Helmerich & Payne

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 2

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 $241 million
as of September 30, 2004.

F I N A N C I A L   H I G H L I G H T S  

Revenues

Net Income
Diluted Earnings per Share 

Dividends Paid per Share

Capital Expenditures

Total Assets

Years Ended September 30,        

2004

2003

( in thousands , except per share amounts)

$   620,928

$

515,284

4,359
.09

.323

88,972

1,406,844

17,873
.35

.32

246,301

1,417,770

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 3

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

When I worked on my first Annual Report twenty-three years ago,
that publication was the single most important way we communicated
to shareholders. A popular staple back then was my dad’s President’s
Letter. He started a tradition of penning a wide-ranging commentary
back in the1960s, and after he retired, I picked up a similar approach
with my first letter in 1990. Over the years, I tackled a range of issues
that bear on all U.S. public companies, including common education,
double taxation, executive compensation, and energy policy. I always
enjoyed readers’ feedback and particularly remember meeting the
author of the most famous President’s Letter, Warren Buffet, who 
recommended to me that I turn the task back to my predecessor.
That’s an offer our Chairman continues to turn down each year,
although it still gets a laugh between us.

Over these same years, the role of the Annual Report has changed 
significantly. Its importance as a communication tool has given way to
more timely webcasts and conference calls, strict disclosures and legal
requirements, and the broad use of increasingly popular and accessible
websites. Along with a growing number of public companies, we have
combined our Annual Report with our 10-K filing as a cost-effective
approach to compliance. 

This letter will change as this document continues to evolve. Before 
summarizing our operations for 2004, I want to thank our employees
for delivering outstanding field performance during a challenging year.

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 4

Contract Drilling Operations
Crude oil prices surged during the last half of 2004, erasing previous
records and reaching past $50 per barrel. Additionally, natural gas
prices remained resilient in 2004, even in the face of record storage
inventories heading into the 2004-2005 heating season. In short, 
our customers have not experienced a healthier commodity price 
environment in decades. According to statistics compiled by Baker
Hughes, average rig activity improved world-wide by approximately 
13 percent in 2004, with nearly three quarters of the gain coming in
the U.S. land market. Almost half of the world’s active rigs are in the
U.S. land market, which at year-end had 1,129 active rigs, compared
with 967 at the end of 2003. In sharp contrast, the U.S. offshore 
market continued to soften and ultimately translated into a significant
negative impact on this year's financial results.

U.S. Offshore Operations
After 20 years of steady performance, the Company has suffered in
recent years through an industry-wide downturn in activity levels for
conventional water depths, where the majority of the Company’s 
offshore platform rigs operate. While this segment appears to have 
stabilized, the Company took a $51.5 million non-cash asset impair-
ment charge against the carrying value of its Gulf of Mexico platform
rigs, reflecting our continued expectation that any recovery in this 
sector will be slow. The Company retired one offshore platform rig at

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 5

the end of 2004, leaving 11 rigs in the fleet, which we believe are the
newest and best available in their class in the Gulf of Mexico market.
At year-end, three rigs were working on full day rates, two rigs were
on standby rates, and six rigs were available for work.

International Operations
Significant improvements in Venezuela and Argentina, as well as 
operations in Hungary and Equatorial Guinea, helped bolster 
performance in 2004. On average, the Company had five more rigs
working in 2004 than in 2003, resulting in a 39 percent increase in 
revenue days. Including a $1.7 million insurance settlement, revenues
increased 37 percent and operating profit climbed to $14 million 
compared with $5.1 million in 2003. Activity in Venezuela increased 
by over three rigs in 2004, and at the close of the year, nine rigs were
running, with a tenth likely to commence in January 2005. After
Venezuela, Ecuador is the second strongest market for the Company
in South America. At year-end, the Company had seven rigs operating
there, and an eighth has a letter of intent to begin operations in
December 2004. Colombia had very weak activity in 2004, but at the
close of the year, one rig had returned to work, and the Company
received a letter of intent to return a second rig to work in December
2004. International operations in South America strengthened 
measurably in 2004, and with the return of four older rigs to the U.S.
and new contracts in Venezuela, Ecuador, and Colombia, the
Company anticipates that it will have 23 rigs out of 27 rigs working
by the end of the first quarter of fiscal 2005.

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 6

The Company's first international FlexRig*, working in Hungary, 
should work through the first fiscal quarter of 2005. The Company
completed a multi-well contract in Chad using its second international
FlexRig during the year, and that rig has since returned to the U.S.
fleet and is working in central Florida. The Company continues to
actively prospect in other regions of the world for attractive growth
opportunities, principally in areas where FlexRig technology can be
applied to add considerable value.

U.S. Land Operations
In July, the U.S. land rig count surpassed the previous high mark set 
in 2001, and activity continues to grow. The Company added ten net
rig years to its fleet capacity during 2004 and worked 13 more rig years
than in 2003. Revenues and cash flow increased 27 and 48 percent,
respectively, and operating profit doubled that of 2003. At the close of
the year, the Company had 87 rigs available to the market, 80 of which
were working. FlexRig utilization during 2004 was 99 percent, compared
with 73 percent for the Company’s remaining fleet. The Company
completed its FlexRig3 construction project, delivering the 32nd
FlexRig3 at the end of March. FlexRig3s have drilled almost 500
wells, 73 percent of which were drilled under or on the customers’
planned drilling time. In further recognition of the superior value, half
of the FlexRig3 fleet is being used to drill directional, more technically 

* The term “FlexRig” used throughout this Annual Report is a Company trademark

Registered in the U.S. Patent and Trademark Office.

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 7

difficult wells compared to an average of 26 percent for the industry
fleet. The FlexRig3 is setting the industry pace in pricing with 20 out
of 32 FlexRig3s currently contracted at $14,000 per day or higher.
The counter cyclical investment made in the FlexRig has strategically
positioned the Company by doubling its U.S. capacity and by 
demonstrating a clear performance differential to the customer. 
Forty-nine of our 50 FlexRigs are located in the U.S. and will 
give the Company improved potential earnings leverage in this 
growing up-cycle.

Outlook
The Company had its share of frustration and disappointment in
2004, but we are encouraged by the momentum we see developing for
2005 and beyond. U.S. land market activity indicates that the industry
is entering a different, but improving part of the drilling cycle, and as
rig counts continue to move up, we expect dayrate pricing will also
ratchet up. The Company’s FlexRig3 continues to receive high marks
in the field, and as oil field costs escalate, the Company expects to see
increasing recognition of its value in the form of higher margins. We
are also encouraged by improvements in the international market and
look to this arena to be a leading source of long-term growth.
Although the offshore platform market has been a disappointment,
the Company maintains a solid foothold in this segment of the 
business with the newest rigs in the Gulf of Mexico fleet and a wealth
of engineering and project management experience that is essential for

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 8

developing future opportunities. While we have no immediate 
plans or announcements regarding new rigs, we do have customers
expressing interest in projects in the U.S., as well as internationally.
We expect that additional investments will be accompanied by term
contracts and dayrates that provide improved financial returns and
that better reflect what we strongly believe to be unparalleled drilling
efficiencies and service.

Sincerely,

Hans Helmerich
President

December 9, 2004

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 9

Financial & Operating Review

SUMMARY OF CONSOLIDATED STATEMENTS OF INCOME*†

Years Ended September 30,

2004

2003

2002

Operating Revenues
Operating Costs
Depreciation①
Operating Income
Income from Investments
Interest Expense
General and Administrative Expense
Income from Continuing Operations
Net Income
Diluted Earnings Per Common Share:

Income from Continuing Operations
Net Income

*$000’s omitted, except per share data.
①2004 includes an asset impairment charge of $51,516
†All data excludes discontinued operations except net income.

SUMMARY FINANCIAL DATA*

Cash**
Working Capital**
Investments
Property, Plant, and Equipment, Net**
Total Assets
Long-term Debt
Shareholders’ Equity
Capital Expenditures
*$000’s omitted.
** Excludes discontinued operations.

RIG FLEET SUMMARY

Drilling Rigs – 

United States Land – FlexRigs
United States Land – Conventional
United States Offshore Platform
International

Total Rig Fleet

Rig Utilization Percentage – 
United States Land – FlexRigs
United States Land – Conventional
United States Land – All Rigs
United States Offshore Platform
International

593,326
416,631
145,941
30,754
27,602
12,695
37,661
4,359
4,359

.09
.09

507,331
345,537
82,513
79,281
7,953
12,289
41,003
17,873
17,873

.35
.35

523,803
361,669
61,447
100,687
28,076
980
36,563
53,706
63,517

1.07
1.26

65,296
185,983
161,532
998,674
1,406,844
200,000
914,110
88,972

38,189
110,848
158,770
1,058,205
1,417,770
200,000
917,251
246,301

46,883
105,852
150,175
897,445
1,227,313
100,000
895,170
312,064

48
39
11
32
130

99
73
87
48
54

43
40
12
32
127

97
67
81
51
39

26
40
12
33
111

96
78
84
83
51

04-HP-876_firstsection.qxd  12/15/04  2:41 PM  Page 10

2001

2000

1999

1998

1997

1996 

1995 

1994 

531,604
330,181
49,532
151,891
10,967
1,701
28,180
80,467
144,254

384,762
248,568
77,317
58,877
32,063
2,730
23,306
36,470
82,300

1.58
2.84

.73
1.64

431,741
290,048
70,092
71,601
7,422
5,389
24,629
32,115
42,788

.65
.86

479,592
322,861
58,187
98,544
45,152
336
21,299
80,790
101,154

1.60
2.00

128,826
223,980
203,271
650,051
1,300,121
50,000
1,026,477
184,668

107,632
179,884
307,425
526,723
1,200,854
50,000
955,703
65,820

21,758
82,893
240,891
553,769
1,073,465
50,000
848,109
78,357

24,476
49,179
200,400
548,555
1,053,200
50,000
793,148
217,597

13
36
10
37
96

100
96
97
98
56

6
32
10
40
88

99
82
85
94
47

6
34
10
39
89

79
68
69
95
53

6
30
10
44
90

100
94
94
99
88

353,355
228,958
48,291
76,106
11,746
34
15,636
48,801
84,186

.97
1.67

27,963
65,802
323,510
392,489
987,432
—
780,580
114,626

—
29
9
39
77

—
99
99
63
91

274,208
184,703
39,592
49,913
5,992
678
15,222
25,844
72,566

.52
1.46

16,892
48,128
229,809
329,377
786,351
—
645,970
83,411

— 
30
11
36
77

— 
88
88
70
85

229,316
158,815
37,364
33,137
11,279
407
14,019
18,464
9,751

.38
.20

19,543
50,038
156,908
286,678
707,061
—
562,435
89,709

— 
30
11
35
76

— 
73
73
66
84

206,991
148,210
31,038
27,743
6,944
385
14,126
13,216
24,971

.27
.51

29,447
76,238
87,414
235,067
624,827
—
524,334
59,379

— 
36
11
29
76

— 
66
66
79
88

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 1

Helmerich & Payne, Inc.

FORM 10-K, 2004

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 2

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K
[X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2004 OR

[  ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM             TO

COMMISSION FILE NUMBER 1-4221
HELMERICH & PAYNE, INC.
(Exact name of registrant as specified in its charter)

DELAWARE                          73-0679879
(State or other jurisdiction of                        (I.R.S. employer

incorporation or organization)                      identification no.)

1437 S. BOULDER AVE., SUITE 1400, TULSA, OKLAHOMA 74119

(Address of principal executive offices)                      (Zip code)

Registrant's telephone number, including area code  (918) 742-5531

Securities registered pursuant to Section 12(b) of the Act:

TITLE OF EACH CLASS

NAME OF EXCHANGE ON WHICH REGISTERED

Common Stock ($0.10 par value)

New York Stock Exchange

Common Stock Purchase Rights

New York Stock Exchange

Securities registered Pursuant to Section 12(g) of the Act:  NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X]  No [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X]  No [  ]

At March 31, 2004, the aggregate market value of the voting stock held by non-affiliates was $1,378,913,985.

Number of shares of common stock outstanding at December 3, 2004: 50,610,987.

D O C U M E N T S   I N C O R P O R AT E D   B Y   R E F E R E N C E
Certain portions of the following documents have been incorporated by reference into this Form 10-K as indicated:

Documents

(1) Annual Report to Stockholders for the fiscal 
year ended September 30, 2004 

(2) Proxy Statement for Annual Meeting of Stockholders 
to be held March 2, 2005

10-K Parts

Parts I and II

Part III

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 3

D I S C L O S U R E   R E G A R D I N G   F O R W A R D - L O O K I N G   S T A T E M E N T S

THIS REPORT INCLUDES “FORWARD-LOOKING STATEMENTS” WITHIN THE MEANING OF THE SECURITIES ACT OF

1933, AS AMENDED, AND THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.  ALL STATEMENTS OTHER

THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS REPORT, INCLUDING, WITHOUT LIMITATION,

STATEMENTS REGARDING THE REGISTRANT’S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS,

PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-

LOOKING STATEMENTS.  IN ADDITION, FORWARD-LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY 

THE USE OF FORWARD-LOOKING TERMINOLOGY SUCH AS “MAY”, “WILL”, “EXPECT”, “INTEND”, “ESTIMATE”,

“ANTICIPATE”, “BELIEVE”, OR “CONTINUE” OR THE NEGATIVE THEREOF OR SIMILAR TERMINOLOGY.  ALTHOUGH

THE REGISTRANT BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS

ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO BE CORRECT.

IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE REGISTRANT’S

EXPECTATIONS ARE DISCLOSED IN THIS REPORT UNDER THE CAPTION “RISK FACTORS” BEGINNING ON PAGE 

6, AS WELL AS IN MANAGEMENT’S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL 

CONDITION ON PAGES 44 THROUGH 53 OF THE COMPANY’S ANNUAL REPORT.  ALL SUBSEQUENT WRITTEN AND

ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE REGISTRANT, OR PERSONS ACTING ON ITS

BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY SUCH CAUTIONARY STATEMENTS.  THE REGISTRANT

ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN 

INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE.

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 4

PART I

I T E M   1 .   B U S I N E S S

Helmerich & Payne, Inc. (the “Company”), was incorporated under the laws of the State of Delaware on February 3,
1940, and is successor to a business originally organized in 1920. The Company is primarily engaged in contract
drilling of oil and gas wells for others. The contract drilling business accounts for almost all of the Company’s operating
revenues. The Company is also engaged in the ownership, development, and operation of commercial real estate.

The Company is organized into two separate operating entities, contract drilling and real estate. Both businesses 
operate independently of the other through wholly owned subsidiaries. Operating decentralization is balanced by a cen-
tralized finance division, which handles all accounting, information technology, budgeting, insurance, cash 
management, and related activities.

The Company’s contract drilling business is composed of three business segments: U.S. land drilling, U.S. offshore
platform drilling and international drilling. The Company's U.S. land drilling is conducted primarily in Oklahoma, Texas,
Wyoming, Colorado, and Louisiana, and offshore from platforms in the Gulf of Mexico and California. The Company
also operated in eight international locations during fiscal 2004: Venezuela, Ecuador, Colombia, Argentina, Bolivia,
Equatorial Guinea, Chad, and Hungary. In addition, the Company is providing drilling consulting services for one cus-
tomer in Russia.

The Company's real estate investments are located in Tulsa, Oklahoma, where the Company maintains its executive offices.

Prior to October 1, 2002, the Company was engaged in the exploration, production and sale of crude oil and natural gas
business (“exploration and production business”). During fiscal 2002, the Company transferred the assets and liabilities
of its exploration and production business to its wholly owned subsidiary, Cimarex Energy Co. On September 30, 2002,
the Company distributed the common stock of Cimarex Energy Co. to the Company’s stockholders and completed a
merger of Key Production Company, Inc. with a subsidiary of Cimarex Energy Co. As a result of this transaction, Cimarex
Energy Co. became a separate publicly-traded company that owned and operated the exploration and production busi-
ness. The Company does not own any common stock of Cimarex Energy Co.

During fiscal 2004, the Company incorporated in Vermont a wholly-owned captive insurance subsidiary. The
Company believes that the use of this captive will reduce its insurance costs.

C O N T R A C T   D R I L L I N G

The Company believes that it is one of the major land and offshore platform drilling contractors in the western hemisphere.
Operating principally in North and South America, the Company specializes in medium to deep drilling in major gas 
producing basins of the United States and in drilling for oil and gas in international locations. In the United States, the
Company draws its customers primarily from the major oil companies and the larger independents. In South America, the
Company's current customers include the Venezuelan state petroleum company and major international oil companies.

In fiscal 2004, the Company received approximately 56 percent of its consolidated revenues from the Company’s ten
largest contract drilling customers. BP plc, ExxonMobil Corporation, and Shell Oil Company (respectively, "BP",
“ExxonMobil” and “Shell”), including their affiliates, are the Company’s three largest contract drilling customers. The
Company performs drilling services for BP, ExxonMobil, and Shell on a world-wide basis. Revenues from drilling services
performed for BP, ExxonMobil and Shell in fiscal 2004 accounted for approximately 10.8 percent, 10.7 percent and 8.4
percent, respectively, of the Company’s consolidated revenues for the same period.

The Company provides drilling rigs, equipment, personnel, and camps on a contract basis. These services are provided
so that the Company’s customers may explore for and develop oil and gas from onshore areas and from fixed 

1

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 5

platforms, tension-leg platforms and spars in offshore areas. Each of the drilling rigs consists of engines, drawworks, a
mast, pumps, blowout preventers, a drillstring, and related equipment. The intended well depth and the drilling site 
conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job. A
land drilling rig may be moved from location to location without modification to the rig. A helicopter rig is one that can
be disassembled into component part loads of approximately 4,000-20,000 pounds and transported to remote locations
by helicopter, cargo plane, or other means. A platform rig is specifically designed to perform drilling operations upon a
particular platform. While a platform rig may be moved from its original platform, significant expense is incurred to 
modify a platform rig for operation on each subsequent platform. In addition to traditional platform rigs, the Company
operates self-moving minimum-space platform drilling rigs and drilling rigs to be used on tension-leg platforms and spars.
The minimum-space rig is designed to be moved without the use of expensive derrick barges. The tension-leg platforms
and spars allow drilling operations to be conducted in much deeper water than traditional fixed platforms.

