Hide Notes 

Slide 2: he story of Fort Worth is the story of a rambunctious southwestern town which evolved from a frontier Army post into one of the most modern cities in the nation. The area has always been blessed geographically, economically and culturally, but its fundamental character was formed by an impressive parade of individuals, many with strong personalities almost larger than life. They worked hard, dreamed big, and were unabashedly proud to be Texans and call Fort Worth their home. We, too, are proud of Fort Worth and its character, and we dedicate this annual report to the men and women, visionaries and laborers, desperadoes and lawmen, tradespeople and professionals, merchants and philanthropists who helped build our community. They brought the cattle, the railroad, the oil business, the military and aviation industries, as well as an eclectic variety of entertainment and arts venues to the city that is home to Cross Timbers Oil Company. Our Company is named after the ancient forests called the Cross Timbers, woodlands of post oak and blackjack oak which mark the eastern margin of the southern Great Plains from North Central Texas through Oklahoma to southeastern Kansas. The Cross Timbers played an important part in our local history, drawing Indians and Fort Worth’s early settlers alike toward its protection and bountiful natural resources. Company Profile Cross Timbers Oil Company, established in 1986, is engaged in the acquisition and development of quality, long-lived producing oil and gas properties and exploration for oil and gas. Since going public in 1993, proved oil and gas reserves have grown at an annual compound growth rate of 41% to more than 1.6 trillion cubic feet. Cross Timbers operates 87% of its properties, which are concentrated in Texas, Oklahoma, Kansas, New Mexico, Wyoming, and Alaska. The Company completed its initial public offering in May 1993 and is listed on the New York Stock Exchange under the symbol “XTO.” It also created the Cross Timbers Royalty Trust (“CRT” traded on the NYSE) which went public in 1992.
Slide 3: Cross Timbers Oil Company FINANCIAL HIGHLIGHTS In thousands except production, per share and per unit data 1998 $ 249,486 $ (105,570)(a) $ (71,498)(a) $ (1.65)(a) $ (1.65)(a) $ 78,480 $ 1.81 $ 1,207,594 $ 615,000 $ 306,000 $ 177,451 44,727 1997 $ 0198,272 $ 0039,201 $ 0023,905 $ 00000.60 $ 00000.59 $ 0089,979 $ 00002.26 $ 0788,455 $ 0239,000 $ 0300,000 $ 0170,243 39,450 1996 $ 0161,335 $ 0(30,973 $ 19,790 $ 00000.50 $ 00000.48 $ 0068,263 $ 00001.71 $ 0523,070 $ 0285,000 $ 0029,757 $ 0142,668 38,447 Financial Total revenues Income (loss) before income tax Earnings (loss) available to common stock Per common share (b) Basic Diluted Operating cash flow (c) Operating cash flow per share (b) Total assets Long-term debt Senior Subordinated notes and other Total stockholders’ equity Common shares outstanding at year-end (b) Production Daily production Oil (Bbls) Gas (Mcf) Natural gas liquids (Bbls) Mcfe Average price Oil (per Bbl) Gas (per Mcf) Natural gas liquids (per Bbl) Proved Reserves Oil (Bbls) Gas (Mcf) Natural gas liquids (Bbls) Mcfe (b) Adjusted for the three-for-two stock splits effected on March 19, 1997 and February 25, 1998. (c) Cash provided by operating activities before changes in current assets and liabilities. 12,598 229,717 3,347 325,390 $000012.21 $000002.07 $000007.62 54,510 1,209,224 17,174 1,639,331 10,905 135,855 220 202,609 $ 00018.90 $ 00002.20 $ 00009.66 47,854 815,775 13,810 1,185,759 9,584 101,845 – 159,349 $ 00021.38 $ 00001.97 – 42,440 540,538 – 795,178 (a) Includes effect of a $93.7 million pre-tax net loss on investment in equity securities and a $2 million pre-tax, non-cash impairment charge. Total Revenues Operating Cash Flow Daily Production Proved Reserves Glossary Bbls Bcf Bcfe BOE E&P Mcf Mcfe Barrels (of oil or NGLs) Billion cubic feet (of gas) Billion cubic feet equivalent Barrels of oil equivalent Exploration & production Thousand cubic feet (of gas) Thousand cubic feet equivalent MMcfe NGLs Tcf Tcfe Million cubic feet equivalent Natural gas liquids Trillion cubic feet (of gas) Trillion cubic feet equivalent One barrel of oil is the energy equivalent of six Mcf of natural gas. 1 5
Slide 4: Cross Timbers Oil Company TO OUR SHAREHOLDERS s a result of a highly successful acquisition program during 1997 and 1998, Cross Timbers was on course to achieve its aggressive goals for 1999. We exceeded our reserves per share goal of 36 thousand cubic feet of gas equivalent (Mcfe) well ahead of schedule. Our cash flow per share goal, however, was based upon $18.00 per barrel of oil and $2.20 per thousand cubic feet of gas (Mcf). Given an industry environment with prices below those levels, we do not expect to meet our 1999 cash flow per share goal. However, we exited 1998 with record production of 275,000 Mcf per day and 19,000 barrels of liquids per day. Moreover, we achieved record reserves of 1.639 trillion cubic feet of gas equivalent, up 38% from year-end 1997, and our 1998 drill-bit finding cost was a stellar $0.48 per Mcfe, despite low oil prices at year end. The importance of our acquisition strategy of buying high-quality, long-lived producing properties is apparent during these adverse times. The Company maintains good cash margins even in a poor commodity price environment. Our cash margin for the fourth quarter of 1998 was $0.59 per Mcfe, which compares favorably to our five-year average drill-bit replacement cost of $0.43. Therefore, we can more than replace our reserves with cash flow during this low price environment and prepare for the inevitable return to normalized prices. In addition, our general and administrative expense of about $0.10 per Mcfe is one of the lowest of our peers and has allowed us to retain our highly skilled employees while other companies are forced to reduce staff. While we had our most successful year in acquisitions and posted exceptional development results in 1998, our financial results were impacted by our decision last summer to invest about $150 million in the equity securities of other energy companies. During that time we could purchase reserves underlying these securities at a lower price per Mcfe than in the property acquisition market. The decision to buy undervalued reserves through stock purchases and resell at higher prices is one we’ve successfully implemented on numerous occasions during the past 20 years. These 1998 stock purchases, however, proved to be ill-timed and resulted in a year-end accounting loss of about two-thirds of our investment. We plan to sell these securities during 1999 and are optimistic that we can sell at higher than year-end prices. Given the market’s diversion of attention from our acquisition and development successes, we do not plan to invest in the securities of other companies in this way in the future. Our goal during 1999 is to re-achieve our long-standing debt goal of $0.40 to $0.45 per Mcfe from $0.56 per Mcfe at year-end 1998. We plan to achieve this goal through the sale of Hugoton Royalty Trust EXPLORATION AND DEVELOPMENT An aggressive 1998 development program resulted in the drilling of 150 wells (142 gas, eight oil), the completion of 250 workovers (220 gas, 30 oil), and the replacement of 137% of production at a cost of just $0.48 per Mcfe. Most of our natural gas activity occurred in East ACQUISITIONS Our acquisitions during the past two years – totaling nearly $600 million – are the best in our 13-year history and continue to exceed expectations. In 1998, we completed significant acquisitions in the East Texas Basin, Alaska’s Cook Inlet, northwest Oklahoma and the San Juan Basin at a total cost of $340 million. These properties fulfill every criteria of our acquisition philosophy. With less than one year of hands-on operation, it already appears that our initial expectations for enhancing reserves were conservative. In particular, the East Texas acquisition has the potential for us to double the reserves acquired over time. Our 12 million BOE Alaskan Cook Inlet acquisition – which increased our oil production by 30% – has a very large original-oil-in-place and complex geology. These attributes typically result in large increases in proved reserves as our technical staff finds the keys to unlocking the reserves. units as well as the anticipated sale of units of an additional royalty trust formed later this year. We plan to fund strategic acquisitions, should they arise, with property sales or equity. Subsequent to the Hugoton Royalty Trust, we will consider forming two additional royalty trusts, one for the San Juan Basin area and one for the Permian Basin area. We could then sell a portion of each trust during the next 6 to 12 months, depending on commodity prices and market conditions. By decreasing our leverage this year, we can position the Company for continued growth through acquisitions and development in future years. Recent mergers of major and independent oil and gas producers should result in substantial domestic producing property dispositions. We plan to take advantage of what we believe will be unprecedented acquisition opportunities in 2000. Our philosophy of acquiring long-lived, high-quality properties and increasing reserves through development will remain unchanged. In this light, the success of the Hugoton Royalty Trust offering adds a new dimension to our capital structure. After our development efforts improve production and reserves – on average 50% – we believe our properties have the attributes to make excellent royalty trusts. We can therefore harvest our value-added activities at high capitalization rates that have the effect of an equity infusion as well as redeploy the proceeds into new properties with more upside potential. 2
Slide 5: Cross Timbers Oil Company TO OUR SHAREHOLDERS Texas, the San Juan Basin, the Fontenelle Unit of southwestern Wyoming and the Ozona area of West Texas. Our oil development was focused on the University Block 9 Field of West Texas, where wells tested at production rates as high as 1,000 Bbls per day. In East Texas, where we initially expected to drill about 50 development wells and to implement 30 workover projects, we have now identified as many as 170 development wells and 300 workover and recompletion opportunities. During the next few years, these identified projects have the potential of increasing the reserves acquired by as much as 75% above the 232 Bcfe purchased. Over time we expect our development efforts to double the reserves acquired. In the San Juan Basin, we have identified as many as 300 development well locations and 100 recompletion opportunities with the potential to increase the reserves acquired by 30% above the 300 Bcfe purchased. We anticipate ongoing studies will continue to result in added reserves. We have set our 1999 exploration and development budget at $60 million. This budget may be revised, depending on commodity prices, but we are determined to increase reserves and keep production flat on an Mcfe basis, exclusive of property sales. During 1999, we plan to drill or participate in the drilling of about 100 wells and implement about 250 workover and recompletion activities. Natural gas projects, now offering the highest rates of return, will be the primary focus of this year’s capital budget. If oil prices continue to strengthen, we will shift a portion of the budget to high impact projects in the University Block 9 and Prentice fields of West Texas. Exploration activities will be minimal with the primary emphasis in the Hugoton area and several exploration test wells in East Texas and central Oklahoma. Longer term, our existing property base offers opportunities for 3-D seismic and geologic mapping for additional exploration. Bob R. Simpson FINANCIAL RESULTS For the year 1998, the Company reported a loss to common shareholders of $71.5 million, or $1.65 per share, compared with earnings of $23.9 million or 60 cents per share in 1997 (adjusted for the three-for-two stock split in February 1998). Without the $61.9 million after-tax loss related to the Company’s investment in equity securities and the $1.3 million after-tax impairment write-off of producing properties, the Company would have reported a loss of only 19 cents per common share. Total revenues for 1998 were $249.5 million, a 26% increase from revenues of $198.3 million for 1997. Cash flow from operations for 1998 was $78.5 million, or $1.81 per share, compared to $90 million, or $2.26 per share for 1997. March 31, 1999 Steffen E. Palko OUTLOOK Obviously, predicting the timing of an industry upturn is risky at best, with so many diverse global elements – economic recovery, political stability, nontraditional weather patterns – involved in the current equation. This has been the longest downturn seen in our 28-year careers. Several observations are in order: We believe our nation’s vulnerability to disruptions in imported supplies is being viewed with considerable complacency. Historic levels of U.S. crude oil inventories, represented as a number of days of U.S. consumption, has dropped from 29.1 days in the 1981-1985 period, to barely 22.4 days in March 1999. That is near the 20-year low. Moreover, U.S. oil production is at a 50-year low in terms of volume, and with low reinvestment rates that volume will continue to slip away. The recent OPEC action to further reduce production is very encouraging and has already had a positive impact on oil prices. We expect oil prices to be surprisingly strong as inventories decline. The case for gas is even more optimistic. The high decline rates in the Gulf of Mexico in conjunction with reduced drilling – rig utilization is at or near historic lows – have prompted many analysts to call for a shortage of natural gas as early as next winter. Cross Timbers will concentrate on reducing debt during 1999. Importantly, our high-quality reserve base and low finding costs will allow us to replace production and prepare for future growth. We will then be in position to take advantage of what we believe will be unprecedented acquisition opportunities during 2000 and beyond. Thank you for your ongoing support. Chairman and Chief Executive Officer Vice Chairman and President 3
Slide 6: The Fort Fort Worth first appeared on the map as a remote Army outpost, established in 1849 as part of a chain of forts intended to protect Texas settlers from sporadic Indian raids. Major Ripley Arnold and his scouting party chose a bend in the West Fork of the Trinity River as the first site, but after a summer flood he moved the fort to a bluff overlooking the river. Fort Worth was named after one of Arnold’s commanders, General William Jenkins Worth, who had died of cholera. Later that same year, Tarrant County, named for state legislator and Indian fighter General Edward H. Tarrant, was established. After the army abandoned the fort in 1853, local settlers moved in and quickly transformed its buildings into homes and businesses. Fort Worth was designated county seat in 1860, and construction of the first courthouse was begun on this site. The Civil War delayed construction, and a fire in 1876 destroyed the completed courthouse, but it was rebuilt and expanded until in 1893 county commissioners decided to build a new, larger building to accommodate the area’s rapid growth. Over the years, the courthouse on the bluff has outlasted several attempts to replace it with a more modern building. Facing south on Main Street and overlooking the Trinity to the north toward the historic Stockyards, the Tarranty County Courthouse has remained the focal point of downtown Fort Worth. Thanks to periodic updating, restoration and renovation, it still serves the citizens of Tarrant County. 4
Slide 7: Cross Timbers Oil Company OPERATIONS REVIEW ross Timbers’ strategy for enhancing shareholder value – to identify, acquire and consistently develop long-lived producing properties with high economic upside potential – is resoundingly reflected in the numerous acquisition and development successes achieved in 1998. To achieve our strategy, we strive to operate a high percentage of properties, to lower field operating costs while increasing production volumes and to deploy talented professionals to apply the latest technological advancements for finding, developing and producing more reserves from existing properties. Often flexible and sound management can help control the timing and nature of capital spending to improve and expand production results during sharp shifts in commodity prices. However, success still begins by making quality acquisitions. ACQUISITIONS Less than two years ago, management set a goal to complete strategic property acquisitions totaling more than $260 million by the end of 1999. Since May 1997, the Company has purchased $560 million in quality properties, creating new core operating areas in the San Juan Basin and East Texas while making significant additions to its franchise operations in Oklahoma. East Texas Basin In April 1998, Cross Timbers completed its largest acquisition to date, purchasing proved reserves of 232 billion cubic feet of gas equivalent (Bcfe) on 88,000 gross (59,000 net) acres in the East Texas Basin. This $215 million purchase from EEX Corporation, effective January 1, 1998, included 784 gross (638 operated) wells in eight fields stretching into Louisiana. Gas reserves accounted for 97% of the value of the acquisition. During August, Cross Timbers acquired an additional 50% interest in the Willow Springs Field for $23.6 million, further strengthening Fontenelle our portfolio of East Texas properties. At the Area time of acquisition, the interests had proved reserves of 19 Bcfe and production of 4.1 million cubic feet per day. Importantly, they constitute additional interests in the operated properties purchased earlier from EEX Corporation. The seller had the right under the operating agreements to prevent development of these properties, which required us to conservatively book the reserves. Our engineers believe these properties have substantial additional potential and this purchase increased our working interest in almost all our wells in this field to 100%, allowing for accelerated development. These two timely acquisitions added high-margin production from a geographically concentrated reserve base with complex geology and Summary of multiple pay zones. Proved Reserves by Area While Cross SEC Assumptions – December 31, 1998 Timbers typically (in thousands) Proved Reserves Discounted increases reserves Natural Gas Present Value before Liquids Income Tax of Proved on its acquisitions Area Oil (Bbls) Gas (Mcf) (Bbls) Reserves Texas 2,127 317,947 – $234,825 25.8% by 50% to 60% over East Juan Basin San 1,199 253,568 17,174 170,868 18.8% Mid-Continent 4,495 189,374 – 163,282 18.0% what was originally Permian Basin 32,295 95,356 – 116,816 12.9% evaluated, these Rocky Mountain 2,481 183,830 – 110,390 12.1% Hugoton 232 159,128 – 89,745 9.9% properties have the Alaska Cook Inlet 11,437 – – 12,719 1.4% potential for a Other (a) ,244 10,021 – 9,961 1.1% doubling of Total 54,510 1,209,224 17,174 $908,606 100.0% reserves. (a) Includes 209,000 Bbls and 8,278,000 Mcf and discounted present value before income tax of $8,109,000 related to the Company’s 22% ownerThe Company ship of Cross Timbers Royalty Trust Units at December 31, 1998. wasted no time in elevating production and probing long-term potential. By adding compression, testing different stimulation techniques, recompleting wells into additional horizons and pursuing field extensions, the Company has identified significant, previously unrecognized upside value. In the past eight months, Cross Timbers has already increased net daily gas production from 80 million cubic feet equivalent to 95 million cubic feet equivalent. Alaskan Cook Inlet In October, Cross Timbers acquired a 100% working interest (87.5% net revenue interest) in two State of Alaska leases, two operated production platforms and a 50% interest in certain operated production pipelines and onshore processing facilities from Shell Oil Company affiliates. The platforms, located in 70 feet of water, are approximately seven miles offshore in the Middle Ground Shoal Field. They contain 29 producing wells and 11 water injection wells. At the time of acquisition, estimated proved reserves were 12 million barrels of oil with net production of 3,700 barrels per day. Production is primarily from multiple zones within the Tyonek Formation between 7,300 feet and 10,000 feet subsea with an estimated reserve-toproduction index of nine years. San Juan Basin Hugoton Area Major County Prentice N.E. Russell University Block 9 East Texas Basin MAJOR PRODUCING AREAS 5
Slide 8: Cowtown After the Civil War, Fort Worth was depleted in spirit and substance. In the early 1870s, the once-booming town had shrunk to only a few hundred people. There was one “ace-in-the-hole,” however, and that was the city’s location along the cattle trails, particularly the famous Chisholm Trail, that took livestock from South Texas to railheads in Kansas for shipment to northern markets where the demand for beef was great. The cowboys who drove the herds became a breed unto themselves. Fort Worth welcomed these tough, hard-working, independent characters who came to town eager for a break from the hardship and danger of the long trail drives. Fort Worth was the last place they could replenish supplies before continuing north, and the first stop on their way back. So the town entertained them with all the diversions they had time and money for, including drink, gambling and the company of certain ladies. The trail drives provided economic stability for Fort Worth, and other businesses emerged to support the needs of West Texas ranchers. Valuable ties between merchants and ranchers were forged which continue to the present time. Burgeoning prosperity meant more of everything — churches, schools, doctors, lawyers, bankers, and even the occasional newspaper. A growing network of holding pens and other facilities for livestock would eventually take up many acres north of the Trinity and downtown Fort Worth. These stockyards were located far enough north to keep most of the odor of cattle, hogs, sheep, mules and horses away from the general population, yet close enough to town for the cowboys to enjoy themselves. 6
