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<SEC-DOCUMENT>0000950134-00-010771.txt : 20001229
<SEC-HEADER>0000950134-00-010771.hdr.sgml : 20001229
ACCESSION NUMBER: 0000950134-00-010771
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 5
CONFORMED PERIOD OF REPORT: 20000930
FILED AS OF DATE: 20001228

FILER:

COMPANY DATA:
COMPANY CONFORMED NAME: HELMERICH & PAYNE INC
CENTRAL INDEX KEY: 0000046765
STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381]
IRS NUMBER: 730679879
STATE OF INCORPORATION: DE
FISCAL YEAR END: 0930

FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-04221
FILM NUMBER: 797241

BUSINESS ADDRESS:
STREET 1: UTICA AT 21ST ST
CITY: TULSA
STATE: OK
ZIP: 74114
BUSINESS PHONE: 9187425531

MAIL ADDRESS:
STREET 1: UTICA AT 21ST ST
CITY: TULSA
STATE: OK
ZIP: 74114
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>d82779e10-k405.txt
<DESCRIPTION>FORM 10-K FOR FISCAL YEAR END SEPTEMBER 30, 2000
<TEXT>

<PAGE> 1

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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, 2000

[ ] 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)

<TABLE>
<S> <C>
DELAWARE 73-0679879
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)

UTICA AT TWENTY-FIRST STREET, TULSA, OKLAHOMA 74114
(Address of principal executive offices) (Zip code)
</TABLE>

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

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

<TABLE>
<CAPTION>
TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
------------------- ------------------------------------
<S> <C>
Common Stock ($0.10 par value) New York Stock Exchange
Common Stock Purchase Rights New York Stock Exchange
</TABLE>

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. [X]

At December 15, 2000, the aggregate market value of the voting stock held
by non-affiliates was $1,698,216,449.

Number of shares of common stock outstanding at December 15,
2000: 50,087,254.

DOCUMENTS INCORPORATED BY REFERENCE

(1) Annual Report to Shareholders for the fiscal year ended September 30,
2000 -- Parts I, II, and IV.

(2) Proxy Statement for Annual Meeting of Security Holders to be held March 7,
2001 -- Part III.

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<PAGE> 2

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

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
MANAGEMENT'S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION ON PAGES 10 THROUGH 17 IN REGISTRANT'S ANNUAL REPORT TO THE
SHAREHOLDERS FOR FISCAL 2000 AND IN THE REMAINDER OF THIS 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 THE 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.

<PAGE> 3

HELMERICH & PAYNE, INC. AND SUBSIDIARIES
Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the Fiscal Year Ended September 30, 2000

PART I

Item 1. BUSINESS
Helmerich & Payne, Inc. (the "Registrant"), was incorporated under the
laws of the State of Delaware on February 3, 1940, and is successor to a
business originally organized in 1920. Registrant is primarily engaged in the
exploration, production, and sale of crude oil and natural gas and in contract
drilling of oil and gas wells for others. These activities account for the
major portion of its operating revenues. The Registrant is also engaged in the
ownership, development, and operation of commercial real estate.

The Registrant is organized into three separate autonomous operating
divisions being contract drilling; oil & gas exploration and production
operations; and real estate. While there is a limited amount of intercompany
activity, each division operates essentially independently of the others. Each
of the divisions, except exploration and production, conducts their respective
business through wholly owned subsidiaries. Operating decentralization is
balanced by a centralized finance division, which handles all accounting, data
processing, budgeting, insurance, cash management, and related activities.

<PAGE> 4

Most of the Registrant's current exploration efforts are concentrated
in Louisiana, Oklahoma, Texas, and the Hugoton Field of western Kansas. The
Registrant also explores from time to time in the Rocky Mountain area, New
Mexico, Alabama, Michigan, and Mississippi. Substantially all of the
Registrant's gas production is sold to and resold by its marketing subsidiary.
This subsidiary also purchases gas from unaffiliated third parties for resale.

The Registrant's domestic contract drilling is conducted primarily in
Oklahoma, Texas, and Louisiana, and offshore from platforms in the Gulf of
Mexico and offshore California. The Registrant has also operated during fiscal
2000 in six international locations: Venezuela, Ecuador, Colombia, Argentina,
Bolivia and Equatorial Guinea.

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

CONTRACT DRILLING

The Registrant 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 Registrant specializes primarily in deep
drilling in major gas producing basins of the United States and in drilling for
oil and gas in remote international areas. For its international operations,
the Registrant operates certain rigs which are transportable by helicopter. In
the United States, the Registrant draws its customers primarily from the major
oil companies and the larger independents. The Registrant also drills for its
own oil and gas division. In South America, the Registrant's current customers
include the Venezuelan state petroleum company and major international oil
companies.

In fiscal 2000, Registrant received approximately 43% of its
consolidated revenues from the Registrant's ten largest contract drilling
customers. BP and Shell Oil Co., including their affiliates, (respectively, "BP"
and "Shell") are the Registrant's two largest contract drilling customers. The

I-2
<PAGE> 5

Registrant performs drilling services for BP and Shell on a world-wide basis.
Revenues from drilling services performed for BP and Shell in fiscal 2000
accounted for approximately 15% and 7%, respectively, of the Registrant's
consolidated revenues for the same period. While the Registrant believes that
its relationship with all of these customers is good, the loss of BP or Shell
or a simultaneous loss of several of its larger customers would have a material
adverse effect on the drilling subsidiary and the Registrant.

The Registrant provides drilling rigs, equipment, personnel, and camps
on a contract basis. These services are provided so that Registrant's customers
may explore for and develop oil and gas from onshore areas and from fixed and
tension leg platforms 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. Conversely, 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, Registrant
operates self-moving minimum space platform drilling rigs and drilling rigs to
be used on tension leg platforms. The minimum space rig is designed to be moved
without the use of expensive derrick barges. The tension leg platform rig
allows drilling operations to be conducted in much deeper water than
traditional fixed platforms. 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.

I-3
<PAGE> 6

The Registrant's workover rigs are equipped with engines, drawworks, a
mast, pumps, and blowout preventers. A workover rig is used to complete a new
well after the hole has been drilled by a drilling rig, and to remedy various
downhole problems that occur in producing wells.

During fiscal 1998, Registrant put to work a new generation of six
highly mobile/depth flexible new rigs (individually the "FlexRig(TM)"). The
FlexRig(TM) may reduce rig move times by at least 50%. In addition, the
FlexRig(TM)allows a greater depth flexibility of between 8,000 to 18,000 feet
and provides greater operating efficiency. During fiscal 2000, the Registrant
ordered 12 new FlexRigs(TM) at an approximate cost of between $7.5 million and
$8.25 million each. The Registrant expects to take delivery of 11 of the new
FlexRigs(TM) in calendar 2001 with the final FlexRig(TM) to be delivered in the
first calendar quarter of 2002. The FlexRigs(TM) will be available for work in
the Registrant's domestic and international drilling operations.

The Registrant'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. Most of the contracts are performed on a "daywork" basis,
under which the Registrant 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 Registrant has previously performed contracts on a
combination "footage" and "daywork" basis, under which the Registrant 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
Registrant has previously accepted "turnkey" contracts under which the
Registrant 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

I-4
<PAGE> 7

normally done on a "footage" basis. "Turnkey" contracts entail varying degrees
of risk greater than the usual "footage" contract. Registrant has not accepted a
"footage" or "turnkey" contract during fiscal 2000. The Registrant believes that
under current market conditions "footage" and "turnkey" contract rates do not
adequately compensate contractors for the added risks. The duration of the
Registrant'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 termination
payment" to be paid to the contractor if a contract is terminated prior to the
expiration of the fixed term.

While current fixed term contracts are for one 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 Registrant and the customer. In most instances
contracts provide for additional payments for mobilization and demobilization.
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. See
Regulations and Hazards, page I-8.

Domestic Drilling

The Registrant believes it is a major land and offshore platform
drilling contractor in the domestic market. At the end of September, 2000, the
Registrant had 47 (37 land rigs and 10 platform rigs) of its rigs operating in
the United States and had management contracts for three customer-owned rigs.

I-5
<PAGE> 8

During fiscal 2000, one land rig was relocated from the Registrant's
domestic operations to the Registrant's operations in Venezuela. In addition,
one of the Registrant's older land rigs was sold.

In December of 2000, Registrant signed three-year term contracts for
five (5) of Registrant's rigs to provide drilling services in Wyoming for a
major oil company. Registrant expects that all five rigs will commence drilling
operations during calendar 2001.

International Drilling

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

Venezuelan operations continue to be a significant part of the
Registrant's operations. At the end of fiscal 2000, the Registrant owned and
operated 18 land drilling rigs in Venezuela with a utilization rate of 32% for
such fiscal year. The Registrant worked for the Venezuelan state petroleum
company during fiscal 2000, and revenues from this work accounted for
approximately 3.6% of the Registrant's consolidated revenues during the fiscal
year.

Registrant's rig utilization rate in Venezuela has decreased from
approximately 36% during the 1999 fiscal year to approximately 32% in fiscal
2000. This reduction in utilization is primarily due to curtailed production and
development activities resulting from prior reductions in worldwide oil prices.
While worldwide oil prices have improved, the Venezuelan state petroleum company
production and development activities continue to lag behind the improvement in
oil prices. Even though the Registrant is, at this time, unable to predict
future fluctuations in its utilization rates during

I-6
<PAGE> 9

fiscal 2001, the Registrant believes that the prospects are good for returning
at least three idle rigs back to work during fiscal 2001.

The Venezuelan government, in early 1996, permitted foreign
exploration and production companies to acquire rights to explore for and
produce oil and gas in Venezuela. Registrant has performed contract drilling
services in Venezuela for three independent oil companies during fiscal 2000.

At the end of fiscal 2000, the Registrant owned and operated seven
drilling rigs in Colombia. The Registrant's utilization rate in Colombia was
62% during fiscal 2000. During fiscal 2000 the revenues generated by Colombian
drilling operations contributed approximately 6.7% of the Registrant's
consolidated revenues. During the first and second quarters of fiscal 2001, the
Registrant expects to move three (3) rigs from Colombia to Houston, Texas. The
Registrant expects continued reduction in activity and revenues from Colombia.

In addition to its operations in Venezuela and Colombia, the
Registrant in fiscal 2000 owned and operated six rigs in Ecuador, six rigs in
Bolivia, and three rigs in Argentina. In Ecuador, Bolivia and Argentina, the
contracts are with large international oil companies. During fiscal 2000, the
Registrant commenced operations under a management contract for a
customer-owned platform rig located in offshore Equatorial Guinea.

Competition

The contract drilling business is highly competitive. Competition in
contract drilling involves such factors as price, rig availability, efficiency,
condition of equipment, reputation, 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.

I-7
<PAGE> 10

Although many contracts for drilling services are awarded based solely
on price, the Registrant has been successful in establishing long-term
relationships with certain customers which have allowed the Registrant to
secure drilling work even though the Registrant may not have been the lowest
bidder for such work. The Registrant has continued to attempt to differentiate
its services based upon its engineering design expertise, operational
efficiency, safety and environmental awareness.

Regulations and Hazards

The drilling operations of the Registrant are subject to the many
hazards inherent in the business, including 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 Registrant believes that it has adequate insurance coverage for
comprehensive general liability, public liability, property damage (including
insurance against loss by fire and storm, blowout, and cratering risks),
workers compensation and employer's liability. No insurance is carried against
loss of earnings or business interruption. The Registrant is unable to obtain
significant amounts of insurance to cover risks of underground reservoir
damage; however, the Registrant is generally indemnified under its drilling
contracts from this risk. The Registrant's present insurance coverage has been
secured through fiscal 2001. However, in view of conditions generally in the
liability insurance industry, no assurance can be given that the Registrant's
present coverage will not be cancelled during fiscal 2001 nor that insurance
coverage will continue to be available at rates considered reasonable.

International operations are subject to certain political, economic,
and other uncertainties not encountered in domestic operations, including risks
of terrorism, 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

I-8
<PAGE> 11

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 Registrant's operations or
on the ability of the Registrant to continue operations in certain areas.
Because of the impact of local laws, the Registrant'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
Registrant holds only a minority interest, or pursuant to arrangements under
which the Registrant conducts operations under contract to local entities. While
the Registrant believes that neither operating through such entities nor
pursuant to such arrangements would have a material adverse effect on the
Registrant's operations or revenues, there can be no assurance that the
Registrant 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 Registrant. The Registrant further attempts to minimize the potential impact
of such risks by operating in more than one geographical area and by attempting
to obtain indemnification from operators against expropriation, nationalization,
and deprivation.

During fiscal 2000, approximately 22% of the Registrant's consolidated
revenues were generated from the international contract drilling business. Over
95% of the international revenues were from operations in South America and 59%
of South American revenues were from Venezuela and Colombia. Exposure to
potential losses from currency devaluation is minimal in the above-mentioned
countries except for Venezuela. 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.

In Venezuela, approximately 60% of the Registrant's invoice billings
are in U.S. dollars and the other 40% are in the local currency, the bolivar.
The Registrant is exposed to risks of currency devaluation in Venezuela as a
result of bolivar receivable balances and necessary bolivar cash balances.

I-9
<PAGE> 12

In 1994, the Venezuelan government established a fixed exchange rate in hopes of
stemming economic problems caused by a high rate of inflation. During the first
week of December, 1995, the government established a new exchange rate,
resulting in further devaluation of the bolivar. In April of 1996, the bolivar
was again devalued when the government decided to abolish its fixed rate policy
and to allow a floating market exchange rate. During fiscal 1999, the Registrant
experienced losses of approximately US$712,000 and in fiscal 2000 it experienced
losses of US$687,000 as a result of the devaluation of the bolivar. Registrant
is unable to predict future devaluation in Venezuela. In the event that fiscal
2001 activity levels are similar to fiscal 2000 and if a 25% to 50% devaluation
would occur, the Registrant could experience potential currency valuation losses
ranging from approximately US$600,000 to US$1,000,000.

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 Registrant's loss of all or a portion of
its assets and business in Venezuela.

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

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<PAGE> 13

The Registrant 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 Registrant, although these measures may add to the costs of
operating drilling equipment in some instances. Additional legislation or
regulation may reasonably be anticipated, and the effect thereof on operations
cannot be predicted.

OIL & GAS EXPLORATION AND PRODUCTION OPERATIONS

The Registrant engages in the origination of prospects; the
identification, acquisition, exploration, and development of prospective and
proved oil and gas properties; the production and sale of crude oil,
condensate, and natural gas; and the marketing of natural gas. The Registrant
considers itself a medium-sized independent producer. All of the Registrant's
oil and gas operations are conducted in the United States.

Most of the Registrant's current exploration and drilling effort is
concentrated in Oklahoma, Kansas, Texas, and Louisiana. The Registrant also
explores from time to time in New Mexico, Alabama, Michigan, Mississippi, and
the Rocky Mountain area.

The Registrant's exploration and production division includes six
geographical exploitation teams comprised of geological, engineering, and land
personnel. These personnel primarily develop in-house oil and gas prospects as
well as review outside prospects and acquisitions for their respective
geographical areas. The Registrant believes that this structure allows each team
to gain greater expertise in its respective geographical area and reduces risk
in the development of prospects.

Since fiscal 1998, the Registrant has focused on developing prospects
using 3D seismic technology. Currently, the Registrant is involved in 3D
surveys covering more than 1,050 square

I-11
<PAGE> 14

miles, of which approximately 750 square miles are proprietary. Approximately
900 square miles of land covered by such surveys is located near the Texas and
Louisiana onshore Gulf Coast.

During fiscal 2000, the Registrant drilled 17 wells with a 60% success
rate in Jefferson County, Texas. These are primarily one well fields identified
from the 3-D seismic. Since the beginning of Registrant's activity in Jefferson
County, Registrant has participated in 21 wells with six dry holes, or a 71%
success rate. Registrant's working interest in this area ranges from 33% to
66%, however Registrant has taken less interest in some prospects and greater
interest in other prospects.

Three wells have been drilled in the West Texas Dixieland area during
fiscal 2000. Two of the wells have been successfully completed, and an uphole
completion will be attempted in the third well. A fourth well is currently
being completed. Registrant will evaluate the results of the fourth well in
order to determine the possibility for a fifth well in the area.

Registrant's major increases in new oil reserves came primarily from
the Kansas Hugoton Field area and from condensate production associated with
successful gas wells along the Gulf Coast.

Commodity prices have allowed several low risk infill drilling
projects to become economically viable. These include additional drilling at
the edge of Hugoton field as well as additional drilling for tight gas in
Oklahoma.

The Registrant's exploration and development program has covered a
range of prospects, from shallow "bread and butter" programs to deep expensive,
high risk/high return wells. During fiscal 2000, the Registrant participated in
68 development and/or wildcat wells, which resulted in new discoveries of
approximately 22.3 BCF of gas and 935,013 barrels of oil and condensate. The
Registrant participated in 13 additional development wells, which resulted in
the development of approximately 13.4 BCF of gas and 2,676 barrels of oil which
was previously classified as proved undeveloped or proved developed
nonproducing reserves. In addition, 30.5 BCF of gas and 191,206

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<PAGE> 15

barrels of oil was booked as additional proved undeveloped reserves in 96
locations, primarily in infill locations in Oklahoma and Kansas. This reserve
increase primarily resulted from higher oil and gas prices and development
drilling success. A total of $57,970,195 was spent in the Registrant's
exploration and development program during fiscal 2000. This figure includes
$4,452,626 of geophysical expense, but is exclusive of expenditures for acreage
and acquisition of proved oil and gas reserves. The Registrant's total
company-wide acquisition cost for acreage in fiscal 2000 was approximately $11
million.

The Registrant spent $105,166 for the acquisition of proved oil and
gas reserves during fiscal 2000. The reserves associated with these
acquisitions were 242,149 MCF of gas and 1,502 barrels of oil.

The Registrant's fiscal 2001 exploration and production budget of
approximately $83 million is 26% greater than its actual exploration and
production expenditures in fiscal 2000.

The Registrant, during fiscal 2000, hired the investment banking firm
of Petrie Parkman & Co. to advise the Company regarding strategic alternatives
with regard to the Registrant's oil and gas division. It is contemplated that a
successful transaction could lead, among other things, to the Company's
exploration and production division being established as a separate public
entity. The Registrant is unable to predict if and when such a transaction may
occur.

Market for Oil and Gas

The Registrant does not refine any of its production. The availability
of a ready market for such production depends upon a number of factors,
including the availability of other domestic production, price, crude oil
imports, the proximity and capacity of oil and gas pipelines, and general
fluctuations in supply and demand. The Registrant does not anticipate any
unusual difficulty in contracting to sell its production of crude oil and
natural gas to purchasers and end-users at prevailing market prices and

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<PAGE> 16
under arrangements that are usual and customary in the industry. The Registrant
and its subsidiary, Helmerich & Payne Energy Services, Inc., have successfully
developed markets with end-users, local distribution companies, and natural gas
brokers for gas produced from successful wildcat wells and development wells.
Substantially all of Registrant's gas production is sold to and resold by
Helmerich & Payne Energy Services, Inc. During fiscal 2000, the price that
Registrant received for the sale of its natural gas has increased. Registrant's
average per MCF natural gas sales price in fiscal 2000 for each of the first
through fourth quarters was $2.28, $2.28, $2.97 and $3.65, respectively.

The Registrant is of the opinion that the natural gas market will
continue to be characterized by high volatility and relatively high prices for
the next 12 to 18 months. The record natural gas prices and high volatility as
evidenced by the dramatic early summer increase in natural gas prices is a
result of ever changing perceptions throughout the industry centered around
supply and demand. Pricing perceptions constantly change as members of the
industry weigh the impacts of decline in deliverability of domestic supply,
increased use of natural gas for electrical generation, continued U.S. economic
growth, the increased usage and better management of natural gas storage,
seasonal usage, fuel switching, usage of gas as a feed stock, and importation of
gas from Canada and Mexico.

The tight supply/demand balance will likely continue until increased
gas drilling activity results in the increased productive capacity. Registrant
presently believes that the natural gas price volatility will continue for the
next three to five years as the natural gas industry reacts to the
supply/demand balance. Long term pricing will obviously react to these short
term factors, as well as other considerations affecting supply/demand.

Historically, the Registrant has had no long-term sales contracts for
its crude oil and condensate production. The Registrant continues its practice
of contracting for the sale of its Kansas and Oklahoma and portions of its west
Texas crude oil for terms of six to twelve months in an attempt to

I-14
<PAGE> 17

assure itself of the best price in the area for crude oil production. During
fiscal 2000, the price that Registrant received for the sale of its crude oil
has steadily increased. Registrant's average per barrel crude oil sales price in
fiscal 2000 for each of the first through fourth quarters was $23.52, $27.80,
$27.98 and $31.02, respectively.

