Helmerich & Payne
Annual Report 2001

Plain-text annual report

Helmerich & Payne, Inc. Annual Report for 2001 Revenue Breakdown for 2001 International 19% Contract Drilling Domestic 40% Exploration & Production 26% Oil and Gas Natural Gas Marketing 12% Investments and Other Income 2% Real Estate 1% Financial Highlights Years Ended September 30, 2001 2000 Revenues Net Income Diluted Earnings Per Share Dividends Paid Per Share $ 826,854,000 $ 631,095,000 $ 144,254,000 $ 182,300,000 $ 2.84 $ .30 $ 1.64 $ .285 Capital Expenditures $ 274,670,000 $ 131,932,000 Total Assets $1,364,507,000 $1,259,492,000 President’s Letter To the Co-owners of Helmerich & Payne, Inc. Sometimes risk factors are difficult to identify, much less quantify. Unthinkable risks confronted each of us and our families in the aftermath of the terrorist attacks on the World Trade Center and Pentagon. Dinner table conversations at home and discussions at work contemplated possible threats of anthrax exposure, bioterror, and even nuclear “dirty bomb” strikes on civilians. Today we are a nation at war, facing a real and present danger to our basic freedoms and liberty. We are also a nation united and determined. A renewed patriotic spirit has raised a standard against the evil that struck at our core values. We have witnessed acts of untold heroism and sacrifice, along with a flood of prayers and support from friends of freedom around the globe. We have been inspired by the leadership of President Bush: “The course of this conflict is not known, yet its outcome is certain. Freedom and fear, justice and cruelty have always been at war and we know that God is not neutral between them. The advance of human freedom now depends on us. We will rally the world to this cause by our efforts, by our courage. We will not tire, we will not falter, and we will not fail.” 2 The President has urged all Americans to take up the fight, in part, by leading our lives. That is what your Company intends to do. Each of our employees plays a proud part in an industry vital to our country’s energy security. Remarkably, energy prices are falling at the end of 2001, even in the face of the current geopolitical situation in the Middle East. Will a “smoking gun” surface to further implicate Iraq in terrorist sponsorship? Will a bloody and volatile Palestinian-Israeli conflict deteriorate further? How should markets price the possible risk of a far-reaching supply disruption? We’re confident the market will sort it all out. That time- tested dynamic of free markets is one of the many enduring principles worth fighting for and defending. All the while, your Company will stand prepared and financially fit for the challenges and opportunities ahead. Sincerely, December 14, 2001 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 Both oil and natural gas prices increased substantially at the beginning of the year, resulting in higher demand for land rigs in the United States. Industry census data produced by Reed-Hycalog indicates that 93 percent of all U.S. land rigs were active during 2001, a level of activity not achieved since the early 1980s. The resulting impact of this environment on the Company’s 2001 financial performance was significant. Contract drilling revenues increased 39 percent, and earnings before interest, taxes, depreciation, and amortization (EBITDA) increased by over 50 percent, driven primarily by increased activity in the U.S. land market. FIVE-YEAR OPERATING SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2001 2000 1999 1998 1997 United States (Dollar figures in thousands) Revenues . . . . . . . . . . . . . . . . . . . . . . EBITDA . . . . . . . . . . . . . . . . . . . . . . . Operating Profit . . . . . . . . . . . . . . . . . $332,399 $133,968 $107,691 $214,531 $071,163 $035,808 $213,647 $061,498 $030,154 $177,059 $060,053 $035,817 $140,294 $044,066 $024,437 Activity Days . . . . . . . . . . . . . . . . . . . Rig Utilization . . . . . . . . . . . . . . . . . . . 18,656 97% 15,083 87% 12,509 75% 14,237 95% 12,872 88% International Revenues . . . . . . . . . . . . . . . . . . . . . . EBITDA . . . . . . . . . . . . . . . . . . . . . . . Operating Profit . . . . . . . . . . . . . . . . . $154,890 $ 47,313 $ 28,475 $136,549 $047,853 $009,753 $182,987 $066,075 $029,845 $253,072 $082,650 $050,834 $176,651 $069,621 $043,118 Activity Days . . . . . . . . . . . . . . . . . . . Rig Utilization . . . . . . . . . . . . . . . . . . . 7,283 56% 7,067 47% 8,442 53% 12,832 88% 12,253 91% At the close of fiscal 2001, Helmerich & Payne International Drilling Co. owned ten offshore platform rigs located in the Gulf of Mexico, and 81 land rigs located in the United States (49), Venezuela (14), Ecuador (7), Bolivia (6), Colombia (3), and Argentina (2). The Company also had five international land rigs undergoing major upgrades in the U.S., as well as five land rigs and two offshore platform rigs at various stages of new construction at year-end. 4 Additionally, the Company operates four management contracts on customer-owned platform rigs, three offshore California and one offshore Equatorial Guinea, West Africa. UNITED STATES OPERATIONS Rig utilization averaged 97 and 98 percent, respectively, for land and offshore platform rigs during the year. The Company worked an average of 41 land rigs and ten offshore platform rigs for the whole year, up from 32 land and nine offshore platform rigs in 2000. A total of 11 rigs were added to the land fleet in 2001, seven new FlexRigsTM, one reconditioned medium depth rig, and three deep rigs that were transferred from international operations. The Company plans to complete the construction of 20 FlexRigs during 2002, which will be available for work in the U.S. or international markets. The highly mobile FlexRig, named for its flexible drilling range of 8,000 to 18,000 feet, offers significant drilling efficiencies through improved technology, including disc- brakes, block control system, and the Company’s patented round mud tank system. The FlexRig design has reduced the average moving time by more than one-half of that for a conventional 1500 horsepower rig. The FlexRig design includes many health, safety, and environmental (HSE) improvements and features reducing HSE hazards. These include noise abatement, enhanced anti-fall protection, and an integrated fluid containment system around the rig floor. During 2001, the Company received commitments to build and operate two new self-moving platform rigs in the Gulf of Mexico, one each from Shell Exploration & Production Co. and BP. These rigs are scheduled to commence operations in the third quarter of 2002. (cid:2) FlexRig is a trademark of Helmerich & Payne International Drilling Co. 5 INTERNATIONAL OPERATIONS Rig utilization averaged 56 percent in 2001, compared with 47 percent in 2000, primarily because the Company moved eight rigs to the U.S. for drilling opportunities or refurbishment during 2001. Revenues increased 13 percent over last year, but EBITDA decreased slightly as improvements in Venezuela, Equatorial Guinea, Ecuador, and Argentina were offset by declines in Colombia and Bolivia. Increased operating profit was primarily the result of reduced depreciation expense caused by rig transfers from international to domestic operations, as well as a change in the estimated useful life of drilling equipment, increasing it from ten to 15 years. OUTLOOK The Company has lowered its expectations for drilling activity in the coming year because of the precipitous drop in both oil and natural gas prices caused by reduced economic activity and mild weather in the U.S. Because the present downturn does not appear to be due to excessive supplies, the Company anticipates that it will be short-lived, improving as energy demand rises in response to U.S. and world economic recovery. This is the second volatile drilling cycle in four years and, with each downturn, the industry loses experienced employees and momentum on capital projects, many of which require long lead times to bring to fruition. The inevitable upturn in the cycle is likely to become even more pronounced, stretching the already thin human, technological, and financial resources of the industry. The Company has focused its investment efforts on delivering the latest in equipment and technology to the field and in training our people to operate safely and effectively. Our primary goal remains to deliver high quality equipment and services that will add measurable value to a customer’s drilling operation. 6 Exploration & Production H E L M E R I C H & PAY N E , I N C . SUMMARY Helmerich & Payne, Inc. explores for and produces oil and natural gas primarily in Kansas, Louisiana, Oklahoma, and Texas. The Company also provides natural gas marketing services through its wholly owned subsidiary, Helmerich & Payne Energy Services, Inc. A substantial increase in the price of natural gas produced record financial results for the Exploration and Production segment in 2001. Revenues and operating profit grew 38 percent and 44 percent, respectively, over 2000 levels. Helmerich & Payne Energy Services, Inc.’s revenues increased 24 percent in 2001, although operating profit remained flat for the year. Oil production declined seven percent to average 2,242 barrels per day in 2001, while prices remained flat at $27.88 per barrel compared with $27.95 per barrel in 2000. Natural gas production also declined to 116,128 thousand cubic feet (Mcf) per day, compared with 128,204 Mcf per day in 2000. Natural gas prices increased 63 percent to average $4.55 per Mcf in 2001, compared with $2.79 per Mcf in 2000. FIVE-YEAR OPERATING SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200100 200000 199900 199800 199700 Revenues . . . . . . . . . . . . . . . . . . . . $ 217,194 $00,157,583 $000,95,953 $000,98,696 $00,111,512 Operating Profit . . . . . . . . . . . . . . . . $ 95,579 $000,66,604 $000,11,245 $000,28,088 $000,55,191 (Revenues and operating profit in thousands) Average Oil Price per barrel . . . . . . . . $ 27.88 $0000,27.95 $0000,14.60 $0000,14.74 $0000,20.77 Oil Production (barrels) . . . . . . . . . . . 985,633 Proved Oil Reserves (barrels) . . . . . . 5,805,386 649,370 4,833,898 701,180 4,761,313 818,356 5,931,595 880,304 6,305,137 Average Natural Gas Prices per Mcf . . $ 4.55 $00000,2.79 $00000,1.83 $00000,2.04 $00000,2.24 Natural Gas Production (Mcf) . . . . . . . 42,386,796 40,463,374 Proved Natural Gas Reserves (Bcf) . . . 263.2 216.3 44,240,332 239.6 42,862,300 251.6 46,922,752 262.5 Gross Wells Completed . . . . . . . . . . Net Wells Completed . . . . . . . . . . . . Net Dry Holes . . . . . . . . . . . . . . . . . 