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EX-13 4 d11352exv13.htm EX-13 ANNUAL REPORT TO STOCKHOLDERS exv13

EXHIBIT 13

Helmerich & Payne, Inc.

ANNUAL REPORT FOR FISCAL 2003

Helmerich & Payne, Inc.

Helmerich & Payne, Inc. is the holding Company for Helmerich & Payne International Drilling Co., an international drilling contractor with land and offshore platform operations in the United States, South America, Africa, and Europe. Holdings also include commercial real estate properties in the Tulsa, Oklahoma, area and an energy-weighted portfolio of publicly-traded securities valued at approximately $170 million as of September 30, 2003. At the end of 2002, the Company completed the spin-off of Cimarex Energy Co. to shareholders. Cimarex, the Company’s former exploration and production division, was merged with Key Production Company, Inc. and currently trades on the New York Stock Exchange under the symbol XEC.

(H & P INC. LOGO)


FINANCIAL HIGHLIGHTS


Years Ended September 30,	2003		2002

	(in thousands, except per share amounts)
Revenues	$	515,284	$	551,879
Net Income from Continuing Operations		17,873		53,706
Net Income		17,873		63,517
Diluted Earnings per Share from Continuing Operations		0.35		1.07
Diluted Earnings per Share		0.35		1.26
Dividends Paid per Share		0.32		0.305
Capital Expenditures		246,301		312,064
Total Assets		1,415,835		1,227,313

President’s Letter

To the Co-owners of Helmerich & Payne, Inc.

It seems every year the oil and gas business plays an important role on the stage of political and economic events. Few years can match 2003 for the sheer number of headline stories. In the heart of the Middle East, Operation Iraqi Freedom brought the quick overthrow of Saddam Hussein. During the time leading up to the war, Venezuela sustained a crippling two-month nationwide strike, threatening an important source of U.S. crude oil. In the spring, record low natural gas inventories and declining production rates prompted Federal Reserve Chairman Alan Greenspan to warn of a potential natural gas shortage and the serious consequences it posed to economic recovery. Later in the summer, the Northeast sustained a sweeping electrical blackout that stranded 50 million customers.

With this backdrop, the President hoped to sign legislation representing the first serious effort in decades at shaping a national energy policy. Before failing by two votes to another Democratic filibuster, the energy bill had mushroomed to over a thousand pages and an estimated cost of some $100 billion, bearing only a weak resemblance to the President’s original request.

The energy bill represented an unworkable combination: too much pork and too little beef. Pork barrel spending included increased subsidies for ethanol and soybean based fuel mandates, add-ons like aid for an energy efficient shopping mall in Syracuse, and even money for a pet rainforest project in Iowa. While spending ballooned to more than three times the Administration’s stated limit, one of the President’s priorities, the approval for exploration in Alaska’s Arctic National Wildlife Refuge, was thrown overboard early in the Congressional

negotiations. In the end, too little was done to streamline and open access to high potential natural gas exploratory plays on Federal lands, and to promote nuclear power, and to develop clean burning coal technology. All three are important components to a balanced U.S. energy supply.

What are the prospects for the passage of an energy bill during the upcoming election year?

Any attempt should speak clearly to the practical challenges of fueling the world’s largest economy. Lewis Lehrman finds that voice in his piece, “Energetic America,” where he argues for an energy policy that promotes a diverse supply base that is both affordable and dependable. He points out that we are in a time when effective economic and energy policies are indispensable to national security issues, and states, “Combined with President Bush’s supply-side tax policy, an unselfconscious supply-side energy and regulatory policy will lead to abundant and cheaper energy, growth of economic opportunity, and full employment.”

However future politics get sorted out, oil and gas will remain at the center of the energy picture for years to come. Your Company plays an important role in providing new supplies to help meet this growing demand. As we go forward, we look to the opportunities ahead.


		Sincerely,

		Hans Helmerich
		President

December 15, 2003

Contract Drilling Operations

The Company’s first full year as a stand-alone drilling contractor was accompanied by a number of unusual factors: high oil and natural gas prices, a second war in the Persian Gulf, and a major strike in Venezuela, which resulted in turmoil within PDVSA, the Company’s largest customer in South America. The Baker Hughes U.S. Land Rig Count increased by over 30 percent in fiscal 2003, but the journey was bumpy and cautious. The Company delivered 19 third generation FlexRigs* to the U.S. market in 2003, expanding its capacity in this segment by nearly one-third. One of the uncertainties ahead is the U.S. offshore platform market, which softened considerably in 2003. The Company’s South American markets also remain weak due in large part to socio-economic and political factors. During 2003, the Company introduced its first generation FlexRig into two new international markets.

U.S. Land Operations

On average, the Company worked 14 more rigs during the year than in 2002, but lower dayrates, combined with higher training and depreciation expenses associated with the FlexRig3 project, muted financial results for 2003 compared to 2002. At the close of the year, 68 out of 83 available rigs were working. The Company’s fleet of 43 FlexRigs and 11 highly mobile rigs maintained an average utilization of 95 percent during the year, while the remaining 29 conventional rigs had an average utilization rate of 58 percent. Demand continues to be weakest in the deep-drilling end of the business where soft rates are under increasing price competition. Out of the Company’s 16 deep-rated conventional rigs, 11 were idle at the close of the fiscal year. By contrast, the Company had only one idle

* The term “FlexRig” used throughout this Annual Report is a Company trademark Registered in the U.S. Patent and Trademark Office.

rig out of the remaining 13 conventional rigs rated at 20,000 feet or less. The FlexRig, with its flexible depth capacity range of 8,000 to 18,000 feet, has shifted the Company’s fleet capability toward the larger medium-depth segment of the drilling market, and this is having a positive impact on the Company’s activity rate.

At the close of 2003, the Company had 27 FlexRig3s operating, and the results in the field continue to prove their value. Of the 173 wells completed by FlexRig3s this past year, better than two out of three have come in ahead of customer-estimated drilling times. The Company’s investment in employee screening, training, and team building for the FlexRig3 is also paying dividends. Eighteen months into the FlexRig3 project, the Company has achieved a retention rate of 78 percent on the initial training effort. Well-trained and stable crews have enabled the project to achieve outstanding field results, and more customers and their non-operating partners are seeing how FlexRigs can lower well costs, reduce well cycle times, and increase productivity. Throughout 2003, FlexRig3s were nearly 100 percent utilized and working at premium dayrates.

Overall, the U.S. land market appears to be in the early stages of a cyclical transition. Drilling services, as well as other oilfield services and supplies, typically gain more pricing power as supply and demand tighten because of reduced industry capacity. It is in this market phase that the distinct advantages of the FlexRig technology will be most apparent to customers as they begin to refocus on total project costs.

U.S. Offshore Operations

Activity in the offshore platform segment declined by almost one-third during 2003, with five of the Company’s 12 offshore platform rigs under contract in the Gulf of Mexico at year-end. The Company also operated one rig in the Gulf of Mexico and two rigs offshore California under management contracts during 2003. The overall profit margin in the offshore segment is likely to come under increasing pressure during the coming year as some of the working rigs are on long-term projects that have reached the full development stage and will likely alternate between operating rates and the lower standby rates. Out of the seven rigs that are idle in the Company’s fleet, six are capable of returning to work on short notice and the seventh will require shipyard maintenance. The Company retains a large share of the offshore platform market and has considerable design and construction experience in conventional, spar, and deep-water tension-leg platform rigs. The Company is well positioned to compete for any opportunities that emerge in the coming year; however, we expect that any recovery in the platform market will be slow due to long project lead times.

International Operations

An average of 12 rigs were fully employed in 2003, compared to 16 rigs in 2002. Ecuador remained the most active country with an average of seven rigs working, followed by Venezuela with an average of four rigs, and Colombia and Bolivia each with less than a full rig year of activity. Operations in Venezuela are improving as seven rigs were working shortly after the close of the fiscal year, and an eighth rig is expected to start work in the second quarter. Despite numerous challenges presented in Venezuela, we are encouraged by the recent increase in activity.

Venezuela still has promising growth potential, and the Company has the best-equipped and maintained rig fleet in the country.

Two first generation FlexRigs were committed to short-term international contracts in 2003. The first is working for a U.S. based independent in Hungary where, at year-end, it was drilling its third well after a smooth, incident-free start-up. Having previously used a FlexRig in U.S. operations, the customer desired to see the technology, versatility, and mobility of these rigs employed in an important international project. The second FlexRig was deployed for a major international operator under a multi-well contract in the central African nation of Chad. This project is scheduled to begin drilling in December 2003.

Outlook

Looking to 2004 and beyond, we see significant opportunities for a growing international business and believe the Company brings a distinctive combination of experience and innovation to this market. The FlexRig will play an important role in capturing this potential, as we endeavor to introduce this unique technology to international markets. While this transition year was not what we had hoped for financially, the Company improved operating performance, expanded its capacity, and is well positioned in high potential markets to participate in future opportunities. The most critical dimension of quality is our performance in the area of health, safety, and the environment (HSE) and, during 2003, the Company logged one of its best years on record. After the close of the fiscal year, two of our largest customers, ExxonMobil and Royal Dutch Shell, separately recognized the Company’s land and offshore operations for leadership and excellence in HSE.

Financial & Operating Review


Years Ended September 30			2003		2002		2001

*SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME†**
	Operating Revenues			507,331		523,803		531,604
	Operating Costs			345,537		361,669		330,181
	Depreciation			82,513		61,447		49,532
	Operating Income			79,281		100,687		151,891
	Income from Investments			7,953		28,076		10,967
	Interest Expense			12,289		980		1,701
	General and Administrative Expense			41,003		36,563		28,180
	Income from Continuing Operations			17,873		53,706		80,467
	Net Income			17,873		63,517		144,254
	Diluted Earnings Per Common Share:
		Income from Continuing Operations		0.35		1.07		1.58
		Net Income		0.35		1.26		2.84

*$000’s omitted, except per share data.

Certain prior year amounts have been reclassified to conform to current year classifications. (see note 1)

†All data excludes discontinued operations except net income.


SUMMARY FINANCIAL DATA*
	Cash**	38,189	46,883	128,826
	Working Capital**	108,913	105,852	223,980
	Investments	158,770	150,175	203,271
	Plant, Property, and Equipment, Net**	1,058,205	897,445	650,051
	Total Assets	1,415,835	1,227,313	1,300,121
	Long-term Debt	200,000	100,000	50,000
	Shareholders’ Equity	917,251	895,170	1,026,477
	Capital Expenditures**	246,301	312,064	184,668

*$000’s omitted.

** Excludes discontinued operations.


RIG FLEET SUMMARY
	Drilling Rigs –
		United States Land – FlexRigs		43	26	13
		United States Land – Conventional		40	40	36
		United States Offshore Platform		12	12	10
		International		32	33	37

			Total Rig Fleet	127	111	96
		Rig Utilization Percentage –
		United States Land – FlexRigs		97	96	100
		United States Land – Conventional		67	78	96
		United States Land – All Rigs		81	84	97
		United States Offshore Platform		51	83	98
		International		39	51	56


2000		1999		1998		1997		1996		1995		1994		1993

	384,762		431,741		479,592		353,355		274,208		229,316		206,991		167,956
	248,568		290,048		322,861		228,958		184,703		158,815		148,210		114,858
	77,317		70,092		58,187		48,291		39,592		37,364		31,038		29,397
	58,877		71,601		98,544		76,106		49,913		33,137		27,743		23,701
	32,063		7,422		45,152		11,746		5,992		11,279		6,944		9,494
	2,730		5,389		336		34		678		407		385		925
	23,306		24,629		21,299		15,636		15,222		14,019		14,126		12,422
	36,470		32,115		80,790		48,801		25,844		18,464		13,216		8,978
	82,300		42,788		101,154		84,186		72,566		9,751		24,971		24,550
	.73		.65		1.60		.97		.52		.38		.27		.18
	1.64		.86		2.00		1.67		1.46		.20		.51		.50
	107,632		21,758		24,476		27,963		16,892		19,543		29,447		61,656
	179,884		82,893		49,179		65,802		48,128		50,038		76,238		104,085
	307,425		240,891		200,400		323,510		229,809		156,908		87,414		84,945
	526,723		553,769		548,555		392,489		329,377		286,678		235,067		209,877
	1,200,854		1,073,465		1,053,200		987,432		786,351		707,061		624,827		610,935
	50,000		50,000		50,000		—		—		—		—		3,600
	955,703		848,109		793,148		780,580		645,970		562,435		524,334		508,927
	65,820		78,357		217,597		114,626		83,411		89,709		59,379		27,823
	6		6		6		—		—		—		—		—
	32		34		30		29		30		30		36		31
	10		10		10		9		11		11		11		11
	40		39		44		39		36		35		29		29

	88		89		90		77		77		76		76		71
	99		79		100		—		—		—		—		—
	82		68		94		99		88		73		66		48
	85		69		94		99		88		73		66		48
	94		95		99		63		70		66		79		70
	47		53		88		91		85		84		88		68

Management’s Discussion & Analysis of Results of Operations and Financial Condition

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 and those factors discussed under Risk Factors beginning on page 5 of the Company’s Report on Form 10-K for fiscal 2003 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.