During fiscal 1998, the Company put to work a new generation of six highly mobile/depth flexible land drilling rigs 
(individually the “FlexRig®”). The FlexRig has been able to significantly reduce average rig move times compared to 
similar depth-rated traditional land rigs. In addition, the FlexRig allows a greater depth flexibility of between 8,000 to
18,000 feet and provides greater operating efficiency. The original six rigs were designated as FlexRig1 rigs.
Subsequently, the Company built and completed 12 new FlexRig2 rigs. During fiscal 2001, the Company announced
that it would build an additional 25 new FlexRigs. These new rigs, known as “FlexRig3”, were the next generation of
FlexRigs which incorporated new drilling technology and new environmental and safety design. This new design included
integrated top drive, AC electric drive, hydraulic BOP handling system, hydraulic tubular make-up and break-out system,
split crown and traveling blocks and an enlarged drill floor that enables simultaneous crew activities. All 25 of these
FlexRig3s were completed by June of 2003. Subsequently, the Company constructed seven more FlexRig3s at an
approximate cost of $11,250,000 each. Construction of these rigs was completed by March of 2004. All FlexRigs are
available for work in the Company’s U.S. and international drilling operations.

The Company’s drilling contracts are obtained through competitive bidding or as a result of negotiations with customers,
and sometimes cover multi-well and multi-year projects. Each drilling rig operates under a separate drilling contract.
During fiscal 2004, all drilling services were performed on a “daywork” contract basis, under which the Company
charges a fixed rate per day, with the price determined by the location, depth, and complexity of the well to be drilled,
operating conditions, the duration of the contract, and the competitive forces of the market. The Company has previously
performed contracts on a combination “footage” and “daywork” basis, under which the Company charged a fixed rate
per foot of hole drilled to a stated depth, usually no deeper than 15,000 feet, and a fixed rate per day for the remainder
of the hole. Contracts performed on a “footage” basis involve a greater element of risk to the contractor than do contracts
performed on a “daywork” basis.  Also, the Company has previously accepted “turnkey” contracts under which the
Company charges a fixed sum to deliver a hole to a stated depth and agrees to furnish services such as testing, coring,
and casing the hole which are not normally done on a “footage” basis. “Turnkey” contracts entail varying degrees of risk
greater than the usual “footage” contract. The Company did not accept any “footage” or “turnkey” contracts during fiscal
2004. The Company believes that under current market conditions “footage” and “turnkey” contract rates do not 
adequately compensate contractors for the added risks. The duration of the Company's drilling contracts are “well-to-well”
or for a fixed term. “Well-to-well” contracts are cancelable at the option of either party upon the completion of drilling at
any one site. Fixed-term contracts customarily provide for termination at the election of the customer, with an “early ter-
mination payment” to be paid to the contractor if a contract is terminated prior to the expiration of the fixed term.

While the duration for current fixed-term contracts are for six month to three year periods, some fixed-term and 
well-to-well contracts are expected to be continued for longer periods than the original terms. However, the contracting
parties have no legal obligation to extend the contracts. Contracts generally contain renewal or extension provisions 
exercisable at the option of the customer at prices mutually agreeable to the Company and the customer. In most
instances contracts provide for additional payments for mobilization and demobilization.

2

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 6

U . S .   L A N D   D R I L L I N G

At the end of September, 2004 and 2003, the Company had 87 and 83, respectively, of its land rigs available for work
in the United States. The total number of rigs owned at the end of the period increased by a net of four rigs, resulting
from five additional FlexRigs being completed during the year and removing from service one older conventional rig. The
Company’s U.S. land operations contributed approximately 56 percent of the Company’s consolidated revenues during
fiscal 2004, compared with 53 percent of consolidated revenues during fiscal 2003 and 42 percent of consolidated 
revenues during fiscal 2002. Rig utilization in fiscal 2004 was 87 percent, up from 81 percent in fiscal 2003. The
Company’s fleet of FlexRigs and highly mobile rigs maintained an average utilization of approximately 97 percent during
fiscal 2004 while the Company’s conventional rigs had an average utilization rate of approximately 67 percent. At the
close of fiscal 2004, 80 land rigs were working out of 87 available rigs.

In November of 2004, the Company sold two conventional 2,000 horsepower U.S. land rigs for a total of $23.9 million.

U . S .   O F F S H O R E   P L A T F O R M   D R I L L I N G

The Company’s offshore platform operations contributed approximately 14 percent of the Company’s consolidated 
revenues during fiscal 2004, compared with 22 percent of consolidated revenues during fiscal 2003 and 24 percent 
of consolidated revenues during fiscal 2002. Rig utilization in fiscal 2004 was 48 percent, down from 51 percent in
fiscal 2003. At the end of this fiscal year, the Company had six of its 11 offshore platform rigs under contract and it 
continued to work under management contracts for three customer-owned rigs. Revenues from drilling services 
performed for the Company’s largest offshore platform drilling customer totaled approximately 61 percent of U.S. 
offshore platform revenues during fiscal 2004.

It is likely during the first six months of calendar 2005 that one additional platform rig will be stacked and one 
management contract will be terminated.

As a result of declining financial trends and unfavorable market conditions in the Gulf of Mexico, the Company completed
an analysis of its offshore platform business in the Gulf of Mexico. Based on this analysis, the Company recorded a pre-
tax asset impairment charge of $51.5 million in the fourth quarter of 2004.

I N T E R N A T I O N A L   D R I L L I N G

General

The Company’s international drilling operations began in 1958 with the acquisition of Sinclair Oil Company’s drilling rigs
in Venezuela. Helmerich & Payne de Venezuela, C.A., a wholly owned subsidiary of the Company, is one of the leading
drilling contractors in Venezuela. Beginning in 1972, with the introduction of its first helicopter rig, the Company 
expanded into other Latin American countries.

The Company’s international operations contributed approximately 24 percent of the Company’s consolidated revenues
during fiscal 2004, compared with 21 percent of consolidated revenues during fiscal 2003 and 27 percent of consolidated
revenues during fiscal 2002. Rig utilization in fiscal 2004 was 54 percent, up from 39 percent in fiscal 2003.

Venezuela

Venezuelan operations continue to be a significant part of the Company’s operations. During fiscal 2004, the Company
moved two additional deep drilling rigs into the country, bringing the Company rig count to 13 land drilling rigs in
Venezuela at the end of fiscal 2004. However, in early fiscal 2005, the Company moved a highly mobile rig to the
United States, leaving the rig count at twelve. The Company worked primarily for the Venezuelan state petroleum 
company, PDVSA, during fiscal 2004, and revenues from this work accounted for approximately eight percent of the
Company’s consolidated revenues during the fiscal year and 33 percent of international drilling revenues. Revenues 

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 7

generated from all Venezuelan drilling operations contributed approximately 37 percent of the Company’s consolidated
revenues during 2004, compared with 29 percent of consolidated revenues during fiscal 2003 and 34 percent of 
consolidated revenues during 2002. The Company had nine rigs working in Venezuela at the end of fiscal 2004.

The Company’s rig utilization rate in Venezuela has increased from approximately 33 percent during fiscal 2003 to
approximately 65 percent in fiscal 2004. Even though the Company is, at this time, unable to predict future fluctuations
in its utilization rates during fiscal 2005, the Company believes that the prospects are good for returning at least one of
its idle rigs back to work in Venezuela during fiscal 2005.

Ecuador

At the end of fiscal 2004, the Company owned eight rigs in Ecuador. The Company’s utilization rate was approximately
74 percent during fiscal 2004, down from approximately 85 percent in fiscal 2003. Revenues generated by Ecuadorian
drilling operations contributed approximately seven percent of the Company’s consolidated revenues during fiscal 2004,
as compared with 10 percent of consolidated revenues during fiscal 2003 and nine percent of consolidated revenues
during fiscal 2002. Revenues from drilling services performed for the Company’s largest customer in Ecuador totaled
approximately 15 percent of international drilling revenues during fiscal 2004. The Ecuadorian drilling contracts are 
primarily with large international oil companies.

Colombia

During fiscal 2004, the Company moved one rig from Colombia to Venezuela, leaving two rigs in Colombia. The
Company's utilization rate in Colombia was approximately 13 percent during fiscal 2004, down from approximately 21
percent in fiscal 2003. The revenues generated by Colombian drilling operations contributed approximately one percent
of the Company's consolidated revenues in fiscal 2004, as compared with one percent of consolidated revenues during
fiscal 2003 and two percent of consolidated revenues during fiscal 2002. At the end of fiscal 2004, the Company was
operating one rig in Colombia, with a commitment for the second rig to begin work in early fiscal 2005.

Other Locations

In addition to its operations in Venezuela, Ecuador and Colombia, in fiscal 2004, the Company owned six rigs in Bolivia,
one rig in Argentina, one rig in Hungary and one rig in Chad. At the end of fiscal 2004, two rigs were working in Bolivia,
one in Argentina and one in Hungary. As of the end of November, 2004, one rig was working in Bolivia.

At the end of fiscal 2004 one rig was moved from Chad to the United States. During November of 2004, three rigs were
moved from Bolivia to the United States.

During fiscal 2004, the Company continued operations under a management contract for a customer-owned platform rig
located offshore Equatorial Guinea. Also, during the fiscal year, the Company commenced a drilling consulting services
contract in Russia.

R E A L   E S T A T E   O P E R A T I O N S

The Company’s real estate operations are conducted exclusively within the metropolitan area of Tulsa, Oklahoma. Its
major holding is Utica Square Shopping Center, consisting of 15 separate buildings, with parking and other common
facilities covering an area of approximately 30 acres. Utica Square contains approximately 441,588 usable square feet,
composed of retail space of 379,018 usable square feet, office space of 38,785 usable square feet, storage space of
6,600 usable square feet and common area space of 17,185 usable square feet. The Company’s real estate operations
occupy approximately 4,140 square feet of general office and storage space within the shopping center. Occupancy in
the shopping center increased from 85 percent in fiscal 2003 to 91 percent in fiscal 2004 with the additions of an
upscale salon and day spa, and a clothing store for teens and young adults.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 8

At the end of the 2004 fiscal year, the Company owned 11 of a total of 73 units in The Yorktown, a 16-story luxury
residential condominium with approximately 150,940 square feet of living area located on a six-acre tract adjacent to
Utica Square Shopping Center. Six of the Company’s units are currently leased.

The Company owns and leases to third parties multi-tenant warehouse space. Three warehouses known as Space
Center, each containing approximately 165,000 square feet of net leasable space, are situated in the southeast part of
Tulsa at the intersection of two major limited-access highways. Present occupancy is 82 percent, which is down from 98
percent in fiscal 2003. Reduced occupancy is the result of the relocation of one tenant’s research facility to a university.
The Company also owns approximately 1.5 acres of undeveloped land lying adjacent to such warehouses.

In August of 2004, the Company sold approximately 1.73 acres of undeveloped land in Southpark. The sales price totaled
approximately $1 million. Southpark is located in a high growth area of southeast Tulsa and is suitable for mixed commercial
and light industrial. Subsequent to such sale and at the end of fiscal 2004, the Company owned approximately 218 acres
in Southpark consisting of approximately 205 acres of undeveloped real estate and approximately 13 acres of 
multi-tenant warehouse area. The warehouse area is known as Space Center East and consists of two warehouses, one
containing approximately 90,000 square feet and the other containing approximately 112,500 square feet. Present 
occupancy decreased to 82 percent in 2004 from 93% in fiscal 2003 due to the loss of one tenant and a reduction of
space by another. The Company believes that a high quality office park, with peripheral commercial, office/warehouse, and
hotel sites, is the best development use for the remaining land. The Company has contracted with a professional engineering
and planning firm to prepare a comprehensive master plan to aid in the possible future development of Southpark.

The Company owns a five-building complex called Tandem Business Park. The property is located adjacent to and east of
the Space Center East facility and contains approximately six acres, with approximately 88,084 square feet of office/ware-
house space. Occupancy has decreased from 84 percent to 69 percent during fiscal 2004 due to the departure of five small
tenants. The Company also owns a 12-building complex, consisting of approximately 204,600 square feet of office/ware-
house space, called Tulsa Business Park. The property is located south and east of the Space Center facility, separated by a
city street, and contains approximately 12 acres. During fiscal 2004, occupancy has decreased from 86 percent to 81 per-
cent.

The Company owns two service center properties located adjacent to arterial streets in south central Tulsa. The first, called
Maxim Center, consists of one office/warehouse building containing approximately 40,800 square feet and is located on
approximately 2.5 acres. During fiscal 2004, occupancy has remained at 94%. The second, called Maxim Place, consists of
one office/warehouse building containing approximately 33,750 square feet and is located on approximately 2.25 acres.
During fiscal 2004, occupancy has increased from 17 percent to 44 percent with the addition of two tenants. In addition,
the Company has established an offsite disaster recovery center at this facility which occupies approximately 3,517 square feet.

The Company, during fiscal 2004, completed relocation within Tulsa of its executive offices. The razing of its former headquarters
building will be completed in the first quarter of fiscal 2005. No development plans for the site are pending.

F I N A N C I A L

Information relating to revenues, total assets and operating profit or loss by business segments may be found on
pages 79 through 81 of the Company’s Annual Report.

E M P L O Y E E S

The Company had 3,056 employees within the United States (six of which were part-time employees) and 1,195
employees in international operations as of September 30, 2004.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 9

A V A I L A B L E   I N F O R M A T I O N

Information relating to the Company’s internet address and the Company’s SEC filings may be found on page 83 of the
Company’s Annual Report.

R I S K   F A C T O R S

In addition to the risk factors discussed elsewhere in this report, the Company cautions that the following “Risk Factors”
could affect its actual results in the future.

1. Competition

Competition in the Contract Drilling Business

The contract drilling business is highly competitive. Competition in contract drilling involves such factors as price, rig
availability, efficiency, condition of equipment, reputation, operating safety, and customer relations. Competition is 
primarily on a regional basis and may vary significantly by region at any particular time. Land drilling rigs can be readily
moved from one region to another in response to changes in levels of activity, and an oversupply of rigs in any region
may result, leading to increased price competition.

Although many contracts for drilling services are awarded based solely on price, the Company has been successful in
establishing long-term relationships with certain customers which have allowed the Company to secure drilling work even
though the Company may not have been the lowest bidder for such work. The Company has continued to attempt to 
differentiate its services based upon its engineering design expertise, operational efficiency, and safety and environmental
awareness. This strategy is less effective when lower demand for drilling services intensifies price competition and makes it
more difficult or impossible to compete on any basis other than price. Also, future improvements in operational efficiency
and safety by the Company’s competitors could negatively affect the Company’s ability to differentiate its services.

Competition in the Real Estate Business

The Company has numerous competitors in the multi-tenant leasing business. The size and financial capacity of these
competitors range from one property sole proprietors to large international corporations. The primary competitive factors
include price, location, and configuration of space. The Company’s competitive position is enhanced by the location of its
properties, its financial capability and the long-term ownership of its properties. However, many competitors have 
financial resources greater than the Company and have more contemporary facilities. Also, current economic conditions
have encouraged prospective tenants to construct owner-occupied buildings rather than lease third party space.

2. Operating Risks

The drilling operations of the Company are subject to the many hazards inherent in the business, including inclement
weather, blowouts and well fires. These hazards could cause personal injury, suspend drilling operations, seriously 
damage or destroy the equipment involved, and cause substantial damage to producing formations and the surrounding
areas. The Company’s offshore platform drilling operations are also subject to potentially greater environmental liability,
adverse sea conditions and platform damage or destruction due to collision with aircraft or marine vessels.

3. Indemnification and Insurance Coverage

The Company has insurance coverage for comprehensive general liability, public liability, property damage, workers 
compensation, and employer's liability. Generally, deductibles are $2 million per occurrence on claims that fall under these
coverages, except that property damage deductibles on rig properties are generally $1 million per occurrence. Excess 
insurance is purchased over these coverages to limit the Company’s exposure to catastrophic claims. No insurance is 
carried against loss of earnings or business interruption. The Company is unable to obtain significant amounts of insurance

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 10

to cover risks of underground reservoir damage, however, the Company is generally indemnified under its drilling contracts
from this risk. The majority of the Company’s insurance coverage has been purchased through fiscal 2005. No assurance
can be given that all or a portion of the Company’s coverage will not be cancelled during fiscal 2005 or that insurance
coverage will continue to be available at rates considered reasonable. Additionally, no assurance can be given that the
Company’s insurance and indemnification arrangements will adequately protect it against all liabilities that could result
from the hazards of its drilling operations. Incurring a liability for which the Company is not fully insured or indemnified
could materially affect the Company’s results of operations.

4. Volatility of Oil and Gas Prices

The Company’s operations can be materially affected by low oil and gas prices. The Company believes that any 
significant reduction in oil and gas prices could depress the level of exploration and production activity and result in a
corresponding decline in demand for the Company’s services. Worldwide military, political and economic events, 
including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the 
supply of, oil and gas. Fluctuations during the last few years in the demand and supply of oil and gas have contributed
to, and are likely to continue to contribute to, price volatility. Any prolonged reduction in demand for the Company’s 
services could have a material and adverse effect on the Company.

5. International Uncertainties and Local Laws

International operations are subject to certain political, economic, and other uncertainties not encountered in U.S. 
operations, including increased risks of terrorism, kidnapping of employees, expropriation of equipment as well as 
expropriation of a particular oil company operator's property and drilling rights, taxation policies, foreign exchange 
restrictions, currency rate fluctuations, and general hazards associated with foreign sovereignty over certain areas in
which operations are conducted. There can be no assurance that there will not be changes in local laws, regulations,
and administrative requirements or the interpretation thereof which could have a material adverse effect on the 
profitability of the Company’s operations or on the ability of the Company to continue operations in certain areas.

Because of the impact of local laws, the Company’s future operations in certain areas may be conducted through entities
in which local citizens own interests and through entities (including joint ventures) in which the Company holds only a
minority interest, or pursuant to arrangements under which the Company conducts operations under contract to local
entities. While the Company believes that neither operating through such entities nor pursuant to such arrangements
would have a material adverse effect on the Company’s operations or revenues, there can be no assurance that the
Company will in all cases be able to structure or restructure its operations to conform to local law (or the administration
thereof) on terms acceptable to the Company.