123.0 69.5 17.0 81.0 42.7 9.1 49.0 23.9 7.1 62.0 35.7 4.2 100.0 49.3 9.6 7 EXPLORATION RESULTS Even though the Company had a record financial performance, it was a disappointing year for the exploration effort. Proved reserves declined from 300 billion cubic feet equivalent (Bcfe) to 252 Bcfe during 2001. Almost half of this decline was the result of the lower natural gas price used in the reserve calculation, which was $1.90 per Mcf in 2001, compared with $5.13 per Mcf in 2000. The Company participated in 123 (69.5 net) wells in 2001, 29 (17 net) of which were dry holes. Given the high natural gas prices, additional emphasis was placed on developing proved undeveloped reserves during the year. Forty-seven gross wells were drilled for this purpose in 2001. The remaining wells included 40 (19 net) wildcat wells, five of which exposed the Company to over 250 Bcfe in net potential reserve additions. OUTLOOK Given that oil and gas prices have declined substantially, the Company plans to be highly selective with regard to drilling prospects in 2002, and will reduce capital expenditures by as much as half of what they were in 2001. With the assistance of the investment bank of Petrie Parkman & Co., the Company is continuing to explore strategic alternatives for the Oil and Gas Division. These alternatives include combining the Company’s oil and gas operations with another of similar size to form a separate, stand-alone exploration and production company. The Company engaged in discussions with a number of companies during the past year and plans to continue these efforts into 2002. 8 Revenues and Operating Profit by Business Segments HELMERICH & PAYNE, INC. Years Ended September 30, 2001 2000 1999 (in thousands) SALES AND OTHER REVENUES: Contract Drilling - Domestic .............................................. Contract Drilling - International ......................................... Total Contract Drilling................................................... $332,399 154,890 487,289 $214,531 136,549 351,080 $213,647 182,987 396,634 Exploration and Production............................................... Natural Gas Marketing ...................................................... Total Oil and Gas Operations....................................... Real Estate ...................................................................... Other ................................................................................. 217,194 100,111 317,305 11,018 11,242 157,583 80,907 238,490 8,999 32,526 95,953 55,259 151,212 8,671 7,802 Total Revenues ........................................................................ $826,854 $631,095 $564,319 OPERATING PROFIT: Contract Drilling - Domestic .............................................. Contract Drilling - International ......................................... Total Contract Drilling................................................... $107,691 28,475 136,166 $ 35,808 9,753 45,561 $ 30,154 29,845 59,999 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 ................................................................... 95,579 5,254 100,833 6,315 243,314 10,592 (15,415) 32 (2,043) (1,378) (8,212) 66,604 5,271 71,875 5,346 122,782 31,973 (11,578) (3,076) (2,152) (1,186) 13,981 11,245 4,418 15,663 5,338 81,000 7,757 (14,198) (6,481) (1,565) (1,575) (16,062) INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATES .......................... $235,102 $136,763 $ 64,938 Note: See Note 14 (pages 30, 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, risks of foreign operations, uninsured risks, 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 2001 was $144,254,000 ($2.84 per share), compared with net income of $82,300,000 ($1.64 per share) in 2000, and $42,788,000 ($0.86 per share) in 1999. Included in the Company's net income, but not related to its operations, were after-tax gains from the sale of investment securities of $691,000 ($0.01 per share) in 2001, $8,152,000 ($0.16 per share) in 2000, and $1,562,000 ($0.03 per share) in 1999. In addition to income from security sales, the Company also recorded net income during 2000 of $6,637,000 ($0.13 per share) from gains relating to non-monetary dividends received. Also included in net income is the Company’s portion of income from its 10 equity affiliates, which totaled $0.04 per share in 2001, $0.06 in 2000, and $0.07 in 1999. The Company’s equity affiliates are Atwood Oceanics, Inc. and a 50-50 joint venture with Atwood called Atwood Oceanics West Tuna Pty. Ltd., which owns an offshore platform rig. Consolidated revenues were $826,854,000 in 2001, $631,095,000 in 2000, and $564,319,000 in 1999. The 31 percent increase from 2000 to 2001 was due to significant increases in revenues from all of the operating divisions. Revenues from investments decreased by $21,381,000. Contract Drilling Division revenues increased by 39 percent due to the strengthening of the U.S. land rig market. This resulted in higher utilization of the Company’s rigs and higher dayrates. Oil and Gas Division revenues rose 33 percent over 2000 due primarily to higher oil and natural gas prices. The 12 percent increase in consolidated revenues from 1999 to 2000 was primarily due to higher oil and natural gas prices resulting in an increase of $87,278,000 in Oil and Gas Division revenues and increased investment revenues of $24,216,000. Partially offsetting these increases was a reduction of international contract drilling revenues of $46,438,000. Revenues from investments were $10,592,000 in 2001, $31,973,000 in 2000, and $7,757,000 in 1999. Included in revenues were pre-tax gains from the sale of investment securities of $1,189,000 in 2001, $13,295,000 in 2000, and $2,547,000 in 1999. Interest income from short-term investments increased in 2001 and 2000 because the Company’s cash and cash equivalent balances increased in each of these years. Dividend income decreased in 2001, primarily because in 2000, the Company recognized $10,706,000 of non-monetary dividends when three Company investees spun-off subsidiaries to their shareholders. Costs and expenses in 2001 were $591,752,000, 72 percent of revenues, compared with 78 percent in 2000, and 88 percent in 1999. Operating costs, as a percentage of operating revenues, were 51 percent in 2001, 53 percent in 2000, and 60 percent in 1999. Operating costs, as a percentage of operating revenues, declined each of the last two years, primarily due to proportionately higher revenues. Effective October 1, 2000, the Company changed the estimated useful life of its drilling equipment from ten years to 15 years, resulting in lower annual depreciation expense of approximately $30 million in 2001. Excluding write- downs of producing properties, depreciation expense was $78,400,000 in 2001, $106,815,000 in 2000, and $99,108,000 in 1999. Producing property 11 write-downs totaled $8,909,000 in 2001, $4,036,000 in 2000, and $10,059,000 in 1999. General and administrative expenses increased by 33 percent from 2000 to 2001, to a total of $15,415,000, compared with $11,578,000 in 2000, and $14,198,000 in 1999. Expenses rose this past year due to costs associated with legal, accounting, and investment banking fees related to the potential spin-off of the Oil and Gas Division, settlements of lawsuits, higher pension expense accrual, and higher labor and bonus charges, compared with 2000. General and administrative expenses decreased in 2000, compared to 1999, due to the inclusion in 1999 of reduced allocations of charges to operations and unusually high expenses relating to corporate aircraft maintenance. Income taxes, as a percentage of pre-tax income, were 40 percent in 2001, 42 percent in 2000, and 40 percent in 1999. Interest expense for the Company was negative $32,000 in 2001, $3,076,000 in 2000, and $6,481,000 in 1999. Most of the expense reduction from 2000 to 2001 resulted from a reversal of interest expense previously accrued relating to an ad valorem tax dispute that was settled for less interest costs than accrued. The specific case was settled during 2001, resulting in a reversal of interest expense of $2,280,000 that had been accrued in 1999. Additionally, the Company reduced its overall debt position during the last half of 1999 and early 2000, resulting in less debt related interest expense booked in the last three years. CONTRACT DRILLING DIVISION revenues, which include both domestic and international segment revenues, increased 39 percent to $487,289,000 during 2001, from $351,080,000 in 2000. Revenues for 2000 were 11 percent lower than in 1999. Division operating profit of $136,166,000 was almost triple that of the $45,461,000 recorded in 2000. Operating profit for 2000 was 24 percent lower than in 1999. Domestic segment revenues were $332,399,000 in 2001, $214,531,000 in 2000, and $213,647,000 in 1999. Domestic segment operating profit was $107,691,000 in 2001, $35,808,000 in 2000, and $30,154,000 in 1999. Rig utilization for the U.S. land fleet was 97 percent in 2001, 85 percent in 2000, and 69 percent in 1999. Domestic platform rig utilization was 98 percent in 2001, 94 percent in 2000, and 95 percent in 1999. Both U.S. land rig and U.S. platform rig revenues increased in 2001 over 2000. Dayrates for U.S. land rigs and total operating days for the U.S. land rig segment increased dramatically during 2001. Operating profit for the 12 domestic operation improved dramatically from 2000 to 2001, mostly on the strength of average land rig dayrates, which improved more than 50 percent, and the resulting improvement in profit margins. The previously discussed change in the estimated useful life of drilling equipment increased domestic operating profit by approximately $15 million in 2001. U.S. platform rig dayrates did not improve, but total operating days helped boost revenues for the year. Improvements in revenues and operating profit from 1999 to 2000 were primarily the result of average U.S. land rig dayrates and profit margins moving up, while the platform business improved only slightly. During 1999, there were approximately $40 million of revenues recorded as a result of a rig construction project that was completed in early 2000. International segment revenues increased by 13 percent from 2000 to 2001, after falling by 25 percent from 1999 to 2000. International operating profit rose to $28,475,000 in 2001, from $9,753,000 in 2000. Operating profit for 1999 was $29,845,000. International rig utilization averaged 56 percent during 2001, 47 percent in 2000, and 53 percent in 1999. International operating profit improved during 2001, mainly due to lower depreciation expenses resulting from a change in the estimated useful life of the Company’s drilling equipment, as previously discussed. The impact of the change added approximately $15 million to international operating profit in 2001. Revenues in Venezuela increased 24 percent during 2001, and the Company expects to see activity improve slightly in 2002. The Company’s labor contract in Equatorial Guinea added $6,054,000 to international revenues in 2001. The decline in operating profit from 1999 to 2000 was primarily due to reduced activity in Colombia where the Company had previously employed ten rigs. Activitiy in Colombia continued to decline in 2000 and 2001, and currently, the Company has one rig working out of the three remaining in that country. Conversely, Equador’s rig count has grown from three in 1999 to seven in 2001, and an eighth, newly refurbished rig will be shipped during the second quarter of 2002, to begin work under a one-year contract. The Company has international operations in several South American countries. With the exception of Venezuela, the Company believes that its exposure to currency valuation losses is minimal due to the fact that virtually all billings and payments are in U.S. dollars. In Venezuela, approximately 50 percent of the Company’s billings are in U.S. dollars and 50 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 2001, the Company experienced a loss of $796,000 due to devaluation of the bolivar, 13 compared with a $687,000 loss in 2000, and a $712,000 loss in 1999. The Company anticipates additional devaluation losses in Venezuela during 2002, but 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 $1,600,000 to $2,600,000. OIL AND GAS DIVISION operating results include those from its Exploration and Production segment, as depicted in the following table. The Natural Gas Marketing segment will be discussed separately. 