Helmerich & Payne
Annual Report 1999

Plain-text annual report

Helmerich & Payne, Inc. Annual Report for 1999 Revenue Breakdown for 1999 International 32% Contract Drilling Domestic 38% Exploration & Production 17% Oil and Gas Natural Gas Marketing 10% Investments and Other Income 1% Real Estate 2% Financial Highlights Years Ended September 30, 1999 1998 Revenues Net Income Diluted Earnings Per Share Dividends Paid Per Share $ 564,319,000 $ 636,640,000 $ 142,788,000 $ 101,154,000 $ 2.86 $ 2.28 $ 2.00 $ .275 Capital Expenditures $ 122,951,000 $ 266,299,000 Total Assets $1,109,699,000 $1,090,430,000 President’s Letter To the Co-owners of Helmerich & Payne, Inc. At the closing of this century, dubbed by some “The Century of Oil,” energy continues to play a fascinating role on the world stage. Wars have been waged over its control and strategic advantage. Great machines of commerce, defense, and development have been fueled by its availability and abundance. It is hard to imagine turning through the pages of history for the last hundred years without the oil patch occupying a prominent place. Your Company has been privileged to play a part of that story for eighty years. Perhaps by now, we should be able to figure out where things are going. But true to character, predicting the future of the energy business remains elusive. Earlier this year, prices plunged to a fifty-year, inflation-adjusted low, prompting seasoned observers, notably The Economist, to predict the specter of prolonged pricing pain in a range of $5 per barrel. Within mere months, oil prices threatened to reach a $30 threshold on the strength of OPEC solidarity and recovering worldwide demand. These dramatic price swings reflect the unprecedented shifts occurring in the industry at the change of the century. What can be said as we move into the new millennium? While no one is suggesting “The Century of Oil, Part Two,” future worldwide energy needs will continue to grow, even in a world of less steel and more E-commerce. The global economy’s appetite for more energy will be met primarily from OPEC’s low cost supplies. While OPEC’s market share will certainly grow, the non-OPEC countries must still provide around half of the demand, and their major fields continue to mature and deplete. New production will be supplied from expensive frontier and deepwater exploration efforts. 2 The need for new drilling is even more profound for declining natural gas production. Over the next ten years, the United States is expected to burn half again our current domestic reserves. Going forward, an emerging cycle of strong supply and demand funda- mentals is taking shape. Like always before, there will be ups and downs and unforeseen surprises. Predictably, financial strength and flexibility will be needed to cope with the industry’s cyclicality and constant change. Technology will continue to be a key driver in delivering added value and reducing costs. Yet the challenge that will determine the clearest strategic advantage is on the people side of the business. From the beginning, our Company has succeeded on the skill, experience, and creative contributions of its people. At the same time, we operate in an industry that has lost over half of its workforce during the last twenty years and continues to suffer from an immeasurable drain of institutional knowledge. Thankfully, that is not the case at Helmerich & Payne, Inc. We are stronger and more talented throughout the organization than ever before. No annual report can capture the enterprise value found in the culture, shared values, and loyalty of its people. Perhaps that story is best told by customers, partners, suppliers, and competitors who know us best and with whom we earn our reputation everyday. As the calendar turns to the year 2000, your Company is confident and excited about the future. Sincerely, December 15, 1999 Hans Helmerich President 3 Drilling H E L M E R I C H & PAY N E I N T E R N AT I O N A L D R I L L I N G C O. SUMMARY Helmerich & Payne International Drilling Co. is a leading drilling contractor with a fleet of 89 drilling rigs worldwide. The Company owns 79 land rigs, 40 of which were located in the United States at year-end, and 39 located in the countries of Venezuela (18), Colombia (10), Bolivia (5), Ecuador (4), and Argentina (2). Additionally, the Company owns 10 offshore platform rigs in the Gulf of Mexico and jointly owns, with Atwood Oceanics, Inc., an offshore platform rig located in Australia. Helmerich & Payne International Drilling Co. also provides management services for two Exxon-owned platform rigs operating offshore California. Low oil prices had a considerable negative impact on the financial performance of the Company, as well as on the contract drilling industry worldwide. Total contract drilling revenues slipped eight percent in 1999, interrupting a string of consecutive increases which began over a decade ago in 1987. Earnings before interest, taxes, depreciation, and amortization (EBITDA) fell ten percent to $127.3 million, and pre-tax operating profit fell to $60 million, from $86.7 million in 1998. Rig utilization fell to an INTERNATIONAL OPERATIONS average of 53 percent in 1999, compared to 88 percent in 1998. The Company’s Venezuelan operation was the hardest hit during the year as rig activity fell to less than half of the previous year’s level, resulting in revenue and EBITDA declines of 55 percent and 65 percent, respectively, in that country. As a leading member of OPEC, Venezuela sharply curtailed production and development activities in its effort to adhere to the revised quota arrangement set forth by the cartel. During 1999, the Company transferred four land rigs and one offshore platform rig from Venezuela to the United 4 States. One of the land rigs and the platform rig began working in the U.S. market during 1999, and another land rig is committed to stay in the U.S. Out of the two remaining land rigs, one was returned to Venezuela in November after refurbishment, and the other will return to the international market at the earliest opportunity. The Company’s operations in Colombia also slowed, with revenues and EBITDA there decreasing 23 percent and 18 percent, respectively. Improvements in the Venezuelan and Colombian drilling markets will likely correlate highly with the health of the world oil market. Additionally, both of these countries grapple with considerable socioeconomic and political challenges, which could also have a significant impact on the speed at which oil exploration and development activities resume to levels the Company has experienced in years past. Increased activity in Argentina and Bolivia helped offset part of the decline experienced internationally in 1999. A significant portion of the drilling in Argentina and Bolivia is aimed at developing natural gas supplies for growing markets in the southern cone region of South America. The Company completed the rig construction phase of Mobil’s Jade project, which made a significant contribution to revenues and EBITDA during 1999. Separately, Helmerich & Payne International Drilling Co. was awarded a management contract for the Jade offshore platform, which is scheduled to begin early in calendar year 2000 in Equatorial Guinea, West Africa. UNITED STATES OPERATIONS The weak crude oil market also factored into the U.S. drilling market during 5 1999, resulting in lower activity levels and dayrates. Utilization averaged 75 percent in 1999, compared with 95 percent in 1998. Lower activity, coupled with decreased dayrates, caused domestic land drilling revenues and EBITDA to decline by 26 percent and 64 percent, respectively. The U.S. land drilling market is becoming increasingly skewed toward natural gas, so future activity levels are likely to become more dependent on the price of this commodity and less on the price of crude oil. During 1999, the Company’s active rigs drilled almost exclusively for natural gas. The Company’s ten offshore platform rigs remained highly active through most of the year, averaging a utilization rate of 95 percent. Domestic offshore revenues and EBITDA increased 24 percent and 39 percent, respectively, over the 1998 level. Two important factors drive the Company’s OUTLOOK operating strategy going forward. First, financial strength and flexibility are important in an industry where cycles are as severe as the one recently experienced. Second, customers will increasingly demand better rig equipment and technology, and higher standards for safety and operating performance in their drilling programs. Even under depressed industry conditions, when the dayrate seems to reign as the paramount component in a bid, the Company has quantified the significant impact that quality performance can have on the ultimate cost of a well. Safety and training programs, high standards for rig maintenance, and design, engineering, and construction experience are in and of themselves sound investments. The return on these investments comes in new projects, solid, long-term customer relationships, a well-recognized reputation for quality performance, and the highest rig utilization among our peers in key drilling markets. 6 Exploration & Production H E L M E R I C H & PAY N E , I N C . Helmerich & Payne, Inc. explores for and produces SUMMARY crude oil and natural gas primarily in the states of Kansas, Louisiana, Oklahoma, and Texas. Additionally, the Company provides natural gas marketing services through its wholly-owned subsidiary, Helmerich & Payne Energy Services, Inc. Helmerich & Payne, Inc. produced an average of 1,779 barrels of oil per day in 1999, compared with 1,921 barrels per day in 1998. Although oil prices fell in 1999 to their lowest point in many years, the average price the Company received declined only slightly to $14.60 per barrel, from $14.74 per barrel in 1998. Natural gas production increased to 121,206 thousand cubic feet (Mcf) per day, from 117,431 Mcf per day. The average price received for natural gas fell ten percent to $1.83 per Mcf, from $2.04 per Mcf in 1998. Reductions in both oil production and natural gas prices pushed revenues down three percent, to $96 million. Additionally, higher depreciation, geophysical, and lease abandonment expenses reduced operating profit to $11.2 million in 1999, compared with $28.1 million in 1998. Helmerich & Payne Energy NATURAL GAS MARKETING Services, Inc. realized a three percent increase in revenues and an 83 percent increase in operating profit in 1999. The dramatic increase in operating profit resulted from favorable forward prices contracted on a small portion of marketed production prior to last year’s mild winter. Helmerich & Payne, Inc. EXPLORATION ACTIVITIES participated in the drilling of 49 (23.9 net) wells in 1999, of which 33 (15.5 net) were completed as natural gas wells, two (1.3 net) as oil wells, and 14 (7.1 net) as dry holes. A total of 15 (5.5 net) wells were exploratory and the remaining 34 (18.4 net) were development wells. Proved reserves at year-end were 4.8 million barrels of oil and 239.6 billion cubic feet (Bcf) of natural gas. 7 Over the past two years, the Company has focused on prospect development utilizing 3D seismic technology. The Company is presently involved in a number of 3D seismic surveys covering over 850 square miles in Texas and Louisiana. Three of these surveys encompassed 185 square miles in Jefferson County, Texas, where the Company has an acreage position with working interests ranging from 54 percent to 66 percent. Four successful wells were drilled in this area during 1999. The Company also participated in 65 square miles of 3D seismic in West Texas and a 94 square mile survey in Galveston County, Texas. Five wells were drilled on these prospects in 1999; two of four Galveston County wells were successful and the West Texas well was in progress at year-end. The Company also participated in a 200 square mile, 3D seismic survey on another south Texas prospect where a wildcat well was drilling at year-end. The Company could potentially participate in more than 20 wells in its Texas prospect areas alone during the first half of fiscal 2000. In Louisiana, the Company purchased a 42 percent working interest in a prospect in Calcasieu Parish, as well as 50 square miles of 3D seismic in the area. At calendar year-end, the first wildcat well was nearing completion and a second well was about to spud. Due to the nature of the exploration business, many OUTLOOK projects can take years to come to fruition. This makes it challenging to gauge the overall success of an effort, particularly when looking at annual reserve replacement and finding cost data. Over the past two years, the Company has invested almost $35 million in acreage and seismic to develop a larger and more technologically-focused portfolio of promising prospects. With this significant amount of spadework completed, the Company is poised to participate in more exploratory drilling in fiscal 2000 than it has in several years. 8 Revenues and Operating Profit by Business Segments HELMERICH & PAYNE, INC. Years Ended September 30, 1999 1998 1997 (in thousands) SALES AND OTHER REVENUES: Contract Drilling - Domestic .............................................. Contract Drilling - International ......................................... Total Contract Drilling................................................... $213,647 182,987 396,634 $177,059 253,072 430,131 $140,294 176,651 316,945 Exploration and Production............................................... Natural Gas Marketing ...................................................... Total Oil and Gas Operations....................................... Real Estate ...................................................................... Other ................................................................................. 95,953 55,259 151,212 8,671 7,802 98,696 53,499 152,195 8,922 45,392 111,512 69,015 180,527 8,641 11,746 Total Revenues ........................................................................ $564,319 $636,640 $517,859 OPERATING PROFIT: Contract Drilling - Domestic .............................................. Contract Drilling - International ......................................... Total Contract Drilling................................................... $030,154 29,845 59,999 $ 35,817 50,834 86,651 $ 24,437 43,118 67,555 Exploration and Production............................................... Natural Gas Marketing ...................................................... Total Oil and Gas Operations..................................... Real Estate ....................................................................... Total Operating Profit ................................................... OTHER: Income from investments.................................................. General and administrative expense................................. Interest expense ............................................................... Corporate depreciation ..................................................... Other corporate expense .................................................. Total Other ................................................................... 11,245 4,418 15,663 5,338 81,000 7,757 (14,198) (6,481) (1,565) (1,575) (16,062) 28,088 2,418 30,506 5,371 122,528 44,603 (11,762) (942) (1,280) (927) 29,692 55,191 3,363 58,554 5,615 131,724 11,437 (9,346) (4,212) (919) (1,269) (4,309) INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATE............................. $064,938 $152,220 $127,415 Note: See Note 13 (pages 31 and 32) for complete segment disclosure. 9 Management’s Discussion & Analysis of Results of Operations and Financial Condition HELMERICH & PAYNE, INC. RISK FACTORS AND FORWARD-LOOKING STATEMENTS The following discussion should be read in conjunction with the consolidated financial statements and related notes included elsewhere herein. The Company’s future operating results may be affected by various trends and factors, which are beyond the Company’s control. These include, among other factors, fluctuations in oil and natural gas prices, expiration or termination of drilling contracts, currency exchange gains and losses, changes in general economic conditions, rapid or unexpected changes in technologies, and uncertain business conditions that affect the Company’s businesses. Accordingly, past results and trends should not be used by investors to anticipate future results or trends. With the exception of historical information, the matters discussed in Management’s Discussion & Analysis of Results of Operations and Financial Condition include forward-looking statements. These forward-looking statements are based on various assumptions. The Company cautions that, while it believes such assumptions to be reasonable and makes them in good faith, assumed facts almost always vary from actual results. The differences between assumed facts and actual results can be material. The Company is including this cautionary statement to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. The factors identified in this cautionary statement are important factors (but not necessarily all important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company. RESULTS OF OPERATIONS All per share amounts included in the Results of Operations discussion are stated on a diluted basis. Helmerich & Payne, Inc.’s net income for 1999 was $42,788,000 ($0.86 per share), compared with net income of $101,154,000 ($2.00 per share) in 1998, and $84,186,000 ($1.67 per share) in 1997. Included in the Company’s net income, but not related to its operations, were after-tax gains from the sale of investment securities of $1,562,000 ($0.03 per share) in 1999, $23,417,000 ($0.46 per share) in 1998, and $2,870,000 ($0.06 per share) in 1997. Also included is the Company’s portion of income from its equity affiliate, Atwood Oceanics, Inc., which was $0.07 per share in 1999, $0.11 per share in 1998, and $0.05 per share in 1997. Net income also included non-cash charges of $6,237,000 ($0.13 per share) in 1999 and $3,356,000 ($0.07 per share) in 1998 related to the write-down of producing properties in accordance with 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. 10 Consolidated revenues were $564,319,000 in 1999, $636,640,000 in 1998, and $517,859,000 in 1997. The 11 percent decline from 1998 to 1999 was primarily due to the $70,085,000 reduction in international contract drilling revenues. An increase in domestic contract drilling revenues of $36,588,000 was offset by a decline in investment revenues of $36,846,000. The 23 percent increase from 1997 to 1998 was due to higher dayrates and utilization in the contract drilling division and higher capital gains from the sales of equity securities. Significant increases in these areas helped offset lower revenues from the Exploration and Production Division due to lower crude oil and natural gas prices. Revenues from investments were $7,757,000 in 1999, $44,603,000 in 1998, and $11,437,000 in 1997. Included in revenues from investments were pre-tax gains from the sale of investment securities of $2,547,000 in 1999, $38,421,000 in 1998, and $4,697,000 in 1997. Interest income was stable during 1999, 1998, and 1997, but dividend income declined slightly as the Company sold shares of dividend paying stocks during the last two years. Costs and expenses in 1999 were $499,381,000, 88 percent of revenues, compared with 76 percent in 1998, and 75 percent in 1997. Operating costs, as a percentage of operating revenues, were 60 percent in 1999, 58 percent in 1998, and 55 percent in 1997. Depreciation, depletion, and amortization (DD&A) expense increased by approximately 24 percent in each of the last two years, due primarily to increases in capital investment made by the Company during the last several years. Also included in DD&A are SFAS 121 impairment charges of $10,059,000 in 1999 and $5,413,000 in 1998. There were no such charges in 1997. General and administrative expenses increased by 21 percent to $14,198,000 in 1999, compared with $11,762,000 in 1998, and $9,346,000 in 1997. Higher overall payroll costs and additional information technology staffing were primary reasons for the increases the last two years. Because of the impact of foreign taxes, income tax expense rose to 40 percent of pre-tax income in 1999, from 37 percent in 1998, and 36 percent in 1997. Interest expense rose to $6,481,000 in 1999, from $942,000 in 1998, and $4,212,000 in 1997. Outstanding bank loans rose at the end of 1998 and into the first half of 1999 as the Company completed a substantial capital expenditure program and, in 1998, repurchased some of its stock. CONTRACT DRILLING DIVISION revenues, which include both domestic and international segment revenues, declined eight percent to $396,634,000 during 1999, from $430,131,000 in 1998. Revenues for 1998 were up 36 percent over the previous year. Division operating profit declined 31 percent to $59,999,000 during 1999, compared with a 28 percent increase from 1997 to 1998. 11 Domestic segment revenues were $213,647,000 in 1999, $177,059,000 in 1998, and $140,294,000 in 1997. Domestic segment operating profit was $30,154,000 in 1999, $35,817,000 in 1998, and $24,437,000 in 1997. Domestic segment revenues were up for 1999 mainly due to $40,790,000 of revenues from the Mobil Jade rig construction project and increased offshore platform rig revenues. Domestic operating profit was down because of lower land rig utilization and dayrates. However, operating profit for 1999 was bolstered by several non-recurring items such as income from the Jade construction project and from several capital reimbursements from operators for new rig equipment on existing rigs. Approximately $7.5 million of operating profit from these sources will likely not occur in fiscal 2000. Domestic segment revenues and operating profit for 1998 increased over 1997 because of improved dayrates from both U.S. land and offshore rig operations and higher utilization of the Company’s offshore platform rigs. Rig utilization for the U.S. land fleet was 69 percent in 1999, 94 percent in 1998, and 99 percent in 1997. Domestic platform rig utilization was 95 percent in 1999, 99 percent in 1998, and 63 percent in 1997. Revenues and operating profit for domestic operations could be lower in 2000 if rig demand remains soft. International segment revenues fell 28 percent to $182,987,000 during 1999, from $253,072,000 in 1998. Revenues were $176,651,000 in 1997. Operating profit for the international segment declined to $29,845,000 in 1999, from $50,834,000 in 1998, and $43,118,000 in 1997. International rig utilization averaged 53 percent during 1999, 88 percent in 1998, and 91 percent in 1997. Revenues and operating profit increased significantly from 1997 to 1998 due to additional rigs and increased dayrates in Venezuela, Ecuador, Peru, and Bolivia. However, as crude oil prices declined, rig activity and profitability declined rapidly during the last half of 1999, particularly in Venezuela. It is anticipated that during 2000, international revenues and operating profit will be down substantially compared with 1999, because of low rig utilization, dayrates and profit margins, particularly in Venezuela and Colombia. The Company has international operations in several South American countries. With the exception of Venezuela, the Company’s exposure to currency valuation losses is immaterial due to the fact that virtually all billings and payments are in U.S. dollars. In Venezuela, approximately 60 percent of the Company’s billings are in U.S. dollars and 40 percent are in bolivars, the local currency. As a result, the Company is exposed to risks of currency devaluation in Venezuela because of the bolivar denominated receivables. During 1999, the Company experienced a loss of $711,566 due to devaluation of the bolivar, compared with a $2,204,000 loss in 1998, and a $579,000 loss in 1997. The Company anticipates additional devaluation losses in Venezuela during 2000, but it is unable to predict the extent of either the devaluation, or its financial impact. Should Venezuela experience a 25 to 50 percent devaluation, Company losses could range from approximately $350,000 to $600,000. Using the same assumptions in 1998 resulted in the Company estimating foreign currency losses in Venezuela for 1999 ranging from $1,500,000 to $2,700,000. OIL AND GAS DIVISION includes operating results from its Exploration and Production segment, as depicted in the following table, and its Natural Gas Marketing segment. 12 Exploration & Production Revenues (in 000’s) . . . . . . . . . . . . . . . . . . . . . . Operating Profit (in 000’s) . . . . . . . . . . . . . . . . . . Natural Gas Production (mmcf per day) . . . . . . . Average Natural Gas Price (per mcf) . . . . . . . . . Crude Oil Production (barrels per day) . . . . . . . . Average Crude Oil Price (per barrel) . . . . . . . . . . 1999 $95,953 $11,245 121.2 $ 1.83 1,779 $ 14.60 1998 $98,696 $28,088 117.4 $ 2.04 1,921 $ 14.74 1997 $111,512 $ 55,191 110.9 $ 2.23 2,700 $ 20.77 Exploration and Production segment revenues and operating profit have declined the past two years as both crude oil and natural gas prices have fallen. Natural gas production increased slightly over the last two years, while oil production has decreased substantially. Much of the decline in oil production was due to the sale of the Company’s Austin Chalk production in the first quarter of 1998. Operating profit has been impacted the last three years by the Company’s efforts to increase the quantity and quality of its exploration projects. Accordingly, geophysical expense and reserve for capitalized costs of undeveloped leases have increased. Also, the Company incurred pre-tax impairment charges as required by SFAS 121 of $10,059,000 in 1999 and $5,413,000 in 1998. No impairment charges were incurred in 1997. During 2000, the Company intends to increase its capital spending over the previous year in order to participate in more exploratory opportunities. Therefore, operating profit for the coming year will be impacted by the results of those efforts. Geophysical expense, reserve for capitalized costs of undeveloped leases, and dry hole expense could be higher as a result of more exploration activity. Also, it is difficult to predict the movement of crude oil and natural gas prices and their impact on operating profit. The Company’s Natural Gas Marketing segment, Helmerich & Payne Energy Services, Inc., (HPESI) derives most of its revenues from selling natural gas produced by other unaffiliated companies. Total Natural Gas Marketing segment revenues were $55,259,000 in 1999, $53,499,000 in 1998, and $69,015,000 in 1997. Operating profit was $4,418,000 in 1999, $2,418,000 in 1998, and $3,363,000 in 1997. Most of the natural gas owned and produced by the Exploration and Production segment is sold through HPESI to third parties at variable prices based on industry pricing publications or exchange quotations. Revenues for the Company’s own natural gas production are reported by the Exploration and Production segment with the Natural Gas Marketing segment retaining a market-based fee from the sale of such production. HPESI sells most of its natural gas with monthly or daily contracts tied to industry market indices, such as Inside FERC Gas Market Report. The Company, through HPESI, has natural gas delivery commitments for periods of less than a year for approximately 35 percent of its total natural gas production. At times, HPESI may enter into fixed price natural gas sales contracts on a small portion (less than ten percent) of its natural gas sales for periods of less than twelve months to guarantee a certain price. In 1999, HPESI had approximately 2.3 percent of its natural gas sales portfolio dedicated to such fixed price contracts. As of September 30, 1999, HPESI had fixed price contracts for approximately 10 percent of its projected monthly sales 13 for the months of November, 1999 through March, 2000, and fixed price contracts for less than four percent of its projected sales for the remainder of fiscal year 2000. There were no fixed price contracts in effect at September 30, 1998. REAL ESTATE DIVISION revenues totaled $8,671,000 for 1999, $8,922,000 for 1998, and $8,641,000 