Helmerich & Payne, Inc. Annual Report for 2001
Revenue Breakdown for 2001
International
19%
Contract
Drilling
Domestic
40%
Exploration &
Production
26%
Oil and Gas
Natural Gas
Marketing
12%
Investments and Other Income 2%
Real Estate 1%
Financial Highlights
Years Ended September 30,
2001
2000
Revenues
Net Income
Diluted Earnings Per Share
Dividends Paid Per Share
$ 826,854,000
$ 631,095,000
$ 144,254,000
$ 182,300,000
$ 2.84
$ .30
$ 1.64
$ .285
Capital Expenditures
$ 274,670,000
$ 131,932,000
Total Assets
$1,364,507,000
$1,259,492,000
President’s Letter
To the Co-owners of Helmerich & Payne, Inc.
Sometimes risk factors are difficult to identify, much less
quantify. Unthinkable risks confronted each of us and our
families in the aftermath of the terrorist attacks on the World
Trade Center and Pentagon. Dinner table conversations at
home and discussions at work contemplated possible threats
of anthrax exposure, bioterror, and even nuclear “dirty bomb”
strikes on civilians.
Today we are a nation at war, facing a real and present
danger to our basic freedoms and liberty. We are also a
nation united and determined. A renewed patriotic spirit
has raised a standard against the evil that struck at our
core values. We have witnessed acts of untold heroism
and sacrifice, along with a flood of prayers and support
from friends of freedom around the globe.
We have been inspired by the leadership of President Bush:
“The course of this conflict is not known, yet its outcome is
certain. Freedom and fear, justice and cruelty have always
been at war and we know that God is not neutral between
them. The advance of human freedom now depends on us.
We will rally the world to this cause by our efforts, by our
courage. We will not tire, we will not falter, and we will not fail.”
2
The President has urged all Americans to take up the fight,
in part, by leading our lives. That is what your Company
intends to do. Each of our employees plays a proud part
in an industry vital to our country’s energy security.
Remarkably, energy prices are falling at the end of 2001,
even in the face of the current geopolitical situation in
the Middle East. Will a “smoking gun” surface to further
implicate Iraq in terrorist sponsorship? Will a bloody
and volatile Palestinian-Israeli conflict deteriorate further?
How should markets price the possible risk of a far-reaching
supply disruption?
We’re confident the market will sort it all out. That time-
tested dynamic of free markets is one of the many enduring
principles worth fighting for and defending. All the while,
your Company will stand prepared and financially fit for the
challenges and opportunities ahead.
Sincerely,
December 14, 2001
Hans Helmerich
President
3
Drilling H E L M E R I C H & PAY N E I N T E R N AT I O N A L D R I L L I N G C O.
SUMMARY Both oil and natural gas prices increased
substantially at the beginning of the year, resulting in higher
demand for land rigs in the United States. Industry census data
produced by Reed-Hycalog indicates that 93 percent of all U.S.
land rigs were active during 2001, a level of activity not
achieved since the early 1980s. The resulting impact of this
environment on the Company’s 2001 financial performance
was significant. Contract drilling revenues increased 39 percent,
and earnings before interest, taxes, depreciation, and
amortization (EBITDA) increased by over 50 percent, driven
primarily by increased activity in the U.S. land market.
FIVE-YEAR OPERATING SUMMARY
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2001
2000
1999
1998
1997
United States
(Dollar figures in thousands)
Revenues . . . . . . . . . . . . . . . . . . . . . .
EBITDA . . . . . . . . . . . . . . . . . . . . . . .
Operating Profit . . . . . . . . . . . . . . . . .
$332,399
$133,968
$107,691
$214,531
$071,163
$035,808
$213,647
$061,498
$030,154
$177,059
$060,053
$035,817
$140,294
$044,066
$024,437
Activity Days . . . . . . . . . . . . . . . . . . .
Rig Utilization . . . . . . . . . . . . . . . . . . .
18,656
97%
15,083
87%
12,509
75%
14,237
95%
12,872
88%
International
Revenues . . . . . . . . . . . . . . . . . . . . . .
EBITDA . . . . . . . . . . . . . . . . . . . . . . .
Operating Profit . . . . . . . . . . . . . . . . .
$154,890
$ 47,313
$ 28,475
$136,549
$047,853
$009,753
$182,987
$066,075
$029,845
$253,072
$082,650
$050,834
$176,651
$069,621
$043,118
Activity Days . . . . . . . . . . . . . . . . . . .
Rig Utilization . . . . . . . . . . . . . . . . . . .
