Devon 1997 annual report

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Devon 1997 annual report

  1. 1. DevonEnergy Corporation R O C K S O L I D . 1997 Annual Report
  2. 2. LETTER TO SHAREHOLDERS 3 Devon’s President Discusses Major 1997 Achievements and Challenges. FIVE-YEAR FINANCIAL HIGHLIGHTS 6 ANOTHER RECORD YEAR 7 Devon Extends Its Series of Record-Breaking Financial Performances. CEO INTERVIEW 9 Larry Nichols Answers Your Questions. A ROCK SOLID COMMITMENT 13 TO EXPLORATION Devon Augments Its Successful Acquisition and Exploitation Strategies with Increased Emphasis on Exploratory Drilling. A ROCK SOLID PORTFOLIO OF 18 PRODUCING PROPERTIES Devon Gives Key Property Highlights and Operating Statistics by Area. FINANCIAL STATEMENTS AND 26 MANAGEMENT’S DISCUSSION AND ANALYSIS BOARD OF DIRECTORS 66 CORPORATE OFFICERS 67 GLOSSARY OF TERMS 68 INVESTOR INFORMATION AND 69 COMMON STOCK TRADING DATA 1 DEVONENERGYCORPORATION C O N T E N T S $ ? This annual report includes “forward-looking statements” as defined by the Securities and Exchange Commission. Such statements are those concerning Devon’s plans, expectations and objectives for future operations. These statements address future financial position, business strategy, future capital expenditures, projected oil and gas production and future costs. Devon believes that the expectations reflected in such forward-looking statements are reasonable. However, important risk factors could cause actual results to differ materially from the company’s expectations. A discussion of these risk factors can be found in the “Management’s Discussion and Analysis . . .” section of this report. Further information is available in the company’s Form 10-K and other publicly available reports, which will be furnished upon request to the company. ON THE COVER GIANT GRANITE BOULDERS, MANY MILLIONS OF YEARS OLD, STAND THE TEST OF TIME AT JOSHUA TREE NATIONAL PARK IN CALIFORNIA. DEVON’S FINANCIAL STABILITY AND TIME-TESTED GROWTH STRATEGIES FORM A ROCK SOLID FOUNDATION FOR THE FUTURE.
  3. 3. Devon Energy Corporation is an oil and gas exploration and production company with its headquarters in Oklahoma City, Oklahoma. We produce and sell oil and gas from wells located primarily in New Mexico, Oklahoma, Texas, Wyoming and Alberta, Canada. We strive to build value per share by: • Purchasing producing oil and gas properties, • Exploring for undiscovered oil and gas reserves, and • Optimizing production from our oil and gas properties.
  4. 4. expenditures went to higher risk exploration projects. The results were more than satisfactory. We drilled and completed 16 productive exploratory wells while drilling only two exploratory dry holes. These results helped drive oil and gas reserve additions and revisions to more than 20 million barrels of oil equivalent. These reserve additions exceeded the company’s 1997 record production. We not only increased Devon’s drilling activities in total, we increased the portion of these activities devoted to exploration. This shift reflects Devon’s increasing commitment to exploration as a means of future growth. During 1998, we plan to further expand our exploration activities. With $60 to $70 million of our capital budget earmarked for 1998 exploration projects, we are more than tripling the resources devoted to exploration. In addition, we recently doubled the size of our exploration staff, added new 3-D seismic workstations and acquired additional seismic data. These measures support our increasing exploration focus. THE CHALLENGES WERE CONSIDERABLE . . . On December 31, 1996, the North American onshore oil and gas assets of Kerr-McGee 2 3 DEVONENERGYCORPORATION No doubt, 1997 was simultaneously the most rewarding and daunting year in Devon’s history. Rewarding in that virtually all of our operating statistics rose dramatically. Daunting in that we had to grow organizationally into our new asset size and scope. It was a year of challenge and achievement. THE ACHIEVEMENTS WERE MANY . . . Once again, the company set all-time records in almost every area of financial and operational performance. We set our tenth consecutive record for year-end oil and gas reserves. We increased oil and gas production 88% from just one year ago to the highest levels in the company’s history. Net earnings climbed 116% to a record $75 million in 1997 — without the benefit of an increase in overall oil and gas prices. More importantly, earnings per share rose to an all-time high of $2.34. Not only was this per share performance the best in the company’s history, but 1997 earnings per share were 49% above last year’s record. By the traditional measures of success, 1997 was clearly a banner year for Devon Energy Corporation. However, some of Devon’s other 1997 accomplishments may not be so obvious. . . . INCLUDING DRILLING RESULTS In 1997, Devon invested over $100 million — the largest drilling and facilities budget in the company’s history. We drilled 295 wells, of which 284 were successfully completed as producers. Over $19 million of our 1997 capital D E A R FE L L O W S H A R E H O L D E R S In 1997, Devon set its tenth consecutive record for oil and gas reserves... 92 93 94 95 96 97 61 78 106 115 179 184 Proved Oil and Gas Reserves (MMBoe) 92 93 94 95 96 97 6.3 8.7 9.5 10.010.7 20.2 Oil and Gas Production (MMBoe) ...as well as oil and gas production... J. Larry Nichols 92 93 94 95 96 97 72 99 101 113 164 313 Total Revenues ($ Millions) ...increasing 1997 total revenues by more than 90% percent over 1996 revenues.
  5. 5. of 1996 and 1997, some in the industry began to invest as if prices would never fall. The annual average price for oil and gas property acquisitions jumped 14% to over $5.00 per Boe in 1997. It appears from early returns that finding costs for exploration also rose. Companies making high priced investments in energy assets based on 1997’s high prices may be in for a rude awakening. In the first quarter of 1998, oil prices are some 45% below the highs of 1997. At Devon, we try to look beyond short-term swings, positive or negative, in oil and gas prices. Though mergers and acquisitions have provided substantial growth for Devon in the past, we executed neither in 1997. We could not justify the high asking prices. Every acquisition we undertake must provide an incremental return for our shareholders by directly contributing to per share results. And prospective acquisitions are always evaluated using conservative oil and gas price assumptions. When high oil and gas prices temporarily prevent us from achieving these goals, we withdraw from the acquisition market. We keep our balance sheet strong and wait for attractive opportunities to reappear. This philosophy has served us well for many years. While numerous names in our industry have come and gone, Devon has not only weathered the effects of volatile oil and gas prices — we have prospered from them. Corporation were merged into Devon. While this transaction was negotiated and signed near the end of 1996, the work of merging these operations into Devon had just begun. In 1997 we successfully integrated this new property base. This property base was larger than our entire company of just six years ago. We hired over 100 new employees, streamlined field operations, upgraded information systems and revamped large portions of Devon’s organizational structure. Rapid growth such as this does not occur without substantial challenges. Devon’s employees, old and new, faced these tests with extraordinary optimism, creativity and determination. The Devon team was not satisfied to merely create the organiza- tional capacity to handle the growth in our property base from our December 1996 merger. We created the organizational foundation to facilitate continued growth in the future. . . . INCLUDING MAINTAINING DISCIPLINE Perhaps Devon’s greatest achievement of 1997 was what we did not do — invest unwisely. In a highly motivated company like ours, the self- induced pressure to grow is intense. This has been a major, positive factor in our merger and acquisition record. However, at Devon, desire is balanced by discipline. In a period of strong oil and gas prices, it is easy to forget how quickly these prices can fall. With relatively high oil and gas prices prevailing for most 20 14 1515 35 75 Net Earnings ($ Millions) Record oil and gas production drove Devon‘s 1997 net earnings up 116% over 1996 net earnings... 92 93 94 95 96 97 ...and almost doubled the company‘s cash margin. 92 93 94 95 96 97 * Revenues less cash expenses. 38 53 55 59 96 181 Cash Margin * ($ Millions)
  6. 6. 4 5 DEVONENERGYCORPORATION WE REMAIN “ROCK SOLID” In an industry where commodity prices and, thus, revenues, can be very volatile, the phrase “rock solid” is not often heard. Why would we choose to apply this to Devon? First, our employees have exhibited the technical skills, motivation and loyalty to be the foundation of our success. Our growth and track record demonstrates this skill and motivation. The fact that we rarely lose staff to competitors shows the loyalty. This past year, when employee recruiting, if not raiding, was rampant, our staff remained loyal. Second, our asset base is equally stable. Our oil and gas reserve life index exceeds eight years. This gives us a consistency of operations and cash flow that is hard to match in our industry. It provides the stability that allows us to maintain our investment discipline. Third, our balance sheet is “bullet proof.” With no debt, substantial cash flow and sizeable assets, oil and gas price volatility has little impact on our endurance. Fourth, our cost structure is low. This provides a significant competitive advantage in our industry. We can generate earnings and cash flow at even low oil and gas prices . . . prices that would be genuinely painful for many of our competitors. Fifth, our prospects for growth are as good as ever before. THE OUTLOOK IS PROMISING I am cautiously optimistic about Devon’s future as we enter 1998. The caution comes from observing current oil and gas prices. As indicated previously, 1998 has opened with relatively low oil prices. This will hurt current revenues. But over the long run, this may not prove so relevant. With our long-lived property base, a short-term decrease in prices will have minimal impact on these long-term investments. The optimism comes from our prospects and financial strength. Our exploration and development programs are better than ever. We have the largest portfolio of undeveloped acreage and seismic data in the company’s history. The opportunities from our property base are reflected in our 1998 drilling and development budget of some $150 million. We anticipate funding this biggest-ever capital budget entirely from working capital and operating cash flow. And should the right opportunity arise, we believe we could fund a cash acquisition of more than one-half billion dollars — without issuing additional equity. Devon Energy Corporation is truly in a rock solid position for the future. J. LARRY NICHOLS President and Chief Executive Officer Oklahoma City, Oklahoma March 27, 1998 On May 31, 1997, H.R. Sanders, Jr. retired from his position as executive vice president of Devon. Over the last 16 years, H.R.’s business acumen and financial creativity have contributed immensely to Devon’s growth and success. I speak for everyone at Devon when I say that we truly miss H.R.’s presence in our day-to-day operations. However, we are continuing to take advantage of his many years of experience as he remains on Devon’s board of directors.