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) . . . . . . . . . . 2001 $217,194 $ 95,579 116.1 $ 4.55 2,242 $ 27.88 2000 $157,583 $066,604 128.2 $0002.79 2,405 $0027.95 1999 $ 95,953 $ 11,245 121.2 $ 001.83 1,779 $ 014.60 Exploration and Production segment revenues and operating profit increased significantly this year as average prices received for the Company’s natural gas production rose dramatically. Average prices received for natural gas increased by 63 percent, while average crude oil prices remained flat, compared to 2000. Natural gas and crude oil production for the Company decreased by nine percent and seven percent, respectively. Increased exploration drilling resulted in dry hole and abandonment charges rising to $33.5 million in 2001, compared with $22.6 million in 2000, and $11.4 million in 1999. Revenues and operating profit for 2000 were up substantially from 1999 due to significant increases in both commodity price levels and Company production volumes for natural gas and crude oil. Average prices for natural gas increased by 52 percent and average crude oil prices increased by 91 percent from 1999 to 2000. In 2000, natural gas and crude oil production increased by six percent and 35 percent, respectively, over 1999 levels. Producing property impairment write-downs totaled $8,909,000 in 2001, $4,036,000 in 2000, and $10,059,000 in 1999. During 2002, the Company’s Oil and Gas Division intends to decrease its capital spending over the previous year. However, dry hole, abandonment, and geophysical expenses are difficult to predict and will continue to impact operating profit for the coming year. Additionally, with a reduced capital spending budget, it is expected that the Company’s production volumes for natural gas and crude oil will decline during the year. 14 The Company has retained the investment banking firm of Petrie Parkman & Co. to analyze, develop, and facilitate possible strategic options for the Oil and Gas Division. It is uncertain whether such a transaction will occur or, if so, when. 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 $100,111,000 in 2001, $80,907,000 in 2000, and $55,259,000 in 1999. Operating profit was $5,254,000 in 2001, $5,271,000 in 2000, and $4,418,000 in 1999. The operating profit margin declined to 5.2 percent in 2001, from 6.5 percent in 2000, and 8 percent in 1999. A rapid decline in natural gas prices over the last three-quarters of the year as well as an increasingly competitive gas marketing environment was primarily responsible for lower margins in 2001. 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 59 percent of its total natural gas production. At times, the Exploration and Production segment may direct HPESI to enter into fixed price natural gas sales contracts on its behalf for a small portion (normally less than 20 percent) of its natural gas sales for periods of less than 12 months to guarantee a certain price. In 2001, HPESI had approximately three percent of its natural gas sales portfolio dedicated to such fixed price sales contracts compared to 13.6 percent in 2000. As of September 30, 2001, HPESI had no long-term fixed contracts. REAL ESTATE DIVISION revenues totaled $11,018,000 for 2001, $8,999,000 for 2000, and $8,671,000 for 1999. Operating profit was $6,315,000 in 2001, $5,346,000 in 2000, and $5,338,000 in 1999. The increase in revenues and operating profit in 2001 was due to the sale of a small parcel of raw land. Occupancy rates, revenues, and operating profit remained solid in 2001 due to the continued strength of the Tulsa economy. No material changes are anticipated in the Real Estate Division in 2002. The Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," effective October 1, 2000, which required that all derivatives be recognized 15 as assets or liabilities in the balance sheet and that these instruments be measured at fair value. The effect of SFAS No. 133 on the Company’s results of operations and financial position was not material for fiscal year 2001, and is not expected to be material in 2002. In 2001, the Financial Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” The Company does not anticipate that these pronouncements will have an immediate material impact on its results of operations or financial position. More information on these pronouncements can be found in Note 12 on page 30 of this Annual Report. LIQUIDITY AND CAPITAL RESOURCES The Company’s capital spending was $274,670,000 in 2001, $131,932,000 in 2000, and $122,951,000 in 1999. Net cash provided from operating activities for those same time periods were $278,856,000 in 2001, $201,836,000 in 2000, and $158,694,000 in 1999. In addition to the net cash provided by operating activities, the Company also generated net proceeds from the sale of portfolio securities of $24,439,000 in 2001, $12,569,000 in 2000, and $2,803,000 in 1999. During 2000, the Company announced a program (FlexRig II program) under which it would construct 12 new FlexRigs at an approximate cost of between $7.5 and $8.25 million each. During 2001, the Company completed construction on seven of those 12 rigs. Additionally, the Company announced in 2001 that it would embark on another construction project (FlexRig III program) to build an additional 25 FlexRigs at an approximate cost of $10.2 million each. It is expected that the Company will complete construction on 15 of those 25 rigs under the FlexRig III program during 2002. During 2001, the Company also announced that it had reached agreement with two operators for offshore platform rig operations in the Gulf of Mexico. This will result in the Company spending approximately $50 million to construct two offshore platform rigs that should commence operations in the Company’s third quarter of 2002. These projects, along with ongoing remodification and refurbishment of existing equipment, plus additional drill pipe and other expenditures, should bring Contract Drilling capital expenditures to approximately $340 million in 2002. Additionally, the Oil and Gas Division has estimated its capital spending needs for the coming year to be approximately $50 million. These capital expenditures, along with miscellaneous real estate and corporate 16 capital expenditures, should bring total Company capital spending for 2002 close to $400 million. Funding for this significant increase in Company capital expenditures will come from existing cash balances, internally generated cash flow, additional bank borrowings, and proceeds from securities sales. As described in Note 2 of Notes to Consolidated Financial Statements, in October 1998, the Company obtained $50 million in long-term debt proceeds. The $50 million of long-term debt matures in October 2003. The interest rate on this debt fluctuates based on the 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 five-year term of the note. The Company's interest rate risk exposure is limited to its potential short-term borrowings, and results predominately from fluctuations in short-term interest rates as measured by 30-day LIBOR. This exposure should increase during 2002, as the Company secures additional debt financing. The strength of the Company’s balance sheet is substantial, with current ratios for 2001 and 2000 at 2.7 and 3.4, respectively, and with total bank borrowings less than four percent of total assets at September 30, 2001. Additionally, the Company manages a large portfolio of marketable securities that, at the close of 2001, had a market value of $226,134,000, with a cost basis of $119,165,000. The portfolio, heavily weighted in energy stocks, is subject to fluctuation in the market and may vary considerably over time. Excluding the Company’s equity-method investments, the portfolio is marked to market on the Company’s balance sheet for each reporting period. During 2001, the Company paid a dividend of $0.30 per share, or a total of $15,047,000, representing the 30th consecutive year of dividend increases. Stock Portfolio Held by the Company September 30, 2001 Number of Shares Cost Basis (in thousands, except share amounts) Market Value Atwood Oceanics, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . Schlumberger, Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Transocean Sedco Forex, Inc.. . . . . . . . . . . . . . . . . . . . . SUNOCO, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phillips Petroleum Company . . . . . . . . . . . . . . . . . . . . . . BANK ONE CORPORATION . . . . . . . . . . . . . . . . . . . . . Kerr-McGee Corporation . . . . . . . . . . . . . . . . . . . . . . . . Occidental Petroleum Corporation . . . . . . . . . . . . . . . . . ONEOK, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,000,000 1,480,000 286,528 312,546 240,000 175,000 150,000 150,000 450,000 $ 52,152 23,511 9,509 2,873 5,976 1,969 3,983 3,566 2,751 12,875 $119,165 $ 78,000 67,636 7,564 11,127 12,946 5,507 7,787 3,651 7,452 24,464 $226,134 17 Consolidated Balance Sheets HELMERICH & PAYNE, INC. Assets CURRENT ASSETS: September 30, 2001 2000 (in thousands) Cash and cash equivalents .............................................................. Accounts receivable, less reserve of $1,661 in 2001 and $2,003 in 2000 ... Inventories ................................................................................... Prepaid expenses and other............................................................. Total current assets .................................................................. $ 122,962 147,235 28,934 32,281 $ 108,087 106,630 25,598 24,829 331,412 265,144 INVESTMENTS ................................................................................. 200,286 304,326 PROPERTY, PLANT AND EQUIPMENT, at cost: Contract drilling equipment .............................................................. Oil and gas properties .................................................................... Real estate properties .................................................................... Other .......................................................................................... Less__Accumulated depreciation, depletion and amortization ................. 