for 1997. Operating profit was $5,338,000 in 1999, $5,371,000 in 1998, and $5,615,000 in 1997. The general economy in Tulsa continued to grow during the year resulting in occupancy rates, revenues, and operating profit remaining strong. Revenues and operating profit for 1997 also reflected the sale of a small parcel of land for a gain of $400,000. No material changes are anticipated in the Real Estate Division in 2000. YEAR 2000 COMPLIANCE The Company’s State of Readiness THE FOLLOWING INFORMATION SHALL CONSTITUTE THE COMPANY’S “YEAR 2000 READINESS DISCLOSURE” WITHIN THE MEANING OF THE YEAR 2000 INFORMATION READINESS ACT. The Company has undertaken various initiatives in an attempt to ensure that its hardware, software and equipment will function properly with respect to dates before and after January 1, 2000. For this purpose, the phrase “hardware, software and equipment” includes systems that are commonly thought of as Information Technology (“IT”) systems, as well as those Non-Information Technology (“Non-IT”) systems and equipment that include embedded technology. IT systems include computer hardware and software, and other related systems. Non-IT systems include certain oil and gas drilling and production equipment, security systems and other miscellaneous systems. The Non-IT systems present the greatest compliance challenge since identification of embedded technology is difficult and because the Company is, to a great extent, reliant on third parties for Non-IT compliance. The Company has formed a Year 2000 (“Y2K”) Project team that is chaired by the Director of IT. The team includes IT staff, corporate staff and representatives from the Company’s business units. The Company has organized its compliance efforts into a four-phase approach as follows: Phase 1: Identification - Identify and inventory mission critical components of Company operations and systems that may be affected. Phase 2: Assessment - Determine which hardware, software and equipment must be modified, upgraded or replaced. Phase 3: Remediation - Modify, upgrade or replace non-compliant hardware, software and equipment. Phase 4: Testing - Fully test all IT systems which are material to the Company’s operations. Selectively test those Non-IT systems and equipment which are material to the Company’s operations. For the purposes of the Y2K Project material items are those items the Company believes to have a risk involving safety of individuals, damage to the environment, material effect on revenues or material damage to property. 14 The following represents the status of the Company’s IT and Non-IT Y2K Compliance: IT • Core accounting and operational (mainframe) systems • Human Resources & Payroll Systems • Network • Desktop Computer Hardware • Standard Company Desktop Computer Software • Business Unit User Software NON-IT • Systems and Equipment STATUS OF COMPLETION Phases 1, 2, 3 & 4 Completed Phases 1, 2, 3 & 4 Completed Phases 1, 2, 3 & 4 Completed Phases 1, 2, 3 & 4 Completed Phases 1, 2, 3 & 4 Completed Phases 1, 2, 3 & 4 Completed Phases 1, 2, 3 & 4 Completed As reflected in the above table, the Company has completed the process of identifying embedded technology and determining the extent to which such technology is Y2K compliant. As part of this process, the Company mailed letters to its significant vendors and service providers to confirm that the products and services purchased from or by such entities are Y2K compliant. Also, the Company has obtained information from significant customers regarding the extent to which Y2K issues may affect the amount of business the Company currently conducts with such customers. As a result of these activities, the Company conducted discussions with the vendors or manufacturers of such mission critical equipment to determine the most effective solutions to Y2K compliance issues. The Cost to Address Y2K Issues The cost of the Company’s Y2K compliance Project was approximately $800,000 which was well below the $1,000,000 budgeted for this purpose. This cost included costs of employees working on the Y2K Project. Costs for new hardware and equipment are being capitalized, and other costs were expensed as incurred. The costs relating to the Company’s Y2K Project were paid from the Company’s general funds. This expenditure mainly relates to repair, upgrading or replacement of existing software and hardware, and solicitation and evaluation of information received from significant vendors, service providers, or customers. The total cost included the costs of independent consultants engaged to review selected Y2K issues. The Company’s Contingency Plan The Company has refined its contingency plans on a business unit and departmental basis. These contingency plans include, but are not limited to: backup and recovery procedures for IT Systems; remediation of existing systems or equipment; installation 15 of new systems or equipment; stockpiling of Y2K compliant goods and supplies; stockpiling old equipment which does not contain embedded technology; replacement of current services with temporary manual processes; finding non-technological alternatives or sources for information; or identification of alternative customers, suppliers or outsourcing subcontractors who stand ready to receive or provide critical goods, equipment and services. The Company has engaged a computer recovery services contractor as a source of alternative computer systems as part of its contingency plan. The Risks of The Company’s Y2K Issues The Company completed an analysis of the operational problems and costs (including loss of revenues) that would be reasonably likely to result from the failure by the Company and certain third parties to complete efforts necessary to achieve Y2K compliance on a timely basis. The Company presently believes that the Y2K issue will not pose significant operational problems for the Company. However, if all significant Y2K issues were not properly identified or assessed, there can be no assurance that the Y2K issue will not materially and adversely impact the Company’s results of operations, liquidity and financial condition or materially and adversely affect the Company’s relationships with customers, vendors, or others. Additionally, there can be no assurance that the lack of Y2K compliance by other entities will not have a material and adverse impact on the Company’s operations or financial condition. The preceding Y2K disclosure is based upon certain forward-looking information. This forward-looking information is based on Management’s good faith estimates. These estimates were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party plans and other factors. Due to the general uncertainty inherent in Y2K issues, including the uncertainty of third party Y2K compliance, the Company cannot ensure its ability to timely and cost-effectively resolve problems associated with Y2K issues that may affect its operations and business, or expose it to third party liability. LIQUIDITY AND CAPITAL RESOURCES The Company’s capital spending for 1999 was $122,951,000, less than half of 1998 capital expenditures of $266,299,000, and 24 percent less than the $161,177,000 spent in 1997. Net cash provided from operating activities for those same time periods were $158,694,000 in 1999, $113,533,000 in 1998, and $165,568,000 in 1997. In addition to the net cash provided by operating activities, the Company also generated net proceeds from the sale of portfolio securities of $2,803,000 in 1999, $73,949,000 in 1998, and $8,557,000 in 1997. In June 1998, the board of directors authorized the Company to repurchase up to 2,000,000 shares of its own stock during a period of one year. A total of 999,100 shares were repurchased in 1998 at a total cost of $19,112,000. The Company plans to increase capital spending during 2000 in its Exploration and Production segment. The increase will likely be offset by a decrease in capital spending in the Company’s Contract Drilling Division. The potential for new contract drilling projects requiring large amounts of capital is difficult to predict at this time. 16 Due to the need for additional funds during 1998 resulting from a reduction in operating cash flow, a significant increase in capital expenditures, and the stock buyback program, the Company increased its available short-term lines of credit and obtained long-term financing. On September 30, 1999, the Company had $5 million in short-term debt borrowings, which had a weighted average maturity of 19 days and a weighted average interest rate of approximately 5.73 percent. As further described in Note 2 of Notes to Consolidated Financial Statements, in October 1998, the Company obtained an additional $50 million in long-term debt proceeds which was used to pay off a portion of its short-term borrowings. The $50 million of long-term debt matures in October 2003. The interest rate on this debt fluctuates based on 30-day London Interbank Offered Rate (LIBOR), however, simultaneous to receiving the $50 million in long-term debt proceeds, the Company entered into a $50 million interest rate swap agreement with a major national bank. The swap effectively fixes the interest rate on this facility at 5.38 percent for the entire 5-year term of the note. The estimated fair value of the interest rate swap is $2,574,000 at September 30, 1999. The Company’s interest rate risk exposure is limited to its short-term borrowings and results predominately from fluctuations in short-term interest rates as measured by 30-day LIBOR. The Company generally borrows for 30-day time periods, and can fix its interest rate for 30-day increments at spreads ranging from 35 to 50 basis points over LIBOR. The strength of the Company’s balance sheet is substantial, with current ratios for 1999 and 1998 at 2.2 and 1.5, respectively, and with total bank borrowings only 5 percent of total assets at September 30, 1999. Additionally, the Company manages a large portfolio of marketable securities that, at the close of 1999, had a market value of $289,005,000, with a cost basis of $117,214,000. The portfolio, heavily weighted in energy stocks, is subject to fluctuation in the market and may vary considerably over time. The portfolio is marked to market on the Company’s balance sheet for each reporting period. During 1999, the Company paid a dividend of $0.28 per share, or a total of $13,849,000, representing the 28th consecutive year of dividend increases. Stock Portfolio Held by the Company September 30, 1999 Number of Shares Book Value (in thousands, except share amounts) Market Value Occidental Petroleum Corporation . . . . . . . . . . . . . . . . . . Atwood Oceanics, Inc.. . . . . . . . . . . . . . . . . . . . . . . . . . . . Schlumberger, Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sunoco, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phillips Petroleum Company . . . . . . . . . . . . . . . . . . . . . . Bank One Corporation.. . . . . . . . . . . . . . . . . . . . . . . . . . Kerr-McGee Corporation . . . . . . . . . . . . . . . . . . . . . . . . ONEOK, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,000,000 3,000,000 1,480,000 312,546 240,000 175,000 184,500 225,000 $ 23,775 41,157 23,511 3,192 5,976 1,969 4,899 2,751 9,984 $117,214 $ 23,125 91,687 92,223 8,556 11,700 6,092 10,159 6,820 38,643 $289,005 17 Consolidated Balance Sheets HELMERICH & PAYNE, INC. Assets CURRENT ASSETS: September 30, 1999 1998 (in thousands) Cash and cash equivalents .............................................................. Accounts receivable, less reserve of $2,908 and $1,908 ........................ Inventories ................................................................................... Prepaid expenses and other............................................................. Total current assets .................................................................. $ 21,758 99,598 25,187 14,081 $ 24,476 119,395 25,401 15,073 160,624 184,345 INVESTMENTS ................................................................................. 238,475 200,400 PROPERTY, PLANT AND EQUIPMENT, at cost: Contract drilling equipment .............................................................. Oil and gas properties .................................................................... Real estate properties .................................................................... Other .......................................................................................... Less__Accumulated depreciation, depletion and amortization ................. 881,269 446,889 49,065 71,139 829,217 435,747 48,451 65,120 1,448,362 757,147 1,378,535 686,164 Net property, plant and equipment............................................... 691,215 692,371 OTHER ASSETS ............................................................................... 19,385 13,314 TOTAL ASSETS ................................................................................ $ 1,109,699 $ 1,090,430 The accompanying notes are an integral part of these statements. 18 Liabilities and Shareholders’ Equity September 30, 1999 1998 (in thousands, except share data) CURRENT LIABILITIES: Accounts payable ............................................................................. Accrued liabilities ............................................................................. Notes payable.................................................................................. Total current liabilities ............................................................... $ 25,704 41,200 5,000 71,904 $ 41,851 38,833 44,800 125,484 NONCURRENT LIABILITIES: Long-term notes payable ................................................................... Deferred income taxes ...................................................................... Other ............................................................................................. Total noncurrent liabilities .......................................................... 50,000 116,588 23,098 189,686 50,000 103,469 18,329 171,798 SHAREHOLDERS’ EQUITY: Common stock, $.10 par value, 80,000,000 shares authorized, 53,528,952 shares issued ............................................................... 