  7. 7. 92 93 94 95 96 97 Cash Margin Per Share ($) 2.76 2.54 2.56 2.68 4.33 5.63 ...and drove 1997 cash margin per share to an all-time record. 92 93 94 95 96 97 Earnings Per Share ($) .94 .98 .64 .66 1.57 2.34 Record production and revenues increased 1997 earnings per share by 49%... LAST YEAR Year Ended December 31, 1993 1994 1995 1996 1997 CHANGE FINANCIAL DATA (Thousands, except per share data) Total Revenues $ 98,757 100,773 113,303 164,017 313,140 91% Cash Expenses $ 45,864 45,699 54,086 68,066 131,695 93% Cash Margin $ 52,893 55,074 59,217 95,951 181,445 89% Non-cash Expenses $ 33,707 41,329 44,715 61,150 106,153 74% Unusual Gain(1) $ 1,300 — — — — NM Net Earnings $ 20,486 13,745 14,502 34,801 75,292 116% Net Earnings per Share: Basic $ 0.98 0.64 0.66 1.57 2.34 49% Diluted $ 0.98 0.63 0.65 1.52 2.17 43% Cash Dividends per Common Share $ 0.09 0.12 0.12 0.14 0.20 43% LAST YEAR December 31, 1993 1994 1995 1996 1997 CHANGE Total Assets $ 285,553 351,448 421,564 746,251 846,403 13% Working Capital $ 15,140 8,305 9,316 19,734 62,416 216% Convertible Preferred Securities of Subsidiary Trust (2) $ — — — 149,500 149,500 — Long-term Debt $ 80,000 98,000 143,000 8,000 — -100% PROPERTY DATA Reserves Oil and Natural Gas Liquids (MBbls) 16,751 47,607 53,935 80,060 81,324 2% Gas (MMcf) 369,254 347,560 363,846 595,519 616,004 3% Total (MBoe) 78,293 105,534 114,576 179,313 183,991 3% SEC @ 10% Present Value (Thousands)(3) $ 380,471 398,206 534,248 1,621,992 913,073 -44% LAST YEAR Year Ended December 31, 1993 1994 1995 1996 1997 CHANGE Production Oil and Natural Gas Liquids (MBbls) 2,748 2,968 3,900 4,768 8,631 81% Gas (MMcf) 35,598 39,335 36,886 35,714 69,327 94% Total (MBoe) 8,681 9,524 10,047 10,720 20,185 88% (1) One-time, non-cash gain of $1.3 million from the required adoption in 1993, of Statement of Financial Accounting Standards No.109. (2) Reflects the issuance of 2.99 million shares of convertible preferred securities on July 10, 1996. (3) Before income taxes. NM Not a meaningful figure. F I V E -Y E A R H I G H L I G H T S 92 93 94 95 96 97 Dividends Per Common Share ($) 0.00 0.09 0.12 0.12 0.14 0.20 While Devon retains most of its earnings to fund growth, we have consis- tently paid cash dividends since 1993. $
  8. 8. 6 7 DEVONENERGYCORPORATION Another Record Year Devon Energy Corporation delivered the best financial performance in the company’s history in 1997. We reached all-time highs for oil and gas production, revenues, net earnings and earnings per share. We retired our remaining long-term debt while driving year-end working capital and total assets to record levels. For 1997, revenues increased 91%, to $313.1 million. Net earnings climbed 116% to $75.3 million. Earnings per common share advanced to $2.34 in 1997, compared to $1.57 in 1996. Earnings per share on a diluted basis also climbed dramatically, to $2.17 in 1997 versus $1.52 in 1996. Production Increase Drives Record Revenues Record production of oil, gas and natural gas liquids drove Devon‘s 1997 revenues and earnings achievements. The company’s 1997 total production of 20.2 million barrels of oil equivalent was an 88% increase over 1996 production. This marked Devon’s tenth consecutive record for annual oil and gas production. The primary contributors to this dramatic increase in production were: s The December 31, 1996 merger of Kerr-McGee’s North American onshore properties into Devon. These properties increased our oil and gas reserve base by 62 million equivalent barrels, or some 50%. s Our aggressive drilling efforts in 1996 and 1997. This more than offset natural decline and increased production on Devon’s historical properties. s A capital improvement program on our Northeast Blanco Unit (NEBU), Devon’s largest gas property, increased production in 1997. By improving the gas gathering system, production facilities and by adding compression, we temporarily reversed natural decline. Our 1997 revenues were not affected by changes in overall product prices. Although our average oil price decreased 9% from $21.00 per barrel in 1996 to $19.05 per barrel in 1997, this was offset by an increase in natural gas prices. The average price we received for our natural gas production climbed 14%, to $2.17 per thousand cubic feet during 1997. Consequently, our average price per barrel of oil equivalent produced in 1997 was $15.15 versus $15.16 in 1996. Higher Pre-tax Expenses Reflect Record Production In addition to nearly doubling 1997 oil and gas production, Devon’s larger property base caused expenses to increase. Total pre-tax expenses rose $87.1 million, to $191.8 million in 1997. The largest contributors were increases in depreciation, depletion and amortization expense (DD&A) and lease operating expense. Our DD&A expense increased $41.9 million, to $85.3 million for 1997. The change in this non-cash expense was our largest expense increase for the year. Most of the increase in DD&A was caused by the rise in overall oil and gas production. Lease operating expense rose $34.1 million during 1997, to $65.7 million. This increase resulted from the additional oil and gas wells we owned during 1997. The additional wells include those we obtained in the December 1996 merger and wells drilled during 1996 and 1997. Income Taxes Rise With Higher Earnings Income tax expense increased $21.6 million in 1997, to $46.0 million. A slight decrease in our financial income tax rate in 1997 was overshadowed by a dramatic rise in pre-tax earnings. Some $20.8 million of 1997 income tax was deferred and, therefore, did not require the use of cash. Cash Margin and Balance Sheet Improves Our cash margin (revenues less cash expenses) increased 89%, to $181.4 million in 1997. During the year, we funded over $120 million of oil and gas exploration, development and property acquisition costs with operating cash flow and working capital. With a record $846.4 million in total assets, no long-term debt and increased cash flow, we ended 1997 financially stronger than ever before. s $
  9. 9. ? ? 8 9 DEVONENERGYCORPORATION Devon has added significant oil and gas reserves through mergers or acquisitions in each of the last few years, yet in 1997 you did not complete a major transaction. What happened? Devon is constantly searching for merger and acquisition opportunities that have good intrinsic returns and can have a positive impact on per share performance. Our success in this area has been one of the keys to our rapid growth. However, when executing an acquisition strategy, the single most important element is discipline. Many companies that have grown through acquisitions have failed in this regard. They go on a buying binge, making one acquisition after another. While such activity feels like growth at the time, it sometimes leads to disappointing long-term results. A company’s balance sheet becomes stretched. Financial flexibility is impaired. Newly acquired assets are not properly integrated into the previous property base. Costs no longer receive proper attention. Return on equity begins to suffer. Or worse yet, the company becomes enamored with building a large company and forgets the most important consideration in evaluating a potential acquisition: the impact on per share results.As major shareholders ourselves, the management team of Devon never forgets for whom we are working. The fact that we did not complete a major transaction in 1997 reflects the fact that we did not uncover any opportunities that met our financial return and per share criteria. Have higher oil and gas prices or the industry’s increased access to debt and equity capital made it impossible to make good acquisitions? No. Absolutely not. While it’s true that readily available capital and 1996-1997 spikes in oil and gas prices temporarily increased competition for acquisitions, the primary drivers behind industry consolidation are alive and well. Oil and gas price volatility, an increasingly complex regulatory environment and continued industry consolidation are all forces that cause oil and gas properties to change hands. With an extremely solid balance sheet, enviable economies of scale in our five focus areas and more than 25 years of experience in making acquisitions, Devon is very well positioned for future acquisitions. President & CEO, Larry Nichols, Answers Your Questions D E V O N E N E R G Y S T E P S U P T O M E E T 1 9 9 8 ’ s C H A L L E N G E S .
  10. 10. With your 1998 drilling and development budget at $140 to $160 million, it appears that Devon is putting increasing emphasis on the drill bit as a means of growth. Why is this? Devon’s increasing profitability, cash flow and superior balance sheet have given us the financial firepower to pursue somewhat higher risk/reward exploration. Devon has been gearing up its exploration efforts over the last five years. Several of the larger projects we have been working on in the Gulf of Mexico and the Permian Basin will come to fruition in 1998. The Kerr-McGee transaction in late 1996 also gave us sizable acreage positions in several attractive exploratory plays that we are now pursuing. Adding these to the exploration projects we already had underway has given us a much larger inventory of exploratory prospects than ever before.Consequently, the exploration portion of our drilling and development budget is expected to increase to $60 - $70 million in 1998. This is not to imply that we are abandoning our historically successful exploitation and development activities. For 1998, we expect the lower risk portion of our budget to total $80 to $100 million. This should provide us a base of “bread and butter” drilling opportunities. Speaking of exploration and development, your historical finding cost from discoveries and revisions has been above industry averages. Why is this, and how can you correct it? This result is an artifact of the normal method used in preparing historic finding cost data. When examining overall finding cost, including both acquisition and exploration activities, it’s apparent that Devon’s finding costs are very low.That is why our DD&A rate of only $4.00 or so per barrel of oil equivalent is among the lowest in the industry. However, when attempting to analyze our acquisition and exploration efforts separately, it’s easy to arrive at an erroneous conclusion. The normal methodology makes our acquisition efforts look better than true economic reality and makes our exploration efforts look worse. The normal method of segregating acquisition and exploration costs is subject to distortion. In mergers and acquisitions, we often purchase properties that have “proved undeveloped reserves.” These reserves are “proven” by engineering standards but are associated with wells not yet drilled. By accounting rules, the initial costs of purchasing such reserves are recorded as “acquisition costs.” However, the costs to drill the associated wells are classified as “exploration and development costs.” This effectively transforms certain of our acquisition-oriented costs into “exploration costs.” Consequently, our exploration costs are boosted above industry averages. This transformation of costs is not problematic for most of the industry. A pure exploration and drilling company (i.e., never does acquisitions) obviously is not forced to deal with these distortions. There is no easy solution for this except for investors to realize the inherent flaws in attempting to bisect Devon’s integrated acquisition and drilling efforts. How successful were your exploration efforts in 1997? I would classify our 1997 exploration and development efforts as reasonably successful. We drilled 18 exploratory wells during 1997, only two of which were dry holes. We drilled 277 development wells with a 97% success rate. We replaced 118% of 1997 production with drilling and revisionsat a finding cost of only $4.84 per barrel of oil equivalent. Despite these successes, we also encountered some disappointments along the way. A lack of rig availability and a lack of experienced drilling crews caused us to push into 1998 some wells that were originally scheduled for drilling in 1997.