1,028,015 521,673 50,579 86,300 1,686,567 868,163 891,749 457,724 50,649 80,268 1,480,390 806,785 Net property, plant and equipment............................................... 818,404 673,605 OTHER ASSETS ............................................................................... 14,405 16,417 TOTAL ASSETS ................................................................................ $ 1,364,507 $ 1,259,492 The accompanying notes are an integral part of these statements. 18 Liabilities and Shareholders’ Equity September 30, 2001 2000 (in thousands, except share data) CURRENT LIABILITIES: Accounts payable ............................................................................. Accrued liabilities ............................................................................. Total current liabilities ...................................................... $ 67,595 53,626 121,221 $ 32,279 46,615 78,894 NONCURRENT LIABILITIES: Long-term notes payable ................................................................... Deferred income taxes ...................................................................... Other ............................................................................................. Total noncurrent liabilities .......................................................... 50,000 144,439 22,370 216,809 50,000 156,650 18,245 224,895 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 ............................................ Less treasury stock, 3,676,155 shares in 2001 and 3,548,480 shares in 2000, at cost .... Total shareholders’ equity........................................................... 80,324 943,105 (1,812) 49,309 1,076,279 49,802 1,026,477 66,090 813,885 (3,277) 106,064 988,115 32,412 955,703 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY ................................. $1,364,507 $1,259,492 The accompanying notes are an integral part of these statements. 19 Consolidated Statements of Income HELMERICH & PAYNE, INC. Years Ended September 30, 2001 2000 1999 (in thousands, except per share amounts) REVENUES: Sales and other operating revenues .................................... Income from investments.................................................. $816,262 10,592 $599,122 31,973 $556,562 7,757 ............................................................................................... 826,854 631,095 564,319 COSTS AND EXPENSES: Operating costs .............................................................. Depreciation, depletion and amortization ............................. Dry holes and abandonments ............................................ Taxes, other than income taxes .......................................... General and administrative ............................................... Interest ......................................................................... ............................................................................................... 413,378 87,309 34,042 41,640 15,415 (32) 591,752 316,933 110,851 22,692 29,202 11,578 3,076 494,332 332,330 109,167 11,727 25,478 14,198 6,481 499,381 INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATES ................................. 235,102 136,763 64,938 INCOME TAX EXPENSE ...................................................... 93,027 57,684 25,706 EQUITY IN INCOME OF AFFILIATES net of income taxes ......................................................... 2,179 3,221 3,556 NET INCOME..................................................................... $144,254 $182,300 $ 42,788 EARNINGS PER COMMON SHARE: BASIC .......................................................................... DILUTED ...................................................................... $0562.88 $0562.84 $ $ 1.66 1.64 $ 0.87 $ 0.86 AVERAGE COMMON SHARES OUTSTANDING: BASIC .......................................................................... DILUTED ...................................................................... 50,096 50,772 49,534 50,035 49,243 49,817 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, 1998 ............ 53,529 $5,353 $59,004 $(5,605) $716,875 4,146 $(37,168) $54,689 $ 793,148 Comprehensive income: Net income........................... Other comprehensive income Unrealized gains on available- for-sale securities, net.......... Comprehensive income ............ Cash dividends ($.28 per share).. Exercise of stock options ........... Tax benefit of stock-based awards Stock issued under Restricted Stock Award Plan................... Amortization of deferred compensation ....................... Balance, Sept. 30, 1999 ............ 53,529 Comprehensive income: Net income........................... Other comprehensive income, Unrealized gains on available- for-sale securities,net .......... Comprehensive income ............ Cash dividends ($.285 per share) Exercise of stock options ........... Purchase of stock for treasury...... Tax benefit of stock-based awards Stock issued under Restricted Stock Award Plan................... Amortization of deferred compensation ....................... Balance, Sept. 30, 2000 ............ 53,529 Comprehensive income: Net income........................... Other comprehensive income, Unrealized gains on available- for-sale securities,net ............. Derivatives instruments losses, net Total other comprehensive income Comprehensive income ............ Cash dividends ($.30 per share).. Exercise of stock options ........... Purchase of stock for treasury..... Tax benefit of stock-based awards Amortization of deferred compensation ...................... 42,788 20,493 2,201 69 (13,866) (226) 1,710 137 (289) (17) 152 5,353 61,411 1,407 (4,487) 159 745,956 3,903 (35,306) 75,182 82,300 30,882 4,491 31 (14,448) (366) 21 3,253 (450) 157 (248) (10) 91 5,353 66,090 1,458 (3,277) 77 813,885 3,548 (32,412) 106,064 144,254 (55,769) (986) 7,965 6,269 (15,047) (646) 774 5,808 (23,198) 42,788 20,493 63,281 (13,866) 3,911 69 1,566 848,109 82,300 30,882 113,182 (14,448) 7,744 (450) 31 1,535 955,703 144,254 (55,769) (986) (56,755) 87,499 (15,047) 13,773 (23,198) 6,269 1,465 $(1,812) 13 $943,105 3,676 $(49,802) 1,478 $49,309 $1,026,477 21 Balance, Sept. 30, 2001 ............ 53,529 $5,353 $80,324 The accompanying notes are an integral part of these statements. Consolidated Statements of Cash Flows HELMERICH & PAYNE, INC. Years Ended September 30, 2001 2000 1999 (in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income ........................................................................ Adjustments to reconcile net income to net cash provided by operating activities: $(144,254 $(182,300 $( 42,788 Depreciation, depletion and amortization........................... Dry holes and abandonments ......................................... Equity in income of affiliates before income taxes................ Amortization of deferred compensation ............................. Gain on sale of securities and non-monetary investment income 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 ................... CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures, including dry hole costs ........................... Acquisition of business, net of cash aquired .............................. Proceeds from sale of property, plant and equipment .................. Purchase of investments....................................................... Proceeds from sale of securities ............................................. 110,851 22,692 (5,196) 1,535 (24,000) (2,479) 944 (7,032) (411) (7,780) 6,575 7,557 21,133 (4,853) 119,536 109,167 11,727 (5,735) 1,566 (2,547) (6,900) 2,148 19,797 214 (5,079) (16,147) 2,367 559 4,769 115,906 201,836 158,694 (131,932) (122,951) 87,309 34,042 (4,383) 1,478 (1,189) (4,895) 906 (39,747) (2,062) (4,874) 34,840 9,065 21,641 2,471 134,602 278,856 (274,670) (2,279) 13,173 18,044 24,439 12,569 9,990 (537) 2,803 Net cash used in investing activities .......................... (239,337) (101,319) (110,695) 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 used in financing activities.......................... NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...................................................................... CASH AND CASH EQUIVALENTS, beginning of period ................. CASH AND CASH EQUIVALENTS, end of period ......................... (5,000) (14,175) (450) 5,437 (14,188) 102,000 (141,800) (13,849) 2,932 (50,717) (15,047) (23,198) 13,601 (24,644) 14,875 108,087 $(122,962 86,329 21,758 $0108,087 (2,718) 24,476 $(021,758 The accompanying notes are an integral part of these statements. 22 Notes to Consolidated Financial Statements HELMERICH & PAYNE, INC. September 30, 2001,2000 and 1999 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 con- solidated operations end on August 31 to facilitate 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 currency transac- tion loss for 2001, 2000, and 1999 was $494,000, $664,000, and $21,000, respectively. USE OF ESTIMATES - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make esti- mates and assumptions that affect the amounts reported in the con- solidated 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 capital- izes all costs to acquire mineral interests 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 oil and gas reserves as deter- mined by the Company and its 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 opera- tions when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the carrying amount of the asset. The Company recognized impairment charges of approxi- mately $8.9 million, $4.0 million and $10.1 million in 2001, 2000, and 1999, respectively, for proved Exploration and Production prop- erties which are included in depreciation, depletion, and amortiza- tion expense. After-tax, the impairment charge reduced 2001, 2000, and 1999 net income by approximately $5.5 million, $2.5 mil- lion, and $6.2 million, respectively. On a diluted basis the impair- ment charges reduced earnings per share in 2001, 2000, and 1999 by $0.11, $0.05, and $0.13, respectively. The Company evaluates impairment of exploration and production assets on a field by field basis. Fair value on all long-lived assets is based on discounted 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: Contract drilling equipment . . . . . . . . . . . . . . . . . . . . . . . . .4 -15 Real estate buildings and equipment . . . . . . . . . . . . . . . . .10- 50 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-33 YEARS As a result of an economic evaluation of useful lives of its drilling equipment, the Company extended the depreciable life of its rig equip- ment from ten to 15 years. This change will provide a better matching of revenues and depreciation expense over the useful life of the equip- ment. This change, effective October 1, 2000, reduced depreciation expense for 2001 by approximately $30 million. 