Slide 9: The Middle Ground Shoal Field, first discovered in 1962, began producing in 1966. To stimulate production, waterflood operations were initiated in 1968 on the east flank of the field. Further, in 1997 a successful pilot waterflood was initated on the west flank of the field, paving the way for future expansion of secondary recovery operations. While our acquisition marked Shell’s departure from Alaska, Cross Timbers was able to retain experienced personnel by hiring almost all of the Shell employees associated with the Alaskan operations. Currently Cross Timbers is one of only three companies operating the 15 platforms in Cook Inlet. Cook Inlet The Company aims to improve the properties in four ways: • expanding waterflood operations where tests have proved promising on the west flank; • converting from gas lift to hydraulic or electrical submersible pumps; • reducing operating costs with automation and offshore separation; and • utilizing a redefined geologic model to determine potential drilling opportunities. San Juan Basin and Northwest Oklahoma In November, Cross Timbers expanded its franchise operations in the San Juan Basin of New Mexico and in northwest Oklahoma by purchasing producing properties from Seagull Energy Corporation for $29.2 million. The transaction included proved reserves of 42.5 Bcfe. The San Juan properties, when combined with non-operated properties in the basin purchased from Amoco in late 1997, form an attractive disposition package, and are part of a pending property sale pursuant to our debt reduction plan. The northwest Oklahoma properties, located in Major and Woodward counties, consist of 171 gross (60 net) wells of which 75 gross (48 net) wells are operated by Cross Timbers. Production at acquisition was about six million cubic feet of gas equivalent per day, primarily from the Morrow, Chester, Mississippian and Hunton formations between 6,000 and 9,000 feet. Most of these properties are included in the Hugoton Royalty Trust. EXPLORATION AND DEVELOPMENT In 1998, Cross Timbers implemented its most successful development plan to date, completing 250 workovers and drilling 150 wells. Due to weakening oil prices and fairly stable gas prices, the program focused on development of the Company’s extensive gas properties. In fact, more than 90% of the completed projects were located in gas provinces. The workover program, the largest in Company history, was highlighted by excellent results in the newly acquired East Texas and San Juan Basin properties, where 65% of the program was implemented. Of the 150 wells drilled, 142 targeted gas reserves. The primary areas of drilling activity were the Fontenelle Unit in southwestern Wyoming (20 wells), the Ozona area in West Texas (21 wells), the Major County area of Oklahoma (18 wells), the Hugoton area of Oklahoma and Kansas (15 wells), the San Juan Basin of New Mexico (48 wells), and the East Texas Basin (10 wells). The workover portion of the budget was greatly enhanced by the addition of the East Texas properties. East Texas workovers result in rates and reserves comparable to development drilling in many areas, but at a much lower cost. Development of oil reserves was concentrated in the University Block 9 Field located in the Permian Basin of West Texas. The objective was to further test the effectiveness of horizontal sidetracks out of existing wells. This decreases capital expenditures and enhances the economics of oil projects. Four vertical wells, one horizontal well and three horizontal sidetrack wells were drilled. All were highly successful. Significant production increases were achieved through the acquisitions and development program, with the 1998 exit rates at a record 275 million cubic feet of gas per day and a record 19,000 barrels of liquids per day. The Company spent about $78 million for exploration and development activities, replacing 137% of its production at a cost of $0.48 per Mcfe. This is quite an achievement in the face of the worst oil prices in a decade. The 1999 exploration and development budget is set at $60 million. This budget will again focus on gas projects with limited spending on oil projects to further delineate and replenish the drilling inventory until oil prices are more favorable. If oil prices continue to strengthen, we can Cook Inlet expand the capital budget to include high impact projects in the University Block 9 and Prentice fields. The Company expects to drill or participate in drilling 100 wells and plans to implement 250 workover and recompletion activities. These activities will allow Cross Timbers to maintain its record daily production rates on an Mcfe basis. Exploration drilling during the past year focused on the Hugoton area. Going forward, 3-D seismic shot in the Hugoton area, as well as the acquisition of leases and seismic data in the Nemeha Ridge area of central Oklahoma, indicate promising results. For 1999, exploration activities will be minimal, focusing on lease acquisitions over identified prospects and the drilling of several exploration test wells in East Texas and central Oklahoma. Cross section view of the Middle Ground Shoal structure. 7
Slide 10: The Railroad Beginning in 1871, rumors circulated that the railroad would find its way to Fort Worth. In 1873, a civic leader and newspaper editor named B.B. Paddock created a map of what Fort Worth would look like with railways projecting from it like the legs of a spider, and it came to be known as the Tarantula Map. Amazingly, the railroads Paddock envisioned actually were established one by one. The first railroad train, the Texas & Pacific, arrived in Fort Worth in 1876, an event which only increased the already bustling atmosphere of the city, and the first train station at Lancaster and South Main was built a few months later. With the coming of the railroad, Fort Worth became known as a place where money could be made, a boom town in earnest, with newcomers from all over the country buying, selling, trading, gambling, or mixing with the cowboys at the numerous saloons which seemed to open overnight. After the raucous ‘70s, Fort Worth settled into becoming a more structured, socially responsible society in the ‘80s. Expansion of the railroad increased shipping opportunities for cattle as well as other products, and the great trail drives dwindled. Local businessmen began to increase their efforts to find a way to pack meat for northern and eastern markets rather than transport it on the hoof. In 1901, Chicago’s Armour & Co. and Swift & Co. opened meat-packing plants in the stockyards, the second largest stockyards in the country. Soon they were processing over a million cattle and almost that many hogs each year. In the first decade of the new century, the population of Fort Worth nearly tripled. 8
Slide 11: East Texas Basin Willow Springs Field, located in Gregg County, Texas, produces from the Cotton Valley, Travis Peak, Rodessa, and Pettit formations. Cross Timbers assumed operations of the East Texas properties Prior to 1998, the field was not heavily developed due to an in May 1998, establishing bases for operations in Tyler and operating agreement that required 100% partner approval for Longview. The Company immediately embarked on an aggressive workover program focused on recompletion opportunities in existing capital expenditures. By August 1998, Cross Timbers acquired the remaining working interest in the field, clearing the way for wellbores. By year-end, the Company had completed 53 workovers aggressive development. The 1998 development program, consisting and drilled 10 development wells. The East Texas properties are a perfect match for Cross Timbers’ of three recompletions and one development well, doubled the field production from 8 million acquire-and-exploit strategy. Located in one of the nation’s premier to 16 million cubic feet gas basins, these properties offer a long history of production from per day. multiple intervals ranging from 7,000 feet to 12,000 feet. Significant recompleProduction comes from eight major fields, with 80% produced from the Travis Peak Formation. Producing fields include Bald Prairie, tions in both the Upper Cotton Valley and Travis Freestone, Tri-Cities, Opelika, Willow Springs, Lansing North, Peak formations underscore Whelan and Louisiana’s Logansport. the significance of the The Travis Peak Formation consists of multiple pay zones bypassed sandstones. distributed throughout a thickness of up to 2,000 feet. These For example, when Cross sandstones were deposited over millions of years during the Middle Block Diagram of East Texas Basin Timbers acquired the Walke Cretaceous Age through ancient river, coastal and deltaic systems. During the Middle Cretaceous Age more than 65 No. 4 well as part of its East Studies of the major fields reveal that many of the wells have million years ago, sandstones were deposited in river, delta, and coastal depositional systems in or Texas acquisition, productbypassed productive sands, leaving numerous recompletion and near ancient seas that covered parts of what is ion was about 200 Mcf per drilling opportunities. Upon acquisition, Cross Timbers’ technical now Texas. Approximately 2,000 feet of interbedded sandstones and shales accumulated during day from the Lower Cotton staff identified 48 development well locations and 30 workover Travis Peak sedimentation. opportunities. We have since identified as many as 170 development Valley sandstones. Shortly after closing the acquisition, we successfully recompleted this well to well locations and more than 300 rework and recompletion the Upper Cotton Valley sandstones at an initial rate of 1,500 Mcf candidates. per day. Prior to this workover, these sandstones had not been The Travis Peak workovers consisted of two different types of completed or produced in the field. Cross Timbers then completed recompletions involving different risks: those wells with untapped the Walke No. 4 to the Travis Peak Formation. This production, productive sands above and those wells with untapped productive when commingled with the Cotton Valley, resulted in a combined sands below the producing interval. The latter wells involve much production rate of more than 3,000 Mcf per day. Clearly, the higher mechanical risk, which apparently resulted in their being potential of the bypassed sandstones provides written off as inaccessible by the previous owner. significant opportunity for production and reserve Cross Timbers’ technical staff devised an innovative growth. workover procedure using a retrievable liner to isolate Another example is the Robertson No. 6, which the producing interval, allowing the deeper sands to be Cross Timbers drilled and completed in both the completed with greatly reduced mechanical risk. The Cotton Valley and Travis Peak formations. The well is retrievable liner procedure has been successfully currently testing at daily rates as high as four million utilized on multiple recompletions in the Logansport, cubic feet. These results highlight the untapped Whelan, and Freestone fields to add significant potential of our East Texas properties by emphasizing reserves. the rate and reserve potential of additional workovers Thirty-eight of the 53 workovers implemented in East Texas were recompletions to intervals not and development wells in the Willow Springs Field. The 1999 development program for this field previously produced in that wellbore. The program anticipates 12 workovers and 10 development wells. was highly successful, with average producing rates of the completed wells exceeding 700 Mcf per day. This success was not limited to a single producing horizon Logansport Field, located in Desoto Parish, or field, but was consistent across all the major fields. Louisiana, produces from the Hosston Formation, The high flow pressure and production rates from which is synonymous with the Travis Peak in Texas. Travis Peak Thickness these workovers confirm our belief that there are Relative thickness of the Travis Development during 1998 consisted of six Peak Formation as it compares recompletions to various sandstones as well as significant reserves yet to be developed. to the Empire State Building. Our development efforts were focused on three The curve on the left is an SP two development wells. fields: Willow Springs, Logansport, and Whelan. log from a well, illustrating the interbedded sandstone shale sequence. 9
Slide 12: Oil By 1900, Fort Worth had become the commercial center for many farms, ranches and smaller towns, particularly in West Texas. Like other cattlemen with close ties to Fort Worth, W. T. Waggoner found oil on his property while trying to find water for his livestock. Such oil discoveries attracted more entrepreneurs who developed their interests, built their homes and began to shape the city’s downtown skyline. Ranger, Texas, about a hundred miles west of Fort Worth, was the site of the first big oil discovery in West Texas in 1917. Discoveries in Burkburnett to the northwest and then Desdemona near Ranger were made in 1918, and for a time it seemed that in some areas of Texas oil popped up whenever a drill bit went down. Because oil for the military during World War I was in short supply, people of all kinds thronged to the discovery sites to try their hand at making some quick oil money. Fort Worth was the focus for the investment frenzy that followed, and the Westbrook Hotel became the favored site for buying and selling leases. For a time there were so many deal-makers flocking to the hotel that even after the lobby was cleared of furniture, their trading activities spilled out onto the sidewalks and the street. This era, in which incredible fortunes were made, solidified Fort Worth as the business center of the West Texas oil boom. Oilmen such as Sid Richardson, Ed Landreth and W. A. Moncrief created wealth not only for their own families, but also for their community. Many of the institutions that give Fort Worth its special identity continue to benefit from the support of these families. 10
Slide 13: The Logansport workovers averaged more than 900 Mcf per day, with development wells completed at initial rates in excess of 2,000 Mcf per day. Evidence suggests that this field, currently developed on 80-acre well spacing, may require 40-acre well spacing to adequately drain remaining gas reserves. Both development wells and workovers indicate very little pressure depletion and, when coupled with gas-in-place calculations, indicate that closer spacing should increase proved reserves. Additionally, the Company has undeveloped acreage in the surrounding area with exciting potential for exploration and trend extension. Development plans for 1999 call for 13 additional recompletions and eight development wells. Whelan Field, located in Harrison County, Texas, produces from the Travis Peak and Rodessa formations. Development activity during 1998 included six Travis Peak recompletions and seven Travis Peak development wells. Additionally, a gas compression facility was installed in the northern portion of the field to decrease line pressures. These efforts have increased field production from 11,000 to 16,000 Mcf per day. Development plans for 1999 continue to target the Travis Peak Formation and include 14 workovers and two development wells. The acquisition of the East Texas properties added significant exploitation and development opportunities to the Company’s project inventory. The high potential of these opportunities may be best seen as we implement the 1999 development budget. The budget includes 75 workovers and 20 development wells in East Texas alone. This equates to 50% of the planned capital expenditures and highlights the spectacular production rate and reserve potential of these properties. San Juan Basin Cross Timbers acquired the San Juan Basin properties from Amoco in the fourth quarter of 1997, opened an office in Farmington, New Mexico and assumed operations in December of that same year. During 1998, the first full year of development, the Company installed 78 new wellhead compressors, completed 15 workovers and participated in the drilling of 48 wells. These activities have increased operated production by 15%. Cross Timbers diligently searched for a major acquisition in the San Juan Basin for many years because these properties exhibit our preferred attributes. Located in one of the nation’s premier gas basins, San Juan properties have long produced from multiple intervals and have extensive upside potential. Moreover, the San Juan Basin has a history of operators bypassing significant producing horizons, the Fruitland Coal Formation being a good example. Other development gains have been achieved by decreasing well spacing to efficiently recover remaining reserves and by lowering pipeline pressures to increase production rates and reserves. Our acquire-and-exploit strategy thrives on such attributes. The past several years have seen significant regulatory changes allowing for increased development in the San Juan Basin. Recently, an application to decrease well spacing in the Mesaverde Formation from 160- to 80-acre spacing was approved, making way for increased drilling. Another operator has proposed a pilot test of the Dakota Formation as a candidate for similar spacing reduction. Approval of this proposal would greatly enhance our portfolio of drilling projects. Further, in 1997 the New Mexico Oil Conservation Division eased the rules governing commingling of producing intervals. This ruling will allow additional development based on the ability to combine multiple intervals in a single wellbore and should increase both production and reserves per well. These changes are the most recent additions to a storied history of realized upside potential in this major gas basin. The highlighted areas indicate focus of drilling activity. San Juan Basin Our San Juan Basin properties produce from eight formations ranging in depth from 1,500 feet to 9,500 feet. At acquisition, Cross Timbers had identified 139 development well locations and 29 workover opportunities. Further study has identified more than 300 development well locations and more than 100 workover and recompletion candidates. The 78 new wellhead compressors installed during 1998 increased gross production by 9,000 Mcf per day, or an average of 115 Mcf per well. To date, the Company has identified more than 120 additional compression candidates, which will be evaluated during 1999. In addition, the Company installed artificial lifts on 10 wells and recompleted two wells to additional producing intervals. Thirteen of the 48 development wells drilled here in 1998 were operated by Cross Timbers. These wells targeted the Dakota and Fruitland Coal formations. The eight Dakota wells, 160-acre development wells concentrated in the South Canyon area, had an average initial rate of 500 Mcf per day. Several of these wells encountered additional sands beyond the main pay interval. These sands had been bypassed in surrounding wells. This type of opportunity for additional sandstone development in the Dakota recurs in many areas of the basin. In fact, a study of several leases uncovered deeper potential in the Burro Canyon and Morrison sands not penetrated in original wells. The Company plans to drill several wells to the Dakota during 1999 to test these deeper sands. The remaining five development wells targeted the Fruitland Coal Formation. Two of the wells were producing at year end, with the other three awaiting pipeline connections. The two producing wells, 11
Slide 14: The Military and Aviation Industries During the oil boom years, Fort Worth businessman and newspaper publisher Amon Carter hit his stride as Fort Worth’s champion promotor and master craftsman of its image. His tireless energy and influence were behind many of the city’s most important developments. He attracted businesses large and small, not the least of which was the aircraft industry. As early as 1911, he began bringing people with a common interest in aviation to town. When World War I began, the Army came looking for a desirable site to house a training camp, and Fort Worth offered land for the proposed facility. In 1917, Camp Bowie emerged practically overnight. Like the fort founded by Major Ripley Arnold, Camp Bowie left an infrastructure after the war which was quickly adapted to residential development. In 1941, with World War II imminent, the Army chose Fort Worth to be the site of a bomber plant. In April of 1942, the same month it opened, the plant produced its first B-24 “Liberator” bomber. During the next three years, Consolidated-Vultee Aircraft Corporation (Convair, then General Dynamics, now Lockheed Martin Tactical Aircraft Systems) manufactured over 3,000 bomber and transport planes at this site. Next to the plant, the Army had built Tarrant Field, where 4,000 bomber pilots were trained during the war. In 1948, the air field was renamed Carswell Air Force Base (now a Naval Air Station Joint Reserve Base) and the Eighth Air Force trained there for global missions in the new atomic age. Both facilities, along with related industries, played a major role in the postwar economic growth of Fort Worth. In addition to the military, commercial aviation also found a favorable climate in Fort Worth. The city would later become a key participant in building DFW International Airport, the largest airport in the world when it opened in 1974. 12