  11. 11. 10 11 DEVONENERGYCORPORATION You have had the Kerr-McGee properties for a full year now. Have these properties met your expectations? What exploitation and exploration opportunities have you uncovered? The Kerr-McGee properties have exceeded our initial expectations. Following integration with Devon’s historical property base, the producing properties from the Kerr-McGee merger were less expensive to operate than we had originally anticipated. Furthermore, we are finding upside through exploration and exploitation projects on these properties. An example of the exploration upside is in the Panhandle Morrow Play in Texas. Here we have assembled over 70,000 net undeveloped acres, almost 300 square miles of 3-D seismic data and successfully completed several exploratory wells. We expect to be drilling here for several years to come. Our House Creek Unit in Wyoming is an example of the exploitation upside. In 1997 we purchased an additional interest and initiated a twelve-well pilot infill program. As a result, production increased by more than 500 barrels of oil per day. Based on the success of the pilot program, we plan to drill an additional 60 to 80 wells in 1998. The 1996 merger also gave us an introduction into Canada. We spent some $8 million in capital expenditures in Canada during 1997 with very good results. We drilled 26 wells, all of which were completed as producers, and replaced almost 150% of 1997’s production with reserve additions. We are looking forward to expanding our presence here again in 1998. Will Devon continue to divest non-core properties in 1998 as you have done in the past? To continue to improve the quality of our property base we constantly identify and sell those properties that evolve as non-strategic or marginally economic. This includes properties that become too expensive to operate and those in areas where we lack critical mass. Our most active years for property sales have generally followed major acquisitions. However, the properties we obtained in the December 1996 merger are of very high quality and have good economic margins. They are also an excellent geographic fit for Devon. As a result, very few of the merger properties were identified for sale. We will continue to regularly review our property base to identify those that no longer meet our criteria. However, the extent to which we engage in property sales in the future, will to a large degree, depend on future acquisitions. Oil and gas prices tend to be both volatile and difficult to predict. Since your revenues are generated almost entirely from the sales of these products, how does Devon cope with this volatility? We have adopted a number of strategies to help reduce the negative effects of oil and gas price volatility. First, and most importantly, we keep our cost structure low. We do this by purchasing and developing properties that can be operated economically, by carefully controlling our general and administrative expenses and by keeping debt levels; i.e., interest expense, low. Second, we balance oil and gas reserves and production so that our revenues are less vulnerable to low prices in either commodity. This is reflected in our 1997 oil to gas production mix of roughly 40%/60%. Third, we pursue projects with long-lived reserves. The ultimate value of these projects is less vulnerable to short-term oil and gas price swings. All of these actions tend to give us more consistent, more sustainable margins than many of our competitors. Another way to be “rock solid” in a “quick sand” industry. s ?
  12. 12. 12 13 DEVONENERGYCORPORATION Oil and gas exploration is nothing new for Devon. In 1973, as a virtually new company, we drilled our first exploratory test. By the late 1970’s, we had one of the most extensive exploratory programs in Oklahoma. In 1989, we discovered the coal seam gas reserves in our largest gas producing property — the Northeast Blanco Fruitland Coal Unit in New Mexico. In 1992, we made a wildcat discovery that we have since developed into one of our largest oil producing properties — Sand Dunes. What is new for Devon is our level of commitment to high potential exploration. In the late 1980’s and early 1990’s Devon was a mid-size exploration and production company. We reinvested most of our cash flow in acquisitions and low risk development drilling. Due to the success of this strategy, we have grown into a much larger company. We now have the size and financial strength to augment our traditional growth strategies with large-scale high potential exploration. In 1997, we ramped up our exploration activity to record levels. We made exploratory discoveries in the Permian Basin, the Mid-Continent and Canada. In all, we drilled 18 exploration wells with an 89% success rate. We deployed the largest exploration budget in the company’s history — over $19 million. And in spite of doubling our production in 1997 to over 20 million barrels of oil equivalent, we more than replaced production with discoveries and revisions. More importantly we laid the foundation to dramatically expand our exploration efforts in 1998 and beyond. With the addition of seven geologists and geophysicists during 1997, we significantly increased the talent we have working on exploration projects. We acquired 263 square miles of 3-D seismic data. To increase our capacity to process seismic data we added three 3-D seismic workstations, bringing our total to seven. And we acquired more than 40,000 net acres of undeveloped leasehold in five exploration plays. The opportunities generated by these activities are reflected in our 1998 exploration budget of $60 to $70 million — more than a 200% increase over 1997. A Rock Solid Commitment to Exploration DEVON IS E X P A N D I N G I T S E X P L O R A T I O N C A P A C I T Y F O R T H E FUTURE.
  13. 13. But isn’t this more risky? Yes and no. Certainly wildcat exploration wells have a lower chance of success than development wells. Then, too, the $60 million to $70 million for 1998 is a materially larger sum than $10 to $20 million of earlier years. But on a percentage basis, Devon is well within its historical risk tolerance. The $60 to $70 million for 1998 is less than 10% of our $846 million balance sheet. All of our 1998 exploratory tests could be dry and we would not have “bet the farm.” Furthermore, our long reserve life would still provide substantial production and cash flow far into the future. So the risk is tolerable. Fortunately, our upside is being expanded disproportionately. A successful test for one of our exploratory wells could add 10, 20 or even 50 Bcfe to our reserves. In the context of Devon’s otherwise relatively low risk profile, these operations have a highly favorable risk/reward profile for us. Following are some of the more exciting exploratory projects we are pursuing for 1998 and beyond: Panhandle Morrow At the end of 1996, we acquired a sizeable acreage position in this emerging exploration play in the Texas Panhandle and western Oklahoma. In 1997, we aggressively acquired additional acreage and conducted four 3-D seismic surveys here. We now have over 70,000 net undeveloped acres on which we have delineated 13 separate multi-well prospects. We drilled and completed four successful exploratory gas wells at depths of between 14,000 and 17,000 feet. In 1998, we expect to drill an additional 15 to 20 Panhandle Morrow wells. In 1998 we will also expand our presence here with the acquisition of additional acreage and seismic data. Poker Lake/Cotton Draw This 26,000-acre property located in the southeastern New Mexico portion of the Permian Basin was the site of a significant Devon gas discovery in 1997. Devon and its partner, a major oil company, drilled this well following the interpretation of our 96 square mile 3-D seismic survey. This well currently produces some 16 92 93 94 95 96 97 59 102 83 199 295 194 Drilling Results DRY PRODUCTIVE Devon drills mostly lower risk development wells. This has helped our drilling success rate exceed 95% over the past six years. 92 93 94 95 96 97 3 4 5 7 19 3 Exploration Expenditures ($ Millions) ...is reflected in our rising exploration budget. 92 93 94 95 96 97 220 167 164 162 494490 Net Undeveloped Acres (Thousands) Devon‘s increasing portfolio of undeveloped acreage upon which to explore... 92 93 94 95 96 97 4 16 8 5 24 11 Reserve Additions from Drilling and Revisions (MMBoe) Devon‘s reserve additions from drilling and revisions more than replaced our record 1997 production.
  14. 14. 14 15 DEVONENERGYCORPORATION We take pride in our ability to find better solutions to challenges big and small. Employees that challenge the status quo with innovative thinking are an integral part of this process. A sterling example of such an employee is Devon field foreman, Troy Settle. Troy has helped to pioneer a better way to dispose of wastewater sometimes produced with oil and gas. In addition to the primary products, oil and gas wells often produce water. This wastewater can be environmentally sensitive. Disposing of it in a cost effective and environmentally sound way has long posed a challenge to oil and gas producers. Typically, this wastewater is stored in on-site tanks and then transported by truck to a disposal facility. Another method is to inject it into absorbent rock formations deep below the surface. However, both of these methods are expensive. Troy has been experimenting with a process known as phytoremediation. This process utilizes salt- tolerant plants to reduce the volume of oilfield wastewater left for disposal. With phytoremediation the produced water is first tested to ensure it contains nothing harmful to livestock. It then flows into a trough where special salt-tolerant plants are growing. The plants consume the water and transpire it from their leaves. The plants are then used onsite to sustain livestock. An oilfield waste product is transformed into a useful commodity! While more experimentation is needed, Troy’s initial field trial indicates that phytoremediation holds promise. It appears that this emerging technology is a safe, environmentally friendly and less expensive means of disposing oilfield wastewater. It holds the potential to save domestic oil and gas producers millions of dollars each year. “Hats off” to innovative thinkers like Troy Settle. s Innovative Thinking: Phytoremediation Devon foreman, Troy Settle, checks a produced wastewater storage tank. Grass grows in troughs of oilfield wastewater at the site of Devon‘s phytoremediation field trial. Cordgrass, shown here, was selected due to its saline tolerance and its suitability for consumption by animals.
  15. 15. million cubic feet per day from the Devonian formation at a depth of 16,500 feet. The well also has significant potential in the Morrow and Wolfcamp formations found at shallower depths in the same area. We are currently drilling our second Devonian well and plan to drill additional wells here later in 1998. To capitalize on the knowledge gained from our Poker Lake/Cotton Draw exploration project, we are conducting a large regional study looking for similar opportunities. South of Poker Lake/Cotton Draw, Devon purchased additional interests in properties in southeast New Mexico and Texas. With the acquisition of acreage and seismic data near completion, Devon and our partners expect to begin drilling during 1998. Breton Sound/Main Pass Devon owns an average 45% working interest in three deep gas prospects located in the shallow, state waters off the Louisiana coast. Each of these prospects targets potential net reserves of 50 to 100 billion cubic feet at depths of 16,000 to 18,000 feet. With wells on two of these prospects currently underway, we expect to complete tests of all three prospects during 1998. Ouachita Overthrust We are prospecting for Ordovician Age formations in three distinctly separate areas: the Black Warrior Basin in Mississippi, the Kerr Basin in south Texas and the Ardmore Basin in southern Oklahoma. In the Black Warrior Basin, we are currently drilling the initial well and have identified 10 additional prospects. In the Kerr Basin, we are acquiring acreage and are planning to acquire additional seismic data during 1998. In the Ardmore Basin, we are acquiring acreage on several prospects and plan to conduct a 3-D seismic survey and drill the initial wildcat during 1998. Pouce Coupe This property is located in Alberta, Canada. When we acquired it, production was from wells completed in Jurassic Age sands. During 1997, we acquired 3-D seismic data and made new zone discoveries in two Triassic Age formations. Based on this success, we plan to drill several more wells on our acreage beginning in 1998. We are also acquiring additional acreage and seismic data to expand this play into the surrounding area. s DEVON EN ER G Y I S I N A R O C K S O L I D P O S I T I O N F O R F U T U R E G R O W T H .
  16. 16. 16 17 DEVONENERGYCORPORATION
  17. 17. Eleven Year Property Data Gas Reserves by Area Total Oil And Gas Reserves by Area Oil Reserves by Area Rocky Mountain 24% Mid- Continent 5% Other 1% Permian Basin 60% Canada 10% Canada 8% Mid- Continent 18% Rocky Mountain 14% Other 1% San Juan Basin 38% Permian Basin 21% Other 1% Canada 9% Mid- Continent 12% Rocky Mountain 19% San Juan Basin 21% Permian Basin 38% A Rock Solid Portfolio of Producing Properties Exploration may provide upside potential, but the foundation of an oil and gas company is its producing properties. Devon has built a concentrated base of profitable oil and gas properties with long-lived reserves. These properties provide us with a dependable source of cash flow with which to fund our future growth. 1987 1988 1989 1990 1991 Reserves Oil and Natural Gas Liquids (MBbls) 2,286 5,590 4,800 4,058 3,798 Gas (MMcf) 34,829 98,388 149,761 169,473 191,642 Total (MBoe) (1) 8,090 21,988 29,760 32,304 35,738 SEC @ 10% Present Value (Thousands) (2) $ 44,460 88,564 137,274 162,084 154,745 Production Oil and Natural Gas Liquids (MBbls) 359 568 681 545 484 Gas (MMcf) 4,522 5,919 7,776 9,314 15,398 Total (MBoe) (1) 1,112 1,554 1,977 2,097 3,050 Average Prices Oil and Natural Gas Liquids (Per Bbl) $ 18.15 14.62 18.15 22.79 19.49 Gas (Per Mcf) $ 1.92 1.69 1.79 1.85 1.24 Oil, Gas and Natural Gas Liquids (Per Boe) (1) $ 13.68 11.76 13.29 14.12 9.35 Production and Operating Expense per Boe (1) $ 4.50 5.31 5.99 5.71 3.48 (1) Gas converted to oil at the ratio of 6 Mcf:1 Bbl (2) Before income taxes.