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. SHIPPING COSTS - The Company’s shipping and handling costs are included under operating costs for all periods presented. DRILLING REVENUES - Contract drilling revenues are comprised primarily of daywork drilling contracts for which the related revenues and expenses are recognized as work progresses. Fiscal 2000 and 1999 contract drilling revenues also include revenues of $4,109,000, and $40,790,000, respectively, from a rig construction contract for which revenues were recognized based on the percentage-of-completion method, measured by the per- centage that incurred costs to date bear to total estimated costs. The Company does not currently have any third party rig construction con- tracts. GAS IMBALANCES - The Company recognizes revenues from gas wells on the sales method, and a liability is recorded for permanent imbalances resulting from gas wells in which the Company has sold more production than it is entitled. INVESTMENTS - The cost of securities used in determining realized gains and losses is based on the average cost basis of the security sold. Net income in 2001 includes a loss of approximately $1.4 million, $0.03 per share on a diluted basis, resulting from the Company’s assessment that the decline in market value of certain available-for-sale securities below their financial cost basis was other than temporary. Net income in 2000 included approximately $6.6 million, $0.13 per share on a diluted basis, on gains related to non-monetary transactions within the Company’s available-for-sale security invested portfolio which were accounted for at fair value. Investments in companies owned from 20 to 50 percent are accounted for using the equity method with the Company recognizing its propor- tionate share of the income or loss of each investee. The Company owned approximately 22% of Atwood Oceanics, Inc. (Atwood) at both September 30, 2001 and 2000. The quoted market value of the Company's investment was $78,000,000 and $125,063,000 at September 30, 2001 and 2000, respectively. Retained earnings at September 30, 2001 includes approximately $25,514,000 of undistrib- uted 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 ........................................................ 2001 $ 147,540 120,395 $ 27,145 $ 3,596 $ 45,891 304,857 19,144 85,948 245,656 2000 (in thousands) $ 134,514 111,366 $ 23,148 $ 3,221 $ 63,951 248,334 17,484 77,332 217,469 1999 $ 150,009 122,289 $ 27,720 $ 3,556 $ 50,532 243,072 19,013 82,362 192,229 Helmerich & Payne, Inc.’s investment................................... $ 52,153 $ 46,353 $ 41,157 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. CAPITALIZATION OF INTEREST – The Company capitalizes interest on major projects during construction. Interest is capitalized on borrowed funds, with the rate based on the average interest rate on related debt. Capitalized interest for 2001, 2000, and 1999 was $1.3 million, $0.4 million, and $0.1 million, respectively. INTEREST RATE RISK MANAGEMENT - The Company uses derivatives as part of an overall operating strategy to moderate certain financial market risks and is exposed to interest rate risk from long-term debt. To manage this risk, in October 1998, the Company entered into an interest rate swap to exchange floating rate for fixed rate interest payments through October 2003, the remaining life of the debt. The difference to be paid or received is accrued and recog- nized as an adjustment of interest expense. As of September 30, 2001, the Company’s interest rate swap had a notional principal amount of $50 million. The Company’s accounting policy for these instruments is based on its designation of such instruments as hedging transactions. An instrument is designated as a hedge based in part on its effectiveness in risk reduction and one-to-one matching of derivative instruments to underlying transactions. The Company records all derivatives on the balance sheet at fair value. For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure of variability in expected future cash flows that is attributable to a particular risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensive income in stockholders’ equity and reclassified into earnings in the same period or periods during which the hedged trans- action affects earnings. The change in value of the derivative instrument in excess of the cumulative change in the present value of the future cash flows of the risk being hedged, if any, is recognized in the current earnings during the period of change. The Company’s interest rate swap has been designated as a cash flow hedge and is 100% effective in hedging the exposure of variability in the future interest payments attributable to the debt because the terms of the interest swap correlate with the terms of the debt. 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, 2001, the Company had committed bank lines totaling $85 million; $50 million expires October 2003 and $35 million expires May 2002. Additionally, the Company had uncommitted credit facilities totaling $10 million. Collectively, the Company had $50 million in out- standing borrowings and outstanding letters of credit totaling $10.6 million against these lines at September 30, 2001. As described above, concurrent with a $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 and an expiration date of October 2003. The swap effectively converts this $50 million facility from a floating rate of LIBOR plus 50 basis points to a fixed effective rate of 5.38 percent. Excluding the impact of the interest rate swap, the average interest rate for the borrowings at September 30, 2001, was approximately 5.66 percent on a 360 day basis. 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, 2001 CURRENT: Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 57,607 8,870 Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,680 State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73,157 DEFERRED: Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TOTAL PROVISION: 14,020 4,701 1,149 19,870 $ 93,027 2000 (in thousands) 1999 $ 325,736 8,766 3,366 37,868 12,318 6,146 1,352 19,816 $ 57,684 $ 9,684 15,963 1,744 27,391 (842) (771) (72) (1,685) $ 25,706 The amounts of domestic and foreign income are as follows: Years Ended September 30, 2001 2000 (in thousands) 1999 INCOME BEFORE INCOME TAXES AND EQUITY IN INCOME OF AFFILIATES: Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $208,288 26,814 Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $129,373 7,390 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $235,102 $136,763 $ 41,693 23,245 $ 64,938 Effective income tax rates on income as compared to the U.S. Federal income tax rate are as follows: 2000 Years Ended September 30, 2001 U.S. Federal income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividends received deduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of foreign taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-conventional fuel source credits utilized . . . . . . . . . . . . . . . . . Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35% -- 2 -- 3 40% 35% -- 5 -- 2 42% The components of the Company’s net deferred tax liabilities are as follows: 2001 September 30, 2000 (in thousands) DEFERRED TAX LIABILITIES: Property, plant and equipment Available-for-sale securities Pension provision Equity investments Other Total deferred tax liabilities DEFERRED TAX ASSETS: Financial accruals Other Total deferred tax assets $ 101,674 33,937 3,194 15,637 506 154,948 6,746 3,763 10,509 $ 75,653 72,583 4,075 12,734 1,217 166,262 9,612 —00 9,612 NET DEFERRED TAX LIABILITIES $ 144,439 $156,650 1999 35% (1) 5 (1) 2 40% 25 NOTE 4 SHAREHOLDERS’ EQUITY In January 2000, the board of directors authorized the repurchase of up to 1,000,000 shares of the Company’s common stock in the 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 2001, the Company purchased 773,800 shares at a cost of approxi- mately $23,198,000 and in fiscal 2000 purchased 20,600 shares at a cost of approximately $450,000. The Company did not pur- chase any shares is fiscal 1999. As of September 30, 2001, the Company is authorized to repurchase up to 205,600 additional shares. 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 market price of the underlying stock on the date of grant. Stock options expire ten years after grant. The Company has reserved 3,135,509 shares of its treasury stock to satisfy the exercise of stock options issued under the 1990 and 1996 Stock Option Plans. Effective after December 6, 2000, additional options are no longer granted under these Plans. Options granted under the 1996 Plan vest over a four-year period. In fiscal 2001, 843,800 options were granted under the 1996 Plan. In March 2001, the Company adopted the 2000 Stock Incentive Plan (the "Stock Incentive Plan"). The Stock Incentive Plan was effective December 6, 2000, and will terminate December 6, 2010. Under this plan, the Company is authorized to grant options for up to 3,000,000 shares of the Company’s common stock at an exercise price not less than the fair market value of the com- mon stock on the date of grant. Up to 450,000 shares of the total authorized may be granted to participants as restricted stock awards. There was no activity under this plan during fiscal 2001. In fiscal 2000 and 1999, 10,000 and 17,000 shares of restricted stock, respectively, were granted at a weighted-average price of $24.75 and $17.00, respectively, which approximated fair market value at the date of grant. Unearned compensation of $248,000 and $289,000 for fiscal 2000 and 1999, respectively, is being amortized over a five-year period as compensation expense. There were no restricted stock grants in fiscal 2001. The following summary reflects the stock option activity and related information (shares in thousands): 2001 2000 1999 Weighted-Average Weighted-Average Weighted-Average Options Exercise Price Options Exercise Price Options Exercise Price Outstanding at October 1, 2,955 $22.94 2,574 $21.34 2,090 $22.09 Granted Exercised Forfeited/Expired Outstanding on September 30, Exercisable on September 30, Shares available on September 30, for options that may be granted 844 (644) (19) 3,136 1,078 3,000 32.36 21.34 25.57 $25.78 $23.82 24.75 15.44 23.00 $22.94 $22.40 767 (364) (22) 2,955 1,046 1,777 16.81 14.28 13.51 $21.34 $20.13 726 (238) (4) 2,574 782 2,537 The following table summarizes information about stock options at September 30, 2001 (shares in thousands): Outstanding Stock Options Exercisable Stock Options Range of Exercise Prices to $16.50 $12.00 Weighted-Average Remaining Contractural Life 3.7 years Weighted-Average Exercise Price $13.78 Options 374 $16.51 $26.51 $12.00 to to to $26.50 $38.31 $38.31 1,511 1,251 3,136 7.3 years 8.2 years 7.2 years $22.08 $33.84 $25.78 26 Options 284 511 283 1,078 Weighted-Average Exercise Price $13.77 $22.18 $36.85 $23.82 The following table reflects pro forma net income and earnings per share had the Company elected to adopt the fair value method of SFAS No. 123, “Accounting for Stock-Based Compensation,” in measuring compensation cost beginning with 1997 employee stock-based awards. Years Ended September 30, 2001 2000 1999 (in thousands, except per share data) Net Income: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $144,254 $139,211 Basic earnings per share: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0 02.88 $ 002.78 Diluted earnings per share: As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0 02.84 $0 02.74 $ 82,300 $ 78,788 $ 001.66 $ 001.59 $ 001.64 $ 001.57 $ 42,788 $040,268 $000 .87 $ 000.82 $0 00.86 $0 00.81 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 2001, 2000, and 1999 were $13.01, $10.80, and $6.81, 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2001 4.5 43% 1.8% 5.2% 2000 5.5 41% .8% 6.0% 1999 5.5 38% 1.2% 6.0% On September 30, 2001, the Company had 49,852,797 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 ten business days after a person acquires 15% or more of the outstanding common stock or ten 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 $0.01 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 . . . . . . . . . . . . . . . . . . . . . . . . . 