SPIN-OFF AND MERGER TRANSACTIONS

On September 30, 2002, Helmerich & Payne, Inc. completed its distribution of 100 percent of the common stock of Cimarex Energy Co. to the Company’s shareholders and the merger of Key Production Company, Inc. into a subsidiary of Cimarex making Key a wholly owned subsidiary of Cimarex. The Cimarex Energy Co. stock distribution was recorded as a dividend and resulted in a decrease to consolidated stockholders’ equity of approximately $152.2 million. The Company and its subsidiaries continue to own and operate contract drilling and real estate businesses, while Cimarex Energy Co. is a separate, publicly traded company that owns and operates an exploration and production business. The Company does not own any common stock of Cimarex Energy Co. (See note 2 of the Consolidated Financial Statements for complete description of the transaction.) As a result of the transaction, the Company is reporting the results of its former exploration and production division (Cimarex Energy Co.) as discontinued operations.

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 2003 was $17,873,000 ($0.35 per share), compared with net income of $63,517,000 ($1.26 per share) in 2002, and $144,254,000 ($2.84 per share) in 2001. Included in net income was income from discontinued operations of $9,811,000 ($0.19 per share) in 2002, and $63,787,000 ($1.26 per share) in 2001. Also included in the Company’s net income, but not related to its operations, were after-tax gains from the sale of investment securities of $3,346,000 ($0.07 per share) in 2003, $15,206,000 ($0.30 per share) in 2002, and $691,000 ($0.01 per share)

in 2001. Also included in net income is the Company’s portion of income or loss from its equity affiliates, Atwood Oceanics, Inc. and a 50-50 joint venture with Atwood called Atwood Oceanics West Tuna Pty. Ltd. (dissolved in 2003). From equity affiliates, the Company recorded a loss of $0.03 per share in 2003, and net income of $0.06 and $0.04 per share in 2002 and 2001, respectively.

Consolidated revenues were $515,284,000 in 2003, $551,879,000 in 2002, and $542,571,000 in 2001. From 2001 to 2003 revenues attributable to contract drilling operations fell slightly each year. However, total revenues increased from 2001 to 2002 due to a larger gain realized on the sale of a portion of the Company’s equity portfolio. U.S. land revenues rose steadily from 2001 to 2003, while international drilling revenues declined significantly during the same period. Although U.S. offshore platform revenues were relatively flat from 2001 to 2002, there was a drop of approximately 15 percent in offshore platform revenues from 2002 to 2003. Revenue reductions in the offshore platform business were mainly due to a drop in rig utilization to 51 percent in 2003, from 83 percent in 2002, and 98 percent in 2001. The increase in U.S. land revenues was fueled by the Company’s increasing rig fleet due to the construction of FlexRigs over the three-year period. The average number of U.S. land rigs available was 76 in 2003, 57 in 2002, and 42 in 2001. Although rig availability increased, rig utilizations fell for the Company’s U.S. land rig fleet to 81 percent in 2003, compared with 84 percent in 2002, and 97 percent in 2001. International rig revenues declined as rig utilizations in that sector fell to 39 percent in 2003, from 51 percent in 2002, and 56 percent in 2001. The Company’s international rig utilization was impacted by significant reductions in activity in Venezuela and Colombia since 2001. Cutbacks in drilling budgets for the government-

owned oil company, PDVSA, reduced drilling in Venezuela. In Colombia, completion of development of a customer’s major oilfield has dramatically reduced drilling activity there.

Revenues from investments were $7,953,000 in 2003, $28,076,000 in 2002, and $10,967,000 in 2001. Included in revenues was the aggregate of pre-tax gains, losses, and write-downs relating to the Company’s portfolio of equity securities which were $5,529,000 in 2003, $24,820,000 in 2002, and $1,189,000 in 2001. Interest and dividend income fell in each year due to reduced cash positions, lower interest rates, and a reduction in the Company’s equity portfolio. Total interest and dividend income was $2,467,000 in 2003, $3,624,000 in 2002, and $9,128,000 in 2001.

Direct operating costs in 2003 were $345,537,000 or 68 percent of operating revenues, compared with $361,669,000 or 69 percent of operating revenues in 2002, and $330,181,000 or 62 percent of operating revenues in 2001. Direct operating costs were lower as a percentage of revenues in 2001, primarily due to the higher average revenue per day and lower daily direct operating costs per day during 2001 in the U.S. land rig segment. Industry rig activity was relatively high in 2001, resulting in higher dayrates for the Company.

Depreciation expense was $82,513,000 in 2003, $61,447,000 in 2002, and $49,532,000 in 2001. Depreciation rose significantly over the two-year period as the Company placed into service 13 new rigs in 2002, and 19 new rigs in 2003. The Company anticipates depreciation expense to increase again during 2004, as a full year of depreciation expense is incurred on rigs placed into service in 2003, and as new rigs are constructed and employed in the field.

The Company’s methodology of reporting business segments and general and administrative expenses has been changed in 2003. This change was driven by last year’s spin-off of our Exploration and Production Company and to better reflect the way the Company manages its contract drilling businesses.

The number of contract drilling business segments reported have increased to three to reflect the Company’s U.S. offshore platform operations separately from the U.S. land rig operations. Formerly, the combined U.S. segments were reported as one segment. It is important to note that total operating profit for U.S. operations and the international contract drilling segment has not changed. U.S. Land and Offshore Platform segments have simply been separated.

Expenses within the Company’s contract drilling business segments have been broken out to delineate direct operating costs from associated general and administrative costs. Formerly, both costs were included in operating costs on the consolidated statements of income. The associated general and administrative costs of the contract drilling segments have been reclassified to general and administrative expense on the consolidated statements of income. These general and administrative costs are still included in the applicable contract drilling segment. No other numbers on the consolidated statements of income were changed or affected by this reclassification.

With the reclassifications, general and administrative expenses totaled $41,003,000 for 2003, $36,563,000 for 2002, and $28,180,000 for 2001. The 30 percent increase from 2001 to 2002 was primarily the

result of increases in employee benefits relating to pension, medical insurance, and 401(k) matching. Employee salaries and bonuses also contributed to the increase, as well as increases in property and casualty insurance costs. With the construction of the FlexRigs, training expenses were also a contributor to the increase from 2001 to 2002. General and administrative expenses rose again from 2002 to 2003 due to additional increases in pension and medical insurance expense, along with increases in property and casualty insurance costs.

Interest expense rose to $12,289,000 in 2003, compared with $980,000 in 2002, and $1,701,000 in 2001. The Company issued a total of $200,000,000 of intermediate-term debt, half of which was placed just prior to the end of fiscal year 2002, and the other half placed at the very beginning of fiscal year 2003. Additionally, the Company also drew on its bank line of credit during 2003, with $30,000,000 drawn at the end of the year.

The provision for income taxes totaled $14,649,000 in 2003, $40,573,000 in 2002, and $54,689,000 in 2001. Effective income tax rates on income from continuing operations were 43 percent in 2003, 44 percent in 2002, and 41 percent in 2001. The increase in effective tax rates from 2001 to 2002 was a result of currency fluctuations, primarily in Venezuela, resulting in additional taxes for inflationary gains and monetary corrections in 2002. There was less of such an effect in 2003, but international income at higher effective tax rates combined with the impact of state income taxes, kept the overall Company tax rate at a relatively high level.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2003 AND 2002


	2003			2002			% Change

	(in thousands, except operating statistics)
*U.S. LAND OPERATIONS*
Revenues	$	273,993		$	232,446			17.9	%
Intersegment elimination		—			(809	)		—
Direct operating expenses		201,398			165,394			21.8
Intersegment elimination		—			(648	)		—
General and administrative expense		9,304			10,087			(7.8	)
Depreciation		44,726			26,311			70.0

Operating profit	$	18,565		$	30,493			(39.1	)

Operating Statistics:
Activity days		22,588			17,478			29.2	%
Average rig revenue per day	$	11,436		$	12,397			(7.8	)
Average rig expense per day	$	8,221		$	8,561			(4.0	)
Average rig margin per day	$	3,215		$	3,836			(16.2	)
Number of owned rigs at end of period		83			66			25.8
Rig utilization		81	%		84	%		(3.6	)

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses.

The Company’s operating profit in its U.S. land rig operations fell by 39 percent from 2002 to 2003, despite the fact that commodity prices were very strong during the year. Historically high crude oil and natural gas prices, and an increasing industry rig count in the United States were all strong signals for an up cycle that could benefit oil service and contract drilling companies. However, in spite of increasing rig activity, average dayrates and margins per rig day fell during the year. Even with higher industry rig counts, the additional capacity added by companies like Helmerich & Payne, along with intense rig-on-rig price competition, delayed improvements in dayrates and margins. More specifically with Helmerich & Payne, 2002 dayrates were aided by the remaining term left on some of the contracts for work relating to FlexRig2s that were completed and commenced work during 2001. Those relatively high dayrates and

margins did not continue at those levels during 2003 after contracts expired. The Company’s increase in rig capacity was brought about by its FlexRig3 construction program that began during 2002 and extended through 2003. During 2003, 19 FlexRig3s were completed and put into service. Two first generation FlexRig’s were sent overseas for work in Hungary and Chad. As a result of the construction program, the Company’s investment in drilling equipment rose significantly, thereby resulting in an increase in depreciation expense. Although the Company will have more rigs available for service next year, and although industry fundamentals are positive going in to 2004, a drop in dayrates or rig utilization could cause U.S. land rig operating profit to decrease next year.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2003 AND 2002


	2003			2002			% Change

	(in thousands, except operating statistics)
*U.S. OFFSHORE PLATFORM OPERATIONS*
Revenues	$	112,633		$	132,249			(14.8	)%
Direct operating expenses		60,589			79,301			(23.6	)
General and administrative expense		2,939			3,451			(14.8	)
Depreciation		12,799			10,809			18.4

Operating profit	$	36,306		$	38,688			(6.2	)

Operating Statistics:
Activity days		2,233			3,286			(32.0	)%
Average rig revenue per day	$	38,239		$	30,424			25.7
Average rig expense per day	$	17,822		$	16,263			9.6
Average rig margin per day	$	20,417		$	14,161			44.2
Number of owned rigs at end of period		12			12			0.0
Rig utilization		51	%		83	%		(38.6	)

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts.