Slide 15: with initial rates in excess of 300 Mcf per day, have the potential to reach 1,000 Mcf per day after dewatering of the coal is completed. Fruitland Coal wells are shallow, low-cost ($190,000 per well) development wells with excellent rate and reserve potential. These wells have expected development costs per Mcfe of $0.25. As such, the Company plans to drill 10 additional Fruitland Coal wells during 1999. In addition, the Company reworked previously acquired 3-D seismic data over the Ute Dome Field located on the northwestern rim of the basin. The seismic reinterpretation revealed multiple drilling opportunities based on structure in both the Dakota and Paradox formations. The Paradox is a thick carbonate formation with several different producing intervals. The last well drilled in the Paradox Formation was in 1979 and is the best performer. It still produces at a rate of 1,500 Mcf per day and has produced 20 Bcf to date. We plan to drill three Paradox wells during 1999. The Dakota Formation, only 2,500 feet deep in this area of the basin, also is an attractive, highly economic target. The San Juan Basin properties, like East Texas, have added exciting exploitation and development opportunities to our project inventory. The 1999 development budget includes 30 recompletions, 40 wellhead compressor installations and 41 development wells (23 operated). Rocky Mountain Fontenelle Area. In 1996, Cross Timbers acquired a 97% interest in the Fontenelle Unit located in the Green River Basin of Wyoming. The Company acquired the remaining interests during the past year giving Cross Timbers 100% working interest. The Fontenelle Unit primarily produces from the low permeability sandstones of the Frontier Formation, and development has focused on 80-acre infill wells with some 40-acre test wells in select areas. This Unit is included in our recently formed Hugoton Royalty Trust. Development of the Unit progressed in 1998 with the drilling of 20 additional wells, which had average initial rates of 800 Mcf per day and average reserves of 1.5 Bcf per well. These new wells increased the total number of wells drilled since assuming operations in 1996 to 62. As a result, 1998 production peaked at 35 million cubic feet per day, the highest rate in the history of the Fontenelle Unit. In addition, two step-out wells were completed, defining trend extension possibilities that will be further tested during 1999. In 1998, a successful 40-acre development well drilled in the southeastern portion of the Unit revealed significant upside potential. Previous wells drilled on 80-acre spacing in this area in 1997 and 1998 encountered original pressure. Data from these 80acre wells showed inadequate depletion from current well spacing in this area of the field. This led to a highly successful 40-acre test well that produced at rates in excess of 1,500 Mcf per day. This successful test proved-up additional 40-acre well opportunities in select areas of the Unit. Cross Timbers also uncovered additional production potential in the Baxter sandstones. Located at 6,500 feet, these sandstones are approximately 1,000 feet shallower than the Frontier sandstones. Previous operators bypassed these sands because their shale-like appearance made them appear noncommercial. Cross Timbers cored this interval and discovered a thinly interbedded shale-sand sequence with favorable reservoir characteristics. This finding led to several successful Baxter sandstone recompletions with initial rates of 450 Mcf per day. As a result, we have defined an area of potential development encompassing one-quarter of the Fontenelle Unit. The Company plans to implement five Baxter sandstone recompletions and drill five development wells during 1999. Hugoton The Hugoton area has produced more than 64 trillion cubic feet (Tcf), making it the largest gas field in North America. As such, our properties in this area provide a foundation for our recently created Hugoton Royalty Trust. Our development efforts in 1998 centered on further delineating the exploration discoveries of 1997. During 1998, the Company drilled or participated in the drilling of 15 wells, mainly targeting the Council Grove Formation at a depth of about 3,500 feet. In 1997, the Company and its partners drilled two successful exploration tests that encountered productive Council Grove carbonates. Delineation of these discoveries continued in 1998 with gross production from the 14 completed wells reaching nine million cubic feet per day (4.5 million net). The southern extension wells have been particularly prolific, with two wells producing at rates exceeding 1.5 million cubic feet per day. We plan to continue this successful program by drilling an additional 13 wells during 1999 to further develop and delineate the productive limits of the field. Another upside has emerged from this recent drilling program. Since the development wells were being drilled to test deeper formations, each well penetrated the entire Chase Group. Gas shows were noticed in the Towanda limestone, which had not been produced or adequately tested in the surrounding area. The Company successfully tested commercial quantities of gas from this interval and is currently studying its remaining acreage position for similar opportunities. We believe that the original Chase development wells, drilled more than 50 years ago, were not drilled deep enough to encounter this interval due to a fear of water production. The recent test well encountered original pressure, confirming that no significant gas has been produced from this interval. The Company plans to further test this interval during 1999 through recompletions of existing wells and by drilling new wells. 13
Slide 16: Entertainment and the Arts From promoting the earthy type of entertainment sought by cowboys and gamblers in old Fort Worth, to showcasing today’s most renowned intellects, artists and performers in world-class facilities, local citizens have always come together to provide a hospitable environment for entertainment, educational and cultural endeavors. Even before the turn of the century, Fort Worth had developed a more cultured way of life. Its first opera house opened in 1876, and in 1889, the Texas Spring Palace opened to show off the many products indigenous to Texas, some of which also served as construction materials. Tourists came from all across the country to view this unusual building and its treasures, but in 1890, a fire destroyed the building. In spite of its short-lived reign, the Spring Palace got people talking about Fort Worth and its unique attractions. The Will Rogers Memorial Center with its coliseum and auditorium, the city’s first large entertainment landmark, was built in 1936 with funds from the Federal goverment, a city bond issue and donations from the community. The Center became the cornerstone of a cluster of museums, parks, and restaurants known as the Cultural District, which today includes the worldrenowned Kimbell Art Museum. Fort Worth’s involvement in the performing arts has also gained momentum over the years, culminating in the 1998 opening of the Nancy Lee and Perry R. Bass Performance Hall. This state-of-the-art facility was recently named one of the top 10 opera houses in the world. Fort Worth has matured remarkably in its first 150 years. Whether visitors come for a taste of the Old West or the best of modern culture, they come away with a sense of both. The city’s most distinctive attraction, however, is the generous spirit of the people who live here, and simply want others to enjoy Fort Worth as much as they do. 14
Slide 17: Permian Basin production at a cost of $0.48 per Mcfe. Our five-year all-in finding cost is $0.64 per Mcfe. These finding costs and production University Block 9 Field. This West Texas field, discovered in replacement statistics are expected to be among the lowest in 1953, is a multiple-pay field producing from the Wolfcamp-, Pennsylvanian- and Devonian-age carbonates from 8,400 to 10,400 the industry. During 1998, the Company produced 4.6 million barrels of oil, feet. Upon completing the consolidation of working interests in the 1.2 million barrels of natural gas liquids (NGLs) and 83.8 billion Penn and Wolfcamp units and a majority of the Devonian leases in cubic feet of natural gas. Daily oil and NGLs 1997, Cross Timbers began an aggressive, highly production averaged 15,945 barrels, up 43% over successful development program that continued Proved Reserves the 11,125 barrels during 1997. Daily gas in 1998. production averaged 229.7 million cubic feet, up Five wells were drilled in this field with 69% from the 135.9 million cubic feet in 1997. average initial production exceeding 200 barrels The 1998 exit rate for daily production, 275,000 per day. One of the five wells successfully tested Mcf of gas and 19,000 barrels of oil and NGLs, the eastern portion of the field, which represents a 38% increase over 1997 exit rates. historically was believed to be adequately Oil prices, at an average $21.38 a barrel in depleted by original development. The new well 1996 and $18.90 in 1997, decreased to $12.21 for is capable of producing more than 1,000 barrels 1998. The average natural gas price for 1998 was per day, a rate not achieved since field discovery. $2.07 per Mcf, down 6% from the 1997 average This achievement redefines the economic of $2.20 per Mcf. NGLs per barrel averaged potential of the field’s eastern portion. $7.62, down 21% from the 1997 average sales price of $9.66. Three horizontal sidetracks from existing Devonian wells also As of December 31, 1998, estimated future net cash flows were completed in 1998. These wells, along with two existing before income tax were $1.677 billion based on prices of $9.50 per horizontal sidetrack wells, are each producing an average of 125 barrel of oil and $2.01 per Mcf of gas. The present value before barrels per day higher than their original vertical well rates. The income tax, discounted at 10%, was $909 million, compared to the horizontal sidetracks were drilled and completed for a cost of 65% year-end 1997 level of $782 million. The prices at year-end 1997 less than the cost to drill a vertical well, providing an attractive were $15.50 per barrel of oil and $2.20 per Mcf of gas. development opportunity. As a result, 15 wells are now candidates Using year-end 1997 oil and natural gas prices, 1998 proved for a horizontal sidetrack development. reserves would have been 1.733 Tcfe, an increase of 46% from Four recompletions to add additional pay in existing wells were 1997. Estimated future net cash flows, before income taxes, would successful in increasing production an average of 80 barrels per have been $2.275 billion with a present value before income tax, day per well. discounted at 10%, of $1.249 billion. Our 1998 exploration and Additional upsides remain for the Devonian wells by completing the Pennsylvanian- and Wolfcamp-age carbonates above development program would have replaced 231 Bcfe or 195% of production at a cost of $.34 per Mcfe. the Devonian. During 1998, we recompleted four existing Devonian wells to the Pennsylvanian for an additional 150 barrels Proved Oil and Gas Reserves per day. December 31, 1998 Overall, the 1998 development program resulted in a peak rate (in thousands) Natural for the University Block 9 Field of 3,900 barrels per day in January Oil Gas Gas Liquids (Bbls) (Mcf) (Bbls) Mcfe 1999, a 34% production increase over the previous year’s peak rate Proved developed 42,876 968,495 14,000 1,309,751 and 300% above the rate at the time of acquisition. This is the Proved undeveloped 11,634 240,729 3,174 329,577 highest field production rate in the past 25 years, allowing for Total proved 54,510 1,209,224 17,174 1,639,328 attractive rates of return despite low oil prices. With an additional Estimated future net cash flows, before income tax $1,677,426 30 to 40 locations identified for future development by either Present value before income tax $908,606 drilling or horizontal sidetracks, Cross Timbers continues to breathe new life into a venerable field. Changes in Proved Reserves (in thousands) RESERVES AND PRODUCTION This was another banner year for Cross Timbers, attributable to substantial acquisitions of producing properties, accelerated development activity and sheer determination by dedicated operations personnel companywide. Estimated proved oil and gas reserves at year-end 1998 were 1.639 Tcfe, up 38% from 1.186 Tcfe at year-end 1997. Cross Timbers replaced 482% of its 1998 production at a cost of $.73 cents per Mcfe. Through the drill bit, we replaced 137% of Oil (Bbls) December 31, 1997 47,854 Revisions (5,893) Extensions and discoveries 821 Production (4,598) Purchases in place 16,331 Sales in place (5) December 31, 1998 54,510 Gas (Mcf) 815,775 (5,429) 172,059 (83,847) 311,260 (594) 1,209,224 Natural Gas Liquids (Bbls) 13,810 2,631 1,875 (1,222) 80 – 17,174 Mcfe 1,185,759 (25,001) 188,235 (118,767) 409,726 (624) 1,639,328 Based on SEC assumptions. 15
Slide 18: Cross Timbers Oil Company SELECTED FINANCIAL DATA In thousands except production, per share and per unit data 1998 1997 1996 1995 1994 Consolidated Statement of Operations and Cash Flows Data (a) Revenues: Oil and condensate Gas and natural gas liquids Gas gathering, processing and marketing Other Total revenues Earnings (loss) available to common stock Per common share (d) Basic Diluted Weighted average common shares outstanding (d) Dividends declared per common share (d) Operating cash flow (e) $ $ $ $ (1.65)(b) $0000.60 (1.65)(b) $0000.59 43,396 0.16 78,480 39,773 $0000.15 $089,979 $ $ 0.50 0.48 39,913 $0000.13 $068,263 $00 (0.28)(c) $ 00 0.09 $00 (0.28)(c) $ 00 0.08 38,072 $0000.13 $040,439 35,829 $0000.13 $037,816 $ 56,164 182,587 9,438 1,297 $075,223 110,104 9,851 3,094 $198,272 $ 75,013 73,402 12,032 ,888 $161,335 $019,790 $060,349 40,543 7,091 3,362 $ 111,345 $ 53,324 38,389 4,274 288 $ 96,275 $ 249,486 $ (71,498)(b) $023,905 $ (10,538)(c) $003,048 Year-end Consolidated Balance Sheet Data (a) Property and equipment, net Total assets Long-term debt Stockholders’ equity $1,051,011 1,207,594 921,000 177,451 $723,836 788,455 539,000 170,243 $450,561 523,070 314,757 142,668 $364,474 402,675 238,475 130,700 $244,555 292,451 142,750 113,333 Operating Data (a) Average daily production: Oil (Bbls) Gas (Mcf) Natural gas liquids (Bbls) Mcfe Average sales price: Oil (per Bbl) Gas (per Mcf) Natural gas liquids (per Bbl) Production expense (per Mcfe) Taxes, transportation and other (per Mcfe) Proved reserves: Oil (Bbls) Gas (Mcf) Natural gas liquids (Bbls) Mcfe 12,598 229,717 3,347 325,390 $12.21 $02.07 $07.62 $00.53 $00.25 54,510 1,209,224 17,174 1,639,331 10,905 135,855 220 202,609 $18.90 $02.20 $09.66 $00.59 $00.22 47,854 815,775 13,810 1,185,759 9,584 101,845 – 159,349 $21.38 $01.97 – $00.67 $00.20 42,440 540,538 – 795,178 9,677 78,408 – 136,470 $17.09 $01.42 – $00.71 $00.17 39,988 358,070 – 597,998 9,497 58,182 – 115,164 $15.38 $01.81 – $00.77 $00.21 33,581 177,061 – 378,547 (a) Significant producing property acquisitions in each of the years presented affect the comparability of year-to-year financial and operating data. (b) Includes effect of a $93.7 million pre-tax net loss on investment in equity securities and a $2 million pre-tax, non-cash impairment charge. (c) Includes effect of a $20.3 million pre-tax, non-cash impairment charge recorded upon adoption of Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. (d) Adjusted for the three-for-two stock splits effected on March 19, 1997 and February 25, 1998. (e) Defined as cash provided by operating activities before changes in current assets and liabilities. 16
Slide 19: Cross Timbers Oil Company MANAGEMENT’S DISCUSSION AND ANALYSIS General The following events affect the comparability of results of operations and financial condition for the years ended December 31, 1998, 1997 and 1996, and may impact future operations and financial condition. Throughout this discussion, the term “Mcfe” refers to thousands of cubic feet of gas equivalent quantities produced for the indicated period, with oil quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf. Three-for-Two Stock Splits. The Company effected a three-for-two stock split on March 19, 1997 and on February 25, 1998. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect both stock splits. 1998 Acquisitions. During 1998, the Company acquired oil- and gas-producing properties for a total cost of $340 million, including: • The East Texas Basin Acquisition. The Company acquired these primarily gas-producing properties for an estimated purchase price of $245 million, later reduced to $215 million by a $30 million production payment sold to EEX Corporation. This acquisition closed on April 24, 1998 and was funded by bank debt, partially repaid from proceeds of the 1998 Common Stock Offering. • The Alaska Cook Inlet Acquisition. In September 1998, the Company acquired these oil-producing properties in exchange for 1,921,850 shares of the Company’s common stock along with certain price guarantees and a non-interest bearing note payable of $6 million, resulting in an estimated purchase price of $44.4 million. • The Seagull Acquisition. This acquisition includes primarily gas-producing properties in northwest Oklahoma and the San Juan Basin of New Mexico. The Company acquired these properties in November 1998 for an estimated purchase price of $29.2 million, funded by bank borrowings. 1997 Acquisitions. During 1997, the Company acquired predominantly gas-producing properties for a total cost of $256 million, funded primarily by bank borrowings and cash flow from operations. The acquisitions include: • The Amoco Acquisition. The Company purchased these properties in the San Juan Basin of New Mexico in December 1997 for an estimated adjusted purchase price of $195 million. This purchase price includes $5.7 million for five-year warrants to purchase 937,500 shares of the Company’s common stock at $15.31 per share. • The Burlington Resources Acquisition. The Company purchased these properties in Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39 million in May 1997. • 6% of the publicly traded outstanding units in Cross Timbers Royalty Trust, at a cost of $5.4 million. 1996 Acquisitions. During 1996, the Company acquired primarily gas-producing properties for a total cost of $106 million funded primarily by bank debt. These acquisitions include: • The Enserch Acquisition. This acquisition closed in July 1996 at a cost of $39.4 million and primarily consisted of operated gas-producing properties in the Green River Basin of southwestern Wyoming. In November 1996, the Company acquired additional interests in the Fontenelle Unit, the most significant property included in the Enserch Acquisition, at a cost of $12.5 million. • Gas-producing properties in the Ozona area of the Permian Basin of West Texas. The Company acquired these mostly operated interests for $28.1 million. • 16% of the publicly traded outstanding units in Cross Timbers Royalty Trust. The Company purchased these units at a total cost of $12.8 million from July through December 1996. 1998, 1997 and 1996 Development and Exploration Programs. Oil development was concentrated in the University Block 9 Field during 1998 and 1997, as well as the Prentice Northeast Unit of West Texas during 1997 and 1996. Gas development focused on the Hugoton Area during 1998, the Ozona Area in 1998 and 1997, the Fontenelle Unit during all three years and Major County, Oklahoma during 1996. Exploration activity during 1998 was primarily geological and geophysical analysis, including seismic studies, of undeveloped properties at a total cost of $8 million. This work was concentrated in the Silurian Reef of Illinois, and Texas County and the Nemeha Ridge Area of Oklahoma. Exploratory expenditures were $2.1 million in 1997 and insignificant in 1996. 1999 Development and Exploration Program. The Company has budgeted $60 million for its 1999 development and exploration program, which is expected to be funded primarily by cash flow from operations. The Company anticipates exploration expenditures will be less than 5% of the 1999 budget. The total capital budget, including acquisitions, will be adjusted throughout 1999 to capitalize on opportunities offering the highest rates of return. 1998 Common Stock Offering. In April 1998, the Company sold 7,203,450 shares of common stock. Net proceeds of $133.1 million were used to partially repay bank debt used to fund the East Texas Basin Acquisition. 1998 Issuance of Common Shares. In September 1998, the Company issued from treasury stock 1,921,850 common shares to subsidiaries of Shell Oil Company for the Alaska Cook Inlet Acquisition. 1997 Senior Subordinated Note Sales. The Company sold $125 million of 9 1⁄4% senior subordinated notes in April 1997 and $175 million of 8 3⁄4% senior subordinated notes in October 1997. Net proceeds of $121.1 million and $169.9 million were used to reduce bank debt. 1997 and 1996 Conversion of Subordinated Notes. During November and December 1996, noteholders converted $27.7 million principal of the 5 1⁄4% convertible subordinated notes into 2,696,521 shares of common stock. In January 1997, noteholders converted the remaining principal of $29.7 million into 2,892,363 shares of common stock. 1996 Preferred Stock Exchange. In September 1996, stockholders exchanged 2,979,249 shares of common stock for 1,138,729 shares of Series A convertible preferred stock pursuant to the Company’s exchange offer. Treasury Stock Purchases. Since May 1996, the Board of Directors has authorized the purchase of a total of 10.5 million shares of the Company’s common stock as part of its strategic acquisition plans. The Company purchased on the open market 4.3 million shares at a cost of $65.6 million in 1998, 2.4 million shares at a cost of $28 million in 1997 and 2.9 million shares at a cost of $30.7 million in 1996.