7,283
56%
7,067
47%
8,442
53%
12,832
88%
12,253
91%
At the close of fiscal 2001, Helmerich & Payne International Drilling
Co. owned ten offshore platform rigs located in the Gulf of Mexico,
and 81 land rigs located in the United States (49), Venezuela (14),
Ecuador (7), Bolivia (6), Colombia (3), and Argentina (2). The
Company also had five international land rigs undergoing major
upgrades in the U.S., as well as five land rigs and two offshore
platform rigs at various stages of new construction at year-end.
4
Additionally, the Company operates four management contracts
on customer-owned platform rigs, three offshore California and
one offshore Equatorial Guinea, West Africa.
UNITED STATES OPERATIONS Rig utilization averaged
97 and 98 percent, respectively, for land and offshore platform rigs
during the year. The Company worked an average of 41 land rigs
and ten offshore platform rigs for the whole year, up from 32 land
and nine offshore platform rigs in 2000. A total of 11 rigs were
added to the land fleet in 2001, seven new FlexRigsTM, one
reconditioned medium depth rig, and three deep rigs that
were transferred from international operations.
The Company plans to complete the construction of 20 FlexRigs
during 2002, which will be available for work in the U.S. or
international markets. The highly mobile FlexRig, named for its
flexible drilling range of 8,000 to 18,000 feet, offers significant
drilling efficiencies through improved technology, including disc-
brakes, block control system, and the Company’s patented round
mud tank system. The FlexRig design has reduced the average
moving time by more than one-half of that for a conventional 1500
horsepower rig. The FlexRig design includes many health, safety,
and environmental (HSE) improvements and features reducing HSE
hazards. These include noise abatement, enhanced anti-fall protection,
and an integrated fluid containment system around the rig floor.
During 2001, the Company received commitments to build and
operate two new self-moving platform rigs in the Gulf of Mexico,
one each from Shell Exploration & Production Co. and BP.
These rigs are scheduled to commence operations in the
third quarter of 2002.
(cid:2) FlexRig is a trademark of Helmerich & Payne International Drilling Co.
5
INTERNATIONAL OPERATIONS Rig utilization averaged
56 percent in 2001, compared with 47 percent in 2000,
primarily because the Company moved eight rigs to the
U.S. for drilling opportunities or refurbishment during 2001.
Revenues increased 13 percent over last year, but EBITDA
decreased slightly as improvements in Venezuela, Equatorial
Guinea, Ecuador, and Argentina were offset by declines in
Colombia and Bolivia. Increased operating profit was primarily
the result of reduced depreciation expense caused by rig
transfers from international to domestic operations, as well
as a change in the estimated useful life of drilling equipment,
increasing it from ten to 15 years.
OUTLOOK The Company has lowered its expectations for
drilling activity in the coming year because of the precipitous
drop in both oil and natural gas prices caused by reduced
economic activity and mild weather in the U.S. Because the
present downturn does not appear to be due to excessive
supplies, the Company anticipates that it will be short-lived,
improving as energy demand rises in response to U.S. and
world economic recovery. This is the second volatile drilling
cycle in four years and, with each downturn, the industry loses
experienced employees and momentum on capital projects,
many of which require long lead times to bring to fruition.
The inevitable upturn in the cycle is likely to become even
more pronounced, stretching the already thin human,
technological, and financial resources of the industry. The
Company has focused its investment efforts on delivering the
latest in equipment and technology to the field and in training
our people to operate safely and effectively. Our primary goal
remains to deliver high quality equipment and services that will
add measurable value to a customer’s drilling operation.
6
Exploration & Production H E L M E R I C H & PAY N E , I N C .
SUMMARY Helmerich & Payne, Inc. explores for and
produces oil and natural gas primarily in Kansas, Louisiana,
Oklahoma, and Texas. The Company also provides natural
gas marketing services through its wholly owned subsidiary,
Helmerich & Payne Energy Services, Inc. A substantial
increase in the price of natural gas produced record financial
results for the Exploration and Production segment in 2001.
Revenues and operating profit grew 38 percent and 44
percent, respectively, over 2000 levels. Helmerich & Payne
Energy Services, Inc.’s revenues increased 24 percent in
2001, although operating profit remained flat for the year.
Oil production declined seven percent to average 2,242
barrels per day in 2001, while prices remained flat at $27.88
per barrel compared with $27.95 per barrel in 2000. Natural
gas production also declined to 116,128 thousand cubic feet
(Mcf) per day, compared with 128,204 Mcf per day in 2000.