During the year, the Company continued to experience a reduction in activity days and rig utilization in its U.S. offshore platform rig operations. Total revenue and revenue per day during 2003 were aided by the recognition of revenue due to early termination of contracts. During the fourth quarter of 2003, one platform rig was stacked and two rigs that were working at full dayrate were changed to standby status, thereby likely causing a reduction of the first quarter 2004 operating profit for the U.S. offshore rig segment of approximately 50 percent from that of the fourth quarter of 2003. Capital expenditures were reduced dramatically due to the fact that there were no new platform rigs under construction during 2003, whereas two new platform rigs were completed during 2002. It is anticipated that during 2004, the U.S. offshore platform market will continue to be soft, unless and until commodity pricing or other circumstances significantly increase demand for platform rigs.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2003 AND 2002


	2003			2002			% Change

	(in thousands, except operating statistics)
*INTERNATIONAL OPERATIONS*
Revenues	$	109,812		$	151,392			(27.5	)%
Direct operating expenses		81,461			115,294			(29.3	)
General and administrative expense		3,110			2,634			18.1
Depreciation		20,092			20,336			(1.2	)

Operating profit	$	5,149		$	13,128			(60.8	)

Operating Statistics:
Activity days		4,515			5,956			(24.2	)%
Average rig revenue per day	$	19,603		$	21,161			(7.4	)
Average rig expense per day	$	14,140		$	14,599			(3.1	)
Average rig margin per day	$	5,463		$	6,562			(16.7	)
Number of owned rigs at end of period		32			33			(3.0	)
Rig utilization		39	%		51	%		(23.5	)

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts.

Rig activity, revenues, and operating profit in the Company’s international operations declined from 2002 to 2003. The general softness in the international markets was broad based and resulted in lower utilizations in each of the countries in which the Company operated during the 2002-2003 period. The Company’s Venezuelan operations, where the largest number of Company international rigs are located, were also hampered by an attempted coup, which resulted in a strike by workers at PDVSA, the government-owned oil company.

During 2002, the Company recorded an estimated devaluation loss totaling $1,200,000 in Argentina when that country experienced a dramatic economic collapse. As a result of the collapse, the government stopped the outflow of dollars from the country and required that former dollar obligations be paid in Argentina pesos. During 2003, the Company was able to reduce its 2002 estimated loss by approximately $980,000 relating to the Argentina currency devaluation.

In Venezuela, approximately 60 percent of the Company’s billings are in U.S. dollars and 40 percent are in bolivars, the local currency. As a result, the Company is exposed to risk of currency devaluation in Venezuela. Devaluation losses for Venezuelan operations totaled $624,000 in 2003 and $4,393,000 in 2002. The Company anticipates devaluation losses in Venezuela during 2004, but is unable to predict the extent of the devaluation. If 2004 rig activity levels are similar to 2003, and if a 25 percent to 50 percent devaluation would occur, the Company could experience potential devaluation losses ranging from approximately $3,200,000 to $5,100,000. (See MD&A section entitled Foreign Currency Exchange Rate Risk for important details regarding potential devaluation losses.)

In addition to potential devaluation, next year’s average dayrate and profit margin per rig, as well as rig utilizations are difficult to predict and, while not expected to decline during 2004, are subject to unpredictable markets that could produce significant volatility.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2003 AND 2002


	2003		2002		% Change

	(in thousands)
*REAL ESTATE*
Revenues	$	10,893	$	8,525		27.8	%
Direct operating expenses		1,789		1,617		10.6
Depreciation		2,535		1,844		37.5

Operating profit	$	6,569	$	5,064		29.7

Operating profit increased by approximately 30 percent from 2002 to 2003 in the Company’s Real Estate division, primarily due to the sale of approximately 15 acres of raw land from the Company’s Southpark investment. Pre-tax profit from the sale of land was approximately $2.2 million. Depreciation expense increased in 2003 due to the acceleration of depreciation on the Company’s headquarters building, which will be razed in 2004. Overall combined occupancy and resulting revenues generated from all the other real estate properties did not materially fluctuate from 2002 to 2003.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2002 AND 2001


	2002			2001			% Change

	(in thousands, except operating statistics)
*U.S. LAND OPERATIONS*
Revenues	$	232,446		$	226,344			2.7	%
Intersegment elimination		(809	)		(4,487	)		(82.0	)
Direct operating expenses		165,394			133,650			23.8
Intersegment elimination		(648	)		(2,553	)		(74.6	)
General and administrative expense		10,087			6,479			55.7
Depreciation		26,311			16,701			57.5

Operating profit	$	30,493		$	67,580			(54.9	)

Operating Statistics:
Activity days		17,478			15,098			15.8	%
Average rig revenue per day	$	12,397		$	14,315			(13.4	)
Average rig expense per day	$	8,561		$	8,175			4.7
Average rig margin per day	$	3,836		$	6,140			(37.5	)
Number of owned rigs at end of period		66			49			34.7
Rig utilization		84	%		97	%		(13.4	)

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses.

U.S. land operating profit declined by 55 percent from 2001 to 2002 as overall industry rig counts declined from a cyclical high brought on by a spike in natural gas prices during 2001. The significant reduction in industry rig counts that followed during 2002 brought about lower dayrates, rig margins, and rig utilizations compared with 2001 levels. Although utilization rates declined during 2002, activity days increased due to an additional 17 rigs put into service in the U.S. land rig market. This increase was due to FlexRig construction and movement of land rigs from South American operations to the U.S. During 2002, the Company completed the final five rigs of its 12-rig FlexRig2 program commenced in 2001. It also placed eight FlexRig3s into service and added four more rigs to the U.S. fleet that were moved from South American operations. Capital spending in U.S. land rig operations

increased as the Company embarked on its FlexRig3, 25-rig construction project. As a result of capital expenditures for U.S. land operations of $236.3 million in 2002, compared with $136.7 million in 2001, depreciation expense rose by approximately 58 percent during 2002.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2002 AND 2001


	2002			2001			% Change

	(in thousands, except operating statistics)
*U.S. OFFSHORE PLATFORM OPERATIONS*
Revenues	$	132,249		$	128,459			3.0	%
Direct operating expenses		79,301			75,810			4.6
General and administrative expense		3,451			2,962			16.5
Depreciation		10,809			9,576			12.9

Operating profit	$	38,688		$	40,111			(3.5	)

Operating Statistics:
Activity days		3,286			3,572			(8.0	)%
Average rig revenue per day	$	30,424		$	28,995			4.9
Average rig expense per day	$	16,263		$	15,734			3.4
Average rig margin per day	$	14,161		$	13,261			6.8
Number of owned rigs at end of period		12			10			20.0
Rig utilization		83	%		98	%		(15.3	)

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts.

Two new offshore platform rigs were completed and placed in service during 2002 at high dayrates, but with short-term contracts. As a result, average rig revenue per day and average margins per day improved from 2001 to 2002. More than offsetting this improvement was a decline in activity days of eight percent, the beginning signs of an overall reduction in that market that continued into 2003.

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2002 AND 2001


	2002			2001			% Change

	(in thousands, except operating statistics)
*INTERNATIONAL OPERATIONS*
Revenues	$	151,392		$	170,270			(11.1	)%
Direct operating expenses		115,294			120,845			(4.6	)
General and administrative expense		2,634			2,112			24.7
Depreciation		20,336			18,838			8.0

Operating profit	$	13,128		$	28,475			(53.9	)

Operating Statistics:
Activity days		5,956			7,283			(18.2	)%
Average rig revenue per day	$	21,161		$	19,683			7.5
Average rig expense per day	$	14,599		$	13,334			9.5
Average rig margin per day	$	6,562		$	6,349			3.4
Number of owned rigs at end of period		33			37			(10.8	)
Rig utilization		51	%		56	%		(8.9	)

Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses and exclude the effects of offshore platform management contracts.

Rig utilization, total activity days, and total revenues declined from 2001 to 2002, resulting in operating profit declining by approximately 54 percent. The most significant declines in activity and profitability were in Company operations located in Colombia and Argentina. Colombia’s rig utilizations fell from 69 percent during 2001 to 31 percent during 2002. Additionally, the number of rigs available in Colombia fell from seven during the first quarter of 2001 to three by the end of 2001. Those four rigs were moved to the United States. Accordingly, profitability in Colombia declined sharply during 2002. Operating profit for Company operations in Venezuela and Argentina also declined during 2002. Devaluation losses in Venezuela were $4,393,000 in 2002, and $796,000 in 2001. (See MD&A section entitled Foreign Currency Exchange Risk for more detail regarding potential devaluation losses.)

COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2002 AND 2001


	2002		2001		% Change

	(in thousands)
*REAL ESTATE*
Revenues	$	8,525	$	11,018		(22.6	)%
Direct operating expenses		1,617		2,419		(33.2	)
Depreciation		1,844		2,284		(19.3	)

Operating profit	$	5,064	$	6,315		(19.8	)

Revenues and operating profit declined from 2001 to 2002 in the Company’s Real Estate division, due to a sale of raw land which resulted in approximately $2 million of operating profit during 2001. Depreciation was higher in 2001 due to the acceleration of depreciation for a building that was razed during 2002. Earnings from ongoing leasing operations were up only slightly from 2001 to 2002.

CRITICAL ACCOUNTING POLICIES

The Company’s consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. The following is a discussion of the critical accounting policies related to property, plant and equipment, impairment of long-lived assets, self-insurance accruals, and revenue recognition. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements.

Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed currently. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. The Company provides for the depreciation of property, plant and equipment using the straight-line method over the estimated useful lives of the assets.

Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are recorded in results of operations.

The Company reviews its long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value as compared to its estimated fair value, which is determined based on the present value of estimated cash flows from the asset and appraisals or sales prices of comparable assets. There were no long-lived asset impairment losses in the Company’s continuing operations during the years ended September 30, 2003, 2002, and 2001. However, should industry market conditions deteriorate from those existing currently, impairment losses could be recorded in the future. All of the Company’s drilling rigs are transportable and are therefore not limited to one area or country. Drilling rigs can be moved from countries where demand is low to countries experiencing high demand for drilling services. When making determinations of location for drilling rigs, the Company considers both long and short-term views of demand and other reasonable business considerations.

The Company is self-insured or maintains high deductibles for certain losses relating to worker’s compensation, general, product, and auto liabilities. Generally, deductibles are $2 million per occurrence on claims that fall under these coverages. Insurance is also purchased on rig properties and generally deductibles are $1 million per occurrence.

Excess insurance is purchased over these coverages to limit the Company’s exposure to catastrophic claims, but there can be no assurance that such coverage will respond or be adequate in all circumstances. Retained losses are estimated and accrued based upon our estimates of the aggregate liability for claims incurred, and using the Company’s historical loss experience and estimation methods that are believed to be reliable.

Revenues and costs on daywork contracts are recognized daily as the work progresses. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Other lump-sum payments received from customers relating to specific contracts are deferred and amortized to income as services are performed. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.

LIQUIDITY AND CAPITAL RESOURCES

The Company’s capital spending for continuing operations was $246,301,000 for 2003, $312,064,000 in 2002, and $184,668,000 in 2001. Net cash provided from operating activities for those same time periods were $96,504,000 in 2003, $151,774,000 in 2002, and $127,435,000 in 2001. In addition to the net cash provided by operating activities, the Company also generated net proceeds from the sale of portfolio securities of $18,215,000 in 2003, $47,146,000 in 2002, and $24,438,000 in 2001.

During 2000, the Company announced a program (FlexRig2 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 (FlexRig3 program) to build an additional 25 FlexRigs at an approximate cost of $11 million each. During 2002, the Company completed the remaining five rigs in the FlexRig2 program and the first eight rigs in the FlexRig3 program. During 2003, the remaining 17 rigs originally planned in the FlexRig3 program were completed. Another seven FlexRig3s were scheduled for construction, two of which were completed by the end of fiscal 2003, and five are scheduled to be completed by March, 2004.

The Company expects to fund its 2004 capital spending of approximately $100,000,000 with internally generated cash flows, its bank line of credit and/or from funds generated by the sale of stock from its investment portfolio. In August 2002, the Company entered into a $200 million intermediate-term unsecured debt obligation with staged maturities from five to 12 years and a weighted average interest rate of 6.31 percent. Funding of the notes occurred on August 15, 2002, and October 15, 2002, in equal amounts of $100 million. The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. Proceeds from the intermediate-term debt were used to repay the balance of the Company’s outstanding debt of $50 million in September 2002, help fund the Company’s rig construction program and for other general corporate purposes.