  18. 18. 18 19 DEVONENERGYCORPORATION Operating Statistics by Core Area PERMIAN SAN JUAN ROCKY MID- TOTAL BASIN BASIN MOUNTAIN CONTINENT OTHER U.S. CANADA TOTAL Producing Wells at Year-end 7,174 915 720 2,184 286 11,279 926 12,205 1997 Production: Oil (MBbls) 4,111 2 1,528 334 80 6,055 950 7,005 Gas (MMcf) 17,731 18,044 6,677 16,669 1,894 61,015 8,312 69,327 NGLs (MBbls) 861 8 374 224 1 1,468 158 1,626 Total (MBoe)(1) 7,927 3,017 3,015 3,336 397 17,692 2,493 20,185 Average Prices: Oil Price ($/Bbl) $ 19.24 18.28 18.60 19.42 18.55 19.08 18.89 19.05 Gas Price ($/Mcf) $ 2.38 2.13 1.99 2.41 2.57 2.28 1.39 2.17 NGL Price ($/Bbl) $ 12.57 11.55 14.68 13.08 12.52 13.18 15.28 13.38 Year-End Reserves: Oil (MBbls) 41,604 7 16,873 2,119 299 60,902 7,541 68,443 Gas (MMcf) 130,718 229,481 87,245 112,815 7,565 567,824 48,180 616,004 NGLs (MBbls) 7,291 50 2,953 1,778 0 12,072 809 12,881 Total (MBoe)(1) 70,682 38,304 34,366 22,699 1,560 167,611 16,380 183,991 Year-End Present Value of Reserves ($ thousands):(2) Before Federal Income Tax $ 344,388 181,760 149,736 134,360 10,204 820,448 92,625 913,073 After Federal Income Tax $ 663,979 62,874 726,853 Year-End Leasehold (Net Acres) Producing 156,635 16,727 90,486 188,061 29,124 481,033 76,200 557,233 Undeveloped 176,421 10,364 93,670 108,335 29,523 418,313 75,732 494,045 Wells Drilled During 1997 174 24 22 40 9 269 26 295 1997 Exploration & Development Expenditures ($ millions) $ 69.5 0.4 11.1 13.8 3.5 98.3 8.3 106.6 Estimated 1998 Capital Expenditures ($ millions) $ 39-44 4 26-29 26-29 36-43 131-149 9-11 140-160 (1) Gas converted to oil at the ratio of 6 Mcf:1 Bbl. (2) Estimated future revenue to be generated from the production of proved reserves, net of estimated future production and development costs, discounted at 10% in accordance with Securities and Exchange Commission guidelines. 5-YEAR 10-YEAR COMPOUND COMPOUND 1992 1993 1994 1995 1996 1997 GROWTH RATE GROWTH RATE 17,360 16,751 47,607 53,935 80,060 81,324 36% 43% 263,598 369,254 347,560 363,846 595,519 616,004 19% 33% 61,294 78,293 105,534 114,576 179,313 183,991 25% 37% 314,566 380,471 398,206 534,248 1,621,992 913,073 24% 35% 1,558 2,748 2,968 3,900 4,768 8,631 41% 37% 28,374 35,598 39,335 36,886 35,714 69,327 20% 31% 6,287 8,681 9,524 10,047 10,720 20,185 26% 34% 18.42 15.63 14.48 15.82 19.82 17.98 — — 1.41 1.54 1.43 1.38 1.91 2.17 9% 1% 10.92 11.27 10.43 11.19 15.16 15.15 7% 1% 3.66 3.84 3.30 3.40 3.94 4.14 2% -1%
  19. 19. 3. Rocky Mountain Region 2. San Juan Basin 4. Mid-Continent Area 5. Western Canada Sedimentary Basin 1. Permian Basin Over a dozen oil and gas producing basins are included in this region which stretches across eight states in the western U.S. Devon’s most significant Rocky Mountain properties are located in the Bighorn and Powder River Basins of Wyoming. The Basin covers a densely drilled 3,700 square mile area in northwest New Mexico and southern Colorado. It has long been one of the largest gas- producing areas of the U.S. This area historically produced from conventional sandstones found at a depth of about 5,500’. Technology pioneered by Devon and a few other companies in the 1980’s and 1990’s resulted in significant production from the Fruitland Coal at a depth of about 3,000’. Natural gas produced from these coal deposits (coal seam gas) makes up almost all of Devon’s San Juan Basin gas production. The region generally designated as the Mid- Continent Area includes three notable oil and gas producing provinces covering portions of Texas, Oklahoma, Arkansas, and Kansas: the Arkoma Basin, the Anadarko Basin and North Central Texas. This prolific oil and gas producing region encompasses about 66,000 square miles of western Texas and southeastern New Mexico and contains more than 500 major oil and gas fields. Acreage held by production from existing wells and large federal exploration units make leases difficult to obtain. Most of Devon’s position here was established through four major transactions. This large geologic feature covers portions of British Columbia, Alberta, Saskatchewan and Manitoba. Within the feature are two troughs defined as the Alberta and the Williston Basins. Devon’s Canadian properties are in the Alberta Basin. 5 4 1 2 3
  20. 20. Grayburg-Jackson Field West Red Lake Area Poker Lake/Cotton Draw Profile 1997 Activity x 50% to 100% working interest in 6,000 acres in southeastern New Mexico. x Initially obtained a 98% working interest in 1,200 acres in 1992 acquisition. x Produces oil from the Grayburg and San Andres formations at 2,500’. x Drilled and compl x Initiated pilot wat x Acquired over 750 x 50% working interest in 26,000 acres in southeastern New Mexico. x Purchased in 1992 acquisition. x Produces from multiple formations at 4,000’ to 17,000’. x Principle reserve targets are the Morrow formation at 14,500’ and the Devonian formation at 16,500’. x Drilled and compl feet per day. x Drilled 4 shallowe x Initiated drilling o x Near 100% working interest in 8,600 acres in southeastern New Mexico. x Purchased in 1994 acquisition. x Produces oil from the Grayburg and San Andres formations at 3,000’ to 4,000’. x One of Devon’s top five properties with 21.9 million barrels of oil equivalent reserves at 12/31/97. x Implemented fina x Drilled and compl x Installed 10 miles x Converted 31 prod x Increased water in 1. Permian Basin Northeast Blanco Unit (NEBU) x 23% working interest in 33,000 acres in northwestern New Mexico. x Originally developed by Devon in the late 1980’s and early 1990’s. x Contains 102 producing wells, 4 water disposal wells, gas and water gathering systems and an automated production control system. x Produces gas primarily from the Fruitland Coal formation at 3,000’. x Devon’s largest property with 24.8 million barrels of oil equivalent reserves at 12/31/97. x Substantially com x Installed 20 field c 32-9 Unit x 28% working interest in 15,400 acres in northwestern New Mexico. x Purchased by Devon in 1993. x Contains 51 producing wells, water disposal facilities and gas and water gathering systems. x Produces gas from the Fruitland Coal formation at 3,000’. x One of Devon‘s top five properties with 13.4 million barrels of oil equivalent reserves at 12/31/97. x Recavitated 3 wel x Maintained produ 2. San Juan Basin House Creek Area x Two federal units in northeastern Wyoming. x 46% working interest in 24,000 acre House Creek Unit. x 26% working interest in 9,700 acre North House Creek Unit. x Obtained in 1996 merger. x Produces oil from the Sussex Sand formation at 8,200’. x One of Devon’s top five properties with 11.8 million barrels of oil equivalent reserves at 12/31/97. x Acquired addition x Initiated a 12 well x Continued infill dr Worland Unit x 98% to 100% working interest in 25,000 acre federal unit in northwestern Wyoming. x Consists of three fields and over 13,000 undeveloped acres. x Small initial position obtained in 1992 acquisition. x Acquired additional interests in 1995 and 1996. x 100% interest in gas processing plant on the Unit. x Produces oil and gas from multiple formations at 7,000’ to 11,000’. x Completed 2 wells x Increased plant ca x Completed a 60 sq x Increased gas gat 3. Rocky Mountain Region Gift Field x 70% working interest in 10,000 acres in northwestern Alberta. x Obtained in 1996 merger. x Produces oil from the Slave Point formation at 5,800’. x Acquired 12 squa x Completed 3-D se x Drilled and compl Pouce Coupe Field x 65% working interest in 10,000 acres in west central Alberta. x Obtained in 1996 merger. x Produces gas from the Halfway and Kiskatinaw formations at 5,500’ and 7,500’, respectively. x Drilled 2 wells. x Recompleted 4 we x Acquired 25 squa 5. Western Canada Sedimentary Basin Panhandle Morrow Play x 55% working interest in 129,000 acres in western Oklahoma and the Texas Panhandle. x Includes 13 separate multi-well prospects. x Obtained in 1996 merger. x Produces gas from the Upper Morrow Chert at 14,000’ to 17,000’. x Drilled and compl x Initiated drilling o x Acquired and/or in x Acquired 31,000 n 4. Mid-Continent Area Pinto Prospect x 100% working interest in 14,000 acres in west central Alberta. x Obtained in 1996 merger. x Produces gas from the Cardium Sand formation at 10,000’. x Acquired 6,400 ac x Acquired over 200 Key Property Highlights
  21. 21. 20 21 22 DEVONENERGYCORPORATION 1998 Plans 65 producer wells. od program. ss acres. x Drill 35 producer wells. x Acquire additional acreage. x Convert producer wells to injector wells to expand waterflood program. x Add additional water injection facilities. a Devonian discovery well that is producing 16 million cubic ective wells, including 1 dry hole. ond Devonian well. x Complete second Devonian well. x Drill third Devonian well. x Perform 3-D seismic survey on additional acreage. se of water injection program on interior of field. 17 producer wells and 9 injector wells. ater lines. r wells to injector wells. on rate to over 40,000 barrels per day. x Convert approximately 30 producer wells to injector wells. x Drill 5 to 10 producer wells and 5 injector wells. d gathering system improvements. ressors resulting in a significant increase in production. x Recavitate 10 to 15 wells. x Install 10 to 15 field compressors. x Finalize gathering system improvements. at gas gathering system capacity. x Perform recavitations and well workovers as needed to sustain production at current levels. orking interest in House Creek Unit. ng program on House Creek Unit. program on North House Creek Unit. x Accelerate infill drilling program on House Creek Unit. - Drill 30 to 40 producer wells. - Drill 30 to 40 injector wells. ated in late 1996. ty by one-third. e mile 3-D seismic survey. g capacity with the installation of 2 field compressors. x Complete interpretation of 3-D seismic survey. x Initiate a multi-well drilling program. les of 3-D seismic data. c data interpretation. 9 wells. x Drill 6 to 8 wells. les of 3-D seismic data. x Interpret 3-D seismic data. x Drill 3 to 6 wells. 4 exploratory wells. dditional wells. reted 3-D seismic data on 6 prospect areas. ndeveloped acres. x Drill 15 to 20 wells. x Interpret existing 3-D seismic data. x Conduct additional 3-D seismic surveys. x Continue to acquire additional acreage. are miles of 3-D seismic data. x Drill first exploratory well.