Natural gas prices increased 63 percent to average $4.55 per
Mcf in 2001, compared with $2.79 per Mcf in 2000.
FIVE-YEAR OPERATING SUMMARY
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
200100
200000
199900
199800
199700
Revenues . . . . . . . . . . . . . . . . . . . . $ 217,194 $00,157,583 $000,95,953 $000,98,696 $00,111,512
Operating Profit . . . . . . . . . . . . . . . . $ 95,579 $000,66,604 $000,11,245 $000,28,088 $000,55,191
(Revenues and operating profit in thousands)
Average Oil Price per barrel . . . . . . . . $ 27.88 $0000,27.95 $0000,14.60 $0000,14.74 $0000,20.77
Oil Production (barrels) . . . . . . . . . . .
985,633
Proved Oil Reserves (barrels) . . . . . .
5,805,386
649,370
4,833,898
701,180
4,761,313
818,356
5,931,595
880,304
6,305,137
Average Natural Gas Prices per Mcf . . $ 4.55 $00000,2.79 $00000,1.83 $00000,2.04 $00000,2.24
Natural Gas Production (Mcf) . . . . . . . 42,386,796
40,463,374
Proved Natural Gas Reserves (Bcf) . . .
263.2
216.3
44,240,332
239.6
42,862,300
251.6
46,922,752
262.5
Gross Wells Completed . . . . . . . . . .
Net Wells Completed . . . . . . . . . . . .
Net Dry Holes . . . . . . . . . . . . . . . . .
123.0
69.5
17.0
81.0
42.7
9.1
49.0
23.9
7.1
62.0
35.7
4.2
100.0
49.3
9.6
7
EXPLORATION RESULTS Even though the Company had
a record financial performance, it was a disappointing year for
the exploration effort. Proved reserves declined from 300 billion
cubic feet equivalent (Bcfe) to 252 Bcfe during 2001. Almost
half of this decline was the result of the lower natural gas price
used in the reserve calculation, which was $1.90 per Mcf
in 2001, compared with $5.13 per Mcf in 2000.
The Company participated in 123 (69.5 net) wells in 2001,
29 (17 net) of which were dry holes. Given the high natural gas
prices, additional emphasis was placed on developing proved
undeveloped reserves during the year. Forty-seven gross wells
were drilled for this purpose in 2001. The remaining wells
included 40 (19 net) wildcat wells, five of which exposed the
Company to over 250 Bcfe in net potential reserve additions.
OUTLOOK Given that oil and gas prices have declined
substantially, the Company plans to be highly selective with
regard to drilling prospects in 2002, and will reduce capital
expenditures by as much as half of what they were in 2001.
With the assistance of the investment bank of Petrie
Parkman & Co., the Company is continuing to explore
strategic alternatives for the Oil and Gas Division. These
alternatives include combining the Company’s oil and gas
operations with another of similar size to form a separate,
stand-alone exploration and production company.
The Company engaged in discussions with a number of
companies during the past year and plans to continue these
efforts into 2002.
8
Revenues and Operating Profit by Business Segments
HELMERICH & PAYNE, INC.
Years Ended September 30,
2001
2000
1999
(in thousands)
SALES AND OTHER REVENUES:
Contract Drilling - Domestic ..............................................
Contract Drilling - International .........................................
Total Contract Drilling...................................................
$332,399
154,890
487,289
$214,531
136,549
351,080
$213,647
182,987
396,634
Exploration and Production...............................................
Natural Gas Marketing ......................................................
Total Oil and Gas Operations.......................................
Real Estate ......................................................................
Other .................................................................................
217,194
100,111
317,305
11,018
11,242
157,583
80,907
238,490
8,999
32,526
95,953
55,259
151,212
8,671
7,802
Total Revenues ........................................................................
$826,854
$631,095
$564,319
OPERATING PROFIT:
Contract Drilling - Domestic ..............................................
Contract Drilling - International .........................................
Total Contract Drilling...................................................
$107,691
28,475
136,166
$ 35,808
9,753
45,561
$ 30,154
29,845
59,999
Exploration and Production...............................................
Natural Gas Marketing ......................................................
Total Oil and Gas Operations.....................................
Real Estate .......................................................................
Total Operating Profit ...................................................
OTHER:
Income from investments..................................................
General and administrative expense.................................
Interest expense ...............................................................
Corporate depreciation .....................................................
Other corporate expense ..................................................
Total Other ...................................................................