Although the Company attempts to minimize the potential impact of such risks by operating in more than one geographical
area, during fiscal 2004, approximately 24 percent of the Company’s consolidated revenues were generated from the 
international contract drilling business. Approximately 78 percent of the international revenues were from operations in South
America and approximately 85 percent of South American revenues were from Venezuela and Ecuador.

6. Currency Risk

General

Contracts for work in foreign countries generally provide for payment in United States dollars, except for amounts required to meet
local expenses. However, government owned petroleum companies are more frequently requesting that a greater proportion of
these payments be made in local currencies. Based upon current information, the Company believes that exposure to potential
losses from currency devaluation is minimal in Colombia, Ecuador, Bolivia, and Equatorial Guinea. In those countries, all 
receivables and payments are currently in U.S. dollars. Cash balances are kept at a minimum which assists in reducing exposure.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 11

Argentina

In 2002, Argentina suffered a 60% devaluation of the peso. As a consequence, the Company secured agreements with its
customers that limited the portion of the accounts receivable that was paid in pesos with the balance of such accounts
receivable paid in U.S. dollars. The Company did not experience Argentine currency losses in fiscal 2004.

Venezuela

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, approximately 60% of the Company’s invoice billings are in U.S. dollars and
40% are in the local currency, the bolivar. The significance of this arrangement is that even though the dollar-based 
invoices may be paid in bolivars, the Company, historically, has usually been able to convert the bolivars into U.S. dollars
in a timely manner and thus avoid, in large measure, devaluation losses pertaining to the dollar-based invoices. However,
this arrangement is effective only in the absence of exchange controls. In January 2003, the Venezuelan government put
into effect exchange controls that fixed the exchange rate and also prohibited the Company, as well as other companies,
from converting the bolivar into U.S. dollars through the Central Bank.

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 in October of 2003,
submitted a request to the Venezuelan government seeking permission to dividend earnings, which would convert 14 
billion bolivars into U.S. dollars. In January 2004, the Venezuelan government approved the Company’s request to convert
bolivar cash balances to U.S. dollars and allowed the remittance of $8.8 million U.S. dollars as dividends to the U.S.
based parent. As a consequence, the Company’s exposure to currency devaluation was reduced by this amount.

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. As a result of the 20 percent devaluation of the bolivar during fiscal 2004, the Company
experienced total devaluation losses of $1.9 million during that same period. 

These devaluation losses may not be reflective of the actual potential for future devaluation losses because of the exchange 
controls that are currently in place. There have been recent press reports of a potential devaluation in calendar 2005. However,
the amount and exact timing of such devaluation is uncertain. While the Company is unable to predict future devaluation in
Venezuela, if fiscal 2005 activity levels are similar to fiscal 2004 and if a ten percent to twenty percent devaluation were to occur,
the Company could experience potential currency devaluation losses ranging from approximately $1.2 million to $2.3 million.

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 again receive these payments in bolivars and thus increase bolivar cash balances and exposure to devaluation.

7. Governmental Instability in Venezuela

Governmental instability continues to exist in Venezuela. 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.

During the mid-1970s, the Venezuelan government nationalized the exploration and production business. At the present
time it appears the Venezuelan government will not nationalize the contract drilling business. Any such nationalization
could result in the Company’s loss of all or a portion of its assets and business in Venezuela.

8. Government Regulation and Environmental Risks

Many aspects of the Company’s operations are subject to government regulation, including those relating to drilling practices
and methods and the level of taxation. In addition, the United States and various other countries have environmental 

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 12

regulations which affect drilling operations. Drilling contractors may be liable for damages resulting from pollution. Under United
States regulations, drilling contractors must establish financial responsibility to cover potential liability for pollution of offshore
waters. Generally, the Company is indemnified under drilling contracts from liability arising from pollution, except in certain
cases of surface pollution. However, the enforceability of indemnification provisions in foreign countries may be questionable.

The Company believes that it is in substantial compliance with all legislation and regulations affecting its operations in the
drilling of oil and gas wells and in controlling the discharge of wastes. To date, compliance has not materially affected the
capital expenditures, earnings, or competitive position of the Company, although these measures may add to the costs of
drilling operations. Additional legislation or regulation may reasonably be anticipated, and the effect thereof on operations
cannot be predicted.

9. Interest Rate Risk

In 2002, the Company entered into a $200 million intermediate-term unsecured debt obligation with staged maturities
from five to 12 years with varying fixed interest rates for each maturity series. There was $200 million outstanding at
September 30, 2004, of which $25 million is due in 2007 and the remaining $175 million is due 2009 through 2014.
The average interest rate during the next four years on this debt is 6.3%, after which it increases to 6.4%. The fair value
of this debt at September 30, 2004 was approximately $216.4 million.

At September 30, 2004, the Company had in place a committed unsecured line of credit totaling $50 million with no 
outstanding borrowings. The Company, as of September 30, 2004, had letters of credit totaling $13 million outstanding
against such line of credit. The Company’s line of credit interest rate is based on LIBOR plus 87 to 112.5 basis points or
prime minus 1.75 to 1.50 basis points based on the Company’s EBITDA to net debt ratio. As the Company draws on this
line of credit, it is subject to the interest rates prevailing during the term at which the Company had outstanding borrow-
ings. Although market interest rates were at historical lows during fiscal year 2004, interest rates could rise for various rea-
sons in the future and increase the Company’s total interest expense, depending upon the amount borrowed against the
credit line.

10. Equity Price Risk

At September 30, 2004, the Company owned stocks in other publicly held companies with a total market value of
$240.7 million. These securities are subject to a wide variety 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 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 sec-
tion of its balance sheet. Any reduction in market value would have an impact on the Company’s debt ratio and financial
strength. In October 2004, the Company sold 1,000,000 shares of its position in Atwood Oceanics, Inc. as part of a
2,175,000 share public offering by Atwood. The sale generated approximately $16.5 million ($0.32 per diluted share) of
net income for the first quarter of fiscal 2005. The Company owns 2,000,000 shares of Atwood after the sale.

11. Reliance on Small Number of Customers

In fiscal 2004, the Company received approximately 56 percent of its consolidated revenues from the Company’s ten largest
contract drilling customers and approximately 30 percent of its consolidated revenues from the Company’s three largest 
customers (including their affiliates). The Company believes that its relationship with all of these customers is good; however,
the loss of one or more of its larger customers would have a material adverse effect on the Company’s results of operations.

12. Key Personnel

The Company utilizes highly skilled personnel in operating and supporting its businesses. In times of high utilization, it can
be difficult to find qualified individuals. Although to date the Company’s operations have not been materially affected by
competition for personnel, an inability to obtain a sufficient number of qualified personnel could materially impact the
Company’s results of operations.

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13. Changes in Technologies

Although the Company takes measures to ensure that it uses advanced oil and natural gas drilling technology, changes in 
technology or improvements in competitors’ equipment could make the Company’s equipment less competitive or require 
significant capital investments to keep its equipment competitive.

14. Concentration of Credit

The concentration of the Company’s customers in the energy industry could cause them to be similarly affected by
changes in industry conditions and, as a result, could impact the Company’s exposure to credit risk. The Company 
cannot offer assurances that losses due to uncollectible receivables will be consistent with expectation.

I T E M   2 .   P R O P E R T I E S

C O N T R A C T   D R I L L I N G

The following table sets forth certain information concerning the Company’s U.S. drilling rigs as of September 30, 2004:

Location

FLEXRIGS

Texas

Texas

Texas

Texas

Texas

Wyoming

Wyoming

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Oklahoma

Texas

Texas

Texas

Texas

Texas

Colorado

Texas

Texas

Oklahoma

Texas

Texas

Louisiana

Oklahoma

Rig

164

165

166

169

178

179

180

181

182

183

184

185

186

187

188

189

210

211

212

213

214

215

216

217

218

219

220

221

222

Optimum Depth 

Rig Type

Drawworks:
Horsepower

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

10

SCR (FlexRig1)

SCR (FlexRig1)

SCR (FlexRig1)

SCR (FlexRig1)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

SCR (FlexRig2)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 14

Location

Texas

Texas

Oklahoma

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Colorado

Texas

Wyoming

HIGHLY MOBILE RIGS

Oklahoma

Texas

Wyoming

Oklahoma

Texas

Oklahoma

Texas

Texas

Wyoming

Texas

Wyoming

CONVENTIONAL RIGS

Texas

Oklahoma

Texas

Oklahoma

Texas

Texas

Louisiana

Oklahoma

Texas

Oklahoma

Texas

Rig

223

224

225

226

227

228

229

230

231

232

233

234

235

236

237

238

239

240

241

158

156

159

141

142

143

145

155

146

147

154

110

96

118

119

120

162

79

80

89

92

94

Optimum Depth 

Rig Type

Drawworks:
Horsepower

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

18,000

10,000

12,000

12,000

14,000

14,000

14,000

14,000

14,000

16,000

16,000

16,000

12,000

16,000

16,000

16,000

16,000

18,000

20,000

20,000

20,000

20,000

20,000

11

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

AC (FlexRig3)

SCR

Mechanical

Mechanical

Mechanical

Mechanical

Mechanical

Mechanical

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

1,500

900

1,200

1,200

1,200

1,200

1,200

1,200

1,200

1,200

1,200

1,500

700

1,000

1,200

1,200

1,200

1,500

2,000

1,500

1,500

1,500

1,500

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 15

Location

Oklahoma

Texas

Oklahoma

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Texas

Louisiana

Texas

Louisiana

Louisiana

Texas

Rig

98

122

97

99

137

149

191

192

72

73

125

134

136

157

161

163

139

OFFSHORE PLATFORM RIGS

Louisiana

Louisiana

Gulf of Mexico

Louisiana

Gulf of Mexico

Louisiana

Louisiana

Louisiana

Gulf of Mexico

Gulf of Mexico

Gulf of Mexico

91

203

205

206

100

105

106

107

201

202

204

Optimum Depth 

Rig Type

Drawworks:
Horsepower

20,000

16,000

20,000

26,000

26,000

26,000

26,000

26,000

30,000

30,000

30,000

30,000

30,000

30,000

30,000

30,000

30,000+

20,000

20,000

20,000

20,000

30,000

30,000

30,000

30,000

30,000

30,000

30,000

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

Conventional

Self-Erecting

Tension-leg

Self-Erecting

Conventional

Conventional

Conventional

Conventional

Tension-leg

Tension-leg

Tension-leg

1,500

1,700

2,000

2,000

2,000

2,000

2,000

2,000

3,000

3,000

3,000

3,000

3,000

3,000

3,000

3,000

3,000

3,000

2,500

2,000

1,500

3,000

3,000

3,000

3,000

3,000

3,000

3,000

The following table sets forth information with respect to the utilization of the Company’s U.S. land drilling rigs for the 

periods indicated:

Years ended September 30,

Number of rigs owned at end of period

Average rig utilization rate during period*

2000

38

85%

2001

49

97%

2002

66

84%

2003

83

81%

2004

87

87%

*A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 16

The following table sets forth certain information concerning the Company’s international drilling rigs as of 
September 30, 2004: 

Location

Argentina

Bolivia*

Bolivia*

Bolivia*

Bolivia

Bolivia

Bolivia

Chad

Colombia

Colombia

Ecuador

Ecuador

Ecuador

Ecuador

Ecuador

Ecuador

Ecuador

Ecuador

Hungary

Venezuela*

Venezuela

Venezuela

Venezuela

Venezuela

Venezuela

Venezuela

Venezuela

Venezuela

Venezuela

Venezuela

Venezuela

Venezuela

Rig

177

171

172

173

123

151

175

167

133

152

22

23

132

176

121

117

138

190

168

140

148

160

113

115

116

127

128

129

135

150

174

153

Optimum Depth 

Rig Type

Draw-Works:
Horsepower

30,000

16,000

16,000

20,000

26,000

30,000+

30,000

18,000

30,000

30,000+

18,000

18,000

18,000

18,000

20,000

26,000

26,000

26,000

18,000

10,000

26,000

26,000

30,000

30,000

30,000

30,000

30,000

30,000

30,000

30,000

30,000

30,000+

SCR

Mechanical

Mechanical

Mechanical

SCR

SCR

SCR

SCR (FlexRig1)

SCR

SCR

SCR (Heli Rig)

SCR (Heli Rig)

SCR

SCR

SCR

SCR

SCR

SCR

SCR (FlexRig1)

Mechanical

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

SCR

3,000

1,000

1,000

2,000

2,100

3,000

3,000

1,500

3,000

3,000

1,700

1,500

1,500

1,500

1,700

2,500

2,500

2,000

1,500

900

2,000

2,000

3,000

3,000

3,000

3,000

3,000

3,000

3,000

3,000

3,000

3,000

*Rig was returned to the United States during November of 2004.

The following table sets forth information with respect to the utilization of the Company’s international drilling rigs for the

periods indicated:

Years ended September 30,

Number of rigs owned at end of period
Average rig utilization rate during period*†

2000

40

47%

2001

37

56%

2002

33

51%

2003

32

39%

2004

32

54%

* A rig is considered to be utilized when it is operated or being moved, assembled, or dismantled under contract.

† Does not include rigs returned to United States for major modifications and upgrades.

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R E A L   E S T A T E   O P E R A T I O N S

See Item 1. BUSINESS, pages 4 through 5 of this Report.

S T O C K   P O R T F O L I O

Information required by this item regarding the stock portfolio held by the Company may be found on page 46 of the Company’s
Annual Report under the caption, “Management’s Discussion and Analysis of Results of Operations and Financial Condition.”

I T E M   3 .   L E G A L   P R O C E E D I N G S

The Company is subject to various claims that arise in the ordinary course of its business. In the opinion of management,
the amount of ultimate liability with respect to these actions will not materially affect the financial position, results of 
operations, or liquidity of the Company. The Company is not a party to, and none of its property is subject to, any material
pending legal proceedings.

I T E M   4 .   S U B M I S S I O N   O F   M AT T E R S   T O   A   V O T E   O F  

S E C U R I T Y   H O L D E R S

None.

E X E C U T I V E   O F F I C E R S   O F   T H E   C O M P A N Y

The following table sets forth the names and ages of the Company’s executive officers, together with all positions and
offices held with the Company by such executive officers. Officers are elected to serve until the meeting of the Board of
Directors following the next Annual Meeting of Stockholders and until their successors have been elected and have 
qualified or until their earlier resignation or removal.

Douglas E. Fears, 55
Vice President and Chief Financial Officer 
since 1988

Steven R. Mackey, 53
Vice President, Secretary and General Counsel
Secretary since 1990; Vice President and 
General Counsel since 1988 

W. H. Helmerich, III, 81
Chairman of the Board
Director since 1949; Chairman of the Board 
since 1960

Hans Helmerich, 46
President and Chief Executive Officer
Director since 1987; President and Chief Executive
Officer since 1989

George S. Dotson, 63
Vice President
Director since 1990; Vice President since 1977 and
President and Chief Operating Officer of Helmerich 
& Payne International Drilling Co. since 1977

14

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 18

PART II

I T E M   5 .   M A R K E T   F O R   T H E   C O M P A N Y ’ S   C O M M O N   S T O C K  
A N D   R E L A T E D   S T O C K H O L D E R   M A T T E R S

The principal market on which the Company’s common stock is traded is the New York Stock Exchange under the symbol
“HP”. The high and low sale prices per share for the common stock for each quarterly period during the past two fiscal
years as reported in the NYSE-Composite Transaction quotations follow:

Quarter

First

Second

Third

Fourth

2003

High

Low

$  30.23

$  23.45

28.94

32.80

30.30

22.60

24.72

25.70

2004

High

Low

$  28.37

$  23.77

30.61

29.55

29.07

27.02

24.25

24.01

The Registrant paid quarterly cash dividends during the past two years as shown in the following table:

Quarter

First

Second

Third

Fourth

Paid per Share
Fiscal

Total Payment
Fiscal

2003

$0.080

0.080

0.080

0.080

2004

$0.080

0.080

0.080

0.0825

2003

2004

$4,000,982

$4,011,879

4,002,239

4,002,971

4,009,076

4,017,204

4,032,709

4,160,221

The Company paid a cash dividend of $0.0825 per share on December 1, 2004, to shareholders of record on

November 15, 2004. Payment of future dividends will depend on earnings and other factors.

As of December 3, 2004, there were 860 record holders of the Company’s common stock as listed by the 

transfer agent’s records.

S U M M A R Y   O F   A L L   E X I S T I N G   E Q U I T Y   C O M P E N S A T I O N   P L A N S

The following chart sets forth information concerning the equity compensation plans of the Company as of

September 30, 2004.

Plan Category:
Equity compensation plans

Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights

Weighted-average 
exercise price of 
outstanding options,
warrants and rights

Number of securities remaining 
available for future issuance under 
equity compensation plans (excluding
securities reflected in column (a))

(a)

(b)

(c)

approved by security holders (1)

4,456,665

$   22.028

1,157,805

Equity compensation plans not

approved by security holders (2)

Total

–
4,456,665

–
$   22.028

–
1,157,805

(1) Includes the 1990 Stock Option Plan, the 1996 Stock Incentive Plan and the 2000 Stock Incentive Plan of the Company.

(2) The Company does not maintain any equity compensation plans that have not been approved by the stockholders.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 19

I T E M   6 .   S E L E C T E D   F I N A N C I A L   D A T A

The following table summarizes selected financial information and should be read in conjunction with the Consolidated
Financial Statements and the Notes thereto and the related Management’s Discussion and Analysis of Results of Operations
and Financial Condition contained at pages 25 through 53 of the Company’s Annual Report. On September 30, 2002, the
Company spun off Cimarex Energy Co. The historical financial data for the business conducted by Cimarex Energy Co. for
2002 has been reported as discontinued operations which is not included in the five-year summary of selected financial data.