Competition

The Registrant competes with numerous other companies and individuals
in the acquisition of oil and gas properties and the marketing of oil and gas.
The Registrant believes that it should continue to prepare for increased
exploration activity without committing to a definite drilling timetable. The
Registrant also believes that competition for the acquisition of gas producing
properties will continue. Considering the Registrant's conservative acquisition
strategy, the Registrant believes that it may be unable to acquire significant
proved developed producing reserves from third parties. The Registrant intends
to continue its review of properties in areas where the Registrant has
expertise. The Registrant's competitors include major oil companies, other
independent oil companies, and individuals. Many of these competitors have
financial resources, staffs, and facilities substantially larger than those of
the Registrant. The effect of these competitive factors on the Registrant cannot
be predicted.

Title to Oil and Gas Properties

The Registrant undertakes title examination and performs curative work
at the time properties are acquired. The Registrant believes that title to its
oil and gas properties is generally good and defensible in accordance with
standards acceptable in the industry.

Oil and gas properties in general are subject to customary royalty
interests contracted for in connection with the acquisitions of title, liens
incident to operating agreements, liens for current taxes, and other burdens
and minor encumbrances, easements, and restrictions. The Registrant believes
that

I-15
<PAGE> 18

the existence of such burdens will not materially detract from the general
value of its leasehold interests.

Governmental Regulation in the Oil and Gas Industry

The Registrant's domestic operations are affected from time to time in
varying degrees by political developments and federal and state laws and
regulations. In particular, oil and gas production operations and economics are
affected by price control, tax, and other laws relating to the petroleum
industry; by changes in such laws; and by constantly changing administrative
regulations. Most states in which the Registrant conducts or may conduct oil and
gas activities regulate the production and sale of oil and natural gas,
including regulation of the size of drilling and spacing units or proration
units, the density of wells which may be drilled, and the unitization or pooling
of oil and gas properties. In addition, state conservation laws establish
maximum rates of production from oil and natural gas wells, generally prohibit
the venting or flaring of natural gas, and impose certain requirements regarding
the ratability of production. The effect of these regulations is to limit the
amounts of oil and natural gas the Registrant can produce from its wells, and to
limit the number of wells or locations at which the Registrant can drill. In
addition, legislation affecting the natural gas and oil industry is under
constant review. Inasmuch as such laws and regulations are frequently expanded,
amended, or reinterpreted, the Registrant is unable to predict the future cost
or impact of complying with such regulations. The Registrant believes that
compliance with existing federal, state and local laws, rules and regulations
will not have a material adverse effect upon its capital expenditures, earnings
or competitive position.

Regulatory Controls

Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated under the Natural Gas Act ("NGA") and
the Natural Gas Policy Act of 1978 ("NGPA") and the regulations promulgated
thereunder.

I-16
<PAGE> 19

The Natural Gas Wellhead Decontrol Act of 1989 amended both the price
and non-price decontrol provisions of the NGPA for the purpose of providing
complete decontrol of first sales of natural gas by January 1, 1993. The
Registrant believes that substantially all of its gas is decontrolled.

Commencing in April, 1992, the Federal Energy Regulatory Commission
("FERC") issued Order 636, Order 636-A, and Order 636-B (collectively, "Order
636") which requires interstate pipelines to provide transportation unbundled
from their sales of gas. Also, such pipelines must provide open-access
transportation on a basis that is equal for all gas supplies. Although Order 636
has provided the Registrant with additional market access and more fairly
applied transportation service rates, it has also subjected the Registrant to
more restrictive pipeline imbalance tolerances and greater penalties for
violation of those tolerances. Order 636 and numerous related orders pertaining
to individual pipelines have been upheld by the Courts. However, the FERC
continues to review and modify open access regulations.

In particular, the FERC recently issued new rules and policies
pertaining to interstate pipeline certificates which require notification of
landowners affected by proposed pipeline construction, and which presume
incremental pricing is appropriate for new construction. The FERC also issued
new rules governing transportation which, among other matters, eliminated
cost-based regulation for certain short term transportation, and require
pipelines to design services that facilitate open access operations and
decrease the use by pipelines of emergency operational orders. In addition, the
FERC has requested comments on certain issues related to its regulation of long
term transportation. Implementation of many details of these rules has been
left to individual pipeline proceedings. In addition, court appeals of the new
rules are pending. While this FERC action affects the Registrant only
indirectly, these rules are intended to further enhance competition in the
natural gas markets. They may also increase the cost of transportation.

I-17
<PAGE> 20

Under the NGA, natural gas gathering facilities are exempt from FERC
jurisdiction. The Registrant believes that its gathering systems meet the
traditional tests that the FERC has used to establish a pipeline's status as a
gatherer. In recent years, the FERC has slightly narrowed its statutory tests
for establishing gathering status. A number of states have either enacted new
laws or are considering the adequacy of existing laws affecting gathering rates
and/or services. For example, in May, 1997, Kansas enacted new gathering
oversight legislation that, among other matters, requires reporting of gathering
prices and authorizes the Kansas Corporation Commission ("KCC") to oversee open
access on gathering systems to assure it is just, reasonable, and
non-discriminatory. Thus, natural gas gathering may receive greater regulatory
scrutiny by state agencies. In addition, the FERC has approved several transfers
by interstate pipelines of gathering facilities to unregulated gathering
companies, including affiliates. This could allow such companies to compete more
effectively with independent gatherers. It is not possible at this time to
predict the ultimate effect of the policy, although it could affect access to
and rates charged for interstate gathering services. However, the Registrant
does not presently believe the status of its facilities would be materially
affected by modification to the statutory criteria.

In February, 1994, the KCC issued an order which modified allowables
applicable to wells within the Hugoton Gas Field so that those proration units
upon which infill wells had been drilled would be assigned a larger allowable
than those units without infill wells. As a consequence of this order, the
Registrant has participated in the drilling of 140 infill wells. If current gas
prices continue, Registrant could participate in the drilling of up to 30
additional infill wells along the edge of the Hugoton field.

In September, 1997, the FERC ruled that ad valorem tax levied by the
State of Kansas was not a severance tax within the meaning of Section 110 of
the NGPA. Therefore, to the extent that first sellers collected revenues in
excess of the maximum lawful price as a result of reimbursement of Kansas ad
valorem taxes, then first

I-18
<PAGE> 21
sellers would be required to make refunds with interest for such excess
revenues on tax bills rendered during the period October 4, 1983 through June
28, 1988. Based upon schedules provided to Registrant by certain interstate
pipelines, the total reimbursement obligation of all working interest owners in
Registrant-operated wells approximated $13 million as of November, 1997. During
this period, Registrant estimated that its reimbursement obligation totaled
approximately $6.7 million, being approximately $2.7 million of principal and
$4.0 million of interest. Approximately 12.5% of such amount would be owed by
Registrant's royalty owners.

Neither the FERC nor Congress has provided the first sellers with any
generic relief on this issue. However, the FERC has permitted the filing of
individual adjustment proceedings by each first seller. Registrant has filed
such adjustment proceedings requesting that its ad valorem tax refund
obligation be reduced. The FERC has not ruled in any of Registrant's adjustment
proceedings.

During the period February through July, 1998, Registrant paid, under
protest, approximately $1,379,000 to four interstate pipelines as partial ad
valorem tax reimbursement and escrowed approximately $6,370,000 pending the
FERC's decision in Registrant's adjustment proceedings. The escrowed amount
includes Registrant's share of the amount of reimbursement obligation allegedly
owed by Registrant's royalty owners. During calendar 2000, settlement
negotiations have occurred among the pipelines, first sellers and other
interested parties. Any settlement among such parties must be approved by the
FERC. A settlement agreement in the Colorado Interstate Gas proceeding has
recently been approved by the FERC. Registrant's settlement amount is less than
the amount that Registrant had escrowed in the Colorado Interstate Gas
proceeding. The final outcome of the other settlement negotiations and the
final resolution of these proceedings cannot be predicted at this time.

I-19
<PAGE> 22
However, the Registrant believes that Registrant's aggregate refund liability
in all pipeline proceedings will not exceed the amount that Registrant has
escrowed for such liability.

Additional proposals and proceedings that might affect the oil and gas
industry are pending before the Congress, the FERC, and the courts. The
Registrant cannot predict when or whether any such proposals may become
effective. In the past, the natural gas industry has been very heavily
regulated. There is no assurance that the current regulatory approach pursued by
the FERC will continue. Notwithstanding the foregoing, it is anticipated that
compliance with existing federal, state and local laws, rules and regulations
will not have a material adverse effect upon the capital expenditures, earnings
or competitive position of the Registrant.

Federal Income Taxation

The Registrant's oil and gas operations, and the petroleum industry in
general, are affected by certain federal income tax laws. The Registrant has
considered the effects of such federal income tax laws on its operations and
does not anticipate that there will be any material impact on the capital
expenditures, earnings or competitive position of the Registrant.

Environmental Laws

The Registrant's activities are subject to existing federal and state
laws and regulations governing environmental quality and pollution control.
Such laws and regulations may substantially increase the costs of exploring,
developing, or producing oil and gas and may prevent or delay the commencement
or continuation of a given operation. In the opinion of the Registrant's
management, its operations substantially comply with applicable environmental
legislation and regulations. The Registrant believes that compliance with
existing federal, state, and local laws, rules, and regulations regulating the
discharge of materials into the environment or otherwise relating to the
protection of the environment

I-20
<PAGE> 23
will not have any material effect upon the capital expenditures, earnings, or
competitive position of the Registrant.

Natural Gas Marketing

Helmerich & Payne Energy Services, Inc., ("HPESI") continues its
emphasis on the purchase of the Registrant's natural gas production. In
addition, HPESI purchases third-party gas for resale and provides compression,
gathering services and processing for a fee. During fiscal year 2000, HPESI's
sales of third-party gas constituted approximately 13% of the Registrant's
consolidated revenues.

HPESI sells natural gas to markets in the Midwest and Rocky Mountain
areas. HPESI's term gas sales contracts are for varied periods ranging from
three months to seven years. However, recent contracts have tended toward
shorter terms. The remainder of HPESI's gas is sold under spot market contracts
having a duration of 30 days or less. For fiscal 2000, HPESI's term gas sales
contracts provided for the sale of approximately 27 BCF of gas at prices which
were indexed to market prices. For fiscal 2001, HPESI currently has
approximately 15 BCF contracted at prices which are indexed to market prices.
The balance of HPESI's gas is selling at spot prices or is not yet contracted.
HPESI presently intends to fulfill such term sales contracts with a portion of
the gas reserves purchased from the Registrant as well as from its purchases of
third-party gas. See pages I-13 through I-20 regarding the market, competition,
and regulation of natural gas.

REAL ESTATE OPERATIONS

The Registrant's real estate operations are conducted exclusively
within the metropolitan area of Tulsa, Oklahoma. Its major holding is Utica
Square Shopping Center, consisting of fifteen separate buildings, with parking
and other common facilities covering an area of approximately 30 acres.
Fourteen of these buildings provide approximately 405,709 square feet of net
leasable retail sales and storage space (98% of which is currently leased) and
approximately 18,590 square feet of net

I-21
<PAGE> 24

leasable general office space (99% of which is currently leased). Approximately
24% of the general office space is occupied by the Registrant's real estate
operations. The fifteenth building is an eight-story medical office building
which provides approximately 76,379 square feet of net leasable medical office
space (50% of which is currently leased). Due to increased operating costs and
related business considerations, the Registrant intends to close the Medical
Building in January 2002. All tenant leases in the Medical Building shall have
expired prior to such date. The Registrant has not decided as to the future use
of the area upon which the Medical Building is located. The Registrant has a
two-level parking garage located in the southwest corner of Utica Square that
can accommodate approximately 250 cars.

Registrant has completed a three-phase renovation for three major
existing tenants in Utica Square Shopping Center.

At the end of the 2000 fiscal year the Registrant 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. One condominium unit was sold during
fiscal 2000. Ten of the Registrant's units are currently leased.

The Registrant owns an eight-story office building located diagonally
across the street from Utica Square Shopping Center, containing approximately
87,000 square feet of net leasable general office and retail space. This
building houses the Registrant's principal executive offices. Approximately 11%
of this building was leased to third parties during fiscal 2000. Registrant
leases approximately 29,000 square feet of office space in Tulsa for
Registrant's oil and gas division.

The Registrant is also engaged in the business of leasing 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

I-22
<PAGE> 25

highways. Present occupancy is 100%. The Registrant also owns approximately 1.5
acres of undeveloped land lying adjacent to such warehouses.

Registrant owns approximately 253.5 acres in Southpark consisting of
approximately 240.5 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. Occupancy has
increased from 96% to 100%. The Registrant believes that a high quality office
park, with peripheral commercial, office/warehouse, and hotel sites, is the
best development use for the remaining land. However, no development plans are
currently pending.

Registrant is a party to a condemnation proceeding initiated during
fiscal 2000 by the Oklahoma Department of Transportation which seeks to
purchase approximately 15.14 acres of undeveloped real property adjacent to a
major expressway in Southpark. The parties are presently litigating the fair
market value of such tract. It is expected that this matter will be concluded
during calendar 2001.

The Registrant also owns a five-building complex called Tandem
Business Park. The project 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/warehouse space. Occupancy has increased from 96% to 100%
during fiscal 2000. The Registrant also owns a twelve-building complex,
consisting of approximately 204,600 square feet of office/warehouse space,
called Tulsa Business Park. The project is located south of the Space Center
facility, separated by a city street, and contains approximately 12 acres.
During fiscal 2000, occupancy has decreased from 96% to 93%. However, on
November 1, 2000, Registrant added a new tenant and increased total occupancy
to 94%.

I-23
<PAGE> 26

The Registrant also 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 located on approximately 2.5 acres. During fiscal 2000, occupancy has
decreased from 100% to 94%. The second, called Maxim Place, consists of one
office/warehouse building containing approximately 33,750 square feet and
located on approximately 2.25 acres. During fiscal 2000, occupancy has remained
at 100%.

Registrant believes that the recent increase in demand for
multi-tenant warehouse space in the Tulsa market will continue. Registrant is
unable to determine how long this increase in demand will continue.

Competition

The Registrant 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.
Registrant'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
Registrant and have more contemporary facilities.

FINANCIAL

Information relating to Revenue and Operating Profit by Business
Segments may be found on pages 9 and 31 through 32 of the Registrant's Annual
Report to Shareholders for fiscal 2000, which is incorporated herein by
reference.

EMPLOYEES

The Registrant had 2,312 employees within the United States (9 of
which were part-time employees) and 1,294 employees in international operations
as of September 30, 2000.

I-24
<PAGE> 27

Item 2. PROPERTIES

CONTRACT DRILLING

The following table sets forth certain information concerning the
Registrant's domestic drilling rigs as of September 30, 2000:

<TABLE>
<CAPTION>
Rig Registrant's Optimum Working Present
Designation Classification Depth in Feet Location
----------- -------------- --------------- ---------------
<S> <C> <C> <C>
158 Medium Depth 10,000 Texas
110 Medium Depth 12,000 Texas
156 Medium Depth 12,000 Texas
159 Medium Depth 12,000 Texas
141 Medium Depth 14,000 Texas
142 Medium Depth 14,000 Texas
143 Medium Depth 14,000 Texas
145 Medium Depth 14,000 Texas
155 Medium Depth 14,000 Texas
96 Medium Depth 16,000 Oklahoma
118 Medium Depth 16,000 Texas
119 Medium Depth 16,000 Texas
120 Medium Depth 16,000 Texas
147 Medium Depth 16,000 Texas
154 Medium Depth 16,000 Texas
162 Medium Depth 16,000 Texas
164 Medium Depth 16,000 Texas
165 Medium Depth 16,000 Texas
166 Medium Depth 16,000 Texas
167 Medium Depth 16,000 Texas
168 Medium Depth 16,000 Texas
169 Medium Depth 16,000 Texas
108 Medium Depth 18,000 Gulf of Mexico
79 Deep 20,000 Louisiana
80 Deep 20,000 Texas
89 Deep 20,000 Texas
91 Deep 20,000 Gulf of Mexico
92 Deep 20,000 Oklahoma
94 Deep 20,000 Texas
98 Deep 20,000 Oklahoma
122 Deep 20,000 Louisiana
203 Deep 20,000 Gulf of Mexico
97 Deep 26,000 Texas
99 Deep 26,000 Texas
</TABLE>

I-25
<PAGE> 28

<TABLE>
<CAPTION>
Rig Registrant's Optimum Working Present
Designation Classification Depth in Feet Location
----------- -------------- --------------- ---------------
<S> <C> <C> <C>
137 Deep 26,000 Texas
149 Deep 26,000 Texas
72 Very Deep 30,000 Alabama
73 Very Deep 30,000 Texas
100 Very Deep 30,000 Gulf of Mexico
105 Very Deep 30,000 Gulf of Mexico
106 Very Deep 30,000 Gulf of Mexico
107 Very Deep 30,000 Gulf of Mexico
157 Very Deep 30,000 Texas
161 Very Deep 30,000 Texas
163 Very Deep 30,000 Louisiana
201 Very Deep 30,000 Gulf of Mexico
202 Very Deep 30,000 Gulf of Mexico
204 Very Deep 30,000 Gulf of Mexico
</TABLE>

The following table sets forth information with respect to the
utilization of the Registrant's domestic drilling rigs for the periods
indicated:

<TABLE>
<CAPTION>
Years ended September 30,
----------------------------------------
1996 1997 1998 1999 2000
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Number of rigs owned at end of
period 41 38 46 50 48

Average rig utilization rate
during period (1) 82% 88% 95% 75% 87%
</TABLE>

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

The following table sets forth certain information concerning the
Registrant's international drilling rigs as of September 30, 2000:

<TABLE>
<CAPTION>
Rig Registrant's Optimum Working Present
Designation Classification Depth in Feet Location
----------- ----------------------- --------------- ----------
<S> <C> <C> <C>
14 Workover/drilling 6,000 Venezuela
19 Workover/drilling 6,000 Venezuela
20 Workover/drilling 6,000 Venezuela
140 Medium Depth 10,000 Venezuela
171 Medium Depth 16,000 Bolivia
172 Medium Depth 16,000 Bolivia
22 Medium Depth (Heli Rig) 18,000 Ecuador
</TABLE>

I-26
<PAGE> 29

<TABLE>
<CAPTION>
Rig Registrant's Optimum Working Present
Designation Classification Depth in Feet Location
----------- ----------------------- --------------- ----------
<S> <C> <C> <C>
23 Medium Depth (Heli Rig) 18,000 Ecuador
132 Medium Depth 18,000 Ecuador
176 Medium Depth 18,000 Ecuador
121 Deep 20,000 Ecuador
173 Deep 20,000 Bolivia
45 Deep 26,000 Venezuela
82 Deep 26,000 Venezuela
83 Deep 26,000 Venezuela
117 Deep 26,000 Venezuela
123 Deep 26,000 Bolivia
138 Deep 26,000 Ecuador
148 Deep 26,000 Venezuela
160 Deep 26,000 Venezuela
170 Deep (Heli Rig) 26,000 Texas
113 Very Deep 30,000 Venezuela
115 Very Deep 30,000 Venezuela
116 Very Deep 30,000 Venezuela
125 Very Deep 30,000 Colombia
127 Very Deep 30,000 Venezuela
128 Very Deep 30,000 Venezuela
129 Very Deep 30,000 Venezuela
133 Very Deep 30,000 Colombia
134 Very Deep 30,000 Colombia
135 Very Deep 30,000 Colombia
136 Very Deep 30,000 Colombia
150 Very Deep 30,000 Venezuela
151 Very Deep 30,000 Bolivia
152 Very Deep 30,000 Colombia
153 Very Deep 30,000 Argentina
174 Very Deep 30,000 Argentina
175 Very Deep 30,000 Bolivia
177 Very Deep 30,000 Argentina
139 Super Deep 30,000+ Colombia
</TABLE>

I-27
<PAGE> 30

The following table sets forth information with respect to the
utilization of the Registrant's international drilling rigs for the periods
indicated:

Average rig utilization rate
during period (1) 85% 91% 88% 53% 47%

</TABLE>

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

OIL AND GAS DIVISION

All of the Registrant's oil and gas operations and holdings are
located within the continental United States.

Crude Oil Sales

The Registrant's net sales of crude oil and condensate for the fiscal
years 1998 through 2000 are shown below:

<TABLE>
<CAPTION>
Average Sales Average Lifting
Year Net Barrels Price per Barrel Cost per Barrel
---- ----------- ---------------- ---------------
<S> <C> <C> <C>

1998 701,180 $14.74 $7.40
1999 649,370 $14.60 $7.02
2000 880,304 $27.95 $6.06
</TABLE>

Natural Gas Sales

The Registrant's net sales of natural and casinghead gas for the three
fiscal years 1998 through 2000 are as follows:

<TABLE>
<CAPTION>
Average Sales Average Lifting
Year Net MCF Price per MCF Cost per MCF
---- ---------- ------------- --------------
<S> <C> <C> <C>
1998 42,862,300 $2.04 $0.3110
1999 44,240,332 $1.83 $0.3300
2000 46,922,752 $2.79 $0.3704
</TABLE>

I-28
<PAGE> 31

Following is a summary of the net wells drilled by the Registrant for
the fiscal years ended September 30, 1998, 1999, and 2000:

<TABLE>
<CAPTION>
Exploratory Wells Development Wells
------------------------- --------------------------
1998 1999 2000 1998 1999 2000
----- ----- ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Productive 1.910 2.917 9.735 29.614 13.846 23.862
Dry 2.900 2.615 5.7017 1.310 4.502 3.403
</TABLE>

On September 30, 2000, the Registrant was in the process of drilling
or completing nine gross or 6.237 net wells.