Slide 20: Cross Timbers Oil Company MANAGEMENT’S DISCUSSION AND ANALYSIS Investment in Equity Securities. The Company acquired common stock of publicly traded independent oil and gas producers at a total cost of $167.7 million in 1998, $6.5 million in 1997 and $16.1 million in 1996. For accounting purposes, the Company considered equity securities purchased in 1998 to be trading securities, whereas it considered equity securities purchased prior to 1998 to be available-for-sale securities. Accordingly, the Company recognized unrealized investment gains and losses in its 1998 statement of operations, as opposed to recording as a component of stockholders’ equity in prior years. During 1998, the Company recognized a $93.7 million loss on investment in equity securities, including a loss on sale of securities of $14.8 million, an unrealized loss of $72.6 million and interest expense of $6.3 million related to the investment. During 1997, the Company recognized a gain of $1.7 million on its investment in equity securities including a gain on sale of securities of $2.4 million and interest expense of $700,000 related to the investment. Property Sales. The Company sold producing properties resulting in net gains of $800,000 in 1998, $1.8 million in 1997 and $500,000 in 1996. Stock Incentive Compensation. Stock incentive compensation results from stock appreciation right (“SAR”) and performance share awards, and subsequent changes in the Company’s stock price. During 1998, stock incentive compensation totaled $1.3 million, which included non-cash performance share compensation of $1.6 million, partially offset by a reduction in SAR compensation of $300,000. In 1997, stock incentive compensation totaled $3.7 million, which included non-cash performance share compensation of $3.3 million and SAR compensation of $400,000. During 1996, stock incentive compensation totaled $6.2 million, which included SAR compensation of $3.7 million (cash payments of $7.1 million, partially offset by prior accruals) and non-cash performance share compensation of $2.5 million. Exercises and forfeitures under the 1991 Stock Incentive Plan reduced outstanding stock incentive units (including SARs) from 836,000 at the beginning of 1996 to 18,000 at year-end 1998. Product Prices. In addition to supply and demand, oil and gas prices are affected by substantial seasonal, political and other fluctuations the Company generally cannot control or predict. Crude oil prices are generally determined by global supply and demand. After sinking to a five-year low at the end of 1993, oil prices reached their highest levels since the 1990 Persian Gulf War during fourth quarter 1996 and January 1997. Crude oil prices ranged from $17 to $20 during most of 1997, then declined to a $16 average in December. Crude oil prices continued to decline throughout 1998, dropping to a West Texas Intermediate price of $8.00 per barrel in December 1998, the lowest level since 1978. This decline is the result of low demand, as well as the failure of OPEC, at its November 1998 meeting, to further reduce production quotas. Low demand has been caused by warmer than normal winter temperatures and a slower than expected recovery in Asian economies. Based on 1998 production, the Company estimates that a $1.00 per barrel increase or decrease in the average oil sales price would result in approximately a $4.4 million change in 1999 annual operating cash flow. (continued) during the summer, have remained lower throughout 1998. Lower gas prices have been primarily because the winters of 1997-1998 and 1998-1999 in the central and eastern U.S. were abnormally mild. The Company has entered into commodity price hedging instruments to reduce its exposure to gas price fluctuations. As a result of these commodity hedging instruments, the Company’s average gas price increased from $1.97 to $2.07 in 1998 and decreased from $2.24 to $2.20 in 1997. Based on 1998 production, the Company estimates that a $0.10 per Mcf increase or decrease in the average gas sales price would result in approximately a $7.7 million change in 1999 annual operating cash flow. Impairment Provision. During 1998, the Company recorded an impairment provision on producing properties of $2 million before income tax. This impairment provision was determined based on an assessment of recoverability of net property costs from estimated future net cash flows from those properties. Estimated future net cash flows are based on management’s best estimate of projected oil and gas reserves and prices. If oil and gas prices remain at lower levels or decline further, the Company may be required to record impairment provisions in the future, which may be material. Results of Operations 1998 Compared to 1997 For the year 1998, loss available to common stock was $71.5 million compared with earnings of $23.9 million for 1997. The 1998 loss includes a $93.7 million loss ($61.8 million after tax) on investment in equity securities and a $2 million ($1.3 million after tax) impairment write-down of producing properties. The remaining decline in earnings is primarily the result of lower product prices and increased interest related to the 1998 acquisitions and treasury stock purchases. Revenues for 1998 were $249.5 million, or 26% above 1997 revenues of $198.3 million. Even though oil production increased by 16%, oil revenue decreased $19.1 million or 25% because of a 35% decrease in oil prices from an average of $18.90 in 1997 to $12.21 in 1998 (see “General-Product Prices” above). Increased production was primarily because of the 1998 acquisitions. Gas revenue increased $72.5 million or 66% because of a 69% increase in production partially offset by a 6% price decrease (see “General-Product Prices” above). Increased gas production was attributable to the 1997 and 1998 acquisitions and development programs. Gas revenues for 1998 also included $9.3 million from San Juan Basin natural gas liquids production attributable to the December 1997 Amoco Acquisition. Gas gathering, processing and marketing revenues decreased $400,000 primarily because of decreased wellhead volumes and lower gas and natural gas liquids prices, partially offset by increased margin. Other revenues were $1.8 million lower primarily because of decreased net gains on sale of properties and decreased lawsuit settlement receipts. Expenses for 1998 totaled $209.2 million as compared with total 1997 expenses of $134.8 million. Most expenses increased in 1998 primarily because of the 1997 and 1998 acquisitions and exploration Natural gas prices are influenced by national and regional supply and development programs. and demand, which is often dependent upon weather conditions. Specific gas prices are also based on the location of production, Production expense increased $19.6 million or 45%. Per Mcfe, pipeline capacity, gathering charges and the energy content of the production expense decreased from $0.59 to $0.53. This decrease is gas. Generally because of colder weather, storage concerns and U.S. primarily because of the lower operating costs of gas-producing economic growth, prices remained relatively high during most of properties acquired in 1997 and 1998, the timing of workovers and 1996 and 1997, reaching their highest levels since 1985. Gas prices operating efficiencies initiated after acquiring operated properties. declined, however, in December 1997 and, except for a rebound Exploration expenses for 1998 totaled $8 million and were
Slide 21: Cross Timbers Oil Company MANAGEMENT’S DISCUSSION AND ANALYSIS predominantly geological and geophysical costs, including seismic analysis, related to the 1998 exploration program. Exploration costs in 1997 totaled $2.1 million. Taxes on production and property, transportation and other deductions increased 77% or $12.7 million because of increased oil and gas revenues, as well as increased property taxes related to the 1997 and 1998 acquisitions. Taxes, transportation and other per Mcfe increased 14% from $0.22 to $0.25 because of increased transportation, compression and other charges related to acquisitions. Depreciation, depletion and amortization (“DD&A”) increased $35.8 million, or 75%, primarily because of the 1997 and 1998 acquisitions and development programs. On an Mcfe basis, DD&A increased from $0.65 in 1997 to $0.70 in 1998 primarily because of the higher cost per Mcfe of the 1998 acquisitions. General and administrative expense decreased $2.3 million, or 15%, because of a $2.4 million decrease in stock incentive compensation, partially offset by increased expenses from Company growth. Excluding stock incentive compensation, general and administrative expense per Mcfe decreased to $0.10 in 1998 from $0.16 in 1997. This reduction resulted from production growth outpacing Company personnel requirements and other administrative expenses. Interest expense increased $26.1 million or 100% primarily because of a comparable increase in weighted average borrowings to partially fund the 1997 and 1998 acquisitions and treasury stock purchases, combined with a 1% increase in the weighted average interest rate and amortization of loan fees. Interest related to investment in equity securities has been classified as part of the loss on investment in equity securities. Interest expense per Mcfe increased from $0.35 in 1997 to $0.44 in 1998 primarily as the result of an increase in the weighted average borrowings to fund treasury stock purchases. 1997 Compared to 1996 Earnings available to common stock for 1997 were $23.9 million as compared with $19.8 million for 1996. Improved earnings were primarily the result of higher gas prices and increased gas production from the 1996 and 1997 acquisitions and development programs. Results included the effects of stock incentive compensation of $3.7 million in 1997 and $6.2 million in 1996. Also included in 1997 results were a $1.7 million gain on investment in equity securities, a gain of $1.8 million on sale of properties and lawsuit settlement proceeds of $1.3 million. A $500,000 gain on sale of properties was included in 1996 results. Dividends on preferred stock issued in September 1996 reduced 1997 earnings by $1.8 million and 1996 earnings by $500,000. Revenues for 1997 were $198.3 million, or 23% above 1996 revenues of $161.4 million. Oil revenue remained constant as a 13% increase in oil production was offset by a 12% decrease in oil prices from an average of $21.38 in 1996 to $18.90 in 1997 (see “General-Product Prices” above). Increased production was primarily because of the 1997 acquisitions and development programs. Gas revenue increased $36.7 million or 50% because of a 33% increase in production combined with a 12% price increase (see “General-Product Prices” above). Increased gas production was attributable to the 1996 and 1997 acquisitions and development programs. Gas revenues for 1997 also included $800,000 from San Juan Basin natural gas liquids production attributable to the December 1997 Amoco Acquisition. Gas gathering, processing and marketing revenues decreased $2.2 million primarily because of a decrease in margin and gas volumes. Other revenues increased $2.2 million primarily because of increased net gains on sale of properties and lawsuit settlement proceeds received in 1997. Expenses for 1997 totaled $134.8 million as compared with total 1996 expenses of $113.3 million. All expenses other than general and administrative expense increased in 1997 primarily because of the 1996 and 1997 acquisitions and exploration and development programs. Production expense increased $4.2 million or 11%. Production expense per Mcfe decreased from $0.67 to $0.59. This decrease is primarily because of the lower operating costs of gas-producing properties acquired in 1996 and 1997, the timing of workovers and operating efficiencies initiated after acquiring operated properties. Exploration expenses for 1997 totaled $2.1 million, and were predominantly geological and geophysical costs related to the 1997 exploration program. Exploration costs in 1996 and prior were included in production expense since not significant. Taxes on production and property, transportation and other deductions increased 37% or $4.5 million because of increased oil and gas revenues, as well as increased property taxes related to the 1996 and 1997 acquisitions. Taxes, transportation and other per Mcfe increased 10% from $0.20 to $0.22 because of increased gas prices and higher property tax rates. DD&A increased $9.9 million, or 26%, primarily because of the 1996 and 1997 acquisitions and development programs. On an Mcfe basis, DD&A remained relatively flat at $0.65 for 1996 and 1997. General and administrative expense decreased $600,000, or 4%, because of a $2.5 million decrease in stock incentive compensation, partially offset by increased expenses from Company growth. Excluding stock incentive compensation, general and administrative expense per Mcfe was $0.16 for 1997 as compared with $0.17 for 1996. Gas gathering and processing expense increased $1.6 million or 23%. This increase was primarily because of rental expense related to the Tyrone plant and gathering system lease that began in March 1996 and the Major County, Oklahoma gathering system lease that began in November 1996. This increase offsets related decreases in DD&A and interest. Interest expense increased $9.9 million or 61% because of a 36% increase in weighted average borrowings to partially fund the 1996 and 1997 acquisitions and purchases of treasury stock, combined with a 20% increase in the weighted average interest rate primarily attributable to the senior subordinated notes sold in April and October 1997. Interest expense per Mcfe increased from $0.28 in 1996 to $0.35 in 1997, primarily because of an increase in the weighted average interest rate, as well as the result of increased bank debt to finance treasury stock purchases. Liquidity and Capital Resources The Company’s primary sources of liquidity are cash flow from operating activities, producing property sales, including sales of royalty trust units, public offerings of equity and debt, and bank debt. Other than for operations, the Company’s cash requirements are generally for the acquisition, exploration and development of oil and gas properties, and debt and dividend payments. The Company believes that its sources of liquidity are adequate to fund its 1999 cash requirements.
Slide 22: Cross Timbers Oil Company MANAGEMENT’S DISCUSSION AND ANALYSIS Cash used by operating activities was $45.8 million in 1998, compared with $98 million cash provided by operations in 1997 and $59.7 million in 1996. The fluctuation from 1997 to 1998 was primarily because of decreased product prices and purchases of equity securities, net of sales. Before changes in working capital, cash flow from operations was $78.5 million in 1998, $90 million in 1997 and $68.3 million in 1996. The 1997 and 1996 acquisitions were primarily financed by long-term debt. The 1998 acquisitions were funded by a combination of bank borrowings, proceeds from a public offering of common stock and the issuance of common stock. Exploration and development expenditures and dividend payments have generally been funded by cash flow from operations. Financial Condition Total assets increased 53% from $788 million at December 31, 1997 to $1.2 billion at December 31, 1998, primarily because of the 1998 acquisitions. As of December 31, 1998, total capitalization of the Company was $1.1 billion, of which 84% was long-term debt. This compares with capitalization of $709 million at December 31, 1997, of which 76% was long-term debt. The increase in the debt-tocapitalization ratio from year-end 1997 to 1998 is because of increased borrowings under the Company’s loan agreement to fund the 1998 acquisitions, purchases of equity securities and other capital expenditures (see “Financing” below). Working Capital The Company generally uses available cash to reduce bank debt and, therefore, does not maintain large cash and cash equivalent balances. Short-term liquidity needs are satisfied by bank commitments under the loan agreement (see “Financing” below). Because of this, and since the Company’s principal source of operating cash flows (i.e., proved reserves to be produced in the following year) cannot be reported as working capital, the Company often has low or negative working capital. Working capital of $38 million at December 31, 1998 is primarily attributable to the investment in equity securities and the related deferred tax benefit. Financing On November 16, 1998, the Company entered into a new Revolving Credit Agreement with commercial banks. As of December 31, 1998, the Company had a borrowing base and commitment of $615 million with no unused borrowing capacity under the loan agreement. The interest rate on borrowings at December 31, 1998 was 6.9%. The Company periodically renegotiates the loan agreement to increase the borrowing commitment and extend the revolving facility; however, the Company cannot assure that it can continue to do so in the future. The Company’s goal in 1999 is to reduce debt by as much as $300 million, resulting in debt of 40 to 45 cents per Mcfe of proved reserves. The borrowing base is redetermined annually based on the value and expected cash flow of the Company’s proved oil and gas reserves. If borrowings exceed the redetermined borrowing base, the banks may require that the excess be repaid within a year. Otherwise, borrowings under the loan agreement do not mature until June 30, 2003, but may be prepaid at any time without penalty. The borrowing base is scheduled to be redetermined in June 1999. Based on year-end proved reserves, the Company does not expect a reduction in the borrowing base upon its redetermination. (continued) Other financing activities in 1998, 1997 and 1996 included the 1998 common stock offering, 1998 issuance of common shares, 1997 senior subordinated note sales, 1997 and 1996 conversion of subordinated notes and 1996 preferred stock exchange. These transactions are described under “General” above. Capital Expenditures In May 1998, the Company announced plans to make strategic acquisitions totaling $150 million from May 1998 through the end of 1999. After closing the Alaska Cook Inlet Acquisition in September, the Seagull Acquisition in November and other smaller acquisitions in the last half of 1998, the Company achieved approximately twothirds of this goal. The Company does not expect to make further significant acquisitions until substantially meeting its debt reduction goal. The Company plans to fund any future acquisitions through a combination of cash flow from operations and proceeds from bank debt, public equity or debt transactions. In 1998, exploration and development cash expenditures totaled $77.4 million compared with the budget of $90 million. In 1997, exploration and development cash expenditures totaled $90.5 million, compared with the budget of $70 million. The Company has budgeted $60 million for the 1999 development program. As it has done historically, the Company expects to fund the 1999 development program with cash flow from operations. Since there are no material long-term commitments associated with this budget, the Company has the flexibility to adjust its actual development expenditures in response to changes in product prices, industry conditions, and the effects of the Company’s acquisition and development programs. A minor portion of the Company’s existing properties are operated by third parties which control the timing and amount of expenditures required to exploit the Company’s interests in such properties. Therefore, the Company cannot assure the timing or amount of these expenditures. To date, the Company has not spent significant amounts to comply with environmental or safety regulations, and it currently does not expect to do so during 1999. However, developments such as new regulations, enforcement policies or claims for damages could result in significant future costs. Dividends The Board of Directors declared quarterly dividends of $0.033 per common share since the Company’s inception through 1996, $0.037 per common share in 1997 and $0.04 per common share in 1998. In February 1999, the Board reduced the quarterly dividend to $0.01 per common share because of the Company’s current focus on debt reduction. The Company’s ability to pay dividends is dependent upon available cash flow, as well as other factors. In addition, the loan agreement restricts the amount of common stock dividends to 25% of operating cash flow for the last four quarters. Cumulative dividends on Series A convertible preferred stock are paid quarterly, when declared by the Board of Directors, based on an annual rate of $1.5625 per share, or $1.8 million annually. Year 2000 “Year 2000,” or the ability of computer systems to process dates with years beyond 1999, affects almost all companies and organizations. Computer systems that are not Year 2000 compliant
Slide 23: Cross Timbers Oil Company MANAGEMENT’S DISCUSSION AND ANALYSIS by January 1, 2000 may cause material adverse effects to companies and organizations that rely upon those systems. Continuity of the Company’s operations in January 2000 will not only depend upon Year 2000 compliance of the Company’s computer systems and computer-controlled equipment, but also compliance of computer systems and computer-controlled equipment of third parties. These third parties include oil and natural gas purchasers and significant service providers such as electric utility companies and natural gas plant, pipeline and gathering system operators. The Company is in the process of reviewing its computer systems and computer-controlled field equipment and making the necessary modifications for Year 2000 compliance. The Company has completed modifications and testing of its primary accounting and land computer programs. The remaining computer systems have been inventoried and assessed. Remediation and testing of significant remaining systems are expected to be complete by August 1999. Some of the Company’s critical field equipment, such as natural gas compressors, are partially controlled or regulated by embedded computer chips. Based on a preliminary review of all operating areas, no significant compliance exceptions have been identified. Approximately 30% of field equipment in operated areas has been inventoried. The Company expects to complete its review of the remaining 70% of field equipment inventories by April 1999. The Company plans to complete remediation and testing of identified exceptions for significant computer-controlled field equipment by August 1999. Based on its review, remediation efforts and the results of testing to date, the Company does not believe that timely modification of its computer systems and computer-controlled equipment for Year 2000 compliance represents a material risk to the Company. The Company estimates that total costs related to Year 2000 compliance efforts will be less than $500,000 of which approximately $50,000 has been incurred and expensed through December 1998. The Company has identified significant third parties whose Year 2000 compliance could affect the Company and is in the process of formally inquiring about their Year 2000 status. The Company has received responses to approximately 30% of its inquiries. Approximately 90% of respondents have indicated that they will be Year 2000 compliant by January 1, 2000. Despite its efforts to assure that such third parties are Year 2000 compliant, the Company cannot provide assurance that all significant third parties will achieve compliance in a timely manner. A third party’s failure to achieve Year 2000 compliance could have a material adverse effect on the Company’s operations and cash flow. The potential effect of Year 2000 non-compliance by third parties is currently unknown. The Company is currently identifying appropriate contingency plans in the event of potential problems resulting from failure of the Company’s or significant third party computer systems on January 1, 2000. The Company has not completed any contingency plans to date. Specific contingency plans will be developed in response to the results of testing scheduled to be complete by August 1999, as well as the assessed probability and risk of system or equipment failure. These contingency plans may include installing backup computer systems or equipment, temporarily replacing systems or equipment with manual processes, and identifying alternative suppliers, service companies and purchasers. The Company expects these plans to be complete by October 1999. New Accounting Standards The Company adopted the following pronouncements in 1998: • SFAS No. 130, Reporting Comprehensive Income, requires that all items that are to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements, and • SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, requires reporting of financial and descriptive information about a company’s reportable operating segments. The Company has identified only one operating segment, which is the exploration and production of oil and gas. The Company will be required to comply with the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which must be adopted for fiscal years beginning after June 15, 1999. SFAS No. 133 requires that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either offset by the change in fair value of the hedged asset or liability (if applicable) or reported as a component of other comprehensive income in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. The definition of derivatives has also been expanded to include contracts that require physical delivery of oil and gas if the contract allows for net cash settlement. The Company primarily uses derivatives to hedge product price and interest rate risks. These derivatives are recorded at cost, and gains and losses on such derivatives are reported when the hedged transaction occurs. Accordingly, adoption of SFAS No. 133 will have an impact on the reported financial position of the Company, and although such impact has not been determined, it is currently not believed to be material. Adoption of SFAS No. 133 should have no significant impact on reported earnings, but could materially affect comprehensive income. Production Imbalances The Company has gas production imbalance positions that are the result of partial interest owners selling more or less than their proportionate share of gas on jointly owned wells. Imbalances are generally settled by disproportionate gas sales over the remaining life of the well or by cash payment by the overproduced party to the underproduced party. The Company uses the entitlement method of accounting for natural gas sales. At December 31, 1998, the Company’s consolidated balance sheet includes a net receivable of $4.9 million for a net underproduced balancing position of 885,000 Mcf of natural gas and 7,909,000 Mcf of carbon dioxide. Production imbalances do not have, and are not expected to have, a significant impact on the Company’s liquidity or operations. Forward-Looking Statements Certain information included in this Management’s Discussion and Analysis, as well as information included in other sections of this annual report, contain forward-looking statements relating to the Company’s operations and the oil and gas industry. Such forwardlooking statements are based on management’s current projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “believes,” “estimates” and similar words. These statements are not guarantees of future
Slide 24: Cross Timbers Oil Company MANAGEMENT’S DISCUSSION AND ANALYSIS performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from what is expressed or forecasted in such forward-looking statements. Among the factors that could cause actual results to differ materially are: •crude oil and natural gas price fluctuations •the Company’s ability to acquire oil and gas properties that meet its objectives and to identify prospects for drilling •potential delays or failure to achieve expected production from existing and future exploration and development projects •potential disruption of operations because of failure to achieve timely Year 2000 compliance by the Company or other entities with which it has material relationships, and •potential liability resulting from pending or future litigation. In addition, these forward-looking statements may be affected by general domestic and international economic and political conditions. Quantitative And Qualitative Disclosures About Market Risk The Company only uses derivative financial instruments for hedging purposes. These instruments principally include interest rate swap agreements and commodity futures, swaps, and option agreements. These financial and commodity-based derivative contracts are used to limit the risks of interest rate fluctuations and natural gas and crude oil price changes. Gains and losses on these derivatives are entirely offset by losses and gains on the respective hedged exposures. The Board of Directors has adopted a policy governing the use of derivative instruments, which requires that all derivatives used by the Company relate to an underlying, offsetting position, anticipated transaction or firm commitment, and prohibits the use of speculative, highly complex or leveraged derivatives. The policy also requires review and approval by the Executive Vice President of all risk management programs using derivatives and all derivative transactions. These programs are also periodically reviewed by the Board of Directors. Hypothetical changes in interest rates and prices chosen for the estimated sensitivity effects are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. It is not possible to accurately predict future changes in interest rates, product prices and investment market values. Accordingly, these hypothetical changes may not necessarily be an indicator of probable future fluctuations. Interest Rate Risk The Company is exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. The Company’s variable rate debt was approximately $620 million at December 31, 1998. The Company attempts to balance the benefit of lower cost variable rate debt that has inherent increased risk with more expensive fixed rate debt that has less market risk. This is accomplished through a mix of bank debt with short-term variable rates and fixed rate subordinated debt, as well as the use of interest (continued) rate swaps. During 1998, the Company entered into interest rate swap agreements that effectively convert interest rates from variable to fixed on $150 million principal through September 2005. The Company had no outstanding interest swap agreements during 1997. The following table shows the carrying amount and fair value of long-term debt and interest rate swaps, and the hypothetical change in fair value that would result from a 100-basis point change in interest rates: (in thousands) December 31, 1998 Long-term debt Interest rate swaps December 31, 1997 Long-term debt (539,000) (538,288) (20,656) $(921,000) – $(894,750) (2,722) $(17,000) (8,655) Carrying Amount Fair Value Hypothetical Change in Fair Value In February and March 1999, the Company terminated its interest rate swaps on notional balances totaling $100 million, resulting in proceeds received and a gain of $1.1 million. This gain will be amortized against interest expense through September 2005. In February 1999, the Company sold a call option that allows the counterparty to terminate the interest rate swap in September 2001 on the remaining $50 million notional balance, resulting in proceeds received of $800,000. This amount will be deferred until the option is exercised or expires. Commodity Price Risk The Company hedges a portion of the market risks associated with its crude oil and natural gas sales. During 1998, the Company primarily entered into gas futures contracts and gas basis swap agreements to reduce exposure to price volatility in the physical markets. As of December 31, 1998, outstanding futures contracts had a fair value of a gain of $3.5 million and outstanding basis swap agreements had a fair value of a loss of $0.7 million. These futures contracts and basis swap agreements are not recorded on the Company’s balance sheet. The Company did not have any significant commodity hedging activity in 1997. For these commodity derivatives that are permitted to be settled in cash or another financial instrument, sensitivity effects are as follows. At year-end 1998, the aggregate effect of a hypothetical 10% change in natural gas prices and basis would result in a $3 million change in the fair value of these financial instruments. This sensitivity does not include the effects of gas contracts that cannot be settled in cash or another financial instrument. See Note 6 to Consolidated Financial Statements. Investment in Equity Securities The Company is subject to price risk on its unhedged portfolio of publicly traded investments in equity securities of energy companies. These securities were classified as trading securities as of year-end 1998. The fair value of these securities at December 31, 1998 was $44.4 million. At year-end 1998, a 25% appreciation or depreciation in equity price would increase or decrease portfolio fair value and pre-tax earnings by approximately $11 million. As of March 1, 1999, the Company had incurred a 1999 pre-tax loss on its investment in equity securities of $8 million, of which $17.5 million was a realized loss, partially offset by a $9.5 million decrease in unrealized loss.