  22. 22. 23 DEVONENERGYCORPORATION F I N A N C I A L S TAT E M E N T S A N D M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S Selected Eleven-Year Financial Data 24 Management’s Discussion and Analysis of Financial Condition and Results of Operations 26 Management’s Responsibility for Financial Statements 39 Independent Auditors’ Report 39 Consolidated Balance Sheets 40 Consolidated Statements of Operations 41 Consolidated Statements of Stockholders’ Equity 42 Consolidated Statements of Cash Flows 43 Notes to Consolidated Financial Statements 44
  23. 23. 1987 1988 1989 1990 OPERATING RESULTS (in thousands, except per share data) Revenues Oil Sales $ 6,509 8,302 12,370 12,412 Gas Sales 8,693 9,983 13,906 17,204 Natural Gas Liquids Sales — — — — Other Revenue 2,098 2,735 2,543 1,302 Total Revenues $ 17,300 21,020 28,819 30,918 Production and Operating Expenses $ 5,037 8,255 11,835 11,983 Depreciation, Depletion and Amortization(1) $ 7,697 7,429 7,350 8,005 General and Administrative Expenses $ 4,056 3,854 6,103 4,919 Interest Expense $ 1,141 2,132 2,140 1,956 Distributions on Preferred Securities of Subsidiary Trust(2) $ — — — — Adjusted Net Earnings (Loss)(3) $ (1,066) (565) 876 2,554 Reported Net Earnings (Loss) $ (1,066) 3,347 876 2,554 Preferred Stock Dividends(4) $ — — 821 2,324 Net Earnings (Loss) to Common Shareholders $ (1,066) 3,347 55 230 Net Earnings (Loss) per Common Share - Basic $ (0.17) 0.48 0.01 0.03 Net Earnings (Loss) per Common Share - Diluted $ (0.17) 0.48 0.01 0.03 Cash Dividends per Common Share $ — — — — Cash Margin(5) $ 7,066 6,779 8,696 11,838 Weighted Average Common Shares Outstanding - Basic 6,165 6,924 8,595 8,640 BALANCE SHEET DATA (in thousands) Total Assets $ 60,715 89,116 97,916 123,547 Long-term Debt $ 13,453 30,000 9,500 28,000 Other Long-term Obligations $ 5,198 6,337 5,071 3,919 Deferred Income Taxes $ 8,217 5,480 5,889 7,036 Preferred Securities of Subsidiary Trust(2) $ — — — — Stockholders’ Equity $ 28,928 41,557 70,156 70,767 Common Shares Outstanding 6,165 8,584 8,608 8,679 (1) Includes $25 million non-cash reduction in the carrying value of oil and gas properties in 1991. (2) Trust convertible preferred securities were issued on July 10, 1996. Due to the date of issuance, 1996 distributions represent less than two quarters of payments. (3) Excludes an unrelated one-time non-cash gain of $3.9 million in 1988 from the required adoption of Statement of Financial Accounting Standards No. 96 and a one-time non-cash gain of $1.3 million in 1993 from the required adoption of Statement of Financial Accounting Standards No.109. (4) Shares of $1.94 convertible preferred stock were issued on August 23, 1989 and converted to common stock on November 2, 1992. Thus preferred dividends were paid for approximately 38 months. (5) Revenues less cash expenses. NM Not a meaningful figure. Selected Eleven-Year Financial Data
  24. 24. DEVONENERGYCORPORATION 24 25 5-YEAR 10-YEAR GROWTH GROWTH 1991 1992 1993 1994 1995 1996 1997 RATE RATE 9,436 27,329 38,395 38,086 55,290 80,142 133,445 37% 35% 19,091 39,973 54,876 56,372 50,732 68,049 150,549 30% 33% — 1,370 4,544 4,908 6,404 14,367 21,754 74% NM 1,815 2,892 942 1,407 877 1,459 7,392 21% 13% 30,342 71,564 98,757 100,773 113,303 164,017 313,140 34% 34% 10,601 23,030 33,325 31,420 34,121 42,226 83,579 29% 32% 32,844 19,894 28,409 34,132 38,090 43,361 85,307 34% 27% 5,832 6,510 7,640 8,425 8,419 9,101 12,922 15% 12% 2,209 2,644 3,422 5,439 7,051 5,277 — NM NM — — — — — 4,753 9,718 NM NM (15,024) 14,615 19,186 13,745 14,502 34,801 75,292 39% NM (15,024) 14,615 20,486 13,745 14,502 34,801 75,292 39% NM 2,270 1,703 — — — — — NM NM (17,294) 12,912 20,486 13,745 14,502 34,801 75,292 42% NM (1.99) 0.94 0.98 0.64 0.66 1.57 2.34 20% NM (1.99) 0.90 0.98 0.63 0.65 1.52 2.17 19% NM — — 0.09 0.12 0.12 0.14 0.20 NM NM 11,650 38,140 52,893 55,074 59,217 95,951 181,445 37% 38% 8,687 13,802 20,822 21,552 22,074 22,160 32,216 18% 18% 102,107 225,972 285,553 351,448 421,564 746,251 846,403 30% 30% 32,000 54,450 80,000 98,000 143,000 8,000 — NM NM 3,204 2,635 2,723 2,683 9,512 11,585 21,040 52% 15% 908 4,151 8,643 27,340 34,452 81,121 101,474 90% 29% — — — — — 149,500 149,500 NM NM 53,015 153,267 172,900 206,406 219,041 472,404 543,576 29% 34% 8,693 20,733 20,842 22,051 22,112 32,141 32,319 9% 18%
  25. 25. OVERVIEW Devon concluded 1997 financially stronger and larger than at any previous time in the company’s history. Over the last three years Devon’s oil and gas reserves have grown 74% to 184 million barrels of oil equivalent (“MMBoe”). Our unused long-term credit lines have increased 64% over the same period, to $208 million. Total assets have increased 141% to $846 million. During the same three years we reduced our long-term debt from $98 million to zero and signifi- cantly increased stockholders’ equity. Our operating performance has also improved by most measures over the last three years. The 1997 oil and gas production of 20.2 MMBoe was 112% over that of 1994. The 1997 production increase, coupled with a 45% increase in oil, gas and NGL prices over 1994 levels, led to revenues and earnings gains. Net earnings for 1997 climbed 448% over those of 1994, to $75.3 million. Net cash provided by operating activities rose from $46.4 million in 1994 to $168.7 million in 1997. The cash margin1 (total revenues less cash expenses) during these same three years has increased from $55.1 million in 1994 to $181.4 million in 1997. This growth in operations was driven primarily by the following events: s We acquired Alta Energy Corporation through a $72 million cash and common stock merger in May 1994. The merger added substantial oil and gas reserves, production and revenues to our Permian Basin position. s In 1995, we entered into a transaction covering substantially all of our San Juan Basin coal seam gas properties (the “San Juan Basin Transaction”). This transaction added approximately $8 million, $10 million and $12 million to our annual revenues in 1997, 1996 and 1995, respectively. See Note 3 to the consolidated financial statements included elsewhere in this report for a detailed discussion of the San Juan Basin Transaction. s On December 31, 1996, Devon acquired all of Kerr-McGee Corporation’s North American onshore oil and gas exploration and production business and properties (the “KMG-NAOS Properties”) in exchange for 9,954,000 shares of Devon common stock. This transaction added approximately 62 million Boe to our year-end 1996 proved reserves (an increase of over 50%), as well as 370,000 net undeveloped acres of leasehold. s We have been successful during the last three years in our drilling efforts. During such period, we have spent approximately $246 million to drill 688 wells, of which 667 were completed as producers. s Prices received from oil, gas and NGL revenues have risen (though with volatility) 45%, from $10.43 per Boe in 1994 to $15.15 per Boe in 1997. The following actions during the last three years improved our liquidity and financial resources while reducing our bank debt: s Our production and revenue gains have given us a substantially larger cash flow and, thus, capital budget. s Our acquisition and drilling efforts during the last three years have added 120.4 MMBoe of proved reserves to our asset base. Combined with 1.8 MMBoe of upward revisions to our reserve estimates, our total reserve additions of 122.2 MMBoe during the past three years were 298% of our production of 41.0 MMBoe. s In July, 1996, Devon, through a newly-formed affiliate trust, issued $149.5 million of 6.5% Trust Convertible Preferred Securities (the “TCP Securities”). Combined with cash flow from operations, this transaction has eliminated Devon’s long-term debt. s Our oil and gas reserve additions, production gains, revenue increases and equity additions over the past three years have allowed us to increase our unused lines of credit. Since the end of 1994, our available long-term credit lines have increased by $81 million to a total of $208 million at year-end 1997. The growth exhibited by Devon over the last three years extends a nine-year expansion period for the company. This period began when we became a public company in 1988. Through our acquisitions and our drilling and development efforts, we have significantly increased oil and gas reserves and production over this period. While we have consistently increased production over this nine-year period, volatility in oil and gas prices has resulted in considerable variability in earnings and cash flows. Prices for oil, natural gas and NGLs are determined primarily by market conditions. Market conditions for these products have been, and will continue to be, influenced by regional and world-wide economic growth, weather and other factors that are beyond our control. Devon’s future earnings and cash flows will continue to depend on market conditions. Management’s Discussion and Analysis of Financial Condition and Results of Operations
  26. 26. Like all oil and gas production companies, we face the challenge of natural production decline. As virgin pressures are depleted, oil and gas production from a given well naturally decrease. Thus, an oil and gas production company depletes part of its asset base with each unit of oil and gas it produces. Historically, we have been able to overcome this natural decline by adding more reserves through drilling and acquisitions than we produce. However, our future growth, if any, will depend on our ability to continue to add reserves in excess of production. Given the dependence of oil and gas prices on factors outside of our control, our management has focused its efforts on increasing oil and gas reserves and production and on controlling expenses. Over its nine year history as a public company, Devon has been able to significantly reduce its production and operating costs per unit of production. However, over the last three years our per-unit operating costs have increased by 25%. 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. (Secondary recovery projects are generally more expensive than primary production. In addition, producing oil is generally more expensive than producing gas. However, oil also generally produces more revenue per Boe than gas.) Higher oil, gas and NGL revenues in 1997 also resulted in higher produc- tion taxes, a component of production and operating expenses. Our future earnings and cash flows are dependent on our ability to continue to contain production and operating costs at levels that allow for profitable production of our oil and gas reserves. RESULTS OF OPERATIONS Devon’s total revenues have risen from $113.3 million in 1995 to $164.0 million in 1996 and $313.1 million in 1997. In each of these years, oil, gas and NGL sales accounted for over 97% of total revenues. Changes in oil, gas and NGL production, prices and revenues from 1995 to 1997 are shown in the table below. (Note: Unless otherwise stated, all references in this discussion to dollar amounts regarding Devon’s Canadian operations are expressed in U.S. dollars.) 26 27 DEVONENERGYCORPORATION TOTAL 1997 1996 Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995 PRODUCTION Oil (MBbls) 7,005 +84% 3,816 +16% 3,300 Gas (MMcf) 69,327 +94% 35,714 -3% 36,886 NGLs (MBbls) 1,626 +71% 952 +59% 600 Oil, Gas and NGLs (MBoe) 20,185 +88% 10,720 +7% 10,047 REVENUES Per Unit of Production: Oil (per Bbl) $ 19.05 -9% 21.00 +25% 16.75 Gas (per Mcf) $ 2.17 +14% 1.91 +38% 1.38 NGLs (per Bbl) $ 13.38 -11% 15.09 +41% 10.68 Oil, Gas and NGLs (per Boe) $ 15.15 — 15.16 +35% 11.19 Absolute (Thousands): Oil $ 133,445 +67% 80,142 +45% 55,290 Gas $ 150,549 +121% 68,049 +34% 50,732 NGLs $ 21,754 +51% 14,367 +124% 6,404 Oil, Gas and NGLs $ 305,748 +88% 162,558 +45% 112,426 1 ”Cash margin“ equals Devon’s total revenues less cash expenses. Cash expenses are all expenses other than the non-cash expenses of deprecia- tion, depletion and amortization and deferred income tax expense. Cash margin is an indicator which is commonly used in the oil and gas industry. This margin measures the net cash which is generated by a company’s operations during a given period, without regard to the period such cash is actually 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 activi- ties determined in accordance with generally accepted accounting principles in analyzing Devon’s results of operations and liquidity.