Acreage Holdings

The Registrant's holdings of acreage under oil and gas leases, as of
September 30, 2000, were as follows:

<TABLE>
<CAPTION>
Developed Acreage Undeveloped Acreage
--------------------------- ---------------------------
Gross Net Gross Net
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Arkansas 3,068.23 1,725.11 -0- -0-
Colorado -0- -0- 320.00 160.00
Kansas 125,599.29 86,931.89 11,497.94 9,936.14
Louisiana 3,414.79 1,525.59 12,560.16 4,966.79
Michigan -0- -0- 13,518.76 13,135.42
Montana 1,997.19 392.99 2,708.95 969.73
Nebraska 480.00 168.00 -0- -0-
Nevada -0- -0- 4,864.04 4,864.04
New Mexico 760.00 96.63 121.88 40.22
North Dakota 200.00 11.52 -0- -0-
Oklahoma 125,158.99 50,675.44 8,178.63 4,804.15
Texas 89,290.15 42,949.27 184,108.75 76,230.86
Wyoming -0- -0- 40.00 105.59
---------- ---------- ---------- ----------
Total 349,968.64 184,476.44 238,319.11 115,212.94
</TABLE>

Acreage is held under leases which expire in the absence of production
at the end of a prescribed primary term, and is, therefore, subject to
fluctuation from year to year as new leases are acquired, old leases expire, and
other leases are allowed to terminate by failure to pay annual delay

I-29
<PAGE> 32

rentals. As shown in the above table, the Registrant has a significant portion
of its undeveloped acreage in Texas, with eight major prospects accounting for
63,191 net acres. The average minimum remaining term of leases in these eight
prospects is approximately 23 months.

Productive Wells

The Registrant's total gross and net productive wells as of September
30, 2000, were as follows:

<TABLE>
<CAPTION>
Oil Wells Gas Wells
------------------ -------------------
Gross Net Gross Net
----- ---- ----- ---
<S> <C> <C> <C> <C>
3,415 163 956 453
</TABLE>

Additional information required by this item with respect to the
Registrant's oil and gas operations may be found on pages I-11 through I-21 of
Item 1. BUSINESS, and pages 23 through 34 of the Registrant's Annual Report to
Shareholders for fiscal 2000, "Notes to Consolidated Financial Statements" and
"Note 14 Supplementary Financial Information for Oil and Gas Producing
Activities."

Estimates of oil and gas reserves, future net revenues, and present
value of future net revenues were prepared by Netherland, Sewell & Associates,
Inc., 4950 Three Allen Center, 333 Clay Street, Houston, Texas 77002. Total oil
and gas reserve estimates do not differ by more than 5% from the total reserve
estimates filed with any other federal authority or agency.

REAL ESTATE OPERATIONS

See Item 1. BUSINESS, pages I-21 through I-24.

I-30
<PAGE> 33

STOCK

As of December 15, 2000:

The Registrant owned 312,546 shares of the common stock of SUNOCO,
Inc. and 184,500 shares of Kerr McGee Corporation which the Registrant received
in a stock merger for Registrant's 500,000 shares of Oryx Energy Company, Inc.

The Registrant owned 3,000,000 shares of the common stock of Atwood
Oceanics, Inc., a Houston, Texas based company engaged in offshore contract
drilling. The Registrant owns approximately 22% of Atwood.

The Registrant owned 1,480,000 shares of the common stock of
Schlumberger, Ltd.

The Registrant owned 240,000 shares of the common stock of Phillips
Petroleum Company, Inc.

The Registrant owned 1,000,000 shares of the common stock of
Occidental Petroleum Corporation, Inc.

The Registrant owned 175,000 shares of the common stock of Banc One
Corporation.

The Registrant owned 225,000 shares of the common stock of ONEOK Inc.

The Registrant owned 286,528 shares of the common stock of Transocean
Sedco Forex, Inc., which it received in a merger between Transocean Offshore
and the contract drilling division of Schlumberger.

The Registrant owned 84,175 shares of the common stock of Protein
Design Labs, Inc.

The Registrant also owned lesser holdings in several other publicly
traded corporations.

I-31
<PAGE> 34

Item 3. LEGAL PROCEEDINGS

There are no material legal proceedings pending against the Registrant.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the names and ages of the Registrant's
executive officers, together with all positions and offices held with the
Registrant 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.

W. H. Helmerich, III, 77 Director since 1949; Chairman of the Board
Chairman of the Board since 1960

Hans Helmerich, 42 Director since 1987; President and Chief
President Executive Officer since 1989

George S. Dotson, 59 Director since 1990; Vice President,
Vice President Drilling since 1977 and President and
Chief Operating Officer of Helmerich &
Payne International Drilling Co. since 1977

Douglas E. Fears, 51 Vice President, Finance, since 1988
Vice President

Steven R. Mackey, 49 Secretary since 1990; Vice President and
Vice President and General Counsel since 1988
Secretary

Steven R. Shaw, 49 Vice President, Production, since 1985;
Vice President Vice President, Exploration and Production
since 1996

Gordon K. Helm, 47 Chief Accounting Officer of the Registrant;
Controller Controller since December 10, 1993

I-32
<PAGE> 35

PART II

Item 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS

The principal market on which the Registrant's common stock is traded
is the New York Stock Exchange. 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:

<TABLE>
<CAPTION>
1999 2000
----------------- -----------------
Quarter High Low High Low
------- ----- ----- ----- -----
<S> <C> <C> <C> <C>
First 24.50 16.75 27.44 19.13
Second 23.94 16.06 31.00 20.00
Third 26.75 20.38 37.75 29.06
Fourth 30.19 23.00 38.31 30.06
</TABLE>

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

<TABLE>
<CAPTION>
Paid per Share Total Payment
------------------- ----------------------------
Fiscal Fiscal
------------------- ----------------------------
Quarter 1999 2000 1999 2000
------- ------ ------ ---------- -----------
<S> <C> <C> <C> <C>
First $0.070 $0.070 $3,457,626 $3,474,612
Second 0.070 0.070 3,459,168 3,475,623
Third 0.070 0.070 3,464,109 3,484,189
Fourth 0.070 0.075 3,468,377 3,740,863
</TABLE>

The Registrant paid a cash dividend of $0.075 per share on December 1,
2000, to shareholders of record on November 15, 2000. Payment of future
dividends will depend on earnings and other factors.

As of December 15, 2000, there were 1,170 record holders of the
Registrant's common stock as listed by the transfer agent's records.

II-1
<PAGE> 36

Item 6. SELECTED FINANCIAL DATA

The Five-year Summary of Selected Financial Data described below
excludes results of Natural Gas Odorizing, Inc. ("NGO") operations. Registrant,
on August 30, 1996, sold its wholly-owned subsidiary, NGO, to Occidental
Petroleum Corporation.

<TABLE>
<CAPTION>
Five-year Summary of Selected Financial Data
-----------------------------------------------------------------------------------
1996 1997 1998 1999 2000
------------ ------------- ---------- ---------- ----------
(in thousands)
<S> <C> <C> <C> <C> <C>
Sales, operating,
Sand other revenues $ 393,255 $ 517,859 $ 636,640 $ 564,319 $ 631,095

Income from con-
tinuing operations 45,426 84,186 101,154 42,788 82,300

Income from continuing
operations per common share:
Basic 0.92 1.69 2.03 0.87 1.66
Diluted 0.91 1.67 2.00 0.86 1.64

Total assets 821,914 1,033,595 1,090,430 1,109,699 1,259,492

Long-term debt -0- -0- 50,000 50,000 50,000

Cash dividends declared
per common share 0.255 0.26 0.275 0.28 0.285
</TABLE>

II-2
<PAGE> 37

The following Five-year Summary of Selected Financial Data includes
only the results of NGO operations.

Five-year Summary of Selected Financial Data for NGO
----------------------------------------------------
<TABLE>
<CAPTION>
1996 1997 1998 1999 2000
---------- ---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C> <C>
Sales, operating,
and other revenues $ 19,540 $ -0- $ -0- $ -0- $ -0-

Income from discontinued
operations 3,090 -0- -0- -0- -0-

Income from discontinued
operations per common share:
Basic 0.06 -0- -0- -0- -0-
Diluted 0.06 -0- -0- -0- -0-
</TABLE>

Item 7. MANAGEMENT'S DISCUSSION & ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION

Information required by this item may be found on pages 10 through 17,
Management's Discussion & Analysis of Results of Operations and Financial
Condition, in the Registrant's Annual Report to Shareholders for fiscal 2000,
which is incorporated herein by reference.

II-3
<PAGE> 38

Item 7(a). QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information required by this item may be found on the following pages
of Management's Discussion & Analysis of Results of Operations and Financial
Condition, in the Registrant's Annual Report to Shareholders for fiscal 2000,
which is incorporated herein by reference:

<TABLE>
<CAPTION>
Market Risk Page
----------- ----
<S> <C>
o Foreign Currency Exchange Rate Risk 13, 23
o Commodity Price Risk 14-15, 30
o Interest Rate Risk 16-17, 24
o Equity Price Risk 17, 23
</TABLE>

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information required by this item may be found on pages 18 through 34
in the Registrant's Annual Report to Shareholders for fiscal 2000, which is
incorporated herein by reference.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE

None.

II-4
<PAGE> 39

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information required under this item with respect to Directors and
with respect to any delinquent filers pursuant to Item 405 of Regulation S-K is
incorporated by reference from the Registrant's definitive Proxy Statement for
the Annual Meeting of Stockholders to be held March 7, 2001, to be filed with
the Commission not later than 120 days after September 30, 2000. See page I-32
for information covering the Registrant's Executive Officers.

Item 11. EXECUTIVE COMPENSATION

This information is incorporated by reference from the Registrant's
definitive Proxy Statement for the Annual Meeting of Stockholders to be held
March 7, 2001, to be filed with the Commission not later than 120 days after
September 30, 2000.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

III-1
<PAGE> 40

PART IV

Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) Document List

1. The financial statements called for by Item 8 are
incorporated herein by reference from the Registrant's Annual
Report to Shareholders for fiscal 2000.

2. Exhibits required by Item 601 of Regulation S-K:

Exhibit Number:

<TABLE>
<CAPTION>
<S> <C>
3.1 Restated Certificate of Incorporation and Amendment
to Restated Certificate of Incorporation of the
Registrant are incorporated herein by reference to
Registrant's Annual Report on Form 10-K to the
Securities and Exchange Commission for fiscal 1996.

3.2 By-Laws of the Registrant are incorporated herein by
reference to Registrant's Annual Report on Form 10-K
to the Securities and Exchange Commission for fiscal
1996.

4.1 Rights Agreement dated as of January 8, 1996,
between the Registrant and The Liberty National Bank
and Trust Company of Oklahoma City, N.A. is
incorporated herein by reference to the Registrant's
Form 8-A, dated January 17, 1996.

* 10.1 Consulting Services Agreement between W. H.
Helmerich, III, and the Registrant effective January
1, 1990, as amended is incorporated herein by
reference to Registrant's Annual Report on Form 10-K
to the Securities and Exchange Commission for fiscal
1996.

* 10.2 Supplemental Retirement Income Plan for Salaried
Employees of Helmerich & Payne, Inc. is incorporated
herein by reference to Registrant's Annual Report on
Form 10-K to the Securities and Exchange Commission
for fiscal 1996.

* 10.3 Helmerich & Payne, Inc. 1990 Stock Option Plan is
incorporated herein by reference to Registrant's
Annual Report on Form 10-K to the Securities and
Exchange Commission for fiscal 1996.
</TABLE>
- -----------------------

* Compensatory Plan or Arrangement.

IV-1
<PAGE> 41

<S> <C>
* 10.4 Form of Nonqualified Stock Option Agreement for
the 1990 Stock Option Plan is incorporated by
reference to Exhibit 99.2 to the Registrant's
Registration Statement No. 33-55239 on Form S-8,
dated August 24, 1994.

* 10.5 Supplemental Savings Plan for Salaried Employees of
Helmerich and Payne, Inc. is incorporated herein by
reference from Registrant's Annual Report on Form
10-K to the Securities and Exchange Commission for
fiscal 1999.

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

* 10.7 Form of Nonqualified Stock Option Agreement for
Helmerich & Payne, Inc. 1996 Stock Incentive Plan is
incorporated by reference to Exhibit 99.2 to
Registrant's Registration Statement on Form S-8
dated September 4, 1997.

* 10.8 Form of Restricted Stock Agreement for Helmerich &
Payne, Inc. 1996 Stock Incentive Plan is
incorporated by reference from Registrant's Annual
Report on Form 10-K to the Securities and Exchange
Commission for fiscal 1997.

* 10.9 Helmerich & Payne, Inc. Non-Employee Directors Stock
Compensation Plan is hereby incorporated by
reference to Exhibit "B" of Registrant's Proxy
Statement dated January 27, 1997.

13. The Registrant's Annual Report to Shareholders for
fiscal 2000.

22. Subsidiaries of the Registrant.

23.1 Consent of Independent Auditors.

27. Financial Data Schedule.

</TABLE>
(b) Report on Form 8-K

None.

- -----------------------

* Compensatory Plan or Arrangement.

IV-2
<PAGE> 42

SIGNATURES

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

HELMERICH & PAYNE, INC.

By /s/ HANS HELMERICH
--------------------------
Hans Helmerich, President
(Chief Executive Officer)
Date: December 28, 2000

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
Registrant and in the capacities and on the dates indicated:

<TABLE>

<S> <C>

By /s/ WILLIAM L. ARMSTRONG By /s/ GLENN A. COX
--------------------------------- ---------------------------------
William L. Armstrong, Director Glenn A. Cox, Director
Date: December 28, 2000 Date: December 28, 2000

By /s/ GEORGE S. DOTSON By /s/ HANS HELMERICH
--------------------------------- ---------------------------------
George S. Dotson, Director Hans Helmerich, Director and CEO
Date: December 28, 2000 Date: December 28, 2000

By /s/ W. H. HELMERICH, III By /s/ L. F. ROONEY, III
--------------------------------- ---------------------------------
W. H. Helmerich, III, Director L. F. Rooney, III, Director
Date: December 28, 2000 Date: December 28, 2000

By /s/ EDWARD B. RUST, JR. By /s/ GEORGE A. SCHAEFER
--------------------------------- ---------------------------------
Edward B. Rust, Jr., Director George A. Schaefer, Director
Date: December 28, 2000 Date: December 28, 2000

By /s/ JOHN D. ZEGLIS By /s/ DOUGLAS E. FEARS
--------------------------------- ---------------------------------
John D. Zeglis, Director Douglas E. Fears
Date: December 28, 2000 (Principal Financial Officer)
Date: December 28, 2000

By /s/ GORDON K. HELM
---------------------------------
Gordon K. Helm, Controller
(Principal Accounting Officer)
Date: December 28, 2000
</TABLE>

<PAGE> 43

EXHIBIT INDEX

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
3.1 Restated Certificate of Incorporation and Amendment
to Restated Certificate of Incorporation of the
Registrant are incorporated herein by reference to
Registrant's Annual Report on Form 10-K to the
Securities and Exchange Commission for fiscal 1996.

3.2 By-Laws of the Registrant are incorporated herein by
reference to Registrant's Annual Report on Form 10-K
to the Securities and Exchange Commission for fiscal
1996.

- --------------------

* Compensatory Plan or Arrangement.

<PAGE> 44

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
* 10.4 Form of Nonqualified Stock Option Agreement for
the 1990 Stock Option Plan is incorporated by
reference to Exhibit 99.2 to the Registrant's
Registration Statement No. 33-55239 on Form S-8,
dated August 24, 1994.

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

* 10.9 Helmerich & Payne, Inc. Non-Employee Directors Stock
Compensation Plan is hereby incorporated by
reference to Exhibit "B" of Registrant's Proxy
Statement dated January 27, 1997.

13. The Registrant's Annual Report to Shareholders for
fiscal 2000.

22. Subsidiaries of the Registrant.

23.1 Consent of Independent Auditors.

27. Financial Data Schedule.
</TABLE>

- --------------------

* Compensatory Plan or Arrangement.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>2
<FILENAME>d82779ex13.txt
<DESCRIPTION>ANNUAL REPORT TO SHAREHOLDERS FOR FISCAL 2000
<TEXT>

<PAGE> 1
EXHIBIT 13

HELMERICH & PAYNE, INC. ANNUAL REPORT FOR 2000

REVENUE BREAKDOWN FOR 2000

[PIE CHART]

<TABLE>
<S> <C>
CONTRACT DRILLING
International 22%
Domestic 34%

OIL AND GAS
Exploration & Production 25%
Natural Gas Marketing 13%

Real Estate 1%
Investments and Other Income 5%
</TABLE>

FINANCIAL HIGHLIGHTS

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999
----------------- -----------------
<S> <C> <C>

Revenues $ 631,095,000 $ 564,319,000
Net Income $ 82,300,000 $ 42,788,000
Diluted Earnings Per Share $ 1.64 $ .86
Dividends Paid Per Share $ .285 $ .28
Capital Expenditures $ 131,932,000 $ 122,951,000
Total Assets $ 1,259,492,000 $ 1,109,699,000
</TABLE>

<PAGE> 2

PRESIDENT'S LETTER

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

Listening to Al Gore's concession speech tonight, after a remarkable thirty-six
days of post election rancor, left mixed emotions. On the positive side, tanks
in the streets were never even a consideration. As Vice President Gore
eloquently stated, "Ours is a nation not under man, but under God and law." Our
great democracy was tested and prevailed once again.

At the same time, it is discouraging to see the level of political discourse
deteriorate to such lows. Congressman Tom DeLay's charge of Al Gore trying to
"steal the election" or Jesse Jackson's claim that George W. Bush had won using
"Nazi tactics" is why both the victor and the vanquished called for a spirit of
reconciliation.

What are the prospects for progress on important policy matters? Sizing up the
challenges facing the new President, one political analyst predicted he would
spend the next four years appeasing his enemies and betraying his friends.

Let's hope not. Constructive debate is one thing and following a zero-sum
approach that in the end hurts every American is something altogether different.
Stalemate is not a luxury available to us. Take energy policy as an example.

The new administration inherits an energy quagmire: Oil and gas prices setting
ten year highs, the reemergence of a stronger, more cohesive OPEC, and a
precarious balance between tight supplies and increasing demand. This situation
underscores the absence of any thought-out national energy policy. We are left
with political jockeying and farce, illustrated by a year of pitiful pleading
with OPEC for more

2
<PAGE> 3

production and the pre-election "emergency" release of thirty million barrels of
oil from the strategic oil reserve.

For years, the industry has faced a punitive regulatory and tax structure, been
blocked from constructing new refinery capacity, and had the most promising
domestic exploratory areas for new supply locked away. Progress should be met by
the highest standards of environmental sensitivity and worker safety. It should
not be sacrificed on the altar of partisan politics.

George W. Bush set the right tone tonight from the Texas Capitol, "I know
America wants reconciliation and unity. I know Americans want progress. And we
must seize this moment and deliver. Together, guided by a spirit of common
sense, common courtesy and common goals, we can unite and inspire the American
citizens."

We should all wish him Godspeed.

This year marks the fiftieth year of my father's service as a Director to the
Company. His wisdom, energy, and intuitive understanding of the industry will
continue to serve our Co-owners well in the years ahead. I consider it an honor
to have worked with him for twenty years.

Sincerely,

/s/ HANS HELMERICH
Hans Helmerich
December 13, 2000 President

3
<PAGE> 4

DRILLING HELMERICH & PAYNE INTERNATIONAL DRILLING CO.

SUMMARY Helmerich & Payne International Drilling Co. owns 38 land rigs and ten
offshore platform rigs in the United States, and 40 land rigs located in the
countries of Venezuela (18), Colombia (7), Ecuador (6), Bolivia (6), and
Argentina (3). The Company also has four management contracts, three for
platform rigs operating offshore California and one for a platform rig operating
offshore Equatorial Guinea, West Africa. Additionally, the Company owns a 50
percent interest in an offshore platform rig that is currently stacked in
Australia.

Significant increases in the prices of crude oil and natural gas produced a
positive, but measured, response in terms of drilling activity during the year.
Led by activity increases in the U.S., the industry worldwide rig count rose by
one-third over the prior year. In contrast, the Company's key South American
markets did not respond to the improved commodity prices. Total contract
drilling revenues and operating profit declined in 2000 by 11 and 24 percent,
respectively, primarily due to continued weakness in international markets.