Slide 25: Cross Timbers Oil Company CONSOLIDATED BALANCE SHEETS December 31 In thousands 1998 1997 ASSETS Current assets: Cash and cash equivalents Accounts receivable, net (Note 8) Investment in equity securities (Note 2) Deferred income tax benefit (Note 5) Other current assets Total Current Assets Property and equipment, at cost – successful efforts method (Notes 1 and 4): Producing properties Undeveloped properties Gas gathering and other Total property and equipment Accumulated depreciation, depletion and amortization Net Property and Equipment Other Assets Loans to Officers (Note 3) Total Assets $ 0012,333 50,607 44,386 24,816 5,436 137,578 $(003,816 43,996 – 445 3,905 52,162 1,335,844 6,845 27,829 1,370,518 (319,507) 1,051,011 13,210 5,795 $1,207,594 931,259 6,406 23,703 961,368 (237,532) 723,836 12,457 – $(788,455 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable and accrued liabilities Payable to Royalty Trust Short-term debt (Note 4) Accrued stock incentive compensation (Note 11) Total Current Liabilities Long-term Debt (Note 4) Deferred Income Taxes Payable (Note 5) Other Long-term Liabilities (Note 6) Commitments and Contingencies (Note 6) Stockholders’ equity (Note 7): Series A convertible preferred stock ($.01 par value, 25,000,000 shares authorized, 1,138,729 issued, at liquidation value of $25) Common stock ($.01 par value, 100,000,000 shares authorized, 54,048,227 and 46,310,710 shares issued) Additional paid-in capital Treasury stock (9,320,971 and 6,860,779 shares) Retained earnings (deficit) Total Stockholders’ Equity Total Liabilities and Stockholders’ Equity See accompanying notes to consolidated financial statements. $ 93,583 968 4,962 75 99,588 921,000 6,892 2,663 $(052,266 2,073 – 554 54,893 539,000 21,320 2,999 28,468 541 338,503 (118,555) (71,506) 177,451 $1,207,594 28,468 463 210,954 (76,656) 7,014 170,243 $(788,455
Slide 26: Cross Timbers Oil Company CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31 In thousands, except per share data 1998 1997 1996 REVENUES Oil and condensate Gas and natural gas liquids Gas gathering, processing and marketing Other Total Revenues EXPENSES Production Exploration Taxes, transportation and other Depreciation, depletion and amortization Impairment (Note 1) General and administrative (Note 11) Gas gathering and processing Trust development costs Total Expenses OPERATING INCOME OTHER INCOME (EXPENSE) Gain (loss) on investment in equity securities (Note 2) Interest expense, net Total Other Income (Expense) INCOME (LOSS) BEFORE INCOME TAX Income Tax Expense (Benefit) (Note 5) NET INCOME (LOSS) Preferred stock dividends EARNINGS (LOSS) AVAILABLE TO COMMON STOCK EARNINGS (LOSS) PER COMMON SHARE (Notes 1 and 9) Basic Diluted Weighted Average Common Shares Outstanding See accompanying notes to consolidated financial statements. $056,164 182,587 9,438 1,297 249,486 $075,223 110,104 9,851 3,094 198,272 $075,013 73,402 12,032 888 161,335 63,148 8,034 29,105 83,560 2,040 13,479 8,360 1,498 209,224 40,262 43,580 2,088 16,405 47,721 – 15,818 8,517 665 134,794 63,478 39,365 – 11,944 37,858 – 16,420 6,905 854 113,346 47,989 (93,719) (52,113) (145,832) (105,570) (35,851) (69,719) 1,779 $ (71,498) 1,735 (26,012) (24,277) 39,201 13,517 25,684 1,779 $023,905 (893) (16,123) (17,016) 30,973 10,669 20,304 514 $019,790 $ $ (1.65) (1.65) 43,396 $0000.60 $0000.59 39,773 $ 000.50 $ 000.48 39,913
Slide 27: Cross Timbers Oil Company CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Year Ended December 31 In thousands 1998 $0(69,719) 1997 $(025,684 1996 $020,304 NET INCOME (LOSS) OTHER COMPREHENSIVE INCOME Unrealized gains on available-for-sale securities (Note 2): Unrealized holding gains Less realized gains included in net income Other Comprehensive Income (Loss) Before Tax Income tax benefit (expense) related to other comprehensive income Other Comprehensive Income (Loss) COMPREHENSIVE INCOME (LOSS) See accompanying notes to consolidated financial statements. – – – – – $0(69,719) 1,434 (2,400) (966) 328 (638) $(025,046 1,022 (56) 966 (328) 638 $020,942
Slide 28: Cross Timbers Oil Company CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31 In thousands (Note 10) 1998 1997 1996 OPERATING ACTIVITIES Net income (loss) Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities: Depreciation, depletion and amortization Impairment Exploration Stock incentive compensation Deferred income tax (Gain) loss from sale of properties and equity securities Other non-cash items Changes in current assets and liabilities (a) Cash Provided (Used) by Operating Activities INVESTING ACTIVITIES Proceeds from sale of long-term investment in equity securities Long-term investment in equity securities Proceeds from sale of property and equipment Property acquisitions Exploration and development costs Gas plant, gathering and other additions Loans to officers Cash Used by Investing Activities FINANCING ACTIVITIES Proceeds from long-term debt Payments on long-term debt Common stock offering Dividends Stock option exercises and other Purchases of treasury stock Cash Provided by Financing Activities INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS Cash and Cash Equivalents, January 1 Cash and Cash Equivalents, December 31 877,900 (496,938) 133,113 (8,460) (269) (66,389) 438,957 8,517 3,816 $ 012,333 688,400 (437,430) – (7,571) 750 (30,954) 213,195 (121) 3,937 $00(3,816 188,000 (81,200) – (5,339) 364 (34,923) 66,902 1,725 2,212 $(003,937 – – 2,494 (296,390) (77,390) (7,517) (5,795) (384,598) 24,626 (6,479) 17,972 (238,294) (90,470) (18,677) – (311,322) 402 (16,093) 37,388 (109,535) (32,291) (4,742) – (124,871) $0(69,719) $(025,684 $(020,304 83,560 2,040 8,034 1,141 (35,744) 86,628 2,540 (124,322) (45,842) 47,721 – 2,088 3,386 13,393 (4,157) 1,864 8,027 98,006 37,858 – – (853) 10,213 (576) 1,317 (8,569) 59,694 (a) Changes in Current Assets and Liabilities Accounts receivable Investment in equity securities (purchases net of sales) Other current assets Accounts payable, accrued liabilities and payable to Royalty Trust Decrease (Increase) in Current Assets and Liabilities See accompanying notes to consolidated financial statements. $ 0((7,022) (131,809) (1,513) 16,022 $(124,322) $0000246 – (970) 8,751 $0(08,027 $0(16,999) – (1,683) 10,113 $00(8,569)
Slide 29: Cross Timbers Oil Company CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY Shares Preferred Stock – – – – Stockholders’ Equity Treasury Stock $ (528) (1,038) (7,931) (30,722) Retained Earnings (Deficit) $(25,626) – – – In thousands (Note 7) Common Stock Additional In Preferred Common Paid-in Issued Treasury Stock Stock Capital 41,434 168 996 – 69 106 768 2,925 $ – – – – $ 414 2 10 – $156,440 2,673 7,189 – Balances, December 31, 1995 Issuance/vesting of performance shares Stock option exercises Treasury stock purchases Exchange of Series A convertible preferred stock for common stock Conversion of subordinated convertible notes to common stock Common stock dividends ($0.13 per share) Preferred stock dividends ($0.45 per share) Net income Balances, December 31, 1996 Issuance/vesting of performance shares Stock option exercises Treasury stock purchases Conversion of subordinated convertible notes to common stock Issuance of warrants Common stock dividends ($0.15 per share) Preferred stock dividends ($1.56 per share) Net income Balances, December 31, 1997 Sale of common stock Issuance/vesting of performance shares Stock option exercises Treasury stock purchases Treasury stock issued Common stock dividends ($0.16 per share) Preferred stock dividends ($1.56 per share) Net loss Balances, December 31, 1998 1,139 (2,979) – 28,468 (30) (28,978) – – – – – – 1,139 – – – 2,696 – – – 42,315 180 924 – – – – – 3,868 76 566 2,351 – – – – 28,468 – – – 27 – – – 423 2 9 – 27,112 – – – 164,436 3,431 8,183 – – – – – (40,219) (1,098) (7,326) (28,013) – (5,242) (514) 20,304 (11,078) – – – – – – – – 1,139 – – – – – – – – 1,139 2,892 – – – – 46,311 7,203 82 452 – – – – – 54,048 – – – – – 6,861 – 27 25 4,330 (1,922) – – – 9,321 – – – – – 28,468 – – – – – – – – $28,468 29 – – – – 463 72 1 5 – – – – – $ 541 29,179 5,725 – – – 210,954 133,041 1,804 2,986 – (10,282) – – – $338,503 – – – – – (76,656) – (536) (483) (65,575) 24,695 – – – $(118,555) – – (5,813) (1,779) 25,684 7,014 – – – – – (7,022) (1,779) (69,719) $(71,506) See accompanying notes to consolidated financial statements.
Slide 30: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Summary of Significant Accounting Policies Cross Timbers Oil Company, a Delaware corporation, was organized in October 1990 to ultimately acquire the business and properties of predecessor entities that were created from 1986 through 1989. Cross Timbers Oil Company completed its initial public offering of common stock in May 1993. The accompanying consolidated financial statements include the financial statements of Cross Timbers Oil Company and its wholly owned subsidiaries (“the Company”). All significant intercompany balances and transactions have been eliminated in the consolidation. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. All common stock shares and per share amounts in the accompanying financial statements have been adjusted for the three-fortwo stock splits effected on March 19, 1997 and February 25, 1998 (Note 7). The Company is an independent oil and gas company with production and exploration concentrated in Texas, Oklahoma, Kansas, New Mexico, Wyoming and Alaska. The Company also gathers, processes and markets gas, transports and markets oil and conducts other activities directly related to the oil and gas producing industry. Property and Equipment The Company follows the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. The Company generally pursues acquisition and development of proved reserves, although the Company increased its exploration activities in 1997 and 1998. Most of the property costs reflected in the accompanying consolidated balance sheets are from acquisitions of producing properties from other oil and gas companies. Producing properties balances include costs of $15,859,000 at December 31, 1998 and $26,570,000 at December 31, 1997, related to wells in progress of drilling. Depreciation, depletion and amortization of producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. Other property and equipment is generally depreciated using the straight-line method over estimated useful lives which range from 3 to 40 years. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized. The estimated undiscounted cost, net of salvage value, of dismantling and removing major oil and gas production facilities, including necessary site restoration, are accrued using the unit-of-production method. Effective October 1, 1995, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. When impairment review is necessary, the carrying value of property, plant and equipment intended to be retained is compared to management’s future estimated pretax cash flow. If impairment is necessary, the asset carrying value is adjusted to fair value. Cash flow pricing estimates are based on existing reserve and production information and pricing assumptions that management believes are reasonable. Generally, for producing properties, the review considers proved reserves, though probable reserves and other conditions are considered if warranted. Impairment of individually significant undeveloped properties is assessed on a property-by-property basis and impairment of other undeveloped properties is assessed and amortized on an aggregate basis. The Company recorded an impairment provision on producing properties of $2,040,000 before income tax in 1998. Cross Timbers Royalty Trust The Company makes monthly net profits payments to Cross Timbers Royalty Trust based on revenues and costs related to properties from which net profits interests were carved. Net profits payments to the Cross Timbers Royalty Trust are generally based on revenues received and costs disbursed by the Company in the prior month. For financial reporting purposes, the Company reduces oil and gas revenues and taxes on production for amounts allocated to the Cross Timbers Royalty Trust. The Cross Timbers Royalty Trust’s portion of development costs are expensed as trust development costs in the accompanying consolidated statements of operations. The Company owned approximately 22% of the Cross Timbers Royalty Trust publicly traded units at December 31, 1998 and 1997. Cross Timbers Royalty Trust units are traded on the New York Stock Exchange under the symbol “CRT.” Hugoton Royalty Trust In December 1998, the Company formed the Hugoton Royalty Trust by conveying an 80% net profits interest in properties that are principally located in the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. These properties represent approximately 30% of the Company’s existing reserve base. The Company filed a registration statement with the Securities and Exchange Commission (“Commission”) in December 1998 and plans to offer approximately 40% of the trust units to the public in March or April 1999. The trust units will be listed on the New York Stock Exchange under the symbol “HGT.” Cash and Cash Equivalents Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less. Investment in Equity Securities In accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities, equity securities acquired during 1998 have been recorded as trading securities since such securities were acquired principally for resale in the near future. Accordingly, such investment at December 31, 1998 has been recorded as a current asset at market value, unrealized holding gains and losses have been recognized in the consolidated statement of operations, and cash flows from purchases and sales of equity securities have been included in cash provided (used) by operating activities in the consolidated statement of cash flows. Gains (losses) on trading securities and interest related to the cost of these investments have been classified as other income (expense). Such gains (losses) were previously classified as other revenue and interest related to such investments was previously classified as interest expense. Prior to 1998, the Company’s investments in equity securities were recorded as available-for-sale securities. As a result, such investments were recorded as long-term assets at market value, unrealized holding gains and losses were recorded as a separate component of stockholders’ equity and cash flows from purchases and sales of equity securities were included in cash provided (used) by investing activities. See Note 2.
Slide 31: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Other Assets Other assets primarily include deferred debt costs that are amortized over the term of the related debt (Note 4). Other assets are presented net of accumulated amortization of $4,697,000 at December 31, 1998 and $2,860,000 at December 31, 1997. Derivatives The Company uses derivatives on a limited basis to hedge interest rate and product price risks, as opposed to their use for trading purposes. Amounts receivable or payable under interest swap agreements are recorded as adjustments to interest expense. Gains and losses on commodity futures contracts and other price risk management instruments are recognized in oil and gas revenues when the hedged transaction occurs. Cash flows related to derivative transactions are included in operating activities. See Note 8. Production Imbalances The Company uses the entitlement method of accounting for gas sales, based on the Company’s net revenue interest in production. Accordingly, revenue is deferred when gas deliveries exceed the Company’s net revenue interest, while revenue is accrued for underdeliveries. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. At December 31, 1998, the Company recorded a net receivable of $4,904,000 for a net underproduced balancing position of 885,000 Mcf of natural gas and 7,909,000 Mcf of carbon dioxide. At December 31, 1997, the Company recorded a net receivable of $5,054,000 for a net underproduced balancing position of 1,114,000 Mcf of natural gas and 8,049,000 Mcf of carbon dioxide. Gas Gathering, Processing and Marketing Revenues Gas produced by the Company and third parties is marketed by the Company to brokers, local distribution companies and end-users. Gas gathering and marketing revenues are recognized in the month of delivery based on customer nominations. Gas processing and marketing revenues are recorded net of cost of gas sold of $56.3 million for 1998, $57.1 million for 1997 and $56.4 million for 1996. These amounts are net of intercompany eliminations. Other Revenues Other revenues include gains and losses from sale of property and equipment. The Company realized gains on sale of property and equipment of $795,000 in 1998, $1,757,000 in 1997 and $520,000 in 1996. Exploration Expense During 1998, the Company incurred $8 million of exploration costs, primarily composed of geological and geophysical costs related to the 1998 exploration program. Exploration costs were $2.1 million in 1997. Interest Expense Interest expense includes amortization of deferred debt costs and is presented net of interest income of $91,000 in 1998, $71,000 in 1997 and $152,000 in 1996, and net of capitalized interest of $1,070,000 in 1998 and $1,185,000 in 1997. No interest was capitalized in 1996. Stock-Based Compensation In accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, no compensation is recorded for stock options or other stock-based awards that are granted to employees with an exercise price equal to or above the common stock price on the grant date. Compensation related to performance share grants is recognized from the grant date until the performance conditions are satisfied, based on the market price of the Company’s common stock. The pro forma effect of recording stock-based compensation at the estimated fair value of awards on the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, is disclosed in Note 11. Earnings per Common Share Effective December 31, 1997, the Company adopted SFAS No. 128, Earnings Per Share, which changed the method of computing and disclosing earnings per share for all periods. Under SFAS No. 128, the Company must report basic earnings per share, which excludes the effect of potentially dilutive securities, and diluted earnings per share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The Company previously only reported earnings per share excluding potentially dilutive securities because their effect was antidilutive or less than 3% dilutive, as prescribed by the accounting pronouncement superseded by SFAS No. 128. See Note 9. Earnings (loss) per common share for all periods presented is based on weighted average common shares outstanding as adjusted for the three-for-two stock splits on March 19, 1997 and February 25, 1998 (Note 7). Segment Reporting In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, the Company has identified only one operating segment, which is the exploration and production of oil and gas. All the Company’s assets are located in the United States and all its revenues are attributable to United States customers. There were no sales to a single purchaser that exceeded 10% of total revenues in 1998. In 1997, gas sales to one purchaser were approximately 14% of total revenues. In 1996, gas sales to two purchasers were approximately 15% and 14% of total revenues. Recent Accounting Pronouncements In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, which is required to be adopted for fiscal years beginning after June 15, 1999. SFAS No. 133 requires that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either a) offset by the change in fair value of the hedged asset or liability (if applicable) or b) reported as a component of other comprehensive income in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. The definition of derivatives has also been expanded to include contracts that require physical delivery of oil and gas if the contract allows for net cash settlement. The Company primarily uses derivatives to hedge product price and interest rate risks. Such derivatives are reported at cost, if any, and gains and losses on such derivatives are reported when the hedged transaction occurs. Accordingly, the Company’s adoption of SFAS No. 133 will have an impact of the reported financial position of the Company, and although such impact has not been determined, it is currently not believed to be material. Adoption of SFAS No. 133 should have no significant impact on reported earnings, but could materially affect comprehensive income.