95,579
5,254
100,833
6,315
243,314
10,592
(15,415)
32
(2,043)
(1,378)
(8,212)
66,604
5,271
71,875
5,346
122,782
31,973
(11,578)
(3,076)
(2,152)
(1,186)
13,981
11,245
4,418
15,663
5,338
81,000
7,757
(14,198)
(6,481)
(1,565)
(1,575)
(16,062)
INCOME BEFORE INCOME TAXES AND
EQUITY IN INCOME OF AFFILIATES ..........................
$235,102
$136,763
$ 64,938
Note: See Note 14 (pages 30, 31 and 32) for complete segment disclosure.
9
Management’s Discussion & Analysis of
Results of Operations and Financial Condition
HELMERICH & PAYNE, INC.
RISK FACTORS AND FORWARD-LOOKING STATEMENTS
The following discussion should be read in conjunction with the
consolidated financial statements and related notes included elsewhere
herein. The Company's future operating results may be affected by various
trends and factors, which are beyond the Company's control. These include,
among other factors, fluctuations in oil and natural gas prices, expiration or
termination of drilling contracts, currency exchange gains and losses, changes
in general economic conditions, rapid or unexpected changes in technologies,
risks of foreign operations, uninsured risks, and uncertain business conditions
that affect the Company's businesses. Accordingly, past results and trends
should not be used by investors to anticipate future results or trends.
With the exception of historical information, the matters discussed in
Management’s Discussion & Analysis of Results of Operations and Financial
Condition include forward-looking statements. These forward-looking
statements are based on various assumptions. The Company cautions that,
while it believes such assumptions to be reasonable and makes them in good
faith, assumed facts almost always vary from actual results. The differences
between assumed facts and actual results can be material. The Company is
including this cautionary statement to take advantage of the "safe harbor"
provisions of the Private Securities Litigation Reform Act of 1995 for any
forward-looking statements made by, or on behalf of, the Company.
The factors identified in this cautionary statement are important factors
(but not necessarily all important factors) that could cause actual results
to differ materially from those expressed in any forward-looking statement
made by, or on behalf of, the Company.
RESULTS OF OPERATIONS
All per share amounts included in the Results of Operations discussion are
stated on a diluted basis. Helmerich & Payne, Inc.'s net income for 2001 was
$144,254,000 ($2.84 per share), compared with net income of $82,300,000
($1.64 per share) in 2000, and $42,788,000 ($0.86 per share) in 1999.
Included in the Company's net income, but not related to its operations,
were after-tax gains from the sale of investment securities of $691,000
($0.01 per share) in 2001, $8,152,000 ($0.16 per share) in 2000, and
$1,562,000 ($0.03 per share) in 1999. In addition to income from security
sales, the Company also recorded net income during 2000 of $6,637,000
($0.13 per share) from gains relating to non-monetary dividends received.
Also included in net income is the Company’s portion of income from its
10
equity affiliates, which totaled $0.04 per share in 2001, $0.06 in 2000, and
$0.07 in 1999. The Company’s equity affiliates are Atwood Oceanics, Inc.
and a 50-50 joint venture with Atwood called Atwood Oceanics West Tuna
Pty. Ltd., which owns an offshore platform rig.
Consolidated revenues were $826,854,000 in 2001, $631,095,000 in 2000,
and $564,319,000 in 1999. The 31 percent increase from 2000 to 2001 was
due to significant increases in revenues from all of the operating divisions.
Revenues from investments decreased by $21,381,000. Contract Drilling
Division revenues increased by 39 percent due to the strengthening of the
U.S. land rig market. This resulted in higher utilization of the Company’s
rigs and higher dayrates. Oil and Gas Division revenues rose 33 percent
over 2000 due primarily to higher oil and natural gas prices. The 12 percent
increase in consolidated revenues from 1999 to 2000 was primarily due to
higher oil and natural gas prices resulting in an increase of $87,278,000 in
Oil and Gas Division revenues and increased investment revenues of
$24,216,000. Partially offsetting these increases was a reduction of
international contract drilling revenues of $46,438,000.
Revenues from investments were $10,592,000 in 2001, $31,973,000 in
2000, and $7,757,000 in 1999. Included in revenues were pre-tax gains
from the sale of investment securities of $1,189,000 in 2001, $13,295,000
in 2000, and $2,547,000 in 1999. Interest income from short-term
investments increased in 2001 and 2000 because the Company’s cash
and cash equivalent balances increased in each of these years. Dividend
income decreased in 2001, primarily because in 2000, the Company
recognized $10,706,000 of non-monetary dividends when three Company
investees spun-off subsidiaries to their shareholders.