2001 50,096 644 32 676 50,772 2000 49,534 492 9 501 50,035 1999 49,243 561 13 574 49,817 Restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 1,250,750 shares of common stock at a weighted-average price of $33.84 were outstanding at September 30, 2001 but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. At September 30, 2000, restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 533,000 shares of common stock at a price of $36.84 were outstanding but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. At September 30, 1999, 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 but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. 27 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 ($1,590,553) at September 30, 2001, 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 available-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, 2001 September 30, 2000 Unrealized Unrealized Fair Cost Gains Losses Value (in thousands) $63,778 $86,901 $ 84,257 $173,137 $3,136 $2,065 $144,899 $257,973 During the years ended September 30, 2001, 2000, and 1999, marketable equity available-for-sale securities with a fair value at the date of sale of $24,439,000, $12,640,000, and $2,803,000, respectively, were sold. The gross realized gains on such sales of available-for-sale securities totaled $3,314,000, $12,576,000, and $2,547,000, respectively, and the gross realized losses totaled $0, $0, and $0 respectively. NOTE 7 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The table below presents changes in the components of accumulated other comprehensive income (loss). Balance at September 30, 1998 . . . . . . . . . . . . . . . . . . . . . . . . 1999 Change: Unrealized Appreciation (Depreciation) on Securities $ 54,689 Pre-income tax amount . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Realized gains in net income (net of $968 income tax) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at September 30, 1999 . . . . . . . . . . . . . . . . . . . . . . . . 2000 Change: Pre-income tax amount . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Realized gains in net income (net of $9,120 income tax) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at September 30, 2000 . . . . . . . . . . . . . . . . . . . . . . . . 2001 Change: Pre-income tax amount . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Realized gains in net income (net of $452 income tax) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at September 30, 2001 . . . . . . . . . . . . . . . . . . . . . . . . NOTE 8 EMPLOYEE BENEFIT PLANS 35,600 (13,528) (1,579) 20,493 75,182 73,810 (28,048) (14,880) 30,882 106,064 (88,762) 33,730 (737) (55,769) $ 50,295 Interest Rate Swap $ (1,590) 604 (986) $ (986) Total $ 54,689 35,600 (13,528) (1,579) 20,493 75,182 73,810 (28,048) (14,880) 30,882 106,064 (90,352) 34,334 (737) (56,755) $ 49,309 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, 2001 2000 (in thousands) Benefit obligation at beginning of year ....................................................... Service cost................................................................................................ Interest cost................................................................................................ Actuarial loss ............................................................................................. Benefits paid............................................................................................... Benefit obligation at end of year ................................................................. $44,838 3,851 3,330 903 (1,189) $51,733 $36,995 3,427 2,741 3,059 (1,384) $44,838 Change in plan assets: Years ended September 30, 2001 2000 (in thousands) Fair value of plan assets at beginning of year ............................................ Actual return (loss) on plan assets ............................................................. Benefits paid............................................................................................... Fair value of plan assets at end of year ..................................................... Funded status of the plan........................................................................... Unrecognized net actuarial (gain) loss ....................................................... Unrecognized prior service cost ................................................................. Unrecognized net transition asset .............................................................. Prepaid benefit cost.................................................................................... $60,611 (5,435) (1,189) $53,987 $ 2,254 6,720 548 (540) $ 8,982 $(58,517 3,478 (1,384) $(60,611 $(15,773 (5,016) 786 (1,079) $(10,464 28 Weighted-average assumptions: Years Ended September 30, Discount rate ...................................................................... Expected return on plan ..................................................... Rate of compensation increase .......................................... Components of net periodic pension expense: 2001 7.50% 9.00% 5.00% Years Ended September 30, 2001 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 .......................................................... $ 3,851 3,330 (5,415) 238 (540) 17 $ 1,481 2000 7.50% 9.00% 5.00% 2000 (in thousands) $ 3,427 2,741 (5,226) 238 (540) (303) $ (337 1999 7.50% 9.00% 5.00% 1999 $ 3,700 2,468 (4,606) 238 (540) 14 $ 1,274 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 $4,935,000, $3,545,000, and $3,315,000 in 2001, 2000, and 1999, respectively. NOTE 9 ACCRUED LIABILITIES Accrued liabilities consist of the following: September 30, 2001 2000 (in thousands) Royalties payable ....................................................................................... Taxes payable - operations......................................................................... Ad valorem tax............................................................................................ Income taxes payable................................................................................. Workers compensation claims.................................................................... Payroll and employee benefits.................................................................... Loss contingency (see note 13) ................................................................. Other .......................................................................................................... ..... $13,527 9,996 354 739 2,585 5,676 10,000 10,749 $53,626 $18,918 6,861 7,783 — 2,840 4,055 — 6,158 $46,615 NOTE 10 SUPPLEMENTAL CASH FLOW INFORMATION Years Ended September 30, 2001 Cash payments: Interest paid........................................................................ Income taxes paid .............................................................. $05,030 $73,039 2000 (in thousands) $02,491 $39,673 1999 $05,705 $27,843 NOTE 11 RISK FACTORS 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 temporary cash investments with established financial institutions and invests in a diversified portfolio of highly rated, short-term money market instruments. 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 eco- nomic 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. 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 com- modity prices received and costs incurred. Due to the volatility of commodity prices, it is possible that the Company’s assumptions used in estimat- ing future cash flows for exploration and production assets may change in the near term. 29 NOTE 12 NEW ACCOUNTING STANDARDS Effective October 1, 2000, the Company adopted Statement of Financial Accounting Standards No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities," as amended, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS 133, as amended, requires that all derivatives be recorded on the balance sheet at fair value. Upon adoption at October 1, 2000, the effect of complying with SFAS 133, as amended, was immaterial to the Company’s results of operations and financial position. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends FASB Statement No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Statement requires that the fair value of a liabil- ity for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. The effect of this standard on the Company’s results of operations and financial position is being evaluated. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations – Reporting the Effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The Statement retains the basic framework of SFAS No. 121, resolves certain implementation issues of SFAS No. 121, extends applicability to discontinued operations, and broadens the presentation of discontinued operations to include a component of an entity. The Statement will be applied prospectively and is effective for financial statements issued for fiscal years beginning after December 15, 2001. Adoption of the Statement is not expected to have any initial impact on the Company’s results of opera- tions or financial position. NOTE 13 CONTINGENT LIABILITIES AND COMMITMENTS LITIGATION SETTLEMENT - As previously discussed in the Company’s filings on Forms 8-K dated March 16, 2001, and June 13, 2001, and in the Company’s Form 10-Q filed on August 13, 2001, the Company is a defendant in Verdin v. R&B Falcon Drilling USA, Inc., et al., a civil action in the United States District Court, Galveston, Texas. The lawsuit alleges, among other things, that the company and many other defendant companies whose collective operations represent a substantial majority of the U.S. offshore drilling industry, conspired to fix wages and benefits paid to drilling employees. Plaintiff con- tends that this alleged conduct violates federal and state antitrust laws. Plaintiff sought treble damages, attorneys’ fees and costs on behalf of him- self and an alleged class of offshore workers. In May 2001, the Company reached an agreement in principle with Plaintiff’s counsel to settle all claims pending court approval of the settlement. In the third quarter of fiscal 