common stock is traded on the Direct requests for corporate information to: American Stock Exchange under the symbol DVN. As of Ms. Pat Douglas February 28, 1997, there were approximately 900 common Devon Energy Corporation stockholders of record. 20 North Broadway, Suite 1500 Oklahoma City, OK 73102-8260 Telephone: (405) 552-4506 Fax: (405) 552-4667 E-mail: [email protected]

DEVON ENERGY CORPORATION 67 DEVON ENERGY CORPORATION 20 North Broadway, Suite 1500 Oklahoma City, Oklahoma 73102-8260 Telephone (405) 235-3611 Fax (405) 552-4667