  27. 27. DOMESTIC 1997 1996 Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995 PRODUCTION Oil (MBbls) 6,055 +59% 3,816 +16% 3,300 Gas (MMcf) 61,015 +71% 35,714 -3% 36,886 NGLs (MBbls) 1,468 +54% 952 +59% 600 Oil, Gas and NGLs (MBoe) 17,692 +65% 10,720 +7% 10,047 REVENUES Per Unit of Production: Oil (per Bbl) $ 19.08 -9% 21.00 +25% 16.75 Gas (per Mcf) $ 2.28 +19% 1.91 +38% 1.38 NGLs (per Bbl) $ 13.18 -13% 15.09 +41% 10.68 Oil, Gas and NGLs (per Boe) $ 15.48 +2% 15.16 +35% 11.19 Absolute (Thousands): Oil $ 115,504 +44% 80,142 +45% 55,290 Gas $ 139,018 +104% 68,049 +34% 50,732 NGLs $ 19,338 +35% 14,367 +124% 6,404 Oil, Gas and NGLs $ 273,860 +68% 162,558 +45% 112,426 CANADA 1997 1996 Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995 PRODUCTION Oil (MBbls) 950 N/A — N/A — Gas (MMcf) 8,312 N/A — N/A — NGLs (MBbls) 158 N/A — N/A — Oil, Gas and NGLs (MBoe) 2,493 N/A — N/A — REVENUES Per Unit of Production: Oil (per Bbl) $ 18.89 N/A — N/A — Gas (per Mcf) $ 1.39 N/A — N/A — NGLs (per Bbl) $ 15.28 N/A — N/A — Oil, Gas and NGLs (per Boe) $ 12.79 N/A — N/A — Absolute (Thousands): Oil $ 17,941 N/A — N/A — Gas $ 11,531 N/A — N/A — NGLs $ 2,416 N/A — N/A — Oil, Gas and NGLs $ 31,888 N/A — N/A — OIL REVENUES 1997 vs. 1996 Oil revenues increased by $53.3 million in 1997. Production gains of 3.2 million barrels added $67.0 million of oil revenues in 1997. This increase was partially offset by a $13.7 million reduction in oil revenues caused by a $1.95 per barrel decrease in the average oil price in 1997. The KMG-NAOS Properties acquired at the end of 1996 were the primary contributors to the increased oil production in 1997. These properties’ 1997 produc- tion totaled 3.1 million barrels. Approximately 2.1 million barrels of such production were in the U.S., while 1 million barrels were produced in Canada. Our other domestic properties produced 3.9 million barrels in 1997. This was an increase of 0.1 million barrels, or 3%, over the 1996 production of 3.8 million barrels. 1996 vs. 1995 Oil revenues increased by $24.9 million in 1996. An increase in the average price of $4.25 per barrel in 1996 added $16.2 million to revenues. Production gains of 516,000 barrels added the remaining $8.7 million of 1996’s increased oil revenues. MD&A
  28. 28. The Grayburg-Jackson Field acquired in 1994 accounted for the majority of 1996’s increased produc- tion. This field produced 1.1 million barrels in 1996, a 37% increase over the 807,000 barrels the field produced in 1995. Production from our other oil prop- erties increased 9% in 1996 to 2.7 million barrels. This is compared to 2.5 million barrels in 1995. GAS REVENUES 1997 vs. 1996 Gas revenues increased by $82.5 million in 1997. An increase in production of 33.6 Bcf added $64.0 million to 1997’s gas revenues. An increase of $0.26 per Mcf in the average price added $18.5 million to 1997’s gas revenues. The KMG-NAOS Properties were responsible for the majority of the increased gas production in 1997. These properties produced 29.8 Bcf in 1997. Approximately 21.5 Bcf of such production was in the U.S., while 8.3 Bcf was produced in Canada. Our coal seam gas properties produced 17.6 Bcf in 1997 compared to 17.4 Bcf in 1996. Devon’s other domestic properties produced 21.9 Bcf in 1997 compared to 18.3 Bcf in 1996. Our coal seam properties averaged $2.13 per Mcf in 1997 compared to $1.72 per Mcf in 1996. The San Juan Basin Transaction added $8.4 million to coal seam gas revenues in 1997 compared to $10.3 million in 1996. The San Juan Basin Transaction increased the average coal seam gas price by $0.48 per Mcf in 1997 and $0.59 per Mcf in 1996. Devon’s domestic conventional gas properties averaged $2.34 per Mcf in 1997 compared to $2.08 per Mcf in 1996. 1996 vs. 1995 Gas revenues increased by $17.3 million in 1996. An increase in the average gas price of $0.53 per Mcf in 1996 added $18.9 million to 1996’s gas revenues. This increase was partially offset by a $1.6 million reduction in gas revenues from a drop in gas production of 1.2 Bcf. Coal seam gas production declined by 16%, from 20.8 Bcf in 1995 to 17.4 Bcf in 1996. However, the average realized coal seam gas price rose by 30% from $1.32 per Mcf in 1995 to $1.72 per Mcf in 1996. Coal seam gas revenues included $10.3 million in 1996 and $12.8 million in 1995 attributable to the San Juan Basin Transaction. This transaction increased the average coal seam gas price by $0.59 per Mcf in 1996 and $0.61 per Mcf in 1995. Total conventional gas production and revenues for 1996 were 18.3 Bcf and $37.9 million, respectively, versus 16.1 Bcf and $23.2 million in 1995. Prices for conventional gas averaged $2.08 per Mcf in 1996 compared to 1995’s average of $1.44. NGL REVENUES 1997 vs. 1996 NGL revenues increased by $7.4 million in 1997. An increase in production of 674,000 barrels added $10.2 million to 1997’s revenues. This increase was partially offset by a $2.8 million reduction in NGL revenues caused by a $1.71 per barrel decrease in 1997’s average price. The majority of the increased NGL production in 1997 was attributable to the KMG-NAOS Proper- ties. These properties produced 339,000 barrels in the U.S. and 158,000 barrels in Canada in 1997. 1996 vs. 1995 NGL revenues increased by $8.0 million in 1996. An increase in average prices of $4.41 per barrel added $4.2 million to the 1996 NGL revenues. The remaining $3.8 million of increased revenues was attributable to increased production of 352,000 barrels in 1996. Additional interests acquired in certain Wyoming properties in December 1995 and the first half of 1996 accounted for 214,000 barrels of the increased production in 1996. These Wyoming proper- ties produced 226,000 barrels in 1996 compared to 12,000 barrels in 1995. Additional drilling in the Sand Dunes area of the Permian Basin increased production from that area from 69,000 barrels in 1995 to 95,000 barrels in 1996. OTHER REVENUES 1997 vs. 1996 Other revenues increased by $5.9 million in 1997. Revenues from processing third party natural gas related to the KMG-NAOS Properties accounted for $3.3 million of the increase. An increase in interest income provided another $1.7 million of the increase in 1997’s other revenues. 1996 vs. 1995 Other revenue increased by $0.6 million in 1996. Increases in gains recognized from the disposal of non-oil and gas fixed assets and from settle- ments of gas contract claims accounted for most of this increase. 28 29 DEVONENERGYCORPORATION
  29. 29. EXPENSES The details of the changes in pre-tax expenses between 1995 and 1997 are shown in the table below. 1997 1996 Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995 ABSOLUTE(Thousands): Production and operating expenses: Lease operating expenses $ 65,655 +108% 31,568 +16% 27,289 Production taxes 17,924 +68% 10,658 +56% 6,832 Depreciation, depletion and amortization of oil and gas properties 82,413 +98% 41,538 +13% 36,640 Subtotal 165,992 +98% 83,764 +18% 70,761 Depreciation and amortization of non-oil and gas properties 2,894 +59% 1,823 +26% 1,450 General and administrative expenses 12,922 +42% 9,101 +8% 8,419 Interest expense 274 -95% 5,277 - 25% 7,051 Distributions on preferred securities of subsidiary trust 9,717 +104% 4,753 N/A — Total $ 191,799 +83% 104,718 +19% 87,681 PER BOE PRODUCED Production and operating expenses: Lease operating expenses $ 3.25 +10% 2.95 +8% 2.72 Production taxes 0.89 -10% 0.99 +46% 0.68 Depreciation, depletion and amortization of oil and gas properties 4.08 +5% 3.88 +6% 3.65 Subtotal 8.22 +5% 7.82 +11% 7.05 Depreciation and amortization of non-oil and gas properties (1) 0.15 -12% 0.17 +21% 0.14 General and administrative expenses (1) 0.64 -25% 0.85 +1% 0.84 Interest expense (1) 0.01 -98% 0.49 - 30% 0.70 Distributions on preferred securities of subsidiary trust (1) 0.48 +9% 0.44 N/A — Total $ 9.50 -3% 9.77 +12% 8.73 (1) Though per Boe general and administrative expenses, interest expense, non-oil and gas property depreciation and distributions 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. MD&A
  30. 30. DEVONENERGYCORPORATION PRODUCTION AND OPERATING EXPENSES The details of the changes in production and operating expenses between 1995 and 1997 are shown in the table below. TOTAL 1997 1996 Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995 ABSOLUTE(Thousands): Recurring lease operating expenses $ 61,658 +118% 28,270 +19% 23,842 Well workover expenses 3,997 +21% 3,298 - 4% 3,447 Production taxes 17,924 +68% 10,658 +56% 6,832 Total production and operating expenses $ 83,579 +98% 42,226 +24% 34,121 PER BOE: Recurring lease operating expenses $ 3.05 +16% 2.64 +11% 2.37 Well workover expenses 0.20 -35% 0.31 - 11% 0.35 Production taxes 0.89 -10% 0.99 +46% 0.68 Total production and operating expenses $ 4.14 +5% 3.94 +16% 3.40 DOMESTIC 1997 1996 Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995 ABSOLUTE(Thousands): Recurring lease operating expenses $ 54,969 +94% 28,270 +19% 23,842 Well workover expenses 3,143 -5% 3,298 - 4% 3,447 Production taxes 17,646 +66% 10,658 +56% 6,832 Total production and operating expenses $ 75,758 +79% 42,226 +24% 34,121 PER BOE: Recurring lease operating expenses $ 3.10 +17% 2.64 +11% 2.37 Well workover expenses 0.18 -42% 0.31 - 11% 0.35 Production taxes 1.00 +1% 0.99 +46% 0.68 Total production and operating expenses $ 4.28 +9% 3.94 +16% 3.40 CANADA 1997 1996 Year Ended December 31, 1997 VS 1996 1996 VS 1995 1995 ABSOLUTE(Thousands): Recurring lease operating expenses $ 6,689 N/A — N/A — Well workover expenses 854 N/A — N/A — Production taxes 278 N/A — N/A — Total production and operating expenses $ 7,821 N/A — N/A — PER BOE: Recurring lease operating expenses $ 2.68 N/A — N/A — Well workover expenses 0.35 N/A — N/A — Production taxes 0.11 N/A — N/A — Total production and operating expenses $ 3.14 N/A — N/A — 30 31