5,353 5,353 Preferred stock, no par value, 1,000,000 shares authorized, no shares issued .......................................................................... Additional paid-in capital .................................................................... Retained earnings ............................................................................ Unearned compensation.................................................................... Accumulated other comprehensive income ............................................ Lesstreasury stock, 3,903,286 shares in 1999 and 4,146,120 shares in 1998, at cost ..... Total shareholders’ equity........................................................... 61,411 745,956 (4,487) 75,182 883,415 35,306 848,109 59,004 716,875 (5,605 54,689 ) 830,316 37,168 793,148 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY ................................. $1,109,699 $1,090,430 The accompanying notes are an integral part of these statements. 19 Consolidated Statements of Income HELMERICH & PAYNE, INC. Years Ended September 30, 1999 1998 1997 (in thousands, except per share amounts) REVENUES: Sales and other operating revenues .................................... Income from investments.................................................. $556,562 7,757 $592,037 44,603 $506,422 11,437 ............................................................................................... 564,319 636,640 517,859 COSTS AND EXPENSES: Operating costs .............................................................. Depreciation, depletion and amortization ............................. Dry holes and abandonments ............................................ Taxes, other than income taxes .......................................... General and administrative ............................................... Interest ......................................................................... ............................................................................................... 332,330 109,167 11,727 25,478 14,198 6,481 499,381 346,066 88,350 11,572 25,728 11,762 942 484,420 276,094 71,691 7,783 21,318 9,346 4,212 390,444 INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATE ................................... 64,938 152,220 127,415 INCOME TAX EXPENSE ...................................................... 25,706 56,677 45,511 EQUITY IN INCOME OF AFFILIATE net of income taxes ......................................................... 3,556 5,611 2,282 NET INCOME..................................................................... $042,788 $101,154 $ 84,186 EARNINGS PER COMMON SHARE: BASIC .......................................................................... DILUTED ...................................................................... $0560.87 $0560.86 $ $ 2.03 2.00 $ 1.69 $ 1.67 AVERAGE COMMON SHARES OUTSTANDING: BASIC .......................................................................... DILUTED ...................................................................... 49,243 49,817 49,948 50,565 49,779 50,561 The accompanying notes are an integral part of these statements. 20 Consolidated Statements of Shareholders’ Equity HELMERICH & PAYNE, INC. Common Stock Shares Amount Additional Paid-in Capital Unearned Compensation Retained Earnings Treasury Stock Shares Amount (in thousands, except per share amounts) Accumulated Other Comprehensive Income (Loss) Total Balance, Sept. 30, 1996 ............ 53,529 $5,353 $47,734 $(9,000 $557,543 3,758 $(21,210) $056,550 $645,970 Comprehensive Income: Net Income .......................... Other comprehensive income, net of tax—unrealized gains on available-for-sale securities ..... Comprehensive income ............ Cash dividends ($.26 per share).. Exercise of Stock Options .......... Lapse of restrictions on Restricted Stock Awards .......... Amortization of deferred Compensation....................... Balance, Sept. 30, 1997 ............ 53,529 Comprehensive Income: Net Income .......................... Other comprehensive loss, net of tax—unrealized losses on available-for-sale securities ..... Comprehensive income ............ Cash dividends ($.275 per share) Exercise of Stock Options .......... Purchase of stock for treasury..... Lapse of restrictions on Restricted Stock Awards .......... Stock issued under Restricted Stock Award Plan................... Amortization of deferred Compensation....................... Balance, Sept. 30, 1998 ............ 53,529 Comprehensive Income: Net Income .......................... Other comprehensive income, net of tax—unrealized gains on available-for-sale securities ..... Comprehensive income ............ Cash dividends ($.28 per share).. Exercise of Stock Options .......... Lapse of restrictions on Restricted Stock Awards .......... Stock issued under Restricted Stock Award Plan................... Amortization of deferred Compensation....................... Balance, Sept. 30, 1999 ............ 53,529 The accompanying notes are an integral part of these statements. 84,186 57,904 (12,987) (257) 1,105 3,306 276 5,353 51,316 629,562 3,501 (20,105) 114,454 820 101,154 (59,765) (14,007) (174) 999 1,015 (19,112) 1,833 98 5,757 (6,791) (180) 1,034 5,353 59,004 1,186 (5,605) 166 716,875 4,146 (37,168) 54,689 42,788 20,493 (13,866) (226) 1,710 2,201 69 137 (289) (17) 152 84,186 57,904 142,090 (12,987) 4,411 276 820 780,580 101,154 (59,765) 41,389 (14,007) 2,848 (19,112) 98 1,352 793,148 42,788 20,493 63,281 (13,866) 3,911 69 $5,353 $61,411 1,407 $(4,487) 159 $745,956 3,903 $(35,306) $075,182 1,566 $848,109 21 Consolidated Statements of Cash Flows HELMERICH & PAYNE, INC. Years Ended September 30, 1999 1998 1997 (in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income ........................................................................ Adjustments to reconcile net income to net cash provided by operating activities: $(042,788 $(101,154 $(084,186 Depreciation, depletion and amortization........................... Dry holes and abandonments ......................................... Equity in income of affiliate before income taxes ................. Amortization of deferred compensation ............................. Gain on sale of securities............................................... Gain on sale of property, plant and equipment.................... Other - net .................................................................. Change in assets and liabilities: Accounts receivable .................................................. Inventories .............................................................. Prepaid expenses and other ....................................... Accounts payable ..................................................... Accrued liabilities ..................................................... Deferred income taxes ............................................... Other noncurrent liabilities .......................................... ........................................................................................... Net cash provided by operating activities ................... 109,167 11,727 (5,735) 1,566 (2,547) (6,900) 2,148 19,797 214 (5,079) (16,147) 2,367 559 4,769 115,906 158,694 88,350 11,572 (9,050) 1,352 (38,421) (2,951) 974 (20,698) (5,762) (4,682) (194) (8,692) (1,231) 1,812 12,379 71,691 7,783 (3,680) 820 (4,697) (4,545) 1,897 (23,323) (2,724) (5,020) 18,619 15,582 7,506 1,473 81,382 113,533 165,568 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures, including dry hole costs ........................... Proceeds from sale of property, plant and equipment .................. Purchase of investments....................................................... Proceeds from sale of securities............................................. (122,951) 9,990 (537) 2,803 (266,299) 15,414 1,056 73,949 (161,177) 9,432 (1,404) 8,557 Net cash used in investing activities .......................... (110,695) (175,880) (144,592) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from notes payable................................................. Payments made on notes payable........................................... Dividends paid.................................................................... Purchases of stock for treasury .............................................. Proceeds from exercise of stock options................................... Net cash provided by (used in) financing activities ....... 102,000 (141,800) (13,849) 2,932 (50,717) 169,800 (80,000) (13,802) (19,112) 1,974 58,860 34,000 (34,000) (12,970) 3,065 (9,905) NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...................................................................... CASH AND CASH EQUIVALENTS, beginning of period ................. CASH AND CASH EQUIVALENTS, end of period ......................... (2,718) 24,476 $(021,758 (3,487) 27,963 $(024,476 11,071 16,892 $(027,963 The accompanying notes are an integral part of these statements. 22 Notes to Consolidated Financial Statements HELMERICH & PAYNE, INC. September 30, 1999,1998 and 1997 NOTE 1 SUMMARY OF ACCOUNTING POLICIES CONSOLIDATION - The consolidated financial statements include the accounts of Helmerich & Payne, Inc. (the Company), and all of its wholly-owned subsidiaries. Fiscal years of the Company’s foreign consolidated operations end on August 31 to facili- tate reporting of consolidated results. TRANSLATION OF FOREIGN CURRENCIES - The Company has determined that the functional currency for its foreign subsidiaries is the U.S. dollar. The foreign cur- rency transaction loss for 1999, 1998 and 1997 was $21,000, $1,953,000 and $452,000, respectively. USE OF ESTIMATES - The preparation of financial statements in conformity with generally accepted accounting principles requires manage- ment to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. PROPERTY, PLANT AND EQUIPMENT - The Company follows the successful efforts method of accounting for oil and gas properties. Under this method, the Company capitalizes all costs to acquire mineral inter- ests in oil and gas properties, to drill and equip exploratory wells which find proved reserves and to drill and equip development wells. Geological and geophysical costs, delay rentals and costs to drill exploratory wells which do not find proved reserves are expensed. Capitalized costs of producing oil and gas properties are depreciated and depleted by the unit-of-production method based on proved developed oil and gas reserves determined by the Company and reviewed by independent engineers. Reserves are recorded for capitalized costs of undeveloped leases based on management’s estimate of recoverability. Costs of surrendered leases are charged to the reserve. In accordance with 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”, the Company recognizes impairment losses for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the carrying amount of the asset. In 1999, the Company recognized an impairment charge of approximately $10.1 million for proved Exploration and Production properties which is included in depreciation, depletion and amortization expense. After-tax, the impair- ment charge reduced 1999 net income by approximately $6.2 million, $0.13 per share on a diluted basis. In 1998, the Company recognized an impairment charge of approxi- mately $5.4 million for proved Exploration and Production properties which is included in depreciation, depletion and amortization expense. After-tax, the impairment charge reduced 1998 net income by approximately $3.4 million, $0.07 per share on a diluted basis. The Company evaluates impair- ment of exploration and production assets on a field by field basis. Fair value on all long-lived assets are based on dis- counted future cash flows or information provided by sales and purchases of similar assets. Substantially all property, plant and equipment other than oil and gas properties is depreciated using the straight-line method based on the following estimated useful lives: YEARS Contract drilling equipment ............................................. 4-10 Real estate buildings and equipment.............................. 10-50 Other ............................................................................... 3-33 CASH AND CASH EQUIVALENTS - Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which mature within three months from the date of purchase. INVENTORIES - Inventories, primarily materials and supplies, are valued at the lower of cost (moving average or actual) or market. DRILLING REVENUE - Contract drilling revenues are comprised primarily of daywork drilling contracts for which the related revenues and expenses are recognized as work progresses. Fiscal 1999 contract drilling revenues also include revenues of $40,790,000 from a rig construction contract for which revenues were recognized based on the percentage-of-completion method, measured by the percentage that incurred costs to date bear to total esti- mated costs. The rig construction contract was complete by September 30, 1999. GAS IMBALANCES - The Company recognizes revenues from gas wells on the sales method, and a liability is recorded for permanent imbalances. INVESTMENTS - The cost of securities used in determining realized gains and losses is based on average cost of the security sold. Investments in companies owned from 20 to 50 percent are accounted for using the equity method with the Company recog- nizing its proportionate share of the income or loss of each investee. The Company owned approximately 22 percent of Atwood Oceanics, Inc. (Atwood) at both September 30, 1999 and 1998. The quoted market value of the Company’s investment was $91,687,500 and $62,437,500 at September 30, 1999 and 1998, respectively. Retained earnings at September 30, 1999 includes approximately $18,697,000 of undistributed earnings of Atwood. 23 Summarized financial information of Atwood is as follows: Gross revenues .............................................................. Costs and expenses ........................................................ Net income .................................................................... Helmerich & Payne, Inc.’s equity in net income, net of income taxes .................................................... Current assets ................................................................ Noncurrent assets ........................................................... Current liabilities ............................................................. Noncurrent liabilities ........................................................ Shareholders’ equity ........................................................ 1999 $ 150,009 122,289 $ 27,720 $ 3,556 $ 50,532 243,072 19,013 82,362 192,229 1998 (in thousands) $ 151,809 112,445 $ 39,364 $ 5,611 $ 51,587 230,150 26,723 91,248 163,766 Helmerich & Payne, Inc.’s investment................................... $ 41,157 $ 35,422 1997 $ 89,082 73,463 $ 15,619 $ 2,282 $ 47,961 168,279 19,621 73,930 122,689 $ 28,895 INCOME TAXES - Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities. OTHER POST EMPLOYMENT BENEFITS - The Company sponsors a health care plan that provides post retirement medical benefits to retired employees. Employees who retire after November 1, 1992 and elect to participate in the plan pay the entire estimated cost of such benefits. The Company has accrued a liability for estimated workers compensation claims incurred. The liability for other benefits to former or inactive employees after employment but before retirement is not material. EARNINGS PER SHARE - Basic earnings per share is based on the weighted-average number of common shares outstanding during the period. Diluted earnings per share includes the dilutive effect of stock options and restricted stock. EMPLOYEE STOCK-BASED AWARDS - Employee stock-based awards are accounted for under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and related information. Fixed plan common stock options do not result in compensation expense, because the exercise price of the stock equals the market price of the underlying stock on the date of grant. TREASURY STOCK - Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to additional paid-in-capital using the average-cost method. DERIVATIVES - As described in Note 2, the Company entered into an interest rate swap agreement in fiscal 1999. This agreement involves the exchange of an amount based on a fixed interest rate for an amount based on a variable interest rate without an exchange of the notional amount upon which the payments are based. The difference to be paid or received is accrued and recognized as an adjustment of interest expense. Gains and losses from termination of interest rate swap agreements are deferred and amortized as an adjustment to interest expense over the original term of the terminated swap agreement. NOTE 2 NOTES PAYABLE AND LONG-TERM DEBT At September 30, 1999, the Company had committed bank lines totaling $120 million; $50 million expires October 2003 and $70 million expires May 2000. Additionally, the Company had uncommitted credit facilities totaling $60 million. Collectively, the Company had $55 million in outstanding borrowings and outstanding letters of credit totaling $8.4 million against these lines at September 30, 1999. Concurrent with the $50 million borrowing under the facility that expires October 2003, the Company entered into an interest rate swap with a notional value of $50 million. The swap effectively converts this $50 million facility from a floating rate to a fixed effective rate of 5.38 percent. The interest rate swap closely correlates with the terms and maturity of the $50 million facility. Excluding the impact of the interest rate swap, the average interest rate for the borrowings at September 30, 1999, was approximately 5.9 percent. The interest rate swap reduces the average rate to approximately 5.4 percent on year-end borrowings. Under the various credit agreements, the Company must meet certain requirements regarding levels of debt, net worth and earnings. 24 NOTE 3 INCOME TAXES The components of the provision (benefit) for income taxes are as follows: Years Ended September 30, 1999 CURRENT: Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,684 Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,963 1,744 State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27,391 DEFERRED: Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TOTAL PROVISION: (842) (771) (72) (1,685) $ 25,706 1998 (in thousands) 1997 $ 36,705 18,728 4,751 60,184 (4,108) 927 (326) (3,507) $ 56,677 $ 18,582 17,214 2,190 37,986 6,349 603 573 7,525 $ 45,511 The amounts of domestic and foreign income are as follows: Years Ended September 30, 1999 1998 (in thousands) 1997 INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATE: Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 41,693 23,245 Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 64,938 $ 106,228 45,992 $ 152,220 $ 84,723 42,692 $127,415 Effective income tax rates on income as compared to the U.S. Federal income tax rate are as follows: 1998 Years Ended September 30, 1999 U.S. Federal income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividends received deduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of higher foreign tax rates . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-conventional fuel source credits utilized . . . . . . . . . . . . . . . . . Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35% (1) 5 (1) 2 40% 35% - 2 - - 37% The components of the Company’s net deferred tax liabilities are as follows: 1999 September 30, 1998 (in thousands) DEFERRED TAX LIABILITIES: Property, plant and equipment Available-for-sale securities Pension provision Equity investment Other Total deferred tax liabilities DEFERRED TAX ASSETS: Financial accruals Other Total deferred tax assets $ 59,695 53,651 3,951 10,759 923 128,979 8,832 3,559 12,391 $ 59,413 41,154 4,602 9,006 114,175 8,853 1,853 10,706 NET DEFERRED TAX LIABILITIES $ 116,588 $ 103,469 1997 35% (1) 1 - 1 36% 25 NOTE 4 SHAREHOLDERS’ EQUITY In June 1998, the board of directors authorized the repurchase of up to 2,000,000 shares of its common stock in open market or private transactions. The repurchased shares will be held in treasury and used for general corporate purposes including use in the Company’s benefit plans. During fiscal 1998, the Company purchased 999,100 shares at a total cost of approximately $19 million. The Company did not purchase any shares in fiscal 1999. The Company has several plans providing for common stock-based awards to employees and to non-employee directors. The plans permit the granting of various types of awards including stock options and restricted stock. Awards may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options expire 10 years after grant. The Company has reserved 1,307,638 shares of its treasury stock to satisfy the exercise of stock options issued under the 1982 and 1990 Stock Option Plans. Effective December 4, 1996, additional options are no longer granted under these plans. Options granted under the 1982 plan vest over a period of nine years while options granted under the 1990 plan generally vest over a seven year period. Options granted under both plans become exercisable in increments as outlined in the plans. In March 1997, the Company adopted the 1996 Stock Incentive Plan (the “Stock Incentive Plan”). The Stock Incentive Plan was effective December 4, 1996, and will terminate December 3, 2006. Under this plan the Company is authorized to grant options for up to 4,000,000 shares of the Company’s common stock at an exercise price not less than the fair market value of the common stock on the date of grant. Up to 600,000 shares of the total authorized may be granted to participants as restricted stock awards. Options granted under the 1996 plan vest over a four-year period. On September 30, 1999, 2,537,000 shares were available for grant under the Stock Incentive Plan. On September 30, 1999, 403,000 shares were available for grant under the Stock Incentive Plan as restricted stock awards. In fis- cal 1999 and 1998, 17,000 and 180,000 shares of restricted stock, respectively, were granted at a weighted-average price of $17.00 and $37.73, respectively, which approximated fair market value at the date of grant. Unearned compensation of $289,000 and $6,791,000 for fiscal 1999 and 1998, respectively, is being amortized over a five-year vesting period as compensation expense. The following summary reflects the stock option activity and related information (shares in thousands): Outstanding at October 1, Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares availableon September 30, for options that may be granted 1999 1998 1997 Weighted-Average Weighted-Average Weighted-Average Options Exercise Price Options Exercise Price Options Exercise Price 2,090 $22.09 1,745 $16.44 1,708 $13.63 16.81 14.28 13.51 $21.34 $20.13 726 (238) (4) 2,574 782 2,537 36.84 12.15 17.54 $22.09 $15.63 544 (175) (24) 2,090 453 3,280 26.07 13.03 14.89 $16.44 $12.22 393 (270) (86) 1,745 135 4,000 The following table summarizes information about stock options at September 30, 1999 (shares in thousands): Range of Exercise Prices to $14.00 $12.00 Outstanding Stock Options Exercisable Stock Options Weighted-Average Remaining Contractural Life 5.1 years Options 812 Weighted-Average Exercise Price $13.59 Options 431 Weighted-Average Exercise Price $13.42 $14.01 $16.51 $26.51 $12.00 to to to to $16.50 117 $26.50 1,105 $37.00 540 $37.00 2,574 0.9 years 8.5 years 8.2 years 7.0 years $16.34 $19.99 $36.84 $21.34 66 150 135 782 $16.34 $26.06 $36.84 $20.13 The following table reflects pro forma net income and earnings per share had the Company applied the fair value method of SFAS No. 123, “Accounting for Stock-Based Compensation”, in measuring compensation cost beginning with 1997 employee stock-based awards. 26 Years Ended September 30, 1999 1998 1997 (in thousands, except per share data) Net Income: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $42,788 40,268 $101,154 99,437 $ 84,186 83,531 Basic earnings per share: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted earnings per share: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .87 .82 .86 .81 2.03 1.99 2.00 1.97 1.69 1.68 1.67 1.65 These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period, and additional options may be granted in future years. The weighted-average fair values of options at their grant date during 1999, 1998 and 1997 were $6.81, $14.63, and $9.50, respectively. The estimated fair value of each option granted is calculated using the Black-Scholes option-pricing model. The following summarizes the weighted-average assumptions used in the model: Expected years until exercise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected stock volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1999 5.5 38% 1.2% 6.0% 1998 7.0 34% 1.6% 5.9% 1997 6.7 27% 1.0% 6.1% On September 30, 1999, the Company had 49,625,666 outstanding common stock purchase rights (“Rights”) pursuant to terms of the Rights Agreement dated January 8, 1996. Under the terms of the Rights Agreement each Right entitled the holder thereof to purchase from the Company one half of one unit consisting of one one-thousandth of a share of Series A Junior Participating Preferred Stock (“Preferred Stock”), without par value, at a price of $90 per unit. The exercise price and the number of units of Preferred Stock issuable on exercise of the Rights are subject to adjustment in certain cases to prevent dilution. The Rights will be attached to the common stock certificates and are not exercisable or transferrable apart from the common stock, until 10 business days after a person acquires 15% or more of the outstanding common stock or 10 business days following the commencement of a tender offer or exchange offer that would result in a person owning 15% or more of the outstanding common stock. In the event the Company is acquired in a merger or certain other business combination transactions (including one in which the Company is the sur- viving corporation), or more than 50% of the Company’s assets or earning power is sold or transferred, each holder of a Right shall have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the exercise price of the Right. The Rights are redeemable under certain circumstances at $.01 per Right and will expire, unless earlier redeemed, on January 31, 2006. As long as the Rights are not separately transferrable, the Company will issue one half of one Right with each new share of common stock issued. NOTE 5 EARNINGS PER SHARE A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows: (in thousands) Basic weighted-average shares . . . . . . . . . . . . . . . . . . . . . . . . Effect of dilutive shares: Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted weighted-average shares . . . . . . . . . . . . . . . . . . . . . . . . . 1999 49,243 561 13 574 49,817 1998 49,948 595 22 617 50,565 1997 49,779 747 35 782 50,561 Restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 540,000 shares of common stock at a price of $36.84 were outstanding at September 30, 1999, but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive, as the exercise prices of the options exceed the average market price of the common shares. NOTE 6 FINANCIAL INSTRUMENTS Notes payable bear interest at market rates and are carried at cost which approximates fair value. The estimated fair value of the Company’s interest rate swap is $2,574,000 at September 30,1999, based on forward-interest rates derived from the year-end yield curve as calculated by the financial institution that is a counterparty to the swap. The estimated fair value of the Company’s avail- able-for-sale securities is primarily based on market quotes. The following is a summary of available-for-sale securities, which excludes those accounted for under the equity method of accounting (see Note 1): Gross Gross Estimated Equity Securities: September 30, 1999 September 30, 1998 Unrealized Unrealized Fair Cost Gains Losses Value (in thousands) $76,057 $76,770 $122,369 $193,364 $1,108 $5,156 $197,318 $164,978 27 During the years ended September 30, 1999, 1998, and 1997, marketable equity available-for-sale securities with a fair value at the date of sale of $2,803,000, $62,792,000 and $8,557,000, respectively, were sold. The gross realized gains on such sales of available-for-sale securities totaled $2,547,000, $30,820,000 and $4,697,000, respectively, and the gross realized losses totaled $0, $1,034,000 and $0 respectively. NOTE 7 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The table below presents changes in the components of accumulated other comprehensive income (loss). Years Ended September 30, 1999 Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . $(54,689 Unrealized gains (losses) on available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . . . 35,600 Less: Reclassification adjustment for net gains realized in net income . . . . . . . . . . . . . . . . . Net unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . Tax benefit (expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net-of-tax amount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,547) 33,053 (12,560) 20,493 1998 (in thousands) $114,454 1997 $056,550 (66,610) (29,786) (96,396) 36,631 (59,765) 98,091 (4,697) 93,394 (35,490) 57,904 Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(75,182 $054,689 $114,454 NOTE 8 EMPLOYEE BENEFIT PLANS The following tables set forth the Company’s disclosures required by SFAS No. 132, “Employers’ Disclosures About Pensions and Other Postretirement Benefits”. Change in benefit obligation: Years ended September 30, 1999 1998 Benefit obligation at beginning of year ....................................................... Service cost................................................................................................ Interest cost................................................................................................ Actuarial (gain) loss ................................................................................... Benefits paid............................................................................................... Benefit obligation at end of year ................................................................. (in thousands) $(36,954 3,700 2,468 (4,468) (1,659) $(36,995 $(33,913 2,836 2,430 231 (2,456) $(36,954 Change in plan assets: Years Ended September 30, 1999 1998 (in thousands) Fair value of plan assets at beginning of year ............................................ Actual return on plan assets....................................................................... Benefits paid............................................................................................... Fair value of plan assets at end of year ..................................................... Funded status of the plan........................................................................... Unrecognized net actuarial gain................................................................. Unrecognized prior service cost ................................................................. Unrecognized net transition asset .............................................................. Prepaid benefit cost.................................................................................... Weighted-average assumptions: Years Ended September 30, Discount rate ...................................................................... Expected return on plan ..................................................... Rate of compensation increase .......................................... 1999 7.50% 9.00% 5.00% $(51,572 8,604 (1,659) $(58,517 $(21,522 (10,127) 1,025 (1,619) $(10,801 1998 6.75% 8.50% 5.00% $(53,834 194 (2,456) $(51,572 $(14,618 (1,647) 1,263 (2,159) $(12,075 1997 7.25% 9.00% 5.50% 28 Components of net periodic (benefit) cost: Years Ended September 30, 1999 Service cost........................................................................ Interest cost ........................................................................ Expected return on plan assets .......................................... Amortization of prior service cost ....................................... Amortization of transition asset .......................................... Recognized net actuarial gain ............................................ Net pension expense (credit).............................................. $ 3,700 2,468 (4,606) 238 (540) 14 $ 1,274 1998 (in thousands) $ 2,836 2,430 (4,542) 238 (540) (65) $ 357 1997 $ 2,114 1,797 (3,592) 239 (540) (66) $ (48) Defined Contribution Plan: Substantially all employees on the United States payroll of the Company may elect to participate in the Company sponsored Thrift/401(k) Plan by contributing a portion of their earnings. The Company contributes amounts equal to 100 percent of the first five percent of the participant’s compensation subject to certain limitations. Expensed Company contributions were $3,315,000, $3,009,000 and $2,255,000 in 1999, 1998 and 1997, respectively. NOTE 9 ACCRUED LIABILITIES Accrued liabilities consist of the following: September 30, 1999 1998 (in thousands) Royalties payable ....................................................................................... Taxes payable - operations......................................................................... Ad valorem tax............................................................................................ Income taxes payable................................................................................. Workers compensation claims.................................................................... Payroll and employee benefits.................................................................... Other .......................................................................................................... ..... $ 9,625 6,990 7,177 3,278 3,122 3,970 7,038 $ 41,200 $ 6,997 6,502 5,907 4,487 3,000 5,576 6,364 $ 38,833 NOTE 10 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, 1999 Cash payments: Interest paid........................................................................ Income taxes paid .............................................................. NOTE 11 RISK FACTORS 1998 (in thousands) 1997 $ 5,705 $ 27,843 $ 1,721 $ 61,056 $ 357 $ 36,347 CONCENTRATION OF CREDIT - Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of temporary cash investments and trade receivables. The Company places its temporary cash investments with high quality financial institutions and limits the amount of credit exposure to any one financial institution. The Company’s trade receivables are primarily with companies in the oil and gas industry. The Company normally does not require collateral except for certain receivables of customers in its natural gas marketing operations. CONTRACT DRILLING OPERATIONS - International drilling operations are significant contributors to the Company’s revenues and net profit. It is possible that operating results could be affected by the risks of such activities, including economic conditions in the international markets in which the Company operates, political and economic instability, fluctuations in currency exchange rates, changes in international regulatory requirements, international employment issues, and the burden of complying with foreign laws. These risks may adversely affect the Company’s future operating results and financial position. During fiscal 1999, the Company’s rig utilization rate decreased compared to the previous two years primarily as a result of reduced demand caused by a decline in the price of oil. The Company believes that its rig fleet is not currently impaired based on an assessment of future cash flows of the assets in question. However, it is possible that the Company’s assessment that it will recover the carrying amount of its rig fleet from future operations may change in the near term. OIL AND GAS OPERATIONS - In estimating future cash flows attributable to the Company’s exploration and production assets, certain assumptions are made with regard to commodity prices received and costs incurred. Due to the volatility of commodity prices, it is possible that the Company’s assumptions used in estimating future cash flows for exploration and production assets may change in the near term. 29 NOTE 12 NEW ACCOUNTING STANDARDS In 1998, the Financial Accounting Standards Board issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, (SFAS 133). This statement is effective for fiscal years beginning after June 15, 2000 and requires that all derivatives be recognized as assets or liabilities in the balance sheet and that these instruments be measured at fair value. The Company has not completed the process of evaluating the impact of adopting SFAS 133. The American Institute of Certified Public Accountants (AICPA) issued Statement of Position (SOP) 98-5, “Reporting on the Costs of Start-Up Activities”, effective for fiscal years beginning after December 15, 1998. The SOP requires that all start-up costs be expensed and that the effect of adopting the SOP be reported as the cumulative effect of a change in accounting principle. The Company will adopt this SOP effective October 1, 1999. The effect of this SOP on the Company’s results of operations and financial position will not be material. NOTE 13 SEGMENT INFORMATION The Company adopted Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures About Segments of an Enterprise and Related Information”, during the fourth quarter of fiscal 1999. SFAS No. 131 establishes standards for reporting infor- mation about segments and related disclosures about products and services, geographical areas, and major customers. Prior year financial statements and notes have been reclassified to conform to the requirements of SFAS No. 131. The Company operates principally in the contract drilling industry, which includes a Domestic segment and an International seg- ment, and in the oil and gas industry, which includes an Exploration and Production segment and a Natural Gas Marketing segment. The contract drilling operations consist of contracting Company-owned drilling equipment primarily to major oil and gas exploration companies. The Company’s primary international areas of operation include Venezuela, Colombia, Ecuador, Argentina and Bolivia. Oil and gas activities include the exploration for and development of productive oil and gas properties located primarily in Oklahoma, Texas, Kansas and Louisiana, as well as, the marketing of natural gas for third parties. The Natural Gas Marketing segment also markets most of the natural gas produced by the Exploration and Production segment retaining a market based fee from the sale of such production. The Company also has a Real Estate segment whose operations are conducted exclusively in the metropolitan area of Tulsa, Oklahoma. The primary areas of operations include a major shopping center and several multi-tenant warehouses. Each reportable segment is a strategic business unit which is managed separately as an autonomous business. Other includes investments in available-for-sale securities, equity owned investments, as well as corporate operations. The Company evaluates performance of its segments based upon operating profit or loss from operations before income taxes which includes revenues from external and internal customers; operating costs; depreciation, depletion and amortization; dry holes and abandonments and taxes other than income taxes. The accounting policies of the segments are the same as those described in Note 1, Summary of Accounting Policies. Intersegment sales are accounted for in the same manner as sales to unaffiliated customers. Summarized financial information of the Company’s reportable segments for each of the years ended September 30, 1999, 1998, and 1997 is shown in the following table: (in thousands) 1999: Contract Drilling External Sales Inter- Segment Total Sales Depreciation Operating Depletion & Profit (Loss) Amortization Total Assets Additions to Long-Lived Assets Domestic . . . . . . . . . . . . . . . . . . . . $213,647 $(02,457 $216,104 $030,154 29,845 International . . . . . . . . . . . . . . . . . 182,987 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 396,634 59,999 Oil & Gas Operations 182,987 399,091 2,457 $031,164 36,178 67,342 $0,371,766 271,746 643,512 $057,975 17,293 75,268 Exploration and Production . . . . . . Natural Gas Marketing . . . . . . . . . 95,953 55,259 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151,212 8,671 Real Estate . . . . . . . . . . . . . . . . . . . . 7,802 Other . . . . . . . . . . . . . . . . . . . . . . . . . Eliminations . . . . . . . . . . . . . . . . . . . 95,953 55,259 151,212 10,202 7,802 (3,988) 1,531 (3,988) 11,245 4,418 15,663 5,338 38,658 174 38,832 1,427 1,566 151,898 15,156 167,054 22,816 276,317 44,333 261 44,594 1,445 1,644 Total . . . . . . . . . . . . . . . . . . . . . $564,319 $(00,000 $564,319 $081,000 $109,167 $1,109,699 $122,951 30 (in thousands) 1998: Contract Drilling External Sales Inter- Segment Total Sales Depreciation Operating Depletion & Profit (Loss) Amortization Total Assets Additions to Long-Lived Assets Domestic . . . . . . . . . . . . . . . . . . . . $177,059 $(04,084 $181,143 $035,817 50,834 International . . . . . . . . . . . . . . . . . 253,072 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 430,131 86,651 Oil & Gas Operations 253,072 434,215 4,084 $023,771 31,689 55,460 $0,351,193 303,907 655,100 $130,237 83,843 214,080 Exploration and Production . . . . . . Natural Gas Marketing . . . . . . . . . 98,696 53,499 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152,195 8,922 Real Estate . . . . . . . . . . . . . . . . . . . . 45,392 Other . . . . . . . . . . . . . . . . . . . . . . . . . Eliminations . . . . . . . . . . . . . . . . . . . 98,696 53,499 152,195 10,448 45,392 (5,610) 1,526 (5,610) 28,088 2,418 30,506 5,371 29,817 292 30,109 1,501 1,280 156,582 15,069 171,651 22,937 240,742 48,066 636 48,702 875 2,642 Total . . . . . . . . . . . . . . . . . . . . . $636,640 $(00,000 $636,640 $122,528 $088,350 $1,090,430 $266,299 1997: Contract Drilling Domestic . . . . . . . . . . . . . . . . . . . . $140,294 $(02,218 $142,512 $024,437 43,118 International . . . . . . . . . . . . . . . . . 