FIVE-YEAR OPERATING SUMMARY

UNITED STATES

Revenues ............. $ 214,531 $ 213,647 $ 177,059 $ 140,294 $ 108,336
EBITDA ............... $ 71,163 $ 61,498 $ 60,053 $ 44,066 $ 24,409
Operating Profit ..... $ 35,808 $ 30,154 $ 35,817 $ 24,437 $ 10,066

Activity Days ........ 15,083 12,509 14,237 12,872 11,660
Rig Utilization ...... 87% 75% 95% 88% 82%

INTERNATIONAL

Revenues ............. $ 136,549 $ 182,987 $ 253,072 $ 176,651 $ 135,695
EBITDA ............... $ 47,853 $ 66,075 $ 82,650 $ 69,621 $ 53,603
Operating Profit ..... $ 9,753 $ 29,845 $ 50,834 $ 43,118 $ 31,176

Activity Days ........ 7,067 8,442 12,832 12,253 11,215
Rig Utilization ...... 47% 53% 88% 91% 85%
</TABLE>

4
<PAGE> 5

INTERNATIONAL OPERATIONS Revenues and earnings before interest, taxes,
depreciation, and amortization (EBITDA) fell 25 and 28 percent, respectively, in
2000 and rig utilization declined to an average of 47 percent, compared with 53
percent in 1999. The majority of these declines came in the Company's largest
international markets of Venezuela and Colombia. At year-end only seven rigs
were under contract in Venezuela, but there are encouraging signs that more
activity is on the horizon in 2001. In anticipation of this, the Company is
adding three new top drive systems to the four already working in Venezuela.
Operations in Colombia also experienced a decline in activity in 2000, and at
year-end, four out of seven rigs were working in that country. The Company moved
three rigs from Colombia for new contracts in Argentina, Bolivia, and Ecuador
during 2000, and after the close of the year, a fourth rig returned for work in
the U.S. market. Operations in Ecuador increased from four to six rigs in 2000,
and after the close of the year the Company was moving an additional rig to
Ecuador from Venezuela. The Company also began work during the second quarter of
2000 under a management contract on Exxon-Mobil's Jade platform located offshore
Equatorial Guinea, West Africa.

UNITED STATES OPERATIONS Land rig utilization averaged 85 percent in 2000,
compared with 69 percent in 1999. The Company kept an average of 32 land rigs
working throughout 2000, seven more than in 1999. Gross daywork revenues and
EBITDA increased 45 and 113 percent, respectively, over the prior year. In
March, the Company announced that it had placed a firm order for 12 highly
mobile land rigs utilizing the same FlexRig(TM) design as the six rigs

(TM)FlexRig is a trademark of Helmerich & Payne International Drilling Co.

5
<PAGE> 6

constructed by the Company in 1998. The FlexRig's depth versatility of 8,000 to
18,000 feet, faster mobilization times, and state of the art technology, all
combine to increase drilling efficiency. The first rig out of the new order
should be ready by January 2001, with the remaining 11 scheduled two per quarter
thereafter. Two of the new FlexRigs will be working as part of a three-year,
five-rig contract in Wyoming that is scheduled to begin early in 2001.

Offshore platform rig utilization remained high throughout the year, averaging
94 percent, compared with 95 percent in 1999. Domestic offshore platform
revenues and EBITDA increased six and eight percent, respectively, in 2000 over
the prior year. The Company began an upgrade of rig 107 late in the year, which
should enable that rig to return to the market by the second quarter of 2001.
Additionally, tension-leg platform (TLP) rig 202 is earning a standby rate until
April 2001, when it is scheduled to begin working on Shell's new TLP, Brutus.

OUTLOOK Consolidations among active drilling customers, as well as the
collective memory of the volatile downturn experienced by the industry two years
ago, tempered the significant new exploration investment expected at the recent
higher commodity price levels. Yet demand is growing and, once again, the
Company and the industry are faced with the challenge of attracting, training,
and retaining qualified employees. Helmerich & Payne International Drilling Co.
has been successful in maintaining very low turnover among its skilled positions
and this experience at the rig level will enhance the Company's objective of
delivering reliable, incident-free operations in the field. In addition to
experienced and competent personnel, the Company is a leader in designing,
engineering, and constructing the newest and most modern rigs available in the
market.

6
<PAGE> 7

EXPLORATION & PRODUCTION HELMERICH & PAYNE, INC.

SUMMARY Helmerich & Payne, Inc. explores for and produces oil and natural gas
primarily in the states of Oklahoma, Kansas, Texas, and Louisiana. The Company
also markets natural gas through its wholly-owned subsidiary, Helmerich & Payne
Energy Services, Inc. In 2000, the Company produced approximately 880,000
barrels of oil and 47 billion cubic feet (Bcf) of natural gas, increases of 36
and six percent, respectively, over the previous year. The Company finished the
year with proved reserves of 6.3 million barrels of oil and 262 Bcf of natural
gas, compared with 4.8 million barrels and 240 Bcf in 1999.

The Company received an average price of $27.95 per barrel for oil and $2.79 per
thousand cubic feet (Mcf) for natural gas in 2000, compared with $14.60 and
$1.83 in 1999. Higher production and commodity prices propelled a 64 percent
increase in exploration and production revenues in 2000, and a record $66.6
million in operating profit. Helmerich and Payne Energy Services, Inc. also
reported record results in 2000, with revenues and operating profit increases of
46 and 19 percent, respectively.

EXPLORATION ACTIVITIES In 2000, the Company participated in 81(42.7 net) wells,
of which 65 (33.6 net) were productive and 16 (9.1 net) were dry holes. Over
one-third of the Company's net wells were exploration risks in 2000, more than
double the annual average number of net exploratory wells drilled over the
previous five-year period. A focal area this year was Jefferson County, Texas,
where the Company has experienced an overall 71 percent success rate utilizing
3D seismic. There remain several additional exploration opportunities in this
area, which should be drilled during 2001.

7
<PAGE> 8

The Company also succeeded in two out of three wells drilled in Reeves County,
Texas, during the year, which were producing at a combined gross rate of 9,000
Mcf per day at year-end.

FIVE-YEAR OPERATING SUMMARY

Revenues ............................ $ 157,583 $ 95,953 $ 98,696 $ 111,512 $ 76,643
Operating Profit .................... $ 66,604 $ 11,245 $ 28,088 $ 55,191 $ 26,333

Average Oil Price per barrel ........ $ 27.95 $ 14.60 $ 14.74 $ 20.77 $ 19.00
Oil Production (barrels) ............ 880,304 649,370 701,180 985,633 809,571
Proved Oil Reserves (barrels) ....... 6,305,137 4,833,898 4,761,313 5,805,386 6,468,116

Average Natural Gas Prices per Mcf .. $ 2.79 $ 1.83 $ 2.04 $ 2.24 $ 1.75
Natural Gas Production (Mcf) ........ 46,922,752 44,240,332 42,862,300 40,463,374 34,535,184
Proved Natural Gas Reserves (Bcf) ... 262.5 239.6 251.6 263.2 272.3

Gross Wells Completed ............... 81.0 49.0 62.0 100.0 63.0
Net Wells Completed ................. 42.7 23.9 35.7 49.3 35.3
Net Dry Holes ....................... 9.1 7.1 4.2 9.6 7.3
</TABLE>

OUTLOOK Five years ago, the Company embarked on a plan to improve exploration
success by increasing both the quantity and quality of its exploration
professionals and by organizing in geographically-focused teams. In 2000, the
Company recorded an $.87 per Mcf equivalent finding cost, as well as a 12
percent growth in proved reserves. With this improved performance, the Company
is poised to grow internally with a number of quality exploration prospects, and
has also begun to review other means of enhancing growth. Toward that end, the
Company retained the investment banking firm of Petrie Parkman & Co. this year
to assist in identifying and developing strategic alternatives for the Oil and
Gas Division.

8
<PAGE> 9

REVENUES AND OPERATING PROFIT BY BUSINESS SEGMENTS
HELMERICH & PAYNE, INC.

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
--------- --------- ---------
(in thousands)
<S> <C> <C> <C>
SALES AND OTHER REVENUES:
Contract Drilling - Domestic ......... $ 214,531 $ 213,647 $ 177,059
Contract Drilling - International .... 136,549 182,987 253,072
--------- --------- ---------
Total Contract Drilling ........... 351,080 396,634 430,131
--------- --------- ---------

Exploration and Production ........... 157,583 95,953 98,696
Natural Gas Marketing ................ 80,907 55,259 53,499
--------- --------- ---------
Total Oil and Gas Operations ...... 238,490 151,212 152,195
--------- --------- ---------

Real Estate .......................... 8,999 8,671 8,922
Other ................................ 32,526 7,802 45,392
--------- --------- ---------
Total Revenues ............................ $ 631,095 $ 564,319 $ 636,640
========= ========= =========

OPERATING PROFIT:
Contract Drilling - Domestic ......... $ 35,808 $ 30,154 $ 35,817
Contract Drilling - International .... 9,753 29,845 50,834
--------- --------- ---------
Total Contract Drilling ........... 45,561 59,999 86,651
--------- --------- ---------

Exploration and Production ........... 66,604 11,245 28,088
Natural Gas Marketing ................ 5,271 4,418 2,418
--------- --------- ---------
Total Oil and Gas Operations ...... 71,875 15,663 30,506
--------- --------- ---------

Real Estate .......................... 5,346 5,338 5,371
--------- --------- ---------
Total Operating Profit ............ 122,782 81,000 122,528
--------- --------- ---------

OTHER:
Income from investments .............. 31,973 7,757 44,603
General and administrative expense ... (11,578) (14,198) (11,762)
Interest expense ..................... (3,076) (6,481) (942)
Corporate depreciation ............... (2,152) (1,565) (1,280)
Other corporate expense .............. (1,186) (1,575) (927)
--------- --------- ---------
Total Other ....................... 13,981 (16,062) 29,692
--------- --------- ---------
INCOME BEFORE INCOME TAXES AND
EQUITY IN INCOME OF AFFILIATE ........ $ 136,763 $ 64,938 $ 152,220
========= ========= =========
</TABLE>

Note: See Note 13 (pages 30, 31 and 32) for complete segment disclosure.

9
<PAGE> 10

MANAGEMENT'S DISCUSSION & ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
HELMERICH & PAYNE, INC.

RISK FACTORS AND FORWARD-LOOKING STATEMENTS

The following discussion should be read in conjunction with the consolidated
financial statements and related notes included elsewhere herein. The Company's
future operating results may be affected by various trends and factors, which
are beyond the Company's control. These include, among other factors,
fluctuations in oil and natural gas prices, expiration or termination of
drilling contracts, currency exchange gains and losses, changes in general
economic conditions, rapid or unexpected changes in technologies, and uncertain
business conditions that affect the Company's businesses. Accordingly, past
results and trends should not be used by investors to anticipate future results
or trends.

With the exception of historical information, the matters discussed in
Management's Discussion & Analysis of Results of Operations and Financial
Condition include forward-looking statements. These forward-looking statements
are based on various assumptions. The Company cautions that, while it believes
such assumptions to be reasonable and makes them in good faith, assumed facts
almost always vary from actual results. The differences between assumed facts
and actual results can be material. The Company is including this cautionary
statement to take advantage of the "safe harbor" provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements made
by, or on behalf of, the Company. The factors identified in this cautionary
statement are important factors (but not necessarily all important factors) that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by, or on behalf of, the Company.

RESULTS OF OPERATIONS

All per share amounts included in the Results of Operations discussion are
stated on a diluted basis. Helmerich & Payne, Inc.'s net income for 2000 was
$82,300,000 ($1.64 per share), compared with net income of $42,788,000 ($0.86
per share) in 1999, and $101,154,000 ($2.00 per share) in 1998. Included in the
Company's net income, but not related to its operations, were after-tax gains
from the sale of investment securities of $8,152,000 ($0.16 per share) in 2000,
$1,562,000 ($0.03 per share) in 1999, and $23,417,000 ($0.46 per share) in 1998.
In addition to income from security sales, the Company also recorded net income
during 2000 of $6,637,000 ($0.13 per share) from gains relating to non-monetary
dividends received. Also

10
<PAGE> 11

included is the Company's portion of income from its equity affiliate, Atwood
Oceanics, Inc., which was $0.06 per share in 2000, $0.07 per share in 1999, and
$0.11 per share in 1998. Net income also included non-cash charges of $2,502,000
($0.05 per share) in 2000, $6,237,000 ($0.13 per share) in 1999, and $3,356,000
($0.07 per share) in 1998 related to write-downs of producing properties as
described in Note 1 of Notes to Consolidated Financial Statements.

Consolidated revenues were $631,095,000 in 2000, $564,319,000 in 1999, and
$636,640,000 in 1998. The 12 percent increase from 1999 to 2000 was due to
higher oil and natural gas prices resulting in an increase of $87,278,000 in Oil
and Gas Division revenues and increased investment revenues of $24,216,000.
Partially offsetting these increases was a reduction of international contract
drilling revenues of $46,438,000. The 11 percent decline from 1998 to 1999 was
primarily due to the $70,085,000 reduction in international contract drilling
revenues. An increase in domestic contract drilling revenues of $36,588,000 was
offset by a decline in investment revenues of $36,846,000 during 1999.

Revenues from investments were $31,973,000 in 2000, $7,757,000 in 1999, and
$44,603,000 in 1998. Included in revenues from investments were pre-tax gains
from the sale of investment securities of $13,295,000 in 2000, $2,547,000 in
1999, and $38,421,000 in 1998. Interest income from short-term investments
increased in 2000 because the cash/cash equivalents were substantially higher in
2000 than in 1999 and 1998. Dividend income increased in 2000 due to $10,706,000
in non-monetary dividends received when three Company investees spun-off
subsidiaries to their shareholders.

Costs and expenses in 2000 were $494,332,000, 78 percent of revenues, compared
with 88 percent in 1999, and 76 percent in 1998. Operating costs, as a
percentage of operating revenues, were 53 percent in 2000, 60 percent in 1999,
and 58 percent in 1998. Operating costs, as a percentage of operating revenues,
declined from 1999 to 2000 primarily due to proportionately higher oil and gas
revenues.

Depreciation, depletion, and amortization (DD&A) expense increased by only 1.5
percent in 2000, but increased by approximately 24 percent from 1998 to 1999.
The increases were affected by write-downs of producing properties of $4,036,000
in 2000, $10,059,000 in 1999, and $5,413,000 in 1998, which are included in
DD&A.

11
<PAGE> 12

General and administrative expenses decreased by 18 percent to $11,578,000 in
2000, compared with $14,198,000 in 1999, and $11,762,000 in 1998. Expenses were
higher than normal in 1999 due to reduced allocations of charges to operations
and to unusually high expenses relating to corporate aircraft maintenance. The
Company completed all Year 2000 readiness and subsequently, experienced no
significant problems or related expenses. Because of the impact of foreign
taxes, income tax expense rose to 42 percent of pre-tax income in 2000, from 40
percent in 1999, and 37 percent in 1998.

Interest expense decreased to $3,076,000 in 2000, from $6,481,000 in 1999. In
1998, interest expense was $942,000. Interest expense was a function of
outstanding bank loans arising at the end of 1998 and into the first half of
1999 as the Company completed a substantial capital expenditure program and
repurchased some of its stock during 1998. Debt reductions occurred in the last
half of 1999 and early 2000.

CONTRACT DRILLING DIVISION revenues, which include both domestic and
international segment revenues, declined 11 percent to $351,080,000 during 2000,
from $396,634,000 in 1999. Revenues for 1999 were down eight percent over the
previous year. Division operating profit declined 24 percent to $45,561,000
during 2000, compared with a 31 percent decrease from 1998 to 1999.

Domestic segment revenues were $214,531,000 in 2000, $213,647,000 in 1999, and
$177,059,000 in 1998. Domestic segment operating profit was $35,808,000 in 2000,
$30,154,000 in 1999, and $35,817,000 in 1998. Rig utilization for the U.S. land
fleet was 85 percent in 2000, 69 percent in 1999, and 94 percent in 1998.
Domestic platform rig utilization was 94 percent in 2000, 95 percent in 1999,
and 99 percent in 1998.

An increase in revenues from U.S. land operations in 2000 helped offset the
reduction in Jade construction revenues recorded in 1999 (as described below),
while offshore platform revenues were up slightly from the previous year. Higher
revenues and profit margins from the U.S. land rig operation were the main
reason for improved domestic operating profit for 2000. Domestic segment
revenues increased from 1998 to 1999, primarily due to $40,790,000 of revenues
from the Mobil Jade rig construction project and increased offshore platform rig
revenues. Domestic operating profit in 1999

12
<PAGE> 13

was down from 1998 because of lower land rig utilization and dayrates. However,
operating profit for 1999 was bolstered by several non-recurring items such as
income from the Jade construction project and from several capital
reimbursements from operators for new rig equipment on existing rigs.

International segment revenues fell 25 percent to $136,549,000 during 2000, from
$182,987,000 in 1999. Revenues were $253,072,000 in 1998. Operating profit for
the international segment declined to $9,753,000 in 2000, from $29,845,000 in
1999, and $50,834,000 in 1998. International rig utilization averaged 47 percent
during 2000, 53 percent in 1999, and 88 percent in 1998.

As crude oil prices declined during 1998, international activity and
profitability began to decline during the second half of that year and into
1999. Activity continued to wane in 2000, particularly in Venezuela and
Colombia. The Company expects activity to improve in Venezuela during 2001, but
the timing and extent of improvements are uncertain. Activity in Colombia is not
expected to improve during 2001. Therefore, the Company has redeployed to other
locations four of the ten rigs previously located there.

The Company has international operations in several South American countries.
With the exception of Venezuela, the Company's exposure to currency valuation
losses is immaterial due to the fact that virtually all billings and payments
are in U.S. dollars. In Venezuela, approximately 60 percent of the Company's
billings are in U.S. dollars and 40 percent are in bolivars, the local currency.

As a result, the Company is exposed to risks of currency devaluation in
Venezuela because of the bolivar denominated receivables. During 2000, the
Company experienced a loss of $687,000 due to devaluation of the bolivar,
compared with a $712,000 loss in 1999, and a $2,204,000 loss in 1998. The
Company anticipates additional devaluation losses in Venezuela during 2001, but
it is unable to predict the extent of either the devaluation, or its financial
impact. Should Venezuela experience a 25 to 50 percent devaluation, Company
losses could range from approximately $600,000 to $1,000,000. Using the same
assumptions in 1999 resulted in the Company estimating foreign currency losses
in Venezuela for 2000 ranging from $350,000 to $600,000.

13
<PAGE> 14

During the latter part of calendar 2000, the Company commenced an economic
evaluation of the useful lives of its drilling rigs. The evaluation is not yet
complete, but if results indicate that the useful lives are longer than
currently estimated, the Company's annual rig depreciation expense may be
reduced beginning in fiscal 2001.

OIL AND GAS DIVISION operating results include those from its Exploration and
Production segment, as depicted in the following table. The Natural Gas
Marketing segment will be discussed separately.

<TABLE>
<CAPTION>
Exploration & Production 2000 1999 1998
- ------------------------ ----------- ----------- -----------
<S> <C> <C> <C>

Revenues (in 000's) ...................... $ 157,583 $ 95,953 $ 98,696
Operating Profit (in 000's) .............. $ 66,604 $ 11,245 $ 28,088
Natural Gas Production (Mmcf per day) .... 128.2 121.2 117.4
Average Natural Gas Price (per Mcf) ...... $ 2.79 $ 1.83 $ 2.04
Crude Oil Production (barrels per day) ... 2,405 1,779 1,921
Average Crude Oil Price (per barrel) ..... $ 27.95 $ 14.60 $ 14.74
</TABLE>

Exploration and Production segment revenues and operating profit increased
significantly this year as average prices received for the Company's production
rose dramatically. Average prices received for natural gas increased by 52
percent and average crude oil prices increased by 91 percent. Crude oil and
natural gas production for the Company increased by 36 percent and six percent,
respectively. Increased exploration drilling caused dry hole and abandonment
charges to rise to $22.6 million in 2000, compared with $11.4 million in 1999,
and $10.9 million in 1998. Revenues and operating profit for 1999 declined from
the previous year due to a ten percent reduction in natural gas prices and a
seven percent reduction in oil production. Additionally, geophysical expense
rose during that period from $4.5 million in 1998, to $8.2 million in 1999. Also
negatively impacting 1999 results was a $10.1 million impairment charge. That
charge compares with $5.4 million in 1998, and $4.0 million in 2000.

During 2001, the Company intends to increase its capital spending over the
previous year in order to participate in more exploration opportunities.
Therefore, operating profit for the coming year could be impacted by possible
increases in geophysical, dry hole, and abandonment expenses. Although natural
gas prices were higher during the early part of fiscal 2001, it is difficult to
predict the level of crude oil and natural gas prices for the remainder of the
year and the impact on operating profit.

14
<PAGE> 15

The Company has retained the investment banking firm of Petrie Parkman & Co. to
analyze, develop, and facilitate possible strategic options for the Oil and Gas
segment. It is uncertain whether such a transaction will occur or, if so, when
it might occur.