  31. 31. 1997 vs. 1996 Recurring lease operating expenses increased by $33.4 million, or 118%, in 1997. The KMG-NAOS Properties accounted for $26.0 million of the increased expenses. Most of the remaining $7.4 million of 1997’s increase was due to wells which were drilled in 1997 and 1996. Recurring expenses per Boe were up by $0.41 per Boe, or 16%, in 1997. This increase was caused by the reduction in the coal seam gas properties share of total production. The recurring operating costs per Boe for the coal seam gas properties are extremely low ($0.43 per Boe in 1997 and $0.32 per Boe in 1996). However, production from these properties remained relatively flat and production from our other properties increased in 1997. Therefore, the coal seam gas proper- ties percentage of overall production dropped from 27% in 1996 to only 15% in 1997. The result is that a larger percentage of Devon’s production in 1997 was attribut- able to its conventional properties, which have a higher operating cost per Boe than the low-cost coal seam gas properties. The recurring operating costs per Boe for our conventional properties were $3.50 per Boe in 1997 and 1996. Thus, the coal seam properties’ costs rose only $0.11 per Boe in 1997 and the conventional prop- erties’ costs remained flat in 1997. However, since the conventional properties represented a larger percentage of our total production in 1997 compared to 1996 (85% in 1997 compared to 73% in 1996), the result was a $0.41 per Boe increase in the overall rate. Most taxing authorities collect production taxes on a fixed percentage of revenue basis. Therefore, as our revenues have increased, so have production taxes. Production taxes increased 68% from $10.7 million in 1996 to $17.9 million in 1997. This increase was due to the 88% increase in combined oil, gas and NGL revenues in 1997. 1996 vs. 1995 Recurring lease operating expenses increased by $4.4 million, or 19%, in 1996. Approximately $2.7 million of the increase was related to the additional interests acquired in the Worland Properties. We acquired these additional interests in December 1995 and the first half of 1996. Recurring lease operating expenses for the Worland Properties increased from $0.1 million in 1995 to $2.8 million in 1996 after Devon increased its ownership in such prop- erties. Most of the remaining $1.7 million increase was due to the higher number of producing wells in the Grayburg-Jackson Field in 1996 compared to 1995. Recurring expenses per Boe were up by $0.27, or 11%, in 1996 compared to 1995. As explained above in the 1997 vs. 1996 discussion, the increase in the percentage of production attributable to conventional properties is also the cause of the increase in per Boe costs in 1996 compared to 1995. The recurring costs for the coal seam gas properties averaged $0.32 per Boe in 1996 and $0.24 per Boe in 1995. The recurring expenses of our conventional oil and gas properties were $3.50 per Boe in 1996 and 1995. Thus, the coal seam properties’ costs rose only $0.08 per Boe in 1996 and the conventional properties’ costs per Boe remained flat in 1996. However, since the conventional properties represented a larger percentage of our total production in 1996 compared to 1995 (73% in 1996 compared to 65% in 1995), the result was a $0.27 per Boe increase in the overall rate. Production taxes increased 56% from $6.8 million in 1995 to $10.7 million in 1996. This increase was primarily due to the 45% increase in combined oil, gas and NGL revenues. Production taxes per Boe increased by $0.31 per Boe, or 46%, in 1996. This was primarily caused by the increase in the average price per Boe received in 1996. DEPRECIATION, DEPLETION AND AMORTIZATION Devon’s largest non-cash expense is depreciation, depletion and amortization (“DD&A”). DD&A of oil and gas properties is calculated as the percentage of total proved reserve volumes produced during the year, multiplied by the net capitalized investment in those reserves including estimated future development costs (the “depletable base”). Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if capital- ized costs change, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. MD&A
  32. 32. 1997 vs. 1996 Oil and gas property related DD&A increased $40.9 million, or 98%, in 1997. Approximately $36.7 million of this increase was caused by the 88% increase in combined oil, gas and NGL production in 1997. The remaining $4.2 million of increase was caused by a 5% increase in the DD&A rate from $3.88 per Boe in 1996 to $4.08 per Boe in 1997. 1996 vs. 1995 Oil and gas property related DD&A increased by $4.9 million, or 13%, in 1996. Approximately $2.5 million of this increase was caused by a 7% increase in total oil, gas and NGL production in 1996. The remaining $2.4 million increase was caused by a 6% increase in the DD&A rate from $3.65 per Boe in 1995 to $3.88 per Boe in 1996. GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”) 1997 vs. 1996 G&A increased by $3.8 million, or 42%, in 1997. Employee salaries and related overhead costs, including insurance and pension expense, increased by $4.9 million. This increase was primarily related to the additional permanent and temporary personnel added at our Oklahoma City and Calgary offices as a result of the addition of the KMG-NAOS Properties. The expansion in personnel also caused office-related costs such as rent, dues, travel, supplies, telephone, etc., to increase by $1.8 million in 1997. The higher salary, overhead and office costs were partially offset by an increase in Devon’s overhead reimbursements. As the operator of a property, we receive these reimbursements from the property’s working interest owners. Devon records the reimburse- ments as reductions to G&A. Due to the addition of the KMG-NAOS Properties, many of which we operate, our overhead reimbursements increased by $3.7 million in 1997. 1996 vs. 1995 G&A increased by $0.7 million, or 8%, in 1996. Employee salaries and related benefits were $1.1 million higher in 1996. Legal expenses and abandoned acquisition expenses were each $0.2 million higher in 1996. These increases were partially offset by a $0.1 million reduction in franchise tax expense due to our 1995 change of incorporation from Delaware to Oklahoma. Also, Devon saw a $0.7 million increase in G&A reimbursements received from joint interest owners in Devon-operated properties. INTEREST EXPENSE 1997 vs. 1996 Interest expense decreased $5.0 million, or 95%, in 1997. This decrease was caused by a drop in the average debt balance outstanding from $77.0 million in 1996 to $0.7 million in 1997. We issued $149.5 million of 6.5% Trust Convertible Preferred Securities (“TCP Securi- ties”) in July, 1996. The proceeds from this issuance, along with cash flow from operations, were used to retire our long-term bank debt early in 1997. (The TCP Securities are discussed further below.) 1996 vs. 1995 Interest expense decreased by $1.8 million, or 25%, in 1996. Approximately $1.5 million of the lower interest expense was due to a lower average debt balance in 1996. The average debt balance dropped from $97.1 million in 1995 to $77.0 million in 1996. This decrease in average debt outstanding was primarily the result of the issuance of the TCP Securi- ties in July 1996. The remaining $0.3 million of interest expense reduction in 1996 resulted from lower interest rates. The interest rates on the debt outstanding during 1996 averaged 6.3%, compared to 1995’s average rate of 6.5%. The overall interest rate (including the effect of the interest rate swap discussed below, various fees paid to the banks and the amortization of certain loan costs) averaged 6.9% in 1996 and 7.3% in 1995. We entered into an interest rate swap agreement in the second quarter of 1995. We terminated the agreement on July 1, 1996 for a gain of $0.8 million. This gain is being recognized ratably in Devon’s oper- ating results as a reduction to interest expense during the period from July 1, 1996 to June 16, 1998 (the original expiration date of the swap agreement). Approximately $0.2 million of the gain was included in the last half of 1996 as a reduction to interest expense. During the time when the agreement was still in effect, it resulted in $0.1 million of reduced interest expense in the year 1995 and had no effect on interest expense for the first six months of 1996. 32 33 DEVONENERGYCORPORATION
  33. 33. DISTRIBUTIONS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST 1997 vs. 1996 Devon, through its affiliate Devon Financing Trust, completed the issuance of $149.5 million of 6.5% TCP Securities in a private placement in July, 1996. The distributions on the TCP Securities accrue at the rate of 1.625% per quarter. Distributions in 1997 were $9.7 million compared to $4.8 million in 1996. The 1996 distribution total repre- sented slightly less than two quarters’ distributions due to the issuance date occurring in July. (See Note 9 to the consolidated financial statements included else- where in this report for a detailed discussion of Devon’s TCP Securities.) 1996 vs. 1995 The TCP Securities were issued in July, 1996. The 1996 distributions of $4.8 million represented slightly less than two quarters’ distributions due to the issuance date occurring in July. INCOME TAXES 1997 vs. 1996 Our effective financial tax rate in 1997 was 38% compared to 41% in 1996. Both rates were above the statutory federal tax rate of 35% due to state income taxes, and certain tax aspects of the San Juan Basin Transaction and a 1994 merger. Also, the 1997 rate was affected by certain tax aspects of the KMG-NAOS transaction and by Cana- dian income taxes which accrue at rates higher than the U.S. statutory rate of 35%. (The effective financial income tax rate for our Canadian operations was 43% in 1997.) 1996 vs. 1995 Our effective financial tax rate in 1996 was 41% compared to 1995’s rate of 43%. Both rates were above the federal statutory rate of 35% due to the effect of the state taxes, San Juan Basin Transaction and 1994 merger noted in the above paragraph. CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY The following discussion of capital expenditures, capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in this report. CAPITAL EXPENDITURES Approximately $130.5 million of cash was spent in 1997 for capital expendi- tures, of which $124.6 million was related to the acqui- sition, drilling or development of oil and gas properties. Most of the drilling and development efforts in 1997 centered in the Permian Basin, which included 174 of the 295 oil and gas wells that we drilled during the year. OTHER CASH USES We began paying a quarterly dividend on our common stock in the second quarter of 1993 at the rate of $0.03 per share. In the fourth quarter of 1996, the quarterly dividend rate was increased to $0.05 per share. Quarterly dividends in 1997 were also paid at the rate of $0.05 per share. CAPITAL RESOURCES AND LIQUIDITY Net cash provided by operating activities (“operating cash flow”) was the primary source of capital and short-term liquidity in 1997. Operating cash flow in 1997 totaled $168.7 million compared to $86.8 million in 1996. This resulted in a 94% increase. In addition to operating cash flow, our credit lines have historically been an important source of capital and liquidity. However, 1997’s increased oper- ating cash flow allowed Devon to fund its 1997 capital expenditures and other cash uses without borrowing against its credit lines. At the end of 1997, we had $208 million of long-term credit lines, all of which was available for future use. Also, we have a $12.5 million Canadian dollars demand facility for our Canadian operations. All of this Canadian facility was also avail- able at the end of 1997 for future use. (See Note 7 to the consolidated financial statements included else- where in this report for a detailed discussion of Devon’s credit lines.) MD&A