176,651 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 316,945 67,555 Oil & Gas Operations 176,651 319,163 2,218 $017,916 26,458 44,374 $0,257,505 210,976 468,481 $195,277 16,900 112,177 Exploration and Production . . . . . . 111,512 69,015 Natural Gas Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180,527 8,641 Real Estate . . . . . . . . . . . . . . . . . . . . 11,746 Other . . . . . . . . . . . . . . . . . . . . . . . . . Eliminations . . . . . . . . . . . . . . . . . . . 111,512 69,015 180,527 10,139 11,746 (3,716) 1,498 (3,716) 55,191 3,363 58,554 5,615 24,627 258 24,885 1,412 1,020 152,892 18,884 171,776 23,310 370,028 43,381 3,170 46,551 1,161 1,288 Total . . . . . . . . . . . . . . . . . . . . . $517,859 $(00,000 $517,859 $131,724 $071,691 $1,033,595 $161,177 The following table reconciles segment operating profit (loss) per the table on page 31 and 32 to income before taxes and equity in income of affiliate as reported on the Consolidated Statements of Income (in thousands). Years Ended September 30, Segment operating profit ...................................................... Unallocated amounts: Income from investments..................................................... General corporate expense ................................................. Interest expense .................................................................. Corporate depreciation ........................................................ Other corporate expense ..................................................... Total unallocated amounts ............................................... Income before income taxes and equity in 1999 $81,000 7,757 (14,198) (6,481) (1,565) (1,575) (16,062) 1998 1997 $122,528 $131,724 44,603 (11,762) (942) (1,280) (927) 29,692 11,437 (9,346) (4,212) (919) (1,269) (4,309) Income of affiliate ................................................................ $64,938 $152,220 $127,415 The following tables present revenues from external customers and long-lived assets by country based on the location of service provided (in thousands). Years Ended September 30, 1999 1998 1997 Revenues United States ................................................................... Venezuela ........................................................................ Colombia ......................................................................... Other Foreign................................................................... Total............................................................................. Long-Lived Assets United States ................................................................... Venezuela ........................................................................ Colombia ......................................................................... Other Foreign................................................................... Total............................................................................. Long-lived assets are comprised of property, plant and equipment. $381,332 59,481 60,838 62,668 $564,319 $479,753 62,931 46,621 101,910 $691,215 $383,568 131,137 79,675 42,260 $636,640 $475,832 85,703 59,848 70,988 $692,371 $341,208 77,858 78,370 20,423 $517,859 $384,861 50,336 69,340 34,488 $539,025 31 Revenues from one company doing business with the contract drilling segment accounted for approximately 17.5 percent, 14.5 percent and 17 percent of the total consolidated revenues during the years ended September 30, 1999, 1998 and 1997, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 12 percent and 10 percent of total consolidated revenues in the years ended September 30, 1999 and 1998. Collectively, revenues from companies controlled by the Venezuelan government accounted for approximately 5.6 percent, 16 percent and 12 percent of total consolidated revenues for the years ended September 30, 1999, 1998 and 1997, respectively. Collectively, the receivables from these customers were approximately $35.6 million and $60.6 million at September 30, 1999 and 1998, respectively. NOTE 14 SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES All of the Company’s oil and gas producing activities are located in the United States. Results of Operations from Oil and Gas Producing Activities - Years Ended September 30, 1999 Revenues ............................................................................ Production costs .................................................................. Exploration expense and valuation provisions ....................... Depreciation, depletion and amortization .............................. Income tax expense ............................................................. Total cost and expenses.................................................... Results of operations (excluding corporate overhead $95,953 23,058 22,992 38,658 3,437 88,145 and interest costs) ............................................................ $07,808 1998 (in thousands) $98,696 21,786 19,005 29,817 9,415 80,023 $18,673 1997 $111,512 21,750 9,943 24,628 19,327 75,648 $ 35,864 Capitalized Costs - September 30, 1999 1998 (in thousands) Proved properties..................................................................................................... Unproved properties ................................................................................................ Total costs ............................................................................................................ Less - Accumulated depreciation, depletion and amortization................................. Net ........................................................................................................................ $421,552 25,337 446,889 312,644 $134,245 $414,770 20,977 435,747 295,045 $140,702 Costs Incurred Relating to Oil and Gas Producing Activities - Years Ended September 30, 1999 Property acquisition: Proved ............................................................................. Unproved.......................................................................... Exploration........................................................................... Development........................................................................ Total ................................................................................. $00,089 14,385 22,292 19,167 $55,933 1998 (in thousands) $ 107 9,096 18,107 28,259 $55,569 1997 $ 47 8,358 9,656 27,808 $45,869 32 Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) - Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological 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 those which are expected to be recovered through existing wells with existing equipment and operating methods. The following is an analysis of proved oil and gas reserves as estimated by the Company and reviewed by independent engineers. OIL (Bbls) GAS (Mmcf) Proved reserves at September 30, 1996 ................................................................... Revisions of previous estimates ................................................................................ Extensions, discoveries and other additions.............................................................. Production.................................................................................................................. Purchases of reserves-in-place ................................................................................. Sales of reserves-in-place ......................................................................................... Proved reserves at September 30, 1997 ................................................................... Revisions of previous estimates ................................................................................ Extensions, discoveries and other additions.............................................................. Production.................................................................................................................. Purchases of reserves-in-place ................................................................................. Sales of reserves-in-place ......................................................................................... Proved reserves at September 30, 1998 ................................................................... Revisions of previous estimates ................................................................................ Extensions, discoveries and other additions.............................................................. Production.................................................................................................................. Purchases of reserves-in-place ................................................................................. Sales of reserves-in-place ......................................................................................... 6,468,116 92,863 419,795 (985,633) 120 (189,875) 5,805,386 (331,280) 175,265 (701,180) 2,890 (189,768) 4,761,313 570,126 151,829 (649,370) 272,301 6,178 25,762 (40,463) 6 (548) 263,236 10,877 20,819 (42,862) 188 (632) 251,626 11,771 22,491 (44,240) 77 (2,105) Proved reserves at September 30, 1999 ................................................................... 4,833,898 239,620 Proved developed reserves at September 30, 1997............................................................................................... September 30, 1998............................................................................................... September 30, 1999............................................................................................... 5,787,116 4,754,319 4,828,071 256,443 249,376 229,765 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) - The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves” (Standardized Measure) is a disclosure requirement under Financial Accounting Standards Board Statement No. 69 “Disclosures About Oil and Gas Producing Activities”. The Standardized Measure does not purport to present the fair market value of a company’s proved oil and gas reserves. This would require consideration of expected future economic and operating conditions, which are not taken into account in calculating the Standardized Measure. Under the Standardized Measure, future cash inflows were estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved oil and gas properties. Tax credits and permanent differences were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a ten percent annual discount rate to arrive at the Standardized Measure. At September 30, 1999 1998 Future cash inflows .................................................................................................... Future costs - Future production and development costs ............................................................ Future income tax expense ................................................................................... Future net cash flows................................................................................................. 10% annual discount for estimated timing of cash flows ........................................... Standardized Measure of discounted future net cash flows ...................................... (in thousands) $688,766 $404,549 (188,579) (135,763) 364,424 (131,806) $232,618 (137,068) (70,890) 196,591 (70,664) $125,927 33 Changes in Standardized Measure Relating to Proved Oil and Gas Reserves (Unaudited) _ Years Ended September 30, 1999 1998 (in thousands) 1997 Standardized Measure - Beginning of year............................ Increases (decreases) - Sales, net of production costs ............................................ Net change in sales prices, net of production costs ........... Discoveries and extensions, net of related future Development and production costs ................................ Changes in estimated future development costs ............... Development costs incurred ............................................... Revisions of previous quantity estimates ........................... Accretion of discount .......................................................... Net change in income taxes ............................................... Purchases of reserves-in-place.......................................... Sales of reserves-in-place.................................................. Other .................................................................................. Standardized Measure - End of year ..................................... $125,927 $205,035 $153,864 (72,895) 142,970 38,164 (11,095) 16,558 17,713 16,700 (40,671) 96 (1,390) 541 $232,618 (76,910) (97,938) 21,922 (14,142) 25,149 5,089 28,012 30,436 65 (2,875) 2,084 $125,927 (89,762) 77,789 42,741 (16,570) 27,509 6,146 20,691 (29,397) 2 (1,551) 13,573 $205,035 NOTE 15 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts) 1999 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter Revenues ............................................................................. Gross profit .......................................................................... Net income ........................................................................... Basic net income per share .................................................. Diluted net income per share ............................................... $143,864 25,071 12,811 .26 .26 $155,374 16,924 7,352 .15 .15 $131,799 23,532 12,196 .25 .24 $133,282 20,090 10,429 .21 .21 1998 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter Revenues ............................................................................. Gross profit .......................................................................... Net income ........................................................................... Basic net income per share .................................................. Diluted net income per share ............................................... $151,823 47,351 29,165 .58 .57 $142,389 32,869 19,337 .39 .38 $177,136 55,098 33,861 .68 .67 $165,292 29,606 18,791 .38 .38 Gross profit represents total revenues less operating costs, depreciation, depletion and amortization, dry holes and abandonments, and taxes, other than income taxes. Net income in the fourth quarter of 1998 includes an after-tax charge of $3.1 million ($0.06 per share, on a diluted basis) related to the write-down of producing properties in accordance with SFAS No. 121. Net income in the second quarter of 1999 includes an after-tax charge of $5.5 million ($0.11 per share, on a diluted basis) in connec- tion with the drilling and completion of a pinnacle reef well with reserve values significantly below its carrying cost. 34 Report of Independent Auditors HELMERICH & PAYNE, INC. The Board of Directors and Shareholders Helmerich & Payne, Inc. We have audited the accompanying consolidated balance sheets of Helmerich & Payne, Inc. as of September 30, 1999 and 1998, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 1999. 