The Company's Natural Gas Marketing segment, Helmerich & Payne Energy Services,
Inc., (HPESI) derives most of its revenues from selling natural gas produced by
other unaffiliated companies. Total Natural Gas Marketing segment revenues were
$80,907,000 in 2000, $55,259,000 in 1999, and $53,499,000 in 1998. Operating
profit was $5,271,000 in 2000, $4,418,000 in 1999, and $2,418,000 in 1998. Most
of the natural gas owned and produced by the Exploration and Production segment
is sold through HPESI to third parties at variable prices based on industry
pricing publications or exchange quotations. Revenues for the Company's own
natural gas production are reported by the Exploration and Production segment
with the Natural Gas Marketing segment retaining a market-based fee from the
sale of such production. HPESI sells most of its natural gas with monthly or
daily contracts tied to industry market indices, such as Inside FERC Gas Market
Report. The Company, through HPESI, has natural gas delivery commitments for
periods of less than a year for approximately 59 percent of its total natural
gas production. At times, the Exploration and Production segment may direct
HPESI to enter into fixed price natural gas sales contracts on its behalf for a
small portion (normally less than 20 percent) of its natural gas sales for
periods of less than 12 months to guarantee a certain price. In 2000, HPESI had
approximately 13.6 percent of its natural gas sales portfolio dedicated to such
fixed price sales contracts compared to 2.3 percent in 1999. As of September 30,
2000, HPESI had fixed price contracts for less than four percent of its
projected monthly sales for the months of November, 2000 through March, 2001,
and no fixed price contracts thereafter.

Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 137 and
SFAS No. 138, is effective for fiscal years beginning after June 15, 2000, and
requires that all derivatives be recognized as assets or liabilities in the
balance sheet and that these instruments be measured at fair value. The effect
of SFAS No. 133 on the Company's results of operations and financial position
for fiscal year 2001 is not expected to be material.

15
<PAGE> 16

REAL ESTATE DIVISION revenues totaled $8,999,000 for 2000, $8,671,000 for 1999,
and $8,922,000 for 1998. Operating profit was $5,346,000 in 2000, $5,338,000 in
1999, and $5,371,000 in 1998. Occupancy rates, revenues, and operating profit
remained solid in 2000 due to the continued strength of the Tulsa economy. No
material changes are anticipated in the Real Estate Division in 2001.

LIQUIDITY AND CAPITAL RESOURCES

The Company's capital spending was $131,932,000 in 2000, $122,951,000 in 1999,
and $266,299,000 in 1998. Net cash provided from operating activities for those
same time periods were $201,836,000 in 2000, $158,694,000 in 1999, and
$113,533,000 in 1998. In addition to the net cash provided by operating
activities, the Company also generated net proceeds from the sale of portfolio
securities of $12,569,000 in 2000, $2,803,000 in 1999, and $73,949,000 in 1998.
In June 1998, the board of directors authorized the Company to repurchase up to
2,000,000 shares of its own stock. A total of 999,100 shares were repurchased in
1998 at a total cost of $19,112,000 and 20,600 shares were repurchased in 2000
at a total cost of $450,000. The Company plans to increase capital spending
during 2001 in its Exploration and Production segment and its Contract Drilling
Division. During fiscal 2000, the Company ordered 12 new rigs at an approximate
cost of between $7.5 million and $8.25 million each and expects to take delivery
of 11 of the new rigs in calendar 2001. The potential for new contract drilling
projects requiring large amounts of capital is difficult to predict at this
time. Total capital spending for the Company will likely exceed $200 million for
2001 and could be greater if additional attractive opportunities become
available. Funding will come from internally generated cash, proceeds from
security sales, and/or additional borrowings.

Due to the need for additional funds during 1998 resulting from a reduction in
operating cash flow, a significant increase in capital expenditures, and the
purchase of Company stock, the Company increased its available short-term lines
of credit and obtained long-term financing. As described in Note 2 of Notes to
Consolidated Financial Statements, in October 1998, the Company obtained $50
million in long-term debt proceeds, which was used to pay off short-term
borrowings. The $50 million of long-term debt matures in October 2003. The
interest rate on this debt fluctuates based on the 30-day London Interbank
Offered Rate (LIBOR). However, simultaneous to receiving

16
<PAGE> 17

the $50 million in long-term debt proceeds, the Company entered into a $50
million interest rate swap agreement with a major national bank. The swap
effectively fixes the interest rate on this facility at 5.38 percent for the
entire five-year term of the note. The estimated fair value of the interest rate
swap was $2,329,000 at September 30, 2000. The Company's interest rate risk
exposure is limited to its potential short-term borrowings and results
predominately from fluctuations in short-term interest rates as measured by
30-day LIBOR.

The strength of the Company's balance sheet is substantial, with current ratios
for 2000 and 1999 at 3.4 and 2.2, respectively, and with total bank borrowings
of only four percent of total assets at September 30, 2000. Additionally, the
Company manages a large portfolio of marketable securities that, at the close of
2000, had a market value of $383,036,000, with a cost basis of $133,254,000. The
portfolio, heavily weighted in energy stocks, is subject to fluctuation in the
market and may vary considerably over time. Excluding the Company's investment
in Atwood Oceanics, Inc., which is accounted for as an equity-method investment,
the portfolio is marked to market on the Company's balance sheet for each
reporting period. During 2000, the Company paid a dividend of $0.285 per share,
or a total of $14,175,000, representing the 29th consecutive year of dividend
increases.

STOCK PORTFOLIO HELD BY THE COMPANY

<TABLE>
<CAPTION>
Number of
September 30, 2000 Shares Cost Basis Market Value
--------- ---------- ------------
(in thousands, except share amounts)
<S> <C> <C> <C>

Occidental Petroleum Corporation ... 1,000,000 $ 23,775 $ 21,812
Atwood Oceanics, Inc. .............. 3,000,000 46,353 125,063
Schlumberger, Ltd. ................. 1,480,000 23,511 121,823
Transocean Sedco Forex, Inc. ....... 286,528 9,509 16,798
SUNOCO, Inc. ....................... 312,546 2,873 8,419
Phillips Petroleum Company ......... 240,000 5,976 15,060
BANK ONE CORPORATION ............... 175,000 1,969 6,661
Kerr-McGee Corporation ............. 184,500 4,899 12,223
ONEOK, Inc. ........................ 225,000 2,751 8,947
Other .............................. 11,638 46,230
---------- ----------
Total .................. $ 133,254 $ 383,036
========== ==========
</TABLE>

17
<PAGE> 18

CONSOLIDATED BALANCE SHEETS
HELMERICH & PAYNE, INC.

ASSETS

<TABLE>
<CAPTION>
September 30, 2000 1999
----------- -----------
(in thousands)
<S> <C> <C>

CURRENT ASSETS:

Cash and cash equivalents ................................ $ 108,087 $ 21,758
Accounts receivable, less reserve of $2,003 and $2,908 ... 106,630 99,598
Inventories .............................................. 25,598 25,187
Prepaid expenses and other ............................... 24,829 14,081
----------- -----------
Total current assets ................................. 265,144 160,624
----------- -----------

INVESTMENTS .................................................. 304,326 238,475
----------- -----------

PROPERTY, PLANT AND EQUIPMENT, at cost:

Contract drilling equipment .................................. 891,749 881,269
Oil and gas properties ....................................... 457,724 446,889
Real estate properties ....................................... 50,649 49,065
Other .................................................... 80,268 71,139
----------- -----------
1,480,390 1,448,362
Less--Accumulated depreciation, depletion and amortization ... 806,785 757,147
----------- -----------
Net property, plant and equipment .................... 673,605 691,215
----------- -----------

OTHER ASSETS ................................................. 16,417 19,385
----------- -----------

TOTAL ASSETS ................................................. $ 1,259,492 $ 1,109,699
=========== ===========
</TABLE>

The accompanying notes are an integral part of these statements.

18
<PAGE> 19

LIABILITIES AND SHAREHOLDERS' EQUITY

<TABLE>
<CAPTION>
September 30, 2000 1999
---------- ----------
(in thousands,
except share data)
<S> <C> <C>
CURRENT LIABILITIES:

Accounts payable ..................................................................... $ 32,279 $ 25,704
Accrued liabilities .................................................................. 46,615 41,200
Notes payable ........................................................................ -- 5,000
---------- ----------
Total current liabilities .................................................... 78,894 71,904
---------- ----------

NONCURRENT LIABILITIES:

Long-term notes payable .............................................................. 50,000 50,000
Deferred income taxes ................................................................ 156,650 116,588
Other ................................................................................ 18,245 23,098
---------- ----------
Total noncurrent liabilities ................................................. 224,895 189,686
---------- ----------

SHAREHOLDERS' EQUITY:

Common stock, $.10 par value, 80,000,000 shares authorized,
53,528,952 shares issued ......................................................... 5,353 5,353
Preferred stock, no par value, 1,000,000 shares authorized,
no shares issued ................................................................. -- --
Additional paid-in capital ........................................................... 66,090 61,411
Retained earnings .................................................................... 813,885 745,956
Unearned compensation ................................................................ (3,277) (4,487)
Accumulated other comprehensive income ............................................... 106,064 75,182
---------- ----------
988,115 883,415
Less treasury stock, 3,548,480 shares in 2000 and 3,903,285 shares in 1999, at cost .. 32,412 35,306
---------- ----------
Total shareholders' equity ................................................... 955,703 848,109
---------- ----------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY................................................ $1,259,492 $1,109,699
========== ==========
</TABLE>

The accompanying notes are an integral part of these statements.

19
<PAGE> 20

CONSOLIDATED STATEMENTS OF INCOME
HELMERICH & PAYNE, INC.

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
---------- ---------- ----------
(in thousands,
except per share amounts)
<S> <C> <C> <C>

REVENUES:
Sales and other operating revenues ......... $ 599,122 $ 556,562 $ 592,037
Income from investments .................... 31,973 7,757 44,603
---------- ---------- ----------
631,095 564,319 636,640
---------- ---------- ----------

COSTS AND EXPENSES:
Operating costs ............................ 316,933 332,330 346,066
Depreciation, depletion and amortization ... 110,851 109,167 88,350
Dry holes and abandonments ................. 22,692 11,727 11,572
Taxes, other than income taxes ............. 29,202 25,478 25,728
General and administrative ................. 11,578 14,198 11,762
Interest ................................... 3,076 6,481 942
---------- ---------- ----------
494,332 499,381 484,420
---------- ---------- ----------

INCOME BEFORE INCOME TAXES AND
EQUITY IN INCOME OF AFFILIATE ............... 136,763 64,938 152,220

INCOME TAX EXPENSE ............................. 57,684 25,706 56,677

EQUITY IN INCOME OF AFFILIATE
net of income taxes ......................... 3,221 3,556 5,611
---------- ---------- ----------

NET INCOME ..................................... $ 82,300 $ 42,788 $ 101,154
========== ========== ==========

EARNINGS PER COMMON SHARE:
BASIC ...................................... $ 1.66 $ 0.87 $ 2.03
DILUTED .................................... $ 1.64 $ 0.86 $ 2.00

AVERAGE COMMON SHARES OUTSTANDING:
BASIC ...................................... 49,534 49,243 49,948
DILUTED .................................... 50,035 49,817 50,565
</TABLE>

The accompanying notes are an integral part of these statements.

20
<PAGE> 21
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
HELMERICH & PAYNE, INC.

<TABLE>
<CAPTION>
Common Stock Additional
--------------------- Paid-in Unearned Retained
Shares Amount Capital Compensation Earnings
-------- -------- ---------- ------------ --------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>

Balance, Sept. 30, 1997 ................ 53,529 $ 5,353 $ 51,316 $ -- $ 629,562
Comprehensive Income:
Net Income ........................... -- -- -- -- 101,154

Other comprehensive loss, net
of tax--unrealized losses on
available-for-sale securities ...... -- -- -- -- --
Comprehensive income ................... -- -- -- -- --

Cash dividends ($.275 per share) ....... -- -- -- -- (14,007)
Exercise of Stock Options .............. -- -- 1,833 -- --
Purchase of stock for treasury ......... -- -- -- -- --

Lapse of restrictions on
Restricted Stock Awards .............. -- -- 98 -- --

Stock issued under Restricted
Stock Award Plan ..................... -- -- 5,757 (6,791) --
Amortization of deferred
Compensation ......................... -- -- -- 1,186 166
------ ---------- ---------- ---------- ----------
Balance, Sept. 30, 1998 ................ 53,529 5,353 59,004 (5,605) 716,875

Comprehensive Income:
Net Income ............................ -- -- -- -- 42,788
Other comprehensive income,
net of tax--unrealized gains
on available-for-sale securities ..... -- -- -- -- --
Comprehensive income ................... -- -- -- -- --

Cash dividends ($.28 per share) ........ -- -- -- -- (13,866)
Exercise of Stock Options .............. -- -- 2,201 -- --
Lapse of restrictions on
Restricted Stock Awards ............... -- -- 69 -- --
Stock issued under Restricted
Stock Award Plan ...................... -- -- 137 (289) --
Amortization of deferred
Compensation .......................... -- -- -- 1,407 159
------ ---------- ---------- ---------- ----------
Balance, Sept. 30, 1999 ................ 53,529 5,353 61,411 (4,487) 745,956

Comprehensive Income:
Net Income ............................ -- -- -- -- 82,300
Other comprehensive income,
net of tax--unrealized gains on
available-for-sale securities ....... -- -- -- -- --
Comprehensive income ................... -- -- -- -- --

Cash dividends ($.285 per share) ....... -- -- -- -- (14,448)
Exercise of Stock Options .............. -- -- 4,491 -- --
Purchase of stock for treasury ......... -- -- -- -- --
Lapse of restrictions on
Restricted Stock Awards .............. -- -- 31 -- --
Stock issued under Restricted
Stock Award Plan ..................... -- -- 157 (248) --
Amortization of deferred
Compensation ......................... -- -- -- 1,458 77
------ ---------- ---------- ---------- ----------
Balance, Sept. 30, 2000 ................ 53,529 $ 5,353 $ 66,090 $ (3,277) $ 813,885
====== ========== ========== ========== ==========
</TABLE>

<TABLE>
<CAPTION>
Accumulated
Treasury Stock Other
-------------------- Comprehensive
Shares Amount Income (Loss) Total
------- ---------- -------------- ----------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>

Balance, Sept. 30, 1997 ................ 3,501 $ (20,105) $ 114,454 $ 780,580
Comprehensive Income:
Net Income ........................... -- -- -- 101,154

Other comprehensive loss, net
of tax--unrealized losses on
available-for-sale securities ...... -- -- (59,765) (59,765)
----------
Comprehensive income ................... -- -- -- 41,389
----------

Cash dividends ($.275 per share) ....... -- -- -- (14,007)
Exercise of Stock Options .............. (174) 1,015 -- 2,848
Purchase of stock for treasury ......... 999 (19,112) -- (19,112)

Lapse of restrictions on
Restricted Stock Awards .............. -- -- -- 98

Stock issued under Restricted
Stock Award Plan ..................... (180) 1,034 -- --
Amortization of deferred
Compensation ......................... -- -- -- 1,352
------ ---------- ---------- ----------
Balance, Sept. 30, 1998 ................ 4,146 (37,168) 54,689 793,148

Comprehensive Income:
Net Income ............................ -- -- -- 42,788
Other comprehensive income,
net of tax--unrealized gains
on available-for-sale securities ..... -- -- 20,493 20,493
----------
Comprehensive income ................... -- -- -- 63,281
----------

Cash dividends ($.28 per share) ........ -- -- -- (13,866)
Exercise of Stock Options .............. (226) 1,710 -- 3,911
Lapse of restrictions on
Restricted Stock Awards ............... -- -- -- 69
Stock issued under Restricted
Stock Award Plan ...................... (17) 152 -- --
Amortization of deferred
Compensation .......................... -- -- -- 1,566
------ ---------- ---------- ----------
Balance, Sept. 30, 1999 ................ 3,903 (35,306) 75,182 848,109

Comprehensive Income:
Net Income ............................ -- -- -- 82,300
Other comprehensive income,
net of tax--unrealized gains on
available-for-sale securities ....... -- -- 30,882 30,882
----------
Comprehensive income ................... -- -- -- 113,182
----------

Cash dividends ($.285 per share) ....... -- -- -- (14,448)
Exercise of Stock Options .............. (366) 3,253 -- 7,744
Purchase of stock for treasury ......... 21 (450) -- (450)
Lapse of restrictions on
Restricted Stock Awards .............. -- -- -- 31
Stock issued under Restricted
Stock Award Plan ..................... (10) 91 -- --
Amortization of deferred
Compensation ......................... -- -- -- 1,535
------ ---------- ---------- ----------
Balance, Sept. 30, 2000 ................ 3,548 $ (32,412) $ 106,064 $ 955,703
====== ========== ========== ==========
</TABLE>

The accompanying notes are an integral part of these statements.

21
<PAGE> 22

CONSOLIDATED STATEMENTS OF CASH FLOWS
HELMERICH & PAYNE, INC.

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................................ $ 82,300 $ 42,788 $ 101,154
---------- ---------- ----------
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization ......................... 110,851 109,167 88,350
Dry holes and abandonments ....................................... 22,692 11,727 11,572
Equity in income of affiliate before income taxes ................ (5,196) (5,735) (9,050)
Amortization of deferred compensation ............................ 1,535 1,566 1,352
Gain on sale of securities and non-monetary investment income .... (24,000) (2,547) (38,421)
Gain on sale of property, plant and equipment .................... (2,479) (6,900) (2,951)
Other - net ...................................................... 944 2,148 974
Change in assets and liabilities:
Accounts receivable ........................................... (7,032) 19,797 (20,698)
Inventories ................................................... (411) 214 (5,762)
Prepaid expenses and other .................................... (7,780) (5,079) (4,682)
Accounts payable .............................................. 6,575 (16,147) (194)
Accrued liabilities ........................................... 7,557 2,367 (8,692)
Deferred income taxes ......................................... 21,133 559 (1,231)
Other noncurrent liabilities .................................. (4,853) 4,769 1,812
---------- ---------- ----------
119,536 115,906 12,379
---------- ---------- ----------
Net cash provided by operating activities .................. 201,836 158,694 113,533
---------- ---------- ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including dry hole costs ........................ (131,932) (122,951) (266,299)
Proceeds from sale of property, plant and equipment ................... 18,044 9,990 15,414
Purchase of investments ............................................... -- (537) 1,056
Proceeds from sale of securities ...................................... 12,569 2,803 73,949
---------- ---------- ----------
Net cash used in investing activities ...................... (101,319) (110,695) (175,880)
---------- ---------- ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable ........................................... -- 102,000 169,800
Payments made on notes payable ........................................ (5,000) (141,800) (80,000)
Dividends paid ........................................................ (14,175) (13,849) (13,802)
Purchases of stock for treasury ....................................... (450) -- (19,112)
Proceeds from exercise of stock options ............................... 5,437 2,932 1,974
---------- ---------- ----------
Net cash provided by (used in) financing activities ........ (14,188) (50,717) 58,860
---------- ---------- ----------

NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS .............................................................. 86,329 (2,718) (3,487)
CASH AND CASH EQUIVALENTS, beginning of period ........................... 21,758 24,476 27,963
---------- ---------- ----------
CASH AND CASH EQUIVALENTS, end of period ................................. $ 108,087 $ 21,758 $ 24,476
========== ========== ==========
</TABLE>

The accompanying notes are an integral part of these statements.

22
<PAGE> 23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
HELMERICH & PAYNE, INC. September 30, 2000, 1999 and 1998

NOTE 1 SUMMARY OF ACCOUNTING POLICIES

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

TRANSLATION OF FOREIGN CURRENCIES -
The Company has determined that the functional currency for its foreign
subsidiaries is the U.S. dollar. The foreign currency transaction loss for 2000,
1999, and 1998 was $664,000, $21,000, and $1,953,000, respectively.

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 -
The Company follows the successful efforts method of accounting for oil and gas
properties. Under this method, the Company capitalizes all costs to acquire
mineral interests in oil and gas properties, to drill and equip exploratory
wells which find proved reserves and to drill and equip development wells.
Geological and geophysical costs, delay rentals and costs to drill exploratory
wells which do not find proved reserves are expensed. Capitalized costs of
producing oil and gas properties are depreciated and depleted by the
unit-of-production method based on proved oil and gas reserves as determined by
the Company and its independent engineers. Reserves are recorded for capitalized
costs of undeveloped leases based on management's estimate of recoverability.
Costs of surrendered leases are charged to the reserve.