Slide 32: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Investment in Equity Securities The Company periodically invests in publicly traded equity securities of select energy companies which it believes to be undervalued. Since classified as trading securities, this investment at December 31, 1998 is recorded as a current asset at market value. Realized gains and losses are computed based on a first-in, first-out determination of cost of securities sold. After sale of its current investment, the Company does not plan to make future investments in equity securities of other energy companies. The following are components of gain (loss) on investment in equity securities (in thousands): 1998 Realized gains (losses) on sale of securities: Gains Losses Net gains (losses) Unrealized gains (losses) (a) Interest expense related to investment in equity securities Gains (losses) on investment in equity securities $ 887 (15,706) (14,819) (72,605) (6,295) $ (93,719) 1997 $2,400 – 2,400 – (665) $1,735 1996 $ 56 – 56 – (949) $ (893) (continued) sales and the Amoco Acquisition. These consulting fees are effectively capitalized as a portion of property cost. 4. Debt The Company’s outstanding debt consists of the following (in thousands): December 31 1998 Short-term Debt: Short-term borrowings, 7.4% at December 31, 1998 Reclassified to long-term debt Total short-term debt Long-term Debt: Senior debt – Bank debt under revolving credit agreements due June 30, 2003, 6.9% at December 31, 1998 Subordinated debt – 91⁄4% senior subordinated notes due April 1, 2007 83⁄4% senior subordinated notes due November 1, 2009 Other long-term debt Sub-total long-term debt Reclassified from short-term debt Total long-term debt $ 4,962 – $ 4,962 1997 $ 10,000 (10,000) $ – $615,000 125,000 175,000 6,000 921,000 – $921,000 $229,000 125,000 175,000 – 529,000 10,000 $539,000 (a) Because investments in equity securities were recorded as available-for-sale securities prior to 1998, unrealized gains and losses for 1997 and 1996 are reported as a component of stockholders’ equity, as shown in the Consolidated Statements of Comprehensive Income. As of March 1, 1999 the Company had incurred a 1999 pre-tax loss on its investment in equity securities of $8 million, of which $17.5 million was a realized loss, partially offset by a $9.5 million decrease in unrealized loss. 3. Related Party Transactions Loans to Officers Pursuant to margin support agreements with each of six officers, the Company agreed to use the value of its investments in equity securities (Note 2) to provide margin support for the officers’ broker accounts in which they held Company common stock. In August 1998, the Board of Directors authorized these agreements so that the officers would not be forced to sell Company common stock, particularly at depressed prices, potentially creating further downward pressure on the stock price. These agreements provide that each officer cannot purchase additional securities in his broker account, or engage in any transaction that would increase the margin requirements for his account, including withdrawal of any funds or securities. The Company also has agreed to pay each officer’s margin debt to the extent unpaid by the officer. In connection with these agreements, in December 1998 the Company loaned four officers a total of $5,795,000 to reduce their margin debt. In January and February 1999, an additional $430,000 was loaned. These loans are full recourse and due in five years, with interest equal to the Company’s bank debt rates (Note 4). Total officer margin debt on their broker accounts at March 1, 1999 was $11.2 million. Other Transactions A director-related company performed consulting services in 1998 in connection with the Cook Inlet Acquisition (Note 12). After the Company recovers its acquisition costs, including interest and subsequent property development and operating costs, the directorrelated company will receive, at its election, either a 20% working interest or a 1% overriding interest conveyed from the Company’s 100% working interest in these properties. In 1997, the Company paid fees of $1.6 million to this director-related company in connection with property Senior Debt On November 16, 1998, the Company entered into a new Revolving Credit Agreement with commercial banks (“loan agreement”). As of December 31, 1998, the loan agreement had a borrowing base and commitment of $615 million with no unused borrowing capacity. The borrowing base is redetermined annually based on the value and expected cash flow of the Company’s proved oil and gas reserves. If borrowings exceed the redetermined borrowing base, the banks may require that the excess be repaid within a year. Otherwise, borrowings under the loan agreement do not mature until June 30, 2003, but may be prepaid at any time without penalty. The Company periodically renegotiates the loan agreement to increase the borrowing commitment and extend the revolving facility. The borrowing base is scheduled to be redetermined in June 1999. Based on year-end proved reserves, the Company does not expect a reduction in the borrowing base upon its redetermination. Reclassification of short-term to long-term debt at December 31, 1997 represents unused capacity under the loan agreement based on outstanding debt balances at that date. Restrictions set forth in the loan agreement include limitations on the incurrence of additional indebtedness, the creation of certain liens, and the redemption or prepayment of subordinated indebtedness. The loan agreement also limits dividends to 25% of cash flow from operations for the latest four consecutive quarterly periods. The Company is also required to maintain a current ratio of not less than one (where unused borrowing commitments are included as a current asset). The loan agreement provides the option of borrowing at floating interest rates based on the prime rate or at fixed rates for periods of up to six months based on certificate of deposit rates or London Interbank Offered Rates (“LIBOR”). Borrowings under the loan agreement at December 31, 1998 were based on LIBOR rates with a maturity of one to six months and accrued at the applicable LIBOR rate plus 1 3⁄8%. Interest is paid at maturity, or quarterly if the term is for a period of 90 days or more. The Company also incurs a commitment fee of 3⁄8% on unused borrowing commitments. The weighted average interest rate on senior debt was 6.9% during 1998 and 1997 and 6.7% during 1996. See Note 8 regarding interest rate swap agreements.
Slide 33: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Subordinated Debt The Company sold $125 million of 91⁄4% senior subordinated notes (“9 1⁄4% Notes”) on April 2, 1997, and $175 million of 83⁄4% senior subordinated notes (“8 3⁄4% Notes”) on October 28, 1997 (the 91⁄4% Notes and the 83⁄4% Notes collectively referred to as “the Notes”). The Notes are general unsecured indebtedness that is subordinate to bank borrowings under the loan agreement. Net proceeds of $121.1 million from the 91⁄4% Notes and $169.9 million from the 8 3⁄4% Notes were used to reduce bank borrowings under the loan agreement. The 91⁄4% Notes mature on April 1, 2007 and interest is payable each April 1 and October 1, while the 8 3⁄4% Notes mature on November 1, 2009 with interest payable each May 1 and November 1. The Company has the option to redeem the 91⁄4% Notes on April 1, 2002 and the 8 3⁄4% Notes on November 1, 2002 at a price of approximately 105%, and thereafter at prices declining ratably at each anniversary to 100% in 2005. In addition, on or prior to April 1, 2000 for the 9 1⁄4% Notes and November 1, 2000 for the 8 3⁄4% Notes, the Company may redeem up to one-third of the Notes with the net proceeds from one or more public equity offerings at a price of approximately 109% plus accrued interest, subject to certain requirements. Upon a change in control of the Company, the holders of the Notes have the right to require the Company to purchase all or a portion of their Notes at 101% plus accrued interest. The Notes were issued under indentures that place certain restrictions on the Company, including limitations on additional indebtedness, liens, dividend payments, treasury stock purchases, disposition of proceeds from asset sales, transfers of assets and transactions with subsidiaries and affiliates. To reduce the interest rate on a portion of its subordinated debt, the Company has entered an agreement with a bank that has purchased on the market Notes with a face value of $21.6 million. The Company pays the bank a variable interest rate based on three-month LIBOR rates, and receives semiannually from the bank the fixed interest rate on the Notes. The term of the agreement for approximately half the Notes is through April 2002, and for the remaining half is through November 2002. Any change in market value of the Notes from the date purchased by the bank is payable to or receivable from the bank. The Company funded market value depreciation of $169,000 in January 1999. The Company has the option of repurchasing the Notes from the bank at any time at market value. Other Debt As part of the Cook Inlet Acquisition, the Company executed a $6 million non-interest bearing promissory note payable to Shell. Payments of $3 million, $2 million and $1 million are due when the average NYMEX crude oil price for 60 consecutive calendar days equals or exceeds $18.50, $19.50 and $20.50, respectively. See also Note 7 “–Registration Statement.” 5. Income Tax The effective income tax rate for the Company was different than the statutory federal income tax rate for the following reasons (in thousands): 1998 Income tax expense (benefit) at the federal statutory rate of 34% State and local taxes and other Income tax expense (benefit) $(35,893) 42 $(35,851) 1997 $13,329 188 $13,517 1996 $10,531 138 $10,669 Components of income tax expense (benefit) are as follows (in thousands): 1998 Current income tax Deferred income tax expense (benefit) Net operating loss carryforward Income tax expense (benefit) $ (107) (2,626) (33,118) $ 1997 1996 124 $ 456 22,509 13,152 (9,116) (2,939) $10,669 $(35,851) $13,517 Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. The Company’s net deferred tax liabilities are recorded as a current asset of $24,816,000 and a long-term liability of $6,892,000 at December 31, 1998, and a current asset of $445,000 and a long-term liability of $21,320,000 at December 31, 1997. Significant components of net deferred tax assets and liabilities are (in thousands): December 31 1998 Deferred tax assets: Net operating loss carryforwards Trust development expenses Accrued stock appreciation right and performance share compensation Unrealized loss on trading securities Other Total deferred tax assets Deferred tax liabilities: Intangible development costs Tax depletion and depreciation in excess of financial statement amounts Other Total deferred tax liabilities Net deferred tax assets (liabilities) $54,044 4,454 576 24,686 2,626 86,386 48,913 16,894 2,655 68,462 $17,924 1997 $ 20,926 3,959 739 – 1,593 27,217 37,856 8,008 2,228 48,092 $(20,875) As of December 31, 1998, the Company has estimated tax loss carryforwards of approximately $160 million, of which $10 million are related to capital losses. The capital loss tax carryforwards expire in 2003 while the remaining $150 million are scheduled to expire in 2008 through 2013. The Company believes it will be able to realize its deferred tax asset, as it plans to utilize its tax loss carryforwards through gains generated from the sale of Hugoton Royalty Trust units and non-strategic asset sales which are to begin in 1999. 6. Commitments and Contingencies Leases The Company leases offices, vehicles and certain other equipment in its primary locations under non-cancelable operating leases. As of December 31, 1998, minimum future lease payments for all noncancelable lease agreements (including the sale and operating leaseback agreements described below) were as follows (in thousands): 1999 2000 2001 2002 2003 Remaining Total $ 7,528 7,177 6,968 6,886 6,858 6,548 $41,965 Amounts incurred by the Company under operating leases (including renewable monthly leases) were $11,180,000 in 1998, $9,132,000 in 1997 and $5,489,000 in 1996.
Slide 34: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In March 1996, the Company sold its Tyrone gas processing plant and related gathering system for $28 million and entered an agreement to lease the facility from the buyers for an initial term of eight years at annual rentals of $4 million, and with fixed renewal options for an additional 13 years. The Company does not have the right or option to purchase, nor does the lessor have the obligation to sell the facility at any time. However, if the lessor decides to sell the facility at the end of the initial term or any renewal period, the lessor must first offer to sell it to the Company at its fair market value. Additionally, the Company has a right of first refusal of any third party offers to buy the facility after the initial term. This transaction has been recorded as a sale and operating leaseback, with no gain or loss on the sale. Proceeds of the sale were used to reduce bank debt. In November 1996, the Company sold its gathering system in Major County, Oklahoma for $8 million and entered an agreement to lease the facility from the buyers for an initial term of eight years, with fixed renewal options for an additional 10 years. Rentals are adjusted monthly based on the 30-day LIBOR rate (Note 4) and may be irrevocably fixed by the Company with 20 days advance notice. As of December 31, 1998, annual rentals were $1.7 million. The Company does not have the right or option to purchase, nor does the lessor have the obligation to sell the facility at any time. However, if the lessor decides to sell the facility at the end of the initial term or any renewal period, the lessor must first offer to sell it to the Company at its fair market value. Additionally, the Company has a right of first refusal of any third party offers to buy the facility after the initial term. This transaction has been recorded as a sale and operating leaseback, with a deferred gain of $3.4 million on the sale. The deferred gain is amortized over the lease term based on pro rata rentals and is recorded in other long-term liabilities in the accompanying balance sheet. Proceeds of the sale were used to reduce bank debt. Employment Agreements Two executive officers have entered into year-to-year employment agreements with the Company. The agreements are automatically renewed each year-end unless terminated by either party upon thirty days notice prior to each December 31. Under these agreements, each of the officers receives a minimum annual salary of $300,000 and is entitled to participate in any incentive compensation programs administered by the Board of Directors. The agreements also provide that, in the event the officer terminates his employment for good reason, as defined in the agreement, the officer will receive severance pay equal to the amount that would have been paid under the agreement had it not been terminated. If such termination follows a change in control of the Company, the officer is entitled to a lump-sum payment of three times his most recent annual compensation. Gas Sales Contracts The Company has entered into 1999 futures contracts to sell 175,000 Mcf per day in April at $1.98 per Mcf, 160,000 Mcf per day in May and June at $1.96 per Mcf, 40,000 Mcf per day in July at $2.00 per Mcf, 50,000 Mcf per day in August and September at $2.04 per Mcf and 30,000 Mcf per day in October through December at an average of $2.13 per Mcf. Prices to be realized for hedged production may be less than these hedged prices because of location, quality and other adjustments. The Company has entered into basis swap agreements that effectively fix the San Juan Basin basis at $0.25 per Mcf for 30,000 Mcf per day for April and May 1999 and 20,000 Mcf per day from June through December 1999, and $0.28 per Mcf for 10,000 Mcf per day from January through December 2000. The Company has basis swap agreements that effectively fix the Wyoming basis at $0.27 per Mcf for (continued) 15,000 Mcf per day for April 1999 and 10,000 Mcf per day from May through December 1999. The Company also has basis swap agreements that effectively fix Oklahoma basis at $0.13 per Mcf for 10,000 Mcf per day for April 1999 through December 1999. The Company’s termination of futures contracts related to first quarter 1999 gas production, net of the effects of basis swap agreements, resulted in a net gain of $6.4 million. This gain will be recognized as additional gas revenue of approximately $0.25 per Mcf in the first quarter of 1999. The Company has committed a minimum gas sales price of $2.00 per Mcf for gas sales related to April 1999 through March 2000 distributions of the Hugoton Royalty Trust. The Company plans to sell approximately 40% of Hugoton Royalty Trust units to the public in March or April 1999. The underlying volumes for units to be sold to the public are approximately 36,000 Mcf per day. Under the terms of its amended purchase and sale agreement with Shell for the Cook Inlet Acquisition (Note 12), the Company has committed to sell to Shell 20,000 Mcf of gas per day from March 1, 1999 through 2003 in the San Juan Basin with an estimated basis differential of $0.24 per Mcf. The Company has also agreed to sell Shell in East Texas daily gas volumes of 22,000 Mcf in 1999, 20,000 Mcf in 2000, 17,500 Mcf in 2001, 16,500 Mcf in 2002 and 15,000 Mcf in 2003 at the index price less a weighted average transportation fee of $0.24 per Mcf. The Company has committed to sell all gas production from certain properties in the East Texas Basin Acquisition to EEX Corporation at market prices through the earlier of December 31, 2001, or until a total of approximately 34.3 billion cubic feet (27.8 billion cubic feet net to the Company’s interest) of gas has been delivered. Based on current production, this sales commitment is approximately 24,700 Mcf (20,000 Mcf net to the Company’s interest) per day. From August 1995 through July 1998 the Company received an additional $0.30 to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, the Company has agreed to sell 11,650 Mcf per day from August 1998 through May 2000 at the index price and 21,650 Mcf per day from June 2000 through July 2005 at a contract price of approximately 10% of the month’s average NYMEX futures contract for West Texas Intermediate crude oil, adjusted for point of physical delivery. Section 29 Tax Credits The Company has entered contracts to monetize Section 29 tax credits generated by production from qualified properties, most of which were acquired in December 1997. As a result, the Company received approximately $2.9 million in 1998 and anticipates receiving approximately $2.8 million annually from 1999 through 2002 which will be recorded as gas revenue. Litigation On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross Timbers Oil Company, was filed against the Company in the District Court of Dewey County, Oklahoma. The action was filed on behalf of all persons who, at any time since June 1991, have been paid royalties on gas produced from any gas well within the State of Oklahoma under which the Company has assumed the obligation to pay royalties. The plaintiffs allege that the Company has reduced royalty payments by postproduction deductions and has entered into contracts with subsidiaries that were not arms-length transactions, which actions reduced the royalties paid to the plaintiffs and those similarly situated, and that such actions are a breach of the leases under which the royalties are paid. The plaintiffs are seeking an accounting and payment of the monies allegedly owed to them. The Company filed motions to dismiss the action due to lack of proper venue, which motions were denied.