F I V E - Y E A R   S U M M A R Y   O F   S E L E C T E D   F I N A N C I A L   D A T A

2000

2001

2002

2003

2004

(in thousands except per share amounts)

Sales, operating, and other revenues 

$416,272

$542,571

$551,879

$515,284

$620,928

Asset Impairment Charge

—

—

—

—

Income from continuing operations

36,470

80,467

53,706

17,873

51,516

4,359

Income from continuing operations

per common share:

Basic

Diluted

Total assets

Long-term debt

0.74

0.73

1.61

1.58

1.08

1.07

0.36

0.35

0.09

0.09

1,200,854

1,300,121

1,227,313

1,417,770

1,406,844

50,000

50,000

100,000

200,000

200,000

Cash dividends declared per common share

0.285

0.30

0.31

0.32

0.3225

I T E M   7. M A N A G E M E N T ’ S   D I S C U S S I O N   &   A N A LY S I S   O F   R E S U LT S   O F  

O P E R AT I O N S   A N D   F I N A N C I A L   C O N D I T I O N

Information required by this item may be found on pages 25 through 53 of the Company’s Annual Report under the
caption “Management’s Discussion & Analysis of Results of Operations and Financial Condition.”

I T E M 7A.   Q U A N T I T A T I V E   A N D   Q U A L I T A T I V E   D I S C L O S U R E S   A B O U T  

M A R K E T   R I S K

Information required by this item may be found on the following pages of the Company’s Annual Report under Management’s
Discussion & Analysis of Results of Operations and Financial Condition and in Notes to Consolidated Financial Statements:

M A R K E T   R I S K

• Foreign Currency Exchange Rate Risk

• Commodity Price Risk

• Interest Rate Risk

• Equity Price Risk

P A G E

49- 51

51- 52

52- 53

53

I T E M   8.   F I N A N C I A L   S T A T E M E N T S   A N D   S U P P L E M E N T A R Y   D A T A

Information required by this item may be found on pages 55 through 82 of the Company’s Annual Report.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 20

I T E M   9.   C H A N G E S   I N   A N D   D I S A G R E E M E N T S   W I T H   A C C O U N TA N T S  

O N   A C C O U N T I N G   A N D   F I N A N C I A L   D I S C L O S U R E

None.

I T E M 9 A.   C O N T R O L S   A N D   P R O C E D U R E S

a) Evaluation of disclosure controls and procedures. As of the end of the period covered by this Annual Report on Form 10-K,
the Company’s management, under the supervision and with the participation of the Company’s Chief Executive Officer and
Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and pro-
cedures. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer believe that:

• the Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed

by the Company in the reports it files or submits under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and

• the Company’s disclosure controls and procedures operate such that important information flows to appropriate

collection and disclosure points in a timely manner and are effective to ensure that such information is 
accumulated and communicated to the Company’s management, and made known to the Company’s Chief
Executive Officer and Chief Financial Officer, particularly during the period when this Annual Report on Form 
10-K was prepared, as appropriate to allow timely decision regarding the required disclosure.

b) Changes in internal controls. There have been no changes in the Company’s internal controls over financial 
reporting during the Company’s last fiscal quarter of 2004 that have materially affected, or are reasonably likely to
materially affect, the Company’s internal control over financial reporting.

I T E M 9 B .   O T H E R   I N F O R M A T I O N

None.

PART III

I T E M   1 0 .   D I R E C T O R S   A N D   E X E C U T I V E O F F I C E R S   O F   T H E   C O M P A N Y

Information required under this item with respect to Directors and with respect to delinquent filers pursuant to Item 405 of
Regulation S-K is incorporated by reference from the Company's definitive Proxy Statement for the Annual Meeting of
Stockholders to be held March 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004.
The information required by this Item with respect to the Company’s Executive Officers appears on page 14 of this Report.

The Company has adopted a Code of Ethics for Principal Executive Officers and Senior Financial Officers. The text of such
Code is located on the Company’s website under “Investor Relations – Corporate Governance.” The Company’s Internet
address is www.hpinc.com.

I T E M   1 1 .   E X E C U T I V E   C O M P E N S A T I O N

This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of
Stockholders to be held March 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 21

I T E M   1 2 .   S E C U R I T Y   O W N E R S H I P   O F   C E R T A I N   B E N E F I C I A L   O W N E R S  
A N D   M A N A G E M E N T   A N D   R E L A T E D   S T O C K H O L D E R   M A T T E R S

This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of
Stockholders to be held March 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004.

I T E M   1 3 .   C E R T A I N   R E L A T I O N S H I P S   A N D   R E L A T E D   T R A N S A C T I O N S

This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of
Stockholders to be held March 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004.

I T E M   1 4 .   P R I N C I P A L   A C C O U N T A N T   F E E S   A N D   S E R V I C E S

This information is incorporated by reference from the Company’s definitive Proxy Statement for the Annual Meeting of
Stockholders to be held March 2, 2005, to be filed with the Commission not later than 120 days after September 30, 2004.

PART IV

I T E M   1 5 .   E X H I B I T S ,   F I N A N C I A L   S TAT E M E N T   S C H E D U L E S ,   A N D  

R E P O R T S   O N   F O R M   8 - K

a) 1. Financial Statements: The following appear in the Company’s Annual Report at the pages indicated below

and are incorporated herein by reference:

Report of Independent Auditors

Consolidated Statements of Income for the Years Ended 

September 30, 2004, 2003 and 2002

54

55

Consolidated Balance Sheets at September 30, 2004 and 2003

56-57

Consolidated Statements of Shareholders’ Equity for the Years Ended 

September 30, 2004, 2003 and 2002

Consolidated Statements of Cash Flows for the Years Ended 

September 30, 2004, 2003 and 2002

Notes to Consolidated Financial Statements

58

59

60-82

2. Financial Statement Schedules: All schedules are omitted as inapplicable or because the required information is

contained in the financial statements or included in the notes thereto.

3. Exhibits. The following documents are included as exhibits to this Form 10-K.  Exhibits incorporated by 

reference herein are duly noted as such. Unless so noted, each exhibit is filed herewith. 

3.1 Restated Certificate of Incorporation and Amendment to Restated Certificate of Incorporation of the
Company are incorporated herein by reference to Exhibit 3.1 of the Company’s Annual Report on Form 
10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221.

3.2 Amended and Restated By-Laws of the Company are incorporated herein by reference to Exhibit 3.2 of
the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter
ended March 31, 2002, SEC File No. 001-04221.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 22

4.1 Rights Agreement dated as of January 8, 1996, between the Company and The Liberty National Bank
and Trust Company of Oklahoma City, N.A. is incorporated herein by reference to the Company’s Form 8-A,
dated January 18, 1996, SEC File No. 001-04221.

*10.1 Consulting Services Agreement between W. H. Helmerich, III, and the Company effective January 1,
1990, is incorporated herein by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K to
the Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221.

*10.2 Supplemental Retirement Income Plan for Salaried Employees of Helmerich & Payne, Inc. is 
incorporated herein by reference to Exhibit 10.6 of the Company’s Annual Report on Form 10-K to the
Securities and Exchange Commission for fiscal 1996, SEC File No. 001-04221.

*10.3 Helmerich & Payne, Inc. 1990 Stock Option Plan is incorporated herein by reference to Exhibit 10.7 of the
Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal 1996, SEC File No.
001-04221.

*10.4 Form of Nonqualified Stock Option Agreement for the 1990 Stock Option Plan is incorporated by reference
to Exhibit 99.2 to the Company’s Registration Statement No. 33-55239 on Form S-8, dated August 26, 1994.

*10.5 Supplemental Savings Plan for Salaried Employees of Helmerich and Payne, Inc. is incorporated herein
by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K to the Securities and Exchange
Commission for fiscal 1999, SEC File No. 001-04221.

*10.6 Helmerich & Payne, Inc. 1996 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1
to the Company’s Registration Statement No. 333-34939 on Form S-8 dated September 4, 1997.

*10.7 Form of Nonqualified Stock Option Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan
is incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement No. 333-34939 on Form
S-8 dated September 4, 1997.

*10.8 Form of Restricted Stock Agreement for the Helmerich & Payne, Inc. 1996 Stock Incentive Plan is
incorporated by reference to Exhibit 10.12 to the Company’s Annual Report on Form 10-K to the Securities
and Exchange Commission for fiscal 1997, SEC File No. 001-04221.

*10.9 Helmerich & Payne, Inc. 2000 Stock Incentive Plan is incorporated herein by reference to Exhibit 99.1
to the Company’s Registration Statement No. 333-63124 on Form S-8 dated June 15, 2001.

*10.10 Form of Agreements for Helmerich & Payne, Inc. 2000 Stock Incentive Plan being (i) Restricted Stock
Award Agreement, (ii) Incentive Stock Option Agreement and (iii) Nonqualified Stock Option Agreement are
incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement No. 333-63124 on Form
S-8 dated June 15, 2001.

*10.11 Form of Director Nonqualified Stock Option Agreement for the 2000 Helmerich & Payne, Inc. Stock
Incentive Plan is incorporated herein by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q
to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.

*10.12 Form of Change of Control Agreement for Helmerich & Payne, Inc. is incorporated herein by reference
to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission
for the quarter ended June 30, 2002, SEC File No. 001-04221. 

10.13 Second Amendment to Credit Agreement, dated as of July 16, 2002, by and among Helmerich & Payne
International Drilling Co., Helmerich & Payne, Inc. and Bank One, Oklahoma, N.A. is incorporated herein by 
reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q to the Securities and Exchange
Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 23

10.14 Credit Agreement, dated as of July 16, 2002, among Helmerich & Payne International Drilling Co.,
Helmerich & Payne, Inc., the several lenders from time to time party thereto, and Bank of Oklahoma, National
Association is incorporated herein by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q
to the Securities and Exchange Commission for the quarter ended June 30, 2002, SEC File No. 001-04221.

10.15 Note Purchase Agreement dated as of August 15, 2002, among Helmerich & Payne International Drilling
Co., Helmerich & Payne, Inc. and various insurance companies is incorporated herein by reference to Exhibit
10.20 of the Company’s Annual Report on Form 10-K to the Securities and Exchange Commission for fiscal
2002, SEC File No. 001-04221.

10.16 Office Lease dated May 30, 2003, between K/B Fund IV and Helmerich & Payne, Inc. is incorporated
herein by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K to the Securities and
Exchange Commission for fiscal 2003, SEC File No. 001-04221.

*10.17 Helmerich & Payne, Inc. Director Deferred Compensation Plan is incorporated herein by reference to
Exhibit 10.1 of the Company’s Form 8-K filed on September 9, 2004.

10.18 Shareholders Agreement and Registration Rights Agreement dated July 19, 2004 between Helmerich &
Payne International Drilling Co. and Atwood Oceanics, Inc. is incorporated herein by reference to Exhibit 1.1 of
the Company’s Amended Schedule 13D filed on July 21, 2004.

10.19 Underwriting Agreement dated October 13, 2004, between Helmerich & Payne International Drilling
Co. and various underwriters is incorporated herein by reference to Exhibit 1.1 of the Company’s Form 8-K
filed on October 14, 2004.

*10.20 Helmerich & Payne, Inc. Annual Bonus Plan for Executive Officers is incorporated herein by reference
to Exhibit 10.1 of the Company’s Form 8-K filed on December 6, 2004.

13. The Company’s Annual Report to Shareholders for fiscal 2004.

21. List of Subsidiaries of the Company is incorporated herein by reference to Exhibit 21 of the Company’s Annual
Report on Form 10-K to the Securities and Exchange Commission for fiscal 2003, SEC File No. 001-04221.

23.1 Consent of Independent Registered Public Accounting Firm.

31.1 Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as
Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Management or Compensatory Plan or Arrangement.

(b) Reports on Form 8-K

The Company filed two reports on Form 8-K during the last quarter of fiscal 2004 as follows:

(cid:1) Form 8-K dated July 22, 2004, containing a Press Release with attached Unaudited Consolidated Condensed
Balance Sheets, Consolidated Statements of Income and Financial Results – Lines of Business, announcing
the Company’s third quarter 2004 earnings.

(cid:1) Form 8-K dated September 2, 2004, disclosing the approval by the Company’s Board of Directors of the
Helmerich & Payne, Inc. Director Deferred Compensation Plan, to become effective October 1, 2004.

20

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 24

S I G N A T U R E S

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has
duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized:

HELMERICH & PAYNE, INC.

/s/ Hans Helmerich

By
Hans Helmerich, President and Chief Executive Officer
Date: December 13, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the
following persons on behalf of the Company and in the capacities and on the dates indicated:

/s/ William L. Armstrong

By 
William L. Armstrong, Director
Date: December 13, 2004

/s/ George S. Dotson

By 
George S. Dotson, Director
Date: December 13, 2004

/s/ W.H. Helmerich, III

By 
W. H. Helmerich, III, Director
Date: December 13, 2004

/s/ Edward B. Rust, Jr.

By 
Edward B. Rust, Jr., Director
Date: December 13, 2004

/s/ John D. Zeglis
By 
John D. Zeglis, Director
Date: December 13, 2004

/s/ Glenn A. Cox
By 
Glenn A. Cox, Director
Date: December 13, 2004

/s/ Hans Helmerich

By              
Hans Helmerich, Director and CEO
Date: December 13, 2004

/s/ L. F. Rooney, III

By               
L. F. Rooney, III, Director
Date: December 13, 2004

/s/ Paula Marshall-Chapman

By            
Paula Marshall-Chapman, Director
Date: December 13, 2004

/s/ Douglas E. Fears
/s/ Douglas E. Fears

By               
Douglas E. Fears, (Principal Financial Officer)
Date: December 13, 2004

/s/ Gordon K. Helm
By 
Gordon K. Helm, Controller
(Principal Accounting Officer)
Date: December 13, 2004

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04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 25

C E R T I F I C A T I O N

I, Hans Helmerich, certify that:

1.

I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit

to state a material fact necessary to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual

report, fairly present in all material respects the financial condition, results of operations and cash flows of the
Registrant as of, and for, the periods presented in this annual report;

4. The Registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures [as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)] for the Registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the Registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the 
period in which this annual report is being prepared;

b) evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this

annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the
end of the period covered by this annual report based on such evaluation; and

c) disclosed in this annual report any change in the Registrant’s internal control over financial reporting that

occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case
of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s
internal control over financial reporting; and

5. The Registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board
of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over 

financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process,
summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant

role in the Registrant’s internal control over financial reporting.

/s/ Hans Helmerich

Hans Helmerich, Chief Executive Officer
December 13, 2004

22

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 26

C E R T I F I C A T I O N

I, Douglas E. Fears, certify that:

1.

I have reviewed this annual report on Form 10-K of Helmerich & Payne, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit

to state a material fact necessary to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual

report, fairly present in all material respects the financial condition, results of operations and cash flows of the
Registrant as of, and for, the periods presented in this annual report;

4. The Registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures [as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)] for the Registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the Registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the 
period in which this annual report is being prepared;

b) evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this

annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the
end of the period covered by this annual report based on such evaluation; and

c) disclosed in this annual report any change in the Registrant’s internal control over financial reporting that

occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case
of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s
internal control over financial reporting; and

5. The Registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board
of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over finan-
cial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, 
summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant

role in the Registrant’s internal control over financial reporting.

/s/ Douglas E. Fears

Douglas E. Fears, Chief Financial Officer
December 13, 2004

23

04-HP-876_10K.qxd  12/15/04  2:43 PM  Page 27

Certification of CEO and CFO Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Helmerich & Payne, Inc. (the “Company”) on Form 10-K for the period
ending September 30, 2004 as filed with the Securities and Exchange Commission on the date hereof (the
“Report”), Hans Helmerich, as Chief Executive Officer of the Company, and Douglas E. Fears, as Chief Financial
Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and

result of operations of the Company.

/s/ Hans Helmerich
Hans Helmerich
Chief Executive Officer
December 13, 2004

/s/ Douglas E. Fears
Douglas E. Fears
Chief Financial Officer
December 13, 2004

24

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 24

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

R I S K   F A C T O R S   A N D   F O RWA R D - L O O K I N G   S TAT E M E N T S

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 6 of the Company’s Annual Report 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.

25

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 25

S P I N - O F F   A N D   M E R G E R   T R A N S A C T I O N S

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 has reported the results of its
former exploration and production division (Cimarex Energy Co.) as
discontinued operations.

E X E C U T I V E   S U M M A R Y

Helmerich & Payne, Inc. is a contract drilling company which owned
and operated a total of 130 drilling rigs at September 30, 2004. The
Company’s primary markets are the United States land rig business in
which the Company owned 87 rigs, the United States offshore platform
rig business in which the Company owned 11 offshore platform rigs,
and the international land rig business in which the Company owned
32 rigs at year end. Over the past year, crude oil and natural gas prices
have risen significantly as the supply and demand outlook for both
commodities have changed. Crude oil demand has improved as markets

26

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 26

like China and India, as well as the U.S., have recorded increases in
demand for crude oil due to economic growth. The U.S. natural gas
market has been promising for some time, but only recently have 
natural gas production levels and overall reserve totals for natural gas
declined to a point that there is a perceived shortage of deliverable 
natural gas to meet the prospective total demand in the U.S. Because of
these dynamics, the overall demand for drilling rig services has increased
both in the U.S. and internationally. Additionally, most offshore rig
markets have also responded positively, with the exception of the 
offshore platform rig market. Fundamental changes in the makeup of
the offshore platform rig business have negatively affected offshore 
platform rig utilization dramatically over the past two years. As a result,
while the Company’s business in its U.S. land and international sectors
improved during 2004, the offshore platform rig business declined and
suffered an operating loss for the year due to a material asset 
impairment charge in that segment.

As the Company looks to 2005, it appears that markets in both U.S.
land and international segments are in a good position to record
improved financial results. The U.S. offshore platform business does not
appear to have good probabilities for improvement, although it should
be fairly stable given the type of projects currently in place. Overall
however, Helmerich & Payne, Inc. should benefit from the prospective
improvements brought about by historical highs in commodity prices,
and the excellent financial condition of the Company.

R E S U LT S   O F   O P E R AT I O N S

All per share amounts included in the Results of Operations discussion
are stated on a diluted basis. Helmerich & Payne, Inc.’s net income for

27

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 27

2004 was $4.4 million ($0.09 per share), compared with $17.9 million
($0.35 per share) for 2003 and $63.5 million ($1.26 per share) for
2002. Included in net income was a pre-tax asset impairment charge
(discussed in detail later) of $51.5 million ($31.9 million after-tax or
$0.63 per share) in 2004 and income from discontinued operations of
$9.8 million ($0.19 per share) in 2002. Included in the Company’s net
income, but not related to its operations, were after-tax gains from the
sale of investment securities of $14.1 million($0.28 per share) in 2004,
$3.3 million ($0.07 per share) in 2003, and $15.2 million($0.30 per
share) in 2002. In addition to income from security sales, the
Company recorded net income during 2004 of $1.5 million ($0.03 per
share) from non-monetary investment gains. 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 net income of
$0.01 per share in 2004, a loss of $0.03 per share in 2003, and net
income of $0.06 per share in 2002. (See Liquidity section of MD&A
for discussion of the sale of a portion of the Company’s Atwood
Oceanic stock shortly after September 30, 2004).