Costs and expenses in 2001 were $591,752,000, 72 percent of revenues,
compared with 78 percent in 2000, and 88 percent in 1999. Operating
costs, as a percentage of operating revenues, were 51 percent in 2001,
53 percent in 2000, and 60 percent in 1999. Operating costs, as a
percentage of operating revenues, declined each of the last two years,
primarily due to proportionately higher revenues.
Effective October 1, 2000, the Company changed the estimated useful life
of its drilling equipment from ten years to 15 years, resulting in lower annual
depreciation expense of approximately $30 million in 2001. Excluding write-
downs of producing properties, depreciation expense was $78,400,000 in 2001,
$106,815,000 in 2000, and $99,108,000 in 1999. Producing property
11
write-downs totaled $8,909,000 in 2001, $4,036,000 in 2000, and
$10,059,000 in 1999.
General and administrative expenses increased by 33 percent from 2000 to
2001, to a total of $15,415,000, compared with $11,578,000 in 2000, and
$14,198,000 in 1999. Expenses rose this past year due to costs associated
with legal, accounting, and investment banking fees related to the potential
spin-off of the Oil and Gas Division, settlements of lawsuits, higher pension
expense accrual, and higher labor and bonus charges, compared with 2000.
General and administrative expenses decreased in 2000, compared to 1999,
due to the inclusion in 1999 of reduced allocations of charges to operations
and unusually high expenses relating to corporate aircraft maintenance.
Income taxes, as a percentage of pre-tax income, were 40 percent in 2001,
42 percent in 2000, and 40 percent in 1999.
Interest expense for the Company was negative $32,000 in 2001,
$3,076,000 in 2000, and $6,481,000 in 1999. Most of the expense
reduction from 2000 to 2001 resulted from a reversal of interest expense
previously accrued relating to an ad valorem tax dispute that was settled
for less interest costs than accrued. The specific case was settled during
2001, resulting in a reversal of interest expense of $2,280,000 that had
been accrued in 1999. Additionally, the Company reduced its overall debt
position during the last half of 1999 and early 2000, resulting in less debt
related interest expense booked in the last three years.
CONTRACT DRILLING DIVISION revenues, which include both domestic
and international segment revenues, increased 39 percent to $487,289,000
during 2001, from $351,080,000 in 2000. Revenues for 2000 were 11
percent lower than in 1999. Division operating profit of $136,166,000 was
almost triple that of the $45,461,000 recorded in 2000. Operating profit for
2000 was 24 percent lower than in 1999.
Domestic segment revenues were $332,399,000 in 2001, $214,531,000 in
2000, and $213,647,000 in 1999. Domestic segment operating profit was
$107,691,000 in 2001, $35,808,000 in 2000, and $30,154,000 in 1999.
Rig utilization for the U.S. land fleet was 97 percent in 2001, 85 percent
in 2000, and 69 percent in 1999. Domestic platform rig utilization was
98 percent in 2001, 94 percent in 2000, and 95 percent in 1999.
Both U.S. land rig and U.S. platform rig revenues increased in 2001 over
2000. Dayrates for U.S. land rigs and total operating days for the U.S. land
rig segment increased dramatically during 2001. Operating profit for the
12
domestic operation improved dramatically from 2000 to 2001, mostly on the
strength of average land rig dayrates, which improved more than 50 percent,
and the resulting improvement in profit margins. The previously discussed
change in the estimated useful life of drilling equipment increased domestic
operating profit by approximately $15 million in 2001. U.S. platform rig
dayrates did not improve, but total operating days helped boost revenues for
the year. Improvements in revenues and operating profit from 1999 to 2000
were primarily the result of average U.S. land rig dayrates and profit margins
moving up, while the platform business improved only slightly. During 1999,
there were approximately $40 million of revenues recorded as a result of a
rig construction project that was completed in early 2000.
International segment revenues increased by 13 percent from 2000 to 2001,
after falling by 25 percent from 1999 to 2000. International operating profit
rose to $28,475,000 in 2001, from $9,753,000 in 2000. Operating profit
for 1999 was $29,845,000. International rig utilization averaged 56 percent
during 2001, 47 percent in 2000, and 53 percent in 1999. International
operating profit improved during 2001, mainly due to lower depreciation
expenses resulting from a change in the estimated useful life of the
Company’s drilling equipment, as previously discussed. The impact of the
change added approximately $15 million to international operating profit in
2001. Revenues in Venezuela increased 24 percent during 2001, and the
Company expects to see activity improve slightly in 2002. The Company’s
labor contract in Equatorial Guinea added $6,054,000 to international
revenues in 2001. The decline in operating profit from 1999 to 2000 was
primarily due to reduced activity in Colombia where the Company had
previously employed ten rigs. Activitiy in Colombia continued to decline in
2000 and 2001, and currently, the Company has one rig working out of the
three remaining in that country. Conversely, Equador’s rig count has grown
from three in 1999 to seven in 2001, and an eighth, newly refurbished rig
will be shipped during the second quarter of 2002, to begin work under
a one-year contract.