Slide 35: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The decision denying the motions is being appealed. A hearing on the class certification issue has not been scheduled. Management believes it has strong defenses against this claim and intends to vigorously defend the action. Management’s estimate of the potential liability from this claim has been accrued in the Company’s financial statements. On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District Court for the Western District of Oklahoma against the Company and certain of its subsidiaries by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the False Claims Act. The Company was not made aware of the claim until the U.S. Justice Department contacted the Company in August 1998. The plaintiff alleges that the Company underpaid royalties on gas produced from federal leases and lands owned by Native Americans by at least 20% during the past 10 years as a result of mismeasuring the volume of gas and incorrectly analyzing its heating content. The plaintiff seeks to recover the amount of royalties not paid, together with treble damages, a civil penalty of $5,000 to $10,000 for each violation and attorney fees and expenses. The Company has not been served with this complaint that is under review by the U.S. Justice Department. The Company has filed a response with the U.S. Justice Department and is awaiting its decision whether to intervene in the case. The Company believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. The Company is involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. Company management and legal counsel do not believe that the ultimate resolution of these claims, including the lawsuits described above, will have a material effect on the Company’s financial position, liquidity or operations. Other To date, the Company’s expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, developments such as new regulations, enforcement policies or claims for damages could result in significant future costs. See also Notes 3 and 12. 7. Equity Three-for-Two Stock Split The Company effected a three-for-two common stock split on February 25, 1998 and March 19, 1997. All common stock shares, treasury stock shares and per share amounts have been retroactively restated to reflect these stock splits. Common Stock On April 27, 1998, the Company completed a public offering of 7,500,000 shares of common stock, of which 7,203,450 shares were sold by the Company and 296,550 shares were sold by a stockholder. The Company’s net proceeds from the offering of $133.1 million were used to partially repay bank debt used to fund the East Texas Basin Acquisition that closed on April 24, 1998 (Note 12). The offering was made pursuant to the shelf registration statement filed with the Commission in February 1998. See “–Registration Statement” below. On September 30, 1998, the Company issued from treasury 1,921,850 shares to Shell Western E&P, Inc., Shell Deepwater Development Holdings, Inc., and Shell Offshore Inc. (“Shell”) for the Cook Inlet Acquisition (Note 12). As of December 31, 1998, these shares are valued at $7.50 per share, or a total of $14.4 million. The Company effectively guaranteed Shell a $20 per share value, resulting in an accrued liability of $12.50 per share, or a total of $24 million, that is included in accounts payable and accrued liabilities in the accompanying consolidated balance sheet at December 31, 1998. Performance Shares The Company issued performance shares totaling 82,125 shares in 1998, 180,000 shares in 1997 and 167,625 shares in 1996 (Note 11). Treasury Stock The Company’s treasury share acquisitions totaled 4,373,138 shares in 1998 at an average cost of $15.19 per share, 2,571,396 shares in 1997 at an average cost of $12.06 per share and 3,341,515 shares in 1996 at an average cost of $10.45 per share. Additionally, the Company received 8,904 shares in 1998, 421,212 shares in 1997 and 457,994 shares in 1996 that are held in treasury, as payment for the option price upon exercise of stock options. Shareholder Rights Plan On August 25, 1998, the Board of Directors adopted a shareholder rights plan that is designed to assure that all shareholders receive fair and equal treatment in the event of any proposed takeover of the Company. Under this plan, a dividend of one preferred share purchase right (“Right”) was declared for each outstanding share of common stock, par value $.01 per share, payable on September 15, 1998 to shareholders of record on that date. Each Right entitles shareholders to buy one one-thousandth of a share of newly created Series A Junior Participating Preferred Stock at an exercise price of $80, subject to adjustment in the event a person acquires, or makes a tender or exchange offer for, 15% or more of the outstanding common stock. In such event, each Right entitles the holder (other than the person acquiring 15% or more of the outstanding common stock) to purchase shares of common stock with a market value of twice the Right’s exercise price. At any time prior to such event, the Board of Directors may redeem the Rights at one cent per Right. The Rights can be transferred only with common stock and expire in ten years. Registration Statement In February 1998, the Company filed a shelf registration statement with the Commission to potentially offer securities which may include debt securities, preferred stock, common stock or warrants to purchase debt securities, preferred stock or common stock. The shelf registration statement was amended on April 8, 1998 to increase the maximum total price of securities to be offered to $400 million at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including reduction of bank debt. After the April 1998 common stock offering, $253.8 million remains available under the shelf registration statement for future sales of securities. Common Stock Warrants As partial consideration for producing properties acquired in December 1997 (Note 12), the Company issued warrants to purchase 937,500 shares of common stock at a price of $15.31 per share for a period of five years. These warrants were valued at $5,725,000 and recorded as additional paid-in capital. Common Stock Dividends Since the Company’s inception, the Board of Directors has declared quarterly dividends of $0.033 per common share through 1996, $0.037 per common share in 1997 and $0.04 per common share in 1998. In February 1999, the quarterly dividend was reduced to $0.01 per
Slide 36: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS common share in response to the low commodity price environment and the Company’s 1999 goal to reduce debt by $300 million. See Note 4 regarding restrictions on dividends. Series A Convertible Preferred Stock In September 1996, pursuant to the Company’s exchange offer, a total of 2,979,249 shares of common stock were exchanged for 1,138,729 shares of Series A convertible preferred stock (“Preferred Stock”). The Company incurred costs of $540,000 related to this exchange offer. All exchanged shares of common stock have been canceled and are authorized but unissued. Preferred Stock is recorded in the accompanying consolidated balance sheet at its liquidation preference of $25 per share. Cumulative dividends on Preferred Stock are payable quarterly in arrears, when declared by the Board of Directors, based on an annual rate of $1.5625 per share. The Preferred Stock has no stated maturity and no sinking fund, and is redeemable, in whole or in part, by the Company after October 15, 1999. Redemption is allowed only under certain circumstances on or before October 15, 2000 at $26.09 per share, and thereafter unconditionally at prices declining ratably annually to $25.00 per share after October 15, 2006, plus dividends accrued and unpaid to the redemption date. The Preferred Stock is convertible at the option of the holder at any time, unless previously redeemed, into shares of common stock at a rate of 2.16 shares of common stock for each share of Preferred Stock, subject to adjustment in certain events. Preferred Stock holders are allowed one vote for each common share into which their Preferred Stock may be converted. Convertible Debt During November and December 1996, $27.7 million principal of the Company’s 5 1⁄4% convertible subordinated notes (Note 4) was converted by noteholders into 2,696,521 shares of common stock. In January 1997, principal of $29.7 million of the notes was converted by noteholders into 2,892,363 shares of common stock. 8. Financial Instruments The Company uses financial and commodity-based derivative contracts to manage exposures to interest rate and commodity price fluctuations. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. Commodity Price Hedging Instruments The Company periodically enters into futures contracts, energy swaps, collars, basis swaps and option agreements to hedge its exposure to price fluctuations on crude oil and natural gas sales. During 1998, the Company recognized net gains of $7.7 million primarily related to futures contracts and basis swap transactions. This gain is recorded as a component of natural gas sales. The Company did not have significant commodity hedging activity during 1997 or 1996. See Note 6. Interest Rate Swap Agreements In September 1998, to reduce variable interest rate exposure on debt, the Company entered into a series of interest rate swap agreements, effectively fixing its interest rate at an average of 6.9% on a total notional balance of $150 million until September 2005. Settlements of net (continued) amounts due are made quarterly, based on LIBOR rates (Note 4), which is the same interest rate basis as the Company’s senior debt borrowings. In February and March 1999, the Company terminated its interest rate swaps on notional balances totaling $100 million, resulting in proceeds received and a gain of $1.1 million. This gain will be amortized against interest expense through September 2005. In February 1999, the Company sold a call option that allows the counterparty to terminate the interest rate swap in September 2001 on the remaining $50 million notional balance, resulting in proceeds received of $800,000. This amount will be deferred until the option is exercised or expires. Fair Value Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at December 31, 1998 and 1997. The following are estimated fair values and carrying values of the Company’s other financial instruments at each of these dates (in thousands): Asset (Liability) December 31, 1998 Carrying Amount Investment in equity securities Short-term debt Long-term debt Futures contracts Basis swap agreements Interest rate swap agreements Fair Value December 31, 1997 Carrying Amount Fair Value $ 44,386 $ 44,386 $ –$ – (4,962) (4,962) – – (921,000) (894,750) (539,000) (538,288) – 3,525 – – – (690) – – – (2,722) – – The fair value of short-term borrowings and bank borrowings approximates the carrying value because of short-term interest rate maturities. The fair value of subordinated notes is based on a current market quote, while other long-term debt is based on the estimated present value of expected cash flows. The fair value of all other financial instruments is based on current market quotes. Concentrations of Credit Risk Although the Company’s cash equivalents and derivative financial instruments are exposed to the risk of credit loss, the Company does not believe such risk to be significant. Cash equivalents are high-grade, short-term securities, placed with highly rated financial institutions. Most of the Company’s receivables are from a broad and diverse group of energy companies and, accordingly, do not represent a significant credit risk. The Company’s gas marketing activities generate receivables from customers including pipeline companies, local distribution companies and end-users in various industries. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss. The Company recorded an allowance for collectibility of all accounts receivable of $375,000 at December 31, 1998 and $911,000 at December 31, 1997. Financial and commodity-based swap contracts expose the Company to the credit risk of non-performance by the counterparty to the contracts. The Company does not believe this risk is significant since these contracts are placed with major banks and financial institutions.
Slide 37: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. Earnings Per Share The following reconciles earnings (numerator) and shares (denominator) used in the computation of basic and diluted earnings per share (in thousands, except per share data): Earnings 1998 Basic Net loss Preferred stock dividends Loss available to common stock – basic Diluted Effect of dilutive securities (a): Stock options Warrants Loss available to common stock – diluted 1997 Basic Net income Preferred stock dividends Earnings available to common stock – basic Diluted Effect of dilutive securities: Stock options Warrants 51⁄4% convertible subordinated notes Earnings available to common stock – diluted 1996 Basic Net income Preferred stock dividends Earnings available to common stock – basic Diluted Effect of dilutive securities: Stock options 51⁄4% convertible subordinated notes Earnings available to common stock – diluted $ 20,304 (514) 19,790 39,913 $ 0.50 $ 25,684 (1,779) 23,905 39,773 $ 0.60 $ (69,719) (1,779) (71,498) 43,396 $ (1.65) Shares Earnings per Share • Vesting of performance shares of 81,000 in 1998 and 243,000 performance shares in 1997 • Receipt of common stock of 8,904 shares (valued at $181,000) in 1998, 421,212 shares (valued at $5,430,000) in 1997 and 457,994 shares (valued at $4,768,000) in 1996 for the option price of exercised stock options • Conversion of 51⁄4% convertible subordinated notes of $29.7 million principal amount into 2,892,363 shares of common stock in 1997 and $27.7 million principal amount into 2,696,521 shares of common stock in 1996 • Exchange of 2,979,249 shares of common stock for 1,138,729 shares of Series A convertible preferred stock in 1996 $ (1.65)(b) – – $ (71,498) 338 23 43,757 Interest payments during 1998 totaled $57,200,000, including $1,070,000 of capitalized interest. Interest payments totaled $21,276,000 in 1997 and $16,369,000 in 1996. Income tax payments were $941,000 in 1997 and $6,000 in 1996; during 1998, net income tax refunds were $454,000. 11. Employee Benefit Plans – – 46 $ 23,951 451 3 115 40,342 $ 0.59 401(k) Plan The Company sponsors a 401(k) benefit plan that allows employees to contribute and defer a portion of their wages. The Company matches employee contributions of up to 10% of wages (8% of wages prior to January 1, 1998). Employee contributions vest immediately while the Company’s matching contributions vest 100% after three years of service. All employees over 21 years of age and with at least three months service with the Company may participate. Company contributions under the plan were $1,766,000 in 1998, $1,180,000 in 1997 and $979,000 in 1996. 1991 Stock Incentive Plan A total of 1,012,500 incentive units (“Units”), have been granted to directors, officers and other key employees under the 1991 Stock Incentive Plan (“1991 Plan”). Units consist of a stock option (“Option”) and a stock appreciation right (“SAR”). An Option provides the right to purchase one share of common stock at the exercise price, which generally is the market price at the date the Unit is granted. A SAR entitles the recipient to a payment equal to twice the excess of the market price of one share of common stock on the date the Option is exercised over the exercise price. As of December 31, 1998, 3,341 Units remain available for grant under the 1991 Plan. General and administrative expense includes a reduction of stock incentive compensation related to SARs of $299,000 in 1998, and stock incentive compensation expense of $359,000 in 1997 and $3.7 million in 1996. SAR cash payments were $180,000 in 1998, $288,000 in 1997 and $7.1 million in 1996. 1994 and 1997 Stock Incentive Plans Under the 1994 Stock Incentive Plan (“1994 Plan”) and the 1997 Stock Incentive Plan (“1997 Plan”), a total of 2,250,000 shares of common stock may be issued under each plan to directors, officers and other key employees pursuant to grants of Options or performance shares of common stock (“performance shares”). At December 31, 1998, 25,177 shares remained available for grant under the 1994 Plan and 102,624 shares remained available for grant under the 1997 Plan. Options vest and become exercisable on terms specified when granted by the compensation committee (“the Committee”) of the Board of – 2,570 $ 22,360 361 6,039 46,313 $ 0.48 (a) Based on common shares outstanding at December 31, 1998, potential conversion of Series A convertible preferred stock becomes dilutive to earnings per share when annual earnings available to common stock exceeds approximately $32.4 million and when quarterly earnings available to common stock exceeds approximately $8.1 million. (b) Because of the antidilutive effect of dilutive securities on loss per common share, diluted loss available to common stock is the same as basic. 10. Supplemental Cash Flow Information The consolidated statements of cash flows exclude the following noncash transactions : • The Cook Inlet Acquisition on September 30, 1998 (Note 12), a purchase of oil-producing properties for 1,921,850 shares of common stock, a related effective guarantee of $20 per share value (Note 7) and a $6 million note payable (Note 4) • Issuance of warrants in 1997 to purchase 937,500 shares of common stock and exchange of properties valued at $15.7 million, as partial consideration for producing properties acquired • Grants of performance shares of 82,125 in 1998, 180,000 in 1997 and 167,625 in 1996 to key employees and nonemployee directors (Note 11)
Slide 38: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Directors. Options granted under the 1994 Plan are not exercisable prior to six months and no Option is exercisable after ten years from its grant date. Options granted under the 1994 Plan and the 1997 Plan generally vest in equal amounts over five years, with provisions for earlier vesting if specified performance requirements are met. In May 1998, all options under the 1994 Plan vested by resolution of the Board of Directors. As of December 31, 1998, there are 356,250 outstanding stock options under the 1997 Plan that vest when the common stock price reaches $25. 1998 Stock Incentive Plan In May 1998, the stockholders approved the 1998 Stock Incentive Plan (“1998 Plan”) under which 6 million shares of common stock are available for grant. Grants under the 1998 Plan are subject to the provision that outstanding stock options and performance shares under all the Company’s stock incentive plans cannot exceed 6% of the Company’s outstanding common stock at the time such grants are made. During 1998, 675,750 stock options were granted under the 1998 Plan. Additionally, 810,375 stock options were designated to be granted to specific optionees upon each of their exercises of all outstanding vested options granted under the 1997 Plan. Stock options will vest and become exercisable annually in equal amounts over a five-year period, with provision for accelerated vesting of half the options when the common stock price first closes at or above $25, and of the remainder when the common stock price first closes at or above $30. Performance Shares Performance shares granted under the 1994, 1997 and 1998 Plans are subject to restrictions determined by the Committee and are subject to forfeiture if performance targets are not met. Otherwise, holders of performance shares generally have all the voting, dividend and other rights of other stockholders. The Company issued performance shares to key employees totaling 72,000 in 1998, 169,875 in 1997 and 154,125 in 1996, of which 81,000 vested in 1998 and 243,000 vested in 1997 when the common stock price reached specified levels. General and administrative expense includes compensation related to these performance share grants of $1.6 million in 1998, $3.3 million in 1997 and $2.5 million in 1996. As of December 31, 1998, there are 72,000 performance shares that vest when the common stock price reaches $22.50. The Company also issued to nonemployee directors a total of 10,125 performance shares in each of 1998 and 1997 and 13,500 performance shares in 1996, which vested upon grant. Royalty Trust Option Plan In May 1998, the stockholders approved the 1998 Royalty Trust Option Plan (“Option Plan”). Under the terms of the Option Plan, the Company may grant to key employees options to purchase units of beneficial interest in one or more royalty trusts that may be established by the Company. Such options will allow the purchase of royalty trust units at fair market value on the date of grant in an aggregate amount not to exceed $12 million. In December 1998, the Company granted options to purchase Hugoton Royalty Trust units at a total price of $12 million, subject to completion of the initial public offering of the Hugoton Royalty Trust within six months of the date of grant. The options will be priced at the initial public offering price. (continued) Unit/Option Activity and Balances The following summarizes Unit and Option activity and balances from 1996 through 1998: Weighted Average Exercise Price 1996 Beginning of year Grants Exercises Forfeitures End of year Exercisable at end of year 1997 Beginning of year Grants Exercises Forfeitures End of year Exercisable at end of year 1998 Beginning of year Grants Exercises Forfeitures End of year Exercisable at end of year $ 11.11 17.52 11.64 17.19 14.23 11.03 24,750 – (6,750) – 18,000 18,000 2,328,697 1,395,750 (1,081,711) (21,750) 2,620,986 1,351,236 $ 7.32 12.11 6.75 8.79 11.11 10.96 50,963 – (26,213) – 24,750 24,750 1,486,996 1,757,250 (897,234) (18,315) 2,328,697 1,119,044 $ 6.27 9.64 5.70 6.61 7.32 6.66 835,810 – (784,658) (189) 50,963 50,963 1,399,250 303,750 (211,079) (4,925) 1,486,996 1,006,146 1991 Plan Incentive Units 1994, 1997 and 1998 Plans Stock Options The following summarizes information about Units/Options at December 31, 1998: Units/Options Outstanding Weighted Average Remaining Term 3.1 years Weighted Average Exercise Price $ 5.43 Units/Options Exercisable Weighted Average Exercise Number Price 18,000 $ 5.43 Range of Exercise Prices 1991 Plan $ 5.32 - $ 7.56 1994, 1997 and 1998 Plans $ 6.61 - $ 7.89 $ 9.67 - $10.92 $12.04 - $13.40 $15.53 - $18.22 Number 18,000 235,015 264,971 762,500 1,358,500 2,638,986 6.5 years 7.4 years 8.4 years 9.4 years 7.23 9.68 12.27 17.58 235,015 264,971 747,000 104,250 1,369,236 7.23 9.68 12.21 15.54 Estimated Fair Value of Grants Using the Black-Scholes option-pricing model and the following assumptions, the weighted average fair value of option grants was estimated to be $6.82 in 1998, $5.05 in 1997 and $3.82 in 1996. 1998 Risk-free interest rates Dividend yield Weighted average expected lives Volatility 5.6% 3.2% 5 years 52% 1997 6.4% 1.6% 5 years 47% 1996 6.4% 1.4% 6 years 35%
Slide 39: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair Value The following are pro forma earnings (loss) available to common stock and earnings (loss) per common share for 1998, 1997 and 1996, as if stock-based compensation had been recorded at the estimated fair value of stock awards at the grant date, as prescribed by SFAS 123, Accounting for Stock-Based Compensation (Note 1): (in thousands, except per share data) Earnings (loss) available to common stock: As reported Pro forma Earnings (loss) per common share: Basic As reported Pro forma Diluted As reported Pro forma 1998 $(71,498) $(75,785) $ (1.65) $ (1.75) $ (1.65) $ (1.75) 1997 $23,905 $21,646 $000.60 $000.54 $000.59 $000.54 1996 $19,790 $19,767 $ 0.50 $ 0.50 $ 0.48 $ 0.48 12. Acquisitions On May 14, 1997, the Company acquired primarily gas-producing properties in Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39 million from a subsidiary of Burlington Resources Inc. The properties are primarily operated interests. The Company funded the acquisition with bank debt and cash flow from operations. On December 1, 1997, the Company acquired interests in certain producing oil and gas properties in the San Juan Basin of New Mexico (“Amoco Acquisition”) from a subsidiary of Amoco Corporation (“Amoco”) for $252 million, including warrants to purchase 937,500 shares of the Company’s common stock at a price of $15.31 per share for a period of five years. After adjustments for other acquisition costs, estimated cash flows through date of closing and preferential purchase rights exercised by third parties, the properties were purchased for approximately $195 million, including approximately $5.7 million value for the warrants. Amoco elected to accept certain producing properties owned by the Company valued at $15.7 million in lieu of cash, reducing cash consideration to $173.6 million, which was funded with bank debt. Additional purchase price revisions may result from post-closing adjustments. On April 24, 1998, the Company acquired producing properties in the East Texas Basin from EEX Corporation (“East Texas Basin Acquisition”) for $265 million. After purchase price adjustments primarily resulting from net revenues from the January 1, 1998 effective date through April 24, 1998, the properties were purchased for an estimated price of $245 million. In connection with the acquisition, the Company sold a production payment to EEX Corporation for $30 million. The production payment is payable from production from certain properties acquired in the East Texas Basin Acquisition during the 10-year period beginning January 1, 2002. EEX Corporation effectively pays all taxes, royalties and production expenses related to such production. The Company has the option to repurchase a portion of this production payment each December, beginning in 1998; this option was not exercised in December 1998. The cost of the East Texas Basin Acquisition (net of the production payment sold) of $215 million was funded by bank borrowings which were partially repaid by proceeds from the sale of common stock (Note 7). Purchase price revisions may result from post-closing adjustments. On September 30, 1998, the Company acquired oil-producing properties in the Middle Ground Shoal Field of Alaska’s Cook Inlet (“Cook Inlet Acquisition”) from various Shell Oil Company affiliates (“Shell”). The acquired interests include a 100% working interest in two State of Alaska leases, two offshore production platforms and a 50% interest in certain operated production pipelines and onshore processing facilities. The acquisition had an effective date of July 1, 1998, and is subject to customary post-closing adjustments. The Company acquired the properties in exchange for 1,921,850 shares of the Company’s common stock. These shares are subject to a contractual $20 price guarantee, resulting in an accrued liability of $24 million recorded at December 31, 1998 (Note 7). The Company also executed a non-interest bearing promissory note to Shell for $6 million. Payments under this note of $3 million, $2 million and $1 million are due when the average NYMEX crude oil price for 60 consecutive calendar days equals or exceeds $18.50, $19.50 and $20.50, respectively. The total estimated purchase price of the Cook Inlet Acquisition is $44.4 million. See Note 3. On March 1, 1999, the Company and Shell entered into an amended agreement to postpone Shell’s resale of Company common stock to no later than August 16, 1999. Prior to that date, the Company will have the options of purchasing the common stock from Shell, registering the shares for resale by Shell, or exchanging the shares with another Company security to be resold by Shell. In the interim, the Company has agreed to make payments to Shell of up to $20 million, including a payment of $5 million on March 2, 1999, and has entered into gas sales and transportation contracts that provide Shell with an estimated value of $7.5 million. If Shell’s proceeds from the sale of Company securities exceeds the remaining amount due Shell, the difference will be refunded to the Company; otherwise, the difference will be paid to Shell. On November 20, 1998, the Company acquired primarily gasproducing properties in northwest Oklahoma and the San Juan Basin of New Mexico for $33.4 million from Seagull Energy Corp. After purchase price adjustments primarily resulting from net revenues from the October 1, 1998 effective date through November 20, 1998, the properties were purchased for an estimated price of $29.2 million. Additional purchase price revisions may result from post-closing adjustments. The Company funded the acquisition with existing lines of credit. These acquisitions have been recorded using the purchase method of accounting. The following presents unaudited pro forma results of operations for the years ended December 31, 1998 and 1997 as if these acquisitions and the April 1998 sale of common stock had been consummated as of January 1, 1998 and 1997. These pro forma results are not necessarily indicative of future results. (in thousands, except per share data) Revenues Net income (loss) Earnings (loss) available to common stock Earnings (loss) per common share: Basic Diluted Pro Forma (Unaudited) 1998 $293,201 $ (64,374) $ (66,153) $ $ (1.41) (1.41) 1997 $366,041 $ 59,924 $ 58,145 $ $ 1.19 1.15 The Company filed a registration statement with the Commission in December 1998 to sell approximately 40% of the Hugoton Royalty Trust units to the public in March or April 1999 (Note 1). The unit sales price is expected to be in the range of $9.00 to $10.00. Assuming the underwriters’ overallotment option is not exercised, the Company will sell 15,000,000 units, or 37.5% of the Trust. Based on a mid-range price of $9.50 per unit, net proceeds to be received by the Company is estimated to be $131.5 million, net of underwriters’ discount and offering expenses. Proceeds from the sale will be used to reduce bank debt. Pro forma results of operations for the year ended December 31, 1998, as if the sale of Trust units and the acquisitions described above were consummated immediately prior to January 1, 1998, would be: revenues of $269.2 million, net loss of $63.7 million and loss available to common stock of $65.5 million, or $1.39 per common share.