Consolidated revenues were $620.9 million in 2004, $515.3 million in
2003, and $551.9 million in 2002. U.S. land revenues rose steadily
from 2002 to 2004, while U.S. offshore platform rig revenues declined
significantly during the same period. 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 86 rigs in 2004, 76 in 2003, and 57 in 2002. U.S.
land rig utilizations for the Company were 87 percent in 2004, 81 
percent in 2003, and 84 percent in 2002. Revenue reductions in the

28

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 28

offshore platform business were mainly due to a drop in rig utilization
to 48 percent in 2004, from 51 percent in 2003 and 83 percent in
2002. Late in 2003, renegotiations for additional work for two rigs
under the expiring contracts resulted in lower dayrates, thereby 
contributing to the decline in revenues. Also late in 2003, two other rigs
were moved to an active standby status which also lowered revenues,
even though those rigs remained active. International rig revenues
declined from 2002 to 2003, and rose during 2004 as rig utilizations
fell from 51 percent in 2002, to 39 percent in 2003, and then rose to
54 percent in 2004.

Revenues from investments were $27.6 million in 2004, $8.0 million in
2003, and $28.1 million in 2002. 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 $25.4 million in
2004, $5.5 million in 2003, and $24.8 million in 2002. 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 $2.0 million in 2004, $2.5 million in
2003, and $3.6 million in 2002.

Direct operating costs in 2004 were $416.6 million or 70 percent of 
operating revenues, compared with $345.5 million or 68 percent of 
operating revenues in 2003, and $361.7 million or 69 percent of operating
revenues in 2002. The 2003 expense to revenue percentage would basically
be the same as 2002 and only slightly less than 2004 except for the fact
that in the offshore platform segment in 2003 one contract had higher
than normal margins and significant early termination revenues.

29

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 29

Depreciation expense was $94.4 million in 2004, $82.5 million in
2003, and $61.4 million in 2002.  Depreciation expense increased 
significantly over the three-year period as the Company placed into
service 13 new rigs in 2002, 19 new rigs in 2003, and 5 new rigs in
2004. The Company anticipates 2005 depreciation expense to be 
consistent with 2004, unless capital expenditures rise unexpectedly.
Additional depreciation as a result of the 5 new land rigs put in 
service during 2004 and capital expenditures will be offset by the
reduction in offshore platform rig depreciation as a result of the asset
impairment charge discussed below. 

During the fourth quarter of 2004, the Company recognized a pre-
tax, non-cash asset impairment charge of $51.5 million related to its
Gulf of Mexico offshore platform rigs. During fiscal 2004, average
revenue per day for the Company’s offshore platform rigs steadily
declined from an average of $32,790 per day during the first quarter
to $28,380 during the fourth quarter. Average cash margins per rig
day declined throughout the year from $15,206 during the first 
quarter of 2004 to $11,003 during the fourth quarter. Total operating
profit for the offshore platform rig segment had averaged over $9 
million per quarter for both fiscal years 2002 and 2003, with an $8.9
million operating profit recorded for the fourth quarter of 2003.
During fiscal 2004, operating profit was $4.4 million, $4.1 million,
$3.8 million, and $4.3 million (excluding the asset impairment
charge) for the four sequential fiscal quarters as shown below.

Quarters Ended

12/31/2003

3/31/2004

6/30/2004

9/30/2004

(in thousands)

Operating profit, as reported

$    4,375

$    4,106

$    3,826

Asset impairment charge

Operating profit, excluding  

–

–

–

$  (47,180)

51,516

asset  impairment charge

$    4,375 

$    4,106 

$    3,826 

$    4,336

30

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 30

During this same three year period, industry platform rig utilization in
the Company’s market declined from 72% during the first quarter of
fiscal 2002, to 47% during the fourth quarter of fiscal 2004. During
this same period, utilization for the Company’s platform rigs fell from
100% (10 of 10) during the first quarter 2002, to a low of 42% (five of
12) during the first and second quarters of 2004. Although activity rose
slightly during the third and fourth quarters of 2004, it is expected to
drop back to five active rigs during the first quarter of 2005.

As demonstrated by these financial trends, the Company’s offshore 
platform business has continued to decline. During the first half of
2004, the Company believed that two new contracts obtained for work
that commenced during the third and fourth quarters and the increases
in commodity prices were precursors to more bidding activity in the
market. That anticipated increase in bid activity did not materialize and
bidding opportunities were very low during the third and fourth 
quarters. Additionally, oil and natural gas commodity prices reached
new historical highs during the Company’s fourth fiscal quarter, but
there was no improvement in the market for the Company’s offshore
platform rigs and no indication from customers that new opportunities
would be forthcoming in the foreseeable future.  

As a result of these events and circumstances, management performed
an analysis of the general industry market conditions in the offshore
platform rig business, and the prospective market demand for the 
offshore platform rigs owned by the Company. Based upon this 
analysis, management determined that the carrying value of certain of
the offshore rigs exceeded the estimated undiscounted future cash flows 
associated with these assets. Accordingly, an asset impairment charge

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04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 31

was recorded to reduce the carrying value of the assets to their estimated
fair value. Because quoted market prices are not available for offshore
platform rigs, the fair value was determined based upon estimated 
discounted future cash flows and rig utilization. The cash flows were
estimated by management considering factors such as prospective 
market demand, recent changes in rig technology and its effect on each
rig’s marketability, any cash investment required to make the rig 
marketable, suitability of rig size and makeup to existing platforms, and
new competitive dynamics due to lower industry utilization.

The timing of the impairment was predicated on a number of industry
and rig-specific factors that, in the opinion of management, appear to be
longer term in nature than originally expected. Future cash flow limitations
for existing rigs became more apparent as long term arrangements for a
few of the Company’s newer rigs were adjusted during the year. Also, one
of the Company’s more marketable rigs was stacked during the fourth
quarter, with no prospects for work in the foreseeable future. It was 
determined that one of the Company’s older rigs was no longer marketable
and, therefore, was written down to its salvage value and removed from the
active rig count as of September 30, 2004.

The Company also assessed its international land rig fleet because of
relatively low rig utilizations during fiscal years 2002, 2003 and 2004.
During that three year period, the Company averaged having 32 rigs
available with average annual international fleet utilizations of 51% in
2002, 39% in 2003, and 54% in 2004. Because of strong land rig
demand in the U.S., five international rigs were returned to the U.S.
during the first quarter of fiscal 2005. Activity in the international
market also improved and the Company’s active rig count in South

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04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 32

America increased during the first quarter. During October 2004, the
Company had 27 international land rigs available for service, with 23
rigs (85%) that were either active or had been committed with signed
letters of intent. Market conditions for international work have
improved substantially over the past six months. Based upon 
management’s analysis, the undiscounted estimated future cash flows 
exceeded the carrying value of our international land rigs.

General and administrative expenses totaled $37.7 million for 2004,
$41 million for 2003, and $36.6 million for 2002. The decrease in total
general and administrative expenses from 2003 to 2004 was primarily
from a reduction in pension expense due to a decrease in the benefit
accrual, reduced field training expense as the FlexRig training program
was completed, and lower salary and bonus expense. These reductions
were partially offset by increases in property, casualty and health 
insurance expenses. The increase from 2002 to 2003 was primarily the
result of increases in employee benefits relating to pension, medical
insurance, and 401(k) matching expenses. Employee salaries and 
bonuses also contributed to the increase, as well as increases in 
property and casualty insurance costs.

Interest expense was $12.7 million in 2004 and $12.3 million in
2003, compared with $1.0 million in 2002. The Company issued
$200 million 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 
beginning of fiscal year 2003. Additionally, the Company drew on its
bank line of credit during 2003, with $30 million drawn at the end of
2003. The $30 million was paid early in fiscal 2004, with no bank
loan outstanding at the end of 2004.

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The provision for income taxes totaled $4.4 million in 2004, $14.6
million in 2003, and $40.6 million in 2002. Effective income tax
rates on income from continuing operations were 55 percent in 2004,
43 percent in 2003, and 44 percent in 2002. Effective income tax
rates are higher for the Company’s international operations than for
its U.S. operations. As a result, the aggregate effective rate is higher in
years when international operations make up a higher percentage of
financial operating profit. International operating profit, as a percent
of total Company operating profit, was 68 percent in 2004, eight per-
cent in 2003, and 15 percent in 2002. (See Note 5 of the Financial
Statements).

C O M PA R I S O N   O F   T H E   Y E A R S   E N D E D   S E P T E M B E R   3 0 ,   2 0 0 4   A N D   2 0 0 3

U.S. LAND OPERATIONS

Revenues

Direct operating expenses

General and administrative expense

Depreciation

Operating profit

Operating Statistics:

Activity days

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of owned rigs at end of period

Rig utilization

2004

2003

% Change

(in thousands, except operating statistics)

$347,793

246,177 

7,765

56,528

$  37,323 

27,472

$ 11,700

$ 8,001

$ 3,699

87

87%

$273,993

201,398

9,304

44,726

$ 18,565 

22,588

$ 11,436

$ 8,221

$ 3,215

83

81%

26.9%

22.2

(16.5)

26.4

101.0

21.6%

2.3

(2.7)

15.1

4.8

7.4

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

34

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 34

The Company’s U.S. land rig operating profit increased 101.0 percent
from 2003 to 2004. This increase was due to improved rig utilization
experienced by the Company, the increased number of rigs available 
during 2004, and the improvement in average rig margins per rig day
during the year. The improved margins were a result of slightly increased
average dayrates and lower expenses per rig day experienced during
2004. The lower expense per day in 2004 was due to the elimination of
excess crew overages that occurred in 2003 in connection with placing
19 new rigs into service. During the fourth quarter of 2004, the
Company began to experience a more significant improvement in  rev-
enue and margin per day due to higher levels of U.S. land rig activity.
Although it is difficult to predict the extent of continued improvement,
it is anticipated that rig activity will continue to improve as long as
crude oil and natural gas prices remain at the historically high levels
experienced during the second half of 2004. Total number of rigs
owned at the end of 2004 as compared to 2003 increased by a net of
four rigs, resulting from five additional FlexRigs being completed 
during the year and removing from service one older conventional rig.
As a result of the new rigs put in service, and a full year of depreciation
of rigs put in service during 2003, total U.S. land rig depreciation
increased 26.4 percent from 2003 to 2004. It is anticipated that 
depreciation will increase during 2005, but at a much lower rate than 
in 2004.

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C O M PA R I S O N   O F   T H E   Y E A R S   E N D E D   S E P T E M B E R   3 0 ,   2 0 0 4   A N D   2 0 0 3

U.S. OFFSHORE OPERATIONS

Revenues

Direct operating expenses

General and administrative expense

Depreciation

Asset impairment charge

Operating profit (loss)*

Operating Statistics:

Activity days

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of owned rigs at end of period

Rig utilization

2004

2003
(in thousands, except operating statistics)

% Change

$  84,993

$112,633

52,987

3,256

12,107

51,516

60,589

2,939

12,799

–

$ (34,873)

$ 36,306

2,088

$  29,432

$  16,509

$  12,923

11

48%

2,233

$  38,239

$  17,822

$  20,417

12

51%

(24.5)%

(12.5)

10.8

(5.4)

–

(196.1)

(6.5)%

(23.0)

(7.4)

(36.7)

( 8.3)

(5.9)

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.

Operating profit in the Company’s U.S. offshore platform rig operations
fell from $36.3 million during 2003 to a loss of $34.9 million in 2004
due primarily to the asset impairment charge of $51.5 million. Excluding
the asset impairment charge, operating profit would have been $16.6 
million for 2004, which is a $19.7 million decline from 2003.

Operating profit (loss), as reported

Asset impairment charge

Operating profit, excluding

asset impairment charge

2004

$ (34.9)

51.5

$  16.6 

(in millions)

2003

$  36.3

—

$  36.3

*Note: This table is a reconciliation of operating profit (loss) for the offshore platform segment for fiscal 2004 and 2003, 

which is provided to assist with yearly comparisons.

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04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 36

Financial performance during 2004 was hindered by continued softness in
the offshore platform rig market which kept rig utilizations at an average of
48 percent for 2004. More importantly, total revenues and revenue per day
declined due to changes in the nature of contract terms on several of the
Company’s rigs. During 2003, contracts for two of the Company’s newest
rigs terminated and were renegotiated at lower dayrates just prior to the end
of the year. Additionally, two other rigs that were working at full dayrates
during 2003 were changed to standby status, thereby reducing total 
revenues and profitability. These specific transactions, coupled with an 
overall softening in the market, caused average rig revenue and margin per
rig day to decline during 2004.

C O M PA R I S O N   O F   T H E   Y E A R S   E N D E D   S E P T E M B E R   3 0 ,   2 0 0 4   A N D   2 0 0 3

INTERNATIONAL OPERATIONS

Revenues

Direct operating expenses

General and administrative expense

Depreciation

Operating profit

Operating Statistics:

Activity days

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of owned rigs at end of period

Rig utilization

2004

2003

% Change

(in thousands, except operating statistics)

$150,698

113,988

2,144

20,530

$ 14,036

6,266

$  19,884

$  14,278

$  5,606

32

54%

$109,812

81,461

3,110

20,092

$   5,149

4,515

$  19,603

$  14,140

$  5,463

32

39%

37.2%

39.9

(31.1)

2.2

172.6

38.8%

1.4

1.0

2.6

–

38.5

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

Included in international operations revenue and margin per day calculations for fiscal 2004 is an insurance gain of $1.7 
million. Without the insurance gain, the revenue per day and margin per day would have been $19,616 and $5,338, respectively.

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Operating profit for the Company’s international operations increased
172.6 percent from 2003 to 2004 due to higher rig activity, improved
margin per rig day, and lower general and administrative expense
resulting from reduced salary, bonus and travel expense. Rig activity
improved, primarily due to improved demand in the Company’s
largest international operation in Venezuela. Venezuelan operations
improved substantially as the government-owned oil company,
PDVSA, increased their spending in an attempt to improve overall
production rates following the reduction in production caused by a
workers’ strike and attempted coup in Venezuela during 2003.
Despite overall improvement of conditions in Venezuela, the currency
there was devalued during the year, resulting in a loss of $1.9 million
for 2004. (See MD&A Section on Foreign Currency Exchange Rate
Risk for more discussion.) Additionally, Company operations
improved substantially in Bolivia and Hungary. Although operations
in Chad ceased at the end of 2004, and it is anticipated that
Hungary’s operations will cease during the first half of 2005, the
Company expects that operations will improve in the Company’s
operations located in Venezuela, Colombia and Ecuador during 2005.
Late in 2004 and during the first quarter of 2005, the Company
returned to the United States five of its 32 international land rigs.
Two of the five rigs have contracts for work as of the first quarter of
2005. Three of the five rigs were scheduled to arrive during the first
quarter 2005 in the U.S. for an assessment of their viability in the
U.S. market. As a result of the improved demand for contract drilling
work in South America, and the reduction in available Company rigs,
it is anticipated that rig utilizations will improve during 2005.

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C O M PA R I S O N   O F   T H E   Y E A R S   E N D E D   S E P T E M B E R   3 0 ,   2 0 0 4   A N D   2 0 0 3

REAL ESTATE

Revenues

Direct operating expenses

Depreciation

Operating profit

2004

$ 9,842

3,347

2,253

$ 4,242

2003

(in thousands)

$ 10,893

1,789

2,535

$ 6,569

% Change

(9.6)%

87.1

(11.1)

(35.4)

Operating profit in the Company’s Real Estate division fell 35.4 percent
from 2003 to 2004, but performance of its core operations actually
improved. The reduction in operating profit was due primarily to a
decline in the profits recorded for the sale of raw land in 2004 versus
2003. While the sale of raw land has not been an ongoing component of
income in the Real Estate division, the Company recorded gains on sales
of land totaling $1.0 million and $2.7 million in 2004 and 2003, 
respectively. Direct operating expenses increased as compared to 2003 due
to demolition costs in 2004 of over $.8 million relating to the razing of
the Company’s former headquarters building, and an increase in 
advertising expense.

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C O M PA R I S O N   O F   T H E   Y E A R S   E N D E D   S E P T E M B E R   3 0 ,   2 0 0 3   A N D   2 0 0 2

U.S. LAND OPERATIONS

Revenues

Intersegment elimination

Direct operating expenses

Intersegment elimination

General and administrative expense

Depreciation

Operating profit

Operating Statistics:

Activity days

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of owned rigs at end of period

Rig utilization

2003

2002

% Change

(in thousands, except operating statistics)

$273,993

–

201,398 

–

9,304

44,726

$232,446

(809)

165,394

(648)

10,087

26,311

$  18,565 

$ 30,493

22,588

$ 11,436

$ 8,221

$ 3,215

83

81%

17,478

$ 12,397

$ 8,561

$ 3,836

66

84%

17.9%

–

21.8

–

(7.8)

70.0

(39.1)

29.2%

(7.8)

(4.0)

(16.2)

25.8

(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
39.1 percent from 2002 to 2003, despite the fact that commodity
prices were very strong during 2003. 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 2003. 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 particularly 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

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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. During
2003, 19 FlexRig3s were completed and put into service. Two first
generation FlexRigs 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.

C O M PA R I S O N   O F   T H E   Y E A R S   E N D E D   S E P T E M B E R   3 0 ,   2 0 0 3   A N D   2 0 0 2

U.S. OFFSHORE OPERATIONS

Revenues

Direct operating expenses

General and administrative expense

Depreciation

Operating profit 

Operating Statistics:

Activity days

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of owned rigs at end of period

Rig utilization

2003

2002
(in thousands, except operating statistics)

% Change

$ 112,633

$132,249

60,589

2,939

12,799

79,301

3,451

10,809

$  36,306

$ 38,688

2,233

$  38,239

$  17,822

$  20,417

12

51%

3,286

$  30,424

$  16,263

$  14,161

12

83%

(14.8)%

(23.6)

(14.8)

18.4

(6.2)

(32.0)%

25.7

9.6

44.2

–

(38.6)

Operating statistics of 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 2003, the Company experienced a reduction in activity days
and rig utilization in its U.S. offshore platform rig operations. Total
revenues and revenue per day during 2003 were aided by the 
recognition of revenue due to early termination of contracts and higher
dayrates for three rigs. 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. Capital expenditures were reduced 
dramatically due to the fact that there were no new platform rigs under

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construction during 2003, whereas two new platform rigs were 
completed during 2002.