In accordance with Statement of Financial Accounting Standards (SFAS) No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of", the Company recognizes impairment losses for long-lived assets
used in operations when indicators of impairment are present and the
undiscounted cash flows are not sufficient to recover the carrying amount of the
asset. In 2000, the Company recognized an impairment charge of approximately
$4.0 million for proved Exploration and Production properties which is included
in depreciation, depletion and amortization expense. After-tax, the impairment
charge reduced 2000 net income by approximately $2.5 million, $0.05 per share on
a diluted basis. In 1999, the Company recognized an impairment charge of
approximately $10.1 million for proved Exploration and Production properties
which is included in depreciation, depletion and amortization expense.
After-tax, the impairment charge reduced 1999 net income by approximately $6.2
million, $0.13 per share on a diluted basis. In 1998, the Company recognized an
impairment charge of approximately $5.4 million for proved Exploration and
Production properties which is included in depreciation, depletion and
amortization expense. After-tax, the impairment charge reduced net income by
approximately $3.4 million, $0.07 per share on a diluted basis. The Company
evaluates impairment of exploration and production assets on a field by field
basis. Fair value on all long-lived assets are based on discounted future cash
flows or information provided by sales and purchases of similar assets.

Substantially all property, plant and equipment other than oil and gas
properties is depreciated using the straight-line method based on the following
estimated useful lives:

<TABLE>
<CAPTION>
YEARS
-----
<S> <C>
Contract drilling equipment........................... 4-10
Real estate buildings and equipment................... 10-50
Other................................................. 3-33
</TABLE>

CASH AND CASH EQUIVALENTS -
Cash and cash equivalents consist of cash in banks and investments readily
convertible into cash which mature within three months from the date of
purchase.

INVENTORIES -
Inventories, primarily materials and supplies, are valued at the lower of cost
(moving average or actual) or market.

DRILLING REVENUE -
Contract drilling revenues are comprised primarily of daywork drilling contracts
for which the related revenues and expenses are recognized as work progresses.
Fiscal 2000 and 1999 contract drilling revenues also include revenues of
$4,109,000 and $40,790,000, respectively, from a rig construction contract for
which revenues were recognized based on the percentage-of-completion method,
measured by the percentage that incurred costs to date bear to total estimated
costs. The Company does not currently have any third party rig construction
contracts.

GAS IMBALANCES -
The Company recognizes revenues from gas wells on the sales method, and a
liability is recorded for permanent imbalances resulting from gas wells in which
the Company has sold more production than it is entitled.

INVESTMENTS -
The cost of securities used in determining realized gains and losses is based on
average cost of the security sold. Net income in 2000 includes approximately
$6,637,000, $0.13 per share on a diluted basis, on gains related to non-monetary
transactions within the Company's available-for-sale security investment
portfolio which were accounted for at fair value.

Investments in companies owned from 20 to 50 percent are accounted for using the
equity method with the Company recognizing

23
<PAGE> 24

its proportionate share of the income or loss of each investee. The Company
owned approximately 22 percent of Atwood Oceanics, Inc. (Atwood) at both
September 30, 2000 and 1999. The quoted market value of the Company's investment
was $125,063,000 and $91,687,500 at September 30, 2000 and 1999, respectively.
Retained earnings at September 30, 2000 includes approximately $21,918,000 of
undistributed earnings of Atwood.

Summarized financial information of Atwood is as follows:

<TABLE>
<CAPTION>
2000 1999 1998
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>

Gross revenues .................................... $ 134,514 $ 150,009 $ 151,809
Costs and expenses ................................ 111,366 122,289 112,445
---------- ---------- ----------
Net income ........................................ $ 23,148 $ 27,720 $ 39,364
========== ========== ==========
Helmerich & Payne, Inc.'s equity in net income,
net of income taxes ......................... $ 3,221 $ 3,556 $ 5,611
========== ========== ==========

Current assets .................................... $ 63,951 $ 50,532 $ 51,587
Noncurrent assets ................................. 248,334 243,072 230,150
Current liabilities ............................... 17,484 19,013 26,723
Noncurrent liabilities ............................ 77,332 82,362 91,248
Shareholders' equity .............................. 217,469 192,229 163,766
========== ========== ==========
Helmerich & Payne, Inc.'s investment .............. $ 46,353 $ 41,157 $ 35,422
========== ========== ==========
</TABLE>

INCOME TAXES -
Deferred income taxes are computed using the liability method and are provided
on all temporary differences between the financial basis and the tax basis of
the Company's assets and liabilities.

OTHER POST EMPLOYMENT BENEFITS -
The Company sponsors a health care plan that provides post retirement medical
benefits to retired employees. Employees who retire after November 1, 1992 and
elect to participate in the plan pay the entire estimated cost of such benefits.

The Company has accrued a liability for estimated workers compensation claims
incurred. The liability for other benefits to former or inactive employees after
employment but before retirement is not material.

EARNINGS PER SHARE -
Basic earnings per share is based on the weighted-average number of common
shares outstanding during the period. Diluted earnings per share includes the
dilutive effect of stock options and restricted stock.

EMPLOYEE STOCK-BASED AWARDS -
Employee stock-based awards are accounted for under Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" and related
information. Fixed plan common stock options do not result in compensation
expense, because the exercise price of the stock equals the market price of the
underlying stock on the date of grant.

TREASURY STOCK -
Treasury stock purchases are accounted for under the cost method whereby the
entire cost of the acquired stock is recorded as treasury stock. Gains and
losses on the subsequent reissuance of shares are credited or charged to
additional paid-in-capital using the average-cost method.

DERIVATIVES -
As described in Note 2, the Company entered into an interest rate swap agreement
in October 1998. This agreement involves the exchange of an amount based on a
fixed interest rate for an amount based on a variable interest rate without an
exchange of the notional amount upon which the payments are based. The
difference to be paid or received is accrued and recognized as an adjustment of
interest expense. Gains and losses from termination of interest rate swap
agreements are deferred and amortized as an adjustment to interest expense over
the original term of the terminated swap agreement.

NOTE 2 NOTES PAYABLE AND LONG-TERM DEBT

At September 30, 2000, the Company had committed bank lines totaling $85
million; $50 million expires October 2003 and $35 million expires May 2001.
Additionally, the Company had uncommitted credit facilities totaling $10
million. Collectively, the Company had $50 million in outstanding borrowings and
outstanding letters of credit totaling $8.2 million against these lines at
September 30, 2000. Concurrent with a $50 million borrowing under the facility
that expires October 2003, the Company entered into an interest rate swap with a
notional value of $50 million. The swap effectively converts this $50 million
facility from a floating rate to a fixed effective rate of 5.38 percent. The
interest rate swap closely correlates with the terms and maturity of the $50
million facility. Excluding the impact of the interest rate swap, the average
interest rate for the borrowings at September 30, 2000, was approximately 6.61
percent on a 360 day basis.

Under the various credit agreements, the Company must meet certain requirements
regarding levels of debt, net worth and earnings.

24
<PAGE> 25
NOTE 3 INCOME TAXES

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

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
-------- -------- --------
(in thousands)
<S> <C> <C> <C>

CURRENT:
Federal ...................... $ 25,736 $ 9,684 $ 36,705
Foreign ...................... 8,766 15,963 18,728
State ........................ 3,366 1,744 4,751
-------- -------- --------
37,868 27,391 60,184
-------- -------- --------
DEFERRED:
Federal ...................... 12,318 (842) (4,108)
Foreign ...................... 6,146 (771) 927
State ........................ 1,352 (72) (326)
-------- -------- --------
19,816 (1,685) (3,507)
-------- -------- --------
TOTAL PROVISION: .................. $ 57,684 $ 25,706 $ 56,677
======== ======== ========
</TABLE>

The amounts of domestic and foreign income are as follows:

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
-------- -------- --------
(in thousands)
<S> <C> <C> <C>
INCOME BEFORE INCOME TAXES AND
EQUITY IN INCOME OF AFFILIATE:
Domestic.......................... $129,373 $ 41,693 $106,228
Foreign........................... 7,390 23,245 45,992
-------- -------- --------
.............................. $136,763 $ 64,938 $152,220
======== ======== ========
</TABLE>

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

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
---- ---- ----
<S> <C> <C> <C>

U.S. Federal income tax rate .................... 35% 35% 35%
Dividends received deduction .................... -- (1) --
Effect of foreign taxes ......................... 5 5 2
Non-conventional fuel source credits utilized ... -- (1) --
Other, net ...................................... 2 2 --
---- ---- ----
Effective income tax rate ....................... 42% 40% 37%
==== ==== ====
</TABLE>

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

<TABLE>
<CAPTION>
September 30, 2000 1999
------------ ------------
(in thousands)
<S> <C> <C>

DEFERRED TAX LIABILITIES:
Property, plant and equipment $ 75,653 $ 59,695
Available-for-sale securities 72,583 53,651
Pension provision 4,075 3,951
Equity investment 12,734 10,759
Other 1,217 923
------------ ------------
Total deferred tax liabilities 166,262 128,979
------------ ------------

DEFERRED TAX ASSETS:
Financial accruals 9,612 8,832
Other -- 3,559
------------ ------------
Total deferred tax assets 9,612 12,391
------------ ------------
NET DEFERRED TAX LIABILITIES $ 156,650 $ 116,588
============ ============
</TABLE>

25
<PAGE> 26

NOTE 4 SHAREHOLDERS' EQUITY

In June 1998, the board of directors authorized the repurchase of up to
2,000,000 shares of its common stock in open market or private transactions. The
repurchased shares will be held in treasury and used for general corporate
purposes including use in the Company's benefit plans. During fiscal 1998, the
Company purchased 999,100 shares at a total cost of approximately $19 million
and in fiscal 2000 purchased 20,600 shares at a cost of approximately $450,000.
The Company did not purchase any shares in fiscal 1999. As of September 30,
2000, the Company is authorized to repurchase up to 979,400 additional shares.

The Company has several plans providing for common stock-based awards to
employees and to non-employee directors. The plans permit the granting of
various types of awards including stock options and restricted stock. Awards may
be granted for no consideration other than prior and future services. The
purchase price per share for stock options may not be less than the market price
of the underlying stock on the date of grant. Stock options expire 10 years
after grant.

The Company has reserved 983,776 shares of its treasury stock to satisfy the
exercise of stock options issued under the 1990 Stock Option Plan. Effective
December 4, 1996, additional options are no longer granted under this plan.
Options granted under the 1990 plan generally vest over a seven year period.
Options granted under the plan become exercisable in increments as outlined in
the plan.

In March 1997, the Company adopted the 1996 Stock Incentive Plan (the "Stock
Incentive Plan"). The Stock Incentive Plan was effective December 4, 1996, and
will terminate December 3, 2006. Under this plan the Company is authorized to
grant options for up to 4,000,000 shares of the Company's common stock at an
exercise price not less than the fair market value of the common stock on the
date of grant. Up to 600,000 shares of the total authorized may be granted to
participants as restricted stock awards. Options granted under the 1996 plan
vest over a four-year period. On September 30, 2000, 1,776,900 shares were
available for grant under the Stock Incentive Plan.

On September 30, 2000, 393,000 shares were available for grant under the Stock
Incentive Plan as restricted stock awards. In fiscal 2000, 1999 and 1998,
10,000, 17,000 and 180,000 shares of restricted stock, respectively, were
granted at a weighted-average price of $24.75, $17.00 and $37.73, respectively,
which approximated fair market value at the date of grant. Unearned compensation
of $248,000, $289,000 and $6,791,000 for fiscal 2000, 1999 and 1998,
respectively, is being amortized over a five-year period as compensation
expense.

The following summary reflects the stock option activity and related information
(shares in thousands):

<TABLE>
<CAPTION>
------------------------- ------------------------- -------------------------
Weighted-Average Weighted-Average Weighted-Average
Options Exercise Price Options Exercise Price Options Exercise Price
------- ---------------- ------- ---------------- ------- ----------------
<S> <C> <C> <C> <C> <C> <C>

Outstanding at October 1, 2,574 $ 21.34 2,090 $ 22.09 1,745 $ 16.44
Granted 767 24.75 726 16.81 544 36.84
Exercised (364) 15.44 (238) 14.28 (175) 12.15
Forfeited/Expired (22) 23.00 (4) 13.51 (24) 17.54
------- ------------ ------- ----------- ------ -----------
Outstanding on September 30, 2,955 $ 22.94 2,574 $ 21.34 2,090 $ 22.09
------- ------------ ------- ----------- ------ -----------
Exercisable on September 30, 1,046 $ 22.40 782 $ 20.13 453 $ 15.63
------- ------------ ------- ----------- ------ -----------
Shares available on September 30,
for options that may be granted 1,777 2,537 3,280
------- ------------ ------- ----------- ------ -----------
</TABLE>

The following table summarizes information about stock options at
September 30, 000 (shares in thousands):

<TABLE>
<CAPTION>
Outstanding Stock Options Exercisable Stock Options
------------------------------------------------------ ----------------------------
Weighted-Average
Range of Remaining Contractural Weighted-Average Weighted-Average
Exercise Prices Options Life Exercise Price Options Exercise Price
------------------- ------- ------------------------- ---------------- ------- ----------------
<S> <C> <C> <C> <C> <C>
$12.00 to $16.50 625 4.2 years $13.64 437 $13.60
$16.51 to $26.50 1,797 8.2 years $22.05 342 $22.40
$26.51 to $37.00 533 7.2 years $36.84 267 $36.84
- -------------------- ------ ---------- ------- ------ -------
$12.00 to $37.00 2,955 7.2 years $22.94 1,046 $22.40
- -------------------- ------ ---------- ------- ------ -------
</TABLE>

The following table reflects pro forma net income and earnings per share had the
Company elected to adopt the fair value method of SFAS No. 123, "Accounting for
Stock-Based Compensation", in measuring compensation cost beginning with 1997
employee stock-based awards.

26
<PAGE> 27

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
---------- ---------- ----------
(in thousands, except per share data)
<S> <C> <C> <C>

Net Income:
As reported .................... $ 82,300 $ 42,788 $ 101,154
Pro forma ...................... $ 78,788 $ 40,268 $ 99,437

Basic earnings per share:
As reported .................... $ 1.66 $ .87 $ 2.03
Pro forma ...................... $ 1.59 $ .82 $ 1.99

Diluted earnings per share:
As reported .................... $ 1.64 $ .86 $ 2.00
Pro forma ...................... $ 1.57 $ .81 $ 1.97
</TABLE>

These pro forma amounts may not be representative of future disclosures since
the estimated fair value of stock options is amortized to expense over the
vesting period, and additional options may be granted in future years.

The weighted-average fair values of options at their grant date during 2000,
1999 and 1998 were $10.80, $6.81, and $14.63, 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:

<TABLE>
<CAPTION>
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Expected years until exercise............ 5.5 5.5 7.0
Expected stock volatility................ 41% 38% 34%
Dividend yield........................... .8% 1.2% 1.6%
Risk-free interest rate.................. 6.0% 6.0% 5.9%
</TABLE>

On September 30, 2000, the Company had 49,980,472 outstanding common stock
purchase rights ("Rights") pursuant to terms of the Rights Agreement dated
January 8, 1996. Under the terms of the Rights Agreement each Right entitled the
holder thereof to purchase from the Company one half of one unit consisting of
one one-thousandth of a share of Series A Junior Participating Preferred Stock
("Preferred Stock"), without par value, at a price of $90 per unit. The exercise
price and the number of units of Preferred Stock issuable on exercise of the
Rights are subject to adjustment in certain cases to prevent dilution. The
Rights will be attached to the common stock certificates and are not exercisable
or transferrable apart from the common stock, until 10 business days after a
person acquires 15% or more of the outstanding common stock or 10 business days
following the commencement of a tender offer or exchange offer that would result
in a person owning 15% or more of the outstanding common stock. In the event the
Company is acquired in a merger or certain other business combination
transactions (including one in which the Company is the surviving corporation),
or more than 50% of the Company's assets or earning power is sold or
transferred, each holder of a Right shall have the right to receive, upon
exercise of the Right, common stock of the acquiring company having a value
equal to two times the exercise price of the Right. The Rights are redeemable
under certain circumstances at $0.01 per Right and will expire, unless earlier
redeemed, on January 31, 2006. As long as the Rights are not separately
transferrable, the Company will issue one half of one Right with each new share
of common stock issued.

NOTE 5 EARNINGS PER SHARE

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

<TABLE>
<CAPTION>
(in thousands) 2000 1999 1998
------- -------- -------

<S> <C> <C> <C>
Basic weighted-average shares................ 49,534 49,243 49,948
Effect of dilutive shares:
Stock options.............................. 492 561 595
Restricted stock........................... 9 13 22
------- -------- -------
501 574 617
------- -------- -------
Diluted weighted-average shares................. 50,035 49,817 50,565
======= ======== =======
</TABLE>

Restricted stock of 180,000 shares at a weighted-average price of $37.73 and
options to purchase 533,000 shares of common stock at a price of $36.84 were
outstanding at September 30, 2000, but were not included in the computation of
diluted earnings per common share.

At September 30, 1999, restricted stock of 180,000 shares at a weighted-average
price of $37.73 and options to purchase 540,000 shares of common stock at a
price of $36.84 were outstanding, but were not included in the computation of
diluted earnings per common share.

At September 30, 1998, restricted stock of 180,000 shares at a weighted-average
price of $37.73 and options to purchase 919,000 shares of common stock at a
price of $32.40 were outstanding, but were not included in the computation of
diluted earnings per common share.

Inclusion of these shares would be antidilutive, as the exercise prices of the
options exceed the average market price of the common shares.

27
<PAGE> 28
NOTE 6 FINANCIAL INSTRUMENTS

Notes payable bear interest at market rates and are carried at cost which
approximates fair value. The estimated fair value of the Company's interest rate
swap is $2,329,000 at September 30, 2000, based on forward-interest rates
derived from the year-end yield curve as calculated by the financial institution
that is a counterparty to the swap. The estimated fair value of the Company's
available-for-sale securities is primarily based on market quotes.

The following is a summary of available-for-sale securities, which excludes
those accounted for under the equity method of accounting (see Note 1):

<TABLE>
<CAPTION>
Gross Gross Estimated
Unrealized Unrealized Fair
Cost Gains Losses Value
-------- ---------- ---------- ---------
(in thousands)
<S> <C> <C> <C> <C>
Equity Securities:
September 30, 2000 $ 86,901 $173,137 $ 2,065 $257,973
September 30, 1999 $ 76,057 $122,369 $ 1,108 $197,318
</TABLE>

During the years ended September 30, 2000, 1999, and 1998, marketable equity
available-for-sale securities with a fair value at the date of sale of
$12,640,000, $2,803,000, and $62,792,000, respectively, were sold. The gross
realized gains on such sales of available-for-sale securities totaled
$12,576,000, $2,547,000, and $30,820,000, respectively, and the gross realized
losses totaled $0, $0, and $1,034,000 respectively.

NOTE 7 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>

Balance, beginning of period ................ $ 75,182 $ 54,689 $ 114,454

Unrealized gains (losses) on
available-for-sale securities .......... 73,810 35,600 (66,610)
Less: Reclassification adjustment
for net gains realized in net income ... (24,000) (2,547) (29,786)
----------- ----------- -----------
Net unrealized gains (losses) ........ 49,810 33,053 (96,396)
Tax benefit (expense) .................... (18,928) (12,560) 36,631
----------- ----------- -----------
Net-of-tax amount .................... 30,882 20,493 (59,765)
----------- ----------- -----------

Balance, end of period ...................... $ 106,064 $ 75,182 $ 54,689
=========== =========== ===========
</TABLE>

NOTE 8 EMPLOYEE BENEFIT PLANS

The following tables set forth the Company's disclosures required by SFAS No.
132, "Employers' Disclosures About Pensions and Other Postretirement Benefits".

Change in benefit obligation:

<TABLE>
<CAPTION>
Years ended September 30, 2000 1999
---------- ----------
(in thousands)
<S> <C> <C>

Benefit obligation at beginning of year ........ $ 36,995 $ 36,954
Service cost ................................... 3,427 3,700
Interest cost .................................. 2,741 2,468
Actuarial (gain) loss .......................... 3,059 (4,468)
Benefits paid .................................. (1,384) (1,659)
---------- ----------
Benefit obligation at end of year .............. $ 44,838 $ 36,995
========== ==========
</TABLE>

Change in plan assets:

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999
---------- ----------
(in thousands)
<S> <C> <C>

Fair value of plan assets at beginning
of year ...................................... $ 58,517 $ 51,572
Actual return on plan assets ................... 3,478 8,604
Benefits paid .................................. (1,384) (1,659)
---------- ----------
Fair value of plan assets at end of year ....... $ 60,611 $ 58,517
========== ==========

Funded status of the plan ...................... $ 15,773 $ 21,522
Unrecognized net actuarial gain ................ (5,016) (10,127)
Unrecognized prior service cost ................ 786 1,025
Unrecognized net transition asset .............. (1,079) (1,619)
---------- ----------
Prepaid benefit cost ........................... $ 10,464 $ 10,801
========== ==========
</TABLE>

28
<PAGE> 29
WEIGHTED-AVERAGE ASSUMPTIONS:

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
---- ---- ----
<S> <C> <C> <C>

Discount rate ........................ 7.50% 7.50% 6.75%
Expected return on plan .............. 9.00% 9.00% 8.50%
Rate of compensation increase ........ 5.00% 5.00% 5.00%
</TABLE>

Components of net periodic cost:

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
---------- ---------- ----------
(in thousands)

<S> <C> <C> <C>
Service cost ................................ $ 3,427 $ 3,700 $ 2,836
Interest cost ............................... 2,741 2,468 2,430
Expected return on plan assets .............. (5,226) (4,606) (4,542)
Amortization of prior service cost .......... 238 238 238
Amortization of transition asset ............ (540) (540) (540)
Recognized net actuarial gain ............... (303) 14 (65)
---------- ---------- ----------
Net pension expense ......................... $ 337 $ 1,274 $ 357
========== ========== ==========
</TABLE>

DEFINED CONTRIBUTION PLAN:

Substantially all employees on the United States payroll of the Company may
elect to participate in the Company sponsored Thrift/401(k) Plan by contributing
a portion of their earnings. The Company contributes amounts equal to 100
percent of the first five percent of the participant's compensation subject to
certain limitations. Expensed Company contributions were $3,545,000, $3,315,000,
and $3,009,000 in 2000, 1999, and 1998, respectively.