  34. 34. 1998 ESTIMATES The forward-looking statements provided in this discussion are based on management’s examination of historical operating trends, the December 31, 1997 reserve reports of independent petroleum engineers and other data in Devon’s possession or available from third parties. We caution that our future oil, gas and NGL production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development and production and sale of oil and gas. These risks include, but are not limited to, price volatility, inflation or lack of avail- ability of goods and services, environmental risks, drilling risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks as outlined below. Also, the financial results for our Canadian operations, obtained in the KMG-NAOS transaction, are subject to currency exchange rate risks. Additional risks are discussed below in the context of line items most affected by such risks. Specific Assumptions and Risks Related to Price and Production Estimates Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and world-wide economic growth, weather and other substantially variable factors. These factors are beyond our control and are difficult to predict. In addition to volatility in general, Devon’s oil, gas and NGL prices may vary considerably due to differences between regional markets and demand for different grades of oil, gas and NGLs. Over 90% of Devon’s revenues are attributable to sales of these three commodities. Consequently, our financial results and resources are highly influenced by this price volatility. Estimates for Devon’s future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil and gas will continue at levels that allow for profitable production of these products. There can be no assurance of such stability. Certain of Devon’s individual oil and gas proper- ties are sufficiently significant as to have a material impact on the company’s overall financial results. With respect to oil production, these properties include the West Red Lake Field and the Grayburg-Jackson Unit, both in southeast New Mexico. Our interest in NEBU and the 32-9 Unit can have a significant effect on overall gas production. The production, transportation and marketing of oil, natural gas and NGLs are complex processes which are subject to disruption due to transportation and processing availability, mechanical failure, human error, meteorological events and numerous other factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for our oil, natural gas and NGLs for 1998 will be substantially similar to those of 1997, unless otherwise noted. Given the general limitations expressed herein, our forward- looking statements for 1998 are set forth below. OIL PRODUCTION AND RELATIVE PRICES Devon expects its oil production in 1998 to total between 6.3 million barrels and 7.3 million barrels. We expect our net oil prices per barrel will average from between $0.20 to $0.45 above West Texas Intermediate posted prices in 1998. GAS PRODUCTION AND RELATIVE PRICES We expect our total gas production in 1998 will be between 67.0 Bcf and 78.5 Bcf. It is expected that coal seam gas production will be between 19.0 Bcf and 22.2 Bcf. Canadian production in 1998 is estimated to be between 6.8 Bcf and 8.0 Bcf. We expect production from the remainder of our gas properties to total between 41.2 Bcf and 48.3 Bcf. Devon expects its 1998 coal seam average price will be between $0.25 and $0.55 per Mcf less than Texas Gulf Coast spot averages. This includes an expected $0.40 to $0.45 per Mcf from the San Juan Basin Transaction. Our Canadian gas production is expected to average from between $0.80 to $1.05 less than Texas Gulf Coast spot averages. (These Canadian differentials are expressed in U.S. dollars, using the year-end 1997 exchange rate of $0.70 U.S. dollar to $1.00 Canadian dollar.) Devon’s remaining gas produc- tion is expected to average $0.05 to $0.25 less than Texas Gulf Coast spot averages during 1998. We had made firm commitments to sell approxi- mately 12,700 Mcf per day of our coal seam gas production throughout 1998 at a fixed price of approxi- mately $1.45 per Mcf, which equates to a price of approximately $2.04 per MMBtu. (The $1.45 per Mcf price includes the effect of adjusting for Btu content 34 35 DEVONENERGYCORPORATION
  35. 35. and is net of costs for transportation and removing carbon dioxide. This price excludes the expected $0.40 to $0.45 per Mcf benefit from the San Juan Basin Transaction.) The effect of these fixed price commit- ments has been included in the expected differential for coal seam gas discussed in the above paragraph. We have also made other commitments to sell certain quan- tities of our 1998 domestic conventional and Canadian gas production at fixed prices. However, such commit- ments to date are not expected to have a material effect on our 1998 gas price differentials due to the limited quantities of gas per day involved. NGL PRODUCTION We expect our production of NGLs in 1998 to total between 1.3 million barrels and 1.5 million barrels. PRODUCTION AND OPERATING EXPENSES Our production and operating expenses vary in response to several factors. Among the most significant of these factors are additions or deletions to our property base and changes in production taxes. Other significant factors are general changes in the prices of services and materials that are used in the operation of our proper- ties and the amount of repair and workover activity required on those properties. Oil, gas and NGL prices will have a direct effect on production taxes to be incurred in 1998. Future prices could 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 uncertainty inherent in estimating future production and operating costs. Given these uncertainties, Devon estimates that 1998’s total production and operating costs will be between $78.0 million and $90.5 million. DEPRECIATION, DEPLETION AND AMORTIZATION The 1998 DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that could be added from drilling or acquisition efforts in 1998 compared to the costs incurred for such efforts. Another notable factor is the revisions to our year-end 1997 reserve estimates which will be made during 1998. The DD&A rate as of the beginning of 1998 was $4.08 per Boe. Assuming a 1998 rate of between $4.10 per Boe and $4.45 per Boe, 1998 oil and gas property related DD&A expense is expected to be $85 million to $93 million. Additionally, we expect our non-oil and gas property related DD&A to total between $3 million and $4 million in 1998. GENERAL AND ADMINISTRATIVE EXPENSES Devon’s general and administrative expenses include the costs of many different goods and services used in support of the company’s business. These goods and services are subject to general price level increases or decreases. In addition, our G&A expenses vary with our level of activity and the related staffing needs. G&A expenses are also affected by the amount of professional services required during any given period. Should our anticipated needs or the prices of the required goods and services differ significantly from our expectations, actual G&A expenses could vary materi- ally from the estimate. Given these limitations, G&A expenses are expected to be between $13 million and $15 million in 1998. INTEREST EXPENSE Devon’s management expects to fund substantially all of its anticipated expenditures during 1998 with working capital and internally generated cash flow. Should our actual capital expenditures or internally generated cash flow vary significantly from expectations, interest expense could differ materially from the following estimate. Given this limitation, interest expense is expected to be less than $1 million in 1998. DISTRIBUTIONS ON TCP SECURITIES TCP Secu- rities are convertible into common shares of Devon at the option of the holder. Any conversions of the TCP Securities would reduce the amount of required distrib- utions. Assuming all $149.5 million of TCP Securities are outstanding for the entire year, we will make $9.7 million of distributions in 1998. MD&A
  36. 36. INCOME TAXES We expect our financial income tax rate in 1998 to be between 34% and 38%. Regard- less of the level of pre-tax earnings reported for financial purposes, we will have a minimum of approxi- mately $2.0 million of financial income tax expense. This results from various aspects of the 1994 Alta merger, the San Juan Basin Transaction and the KMG- NAOS acquisition. Therefore, if the actual amount of 1998 pre-tax earnings differs materially from what Devon currently expects, the actual financial income tax rate for 1998 could differ from the expected rate of 34% to 38%. Also, based on our current expectations of 1998 taxable income, we anticipate our current portion of 1998 income taxes will be between $12 million and $17 million. However, unanticipated revenue and earn- ings fluctuations could easily make these tax estimates inaccurate. CAPITAL EXPENDITURES Our capital expendi- tures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected costs of the capital additions. Should our price expecta- tions for our future production change significantly, we may accelerate or defer some projects. Thus, we may increase or decrease total 1998 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. Though Devon has completed several major property transactions in recent years, these transactions are opportunity driven. Thus, we do not “budget,” nor can we reasonably predict, the timing or size of such possible acquisitions, if any. Given these limitations, we expect our 1998 capital expenditures for drilling and development efforts to total between $140 million and $160 million, including $8 million to $12 million in Canada. (Cana- dian amounts are expressed in U.S. dollars, using the year-end 1997 exchange rate of $0.70 U.S. dollar to $1.00 Canadian dollar.) We expect to spend $45 million to $60 million in 1998 for drilling, facilities and waterflood costs related to reserves classified as proved as of year-end 1997. Devon also plans to spend another $60 million to $70 million on new, higher risk/reward projects. OTHER CASH USES Devon’s management expects the policy of paying a quarterly dividend to continue. With the current $0.05 per share quarterly dividend rate and 32.3 million shares of common stock outstanding, 1998 dividends are expected to approxi- mate $6.5 million. CAPITAL RESOURCES AND LIQUIDITY The estimated future drilling and development activities are expected to be funded through a combination of working capital and net cash provided by operations. The amount of net cash to be provided by operating activities in 1998 is uncertain due to the factors affecting revenues and expenses cited above. However, we expect that our capital resources will be more than adequate to fund our anticipated capital expenditures. Based on the expected level of 1998’s capital expenditures and net cash provided by operations, we do not expect to rely on our existing credit lines to fund a material portion of our capital expenditures. However, if significant acquisitions or other unplanned capital requirements arise during the year, we could utilize our existing credit lines and/or seek to establish and utilize other sources of financing. The unused portion of existing credit lines at the end of 1997 consisted of $208 million of long-term credit facilities, and a $12.5 million Canadian dollars demand facility for our Canadian operations. If so desired, we believe that our lenders would increase our credit lines to at least $450 million to $500 million. However, Devon does not desire nor anticipate a need to increase its credit lines above their current levels. POTENTIAL REDUCTION IN CARRYING VALUE OF OIL AND GAS PROPERTIES Under the full cost method of accounting, the net book value of oil and gas proper- ties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The net book value is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value above the ceiling is written off as an expense. 36 37 DEVONENERGYCORPORATION

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