C O M PA R I S O N   O F   T H E   Y E A R S   E N D E D   S E P T E M B E R   3 0 ,   2 0 0 3   A N D   2 0 0 2

INTERNATIONAL OPERATIONS

Revenues

Direct operating expenses

General and administrative expense

Depreciation

Operating profit

Operating Statistics:

Activity days

Average rig revenue per day

Average rig expense per day

Average rig margin per day

Number of owned rigs at end of period

Rig utilization

2003

2002

% Change

(in thousands, except operating statistics)

$109,812

81,461

3,110

20,092

$ 5,149

4,515

$  19,603

$  14,140

$  5,463

32

39%

$151,392

115,294

2,634

20,336

$ 13,128

5,956

$ 21,161

$ 14,599

$    6,562

33

51%

(27.5)%

(29.3)

18.1

(1.2)

( 60.8)

(24.2)%

(7.4)

(3.1)

(16.7)

(3.0)

(23.5)

Operating statistics of per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses,
the effects of management contracts, or the effect of currency revaluation expense.

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 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.  The
Company has currency risks in Venezuela described in detail later in
the MD&A under Foreign Currency Exchange Rate Risk.  Due to
that exposure, the Company recorded currency devaluation losses for
Venezuelan operations totaling $.6 million in 2003 and $4.4 million
in 2002.

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During 2002, the Company recorded an estimated devaluation loss
totaling $1.2 million 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
devaluation loss by approximately $1.0 million by securing
agreements with its customers that limited the portion of the accounts
receivable that was paid in pesos with the balance of such accounts
receivable paid in U.S. dollars.

C O M PA R I S O N   O F   T H E   Y E A R S   E N D E D   S E P T E M B E R   3 0 ,   2 0 0 3   A N D   2 0 0 2

Years Ended September 30,

REAL ESTATE

Revenues

Direct operating expenses

Depreciation

Operating profit 

2003

$ 9,842

3,347

2,253

$ 4,242

2002
(in thousands)

$10,893

1,789

2,535

$ 6,569

% Change

(9.6)%

87.1

(11.1)

(35.4)

Operating profit increased by 29.7 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 South Park
investment. Pre-tax profit from the sale of land was approximately $2.7
million. Depreciation expense increased in 2003 due to the acceleration
of depreciation on the Company’s headquarters building, which was
demolished in 2004. Overall combined occupancy and resulting 
revenues generated from all the other real estate properties did not 
materially fluctuate from 2002 to 2003.

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L I Q U I D I T Y   A N D   C A P I TA L   R E S O U R C E S

The Company’s capital spending for continuing operations was $89
million in 2004, $246.3 million in 2003, and $312.1 million in
2002. Net cash provided from operating activities for those same time
periods was $135.4 million in 2004, $96.5 million in 2003, and
$151.8 million in 2002. In addition to the net cash provided by 
operating activities, the Company also generated net proceeds from
the sale of portfolio securities of $30.9 million in 2004, $18.2 million
in 2003, and $47.1 million in 2002. The Company’s 2005 capital
spending estimate is $55 million, down from $89 million in 2004 due
to the completion of the FlexRig construction in March, 2004.

During 2000, the Company announced its 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 $11.0 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 were completed by March, 2004.

In August 2002, the Company entered into a $200 million 
intermediate-term unsecured debt obligation with staged maturities from
5 to 12 years and a weighted average interest rate of 6.31 percent.

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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, to help fund the Company’s rig 
construction program and for other general corporate purposes.

On September 30, 2004, the Company had a committed unsecured line
of credit totaling $50 million, with no money drawn and letters of credit
totaling $13 million outstanding against the line. The line of credit
matures in 2005 and bears interest of LIBOR plus .875 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 a minimum level of tangible net worth.

Current ratios for September 30, 2004, and 2003 were 4.1 and 2.3,
respectively. The debt to total capitalization ratio was 18 percent and 20
percent at September 30, 2004 and 2003, respectively. Additionally, the
Company manages a large portfolio of marketable securities that, at the
close of 2004, had a market value of $240.7 million. The Company’s
investments in Atwood Oceanics, Inc., and Schlumberger, Ltd., made up
almost 94 percent of the portfolio’s market value on September 30, 2004.
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. In July 2004, Atwood Oceanics,
Inc., (Atwood) the Company’s equity affiliate, filed a Registration
Statement covering all 3,000,000 shares of Atwood stock owned by H&P.

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On October 19, 2004, Atwood and Helmerich & Payne closed a public
offering in which Helmerich & Payne sold 1,000,000 Atwood shares and
received approximately $45.8 million. The Company now owns 2,000,000
shares or approximately 13.3 percent of the outstanding shares of Atwood.

During 2004, the Company paid a dividend of $.3225 per share, or a total of
$16.2 million, representing the 32nd consecutive year of  dividend increases.

S T O C K   P O R T F O L I O   H E L D   B Y   T H E   C O M PA N Y

September 30, 2004

Number of Shares

Cost Basis

Market Value

Atwood Oceanics, Inc.

Schlumberger, Ltd.

Other

Total

M AT E R I A L   C O M M I T M E N T S

3,000,000

1,230,000

( in thousands, except share amounts)

$  57,824

19,539

8,272

$ 85,635

$ 142,620

82,791

15,298

$240,709

The Company has no off balance sheet arrangements. The Company’s
contractual obligations as of September 30, 2004, are summarized in
the table below:

Payments Due By Year

Total

2005

2006

2007

2008

2009

After 2009

Long-term debt (a)

$ 200,000

$ 

–

$    –

$ 25,000

$   –

$ 25,000

$150,000

Operating leases (b)

9,929

2,542

2,261

1,844

1,412

1,408

462

Total Contractual Obligations

$209,929

$2,542

$ 2,261

$ 26,844

$1,412

$ 26,408

$150,462

( in thousands)

(a) See Note 4 “Long-term Debt” to the Company’s Consolidated Financial Statements.
(b) See Note 14 “Commitments and Contingencies” to the Company’s Consolidated Financial Statements.

The above table does not include obligations for the Company’s pension
plan, for which the recorded liability at September 30, 2004 is $19.2 million.
Based on current information available from plan actuaries, the Company
anticipates no contributions will be made in 2005. Future contributions
beyond 2005 are difficult to estimate due to multiple variables involved.

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C R I T I C A L   A C C O U N T I N G   P O L I C I E S

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, which relate 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 as incurred.
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’s management assesses the potential impairment of its
long-lived assets whenever events or changes in conditions indicate
that the carrying value of an asset may not be recoverable. Changes
that trigger such an assessment may include equipment obsolescence,
changes in the market demand for a specific asset, periods of relatively
low rig utilizations, declining revenue per rig day, declining cash mar-
gin per rig day, completion of specific contracts, and/or overall
changes in general market conditions. If a review of the long-lived
assets indicates that the carrying value of certain of these assets is more

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04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 47

than the estimated undiscounted future cash flows, an impairment
charge is made to adjust the carrying value to the estimated fair 
market value of the asset. See additional discussion of impairment
assumptions, including determination of fair value, under Results of
Operations. Use of different assumptions could result in an 
impairment charge different from that reported.

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 cir-
cumstances. 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. Nonetheless, insurance estimates include 
certain assumptions and management judgments regarding the 
frequency and severity of claims, claim development, and settlement
practices.  Unanticipated changes in these factors may produce 
materially different amounts of expense that would be reported under
these programs.

The Company’s pension benefit costs and obligations are dependent
on various actuarial assumptions. The Company makes assumptions
relating to discount rates, rate of compensation increase, and expected
return on plan assets. The Company bases its discount rate 

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04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 48

assumption on current yields on AA-rated corporate long-term bonds.
The rate of compensation increase assumption reflects actual experience
and future outlook. The expected return on plan assets is determined
based on historical portfolio results and future expectations of rates of
return. Actual results that differ from estimated assumptions are 
accumulated and amortized over the estimated future working life of 
the plan participants and could therefore affect expense recognized and 
obligations recorded in future periods.

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 con-
tracts 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. 

Q UA N T I TAT I V E   A N D   Q UA L I TAT I V E   D I S C L O S U R E S   A B O U T   M A R K E T   R I S K
Foreign Currency Exchange Rate Risk The Company has international
operations in Hungary and in several South American countries, as
well as a labor contract for work in Equatorial Guinea and Russia.
With the exception of Venezuela, the Company’s exposure to currency
valuation losses is usually minimal due to the fact that virtually all
invoice 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. 

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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 $1.2 million in 2002. The Company
was able to reduce this estimated loss by approximately $1.0 million
during 2003 by securing agreements with its customers that limited
the portion of the accounts receivable that was paid in pesos with the
balance of such accounts receivable paid in U.S. dollars. At the present
time, the Company has one rig working in Argentina.

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, approximately 60% of the Company's invoice
billings to the Venezuelan state oil company, PDVSA, are in U.S. dollars
and 40% 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 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. In January 2004, the
Venezuelan government approved the conversion of bolivar cash balances
to U.S. dollars and the remittance of $8.8 million U.S. dollars as 
dividends by the Company’s Venezuelan subsidiary to the U.S. based 
parent.  As a consequence, the Company’s exposure to currency 
devaluation was reduced by this amount.

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04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 50

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. As a result of the 20% devaluation of the bolivar during 
fiscal 2004 (from September 2003 through August 2004), the Company
experienced total devaluation losses of $1.9 million during that same 
period. This 20% devaluation loss may not be reflective of the actual
potential for future devaluation losses because of the exchange controls
that are currently in place. There have been recent press reports of a
potential devaluation in calendar 2005. However, the exact amount and
timing of such devaluation is uncertain. While the Company is unable to
predict future devaluation in Venezuela, if fiscal 2005 activity levels are
similar to fiscal 2004 and if a 10% to 20% devaluation were to occur, the
Company could experience potential currency devaluation losses ranging
from approximately $1.2 million to $2.3 million.

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 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, 

51

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 51

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. The Company currently maintains all of its
debt portfolio in fixed-rate 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.

Due to the fact that all of the Company’s debt at year-end has fixed rate
interest obligations, there is no current risk due to interest rate fluctuation.

The following tables provide information as of September 30, 2004
and 2003 about the Company’s interest rate risk sensitive instruments:

I N T E R E S T   R AT E   R I S K   (in thousands)

2005

2006

2007

2008

2009

After 
2009

Total

Fair Value
@ 9/30/04

Fixed Rate Debt

Average Interest Rate

–

–

–

–

$  25,000

5.5%

Variable Rate Debt

$ 30,000

$ –

$ 

Average Interest Rate (a)

–

–

–

–

–

–

$ –

–

$  25,000

$150,000

$200,000

$216,400

5.9%

6.5%

6.3%

$ 

–

–

$

–

–

$  30,000

$  30,000

–

(a)

(a) LIBOR plus an increment of .875 to 1.125% depending on certain financial ratios.

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04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 52

I N T E R E S T   R AT E   R I S K   (in thousands)

2004

2005

2006

2007

2008

After 
2008

Total

Fair Value
@ 9/30/03

Fixed Rate Debt

Average Interest Rate

$    –

–

$ –

–

Variable Rate Debt

$ 30,000

$ –

Average Interest Rate (a)

–

–

$ –

–

$ –

–

$ 25,000

$ –

$175,000

$ 200,000

$ 226,500

5.5%

$     –

–

–

$ –

–

6.4%

6.3%

$    –

$  30,000

$   30,000

–

(a)

(a) LIBOR plus an increment of .875 to 1.125% depending on certain financial ratios.

Equity Price Risk. On September 30, 2004, the Company owned stocks in other
publicly held companies with a total market value of $240.7 million. The
Company’s investments in Atwood Oceanics, Inc., and Schlumberger, Ltd., made
up almost 94 percent of the portfolio’s market value at September 30, 2004.
Although the Company sold a portion of its position in Schlumber in 2004 and
Atwood in the first quarter of 2005, the Company has no specific plans to sell
additional securities, but may sell additional securities based on market conditions
and other circumstances. 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 $169.5 million at September 30, 2003.

53

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Report of Independent 
Registered Public Accounting Firm

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, 2004 and 2003, and the related consolidated statements of income, shareholders’

equity, and cash flows for each of the three years in the period ended September 30, 2004.  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 the standards of the Public Company Accounting

Oversight Board (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, 2004 and 2003, and

the consolidated results of its operations and its cash flows for each of the three years in the period

ended September 30, 2004, in conformity with U.S. generally accepted accounting principles.

E R N S T   &   Y O U N G   L L P

Tulsa, Oklahoma
November 23, 2004

54

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Consolidated Statements of Income

Years Ended September 30,

2004

2003

2002

REVENUES

Operating revenues

Income from investments

COSTS AND EXPENSES

Direct operating costs

Depreciation

Asset impairment charge

General and administrative

Interest

(in thousands, except per share amounts)

$593,326

$507,331

$523,803

27,602

7,953

28,076

620,928

515,284

551,879

416,631

345,537

361,669

94,425

51,516

37,661

12,695

82,513

61,447

–

41,003

12,289

–

36,563

980

612,928

481,342

460,659

Income from continuing operations before income

taxes and equity in income (loss) of affiliates

8,000

33,942

91,220

Provision for income taxes

Equity in income (loss) of affiliates

net of income taxes

Income from continuing operations

Income from discontinued operations

4,365

14,649

40,573

724

( 1,420)

3,059

4,359

17,873

53,706

–

–

9,811

NET INCOME

$

4,359

$  17,873

$  63,517

Basic earnings per common share:

Income from continuing operations

Income from discontinued operations

Net income

Diluted earnings per common share: 

Income from continuing operations

Income from discontinued operations

Net income

$    0.09

$    0.36

$   1.08

–

–

0.19

$    0.09 

$

0.36  $   1.27

$    0.09

$    0.35

$   1.07

–

–

0.19

$    0.09

$    0.35  $   1.26

Average common shares outstanding (in thousands):

Basic

Diluted

50,312

50,833

50,039

50,596

49,825

50,345

The accompanying notes are an integral part of these statements. 

55

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Consolidated Balance Sheets

ASSETS

CURRENT ASSETS:      

September 30, 

2004

2003  

(in thousands)

Cash and cash equivalents

$ 65,296

$

38,189

Accounts receivable, less reserve of $1,265 in 2004 and $1,319 in 2003

Inventories 

Deferred income taxes

Prepaid expenses and other

Total current assets 

133,262

20,826

4,346

22,156

91,088

22,533

1,935

45,721

245,886

199,466

INVESTMENTS 

161,532

158,770

PROPERTY, PLANT AND EQUIPMENT, at cost:    

Contract drilling equipment 

Construction in progress 

Real estate properties 

Other 

Less-accumulated depreciation and amortization 

Net property, plant and equipment 

OTHER ASSETS 

TOTAL ASSETS

The accompanying notes are an integral part of these statements.

1,531,937

1,490,389

1,228

56,307

93,640

45,004

56,247

87,570

1,683,112

1,679,210

684,438

998,674

621,005

1,058,205

752

1,329

$1,406,844

$1,417,770

56

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LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30,

2004

2003

(in thousands, except share data)

$   —

$  30,000

CURRENT LIABILITIES:

Notes payable 

Accounts payable 

Accrued liabilities 

Total current liabilities

NONCURRENT LIABILITIES:

Long-term notes payable 

Deferred income taxes 

Other 

Total noncurrent liabilities 

SHAREHOLDERS’ EQUITY:

28,012

31,891

59,903

200,000

194,573

38,258

432,831

5,353

—

85,466

828,763

—

36,252

955,834

41,724

914,110

29,630

28,988

88,618

200,000

183,672

28,229

411,901

5,353

—

83,302 

840,776

(10)

33,668

963,089 

45,838

917,251

Common stock, $.10 par value, 80,000,000 shares authorized,

53,528,952 shares issued 

Preferred stock, no par value, 1,000,000 shares authorized, no shares issued

Additional paid-in capital 

Retained earnings 

Unearned compensation

Accumulated other comprehensive income

Less treasury stock, 3,083,516 shares in 2004 and 

3,388,588 shares in 2003, at cost 

Total shareholders’ equity 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

$1,406,844

$1,417,770

The accompanying notes are an integral part of these statements.

September 30,         2002 2001

2000

57

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Consolidated Statements of Shareholders’ Equity

Common Stock
Shares      Amount

Additional
Paid-in
Capital

Unearned
Compensation

Retained
Earnings

Treasury Stock

Shares    

Amount

(in thousands, except per share amounts) 

Accumulated
Other
Comprehensive 
Income (Loss)

Total

Balance, September 30, 2001

53,529

$5,353

$80,324

$(1,812)

$943,105

3,676

$(49,802)

$49,309

$1,026,477

Comprehensive Income:

Net Income
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
Cash dividends ($.31 per share)
Exercise of stock options
Forfeiture of Restricted Stock Award
Tax benefit of stock-based awards
Amortization of deferred 

compensation

1,099
88
978

Balance, September 30, 2002

53,529

5,353

82,489

Balance, September 30, 2003

53,529

5,353

83,302

Comprehensive Income:

Net Income
Other comprehensive income: 
Unrealized gains on available-

for-sale securities, net 

Derivatives instruments amort., net
Minimum pension liability adjustment, net

Total other comprehensive gain

Total comprehensive income
Cash dividends ($.32 per share)
Exercise of stock options
Tax benefit of stock-based awards
Amortization of deferred 

compensation

Comprehensive Income:

Net Income
Other comprehensive income (loss): 

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 ($.3225 per share)
Exercise of stock options
Tax benefit of stock-based awards
Amortization of deferred 

compensation

63,517

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

156

1,466
(190)

(152,201)
(15,492)

(181)
23

2,455
(244)

838,929

3,518

(47,591)

16,180

17,873

15,005
982
1,501

441
372

(16,026)

(129)

1,753

180
(10)

840,776

3,389

(45,838)

33,668

4,359

3,721
72
(1,209)

(16,372)

(305)

4,114

813
1,351

10

63,517

(25,449)
(68)
(7,612)
(33,129)
30,388
(152,201)
(15,492)
3,554

978

1,466
895,170

17,873

15,005
982
1,501
17,488
35,361
(16,026)
2,194
372

180
917,251

4,359

3,721
72
(1,209)
2,584
6,943
(16,372)
4,927
1,351

10

Balance, September 30, 2004

53,529

$5,353

$85,466

$

–

$828,763

3,084

$(41,724)

$ 36,252

$ 914,110

The accompanying notes are an integral part of these statements. 