The Company has international operations in several South American
countries. With the exception of Venezuela, the Company believes that
its exposure to currency valuation losses is minimal due to the fact that
virtually all billings and payments are in U.S. dollars. In Venezuela,
approximately 50 percent of the Company’s billings are in U.S. dollars
and 50 percent are in bolivars, the local currency. As a result, the
Company is exposed to risks of currency devaluation in Venezuela
because of the bolivar denominated receivables. During 2001, the
Company experienced a loss of $796,000 due to devaluation of the bolivar,
13
compared with a $687,000 loss in 2000, and a $712,000 loss in 1999.
The Company anticipates additional devaluation losses in Venezuela
during 2002, but is unable to predict the extent of either the devaluation
or its financial impact. Should Venezuela experience a 25 to 50 percent
devaluation, Company losses could range from approximately $1,600,000
to $2,600,000.
OIL AND GAS DIVISION operating results include those from its Exploration
and Production segment, as depicted in the following table. The Natural Gas
Marketing segment will be discussed separately.
Exploration & Production
Revenues (in 000’s) . . . . . . . . . . . . . . . . . . . . . .
Operating Profit (in 000’s) . . . . . . . . . . . . . . . . . .
Natural Gas Production (Mmcf per day) . . . . . . .
Average Natural Gas Price (per Mcf) . . . . . . . . .
Crude Oil Production (barrels per day) . . . . . . . .
Average Crude Oil Price (per barrel) . . . . . . . . . .
2001
$217,194
$ 95,579
116.1
$ 4.55
2,242
$ 27.88
2000
$157,583
$066,604
128.2
$0002.79
2,405
$0027.95
1999
$ 95,953
$ 11,245
121.2
$ 001.83
1,779
$ 014.60
Exploration and Production segment revenues and operating profit increased
significantly this year as average prices received for the Company’s natural
gas production rose dramatically. Average prices received for natural gas
increased by 63 percent, while average crude oil prices remained flat,
compared to 2000. Natural gas and crude oil production for the Company
decreased by nine percent and seven percent, respectively. Increased
exploration drilling resulted in dry hole and abandonment charges rising
to $33.5 million in 2001, compared with $22.6 million in 2000, and $11.4
million in 1999. Revenues and operating profit for 2000 were up
substantially from 1999 due to significant increases in both commodity
price levels and Company production volumes for natural gas and crude oil.
Average prices for natural gas increased by 52 percent and average crude oil
prices increased by 91 percent from 1999 to 2000. In 2000, natural gas and
crude oil production increased by six percent and 35 percent, respectively,
over 1999 levels. Producing property impairment write-downs totaled
$8,909,000 in 2001, $4,036,000 in 2000, and $10,059,000 in 1999.
During 2002, the Company’s Oil and Gas Division intends to decrease its
capital spending over the previous year. However, dry hole, abandonment,
and geophysical expenses are difficult to predict and will continue to impact
operating profit for the coming year. Additionally, with a reduced capital
spending budget, it is expected that the Company’s production volumes for
natural gas and crude oil will decline during the year.
14
The Company has retained the investment banking firm of Petrie Parkman & Co.
to analyze, develop, and facilitate possible strategic options for the Oil and Gas
Division. It is uncertain whether such a transaction will occur or, if so, when.