2001, the Company accrued $3.25 million to contract drilling expense based on the pending settlement. The total settlement liability is $10 million of which $6.75 million will be paid by the Company’s insurer. The Company does not believe that the settlement will have a material adverse affect on its business or financial position. KANSAS AD VALOREM SETTLEMENT - In fiscal 1997, the Company was assessed with approximately $6.7 million of Kansas ad valorem taxes which had been reimbursed to the Company for the period from October 1983 through June 1988 by interstate pipelines transporting natural gas to end users. In fiscal 1997, based on the assessment, natural gas revenues were reduced by $2.7 million and interest expense was increased by $4.0 million. In March 1998, approximately $6.1 million of the unpaid assessment was placed in an escrow account pending resolution of this matter. Since March 1998, the escrow account and the related liability continued to accrue interest income and interest expense of approximately $1.0 million. The Federal Energy Regulatory Commission approved settlements between the Company and three of the pipelines. The last of these settlements was final in May 2001. The Company paid approximately $3.9 million out of its escrow account for the settlement of all three pipeline proceedings. The three settlements were approximately $3.1 million less than the amount the Company accrued for this liability. The impact of these settlements in the third quarter of fiscal 2001 was to increase natural gas revenues by approximately $1.1 million, reduce interest expense by approximately $2.0 million and reduce the liability by $3.1 million. At September 30, 2001, the Company continues to escrow approximately $337,000 to cover reimbursement lia- bility in the remaining two pipeline proceedings. The Company believes this amount will be adequate to cover future reimbursement liability. COMMITMENTS - The Company, on a regular basis, makes commitments for the purchase of contract drilling equipment. At September 30, 2001, the Company has commitments of approximately $230 million for the purchase of drilling equipment. NOTE 14 SEGMENT INFORMATION The Company operates principally in the contract drilling industry, which includes a Domestic segment and an International segment, and in the oil and gas industry, which includes an Exploration and Production segment and a Natural Gas Marketing segment. The contract drilling opera- tions 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 opera- tions 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 busi- ness. Other includes investments in available-for-sale securities and corporate operations. The "other" component of Total Assets also includes the Company’s investment in equity-owned investments. 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. 30 Summarized financial information of the Company’s reportable segments for each of the years ended September 30, 2001, 2000, and 1999 is shown in the following table: (in thousands) 2001: Contract Drilling External Sales Inter- Segment Total Sales Depreciation Operating Depletion & Amortization Profit Total Assets Additions to Long-Lived Assets Domestic . . . . . . . . . . . . . . . . . . . . $332,399 $(04,487 $336,886 $107,691 28,475 International Services . . . . . . . . . . 154,890 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 487,289 136,166 Oil & Gas Operations 154,890 491,776 4,487 Exploration and Production . . . . . . 217,194 Natural Gas Marketing . . . . . . . . . 100,111 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317,305 11,018 Real Estate . . . . . . . . . . . . . . . . . . . . 11,242 Other . . . . . . . . . . . . . . . . . . . . . . . . . Eliminations . . . . . . . . . . . . . . . . . . . 95,579 5,254 100,833 6,315 217,194 100,111 317,305 12,563 11,242 (6,032) 1,545 (6,032) $025,890 18,838 44,728 $0,506,173 268,947 775,120 $144,063 38,022 182,085 38,104 170 38,274 2,264 2,043 190,907 14,598 205,505 22,621 361,261 89,733 269 90,002 1,190 1,393 Total . . . . . . . . . . . . . . . . . . . . . $826,854 $(00,000 $826,854 $243,314 $ 87,309 $1,364,507 $274,670 2000: Contract Drilling Domestic . . . . . . . . . . . . . . . . . . . . $214,531 $(03,048 $217,579 $035,808 9,753 International . . . . . . . . . . . . . . . . . 136,549 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 351,080 45,561 Oil & Gas Operations 136,549 354,128 3,048 $035,310 38,096 73,406 $0,342,278 259,892 602,170 $040,722 13,825 54,547 Exploration and Production . . . . . . 157,583 80,907 Natural Gas Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238,490 8,999 Real Estate . . . . . . . . . . . . . . . . . . . . 32,526 Other . . . . . . . . . . . . . . . . . . . . . . . . . Eliminations . . . . . . . . . . . . . . . . . . . 157,583 80,907 238,490 10,544 32,526 (4,593) 1,545 (4,593) 66,604 5,271 71,875 5,346 33,462 164 33,626 1,598 2,221 174,466 21,897 196,363 24,235 436,724 65,804 175 65,979 2,909 8,497 Total . . . . . . . . . . . . . . . . . . . . . $631,095 $(00,000 $631,095 $122,782 $110,851 $1,259,492 $131,932 1999: Contract Drilling 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 The following table reconciles segment operating profit per the table on page 31 to income before taxes and equity in income of affiliate as reported on the Consolidated Statements of Income (in thousands). Years Ended September 30, 2001 2000 1999 Segment operating profit ...................................................... Unallocated amounts: Income from investments..................................................... General and administrative expense ................................... Interest expense .................................................................. Corporate depreciation ........................................................ Other corporate expense ..................................................... Total unallocated amounts ............................................... Income before income taxes and equity in $243,314 $122,782 $(81,000 10,592 (15,415) 32 (2,043) (1,378) (8,212) 31,973 (11,578) (3,076) (2,152) (1,186) 13,981 7,757 (14,198) (6,481) (1,565) (1,575) (16,062) income of affiliates ............................................................... $235,102 $136,763 $ 64,938 31 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, 2001 2000 1999 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. $671,964 43,409 27,045 84,436 $826,854 $616,472 84,856 16,195 100,881 $818,404 $494,546 34,922 42,509 59,118 $631,095 $477,593 37,001 26,361 132,650 $673,605 $381,332 59,481 60,838 62,668 $564,319 $479,753 62,931 46,621 101,910 $691,215 Revenues from one company doing business with the contract drilling segment accounted for approximately 14.9 percent, 15.2 percent, and 17.5 percent of the total consolidated revenues during the years ended September 30, 2001, 2000 and 1999, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 8.0 percent, 7.4 percent, and 12 percent of total consolidated revenues in the years ended September 30, 2001, 2000, and 1999, respectively. Collectively, the receivables from these customers were approximately $32.6 million and $17.4 million at September 30, 2001 and 2000, respectively. NOTE 15 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, 2001 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 $217,194 37,418 46,093 38,104 34,986 156,601 2000 (in thousands) $157,583 26,685 30,832 33,462 23,447 114,426 and interest costs) ............................................................ $060,593 $ 43,157 1999 $95,953 23,058 22,992 38,658 3,437 88,145 $ 7,808 Capitalized Costs - September 30, 2001 2000 (in thousands) Proved properties..................................................................................................... Unproved properties ................................................................................................ Total costs ............................................................................................................ Less - Accumulated depreciation, depletion and amortization................................. Net ........................................................................................................................ $486,772 34,901 521,673 357,094 $164,579 Costs Incurred Relating to Oil and Gas Producing Activities - Years Ended September 30, 2001 Property acquisition: Proved ............................................................................. Unproved.......................................................................... Exploration........................................................................... Development........................................................................ Total ................................................................................. $ 00,738 18,612 44,166 41,459 $104,975 2000 (in thousands) $00,105 11,040 43,833 18,843 $73,821 $430,675 27,050 457,725 314,091 $143,634 1999 $00, 89 14,385 22,292 19,167 $55,933 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 demon- strate 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 Netherland, Sewell & Associates, Inc. at September 30, 2001 and 2000. Amounts at Sepbember 30, 1999 were estimated by the Company and reviewed by independent engineers. 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 ......................................................................................... Proved reserves at September 30, 1999 ................................................................... 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, 2000 ................................................................... Revisions of previous estimates ................................................................................ Extensions, discoveries and other additions.............................................................. Production.................................................................................................................. Purchases of reserves-in-place ................................................................................. Sales of reserves-in-place ......................................................................................... OIL (Bbls) 4,761,313 570,126 151,829 (649,370) 4,833,898 1,316,714 1,119,314 (880,304) 1,502 (85,987) 6,305,137 (700,329) 1,144,709 (818,356) 434 GAS (Mmcf) 251,626 11,771 22,491 (44,240) 77 (2,105) 239,620 17,363 52,569 (46,923) 242 (373) 262,498 (17,018) 12,748 (42,387) 496 Proved reserves at September 30, 2001 ................................................................... 5,931,595 216,337 Proved developed reserves at September 30, 1999............................................................................................... September 30, 2000............................................................................................... September 30, 2001............................................................................................... 