58

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Consolidated Statements of Cash Flows

Years Ended September 30,

2004

2003
(in thousands)

2002

OPERATING ACTIVITIES:

Income from continuing operations
Adjustments to reconcile income from continuing

operations to net cash provided by operating activities:

Depreciation
Asset impairment charge
Equity in (income) loss of affiliates before income taxes
Amortization of deferred compensation
Gain on sales of securities
Non-monetary investment (gain) loss
Gain on sale of property, plant and equipment
Deferred income tax expense
Other – net
Change in assets and liabilities:

Accounts receivable
Inventories
Prepaid expenses and other
Accounts payable
Accrued liabilities
Deferred income taxes
Other noncurrent liabilities

Net cash provided by operating activities

INVESTING ACTIVITIES:
Capital expenditures
Proceeds from sale of property, plant and equipment
Purchase of investments
Proceeds from sale of securities

Net cash used in investing activities

FINANCING ACTIVITIES:

Proceeds from long-term debt
Payments on long-term debt
(Decrease) increase in short-term notes
Dividends paid
Proceeds from exercise of stock options

Net cash provided by (used in) financing activities

DISCONTINUED OPERATIONS:

Net cash provided by operating activities
Net cash (used in) investing activities
Cash of discontinued operations at spinoff

Net cash used in discontinued operations

Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period

The accompanying notes are an integral part of these statements.

59

$ 4,359

$ 17,873

$  53,706 

94,425
51,516

(1,168)
10
(22,766)
(2,521)
(5,377)
5,934
(98)

(25,335)
1,707
24,142
(1,618)
2,870
2,323
6,997
131,041
135,400

(88,972)
7,941
—
14,033
(66,998)

—
—

(30,000)
(16,222)
4,927
(41,295)

—
—
—
—

82,513
—
2,290
180
(5,529)
—
(3,689)
41,391
336

1,516
251
(29,355)
(11,415)
(1,281)
(166)
1,589
78,631
96,504

(246,301)
6,720
—
18,215
(221,366)

100,000
—
30,000
(16,026)
2,194
116,168

—
—
—
—

61,447
—
(5,014)
1,122
(25,551)
1,204
(1,392)
21,147
791

24,148
1,042 
24,381 
(3,769)
955 
2,986 
(5,429) 
98,068 
151,774 

(312,064)
4,135
(5,656)
47,146
(266,439)

100,000
(50,000)
—
(15,221)
3,554
38,333

62,792
(55,232)
(13,171)
(5,611)

27,107
38,189
$ 65,296

(8,694)
46,883
$ 38,189

(81,943)
128,826
$ 46,883

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 59

Notes to Consolidated Financial Statements

NOTE 1  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

September 30, 2004, 2003 and 2002

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Helmerich & Payne, Inc. (the Company), and 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 con-

tinuing operations of the Company (see Note 2).

Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified

to conform to current year presentation.

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 $(2.2) million, $.4 million, and $(5.5) million, for 2004, 2003, and

2002, 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.

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 2004, 2003,

and 2002 was $.5 million, $1.8 million, and $2.5 million, respectively.

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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.

CASH AND CASH EQUIVALENTS

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which mature

within three months from the date of purchase.

INVENTORIES AND SUPPLIES

Inventories and supplies are primarily replacement parts and supplies held for use in our drilling operations.

Inventories 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. The Company recognizes reimbursements received for out-of-pocket expenses incurred

as revenues and accounts for out-of-pocket expenses as direct costs.

RENT REVENUES

The Company enters into leases with tenants in its rental properties consisting primarily of retail and multi-tenant

warehouse space. The lease terms of tenants occupying space in the retail centers and warehouse buildings range

from one to ten years. Minimum rents are recognized on a straight-line basis over the term of the related leases.

Overage and percentage rents are based on tenants’ sales volume. The Company’s rent revenues are as follows:

Years ended September 30,

Minimum rents

Overage and percentage rents 

2004

$    7,490

$    1,207 

2003
(in thousands)

$    7,333 

$       768

2002

$    6,980 

$       915

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At September 30, 2004, minimum future rental income to be received on noncancelable operating leases

were as follows (in thousands):

Fiscal Year

2005

2006 

2007

2008

2009

Thereafter

Total 

Amount

$   6,525

5,654 

5,103 

4,092

3,175

7,765

$ 32,314

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 2004 includes approximately $1.5 million, $0.03 per share on a diluted

basis, on gains related to non-monetary transactions within the Company’s available-for-sale investment 

portfolio which were accounted for at fair value. Net income in 2002 includes a loss of approximately $0.5

million, $0.01 per share on a diluted basis, resulting from the Company’s assessment that the decline in 

market value of certain available-for-sale securities below their financial cost basis was other than temporary.

There were no losses in 2004 and 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 percent of Atwood Oceanics, Inc. (Atwood) at both September 30, 2004 and 2003. The

quoted market value of the Company's investment was $142.6 million and $72 million at September 30, 2004

and 2003, respectively. Retained earnings at September 30, 2004 and 2003 includes approximately $29 million

and $28 million, respectively, of undistributed earnings of Atwood.

In October 2004, the Company sold 1,000,000 shares of its position in Atwood as part of a 2,175,000 share

public offering of Atwood. The sale generated approximately $16.5 million ($0.32 per diluted share) of net
income for the first quarter of fiscal 2005. With its remaining 2,000,000 shares of Atwood, the Company will

own approximately 13.3 percent of Atwood. The Company will continue to account for Atwood on the equity

method as the Company continues to have significant influence through its board of director seats.

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Summarized financial information of Atwood is as follows:

September 30,

Gross revenues

Costs and expenses 

Net income (loss)

Helmerich & Payne, Inc.’s equity in 

2003

$ 163,454

155,867 

$

7,587 

2002
(in thousands)

$ 144,766 

157,568

$ (12,802) 

2001

$ 149,157 

120,872

$  28,285

net income (loss), net of income taxes

$  

724

$   (1,414)

$    4,206

Current assets 

Noncurrent assets 

Current liabilities 

Noncurrent liabilities 

Shareholders’ equity 

$   92,966 

$   72,182 

$   71,813

405,970 

60,053 

167,294 

271,589 

447,464

40,504 

215,757 

263,385 

372,717

24,416 

143,981

276,133

Helmerich & Payne, Inc.’s investment

$   57,824 

$   56,655 

$   58,937

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 worker’s 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 6. 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.”

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September 30,

2004

2003
(in thousands, except per share amounts)

2002

Net income, as reported 

$   4,359

$ 17,873 

$ 63,517

Add: Stock-based employee compensation 

expense included in the Consolidated Statements 

of Income, net of related tax effects

6

112

909

Deduct: Total stock based employee compensation 

expense determined under fair value based 

method for all awards, net of related tax effects

(4,172)

( 4,387)

( 3,354)

Pro forma net income 

$     193

$ 13,598 

$ 61,072

Earnings per share:

Basic-as reported

Basic-pro forma

Diluted-as reported

Diluted-pro forma

$    0.09

$    0.00

$    0.09 

$    0.00 

$    0.36 

$    0.27 

$    0.35 

$    0.27 

$    1.27

$    1.23

$    1.26

$    1.21

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 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.

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 past and future periods, including all taxes arising from the Cimarex

business prior to the time Cimarex was formed, and agrees to hold the Company harmless in respect of those

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04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 64

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 year ended September 30, 2002 is as follows:

September 30,

Revenues

Income from operations:

Income before income taxes

Tax provision

Income from discontinued operations

2002
(in thousands)

$172,827

15,138

5,327

$   9,811

NOTE 3  IMPAIRMENT OF LONG-LIVED ASSETS

The Company periodically evaluates long-lived assets when events or circumstances indicate, in management’s

judgment, that the carrying value of such assets may not be recoverable. Changes that could trigger such an

assessment may include a significant decline in revenue or cash margin per day, extended periods of low rig

utilization, changes in market demand for a specific asset, obsolescence, completion of specific contracts,

and/or overall general market conditions. If a review of the long-lived assets indicates that the carrying value of

certain of these assets is more than the estimated undiscounted future cash flows, an impairment charge is

made to adjust the carrying value to the estimated fair market value of the asset.

In evaluating the Company’s U.S. Offshore Platform business in the Gulf of Mexico, indicators of impairment

were present, including declines in revenue and margin per day, industry and Company platform rig utilization,

and bid activity. As the result of the declining financial trends and the generally unfavorable market conditions in

the Gulf of Mexico, management completed an analysis of the general market conditions in the offshore platform

rig business and the prospective market demand for each of the 12 offshore rigs owned by the Company.
Based on this analysis, management determined that the carrying value of certain offshore rigs exceeded the

estimated undiscounted future cash flows associated with these assets; therefore, an impairment charge was

required. The amount of the impairment charge represented the difference between the estimated fair value of

the asset and its carrying value. Because quoted market prices are not available for offshore platform rigs, the

fair value was determined based on estimated discounted future cash flows and rig utilization. Cash flows were

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estimated by management considering factors such as prospective market demand, recent changes in technol-

ogy and its effect on each rig’s marketability and cash investment required, suitability of rig size and makeup to

existing platforms, and new competitive dynamics due to lower industry utilization.

Based on its analysis, the Company recorded a $51.5 million pre-tax impairment charge to the Offshore Platform

segment in the fourth quarter of fiscal 2004. In conjunction with the impairment charge, the Company retired rig 108

at September 30, 2004, which brings the number of available platform rigs to eleven. The Company also reduced

the depreciable lives of five platform rigs to four years and the salvage value of each of the offshore rigs to $1.0 

million. As a result of the impairment charge and the change in depreciable lives and salvage values, depreciation

expense in future years in the Offshore Platform segment will be reduced by approximately $2.0 million a year.

NOTE 4  NOTES PAYABLE AND LONG-TERM DEBT

At September 30, 2004, the Company had $200 million in long-term debt outstanding at fixed rates and 

maturities as summarized in the following table.

(In thousands)

Issue Amount

$ 25,000

$ 25,000

$ 75,000

$ 75,000

Maturity Date

August 15, 2007

August 15, 2009

August 15, 2012

August 15, 2014

Interest Rate

5.51%

5.91%

6.46%

6.56%

The terms of the debt obligations require the Company to maintain a minimum ratio of debt to total capitaliza-

tion. The proceeds of the debt issuances were used to repay $50 million of outstanding debt, to fund the

Company’s rig construction program and for other general corporate purposes. This debt is held by various

entities including $8.0 million held by a company affiliated with one of the Company’s Board members.

At September 30, 2004, the Company had a committed unsecured line of credit totaling $50 million. Letters 

of credit totaling $13 million were outstanding against the line, leaving $37 million available to borrow. Under

terms of the line of credit, the Company must maintain certain financial ratios including debt to total capitaliza-

tion and debt to earnings before interest, taxes, depreciation, and amortization, and maintain certain levels of

liquidity and tangible net worth. The interest rate varies based on LIBOR plus .875 to 1.125 percent or prime
minus 1.75 percent to prime minus 1.50 percent depending on ratios described above. 

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NOTE 5 INCOME TAXES 

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

Years Ended September 30,

2004 

2003 
(In thousands)

2002

CURRENT:

Federal

Foreign 

State 

DEFERRED:   

Federal 

Foreign 

State 

$ 

(5,997)

$  (34,495)

$  13,324 

4,622

(194)

(1,569)

4,037

1,902

(5)

5,934

6,870 

883 

(26,742) 

42,835 

(3,383) 

1,939 

41,391 

5,080 

1,022 

19,426 

16,019 

3,732 

1,396 

21,147 

TOTAL PROVISION: 

$    4,365

$ 14,649 

$ 40,573 

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

Years Ended September 30,

2004 

Income (loss) from continuing operations before income taxes

and equity in income (loss) of affiliates:

Domestic 

Foreign 

$ (2,972) 

10,972

$ 

8,000

2003 
(In thousands)

$ 31,164 

2,778

$ 33,942 

2002

$  82,012 

9,208 

$  91,220

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

September 30,

2004 

2003 

2000

(In thousands)

Deferred tax liabilities:

Property, plant and equipment 

Available-for-sale securities 

Equity investments 

Total deferred tax liabilities

Deferred tax assets:

Pension reserves 

Insurance reserves

Net operating loss carryforwards

Alternative minimum tax credit carryforwards

Financial accruals 

Other  

Total deferred tax assets     

Net deferred tax liabilities

$ 188,409

28,203

17,793

234,405 

7,283 

4,452 

21,077 

2,542 

7,574 

1,250

44,178

$190,227

$164,078

25,106 

17,349 

206,533 

4,918

3,688

4,074

5,333

4,446

2,337

24,796

$181,737

Reclassifications have been made to the fiscal 2003 balances for certain components of deferred tax assets and liabilities in order to

conform to the current year’s presentation.

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Deferred tax assets and liabilities included in the consolidated balance sheets are as follows:

September 30,

2004 

2003

Other current assets

Deferred income taxes

Total

$      4,346

(194,573)

$ (190,277)

(In thousands)

$     1,935 

(183,672)

$(181,737)

As of September 30, 2004, the Company’s federal and state net operating loss carryforwards for income tax purposes were approximately 

$43 million and $66 million, respectively. If not utilized, the federal net operating loss carryforwards will expire in fiscal 2024, and the state net 

operating loss carryforwards will begin to expire in fiscal 2008.

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,

2004 

2003 

2002

U.S. Federal income tax rate

Effect of foreign taxes

State income taxes

Other

Effective income tax rate 

NOTE 6  SHAREHOLDERS’ EQUITY 

35%

18

—

2

55% 

35%

4

4

—

43% 

35% 

7

2

—

44%

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. The Company did not repurchase any

shares in fiscal 2004, 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. There were no restricted stock grants in fiscal 2004, 2003, or 2002.  

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 partici-

pants 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 spinoff 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.

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The following summary reflects the stock option activity for the Company’s common stock and related information

for 2004, 2003, and 2002 (shares in thousands):

Outstanding at October 1, 

Granted 

Exercised 

Adjustment for Cimarex spinoff

Forfeited/Expired 

Outstanding on September 30, 

Exercisable on September 30, 

Shares available to grant 

Options

4,327

469

(305)

—

(34)

4,457

2,997

1,158

2004

2003

2002

Weighted-Average
Exercise Price

Options

Weighted-Average
Exercise Price

Options

Weighted-Average
Exercise Price

$21.41

3,875 

$20.28 

3,136 

$25.78

24.18

16.15

—

25.38

$22.03

$20.62

611 

(130) 

—

(29) 

4,327 

2,575 

1,597  

27.74 

16.93 

—

23.85 

$21.41 

$19.34 

820 

(181) 

926

29.89 

19.61 

—

(826) 

28.15 

3,875 

1,935 

2,195  

$20.28 

$19.07 

The following table summarizes information about stock options at September 30, 2004 (shares in thousands):

Outstanding Stock Options

Exercisable Stock Options

Range of
Exercise Prices 

$10.22 to $12.79 

$18.83 to $22.66 

$24.59 to $28.04 

$10.22 to $28.04 

Options

685 

1,550 

2,222 

4,457 

Weighted-Average
Remaining Life

Weighted-Average
Exercise Price

2.9

5.6

6.8

5.8

$11.86

$20.81

$26.01

$22.03

Options

685

1,174

1,138

2,997

Weighted-Average
Exercise Price

$11.86

$20.22

$26.30

$20.62

The weighted-average fair value of options at their grant date during 2004, 2003, and 2002 was $10.24, $10.72,

and $12.47, 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:

Risk-free interest rate

Expected stock volatility

Dividend yield

Expected years until exercise

2004 

3.7%

44%

.8%

5.5

2003 

3.1%

48%

.8%

4.5

2002

4.0% 

48%

.8% 

4.5

On September 30, 2004, the Company had 50,445,436 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

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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 7  EARNINGS PER SHARE

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

Basic weighted-average shares

Effect of dilutive shares:

Stock options

Restricted stock 

Diluted weighted-average shares 

2004 

50,312

521

—

521

50,833

2003 

(in thousands)

50,039

555

2

557

50,596

2002

49,825

508

12

520

50,345

At September 30, 2004, options to purchase 1,027,680 shares of common stock at a weighted-average price

of $27.84 were outstanding, but were not included in the computation of diluted earnings per common share.

Inclusion of these shares would be antidilutive.

At September 30, 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.

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NOTE 8  FINANCIAL INSTRUMENTS

The Company had $200 million of long-term debt outstanding at September 30, 2004 which had an estimated

fair value of $216.4 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 the cost of borrowings, if any, would approximate fair value. 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):

Equity Securities:

September 30, 2004

September 30, 2003

Cost

Gross Unrealized
Gains

Gross Unrealized 
Losses

Estimated Fair
Value

(in thousands)

$  27,811

$  33,300

$  70,448

$  64,276

$       170

$

0

$  98,089

$  97,576

During the years ended September 30, 2004, 2003, and 2002, marketable equity available-for-sale securities

with a fair value at the date of sale of $30.9 million, $18.2 million, and $46.7 million, respectively, were 

sold. For the same years, the gross realized gains on such sales of available-for-sale securities totaled $22.8

million, $8.6 million, and $25.9 million, respectively, and the gross realized losses totaled $7 thousand, $3.1

million and $232 thousand, respectively.