NOTE 9 ACCRUED LIABILITIES

Accrued liabilities consist of the following:

<TABLE>
<CAPTION>
September 30, 2000 1999
---------- ----------
(in thousands)
<S> <C> <C>

Royalties payable ...................... $ 18,918 $ 9,625
Taxes payable - operations ............. 6,861 6,990
Ad valorem tax ......................... 7,783 7,177
Income taxes payable ................... -- 3,278
Workers compensation claims ............ 2,840 3,122
Payroll and employee benefits .......... 4,055 3,970
Other .................................. 6,158 7,038
---------- ----------
$ 46,615 $ 41,200
========== ==========
</TABLE>

NOTE 10 SUPPLEMENTAL CASH FLOW INFORMATION

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>

CASH PAYMENTS:
Interest paid .............. $ 2,491 $ 5,705 $ 1,721
Income taxes paid .......... $ 39,673 $ 27,843 $ 61,056
</TABLE>

NOTE 11 RISK FACTORS

CONCENTRATION OF CREDIT -
Financial instruments which potentially subject the Company to concentrations of
credit risk consist primarily of temporary cash investments and trade
receivables. The Company places temporary cash investments with established
financial institutions and invests in a diversified portfolio of highly rated,
short-term money market instruments. The Company's trade receivables are
primarily with companies in the oil and gas industry. The Company normally does
not require collateral except for certain receivables of customers in its
natural gas marketing operations.

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

The Company's decreased rig utilization rates during fiscal 1999 continued in
fiscal 2000. Depressed oil prices, the primary cause of the decrease, have since
recovered, with utilization recovery lagging behind. The Company believes that
its rig fleet is not currently impaired based on an assessment of future cash
flows of the assets in question. However, it is possible that the Company's
assessment that it will recover the carrying amount of its rig fleet from future
operations may change in the near term.

29
<PAGE> 30

OIL AND GAS OPERATIONS -
In estimating future cash flows attributable to the Company's exploration and
production assets, certain assumptions are made with regard to commodity prices
received and costs incurred. Due to the volatility of commodity prices, it is
possible that the Company's assumptions used in estimating future cash flows for
exploration and production assets may change in the near term.

NOTE 12 NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities", as amended by SFAS No. 137 and
SFAS No. 138, is effective for fiscal years beginning after June 15, 2000 and
requires that all derivatives be recognized as assets or liabilities in the
balance sheet and that these instruments be measured at fair value. The Company
will adopt the provisions of SFAS No. 133, as amended, effective October 1,
2000. The impact of the Company's adoption of SFAS No. 133, as amended, on the
Company's results of operations and financial position is not expected to be
material.

NOTE 13 SEGMENT INFORMATION

The Company operates principally in the contract drilling industry, which
includes a Domestic segment and an International segment, and in the oil and gas
industry, which includes an Exploration and Production segment and a Natural Gas
Marketing segment. The contract drilling operations consist of contracting
Company-owned drilling equipment primarily to major oil and gas exploration
companies. The Company's primary international areas of operation include
Venezuela, Colombia, Ecuador, Argentina and Bolivia. Oil and gas activities
include the exploration for and development of productive oil and gas properties
located primarily in Oklahoma, Texas, Kansas, and Louisiana, as well as, the
marketing of natural gas for third parties. The Natural Gas Marketing segment
also markets most of the natural gas produced by the Exploration and Production
segment retaining a market based fee from the sale of such production. The
Company also has a Real Estate segment whose operations are conducted
exclusively in the metropolitan area of Tulsa, Oklahoma. The primary areas of
operations include a major shopping center and several multi-tenant warehouses.
Each reportable segment is a strategic business unit which is managed separately
as an autonomous business. Other includes investments in available-for-sale
securities and corporate operations. The "other" component of Total Assets also
includes the Company's investment in equity-owned investments.

The Company evaluates performance of its segments based upon operating profit or
loss from operations before income taxes which includes revenues from external
and internal customers; operating costs; depreciation, depletion and
amortization; dry holes and abandonments and taxes other than income taxes. The
accounting policies of the segments are the same as those described in Note 1,
Summary of Accounting Policies. Intersegment sales are accounted for in the same
manner as sales to unaffiliated customers.

Summarized financial information of the Company's reportable segments for each
of the years ended September 30, 2000, 1999, and 1998 is shown in the following
table:

<TABLE>
<CAPTION>
Depreciation Additions
External Inter- Total Operating Depletion & Total to Long-Lived
(in thousands) Sales Segment Sales Profit Amortization Assets Assets
---------- ---------- ---------- ---------- ------------ ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
2000:
CONTRACT DRILLING
Domestic ...................... $ 214,531 $ 3,048 $ 217,579 $ 35,808 $ 35,310 $ 342,278 $ 40,722
International ................. 136,549 -- 136,549 9,753 38,096 259,892 13,825
---------- ---------- ---------- ---------- ----------- --------- ----------
351,080 3,048 354,128 45,561 73,406 602,170 54,547
---------- ---------- ---------- ---------- ----------- --------- ----------
OIL & GAS OPERATIONS
Exploration and Production .... 157,583 -- 157,583 66,604 33,462 174,466 65,804
Natural Gas Marketing ......... 80,907 -- 80,907 5,271 164 21,897 175
---------- ---------- ---------- ---------- ----------- --------- ----------
238,490 238,490 71,875 33,626 196,363 65,979
---------- ---------- ---------- ---------- ----------- --------- ----------

REAL ESTATE ..................... 8,999 1,545 10,544 5,346 1,598 24,235 2,909
OTHER ........................... 32,526 -- 32,526 -- 2,221 436,724 8,497
ELIMINATIONS .................... -- (4,593) (4,593) -- -- -- --
---------- ---------- ---------- ---------- ----------- --------- ----------
TOTAL ....................... $ 631,095 -- $ 631,095 $ 122,782 $ 110,851 $1,259,492 $ 131,932
========== ========== ========== ========== =========== ========= ==========
</TABLE>

30
<PAGE> 31

Depreciation Additions
External Inter- Total Operating Depletion & Total to Long-Lived
(in thousands) Sales Segment Sales Profit Amortization Assets Assets
- -------------- --------- ------- ----- --------- ------------ ------ -------------
<S> <C> <C> <C> <C> <C> <C> <C>
1999:
CONTRACT DRILLING
Domestic.......................... $213,647 $ 2,457 $216,104 $ 30,154 $ 31,164 $ 371,766 $ 57,975
International..................... 182,987 -- 182,987 29,845 36,178 271,746 17,293
-------- -------- -------- -------- -------- ---------- --------
396,634 2,457 399,091 59,999 67,342 643,512 75,268
-------- -------- -------- -------- -------- ---------- --------
OIL & GAS OPERATIONS
Exploration and Production........ 95,953 -- 95,953 11,245 38,658 151,898 44,333
Natural Gas Marketing............. 55,259 -- 55,259 4,418 174 15,156 261
-------- -------- -------- -------- -------- ---------- --------
151,212 -- 151,212 15,663 38,832 167,054 44,594
-------- -------- -------- -------- -------- ---------- --------
REAL ESTATE......................... 8,671 1,531 10,202 5,338 1,427 22,816 1,445
OTHER............................... 7,802 -- 7,802 -- 1,566 276,317 1,644
ELIMINATIONS........................ -- (3,988) (3,988) -- -- -- --
-------- -------- -------- -------- -------- ---------- --------
TOTAL........................... $564,319 $ -- $564,319 $ 81,000 $109,167 $1,109,699 $122,951
======== ======== ======== ======== ======== ========== ========
1998:
CONTRACT DRILLING
Domestic.......................... $177,059 $ 4,084 $181,143 $ 35,817 $ 23,771 $ 351,193 $130,237
International..................... 253,072 -- 253,072 50,834 31,689 303,907 83,843
-------- -------- -------- -------- -------- ---------- --------
430,131 4,084 434,215 86,651 55,460 655,100 214,080
-------- -------- -------- -------- -------- ---------- --------
OIL & GAS OPERATIONS
Exploration and Production........ 98,696 -- 98,696 28,088 29,817 156,582 48,066
Natural Gas Marketing............. 53,499 -- 53,499 2,418 292 15,069 636
-------- -------- -------- -------- -------- ---------- --------
152,195 -- 152,195 30,506 30,109 171,651 48,702
-------- -------- -------- -------- -------- ---------- --------

REAL ESTATE......................... 8,922 1,526 10,448 5,371 1,501 22,937 875
OTHER............................... 45,392 -- 45,392 -- 1,280 240,742 2,642
ELIMINATIONS........................ -- (5,610) (5,610) -- -- -- --
-------- -------- -------- -------- -------- ---------- --------
TOTAL........................... $636,640 $ -- $636,640 $122,528 $ 88,350 $1,090,430 $266,299
======== ======== ======== ======== ======== ========== ========
</TABLE>

The following table reconciles segment operating profit per the table on pages
30 and 31 to income before taxes and equity in income of affiliate as reported
on the Consolidated Statements of Income (in thousands).

Years Ended September 30, 2000 1999 1998
--------- --------- ---------

<S> <C> <C> <C>
Segment operating profit .................... $ 122,782 $ 81,000 $ 122,528

Unallocated amounts:
Income from investments .................. 31,973 7,757 44,603
General and administrative expense ....... (11,578) (14,198) (11,762)
Interest expense ......................... (3,076) (6,481) (942)
Corporate depreciation ................... (2,152) (1,565) (1,280)
Other corporate expense .................. (1,186) (1,575) (927)
--------- --------- ---------
Total unallocated amounts .............. 13,981 (16,062) 29,692
--------- --------- ---------

Income before income taxes and equity in
Income of affiliate ...................... $ 136,763 $ 64,938 $ 152,220
========= ========= =========
</TABLE>

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, 2000 1999 1998
-------- -------- --------
<S> <C> <C> <C>
Revenues
United States ......... $494,546 $381,332 $383,568
Venezuela ............. 34,922 59,481 131,137
Colombia .............. 42,509 60,838 79,675
Other Foreign ......... 59,118 62,668 42,260
-------- -------- --------
Total ............... $631,095 $564,319 $636,640
======== ======== ========
Long-Lived Assets
United States ......... $477,593 $479,753 $475,832
Venezuela ............. 37,001 62,931 85,703
Colombia .............. 26,361 46,621 59,848
Other Foreign ......... 132,650 101,910 70,988
-------- -------- --------

Total ............... $673,605 $691,215 $692,371
======== ======== ========
</TABLE>

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

31
<PAGE> 32

Revenues from one company doing business with the contract drilling segment
accounted for approximately 15.2 percent, 17.5 percent and 14.5 percent of the
total consolidated revenues during the years ended September 30, 2000, 1999, and
1998, respectively. Revenues from another company doing business with the
contract drilling segment accounted for approximately 7.4 percent, 12 percent,
and 10 percent of total consolidated revenues in the years ended September 30,
2000, 1999, and 1998, respectively. Collectively, revenues from companies
controlled by the Venezuelan government accounted for approximately 3.6 percent,
5.6 percent and 16 percent of total consolidated revenues for the years ended
September 30, 2000, 1999, and 1998, respectively. Collectively, the receivables
from these customers were approximately $24.0 million and $35.6 million at
September 30, 2000 and 1999, respectively.

NOTE 14 SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES

All of the Company's oil and gas producing activities are located in the United
States.

Results of Operations from Oil and Gas Producing Activities -

Years Ended September 30, 2000 1999 1998
------------ ------------ ------------
(in thousands)
<S> <C> <C> <C>
Revenues ................................................ $ 157,583 $ 95,953 $ 98,696
------------ ------------ ------------
Production costs ........................................ 26,685 23,058 21,786
Exploration expense and valuation provisions............. 30,832 22,992 19,005
Depreciation, depletion and amortization................. 33,462 38,658 29,817
Income tax expense ...................................... 23,447 3,437 9,415
------------ ------------ ------------
Total cost and expenses ............................... 114,426 88,145 80,023
------------ ------------ ------------
Results of operations (excluding corporate overhead
and interest costs) ................................... $ 43,157 $ 7,808 $ 18,673
============ ============ ============
</TABLE>

Capitalized Costs -

September 30, 2000 1999
------------ ------------
(in thousands)
<S> <C> <C>
Proved properties ............................................ $ 430,675 $ 421,552
Unproved properties .......................................... 27,050 25,337
------------ ------------
Total costs ................................................ 457,725 446,889

Less - Accumulated depreciation, depletion and amortization .. 314,091 312,644
------------ ------------
Net ........................................................ $ 143,634 $ 134,245
============ ============
</TABLE>

Costs Incurred Relating to Oil and Gas Producing Activities -

Years Ended September 30, 2000 1999 1998
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Property acquisition:
Proved ................................. $ 105 $ 89 $ 107
Unproved ............................... 11,040 14,385 9,096
Exploration .............................. 43,833 22,292 18,107
Development .............................. 18,843 19,167 28,259
----------- ----------- -----------
Total .................................. $ 73,821 $ 55,933 $ 55,569
=========== =========== ===========
</TABLE>

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) -

Proved reserves are estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those which are
expected to be recovered through existing wells with existing equipment and
operating methods. The following is an analysis of proved oil and gas reserves
as estimated by Netherland, Sewell &~Associates, Inc. at September 30, 2000. All
prior years were estimated by the Company and reviewed by independent engineers.

32
<PAGE> 33

OIL (Bbls) GAS (Mmcf)
---------- ----------

<S> <C> <C>
Proved reserves at September 30, 1997 ......... 5,805,386 263,236
Revisions of previous estimates ............... (331,280) 10,877
Extensions, discoveries and other additions ... 175,265 20,819
Production .................................... (701,180) (42,862)
Purchases of reserves-in-place ................ 2,890 188
Sales of reserves-in-place .................... (189,768) (632)
---------- ----------

Proved reserves at September 30, 1998 ......... 4,761,313 251,626
Revisions of previous estimates ............... 570,126 11,771
Extensions, discoveries and other additions ... 151,829 22,491
Production .................................... (649,370) (44,240)
Purchases of reserves-in-place ................ -- 77
Sales of reserves-in-place .................... -- (2,105)
---------- ----------
Proved reserves at September 30, 1999 ......... 4,833,898 239,620
Revisions of previous estimates ............... 1,316,714 17,363
Extensions, discoveries and other additions ... 1,119,314 52,569
Production .................................... (880,304) (46,923)
Purchases of reserves-in-place ................ 1,502 242
Sales of reserves-in-place .................... (85,987) (373)
---------- ----------
Proved reserves at September 30, 2000 ......... 6,305,137 262,498
========== ==========

Proved developed reserves at
September 30, 1998 ......................... 4,754,319 249,376
========== ==========
September 30, 1999 ......................... 4,828,071 229,765
========== ==========
September 30, 2000 ......................... 5,847,217 217,334
========== ==========
</TABLE>

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (Unaudited) -

The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement under
Financial Accounting Standards Board Statement No. 69 "Disclosures About Oil and
Gas Producing Activities". The Standardized Measure does not purport to present
the fair market value of a company's proved oil and gas reserves. This would
require consideration of expected future economic and operating conditions,
which are not taken into account in calculating the Standardized Measure.

Under the Standardized Measure, future cash inflows were estimated by applying
year-end prices to the estimated future production of year-end proved reserves.
Future cash inflows were reduced by estimated future production and development
costs based on year-end costs to determine pre-tax cash inflows. Future income
taxes were computed by applying the statutory tax rate to the excess of pre-tax
cash inflows over the Company's tax basis in the associated proved oil and gas
properties. Tax credits and permanent differences were also considered in the
future income tax calculation. Future net cash inflows after income taxes were
discounted using a ten percent annual discount rate to arrive at the
Standardized Measure.

At September 30, 2000 1999
------------- -------------
(in thousands)

<S> <C> <C>
Future cash inflows ........................................ $ 1,377,922 $ (688,766)
Future costs -
Future production and development costs ................ (317,898) (188,579)
Future income tax expense .............................. (331,672) (135,763)
------------- -------------
Future net cash flows ...................................... 728,352 364,424
10% annual discount for estimated timing of cash flows ..... (240,281) (131,806)
------------- -------------
Standardized Measure of discounted future net cash flows ... $ 488,071 $ 232,618
============= =============
</TABLE>

33
<PAGE> 34

Changes in Standardized Measure Relating to Proved Oil and Gas Reserves
(Unaudited) -

Years Ended September 30, 2000 1999 1998
------------ ------------ ------------
(in thousands)
<S> <C> <C> <C>
Standardized Measure - Beginning of year ..................... $ 232,618 $ 125,927 $ 205,035
Increases (decreases) -
Sales, net of production costs ............................. (130,898) (72,895) (76,910)
Net change in sales prices, net of production costs ........ 261,926 142,970 (97,938)
Discoveries and extensions, net of related future
development and production costs ....................... 156,840 38,164 21,922
Changes in estimated future development costs .............. (36,994) (11,095) (14,142)
Development costs incurred ................................. 13,587 16,558 25,149
Revisions of previous quantity estimates ................... 57,730 17,713 5,089
Accretion of discount ...................................... 30,951 16,700 28,012
Net change in income taxes ................................. (114,762) (40,671) 30,436
Purchases of reserves-in-place ............................. 542 96 65
Sales of reserves-in-place ................................. (700) (1,390) (2,875)
Other ...................................................... 17,231 541 2,084
------------ ------------ ------------
Standardized Measure - End of year ........................... $ 488,071 $ 232,618 $ 125,927
============ ============ ============
</TABLE>

NOTE 15 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

(in thousands, except per share amounts)

2000 1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Revenues ............................ $ 149,581 $ 151,848 $ 151,968 $ 177,698
Gross profit ........................ 37,852 36,256 32,605 44,704
Net income .......................... 20,461 19,273 18,557 24,009
Basic net income per share .......... .41 .39 .37 .48
Diluted net income per share ........ .41 .39 .37 .48
</TABLE>

1999 1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Revenues .......................... $ 143,864 $ 155,374 $ 131,799 $ 133,282
Gross profit ...................... 25,071 16,924 23,532 20,090
Net income ........................ 12,811 7,352 12,196 10,429
Basic net income per share ........ .26 .15 .25 .21
Diluted net income per share ...... .26 .15 .24 .21
</TABLE>

Gross profit represents total revenues less operating costs, depreciation,
depletion and amortization, dry holes and abandonments, and taxes, other than
income taxes.

The sum of earnings per share for the four quarters may not equal the total
earnings per share for the year due to changes in the average number of common
shares outstanding.

Net income in the first quarter of 2000 includes approximately $6.3 million
($0.13 per share, on a diluted basis) on gains related to a non-monetary
dividend received and a gain on the conversion of shares of common stock of a
Company investee pursuant to that investee being acquired.

Net income in the fourth quarter of 2000 includes an after-tax charge of $2.5
million ($0.05 per share, on a diluted basis) related to the write-down of
producing properties in accordance with SFAS No. 121.

Net income in the second quarter of 1999 includes an after-tax charge of $5.5
million ($0.11 per share, on a diluted basis) in connection with the drilling
and completion of a pinnacle reef well with reserve values significantly below
its carrying cost.

<PAGE> 35

REPORT OF INDEPENDENT AUDITORS

HELMERICH & PAYNE, INC.

The Board of Directors and Shareholders
Helmerich & Payne, Inc.