4,828,071 5,847,217 4,865,569 229,765 217,334 198,103 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 per- manent differences were also considered in the future income tax calculation. Future net cash inflows after income taxes were dis- counted using a ten percent annual discount rate to arrive at the Standardized Measure. At September 30, 2001 2000 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) $ 467,886 $1,377,922 (174,703) (81,253) 211,930 (67,891) $ 144,039 (317,898) (331,672) 728,352 (240,281) $( 488,071 33 Changes in Standardized Measure Relating to Proved Oil and Gas Reserves (Unaudited) _ Years Ended September 30, 2001 2000 (in thousands) 1999 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.................................................. Changes in production rates and other .............................. Standardized Measure - End of year ..................................... $(488,071 $ 232,618 $ 125,927 (179,776) (400,679) 29,387 10,667 17,311 (15,298) 68,021 160,776 619 (35,060) $(144,039 (130,898) 261,926 156,840 (36,994) 13,587 57,730 30,951 (114,762) 542 (700) 17,231 $ 488,071 (72,895) 142,970 38,164 (11,095) 16,558 17,713 16,700 (40,671) 96 (1,390) 541 $ 232,618 NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts) 2001 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter Revenues ............................................................................. Gross profit .......................................................................... Net income ........................................................................... Basic net income per share .................................................. Diluted net income per share ............................................... $192,550 59,614 33,840 .68 .67 $221,569 72,939 41,749 .83 .82 $217,222 67,607 40,437 .80 .79 $195,513 50,325 28,228 .56 .56 2000 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter Revenues ............................................................................. Gross profit .......................................................................... Net income ........................................................................... Basic net income per share .................................................. Diluted net income per share ............................................... $149,581 37,852 20,461 .41 .41 $151,848 36,256 19,273 .39 .39 $151,968 32,605 18,557 .37 .37 $177,698 44,704 24,009 .48 .48 Gross profit represents total revenues less operating costs, depreciation, depletion and amortization, dry holes and abandonments, and taxes, other than income taxes. The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the aver- age number of common shares outstanding. Net income in the second quarter of 2001 includes an after-tax charge of $2.4 million ($0.05 per share, on a diluted basis) related to the write-down of producing properties in accordance with SFAS No. 121. Net income in the third quarter of 2001 includes an after-tax gain of approximately $1.9 million ($0.04 per share, on a diluted basis) related to a 1997 Kansas ad valorem assessment that was settled at less than the original liability. The after-tax gain increased natural gas revenues by approximately $.7 million and decreased interest expense by approximately $1.2 million. Net income in the fourth quarter of 2001 includes an after-tax charge of $2.8 million ($0.06 per share, on a diluted basis) related to the write-down of producing properties in accordance with SAFS No. 121. Net income in the first quarter of 2000 includes approximately $6.3 million ($0.13 per share, on a diluted basis) on gains related to a non-monetary dividend received and a gain on the conversion of shares of common stock of a Company investee pursuant to that investee being acquired. Net income in the fourth quarter of 2000 includes an after-tax charge of $2.5 million ($0.05 per share, on a diluted basis) related to the write-down of producing properties in accordance with SFAS No. 121. 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, 2001 and 2000, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2001. 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 auditing standards generally accepted in the United States. 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, 2001 and 2000, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2001, in conformity with accounting principles generally accepted in the United States. Tulsa, Oklahoma November 19, 2001 Stock Price Information Closing Market Price Per Share 2001 2000 QUARTERS HIGH LOW HIGH First .................................................. Second ............................................. Third ................................................. Fourth............................................... $ 44.19 58.51 51.23 32.77 $ 28.94 39.63 30.82 23.74 $ 27.44 31.00 37.75 38.31 LOW $ 19.13 20.00 29.06 30.06 Dividend Information QUARTERS Paid Per Share Total Payment 2001 2000 2001 2000 STOCKHOLDERS’ MEETING The annual meeting of stockholders will be held on March 6, 2002. 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 25, 2002. 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 14, 2001, there were 1,090 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. ADDITIONAL INFORMATION In a continuing effort to find timely and cost effec- tive communications solutions to serve the needs of our shareholders, we are discontinuing the printing and distribution of our traditional quarterly shareholder reports. Effective the first quarter ending December 31, 2001, quarterly reports on Form 10-Q, earnings releases and financial statements will be made available on the investor relations section of the Company's Web site. Quarterly reports on Form 10-Q, earnings releases and financial statements will also be available free of charge upon written request. First .................................................. $.075 $.070 .070 Second .............................................. .070 Third ................................................. .075 Fourth................................................ .075 .075 .075 $3,748,896 3,776,612 3,796,489 3,765,488 $3,474,612 3,475,623 3,484,189 3,740,863 DIRECT INQUIRIES TO: Investor Relations 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, 2001 2000 1999 REVENUES AND INCOME* (cid:2) 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(cid:3) : Basic ...................................................................................... Diluted.................................................................................... Net Income(cid:3) : Basic ...................................................................................... Diluted.................................................................................... Cash Dividends ........................................................................... Shares Outstanding*................................................................... FINANCIAL POSITION Net Working Capital* .................................................................. Ratio of Current Assets to Current Liabilities .............................. Investments* ............................................................................... Total Assets* ............................................................................... Long-Term Debt* ........................................................................ Shareholders’ Equity* ................................................................. 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........................................... 484,927 22,815 192,962 99,140 9,066 3,909 14,035 826,854 278,856 144,254 144,254 2.88 2.84 2.88 2.84 .30 49,853 349,992 24,601 131,056 78,921 8,991 14,482 23,052 631,095 201,836 82,300 82,300 1.66 1.64 1.66 1.64 .285 49,980 394,715 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 49,626 210,191 2.73 200,286 1,364,507 50,000 1,026,477 186,250 3.36 304,326 1,259,492 50,000 955,703 88,720 2.23 238,475 1,109,699 50,000 848,109 173,856 74,580 1,144 28,904 __ 278,484 1,028,015 486,772 34,901 50,579 86,300 __ 49,774 54,764 2,880 24,514 __ 68,639 29,947 1,435 22,930 __ 131,932 122,951 891,749 430,674 27,050 50,649 80,268 __ 881,269 421,552 25,337 49,065 71,139 __ 1,686,567 1,480,390 1,448,362 * 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. (cid:2) See Note 14 for segment presentation of revenues. 36 (cid:3) 1998 1997 1996 1995 1994 1993 1992 1991 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 58,861 1.47 200,400 1,090,430 50,000 793,148 62,837 1.66 323,510 1,033,595 __ 780,580 206,794 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 __ 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 1,581 109,747 568,110 392,562 9,242 46,970 53,547 __ 1,378,535 1,160,881 1,070,431 203,325 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 9,717 859 111,776 501,682 384,755 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 13,131 943,102 149,661 15,392 52,446 63,786 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 12,545 873,322 112,833 16,369 38,370 40,410 7,541 4,050 6,646 226,219 60,414 8,973 10,849 .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 37 Eleven-Year Operating Review HELMERICH & PAYNE, INC. Years Ended September 30, 2001 2000 1999 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............................................ 59 32 346 4,415 12,761 97 56 48 40 335 4,058 12,115 87 47 46 44 242 2,938 12,142 75 53 PETROLEUM EXPLORATION AND DEVELOPMENT Gross Wells Completed ..................................................................... Net Wells Completed ......................................................................... Net Dry Holes .................................................................................... 123 69.5 17.0 81 42.7 9.1 49 23.9 7.1 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........................................................................ 2,242 113 55 4 2,405 107.1 55.5 3 1,779 124 54 5 116,128 493 128,204 453 121,206 439 REAL ESTATE MANAGEMENT Gross Leasable Area (square feet)* .................................................. Percentage Occupancy...................................................................... 1,652 93 1,652 91 1,652 95 TOTAL NUMBER OF EMPLOYEES Helmerich & Payne, Inc. and Subsidiaries ......................................... 4,245 3,606 3,440 * 000’s omitted. 38 1998 1997 1996 1995 1994 1993 1992 1991 46 44 242 2,938 12,142 95 88 38 39 246 2,753 11,192 88 91 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 62 35.7 4.2 100 49.3 9.6 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 1,921 124 53 5 2,700 133 49 5 117,431 436 110,859 410 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 1,652 97 1,652 95 1,654 94 1,652 87 1,652 83 1,656 86 1,656 87 1,664 86 3,340 3,627 3,309 3,245 2,787 2,389 1,928 1,758 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** Chairman and Chief Executive Officer AT&T Wireless Services Basking Ridge, New Jersey * Member, Audit Committee ** Member, Human Resources Committee 40 

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