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NOTE 9  ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

Unrealized Appreciation
(Depreciation)
on Securities

Interest Rate 
Swap

Minimum Pension 
Liability

Total

(in thousands)

Balance at September 30, 2001 

$ 50,295 

$ 

(986) 

$    

–

$ 49,309

2002 Change:

Pre-income tax amount 

Income tax provision 

Amortization of swap

(16,228)

6,167

(net of $7 income tax benefit)

–

Realized gains in net income

(net of $9,431 income tax)

Balance at September 30, 2002 

2003 Change:

Pre-income tax amount 

Income tax provision 

Amortization of swap

(15,388)

(25,449) 

24,846 

29,731 

(11,298) 

(net of $602 income tax benefit)

–

Realized gains in net income

(net of $2,101 income tax)

Balance at September 30, 2003 

2004 Change:

Pre-income tax amount

Income tax provision 

Amortization of swap

(3,428)

15,005

39,851 

31,420

(11,940) 

(net of $45 income tax benefit)

–

Realized gains in net income

(net of $9,659 income tax)

(15,759)

3,721

(127)

48

11

–

(68)

(1,054)

– 

– 

982

–

982 

(72) 

–

–

72

–

72

(12,277)

4,665

(28,632)

10,880

–

–

(7,612)

(7,612)

2,421

(920)

–

–

1,501

(6,111) 

(1,951)

742

–

–

(1,209)

11

(15,388)

(33,129)

16,180

32,152

(12,218)

982

(3,428)

17,488

33,668 

29,469

(11,198)

72

(15,759)

2,584

Balance at September 30, 2004 

$ 43,572 

$ 

– 

$ (7,320) 

$ 36,252

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NOTE 10  EMPLOYEE BENEFIT PLANS

The Company maintains a noncontributory defined pension plan for substantially all U.S. employees who meet

certain age and service requirements. 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 Pension Plan frozen.

The following table and other information in this footnote provide information at September 30 as to the Company

sponsored domestic defined pension plan as required by SFAS No. 132 (Revised 2003), “Employers’ Disclosures

About Pensions and Other Postretirement Benefits.”

Change in benefit obligation:

Years Ended September 30,          2004 

2003

(in thousands)

Benefit obligation at beginning of year 

$ 71,174 

$ 68,134

Service cost 

Interest cost 

Curtailments 

Actuarial loss 

Benefits paid

3,943 

4,403 

—

5,985

(3,283)

5,401

4,423

(8,444)

6,269

(4,609)

Benefit obligation at end of year 

$ 82,222

$ 71,174

Change in plan assets:

Years Ended September 30,          2004 

(in thousands)

Fair value of plan assets at beginning of year

Actual gain (loss) on plan assets

Benefits paid

Fair value of plan assets at end of year 

Funded status of the plan

Unrecognized net actuarial loss 

Unrecognized prior service cost 

Accumulated other comprehensive loss 

(before tax)

Accrued benefit cost

$ 53,635 

6,298

(3,283)

$ 56,650

$ (25,572)

18,211

1

(11,807)

$ (19,167)

2003

$ 48,286

9,958

(4,609)

$ 53,635

$ (17,539)

15,052

20

(9,856)

$ (12,323)

Weighted-average assumptions:

Discount rate 

Years Ended September 30,          2004 
5.75% 

Expected return on plan assets

Rate of compensation increase 

8.00% 

5.00% 

73

2003 
6.25% 

8.00% 

5.00% 

2002
6.75%

8.00%

5.00% 

04-HP-876_newMDA.qxd  12/15/04  3:04 PM  Page 73

The Company anticipates that no funding of its Pension Plan will be required in fiscal 2005.

COMPONENTS OF NET PERIODIC PENSION EXPENSE:

Years Ended September 30,                  2004 

Service cost 

Interest cost 

Expected return on plan assets 

Amortization of prior service cost 

Amortization of transition asset 

Recognized net actuarial loss

Curtailment gain 

Net pension expense 

2003 

(in thousands)

$ 5,401 

4,423

( 3,807)

180

—

1,550

84

2002

$ 4,769

3,835

( 4,804)

238

(540)

120

—

$ 3,944 

4,403 

(4,232) 

19 

—

760 

—

$ 4,894

$ 7,831

$ 3,618

The following table reflects the expected benefits to be paid from the Pension Plan in each of the next five fiscal

years, and in the aggregate for the five years thereafter.

2005 

2006 

2007

2008

2009

2010-2014

Total

Years Ended September 30,

$ 3,967

$ 4,112

$ 4,134

$ 4,201

$ 4,278

$23,515

$44,207

(in thousands)

Included in the Pension Plan is an unfunded supplemental executive retirement plan.

The accumulated benefit obligation for the defined Pension Plan was $75.7 million, $66.1 million and $55.7

million at September 30, 2004, 2003, and 2002, respectively.

The Company evaluates the Pension Plan to determine whether any additional minimum liability is required. 

As a result of changes in the interest rates, an adjustment to the minimum pension liability was required. The 

adjustment to the liability is recorded as a charge to accumulated other comprehensive loss, net of tax, in

shareholders’ equity in the consolidated balance sheets.

INVESTMENT STRATEGY AND ASSET ALLOCATION

The Company’s investment policy and strategies are established with a long-term view in mind. The investment

strategy is intended to help pay the cost of the Plan while providing adequate security to meet the benefits

promised under the Plan. The Company maintains a diversified asset mix to minimize the risk of a material loss

to the portfolio value that might occur from devaluation of any one investment. In determining the appropriate

asset mix, the Company’s financial strength and ability to fund potential shortfalls are considered.

The expected long-term rate of return on plan assets is based on historical and projected rates of return for

current and planned asset classes in the Plans’ investment portfolio after analyzing historical experience and

future expectations of the return and volatility of various asset classes.

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The target allocation for 2005 and the asset allocation for the domestic Pension Plan at the end of fiscal 2004

and 2003, by asset category, follows:

Target Allocation

Percentage of Plan Assets
At September 30,

Asset Category

U.S. equities

International equities

Fixed income

Real estate and other

Total

2005

56%

14

25

5

100%

2004

57%

15

27

1

2003

57%

15

26

2

100%

100%

The fair value of plan assets was $56.7 million and $53.6 million at September 30, 2004 and 2003, respectively,

and the expected long-term rate of return on these plan assets was 8% in 2004 and 8% in 2003. 

DEFINED CONTRIBUTION PLAN

Substantially all employees on the United States payroll of the Company may elect to participate in the Company

sponsored 401(k)/Thrift 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 $5.6 million, $5.6 million, and $5.2 million in 2004, 2003, and 

2002, respectively.

NOTE 11  SUPPLEMENTAL BALANCE SHEET INFORMATION  

The following reflects the activity in the Company’s reserve for bad debt for 2004 and 2003:

Reserve for bad debt:

Balance at October 31,
Provision for bad debt

Write-off of bad debt

Balance at September 30,

2004 

2003

(in thousands)

$ 1,319
15

(69)

$ 1,265 

$ 1,337
45

(63)

$ 1,319

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Accounts receivable, prepaid expenses, and accrued liabilities at September 30 consist of the following:

September 30,                  2004 

2003

(in thousands)

Accounts receivable:

Trade receivables

Investment sales receivables

Prepaid expenses and other:

Time deposits 

Income tax asset

Deferred mobilization

Restricted cash

Other 

Accrued liabilities:

Taxes payable – operations 

Workers compensation claims 

Payroll and employee benefits 

Deferred income / prepays

Other 

$116,423 

16,839

$133,262

$    350 

5,831

2,846

2,000

11,129 

$ 22,156 

$ 6,531 

2,877 

8,678 

2,844 

10,961 

$ 31,891 

$ 91,088

— 

$ 91,088

$

322

32,619

2,993

—

9,787

$ 45,721

$ 8,386

2,820

6,768

1,535

9,479

$ 28,988

NOTE 12  SUPPLEMENTAL CASH FLOW INFORMATION 

Years Ended September 30,                  2004

2003

(in thousands)

2002  

Cash payments:

Interest paid, net of amount capitalized

Income taxes paid 

$ 12,653

$ 7,010

$ 11,375

$ 5,838

$

477

$  9,779

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NOTE 13 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 established 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 management’s 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, claim 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 operat-

ing 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 accounts owed in bolivars. The Company, historically, has been able to convert the

bolivars received in payment of the U.S. dollar-based billings into 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. 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. In

January 2004 the Venezuelan government approved the conversion of bolivar cash balances to U.S. dollars

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and the remittance of those U.S. dollars as dividends by the Company’s Venezuelan subsidiary to the U.S.

based parent. The Company was able to remit $8.8 million of such dividends in January 2004. This reduced

the Company’s exposure to currency devaluation in Venezuela.

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. As a result of the 20 percent devaluation of the bolivar

during fiscal 2004 (from September 2003 through August 2004), the Company experienced total devaluation

losses of $1.9 million during that same period. This 20 percent devaluation loss may not be reflective of the

potential for future devaluation losses because of the exchange controls that are currently in place. There

have been recent press reports of a potential devaluation in calendar 2005. However, the exact amount and

timing of such devaluation is uncertain. While the Company is unable to predict future devaluation in Venezuela,

if fiscal 2005 activity levels are similar to fiscal 2004 and if a 10 percent to 20 percent devaluation would

occur, the Company could experience potential currency devaluation losses ranging from approximately $1.2

million to $2.3 million.

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.

Venezuela continues to experience significant 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.

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, 2004, the Company did not have any material commitments for the purchase of drilling equipment.

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LEASES

In May 2003, the Company signed a six-year lease for approximately 114,000 square feet of office space near

downtown Tulsa, Oklahoma. The Company also conducts certain operations in leased premises and leases

telecommunication equipment. Future minimum lease payments required under noncancelable operating leases

as of September 30, 2004 are as follows (in thousands):

Fiscal Year

2005

2006

2007

2008

2009

Thereafter

Total

Amount

$ 2,542

2,261

1,844

1,412

1,408

462

$ 9,929

Total rent expense was $2.0 million, $1.1 million and $1.0 million for 2004, 2003 and 2002, 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.

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Summarized financial information of the Company’s reportable segments for each of the years ended

September 30, 2004, 2003, and 2002 is shown in the following table:

(in thousands)

2004:
Contract Drilling

U.S. Land 
U.S. Offshore Platform 
International Services 

Real Estate 
Other 
Eliminations 

Total 

2003:
Contract Drilling

U.S. Land 
U.S. Offshore Platform 
International Services 

Real Estate 
Other 
Eliminations 

Total 

2002:
Contract Drilling

$ 347,793
84,993
150,698 
583,484 
9,842 
27,602 
—

$ 620,928

$ 273,993
112,633
109,812 
496,438 
10,893 
7,953 
—

$ 515,284

U.S. Land 
$ 231,637
U.S. Offshore Platform   132,249
151,392 
International Services 
515,278 
8,525 
28,076 
—
$ 551,879  

Real Estate 
Other 
Eliminations 
Total 

External
Sales 

Inter-
Segment

Total
Sales

Operating Profit
(loss)

Depreciation

Total
Assets

Additions
to Long-Lived
Assets

$ 68,680
1,512
9,513
79,705
3,538
5,729
—
$ 88,972

$ 216,590
7,191
12,733
236,514
7,628
2,159
—

$ 246,301

$ 236,254
48,273
23,157
307,684
3,181
1,199
— 

$ 312,064

$ —
—
—
—
897
—
(897)

$ —

$ —
—
—
—
1,439
—
(1,439)

$ —

$ 809 
— 
—
809 
1,491 
—
(2,300) 

$ —

$ 347,793
84,993
150,698
583,484
10,739
27,602
(897)
$ 620,928

$ 273,993
112,633
109,812
496,438
12,332
7,953
(1,439)
$ 515,284

$ 37,323
(34,873)
14,036 
16,486 
4,242 
—
—
$ 20,728 

$ 18,565
36,306
5,149 
60,020 
6,569 
—
—
$ 66,589 

$ 56,528
12,107
20,530
89,165
2,253
3,007
—

$  742,642
102,557
261,893
1,107,092
33,044
266,708
—

$ 94,425 

$1,406,844

$ 44,726
12,799
20,092
77,617
2,535
2,361
—

$  730,642
170,580
243,918
1,145,140
31,472
241,158
—

$ 82,513 

$1,417,770

$ 232,446
132,249
151,392 
516,087 
10,016 
28,076 
(2,300) 
$ 551,879 

$ 30,493
38,688
13,128
82,309
5,064
—
—
$ 87,373

$ 26,311
10,809
20,336
57,456
1,844
2,147
—

$   555,137
173,474
254,940 
983,551 
26,562 
217,200 
—

$ 61,447 

$1,227,313

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The following table reconciles segment operating profit 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,

2004 

2003 

Segment operating profit 
Unallocated amounts:

Income from investments 
Corporate and administrative expense 
Interest expense 
Corporate depreciation 
Other corporate expense

Total unallocated amounts 

Income before income taxes and equity in

income (loss) of affiliates 

$ 20,728 

$ 66,589 

27,602 
(24,496)
(12,695) 
(3,007) 
(132) 
(12,728) 

7,953 
(25,650) 
(12,289) 
(2,361) 
(300) 
(32,647)

2002

$ 87,373

28,076
(20,391)
(980)
(2,147)
(711)
3,847

$  8,000 

$ 33,942 

$ 91,220

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,

2004 

2003 

2002

Revenues

United States 
Venezuela 
Ecuador 
Colombia 
Other Foreign

Total 

Long-Lived Assets
United States 
Venezuela 
Ecuador 
Colombia 
Other Foreign

Total 

$  470,230 
56,279 
43,540 
3,704 
47,175 
$ 620,928 

$  799,207 
85,336 
46,809 
9,336 
57,986 
$ 998,674 

$ 405,472 
31,763 
50,783 
6,081 
21,185 
$ 515,284 

$   867,365 
75,179 
46,778 
12,984 
55,899 
$1,058,205 

$ 400,487
50,763
47,501
11,612
41,516
$ 551,879

$ 698,316
72,630
49,353
14,339
62,807
$ 897,445

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

Revenues from one company doing business with the contract drilling segment accounted for approximately

10.8 percent, 15.7 percent, and 16.3 percent of the total consolidated revenues during the years ended

September 30, 2004, 2003, and 2002, respectively. Revenues from another company doing business with the

contract drilling segment accounted for approximately 10.7 percent, 14.6 percent, and 14.7 percent of total

consolidated revenues in the years ended September 30, 2004, 2003, and 2002, respectively. Revenues from

another company doing business with the contract drilling segment accounted for approximately 8.4 percent,

11.5 percent, and 12.3 percent of total consolidated revenues in the years ended September 30, 2004,

2003, and 2002, respectively. Collectively, the receivables from these customers were approximately $28.6

million and $36.0 million at September 30, 2004 and 2003, respectively.

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NOTE 16  SUBSEQUENT EVENT

In November 2004, the Company sold two conventional  2,000 horsepower rigs from its U.S. land fleet for a total of $23.9 million.

NOTE 17  SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

(in thousands, except per share amounts) 

1st Quarter

2nd Quarter

3rd Quarter

4th Quarter

2004

Revenues

Asset impairment charge

Gross profit (loss) 

Net income (loss) 

Basic net income (loss) per common share:

Diluted net income (loss) per common share:

2003

Revenues

Gross profit 

Net income 

Basic net income per common share:

Diluted net income per common share:

$ 140,458 

$ 151,186 

$ 147,874 

$ 181,410

—

24,663 

6,588 

.13 

.13 

—

23,124 

6,048 

.12 

.12 

—

18,638 

4,347 

.09 

.09 

51,516   

(8,069) 

(12,624) 

(.25) 

(.25)

1st Quarter

2nd Quarter

3rd Quarter

4th Quarter

$ 113,313 

$ 126,320 

$ 137,025 

$ 138,626

14,021 

607 

.01 

.01 

19,024 

2,574 

.05 

.05 

26,788 

8,162 

.16 

.16 

27,401 

6,530 

.13 

.13

Gross profit (loss) 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 first quarter of 2004 has been adjusted upward from amounts previously reported by 

approximately $1.0 million ($0.02 per share, on a diluted basis) to reflect a non-monetary gain on the 

conversion of shares of common stock of a company investee pursuant to that investee being acquired. All

future public filings will reflect this change.

In the fourth quarter of fiscal 2004, the net loss includes an after-tax gain on sale of available-for-sale securities

of $8.1 million, $0.16 per share, on a diluted basis.

In the fourth quarter of fiscal 2004, the net loss includes an after-tax asset impairment charge of approximately

$32 million, $0.63 per share, on a diluted basis.

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 from affiliates of $2.0 million,

$0.04 per share, on a diluted basis.

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Directors

Officers

W. H. Helmerich, III
Chairman of the Board

Hans Helmerich
President and Chief Executive Officer

George S. Dotson
Vice President,
President of Helmerich & Payne
International Drilling Co.

Douglas E. Fears
Vice President and 
Chief Financial Officer

Steven R. Mackey
Vice President, Secretary,
and General Counsel

W. H. Helmerich, III
Chairman of the Board
Tulsa, Oklahoma

Hans Helmerich
President and Chief Executive Officer
Tulsa, Oklahoma

William L. Armstrong **(***)
Chairman
Transland Financial Services, Inc.
Denver, Colorado

Glenn A. Cox *(***)
President and Chief Operating Officer, Retired
Phillips Petroleum Company
Bartlesville, Oklahoma

George S. Dotson
Vice President,
President of Helmerich & Payne
International Drilling Co.
Tulsa, Oklahoma

Paula Marshall-Chapman**(***)
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, Retired
AT&T Wireless Services, Inc.
Basking Ridge, New Jersey

* Member, Audit Committee
** Member, Human Resources Committee
*** Member, Nominating and Corporate Governance Committee

83

Stockholders’ Meeting
The annual meeting of stockholders will be held 
|on March 2, 2005. 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, 2005.

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 3, 2004, there were 860 record
holders of Helmerich & Payne, Inc. common stock
as listed by the transfer agent’s records.

Our Transfer Agent is responsible for our share-
holder records, issuance of stock certificates, 
and distribution of our dividends and the IRS Form
1099. Your requests, as shareholders, concerning
these matters are most efficiently answered by
corresponding directly with The Transfer Agent at
the following address:

UMB Bank
Security Transfer Division
928 Grand Blvd., 13th Floor
Kansas City, MO 64106
Telephone: (800) 884-4225
(816) 860-5000

Available 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.

Annual CEO Certification
The annual CEO Certification required by Section
303A.12(a) of the New York Stock Exchange Listed
Company Manual was provided to the New York
Stock Exchange on or about March 12, 2004.

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