On September 30, 2003, the Company had a committed unsecured line of credit totaling $125 million, with short-term loans totaling $30 million and letters of credit totaling $13.7 million outstanding against the line.

The line of credit matures in July 2004 and bears interest of LIBOR + .87 percent to 1.125 percent depending on certain financial ratios of the Company. The Company must maintain certain financial ratios including debt to total capitalization and debt to earnings before interest, taxes, depreciation, and amortization, and maintain certain levels of liquidity and tangible net worth.

The strength of the Company’s balance sheet is substantial, with current ratios for September 30, 2003, and 2002 at 2.2 and 2.5, respectively, and with debt to total capitalization of 18 percent and 10 percent, respectively. Additionally, the Company manages a large portfolio of marketable securities that, at the close of 2003, had a market value of $169,546,000. The Company’s investments in Atwood Oceanics, Inc., Schlumberger, Ltd., and ConocoPhillips made up almost 90 percent of the portfolio’s market value on September 30, 2003. The value of the portfolio is subject to fluctuation in the market and may vary considerably over time. Excluding the Company’s equity-method investments, the portfolio is recorded at fair value on the Company’s balance sheet for each reporting period. During 2003, the Company paid a dividend of $0.32 per share, or a total of $16,015,268, representing the 31st consecutive year of dividend increases.

STOCK PORTFOLIO HELD BY THE COMPANY


September 30, 2003	Number of Shares		Cost Basis		Market Value

	(in thousands, except share amounts)
Atwood Oceanics, Inc.		3,000,000	$	56,655	$	71,970
Schlumberger, Ltd.		1,480,000		23,511		71,632
ConocoPhillips		140,000		3,486		7,665
Other				6,303		18,279

Total			$	89,955	$	169,546

MATERIAL COMMITMENTS

The Company has no off balance sheet arrangements, as defined by SEC rules. The Company’s contractual obligations as of September 30, 2003, including payments due by year are as follows (in thousands):


	Total		2004		2005		2006		2007		2008		After 2008

Short-term loans (a)	$	30,000	$	30,000	$	—	$	—	$	—	$	—	$	—
Long-term debt (a)		200,000		—		—		—		25,000		—		175,000
Operating leases (b)		8,146		1,285		1,048		1,311		1,385		1,385		1,732
Purchase obligations		36,415		35,530		530		355		—		—		—

Total Contractual Obligations	$	274,561	$	66,815	$	1,578	$	1,666	$	26,385	$	1,385	$	176,732

(a) See Note 3 “Long-term Debt” to the Company’s Consolidated Financial Statements.

(b) See Note 14 “Commitments and Contingencies” to the Company’s Consolidated Financial Statements.

An actuarial study of the Company’s pension plan projects that no funding will be required in fiscal years 2004 or 2005. After 2005, funding requirements, if any, will be subject to returns on plan assets and other external factors.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Foreign Currency Exchange Rate Risk. The Company has international operations in Hungary, Chad, and in several South American countries, as well as a labor contract for work off the coast of Equatorial Guinea. With the exception of Venezuela, the Company’s exposure to currency valuation losses is usually minimal due to the fact that virtually all billings and receipts in other countries are in U.S. dollars. Even though the Company’s contract with its customers in Argentina was in U.S. dollars, the Company recorded a devaluation loss as Argentina experienced a dramatic economic collapse during 2002. As a result of the economic collapse, the government stopped the outflow of dollars from the country and required that former dollar obligations be paid in Argentina pesos,

resulting in the Company recording an estimated loss of $1,200,000 in 2002. The Company was able to reduce this estimated loss by approximately $980,000 during 2003. At the present time, the Company has two rigs located in Argentina, one of which will begin working during early 2004.

The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. In Venezuela, while approximately 60 percent of the Company’s invoice billings to the Venezuelan state oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar, PDVSA typically pays all amounts owed in bolivars. The Company, historically, has usually been able to convert the bolivars received in payment of the dollar-based billings into dollars in a timely manner and thus avoid, in large measure, devaluation losses pertaining to these dollar-based invoices. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate at 1600 Bolivars to one U.S. dollar and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars through the central bank. As a result of these exchange controls, the Company has been unable since January 2003 to convert its bolivar cash balances into U.S. dollars. As of September 30, 2003, the Company’s bolivar balance was approximately 14 billion bolivars or approximately $8.8 million. Historically, the Company has kept bolivar cash balances at necessary minimum levels to fund local operating costs.

As part of the exchange controls regulation, the Venezuelan government provided a mechanism by which companies could request conversion of bolivars into U.S. dollars. In compliance with such regulations, the

Company on October 1, 2003, submitted a request to the Venezuelan government seeking permission to dividend earnings, which effectively will convert 14 billion bolivars into approximately $8.8 million. The Company is unable to predict if or when this request will be approved.

From August of 2002 to August of 2003, there was a 13 percent devaluation of the bolivar. As a result, the Company experienced a $624,000 devaluation loss for 2003. This 13 percent devaluation loss may not be reflective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2004 activity levels are similar to fiscal 2003 and if a 25 percent to 50 percent devaluation should occur, the Company could experience potential currency devaluation losses ranging from approximately $3,200,000 to $5,100,000.

In late August 2003, the Venezuelan state petroleum company agreed, on a prospective basis, to pay a portion of the Company’s dollar-based invoices in U.S. dollars. While this is a positive development in light of the existing exchange controls, there is no guarantee as to how long this arrangement will continue. Were this agreement to end, the Company would revert back to receiving these payments in bolivars and thus increase bolivar cash balances and exposure to devaluation.

Commodity Price Risk. The demand for contract drilling services is a result of exploration and production companies spending money to explore and develop drilling prospects in search for crude oil and natural gas. Their appetite for such spending is driven by their cash flow and financial strength, which is very dependent, among other things, on crude oil and natural gas commodity prices. Crude oil

prices are determined by a number of factors including supply and demand, worldwide economic conditions, and geopolitical factors. Crude oil and natural gas prices have been volatile and very difficult to predict. This difficulty has led many exploration and production companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of commodity prices.

Interest Rate Risk. The Company’s interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based on borrowings from its commercial banks. To reduce the impact of fluctuations in interest rates, the Company maintains a portion of its total debt portfolio in fixed-rate debt. On September 30, 2003, the amount of the Company’s fixed-rate debt was approximately 87 percent of total debt. In the past, the Company has entered into financial instruments such as interest rate swaps and may consider this and other financial instruments in the future to manage the portfolio mix between fixed and floating rate debt and to mitigate the impact of changes in interest rates based on management’s assessment of future interest rates, volatility of the yield curve, and the Company’s ability to access the capital markets in a timely manner.

Based on the outstanding borrowings under variable-rate debt instruments on September 30, 2003, a change in the average interest rate of 100 basis points would result in a change in net income and cash flows before income taxes on an annual basis of approximately $0.2 million and $0.3 million, respectively.

The following tables provide information as of September 30, 2003 and 2002 about the Company’s interest rate risk sensitive instruments:

INTEREST RATE RISK (dollars in thousands)


													After						Fair Value
		2004		2005		2006		2007			2008		2008			Total			@ 9/30/03

Fixed Rate Debt			—		—		—	$	25,000			—	$	175,000		$	200,000		$	226,500
	Average Interest Rate		—		—		—		5.5	%		—		6.4	%		6.4	%		—
Variable Rate Debt		$	30,000		—		—		—			—		—		$	30,000		$	30,000
	Average Interest Rate (a)		—		—		—		—			—		—			(a	)		—

(a) LIBOR plus an increment of .875% to 1.25% depending on certain financial ratios.

INTEREST RATE RISK (dollars in thousands)


													After						Fair Value
		2003		2004		2005		2006		2007			2007			Total			@ 9/30/02

Long Term Debt
	Fixed Rate		—		—		—		—	$	12,500		$	87,500		$	100,000		$	109,700
	Average Interest Rate		—		—		—		—		5.5	%		6.4	%		6.4	%		—
Interest Rate Swap (b)			—		—		—		—		—			—			(b	)		(1,700	)

(b) At September 30, 2002, the Company held an interest rate swap on $50 million face value debt to receive variable interest payments based on 30-day LIBOR rates and pay fixed interest payments of 5.4% through October 27, 2003.

Equity Price Risk. On September 30, 2003, the Company owned stocks in other publicly held companies with a total market value of $169,546,000. These securities are subject to a wide variety and number of market-related risks that could substantially reduce or increase the market value of the Company’s holdings. Except for the Company’s holdings in its equity affiliate, Atwood Oceanics, Inc., the portfolio is recorded at fair value on its balance sheet with changes in unrealized after-tax value reflected in the equity section of its balance sheet. Any reduction in market value would have an impact on the Company’s debt ratio and financial strength. The total market value of the portfolio of securities was $175,668,000 at September 30, 2002.

Report of Independent Auditors

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, 2003 and 2002, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2003. 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, 2003 and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2003, in conformity with accounting principles generally accepted in the United States.

ERNST & YOUNG LLP

Tulsa, Oklahoma
November 19, 2003

Consolidated Statements of Income


Years Ended September 30,			2003			2002		2001

			(in thousands, except per share amounts)
REVENUES
	Operating revenues		$	507,331		$	523,803	$	531,604
	Income from investments			7,953			28,076		10,967

				515,284			551,879		542,571

COSTS AND EXPENSES
	Direct operating costs			345,537			361,669		330,181
	Depreciation			82,513			61,447		49,532
	General and administrative			41,003			36,563		28,180
	Interest			12,289			980		1,701

				481,342			460,659		409,594

Income from continuing operations before income taxes and equity in income (loss) of affiliates				33,942			91,220		132,977
Provision for income taxes				14,649			40,573		54,689
Equity in income (loss) of affiliates net of income taxes				(1,420	)		3,059		2,179

Income from continuing operations				17,873			53,706		80,467
Income from discontinued operations				—			9,811		63,787

NET INCOME			$	17,873		$	63,517	$	144,254

Basic earnings per common share:
	Income from continuing operations		$	0.36		$	1.08	$	1.61
	Income from discontinued operations			—			0.19		1.27

		Net income	$	0.36		$	1.27	$	2.88

Diluted earnings per common share:
	Income from continuing operations		$	0.35		$	1.07	$	1.58
	Income from discontinued operations			—			0.19		1.26

		Net income	$	0.35		$	1.26	$	2.84

Average common shares outstanding (in thousands)
	Basic			50,039			49,825		50,096
	Diluted			50,596			50,345		50,772

The accompanying notes are an integral part of these statements.

Consolidated Balance Sheets

ASSETS


September 30,			2003		2002

			(in thousands)
CURRENT ASSETS:
	Cash and cash equivalents		$	38,189	$	46,883
	Accounts receivable, less reserve of $1,319 in 2003 and $1,337 in 2002			91,088		92,604
	Inventories			22,533		22,511
	Prepaid expenses and other			45,721		16,753

		Total current assets		197,531		178,751

INVESTMENTS				158,770		150,175

PROPERTY, PLANT AND EQUIPMENT, at cost:
	Contract drilling equipment			1,490,389		1,235,784
	Construction in progress			45,004		72,303
	Real estate properties			56,247		48,925
	Other			87,570		82,310

				1,679,210		1,439,322
	Less-accumulated depreciation and amortization			621,005		541,877

		Net property, plant and equipment		1,058,205		897,445

OTHER ASSETS				1,329		942

TOTAL ASSETS			$	1,415,835	$	1,227,313

The accompanying notes are an integral part of these statements.

LIABILITIES AND SHAREHOLDERS’ EQUITY


September 30,			2003			2002

			(in thousands, except share data)
CURRENT LIABILITIES:
	Notes payable		$	30,000		$	—
	Accounts payable			29,630			41,045
	Accrued liabilities			28,988			31,854

		Total current liabilities		88,618			72,899

NONCURRENT LIABILITIES:
	Long-term notes payable			200,000			100,000
	Deferred income taxes			181,737			131,401
	Other			28,229			27,843

		Total noncurrent liabilities		409,966			259,244

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			83,302			82,489
	Retained earnings			840,776			838,929
	Unearned compensation			(10	)		(190	)
	Accumulated other comprehensive income			33,668			16,180

				963,089			942,761
	Less treasury stock, 3,388,588 shares in 2003 and 3,518,282 shares in 2002, at cost			45,838			47,591

		Total shareholders’ equity		917,251			895,170

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY			$	1,415,835		$	1,227,313

The accompanying notes are an integral part of these statements.