Slide 40: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. Quarterly Financial Data (Unaudited) The following are summarized quarterly financial data for the years ended December 31, 1998 and 1997 (in thousands, except per share data): Quarter 1st 1998 Revenues Gross profit (a) Earnings (loss) available to common stock Earnings (loss) per common share Basic Diluted Average shares outstanding 1997 Revenues Gross profit (a) Earnings available to common stock Earnings per common share Basic Diluted Average shares outstanding $ 52,286 $ 24,625 $ 10,650 $ $ 0.26 0.25 40,395 $ 45,520 $ 43,734 $ 16,595 $ 14,242 $ 3,735 $ $ $ 2,779 $ 56,732 $ 23,834 $ 6,741 $ $ 0.17 0.17 39,629 $ 49,968 $ 13,007 $ (184) $ $ 0.00 0.00 39,046 $ 61,652 $ 67,044 $ 14,510 $ 16,568 $ $ $ 759 $ 70,822 $ 9,656 2nd 3rd 4th (continued) $ (31,004) $(41,069) 0.02 $ (0.69) $ (0.90) 0.02 $ (0.69) $ (0.90) 43,940 44,765 45,440 Standardized Measure The standardized measure of discounted future net cash flows (“standardized measure”) and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of year-end prices for oil and gas and year-end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. Estimated future income taxes are calculated by applying year-end statutory rates to future pre-tax net cash flows, less the tax basis of related assets and applicable tax credits. The standardized measure does not represent management’s estimate of the Company’s future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year-end prices used to determine the standardized measure of discounted cash flows, are influenced by seasonal demand and other factors and may not be the most representative in estimating future revenues or reserve data. Proved Reserves (in thousands) Oil (Bbls) December 31, 1995 Revisions Extensions, additions and discoveries Production Purchases in place Sales in place December 31, 1996 Revisions Extensions, additions and discoveries Production Purchases in place Sales in place December 31, 1997 Revisions Extensions, additions and discoveries Production Purchases in place Sales in place December 31, 1998 Proved Developed Reserves December 31, 1995 December 31, 1996 December 31, 1997 December 31, 1998 39,988 2,361 2,220 (3,508) 1,552 (173) 42,440 (989) 9,263 (3,980) 3,195 (2,075) 47,854 (5,893) 821 (4,598) 16,331 (5) 54,510 Gas (Mcf) 358,070 29,379 37,480 (37,275) 153,400 (516) 540,538 (14,182) 112,906 (49,587) 248,040 (21,940) 815,775 (5,429) 172,059 (83,847) 311,260 (594) 1,209,224 – – (80) 13,890 – 13,810 2,631 1,875 (1,222) 80 – 17,174 Natural Gas Liquids (Bbls) (a) 0.09 $ 0.07 0.09 $ 0.07 39,498 39,581 (a) Operating income before general and administrative expense. 14. Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited) All of the Company’s operations are directly related to oil and gas producing activities located in the United States. Costs Incurred Related to Oil and Gas Producing Activities The following table summarizes costs incurred whether such costs are capitalized or expensed for financial reporting purposes (in thousands): 1998 Acquisitions: Producing properties Undeveloped properties Development (a) Exploration (b) Total $339,889 514 69,367 8,034 $417,804 1997 $251,663 3,964 86,555 2,088 $344,270 1996 $105,252 563 44,758 280 $150,853 28,946 31,883 33,835 42,876 320,230 466,412 677,710 968,495 11,494 14,000 (a) Includes capitalized interest of $1,070,000 in 1998 and $800,000 in 1997. No interest was capitalized in prior years. (b) Primarily includes geological and geophysical costs. Proved Reserves Independent petroleum engineers have estimated the Company’s proved oil and gas reserves, all of which are located in the United States. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. (a) Proved reserves attributable to natural gas liquids were not considered significant prior to the Amoco Acquisition in December 1997 (Note 12). Natural gas liquids proved reserves as disclosed include only San Juan Basin properties purchased in this acquisition.
Slide 41: Cross Timbers Oil Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (in thousands) 1998 Future cash inflows Future costs: Production Development Future net cash flows before income tax Future income tax Future net cash flows 10% annual discount Standardized measure (a) $3,041,776 (1,135,789) (228,561) 1,677,426 (231,249) 1,446,177 (637,774) $ 808,403 December 31 1997 $2,604,453 (979,317) (140,594) 1,484,542 (291,375) 1,193,167 (551,058) $ 642,109 1996 $2,634,641 (819,780) (77,837) 1,737,024 (450,987) 1,286,037 (579,556) $ 706,481 (a) Before income tax, the year-end standardized measure (or discounted present value of future net cash flows) was $908,606,000 in 1998, $782,322,000 in 1997 and $946,150,000 in 1996. Changes in Standardized Measure of Discounted Future Net Cash Flows (in thousands) Standardized measure, January 1 Revisions: Prices and costs Quantity estimates Accretion of discount Future development costs Income tax Production rates and other Net revisions Extensions, additions and discoveries Production Development costs Purchases in place (a) Sales in place Net change Standardized measure, December 31 1998 $ 642,109 (184,568) 65,600 71,942 (104,636) 40,011 (296) (111,947) 96,829 (146,498) 56,904 271,806 (800) 166,294 $ 808,403 1997 $ 706,481 (388,559) 55,497 86,845 (120,073) 99,455 (1,614) (268,449) 92,582 (125,343) 73,062 207,387 (43,611) (64,372) $ 642,109 1996 $ 335,156 360,053 34,099 37,291 (36,267) (169,118) (155) 225,903 49,802 (97,106) 33,484 160,670 (1,428) 371,325 $ 706,481 Year-end oil prices used in the estimation of proved reserves and calculation of the standardized measure were $9.50 for 1998, $15.50 for 1997, $24.25 for 1996 and $18.00 for 1995. Year-end average gas prices were $2.01 for 1998, $2.20 for 1997, $3.02 for 1996 and $1.68 for 1995. Year-end average natural gas liquids prices were $3.99 for 1998 and $11.07 for 1997. Proved oil and gas reserves at December 31, 1998 include 209,000 Bbls and 8,278,000 Mcf, and the standardized measure, before income tax, includes approximately $8 million attributable to the Company’s ownership of approximately 22% of the Cross Timbers Royalty Trust. Year-end 1998 oil and gas reserves also include 3,224,000 Bbls and 412,058,000 Mcf, and the standardized measure, before income tax, includes approximately $280 million attributable to the Company’s full ownership of the Hugoton Royalty Trust. See Note 12. Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity. (a) Based on the year-end present value (at year-end prices and costs) plus the cash flow received from such properties during the year, rather than the estimated present value at the date of acquisition.
Slide 42: Cross Timbers Oil Company REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Cross Timbers Oil Company We have audited the accompanying consolidated balance sheets of Cross Timbers Oil Company and its subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of operations, comprehensive income, cash flows and stockholders’ equity for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Fort Worth, Texas March 12, 1999
Slide 43: Cross Timbers Oil Company MARKET PRICE OF COMMON STOCK AND DIVIDENDS DECLARED PER SHARE Common Stock Cross Timbers common stock began trading on the New York Stock Exchange on May 11, 1993 under the symbol “XTO.” The following table shows the high and low prices of Cross Timbers common stock and the dividends declared for 1997 and 1998. These values have been adjusted for the three-for-two splits that occurred in March 1997 and February 1998. As of March 1, 1999, there were 547 holders of record of Cross Timbers common stock. Quarter End High Low Dividend 1998 March 31 June 30 September 30 December 31 $ 20.125 20.875 19.313 16.813 $ 14.672 16.375 11.375 5.063 $ .040 .040 .040 .040 1997 March 31 June 30 September 30 December 31 $ 13.719 13.750 16.375 19.125 $ 10.422 9.828 12.328 13.297 $ .037 .037 .037 .037
Slide 44: Cross Timbers Oil Company CORPORATE INFORMATION Corporate Headquarters 810 Houston Street, Suite 2000 Fort Worth, Texas 76102 (817) 870-2800 Oklahoma City Office 210 West Park Avenue, Suite 2350 Oklahoma City, Oklahoma 73102 (405) 232-4011 Midland Office 3000 N. Garfield, Suite 175 Midland, Texas 79705 (915) 682-8873 Farmington Office 6001 U.S. Hwy. 64 Farmington, New Mexico 87401 (505) 632-5200 Tyler Office Woodgate Center 1001 ESE Loop 323, Suite 410 Tyler, Texas 75701 (903) 939-1200 Alaska Office 52260 Shell Road Kenai, Alaska 99611 (907) 776-8473 Annual Meeting Tuesday, May 18, 1999 at 10 a.m. W. T. Waggoner Building, 1st Floor 810 Houston Street Fort Worth, Texas Independent Auditors Arthur Andersen LLP Fort Worth, Texas Senior Subordinated Notes 91⁄4% Notes due 2007 83⁄4% Notes due 2009 Transfer Agents and Registrars Common and Preferred Stock: ChaseMellon Shareholder Services, L.L.C. Dallas, Texas www.chasemellon.com Senior Subordinated Notes: Bank of New York Corporate Trust Division New York, New York Form 10-K Copies of the Company’s Annual Report on Form 10-K filed with the Securities and Exchange Commission may be obtained upon request to Investor Relations at our corporate address. Senior Officers Bob R. Simpson Chairman and Chief Executive Officer Steffen E. Palko Vice Chairman and President J. Richard Seeds Executive Vice President Louis G. Baldwin Senior Vice President and Chief Financial Officer Keith A. Hutton Senior Vice President, Asset Development Bennie G. Kniffen Senior Vice President and Controller Thomas L. Vaughn Senior Vice President, Operations Vaughn O. Vennerberg II Senior Vice President, Land Frank G. McDonald Vice President and General Counsel and Assistant Secretary Robert C. Myers Vice President, Human Resources John M. O’Rear Vice President and Treasurer Terry L. Schultz Vice President, Gas Marketing Mark A. Stevens Vice President, Taxation E. E. Storm III Vice President and General Counsel, Land and Acquisitions L. Frank Thomas III Vice President, Information Technology Michael R. Tyson Assistant Controller and Director of Financial Reporting Direct Stock Purchase/Dividend Reinvestment Plan A Direct Stock Purchase and Dividend Reinvestment Plan allows new investors to buy Cross Timbers common stock for as little as $500 and existing shareholders to automatically reinvest dividends. For more information, request a prospectus from: ChaseMellon Shareholder Services, L.L.C. at (800) 938-6387. Shareholder Services For questions about dividend checks, electronic payment of dividends, stock certificates, address changes, account balance, transfer procedures and year-end tax information call (888) 877-2892. Web Site www.crosstimbers.com Directors Bob R. Simpson Chairman and Chief Executive Officer Cross Timbers Oil Company Steffen E. Palko Vice Chairman and President Cross Timbers Oil Company J. Richard Seeds Executive Vice President Cross Timbers Oil Company J. Luther King, Jr. President Luther King Capital Management Corporation Jack P. Randall President Randall & Dewey Scott G. Sherman Owner Sherman Enterprises Advisory Director Dr. Lane G. Collins Professor of Accounting Baylor University Other Officers Virginia N. Anderson Corporate Secretary Adam E. Auten Assistant Treasurer Nick J. Dungey Vice President, Natural Gas Operations Robert B. Gathright Assistant Controller Jeffrey F. Heyer Larry B. McDonald Senior Vice President, Operations Vice President, Geology Ken K. Kirby Timothy L. Petrus Vice President, Operations Senior Vice President, East Texas Acquisitions Kenneth F. Staab Senior Vice President, Engineering Gary L. Markestad Vice President, Operations San Juan Basin
Slide 45: Special thanks to the following individuals for their gracious assistance in assembling some of the images of Fort Worth and information on its history: Dr. Gerald Saxon, Donita Maligi, and Shirley Rodnitzky of the Special Collections Division, The University of Texas at Arlington Libraries; Judy Alter and Tracy Row of Texas Christian University Press; and William B. Potter. Courtesy, W. D. Smith, Inc. Commercial Photography Collection, Special Collections Division, The University of Texas at Arlington Libraries: Cover Cover, Page 6 Page 8 Page 10 Page 14 Tarrant County Courthouse Livestock Exchange Building Texas and Pacific Station, c. 1913 W.T. Waggoner Building Flatiron Building Will Rogers on horseback (statue) Will Rogers Memorial Center Texas Spring Palace Courtesy, Fort Worth Star-Telegram Photograph Collection, Special Collections Division, The University of Texas at Arlington Libraries: Cover Inside Front and Back Cover Page 4 Page 6 Page 8 Page 10 Page 12 People in Stockyards Map of Fort Worth, 1886 (background) Quanah Parker (portrait, and on horseback) Trail drive Swift packing plant Grand Champions Thistle Hill Camp Bowie, 36th Division Camp Bowie soldiers and tents Courtesy, Jack White Photograph Collection, Special Collections Division, The University of Texas at Arlington Libraries: Page 4 Courthouse under construction, c. 1894 The page 4 background illustration of “Old Fort Worth,” an overall view of the post from the west, was provided by the artist, William B. Potter, Fort Worth, Texas. The B-24 production line photo on page 12 was furnished by Lockheed Martin Tactical Aircraft Systems, Fort Worth, Texas. Sources: Fort Worth, Outpost on the Trinity, by Oliver Knight, with an Essay on the Twentieth Century by Cissy Stewart Lale. Originally published: University of Oklahoma Press, Norman, Oklahoma, 1953. Reprinted: Texas Christian University Press, Fort Worth, Texas, 1990. The Fort That Became a City: An Illustrated Reconstruction of Fort Worth, Texas, 1849-1853. Drawings by William B. Potter. Text by Richard F. Selcer. Texas Christian University Press, Fort Worth, Texas, 1995. Fort Worth’s Legendary Landmarks. Text by Carol Roark; Photographs by Byrd Williams. Texas Christian University Press, Fort Worth, Texas, 1995. Statements concerning results of future development expenditures, strategic acquisitions, cash flow per share, proved reserves and debt levels are forward-looking statements. These statements are based on assumptions concerning commodity prices, drilling results and production, and administrative and other costs that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of business risks and there is no assurance that these goals and projections can or will be met. In addition, acquisitions that meet the Company’s profitability, size, geographic and other criteria may not be available on acceptable economic terms. Further information is available in the Company’s filings with the Securities and Exchange Commission, which are incorporated by this reference as though fully set forth herein.
Slide 46: Cross Timbers Oil Company 810 Houston Street, Suite 2000 • Fort Worth, Texas 76102 (817) 870-2800 • www.crosstimbers.com