The Company's Natural Gas Marketing segment, Helmerich & Payne Energy
Services, Inc., (HPESI) derives most of its revenues from selling natural gas
produced by other unaffiliated companies. Total Natural Gas Marketing
segment revenues were $100,111,000 in 2001, $80,907,000 in 2000, and
$55,259,000 in 1999. Operating profit was $5,254,000 in 2001, $5,271,000
in 2000, and $4,418,000 in 1999. The operating profit margin declined to
5.2 percent in 2001, from 6.5 percent in 2000, and 8 percent in 1999. A
rapid decline in natural gas prices over the last three-quarters of the year as
well as an increasingly competitive gas marketing environment was primarily
responsible for lower margins in 2001. Most of the natural gas owned and
produced by the Exploration and Production segment is sold through HPESI
to third parties at variable prices based on industry pricing publications or
exchange quotations. Revenues for the Company's own natural gas
production are reported by the Exploration and Production segment with the
Natural Gas Marketing segment retaining a market-based fee from the sale of
such production. HPESI sells most of its natural gas with monthly or daily
contracts tied to industry market indices, such as Inside FERC Gas Market
Report. The Company, through HPESI, has natural gas delivery commitments
for periods of less than a year for approximately 59 percent of its total
natural gas production. At times, the Exploration and Production segment
may direct HPESI to enter into fixed price natural gas sales contracts on its
behalf for a small portion (normally less than 20 percent) of its natural gas
sales for periods of less than 12 months to guarantee a certain price. In 2001,
HPESI had approximately three percent of its natural gas sales portfolio
dedicated to such fixed price sales contracts compared to 13.6 percent in
2000. As of September 30, 2001, HPESI had no long-term fixed contracts.
REAL ESTATE DIVISION revenues totaled $11,018,000 for 2001,
$8,999,000 for 2000, and $8,671,000 for 1999. Operating profit was
$6,315,000 in 2001, $5,346,000 in 2000, and $5,338,000 in 1999. The
increase in revenues and operating profit in 2001 was due to the sale of a
small parcel of raw land. Occupancy rates, revenues, and operating profit
remained solid in 2001 due to the continued strength of the Tulsa economy.
No material changes are anticipated in the Real Estate Division in 2002.
The Company adopted Statement of Financial Accounting Standards (SFAS)
No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
effective October 1, 2000, which required that all derivatives be recognized
15
as assets or liabilities in the balance sheet and that these instruments be
measured at fair value. The effect of SFAS No. 133 on the Company’s
results of operations and financial position was not material for fiscal year
2001, and is not expected to be material in 2002.
In 2001, the Financial Standards Board (FASB) issued SFAS No. 143,
“Accounting for Asset Retirement Obligations,” and SFAS No. 144,
“Accounting for the Impairment or Disposal of Long-lived Assets.” The
Company does not anticipate that these pronouncements will have an
immediate material impact on its results of operations or financial position.
More information on these pronouncements can be found in Note 12 on
page 30 of this Annual Report.
LIQUIDITY AND CAPITAL RESOURCES
The Company’s capital spending was $274,670,000 in 2001,
$131,932,000 in 2000, and $122,951,000 in 1999. Net cash provided
from operating activities for those same time periods were $278,856,000
in 2001, $201,836,000 in 2000, and $158,694,000 in 1999. In addition to
the net cash provided by operating activities, the Company also generated
net proceeds from the sale of portfolio securities of $24,439,000 in 2001,
$12,569,000 in 2000, and $2,803,000 in 1999.
During 2000, the Company announced a program (FlexRig II program)
under which it would construct 12 new FlexRigs at an approximate cost
of between $7.5 and $8.25 million each. During 2001, the Company
completed construction on seven of those 12 rigs. Additionally, the
Company announced in 2001 that it would embark on another construction
project (FlexRig III program) to build an additional 25 FlexRigs at an
approximate cost of $10.2 million each. It is expected that the Company
will complete construction on 15 of those 25 rigs under the FlexRig III
program during 2002. During 2001, the Company also announced that it
had reached agreement with two operators for offshore platform rig
operations in the Gulf of Mexico. This will result in the Company spending
approximately $50 million to construct two offshore platform rigs that
should commence operations in the Company’s third quarter of 2002.
These projects, along with ongoing remodification and refurbishment of
existing equipment, plus additional drill pipe and other expenditures, should
bring Contract Drilling capital expenditures to approximately $340 million
in 2002. Additionally, the Oil and Gas Division has estimated its capital
spending needs for the coming year to be approximately $50 million. These
capital expenditures, along with miscellaneous real estate and corporate
16
capital expenditures, should bring total Company capital spending for 2002
close to $400 million. Funding for this significant increase in Company
capital expenditures will come from existing cash balances, internally generated
cash flow, additional bank borrowings, and proceeds from securities sales.
As described in Note 2 of Notes to Consolidated Financial Statements, in
October 1998, the Company obtained $50 million in long-term debt proceeds.
The $50 million of long-term debt matures in October 2003. The interest rate
on this debt fluctuates based on the 30-day London Interbank Offered Rate
(LIBOR). However, simultaneous to receiving the $50 million in long-term
debt proceeds, the Company entered into a $50 million interest rate swap
agreement with a major national bank. The swap effectively fixes the interest
rate on this facility at 5.38 percent for the entire five-year term of the note.