Consolidated Statements of Shareholders’ Equity


				Common Stock				Additional
								Paid-in		Unearned			Retained
				Shares		Amount		Capital		Compensation			Earnings

				(in thousands, except per share amounts)
Balance, September 30, 2000					53,529	$	5,353	$	66,090	$	(3,277	)	$	813,885
Comprehensive Income:
	Net Income													144,254
	Other comprehensive loss:
		Unrealized losses on available-for sale securities, net
		Derivatives instruments losses, net
	Total other comprehensive loss
Total comprehensive income
Cash dividends ($.30 per share)														(15,047	)
Exercise of stock options									7,965
Purchase of stock for treasury
Tax benefit of stock-based awards									6,269
Amortization of deferred compensation											1,465			13

Balance, September 30, 2001					53,529		5,353		80,324		(1,812	)		943,105
Comprehensive Income:
	Net Income													63,517
	Other comprehensive (loss):
		Unrealized losses on available-for sale securities, net
		Derivatives instruments losses, net
		Minimum pension liability adjustment, net
			Total other comprehensive loss
Total comprehensive income
Distribution of Cimarex Energy Co. Stock														(152,201	)
Cash dividends ($.31 per share)														(15,492	)
Exercise of stock options									1,099
Forfeiture of Restricted Stock Award									88		156
Tax benefit of stock-based awards									978
Amortization of deferred compensation											1,466

Balance, September 30, 2002					53,529		5,353		82,489		(190	)		838,929
Comprehensive Income:
	Net Income													17,873
	Other comprehensive income:
		Unrealized gains on available-for sale securities, net
		Derivatives instruments amort., net
		Minimum pension liability adjustment, net
			Total other comprehensive gain
Comprehensive income
Cash dividends ($.32 per share)														(16,026	)
Exercise of stock options									441
Tax benefit of stock-based awards									372
Amortization of deferred compensation											180

Balance, September 30, 2003					53,529	$	5,353	$	83,302	$	(10	)	$	840,776

[Additional columns below]

[Continued from above table, first column(s) repeated]

Accumulated

Treasury Stock Other

Comprehensive

Shares Amount Income (Loss) Total

(in thousands, except per share amounts)

Balance, September 30, 2000
3,548 $ (32,412 ) $ 106,064 $ 955,703

Comprehensive Income:

Net Income
144,254

Other comprehensive loss:

Unrealized losses on available-for sale securities, net
(55,769 ) (55,769 )

Derivatives instruments losses, net
(986 ) (986 )

Total other comprehensive loss
(56,755 )

Total comprehensive income
87,499

Cash dividends ($.30 per share)
(15,047 )

Exercise of stock options
(646 ) 5,808 13,773

Purchase of stock for treasury
774 (23,198 ) (23,198 )

Tax benefit of stock-based awards
6,269

Amortization of deferred compensation
1,478

Balance, September 30, 2001
3,676 (49,802 ) 49,309 1,026,477

Comprehensive Income:

Net Income
63,517

Other comprehensive (loss):

Unrealized losses on available-for sale securities, net
(25,449 ) (25,449 )

Derivatives instruments losses, net
(68 ) (68 )

Minimum pension liability adjustment, net
(7,612 ) (7,612 )

Total other comprehensive loss
(33,129 )

Total comprehensive income
30,388

Distribution of Cimarex Energy Co. Stock
(152,201 )

Cash dividends ($.31 per share)
(15,492 )

Exercise of stock options
(181 ) 2,455 3,554

Forfeiture of Restricted Stock Award
23 (244 )

Tax benefit of stock-based awards
978

Amortization of deferred compensation
1,466

Balance, September 30, 2002
3,518 (47,591 ) 16,180 895,170

Comprehensive Income:

Net Income
17,873

Other comprehensive income:

Unrealized gains on available-for sale securities, net
15,005 15,005

Derivatives instruments amort., net
982 982

Minimum pension liability adjustment, net
1,501 1,501

Total other comprehensive gain
17,488

Comprehensive income
35,361

Cash dividends ($.32 per share)
(16,026 )

Exercise of stock options
(129 ) 1,753 2,194

Tax benefit of stock-based awards
372

Amortization of deferred compensation
180

Balance, September 30, 2003
3,389 $ (45,838 ) $ 33,668 $ 917,251

The accompanying notes are an integral part of these statements.

Consolidated Statements of Cash Flows


Years Ended September 30,					2003			2002			2001

					(in thousands)
OPERATING ACTIVITIES:
	Income from continuing operations				$	17,873		$	53,706		$	80,467

	Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
		Depreciation				82,513			61,447			49,532
		Equity in (income) loss of affiliates before income taxes				2,290			(5,014	)		(3,593	)
		Amortization of deferred compensation				180			1,122			1,135
		Gain on sales of securities and non-monetary investment loss, net				(5,529	)		(24,347	)		(1,189	)
		Gain on sale of property, plant and equipment				(3,689	)		(1,392	)		(4,201	)
		Other – net				336			791			876
		Change in assets and liabilities:
			Accounts receivable			1,516			24,148			(49,405	)
			Inventories			251			1,042			(68	)
			Prepaid expenses and other			(29,355	)		24,381			(11,411	)
			Accounts payable			(11,415	)		(3,769	)		29,290
			Accrued liabilities			(1,281	)		955			18,435
			Deferred income taxes			41,225			24,133			15,291
			Other noncurrent liabilities			1,589			(5,429	)		2,276

						78,631			98,068			46,968

				Net cash provided by operating activities		96,504			151,774			127,435

INVESTING ACTIVITIES:
	Capital expenditures					(246,301	)		(312,064	)		(184,668	)
	Acquisition of business, net of cash acquired					—			—			(2,279	)
	Proceeds from sale of property, plant and equipment					6,720			4,135			11,984
	Purchase of investments					—			(5,656	)		—
	Proceeds from sale of securities					18,215			47,146			24,438

				Net cash used in investing activities		(221,366	)		(266,439	)		(150,525	)

FINANCING ACTIVITIES:
	Proceeds from notes payable					151,331			100,000			—
	Payments on notes payable					(21,331	)		(50,000	)		—
	Dividends paid					(16,026	)		(15,221	)		(15,047	)
	Purchases of stock for treasury					—			—			(23,198	)
	Proceeds from exercise of stock options					2,194			3,554			13,601

				Net cash provided by (used in) financing activities		116,168			38,333			(24,644	)

DISCONTINUED OPERATIONS:
	Net cash provided by operating activities					—			62,792			157,286
	Net cash (used in) investing activities					—			(55,232	)		(88,813	)
	Cash of discontinued operations at spinoff					—			(13,171	)		—

				Net cash provided by (used in) discontinued operations		—			(5,611	)		68,473

Net increase (decrease) in cash and cash equivalents						(8,694	)		(81,943	)		20,739
Cash and cash equivalents, beginning of period						46,883			128,826			108,087

Cash and cash equivalents, end of period					$	38,189		$	46,883		$	128,826

The accompanying notes are an integral part of these statements.

Notes to Consolidated Financial Statements

September 30, 2003, 2002 and 2001

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Helmerich & Payne, Inc. (the Company), and all of its wholly-owned subsidiaries. Fiscal years of the Company’s foreign consolidated operations end on August 31 to facilitate reporting of consolidated results.

BASIS OF PRESENTATION

On September 30, 2002, the Company distributed 100 percent of the common stock of Cimarex Energy Co. to the Company’s shareholders. Cimarex Energy Co. held the Company’s exploration and production business and has been accounted for as discontinued operations in the accompanying consolidated financial statements. Unless indicated otherwise, the information in the notes to consolidated financial statements relates to the continuing operations of the Company (see Note 2).

As described below, the Company increased the number of business segments it is reporting and how it classifies certain general and administrative expenses in 2003. These changes were driven by the new organization of the Company as a result of last year’s spin-off of the exploration and production business and to better reflect the way the Company now manages its contract drilling businesses. All prior periods reflect these changes.

The number of contract drilling business segments reported have increased to three to reflect the Company’s U.S. Offshore Platform operations separately from the U.S. Land operations. Formerly, the combined U.S. segments were reported as one segment. Total operating profit for U.S. operations and the International contract drilling segment has not changed. Prior year segment disclosures have been changed to reflect the increased number of reported segments for all periods presented (see Note 15).

General and administrative expenses within the Company’s contract drilling business segments have been reclassified to delineate direct operating costs from associated general and administrative costs. Formerly, both costs were included in operating costs on the consolidated statements of income. The associated general and administrative costs of the contract drilling segments of $15,353,000, $16,172,000, and $11,553,000 for 2003, 2002 and 2001, respectively have been reclassified to general and administrative expense on the consolidated statements of income for all periods presented. General and administrative costs within the contract drilling segments continue to be included in segment operating profit. No other amounts on the consolidated statements of income were changed or affected by this reclassification.

Prior year amounts for Investments and Other Assets have been reclassified to conform to current year classification.

Included in the Company’s operating revenues for the fiscal year ended September 30, 2003 are reimbursements for “out-of-pocket” expenses of $31.0 million. Previously, the Company recognized reimbursements received as a reduction to the related operating costs. Emerging Issues Task Force (EITF) No. 01-14, “Income Statement Characterization of Reimbursements Received for Out of Pocket Expenses Incurred” requires that reimbursements received for “out-of-pocket” expenses be included in operating revenues. The effect of EITF 01-14 resulted in a reclassification to fiscal year 2002 and 2001, that increased operating revenues and direct operating costs by $41.0 million and $33.3 million, respectively. These reclassifications had no impact on net income.

TRANSLATION OF FOREIGN CURRENCIES

The Company has determined that the functional currency for its foreign subsidiaries is the U.S. dollar. Foreign currency transaction gain (losses) were $422,000, ($5,473,000) and ($494,000), for 2003, 2002 and 2001, respectively. These amounts are included in direct operating costs.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost less accumulated depreciation. Substantially all property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets (contract drilling equipment, 4-15 years; real estate buildings and equipment, 10-50 years; and other, 3-33 years). The Company charges the cost of maintenance and repairs to direct operating cost, while betterments and refurbishments are capitalized.

VALUATION OF LONG-LIVED ASSETS

The Company periodically evaluates the carrying value of long-lived assets to be held and used, including intangible assets, when events or circumstances warrant such a review. The Company recognizes impairment losses for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows expected to be generated by the asset are not sufficient to recover the carrying amount of the asset. On October 1, 2002 the Company adopted Statement of Financial Accounting Standard (“SFAS”) No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” which did not impact the Company’s results of operations or financial position.

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.

Currently, the Company is unable to convert bolivar cash balances in Venezuela into U.S. dollars or to transfer any such funds out of Venezuela as a result of exchange controls put in place by the Venezuelan government. (See Note 12 for further discussion.)

INVENTORIES AND SUPPLIES

Inventory and supplies are primarily replacement parts and supplies held for use in our drilling operations. Inventory and supplies are valued at the lower of cost (moving average or actual) or market value.

DRILLING REVENUES

Contract drilling revenues are comprised primarily of daywork drilling contracts for which the related revenues and expenses are recognized as work progresses. For certain contracts, the Company receives lump-sum payments for the mobilization of rigs and other drilling equipment. Revenues earned, net of direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.

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 2002 and 2001 includes a loss of approximately $0.5 million, $0.01 per share on a diluted basis, and $1.4 million, $0.03 per share on a diluted basis, respectively, 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. There were no losses in 2003 as the result of a decline in market values that were considered other than temporary by the Company.