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helmerich & Payne, Inc. at September 30, 1999 and 1998, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 1999, in conformity with generally accepted accounting principles. Tulsa, Oklahoma November 19, 1999 Stock Price Information Closing Market Price Per Share 1999 1998 QUARTERS HIGH LOW HIGH First .................................................. Second ............................................. Third ................................................. Fourth............................................... $ 24.50 23.94 26.75 30.19 $ 16.75 16.06 20.38 23.00 $ 44.97 33.19 33.25 24.38 LOW $31.06 24.56 21.56 16.25 Dividend Information QUARTERS Paid Per Share Total Payment 1999 1998 1999 1998 First .................................................. $.070 $.065 .070 Second .............................................. .070 Third ................................................. .070 Fourth................................................ .070 .070 .070 $3,457,626 3,459,168 3,464,109 3,468,377 $3,256,874 3,519,195 3,521,332 3,504,269 STOCKHOLDERS’ MEETING The annual meeting of stockholders will be held on March 1, 2000. A formal notice of the meet- ing, together with a proxy statement and form of proxy, will be mailed to shareholders on or about January 27, 2000. STOCK EXCHANGE LISTING Helmerich & Payne, Inc. Common Stock is traded on the New York Stock Exchange with the ticker symbol “HP.” The newspaper abbreviation most commonly used for financial reporting is “HelmP.” Options on the Company’s stock are also traded on the New York Stock Exchange. STOCK TRANSFER AGENT AND REGISTRAR As of December 15, 1999, there were 1,306 record holders of Helmerich & Payne, Inc. com- mon stock as listed by the transfer agent’s records. Our Transfer Agent is responsible for our share- holder records, issuance of stock certificates, and distribution of our dividends and the IRS Form 1099. Your requests, as shareholders, concerning these matters are most efficiently answered by corresponding directly with The Transfer Agent at the following address: UMB Bank Security Transfer Division 928 Grand Blvd., 13th Floor Kansas City, MO 64106 Telephone: (800) 884-4225 (816) 860-5000 FORM 10-K The Company’s Annual Report on Form 10-K, which has been submitted to the Securities and Exchange Commission, is available free of charge upon written request. DIRECT INQUIRIES TO: President Helmerich & Payne, Inc. Utica at Twenty-First Tulsa, Oklahoma 74114 Telephone: (918) 742-5531 Internet Address: http://www.hpinc.com 35 Eleven-Year Financial Review HELMERICH & PAYNE, INC. Years Ended September 30, 1999 1998 1997 REVENUES AND INCOME* › Contract Drilling Revenues.......................................................... Crude Oil Sales........................................................................... Natural Gas Sales ....................................................................... Gas Marketing Revenues............................................................ Real Estate Revenues................................................................. Dividend Income ......................................................................... Other Revenues .......................................................................... Total Revenues††........................................................................ Net Cash Provided by Continuing Operations†† ........................ Income from Continuing Operations ........................................... Net Income ................................................................................. PER SHARE DATA Income from Continuing Operations‹ : Basic ...................................................................................... Diluted.................................................................................... Net Income‹ : Basic ...................................................................................... Diluted.................................................................................... Cash Dividends ........................................................................... Shares Outstanding*................................................................... 394,715 9,479 81,533 54,263 8,663 3,569 12,097 564,319 158,694 42,788 42,788 .87 .86 .87 .86 .28 49,626 427,713 10,333 87,646 52,469 8,587 4,117 45,775 636,640 113,533 101,154 101,154 2.03 2.00 2.03 2.00 .275 49,383 315,327 20,475 87,737 66,306 8,224 5,268 14,522 517,859 165,568 84,186 84,186 1.69 1.67 1.69 1.67 .26 50,028 FINANCIAL POSITION Net Working Capital* .................................................................. Ratio of Current Assets to Current Liabilities .............................. Investments* ............................................................................... Total Assets* ............................................................................... Long-Term Debt* ........................................................................ Shareholders’ Equity* ................................................................. 88,720 2.23 238,475 1,109,699 50,000 848,109 58,861 1.47 200,400 1,090,430 50,000 793,148 62,837 1.66 323,510 1,033,595 __ 780,580 CAPITAL EXPENDITURES* Contract Drilling Equipment ........................................................ Wells and Equipment .................................................................. Real Estate ................................................................................. Other Assets (includes undeveloped leases) .............................. Discontinued Operations............................................................. Total Capital Outlays ................................................................... PROPERTY, PLANT AND EQUIPMENT AT COST* Contract Drilling Equipment ........................................................ Producing Properties .................................................................. Undeveloped Leases .................................................................. Real Estate ................................................................................. Other ........................................................................................... Discontinued Operations............................................................. Total Property, Plant and Equipment........................................... 68,639 29,947 1,435 22,930 __ 122,951 881,269 421,552 25,337 49,065 71,139 __ 206,794 38,970 854 19,681 __ 266,299 829,217 414,770 20,977 48,451 65,120 __ 109,036 35,024 1,095 16,022 __ 161,177 643,619 395,812 14,109 47,682 59,659 __ 1,448,362 1,378,535 1,160,881 * 000’s omitted. ††Chemical operations were sold August 30, 1996. Prior year amounts have been restated to exclude discontinued operations. Includes $13.6 million ($.28 per share, on a diluted basis) effect of impairment charge for adoption of SFAS No. 121 in 1995 and cumulative effect of change in accounting for income taxes of $4,000,000 ($.08 per share, on a diluted basis) in 1994. › See Note 13 for segment presentation of revenues. 36 ‹ 1996 1995 1994 1993 1992 1991 1990 1989 244,338 15,378 60,500 57,817 8,076 3,650 3,496 393,255 121,420 45,426 72,566 .92 .91 1.47 1.46 .2525 49,771 51,803 1.83 229,809 821,914 __ 645,970 79,269 21,142 752 7,003 1,581 109,747 203,325 13,227 33,851 34,729 7,560 3,389 10,640 306,721 84,010 5,788 9,751 .12 .12 .20 .20 .25 49,529 50,038 1.74 156,908 707,061 __ 562,435 80,943 19,384 873 9,717 859 111,776 568,110 392,562 9,242 46,970 53,547 __ 1,070,431 501,682 384,755 8,051 46,642 55,655 13,937 1,010,722 182,781 13,161 45,261 51,874 7,396 3,621 6,058 310,152 74,463 17,108 24,971 .35 .35 .51 .51 .2425 49,420 76,238 2.63 87,414 621,689 __ 524,334 53,752 40,916 902 9,695 618 105,883 444,432 377,371 11,729 47,827 48,612 13,131 943,102 112,833 149,661 16,369 15,392 38,370 52,446 63,786 40,410 7,541 4,050 6,646 226,219 60,414 8,973 10,849 7,620 3,535 8,283 300,723 72,493 22,158 24,550 .46 .45 .51 .50 .24 49,275 104,085 3.24 84,945 610,504 3,600 508,927 24,101 23,142 436 5,901 629 54,209 418,004 340,176 10,010 47,502 45,085 12,545 873,322 .19 .19 .22 .22 .2325 49,152 82,800 3.31 87,780 585,504 8,339 493,286 43,049 21,617 690 16,984 158 82,498 404,155 329,264 12,973 47,286 43,153 11,962 848,793 105,364 17,374 35,628 10,055 7,542 5,285 20,020 201,268 50,006 19,608 21,241 .41 .41 .44 .44 .23 48,976 108,212 4.19 96,471 575,168 5,693 491,133 56,297 34,741 2,104 6,793 2,594 102,529 370,494 312,438 5,552 46,671 36,423 11,838 783,416 90,974 16,058 37,697 10,566 7,636 7,402 56,131 226,464 53,288 45,489 47,562 .94 .93 .98 .98 .22 48,971 146,741 3.72 99,574 582,927 5,648 479,485 18,303 16,489 1,467 5,448 1,153 42,860 324,293 287,248 5,507 44,928 32,135 9,270 703,381 78,315 14,821 33,013 __ 7,778 9,127 17,371 160,425 65,474 20,715 22,700 .43 .43 .47 .47 .21 48,346 114,357 3.12 130,443 591,229 49,087 443,396 17,901 30,673 878 6,717 815 56,984 323,313 279,768 5,441 48,016 29,716 8,156 694,410 37 Eleven-Year Operating Review HELMERICH & PAYNE, INC. Years Ended September 30, 1999 1998 1997 CONTRACT DRILLING Drilling Rigs, United States ................................................................ Drilling Rigs, International.................................................................. Contract Wells Drilled, United States................................................. Total Footage Drilled, United States* ................................................. Average Depth per Well, United States ............................................. Percentage Rig Utilization, United States .......................................... Percentage Rig Utilization, International............................................ 50 39 273 3,078 11,275 75 53 46 44 242 2,938 12,142 95 88 38 39 246 2,753 11,192 88 91 PETROLEUM EXPLORATION AND DEVELOPMENT Gross Wells Completed ..................................................................... Net Wells Completed ......................................................................... Net Dry Holes .................................................................................... 49 23.9 7.1 62 35.7 4.2 100 49.3 9.6 PETROLEUM PRODUCTION Net Crude Oil and Natural Gas Liquids Produced (barrels daily)................................................................. Net Oil Wells Owned — Primary Recovery........................................ Net Oil Wells Owned — Secondary Recovery................................... Secondary Oil Recovery Projects ...................................................... Net Natural Gas Produced (thousands of cubic feet daily) ....................................................... Net Gas Wells Owned........................................................................ 1,779 124 54 5 1,921 124 53 5 2,700 133 49 5 121,206 439 117,431 436 110,859 410 REAL ESTATE MANAGEMENT Gross Leasable Area (square feet)* .................................................. Percentage Occupancy...................................................................... 1,652 95 1,652 97 1,652 95 TOTAL NUMBER OF EMPLOYEES Helmerich & Payne, Inc. and Subsidiaries† ....................................... 3,440 3,340 3,627 * 000’s omitted. † 1988-1989 include U.S. employees only 38 1996 1995 1994 1993 1992 1991 1990 1989 41 36 233 2,499 10,724 82 85 41 35 212 1,933 9,119 71 84 47 29 162 1,842 11,367 69 88 42 29 128 1,504 11,746 53 68 39 30 100 1,085 10,853 42 69 46 25 106 1,301 12,274 47 69 49 20 119 1,316 11,059 50 45 49 20 108 1,350 12,500 44 46 63 35.3 7.3 59 27.4 5.9 44 15 1.7 42 15.9 4.3 54 17.8 4.3 45 20.2 4.3 36 15.3 3.4 45 15.2 2.8 2,212 176.9 63.8 12 94,358 378 2,214 186 64 12 72,387 354 2,431 202 71 14 72,953 341 2,399 202 71 14 78,023 307 2,334 220 74 14 75,470 289 2,152 227 55 12 66,617 278 2,265 223 46 12 65,147 194 2,486 201 214 17 57,490 205 1,654 94 1,652 87 1,652 83 1,656 86 1,656 87 1,664 86 1,664 85 1,669 90 3,309 3,245 2,787 2,389 1,928 1,758 1,864 1,100 39 Directors Officers W. H. Helmerich, III Chairman of the Board Hans Helmerich President and Chief Executive Officer George S. Dotson Vice President, President of Helmerich & Payne International Drilling Co. Douglas E. Fears Vice President and Chief Financial Officer Steven R. Mackey Vice President, Secretary, and General Counsel Steven R. Shaw Vice President, Exploration & Production W. H. Helmerich, III Chairman of the Board Tulsa, Oklahoma Hans Helmerich President and Chief Executive Officer Tulsa, Oklahoma William L. Armstrong** Chairman Transland Financial Services, Inc. Denver, Colorado Glenn A. Cox* President and Chief Operating Officer, Retired Phillips Petroleum Company Bartlesville, Oklahoma George S. Dotson Vice President, President of Helmerich & Payne International Drilling Co. Tulsa, Oklahoma L. F. Rooney, III* Chief Executive Officer Manhattan Construction Company Tulsa, Oklahoma Edward B. Rust, Jr. Chairman and Chief Executive Officer State Farm Insurance Companies Bloomington, Illinois George A. Schaefer** Chairman and Chief Executive Officer, Retired Caterpillar Inc. Peoria, Illinois John D. Zeglis** President AT&T Basking Ridge, New Jersey * Member, Audit Committee ** Member, Human Resources Committee 40 

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