We have audited the accompanying consolidated balance sheets of Helmerich &
Payne, Inc. as of September 30, 2000 and 1999, and the related consolidated
statements of income, shareholders' equity, and cash flows for each of the three
years in the period ended September 30, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Helmerich &
Payne, Inc. at September 30, 2000 and 1999, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
September 30, 2000, in conformity with accounting principles generally accepted
in the United States.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
November 17, 2000

STOCK PRICE INFORMATION

<TABLE>
<CAPTION>
Closing Market Price Per Share
----------------------------------------
2000 1999
------------------ ------------------
QUARTERS HIGH LOW HIGH LOW
- -------- ------- ------- ------- -------
<S> <C> <C> <C> <C>
First............................... $ 27.44 $ 19.13 $ 24.50 $ 16.75
Second.............................. 31.00 20.00 23.94 16.06
Third............................... 37.75 29.06 26.75 20.38
Fourth.............................. 38.31 30.06 30.19 23.00
</TABLE>

DIVIDEND INFORMATION

<TABLE>
<CAPTION>
Paid Per Share Total Payment
-------------- --------------------------
2000 1999 2000 1999
----- ----- ---------- ----------
QUARTERS
- --------
<S> <C> <C> <C> <C>
First............................. $.070 $.070 $3,474,612 $3,457,626
Second............................ .070 .070 3,475,623 3,459,168
Third............................. .070 .070 3,484,189 3,464,109
Fourth............................ .075 .070 3,740,863 3,468,377
</TABLE>

STOCKHOLDERS' MEETING

The annual meeting of stockholders will be held on March 7, 2001. A formal
notice of the meeting, together with a proxy statement and form of proxy, will
be mailed to shareholders on or about January 26, 2001.

STOCK EXCHANGE LISTING

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

STOCK TRANSFER AGENT AND REGISTRAR

As of December 15, 2000, there were 1,170 record holders of Helmerich & Payne,
Inc. common stock as listed by the transfer agent's records.

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

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

FORM 10-K

The Company's Annual Report on Form 10-K, which has been submitted to the
Securities and Exchange Commission, is available free of charge upon written
request.

DIRECT INQUIRIES TO:
President
Helmerich & Payne, Inc.
Utica at Twenty-First
Tulsa, Oklahoma 74114
Telephone: (918) 742-5531

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

<PAGE> 36

ELEVEN-YEAR FINANCIAL REVIEW

HELMERICH & PAYNE, INC.

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
---------- ---------- ----------
<S> <C> <C> <C>
REVENUES AND INCOME*(2)
Contract Drilling Revenues ....................... 349,992 394,715 427,713
Crude Oil Sales .................................. 24,601 9,479 10,333
Natural Gas Sales ................................ 131,056 81,533 87,646
Gas Marketing Revenues ........................... 78,921 54,263 52,469
Real Estate Revenues ............................. 8,991 8,663 8,587
Dividend Income .................................. 14,482 3,569 4,117
Other Revenues ................................... 23,052 12,097 45,775
Total Revenues+ .................................. 631,095 564,319 636,640
Net Cash Provided by Continuing Operations+ ...... 201,836 158,694 113,533
Income from Continuing Operations ................ 82,300 42,788 101,154
Net Income ....................................... 82,300 42,788 101,154

PER SHARE DATA
Income from Continuing Operations(1):
Basic ........................................ 1.66 .87 2.03
Diluted ...................................... 1.64 .86 2.00
Net Income(1):
Basic ........................................ 1.66 .87 2.03
Diluted ...................................... 1.64 .86 2.00
Cash Dividends ................................... .285 .28 .275
Shares Outstanding* .............................. 49,980 49,626 49,383

FINANCIAL POSITION
Net Working Capital* ............................. 186,250 88,720 58,861
Ratio of Current Assets to Current Liabilities ... 3.36 2.23 1.47
Investments* ..................................... 304,326 238,475 200,400
Total Assets* .................................... 1,259,492 1,109,699 1,090,430
Long-Term Debt* .................................. 50,000 50,000 50,000
Shareholders' Equity* ............................ 955,703 848,109 793,148

CAPITAL EXPENDITURES*
Contract Drilling Equipment ...................... 49,774 68,639 206,794
Wells and Equipment .............................. 54,764 29,947 38,970
Real Estate ...................................... 2,880 1,435 854
Other Assets (includes undeveloped leases) ....... 24,514 22,930 19,681
Discontinued Operations .......................... -- -- --
Total Capital Outlays ............................ 131,932 122,951 266,299

PROPERTY, PLANT AND EQUIPMENT AT COST*
Contract Drilling Equipment ...................... 891,749 881,269 829,217
Producing Properties ............................. 430,674 421,552 414,770
Undeveloped Leases ............................... 27,050 25,337 20,977
Real Estate ...................................... 50,649 49,065 48,451
Other ............................................ 80,268 71,139 65,120
Discontinued Operations .......................... -- -- --
Total Property, Plant and Equipment .............. 1,480,390 1,448,362 1,378,535
</TABLE>

* 000's omitted.

+ Chemical operations were sold August 30, 1996. Prior year amounts have been
restated to exclude discontinued operations.

(1) Includes $13.6 million ($.28 per share, on a diluted basis) effect of
impairment charge for adoption of SFAS No. 121 in 1995 and cumulative
effect of change in accounting for income taxes of $4,000,000 ($.08 per
share, on a diluted basis) in 1994.

(2) See Note 13 for segment presentation of revenues.

<PAGE> 37

<TABLE>
<CAPTION>
Years Ended September 30, 1997 1996 1995 1994
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
REVENUES AND INCOME*(2)
Contract Drilling Revenues ....................... 315,327 244,338 203,325 182,781
Crude Oil Sales .................................. 20,475 15,378 13,227 13,161
Natural Gas Sales ................................ 87,737 60,500 33,851 45,261
Gas Marketing Revenues ........................... 66,306 57,817 34,729 51,874
Real Estate Revenues ............................. 8,224 8,076 7,560 7,396
Dividend Income .................................. 5,268 3,650 3,389 3,621
Other Revenues ................................... 14,522 3,496 10,640 6,058
Total Revenues+ .................................. 517,859 393,255 306,721 310,152
Net Cash Provided by Continuing Operations+ ...... 165,568 121,420 84,010 74,463
Income from Continuing Operations ................ 84,186 45,426 5,788 17,108
Net Income ....................................... 84,186 72,566 9,751 24,971

PER SHARE DATA
Income from Continuing Operations(1):
Basic ........................................ 1.69 .92 .12 .35
Diluted ...................................... 1.67 .91 .12 .35
Net Income(1):
Basic ........................................ 1.69 1.47 .20 .51
Diluted ...................................... 1.67 1.46 .20 .51
Cash Dividends ................................... .26 .2525 .25 .2425
Shares Outstanding* .............................. 50,028 49,771 49,529 49,420

FINANCIAL POSITION
Net Working Capital* ............................. 62,837 51,803 50,038 76,238
Ratio of Current Assets to Current Liabilities ... 1.66 1.83 1.74 2.63
Investments* ..................................... 323,510 229,809 156,908 87,414
Total Assets* .................................... 1,033,595 821,914 707,061 621,689
Long-Term Debt* .................................. -- -- -- --
Shareholders' Equity* ............................ 780,580 645,970 562,435 524,334

CAPITAL EXPENDITURES*
Contract Drilling Equipment ...................... 109,036 79,269 80,943 53,752
Wells and Equipment .............................. 35,024 21,142 19,384 40,916
Real Estate ...................................... 1,095 752 873 902
Other Assets (includes undeveloped leases) ....... 16,022 7,003 9,717 9,695
Discontinued Operations .......................... -- 1,581 859 618
Total Capital Outlays ............................ 161,177 109,747 111,776 105,883

PROPERTY, PLANT AND EQUIPMENT AT COST*
Contract Drilling Equipment ...................... 643,619 568,110 501,682 444,432
Producing Properties ............................. 395,812 392,562 384,755 377,371
Undeveloped Leases ............................... 14,109 9,242 8,051 11,729
Real Estate ...................................... 47,682 46,970 46,642 47,827
Other ............................................ 59,659 53,547 55,655 48,612
Discontinued Operations .......................... -- -- 13,937 13,131
Total Property, Plant and Equipment .............. 1,160,881 1,070,431 1,010,722 943,102

Years Ended September 30, 1993 1992 1991 1990
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
REVENUES AND INCOME*(2)
Contract Drilling Revenues ....................... 149,661 112,833 105,364 90,974
Crude Oil Sales .................................. 15,392 16,369 17,374 16,058
Natural Gas Sales ................................ 52,446 38,370 35,628 37,697
Gas Marketing Revenues ........................... 63,786 40,410 10,055 10,566
Real Estate Revenues ............................. 7,620 7,541 7,542 7,636
Dividend Income .................................. 3,535 4,050 5,285 7,402
Other Revenues ................................... 8,283 6,646 20,020 56,131
Total Revenues+ .................................. 300,723 226,219 201,268 226,464
Net Cash Provided by Continuing Operations+ ...... 72,493 60,414 50,006 53,288
Income from Continuing Operations ................ 22,158 8,973 19,608 45,489
Net Income ....................................... 24,550 10,849 21,241 47,562

PER SHARE DATA
Income from Continuing Operations(1):
Basic ........................................ .46 .19 .41 .94
Diluted ...................................... .45 .19 .41 .93
Net Income(1):
Basic ........................................ .51 .22 .44 .98
Diluted ...................................... .50 .22 .44 .98
Cash Dividends ................................... .24 .2325 .23 .22
Shares Outstanding* .............................. 49,275 49,152 48,976 48,971

FINANCIAL POSITION
Net Working Capital* ............................. 104,085 82,800 108,212 146,741
Ratio of Current Assets to Current Liabilities ... 3.24 3.31 4.19 3.72
Investments* ..................................... 84,945 87,780 96,471 99,574
Total Assets* .................................... 610,504 585,504 575,168 582,927
Long-Term Debt* .................................. 3,600 8,339 5,693 5,648
Shareholders' Equity* ............................ 508,927 493,286 491,133 479,485

CAPITAL EXPENDITURES*
Contract Drilling Equipment ...................... 24,101 43,049 56,297 18,303
Wells and Equipment .............................. 23,142 21,617 34,741 16,489
Real Estate ...................................... 436 690 2,104 1,467
Other Assets (includes undeveloped leases) ....... 5,901 16,984 6,793 5,448
Discontinued Operations .......................... 629 158 2,594 1,153
Total Capital Outlays ............................ 54,209 82,498 102,529 42,860

PROPERTY, PLANT AND EQUIPMENT AT COST*
Contract Drilling Equipment ...................... 418,004 404,155 370,494 324,293
Producing Properties ............................. 340,176 329,264 312,438 287,248
Undeveloped Leases ............................... 10,010 12,973 5,552 5,507
Real Estate ...................................... 47,502 47,286 46,671 44,928
Other ............................................ 45,085 43,153 36,423 32,135
Discontinued Operations .......................... 12,545 11,962 11,838 9,270
Total Property, Plant and Equipment .............. 873,322 848,793 783,416 703,381
</TABLE>

<PAGE> 38

ELEVEN-YEAR OPERATING REVIEW
HELMERICH & PAYNE, INC.

<TABLE>
<CAPTION>
Years Ended September 30, 2000 1999 1998
------ ------ ------
<S> <C> <C> <C>
CONTRACT DRILLING
Drilling Rigs, United States................. 48 46 46
Drilling Rigs, International................. 40 44 44
Contract Wells Drilled, United States........ 335 242 242
Total Footage Drilled, United States*........ 4,058 2,938 2,938
Average Depth per Well, United States........ 12,115 12,142 12,142
Percentage Rig Utilization, United States.... 87 75 95
Percentage Rig Utilization, International.... 47 53 88

PETROLEUM EXPLORATION AND DEVELOPMENT

Gross Wells Completed........................ 81 49 62
Net Wells Completed.......................... 42.7 23.9 35.7
Net Dry Holes................................ 9.1 7.1 4.2

PETROLEUM PRODUCTION
Net Crude Oil and Natural Gas Liquids
Produced (barrels daily)................... 2,405 1,779 1,921
Net Oil Wells Owned -- Primary Recovery...... 107.1 124 124
Net Oil Wells Owned -- Secondary Recovery.... 55.5 54 53
Secondary Oil Recovery Projects.............. 3 5 5
Net Natural Gas Produced
(thousands of cubic feet daily)............ 128,204 121,206 117,431
Net Gas Wells Owned.......................... 453 439 436

REAL ESTATE MANAGEMENT
Gross Leasable Area (square feet)*........... 1,652 1,652 1,652
Percentage Occupancy......................... 91 95 97

TOTAL NUMBER OF EMPLOYEES

Helmerich & Payne, Inc. and Subsidiaries..... 3,606 3,440 3,340

</TABLE>

* 000's omitted.

38
<PAGE> 39

<TABLE>
<CAPTION>
Years Ended September 30, 1997 1996 1995 1994 1993 1992 1991 1990
------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
CONTRACT DRILLING
Drilling Rigs, United States................. 38 41 41 47 42 39 46 49
Drilling Rigs, International................. 39 36 35 29 29 30 25 20
Contract Wells Drilled, United States........ 246 233 212 162 128 100 106 119
Total Footage Drilled, United States*........ 2,753 2,499 1,933 1,842 1,504 1,085 1,301 1,316
Average Depth per Well, United States........ 11,192 10,724 9,119 11,367 11,746 10,853 12,274 11,059
Percentage Rig Utilization, United States.... 88 82 71 69 53 42 47 50
Percentage Rig Utilization, International.... 91 85 84 88 68 69 69 45

PETROLEUM EXPLORATION AND DEVELOPMENT
Gross Wells Completed........................ 100 63 59 44 42 54 45 36
Net Wells Completed.......................... 49.3 35.3 27.4 15 15.9 17.8 20.2 15.3
Net Dry Holes................................ 9.6 7.3 5.9 1.7 4.3 4.3 4.3 3.4

PETROLEUM PRODUCTION
Net Crude Oil and Natural Gas Liquids
Produced (barrels daily)................... 2,700 2,212 2,214 2,431 2,399 2,334 2,152 2,265
Net Oil Wells Owned -- Primary Recovery...... 133 176.9 186 202 202 220 227 223
Net Oil Wells Owned -- Secondary Recovery.... 49 63.8 64 71 71 74 55 46
Secondary Oil Recovery Projects.............. 5 12 12 14 14 14 12 12
Net Natural Gas Produced
(thousands of cubic feet daily)............ 110,859 94,358 72,387 72,953 78,023 75,470 66,617 65,147
Net Gas Wells Owned.......................... 410 378 354 341 307 289 278 194

REAL ESTATE MANAGEMENT
Gross Leasable Area (square feet)*........... 1,652 1,654 1,652 1,652 1,656 1,656 1,664 1,664
Percentage Occupancy......................... 95 94 87 83 86 87 86 85

TOTAL NUMBER OF EMPLOYEES
Helmerich & Payne, Inc. and Subsidiaries..... 3,627 3,309 3,245 2,787 2,389 1,928 1,758 1,864

</TABLE>

39
<PAGE> 40

<TABLE>
<CAPTION>
DIRECTORS OFFICERS
- --------- --------

<S> <C>
W. H. HELMERICH, III W. H. HELMERICH, III
Chairman of the Board Chairman of the Board
Tulsa, Oklahoma
HANS HELMERICH
HANS HELMERICH President and Chief Executive Officer
President and Chief Executive Officer
Tulsa, Oklahoma GEORGE S. DOTSON
Vice President,
WILLIAM L. ARMSTRONG** President of Helmerich & Payne
Chairman International Drilling Co.
Transland Financial Services, Inc.
Denver, Colorado DOUGLAS E. FEARS
Vice President and
GLENN A. COX* Chief Financial Officer
President and Chief Operating Officer, Retired
Phillips Petroleum Company STEVEN R. MACKEY
Bartlesville, Oklahoma Vice President, Secretary,
and General Counsel
GEORGE S. DOTSON
Vice President, STEVEN R. SHAW
President of Helmerich & Payne Vice President,
International Drilling Co. Exploration & Production
Tulsa, Oklahoma

L. F. ROONEY, III*
Chief Executive Officer
Manhattan Construction Company
Tulsa, Oklahoma

EDWARD B. RUST, JR.
Chairman and Chief Executive Officer
State Farm Insurance Companies
Bloomington, Illinois

GEORGE A. SCHAEFER**
Chairman and Chief Executive Officer, Retired
Caterpillar Inc.
Peoria, Illinois

JOHN D. ZEGLIS**
President
AT&T
Basking Ridge, New Jersey
</TABLE>

* Member, Audit Committee
** Member, Human Resources Committee

40
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-22
<SEQUENCE>3
<FILENAME>d82779ex22.txt
<DESCRIPTION>SUBSIDIARIES OF THE REGISTRANT
<TEXT>

<PAGE> 1
EXHIBIT 22

SUBSIDIARIES OF THE REGISTRANT

Helmerich & Payne, Inc.

Subsidiaries of Helmerich & Payne, Inc.

Helmerich & Payne Properties, Inc. (Incorporated in Oklahoma)
Utica Square Shopping Center, Inc. (Incorporated in Oklahoma)
The Hardware Store of Utica Square, Inc. (Incorporated in Oklahoma)
The Space Center, Inc. (Incorporated in Oklahoma)
H&P DISC, Inc. (Incorporated in Oklahoma)
Helmerich & Payne Coal Co. (Incorporated in Oklahoma)
Helmerich & Payne Energy Services, Inc. (Incorporated in Oklahoma)
Helmerich & Payne International Drilling Co. (Incorporated in
Delaware)

Subsidiaries of Helmerich & Payne International Drilling Co.

Helmerich & Payne (Africa) Drilling Co. (Incorporated
in Cayman Islands, British West Indies)
Helmerich & Payne Drilling (Bolivia) S.A.
(Incorporated in Bolivia)
Helmerich & Payne (Colombia) Drilling Co. (Incorporated
in Oklahoma)
Helmerich & Payne (Gabon) Drilling Co. (Incorporated in
Cayman Islands, British West Indies)
Helmerich & Payne (Argentina) Drilling Co. (Incorporated
in Oklahoma)
Helmerich & Payne (Peru) Drilling Co. (Incorporated in
Oklahoma)
Helmerich & Payne (Peru) Drilling Co., Sucursal del Peru,
Lima (Lima Branch - Incorporated in Peru)
Helmerich & Payne (Peru) Drilling Co., Sucursal del Peru
(Iquitos Branch - Incorporated in Peru)
Helmerich & Payne (Australia) Drilling Co. (Incorporated
in Oklahoma)
Helmerich & Payne del Ecuador, Inc. (Incorporated in
Oklahoma)
Helmerich & Payne de Venezuela, C.A. (Incorporated in
Venezuela)
Helmerich & Payne, C.A. (Incorporated in Venezuela)
Helmerich & Payne Rasco, Inc. (Incorporated in Oklahoma)
H&P Finco (Incorporated in Cayman Islands, British
West Indies)
H&P Invest Ltd. (Incorporated in Cayman Islands), British
West Indies, doing business as H&P (Yemen) Drilling Co.

Subsidiary of H&P Invest Ltd.

Turrum Pty. Ltd. (Incorporated in Papua, New Guinea)
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.1
<SEQUENCE>4
<FILENAME>d82779ex23-1.txt
<DESCRIPTION>CONSENT OF INDEPENDENT AUDITORS
<TEXT>

<PAGE> 1
EXHIBIT 23.1

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in this Annual Report
(Form 10-K) of Helmerich & Payne, Inc. of our report dated November 17, 2000,
included in the 2000 Annual Report to Shareholders of Helmerich & Payne, Inc.

We also consent to the incorporation by reference in the Registration
Statements (Form S-8 Nos. 33-55239, 333-24211, and 333-34939) pertaining,
respectively, to the 1990 Stock Option Plan, Non-Employee Directors' Stock
Compensation Plan, and 1996 Stock Incentive Plan of our report dated November
17, 2000, with respect to the consolidated financial statements of Helmerich &
Payne, Inc. incorporated by reference in the Annual Report (Form 10-K) for the
year ended September 30, 2000.

ERNST & YOUNG LLP

Tulsa, Oklahoma
December 27, 2000
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-27
<SEQUENCE>5
<FILENAME>d82779ex27.txt
<DESCRIPTION>FINANCIAL DATA SCHEDULE
<TEXT>

<ARTICLE> 5
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-2000
<PERIOD-START> OCT-01-1999
<PERIOD-END> SEP-30-2000
<CASH> 108,087
<SECURITIES> 304,326
<RECEIVABLES> 108,633
<ALLOWANCES> 2,003
<INVENTORY> 25,598
<CURRENT-ASSETS> 265,144
<PP&E> 1,480,390
<DEPRECIATION> 806,785
<TOTAL-ASSETS> 1,259,492
<CURRENT-LIABILITIES> 78,894
<BONDS> 0
<PREFERRED-MANDATORY> 0
<PREFERRED> 0
<COMMON> 5,353
<OTHER-SE> 950,350
<TOTAL-LIABILITY-AND-EQUITY> 1,259,492
<SALES> 599,122
<TOTAL-REVENUES> 631,095
<CGS> 482,873
<TOTAL-COSTS> 482,873
<OTHER-EXPENSES> 9,183
<LOSS-PROVISION> (800)
<INTEREST-EXPENSE> 3,076
<INCOME-PRETAX> 136,763
<INCOME-TAX> 57,684
<INCOME-CONTINUING> 82,300
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 82,300
<EPS-BASIC> 1.66
<EPS-DILUTED> 1.64

</TABLE>
</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
-----END PRIVACY-ENHANCED MESSAGE-----