Investments in companies owned from 20 to 50 percent are accounted for using the equity method with the Company recognizing its proportionate share of the income or loss of each investee. The Company owned approximately 21.7% of Atwood Oceanics, Inc. (Atwood) at both September 30, 2003 and 2002. The quoted market value of the Company’s investment was $71,970,000 and $87,750,000 at September 30, 2003 and 2002, respectively. Retained earnings at September 30, 2003 includes approximately $28,306,000 of undistributed earnings of Atwood.

Summarized financial information of Atwood is as follows:


September 30	2003			2002		2001

	(in thousands)
Gross revenues	$	144,766		$	149,157	$	147,541
Costs and expenses		157,568			120,872		120,195

Net income (loss)	$	(12,802	)	$	28,285	$	27,346

Helmerich & Payne, Inc.’s equity in net income (loss), net of income taxes	$	(1,414	)	$	4,206	$	3,596

Current assets	$	72,182		$	71,813	$	45,891
Noncurrent assets		447,464			372,717		304,857
Current liabilities		40,504			24,416		19,144
Noncurrent liabilities		215,757			143,981		85,948
Shareholders’ equity		263,385			276,133		245,656

Helmerich & Payne, Inc.’s investment	$	56,655		$	58,937	$	52,153

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 interpretations. Fixed plan common stock options generally do not result in compensation expense, because the exercise price of the options issued by the Company equals the market price of the underlying stock on the date of grant. The plans under which the Company issues stock based awards are described more fully in Note 5. The following table illustrates the effect on net income and earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.”


September 30		2003			2002			2001

		(in thousands)
Net income, as reported		$	17,873		$	63,517		$	144,254
Add: Stock-based employee compensation expense included in the Consolidated Statements of Income, net of related tax effects			112			909			908
Deduct: Total stock based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(4,387	)		(3,354	)		(5,951	)

Pro forma net income		$	13,598		$	61,072		$	139,211

Earnings per share:
	Basic-as reported	$	0.36		$	1.27		$	2.88

	Basic-pro forma	$	0.27		$	1.23		$	2.78

	Diluted-as reported	$	0.35		$	1.26		$	2.84

	Diluted-pro forma	$	0.27		$	1.21		$	2.74

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.

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 2003, 2002 and 2001 was $1.8 million, $2.5 million and $1.1 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 recognized as an adjustment of interest expense. As of September 30, 2003, 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 transaction 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.

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.

The Company has one derivative, an interest rate swap, that is discussed further in Note 3.

NOTE 2 DISCONTINUED OPERATIONS

On September 30, 2002, the Company’s distribution of 100 percent of the common stock of Cimarex Energy Co. and the merger of Key Production Company, Inc. with Cimarex was completed. In connection with the distribution, approximately 26.6 million shares of the Cimarex Energy Co. common stock on a diluted basis were distributed to shareholders of the Company of record on September 27, 2002. The Cimarex Energy Co. stock distribution was recorded as a dividend and resulted in a decrease to consolidated shareholders’ equity of approximately $152.2 million. The Company does not own any common stock of Cimarex Energy Co.

Under terms of a tax sharing agreement, each party has agreed to indemnify the other in respect of all taxes for which it is responsible under the tax sharing agreement. Cimarex is responsible for all taxes related to the exploration and production business for all of past and future periods, including all taxes arising from the Cimarex business prior to the time that Cimarex was formed, and agrees to hold the Company harmless in respect of those taxes. Cimarex is entitled to receive all refunds and credits of taxes previously paid with respect to the exploration and production business. Cimarex will not receive the benefit of any loss or similar tax attribute arising during the time that losses from the Cimarex business are included in the Company’s consolidated federal income tax return. The Company remains responsible for all taxes related to the business of the Company other than the exploration and production business and has agreed to indemnify Cimarex in respect of any liability for any such taxes.

Summarized results of discontinued operations for the years ended September 30, 2002 and 2001, are as follows:


September 30			2002		2001

			(in thousands)
Revenues			$	172,827	$	317,580
Income from operations:
	Income before income taxes			15,138		102,125
	Tax provision			5,327		38,338

		Income from discontinued operations	$	9,811	$	63,787

NOTE 3 NOTES PAYABLE AND LONG-TERM DEBT

At September 30, 2003, the Company had $200 million in long-term debt outstanding at fixed rates and maturities as summarized in the following table. Funding of the notes occurred on August 15, 2002 and October 15, 2002 in equal amounts of $100 million.


(In thousands)
Issue Amount	Maturity Date	Interest Rate

$25,000	August 15, 2007		5.51	%
$25,000	August 15, 2009		5.91	%
$75,000	August 15, 2012		6.46	%
$75,000	August 15, 2014		6.56	%

The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitalization. The proceeds of the debt issuances were used to repay $50 million of outstanding debt, fund the Company’s rig construction program and for other general corporate purposes.

At September 30, 2003, the Company had a committed unsecured line of credit totaling $125 million. Short-term loans totaling $30 million and letters of credit totaling $13.7 million were outstanding against the line, leaving $81.3 million available to borrow. The weighted average interest rate on short-term loans at September 30, 2003 was 2.0 percent. Under terms of the line of credit, the Company must maintain certain financial ratios including debt to total capitalization and debt to earnings before interest, taxes, depreciation, and amortization, and maintain certain levels of liquidity and tangible net worth. A non-use fee of 0.15 percent per annum is calculated on the average daily unused amount, payable quarterly. The interest rate varies based on LIBOR plus .875 to 1.125 percent depending on ratios described above. The line of credit matures in July, 2004. Subsequent to September 30, 2003, the Company has paid $10 million of short-term debt.

At September 30, 2003, the Company held an unassociated interest rate swap tied to 30-day LIBOR in the amount of $50 million which matured on October 27, 2003. The swap instrument was originally designated as a hedge of a $50 million loan that was paid off in September 2002. The swap liability was valued at approximately $0.1 million on September 30, 2003.

The interest rate swap liability was valued at approximately $1.7 million on the date the $50 million debt was paid off. The $1.7 million is being amortized over the remaining life of the swap as interest expense. In fiscal 2003, $1.6 million was amortized and included in interest expense. Changes to the value of the interest rate swap subsequent to the date the $50 million debt was paid are recorded to income.

NOTE 4 INCOME TAXES

The components of the provision (benefit) for income taxes from continuing operations are as follows:


Years Ended September 30,				2003			2002			2001

			(In thousands)
CURRENT:
	Federal			$	(34,495	)	$	13,324		$	28,911
	Foreign				6,870			5,080			8,870
	State				883			1,022			2,651

					(26,742	)		19,426			40,432

DEFERRED:
	Federal				42,835			16,019			8,850
	Foreign				(3,383	)		3,732			4,701
	State				1,939			1,396			706

					41,391			21,147			14,257

TOTAL PROVISION:				$	14,649		$	40,573		$	54,689


The amounts of domestic and foreign income from continuing operations are as follows:

Years Ended September 30,				2003			2002			2001

			(In thousands)
Income from continuing operations before income taxes and equity in income (loss) of affiliates:
	Domestic			$	31,164		$	82,012		$	106,163
	Foreign				2,778			9,208			26,814

				$	33,942		$	91,220		$	132,977


Effective income tax rates on income from continuing operations as compared to the U.S. Federal income tax rate are as follows:

Years Ended September 30,				2003			2002			2001

U.S. Federal income tax rate					35	%		35	%		35	%
Effect of foreign taxes					4			7			4
State income taxes					4			2			2

Effective income tax rate					43	%		44	%		41	%


The components of the Company’s net deferred tax liabilities are as follows:

September 30,				2003			2002

					(In thousands)
Deferred tax liabilities:
	Property, plant and equipment			$	153,736		$	111,822
	Available-for-sale securities				25,106			18,170
	Equity investments				17,349			18,216

		Total deferred tax liabilities			196,191			148,208

Deferred tax assets:
	Financial accruals				6,079			7,196
	Pension reserve				4,917			2,802
	Other				3,458			6,809

		Total deferred tax assets			14,454			16,807

Net deferred tax liabilities				$	181,737		$	131,401

NOTE 5 SHAREHOLDERS’ EQUITY

In December 2001, the board of directors authorized the repurchase of up to 2,000,000 shares per calendar year 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 approximately $23,198,000 under previous authorizations from the board of directors. The Company did not purchase any shares in fiscal 2003 or 2002.

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. Restricted stock 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.

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 common stock on the date of grant. Up to 450,000 shares of the total authorized may be granted to participants as restricted stock awards. In fiscal 2003 and 2002, 610,700 and 819,800 options, respectively, were granted under the 2000 plan. There were no restricted stock grants in fiscal 2003 or 2002. There was no activity under this plan during fiscal 2001.

On September 30, 2002, the Company distributed 100 percent of the common stock of Cimarex Energy Co. to the Company’s shareholders. The distribution was recorded as a dividend and resulted in a decrease to consolidated shareholders equity of approximately $152.2 million. Any options held by Cimarex employees at the distribution date were automatically forfeited per the terms of the Company’s stock incentive plans. Both vested and unvested options held by remaining participants at September 30, 2002 were adjusted (the number of options and exercise price) to reflect the change in the value of Company common stock as the result of the spin-off of Cimarex. The adjustment was made in such a way that the aggregate intrinsic value of the options and the ratio of the exercise price per share to the market value per share remained the same.

The following summary reflects the stock option activity for the Company’s common stock and related information for 2003, 2002, and 2001. (shares in thousands):


	2003					2002					2001

				Weighted-Average					Weighted-Average					Weighted-Average
	Options			Exercise Price		Options			Exercise Price		Options			Exercise Price

Outstanding at October 1,		3,875		$	20.28		3,136		$	25.78		2,955		$	22.94
Granted		611			27.74		820			29.89		844			32.36
Exercised		(130	)		16.93		(181	)		19.61		(644	)		21.34
Adjustment for Cimarex spinoff		—			—		926			—		—			—
Forfeited/Expired		(29	)		23.85		(826	)		28.15		(19	)		25.57

Outstanding on September 30,		4,327		$	21.41		3,875		$	20.28		3,136		$	25.78

Exercisable on September 30,		2,575			19.34		1,935		$	19.07		1,078		$	23.82
Shares available to grant		1,597					2,195					3,000

The following table summarizes information about stock options at September 30, 2003 (shares in thousands):


	Outstanding Stock Options						Exercisable Stock Options

Range of			Weighted-Average		Weighted-Average				Weighted-Average
Exercise Prices	Options		Remaining Life		Exercise Price		Options		Exercise Price

$10.22 to $12.78		380		1.9	$	10.58		380	$	10.58
$12.79 to $19.84		1,376		5.2	$	17.03		1,195	$	16.76
$19.85 to $28.04		2,571		7.5	$	25.35		1,000	$	25.74

$10.22 to $28.04		4,327		6.3	$	21.41		2,575	$	19.34

The weighted-average fair values of options at their grant date during 2003, 2002, and 2001 was $10.72, $12.47, and $13.01, 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:


	2003			2002			2001

Expected years until exercise		4.5			4.5			4.5
Expected stock volatility		45	%		48	%		43	%
Dividend yield		.75	%		.8	%		.8	%
Risk-free interest rate		3.1	%		4.0	%		5.2	%

On September 30, 2003, the Company had 50,140,364 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 percent 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 percent 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 surviving corporation), or more than 50 percent 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 6 EARNINGS PER SHARE

A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows:


		2003		2002		2001

		(in thousands)
Basic weighted-average shares			50,039		49,825		50,096
Effect of dilutive shares:
	Stock options		555		508		644
	Restricted stock		2		12		32

			557		520		676

Diluted weighted-average shares			50,596		50,345		50,772

At September 30, 2003, options to purchase 1,030,791 shares of common stock at a weighted-average price of $27.86 were outstanding, but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive.

Restricted stock of 44,675 shares at a weighted-average price of $30.38 and options to purchase 451,421 shares of common stock at a weighted-average price of $27.98 were outstanding at September 30, 2002, but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive.

At September 30, 2001, restricted stock of 120,018 shares at a weighted-average price of $37.73 and options to purchase 1,250,750 shares of common stock at a price of $33.84 were outstanding, but were not included in the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive.

NOTE 7 FINANCIAL INSTRUMENTS

The Company had $200 million of long-term debt outstanding at September 30, 2003, which had an estimated fair value of $226.5 million. The debt was valued based on the prices of similar securities with similar terms and credit ratings. The Company used the expertise of an outside investment banking firm to assist with the estimate of the fair value of the long-term debt. The Company’s line of credit and 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 a liability of $0.1 million at September 30, 2003, 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 Unrealized		Gross Unrealized		Estimated Fair
		Cost		Gains		Losses		Value

		(in thousands)
Equity Securities:
	September 30, 2003	$	33,300	$	64,276	$	0	$	97,576
	September 30, 2002	$	46,325	$	43,846	$	3,772	$	86,399

During the years ended September 30, 2003, 2002, and 2001, marketable equity available-for-sale securities with a fair value at the date of sale of $18,215,000, $46,692,000, and $24,438,000, respectively, were sold. The gross realized gains on such sales of available-for-sale securities totaled $8,582,000, $25,893,000, and $3,314,000, respectively, and the gross realized losses totaled $3,053,000, $232,000, and $0, respectively.

NOTE 8 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The table below presents changes in the components of accumulated other comprehensive income (loss).


		Unrealized Appreciation			Interest			Minimum
		(Depreciation)			Rate			Pension
		on Securities			Swap			Liability			Total

		(in thousands)
Balance at September 30, 2000		$	106,064		$	—		$	—		$	106,064
2001 Change:
	Pre-income tax amount		(88,762	)		(1,590	)		—			(90,352	)
	Income tax provision		33,730			604			—			34,334
	Realized gains in net income (net of $452 income tax)		(737	)		—			—			(737	)

			(55,769	)		(986	)		—			(56,755	)

Balance at September 30, 2001			50,295			(986	)		—			49,309

2002 Change:
	Pre-income tax amount		(16,228	)		(127	)		(12,277	)		(28,632	)
	Income tax provision		6,167			48			4,665			10,880
	Amortization of swap (net of $7 income tax benefit)		—			11			—			11
	Realized gains in net income (net of $9,431 income tax)		(15,388	)		—			—			(15,388	)

			(25,449	)		(68	)		(7,612	)		(33,129	)

Balance at September 30, 2002			24,846			(1,054	)		(7,612	)		16,180

2003 Change:
	Pre-income tax amount		29,731			—			2,421			32,152
	Income tax provision		(11,298	)		—			(920	)		(12,218	)
	Amortization of swap (net of $602 income tax benefit)		—			982			—			982
	Realized gains in net income (net of $2,101 income tax)		(3,428	)		—			—			(3,428	)

			15,005			982			1,501			17,488

Balance at September 30, 2003		$	39,851		$	(72	)	$	(6,111	)	$	33,668

NOTE 9 EMPLOYEE BENEFIT PLANS

In July 2003, the Company revised the Helmerich & Payne, Inc. Employee Retirement Plan (“Pension Plan” ) to close the Pension Plan to new participants effective October 1, 2003, and reduce benefit accruals for current participants through September 30, 2006, at which time benefit accruals will be discontinued and the plan frozen. These revisions to the Pension Plan had no effect upon pension expense accruals for fiscal 2003.

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,	2003			2002

	(in thousands)
Benefit obligation at beginning of year	$	68,134		$	51,733
Service cost		5,401			4,769
Interest cost		4,423			3,835
Curtailments		(8,444	)		(1,232	)
Actuarial loss		6,269			11,036
Benefits paid		(4,609	)		(2,007	)

Benefit obligation at end of year	$	71,174		$	68,134

Change in plan assets:


Years Ended September 30,	2003			2002

	(in thousands)
Fair value of plan assets at beginning of year	$	48,286		$	53,987
Actual gain (loss) on plan assets		9,958			(3,694	)
Benefits paid		(4,609	)		(2,007	)

Fair value of plan assets at end of year	$	53,635		$	48,286

Funded status of the plan	$	(17,539	)	$	(19,848	)
Unrecognized net actuarial loss		15,052			24,929
Unrecognized prior service cost		20			284
Accumulated other comprehensive loss (before tax)		(9,856	)		(12,277	)

Accrued benefit cost	$	(12,323	)	$	(6,912	)

Weighted-average assumptions:


Years Ended September 30,	2003			2002			2001

Discount rate		6.25	%		6.75	%		7.50	%
Expected return on plan assets		8.00	%		8.00	%		9.00	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%

COMPONENTS OF NET PERIODIC PENSION EXPENSE:


Years Ended September 30,	2003			2002			2001

	(in thousands)
Service cost	$	5,401		$	4,769		$	3,851
Interest cost		4,423			3,835			3,330
Expected return on plan assets		(3,807	)		(4,804	)		(5,415	)
Amortization of prior service cost		180			238			238
Amortization of transition asset		—			(540	)		(540	)
Curtailment gain		1,550			120			17
Recognized net actuarial loss		84			—			—

Net pension expense	$	7,831		$	3,618		$	1,481

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 $5,568,000, $5,226,000, and $4,499,000 in 2003, 2002, and 2001, respectively.

NOTE 10 OTHER CURRENT ASSETS AND ACCRUED LIABILITIES

Prepaid expenses and other consist of the following:


September 30,	2003		2002

	(in thousands)
Time deposits	$	322	$	337
Income tax receivable		32,619		9,304
Deferred mobilization		2,993		—
Other		9,787		7,112

	$	45,721	$	16,753

Accrued liabilities consist of the following:


September 30,	2003		2002

	(in thousands)
Taxes payable – operations	$	8,386	$	7,660
Workers compensation claims		2,820		2,506
Payroll and employee benefits		6,768		7,032
Deferred income		1,535		6,016
Other		9,479		8,640

	$	28,988	$	31,854

NOTE 11 SUPPLEMENTAL CASH FLOW INFORMATION


Years Ended September 30,		2003		2002		2001

		(in thousands)
Cash payments:
	Interest paid, net of amount capitalized	$	11,375	$	477	$	1,546
	Income taxes paid	$	5,838	$	9,779	$	42,523

NOTE 12 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 and are typically not secured by collateral. The Company provides an allowance for doubtful accounts, when necessary, to cover estimated credit losses. Such an allowance is based on managements knowledge of customer accounts. No significant credit losses have been experienced by the Company.

SELF-INSURANCE

The Company self-insures a significant portion of its expected losses under its worker’s compensation, general, and automobile liability programs in the United States. Insurance coverage has been purchased for individual claims that exceed $2 million. The Company records estimates for incurred outstanding liabilities for unresolved worker’s compensation, general liability claims and for claims that are incurred but not reported. Estimates are based on historic experience and statistical methods that the Company believes are reliable. Nonetheless, insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claims development, and settlement practices. Unanticipated changes in these factors may produce materially different amounts of expense that would be reported under these programs.

CONTRACT DRILLING OPERATIONS

International drilling operations are significant contributors to the Company’s revenues and net profit. It is possible that operating results could be affected by the risks of such activities, including economic conditions in the international markets in which the Company operates, political and economic instability, fluctuations in currency exchange rates, changes in international regulatory requirements, international employment issues, and the burden of complying with foreign laws. These risks may adversely affect the Company’s future operating results and financial position.

The Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. In Venezuela, while approximately 60 percent of the Company’s billings to the Venezuelan oil company, PDVSA, are in U.S. dollars and 40 percent are in the local currency, the bolivar, PDVSA typically pays all amounts owed in bolivars. The Company, historically, has usually been able to convert the bolivars received in payment of the dollar-based billings into U.S. dollars in a timely manner. In January 2003, the Venezuelan government put into effect exchange controls that fixed the exchange rate at 1600 bolivars to one U.S. dollar and also prohibited the Company, as well as other companies, from converting the bolivar into U.S. dollars. As a result of these exchange controls, the Company has been unable since January 2003 to convert its bolivar cash balances into U.S. dollars. As of September 30, 2003, the Company’s bolivar balance was approximately 14 billion bolivars or approximately $8.8 million. Historically, the Company has kept bolivar cash balances at necessary minimum levels to fund local operating costs. In compliance with applicable

regulations the Company on October 1, 2003, submitted a request to the Venezuelan government seeking permission to convert existing bolivar balances into U.S. dollars. The Company is unable to predict if or when this request will be approved.

As stated above, the Company is exposed to risks of currency devaluation in Venezuela primarily as a result of bolivar receivable balances and bolivar cash balances. From August of 2002 to August of 2003, there was a 13 percent devaluation of the bolivar. As a result, the Company experienced a $624,000 devaluation loss. This 13 percent devaluation loss may not be reflective of the actual potential for future devaluation losses because of the exchange controls that are currently in place. While the Company is unable to predict future devaluation in Venezuela, if fiscal 2004 activity levels are similar to fiscal 2003 and if a 25 to 50 percent devaluation would occur, the Company could experience potential currency devaluation losses ranging from approximately $3,200,000 to $5,100,000.

In late August 2003, the Venezuelan state petroleum company agreed, on a go-forward basis, to pay a portion of the Company’s dollar-based invoices in U.S. dollars. While this is a positive development in light of the existing exchange controls, there is no guarantee as to how long this arrangement will continue. Were this agreement to end, The Company would revert back to receiving these payments in Bolivars and thus increase Bolivar cash balances and exposure to devaluation.

Recent events in Venezuela have created greater governmental instability. In the event that extended labor strikes occur or turmoil increases, the Company could experience shortages in material and supplies necessary to operate some or all of its Venezuelan drilling rigs.

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.

NOTE 13 NEW ACCOUNTING STANDARDS

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. The Statement requires that the fair value of a liability 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. There was no impact on the Company’s results of operations and financial position upon adopting SFAS No. 143 on October 1, 2002.

NOTE 14 CONTINGENT LIABILITIES AND COMMITMENTS

COMMITMENTS

The Company, on a regular basis, makes commitments for the purchase of contract drilling equipment. At September 30, 2003, the Company has commitments of approximately $35 million for the purchase of drilling equipment.

LEASES

In May 2003, the Company signed a six-year lease for approximately 114,000 square feet of office space near downtown Tulsa. The lease will be effective as the Company moves during the first quarter of fiscal 2004. Future annual minimum lease payments under this noncancelable lease and other noncancelable leases as of September 30, 2003 were as follows: (in thousands)


Fiscal Year		Amount

2004		$	1,285
2005			1,048
2006			1,311
2007			1,385
2008			1,385
Thereafter			1,732

	Total	$	8,146

Total rent expense was $1,108,000, $1,027,000 and $736,000 for 2003, 2002 and 2001, respectively.

NOTE 15 SEGMENT INFORMATION

The Company operates principally in the contract drilling industry. The Company’s contract drilling business includes the following operating segments: U.S. Land, U.S.Offshore Platform, and International. The contract drilling operations consist primarily 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. The Company also has a Real Estate segment whose operations are conducted exclusively in the metropolitan area of Tulsa, Oklahoma. The primary areas of operations include a major shopping center and several multi-tenant warehouses. Each reportable segment is a strategic business unit which is managed separately. Other includes Investments and corporate operations. As described in Note 2 the Company’s oil and gas operations were distributed to Company shareholders on September 30, 2002. Such operations have been treated as discontinued operations and have been excluded from these segment disclosures.

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; direct operating costs;

depreciation; and allocated general and administrative costs; but excludes corporate costs for other depreciation and other income and expense. General and administrative costs are allocated to the segments based primarily on specific identification, and to the extent that such identification was not practical, on other methods which the Company believes to be a reasonable reflection of the utilization of services provided. The accounting policies of the segments are the same as those described in Note 1, Summary of Accounting Policies. Intersegment sales are accounted for in the same manner as sales to unaffiliated customers.

Summarized financial information of the Company’s reportable segments for each of the years ended September 30, 2003, 2002, and 2001 is shown in the following table:


																Additions
		External		Inter-			Total			Operating				Total		to Long-Lived
(in thousands)		Sales		Segment			Sales			Profit		Depreciation		Assets		Assets

2003:
Contract Drilling
	U.S. Land	$	273,993	$	—		$	273,993		$	18,565	$	44,726	$	728,707	$	216,590
	U.S. Offshore Platform		112,633		—			112,633			36,306		12,799		170,580		7,191
	International Services		109,812		—			109,812			5,149		20,092		243,918		12,733

			496,438		—			496,438			60,020		77,617		1,143,205		236,514

Real Estate			10,893		1,439			12,332			6,569		2,535		31,472		7,628
Other			7,953		—			7,953			—		2,361		241,158		2,159
Eliminations			—		(1,439	)		(1,439	)		—		—		—		—

	Total	$	515,284	$	—		$	515,284		$	66,589	$	82,513	$	1,415,835	$	246,301

2002:
Contract Drilling
	U.S. Land	$	231,637	$	809		$	232,446		$	30,493	$	26,311	$	555,137	$	236,254
	U.S. Offshore Platform		132,249		—			132,249			38,688		10,809		173,474		48,273
	International Services		151,392		—			151,392			13,128		20,336		254,940		23,157

			515,278		809			516,087			82,309		57,456		983,551		307,684

Real Estate			8,525		1,491			10,016			5,064		1,844		26,562		3,181
Other			28,076		—			28,076			—		2,147		217,200		1,199
Eliminations			—		(2,300	)		(2,300	)		—		—		—		—

Total		$	551,879	$	—		$	551,879		$	87,373	$	61,447	$	1,227,313	$	312,064

2001:
Contract Drilling
	U.S. Land	$	221,857	$	4,487		$	226,344		$	67,580	$	16,701	$	366,193	$	136,740
	U.S. Offshore Platform		128,459		—			128,459			40,111		9,576		139,980		7,323
	International Services		170,270		—			170,270			28,475		18,838		268,947		38,022

			520,586		4,487			525,073			136,166		45,115		775,120		182,085

Real Estate			11,018		1,545			12,563			6,315		2,284		22,621		1,190
Other			10,967		—			10,967			—		2,133		367,123		1,393
Eliminations			—		(6,032	)		(6,032	)		—		—		—		—

Total		$	542,571	$	—		$	542,571		$	142,481	$	49,532	$	1,164,864	$	184,668

The following table reconciles segment operating profit per the table on page 59 to income before taxes and equity in income (loss) of affiliates as reported on the Consolidated Statements of Income (in thousands).


Years Ended September 30,			2003			2002			2001

Segment operating profit			$	66,589		$	87,373		$	142,481
Unallocated amounts:
	Income from investments			7,953			28,076			10,967
	Corporate and administrative expense			(25,650	)		(20,391	)		(16,627	)
	Interest expense			(12,289	)		(980	)		(1,701	)
	Corporate depreciation			(2,361	)		(2,147	)		(2,133	)
	Other corporate expense			(300	)		(711	)		(10	)

		Total unallocated amounts		(32,647	)		3,847			(9,504	)

Income before income taxes and equity in income (loss) of affiliates			$	33,942		$	91,220		$	132,977

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,			2003		2002		2001

Revenues
	United States		$	405,472	$	400,487	$	372,301
	Venezuela			31,763		50,763		49,163
	Ecuador			50,783		47,501		37,839
	Colombia			6,081		11,612		28,886
	Other Foreign			21,185		41,516		54,382

		Total	$	515,284	$	551,879	$	542,571

Long-Lived Assets
	United States		$	867,365	$	698,316	$	448,119
	Venezuela			75,179		72,630		84,856
	Ecuador			46,778		49,353		33,520
	Colombia			12,984		14,339		16,195
	Other Foreign			55,899		62,807		67,361

		Total	$	1,058,205	$	897,445	$	650,051

Long-lived assets are comprised of property, plant and equipment.

Revenues from one company doing business with the contract drilling segment accounted for approximately 15.7 percent, 16.3 percent, and 23.9 percent of the total consolidated revenues during the years ended September 30, 2003, 2002, and 2001, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 14.6 percent, 14.7 percent, and 12.8 percent of total consolidated revenues in the years ended September 30, 2003, 2002, and 2001, respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 11.5 percent, 12.3 percent, and 8.4 percent of total consolidated revenues in the years ended September 30, 2003, 2002, and 2001, respectively. Collectively, the receivables from these customers were approximately $36.0 million and $35.0 million at September 30, 2003 and 2002, respectively.

NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

(in thousands, except per share amounts)


2003	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter

Revenues	$	113,313	$	126,320	$	137,025	$	138,626
Gross profit		14,021		19,024		26,788		27,401
Net income		607		2,574		8,162		6,530
Basic net income per common share:		.01		.05		.16		.13
Diluted net income per common share:		.01		.05		.16		.13


2002		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter

Revenues		$	143,883	$	132,344	$	152,049	$	123,603
Gross profit			37,378		24,093		47,477		19,815
Income from continuing operations			18,127		8,129		22,551		4,899
Net income			15,604		10,872		28,218		8,823
Basic earnings per common share:
	Income from continuing operations		.36		.16		.46		.10
	Net income		.31		.22		.57		.18
Diluted earnings per common share:
	Income from continuing operations		.36		.16		.45		.10
	Net income		.31		.22		.56		.17

Gross profit represents total revenues less operating costs and depreciation.

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 average number of common shares outstanding.

Net income in the fourth quarter of 2003 includes after-tax gains on sale of available-for-sale securities of $3.2 million, $0.06 per share, on a diluted basis.

Net income in the fourth quarter of 2003 includes an after-tax equity loss in loss of affiliates of $2 million, $0.04 per share, on a diluted basis.

Net income in the third quarter of 2002 includes after-tax gains on sale of available-for-sale securities of $15.2 million, $0.30 per share, on a diluted basis.

Directors Officers

W. H. Helmerich, III W. H. Helmerich, III

Chairman of the Board Chairman of the Board

Tulsa, Oklahoma

Hans Helmerich

Hans Helmerich President and Chief Executive Officer

President and Chief Executive Officer

Tulsa, Oklahoma George S. Dotson

Vice President,

William L. Armstrong**(***) President of Helmerich & Payne

Chairman International Drilling Co.

Transland Financial Services, Inc.

Denver, Colorado Douglas E. Fears

Vice President and

Glenn A. Cox*(***) Chief Financial Officer

President and Chief Operating Officer, Retired

Phillips Petroleum Company Steven R. Mackey

Bartlesville, Oklahoma Vice President, Secretary,

and General Counsel

George S. Dotson

Vice President, Gordon K. Helm

President of Helmerich & Payne Controller

International Drilling Co.

Tulsa, Oklahoma

Paula Marshall-Chapman**(***)

President and Chief Executive Officer

The Bama Companies, Inc.

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

John D. Zeglis**(***)

Chairman and Chief Executive Officer

AT&T Wireless Services

Basking Ridge, New Jersey

* Member, Audit Committee

** Member, Human Resources Committee

*** Member, Nominating and Corporate Governance Committee

Stockholders’ Meeting

The annual meeting of stockholders will be held on March 3, 2004. A formal notice of the meeting, together with a proxy statement and form of proxy will be mailed to shareholders on or about January 27, 2004.

Stock Exchange Listing

Helmerich & Payne, Inc. Common Stock is traded on the New York Stock Exchange with the ticker symbol “HP.” The newspaper abbreviation most commonly used for financial reporting is “HelmP.” Options on the Company’s stock are also traded on the New York Stock Exchange.

Stock Transfer Agent and Registrar

As of December 15, 2003, there were 1,017 record holders of Helmerich & Payne, Inc. common stock as listed by the transfer agent’s records.

Our Transfer Agent is responsible for our shareholder 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

Additional Information

Quarterly reports on Form 10-Q, earnings releases, and financial statements are made available on the investor relations section of the Company’s Web site. Also located on the investor relations section of the Company’s Web site are certain corporate governance documents, including the following: the charters of the committees of the Board of Directors; the Company’s Corporate Governance Guidelines; the Code of Ethics for Principal Executive Officer and Senior Financial Officers; certain Audit Committee Practices and a description of the means by which employees and other interested persons may communicate certain concerns to the Company’s Board of Directors, including the communication of such concerns confidentially and anonymously via the Company’s ethics hotline at 1-800-205-4913. Quarterly reports, earnings releases, financial statements and the various corporate governance documents are also available free of charge upon written request.

Direct Inquiries To:

Investor Relations
Helmerich & Payne, Inc.
1437 South Boulder Avenue
Tulsa, Oklahoma 74119
Telephone: (918) 742-5531

Internet Address: http://www.hpinc.com

(a)		See Note 3 “Long-term Debt” to the Company’s Consolidated Financial Statements.

(b)		See Note 14 “Commitments and Contingencies” to the Company’s Consolidated Financial Statements.


										Accumulated
				Treasury Stock						Other
										Comprehensive
				Shares			Amount			Income (Loss)			Total

				(in thousands, except per share amounts)
Balance, September 30, 2000					3,548		$	(32,412	)	$	106,064		$	955,703
Comprehensive Income:
	Net Income													144,254
	Other comprehensive loss:
		Unrealized losses on available-for sale securities, net									(55,769	)		(55,769	)
		Derivatives instruments losses, net									(986	)		(986	)

	Total other comprehensive loss													(56,755	)

Total comprehensive income														87,499

Cash dividends ($.30 per share)														(15,047	)
Exercise of stock options					(646	)		5,808						13,773
Purchase of stock for treasury					774			(23,198	)					(23,198	)
Tax benefit of stock-based awards														6,269
Amortization of deferred compensation														1,478

Balance, September 30, 2001					3,676			(49,802	)		49,309			1,026,477
Comprehensive Income:
	Net Income													63,517
	Other comprehensive (loss):
		Unrealized losses on available-for sale securities, net									(25,449	)		(25,449	)
		Derivatives instruments losses, net									(68	)		(68	)
		Minimum pension liability adjustment, net									(7,612	)		(7,612	)

			Total other comprehensive loss											(33,129	)

Total comprehensive income														30,388

Distribution of Cimarex Energy Co. Stock														(152,201	)
Cash dividends ($.31 per share)														(15,492	)
Exercise of stock options					(181	)		2,455						3,554
Forfeiture of Restricted Stock Award					23			(244	)
Tax benefit of stock-based awards														978
Amortization of deferred compensation														1,466

Balance, September 30, 2002					3,518			(47,591	)		16,180			895,170
Comprehensive Income:
	Net Income													17,873
	Other comprehensive income:
		Unrealized gains on available-for sale securities, net									15,005			15,005
		Derivatives instruments amort., net									982			982
		Minimum pension liability adjustment, net									1,501			1,501

			Total other comprehensive gain											17,488

Comprehensive income														35,361

Cash dividends ($.32 per share)														(16,026	)
Exercise of stock options					(129	)		1,753						2,194
Tax benefit of stock-based awards														372
Amortization of deferred compensation														180

Balance, September 30, 2003					3,389		$	(45,838	)	$	33,668		$	917,251


Directors		Officers

W. H. Helmerich, III		W. H. Helmerich, III
Chairman of the Board		Chairman of the Board
Tulsa, Oklahoma
		Hans Helmerich
Hans Helmerich		President and Chief Executive Officer
President and Chief Executive Officer
Tulsa, Oklahoma		George S. Dotson
		Vice President,
William L. Armstrong(*)		President of Helmerich & Payne
Chairman		International Drilling Co.
Transland Financial Services, Inc.
Denver, Colorado		Douglas E. Fears
		Vice President and
*Glenn A. Cox(*)		Chief Financial Officer
President and Chief Operating Officer, Retired
Phillips Petroleum Company		Steven R. Mackey
Bartlesville, Oklahoma		Vice President, Secretary,
		and General Counsel
George S. Dotson
Vice President,		Gordon K. Helm
President of Helmerich & Payne		Controller
International Drilling Co.
Tulsa, Oklahoma

Paula Marshall-Chapman(*)
President and Chief Executive Officer
The Bama Companies, Inc.
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

John D. Zeglis(*)
Chairman and Chief Executive Officer
AT&T Wireless Services
Basking Ridge, New Jersey