The Company's interest rate risk exposure is limited to its potential short-term
borrowings, and results predominately from fluctuations in short-term interest
rates as measured by 30-day LIBOR. This exposure should increase during
2002, as the Company secures additional debt financing.
The strength of the Company’s balance sheet is substantial, with current
ratios for 2001 and 2000 at 2.7 and 3.4, respectively, and with total bank
borrowings less than four percent of total assets at September 30, 2001.
Additionally, the Company manages a large portfolio of marketable securities
that, at the close of 2001, had a market value of $226,134,000, with a cost
basis of $119,165,000. The portfolio, heavily weighted in energy stocks,
is subject to fluctuation in the market and may vary considerably over time.
Excluding the Company’s equity-method investments, the portfolio is
marked to market on the Company’s balance sheet for each reporting period.
During 2001, the Company paid a dividend of $0.30 per share, or a total of
$15,047,000, representing the 30th consecutive year of dividend increases.
Stock Portfolio Held by the Company
September 30, 2001
Number of
Shares
Cost Basis
(in thousands, except share amounts)
Market Value
Atwood Oceanics, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . .
Schlumberger, Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transocean Sedco Forex, Inc.. . . . . . . . . . . . . . . . . . . . .
SUNOCO, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Phillips Petroleum Company . . . . . . . . . . . . . . . . . . . . . .
BANK ONE CORPORATION . . . . . . . . . . . . . . . . . . . . .
Kerr-McGee Corporation . . . . . . . . . . . . . . . . . . . . . . . .
Occidental Petroleum Corporation . . . . . . . . . . . . . . . . .
ONEOK, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,000,000
1,480,000
286,528
312,546
240,000
175,000
150,000
150,000
450,000
$ 52,152
23,511
9,509
2,873
5,976
1,969
3,983
3,566
2,751
12,875
$119,165
$ 78,000
67,636
7,564
11,127
12,946
5,507
7,787
3,651
7,452
24,464
$226,134
17
Consolidated Balance Sheets
HELMERICH & PAYNE, INC.
Assets
CURRENT ASSETS:
September 30,
2001
2000
(in thousands)
Cash and cash equivalents ..............................................................
Accounts receivable, less reserve of $1,661 in 2001 and $2,003 in 2000 ...
Inventories ...................................................................................
Prepaid expenses and other.............................................................
Total current assets ..................................................................
$ 122,962
147,235
28,934
32,281
$ 108,087
106,630
25,598
24,829
331,412
265,144
INVESTMENTS .................................................................................
200,286
304,326
PROPERTY, PLANT AND EQUIPMENT, at cost:
Contract drilling equipment ..............................................................
Oil and gas properties ....................................................................
Real estate properties ....................................................................
Other ..........................................................................................
Less__Accumulated depreciation, depletion and amortization .................
1,028,015
521,673
50,579
86,300
1,686,567
868,163
891,749
457,724
50,649
80,268
1,480,390
806,785
Net property, plant and equipment...............................................
818,404
673,605
OTHER ASSETS ...............................................................................
14,405
16,417
TOTAL ASSETS ................................................................................
$ 1,364,507
$ 1,259,492
The accompanying notes are an integral part of these statements.
18
Liabilities and Shareholders’ Equity
September 30,
2001
2000
(in thousands,
except share data)
CURRENT LIABILITIES:
Accounts payable .............................................................................
Accrued liabilities .............................................................................
Total current liabilities ......................................................
$ 67,595
53,626
121,221
$ 32,279
46,615
78,894
NONCURRENT LIABILITIES:
Long-term notes payable ...................................................................
Deferred income taxes ......................................................................
Other .............................................................................................
Total noncurrent liabilities ..........................................................
50,000
144,439
22,370
216,809
50,000
156,650
18,245
224,895
SHAREHOLDERS’ EQUITY:
Common stock, $.10 par value, 80,000,000 shares authorized,
53,528,952 shares issued ...............................................................
5,353
5,353
Preferred stock, no par value, 1,000,000 shares authorized,
no shares issued ..........................................................................
Additional paid-in capital ....................................................................
Retained earnings ............................................................................
Unearned compensation....................................................................
Accumulated other comprehensive income ............................................
Less treasury stock, 3,676,155 shares in 2001 and 3,548,480 shares in 2000, at cost ....
Total shareholders’ equity...........................................................
80,324
943,105
(1,812)
49,309
1,076,279
49,802
1,026,477
66,090
813,885
(3,277)
106,064
988,115
32,412
955,703
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY .................................
$1,364,507
$1,259,492
The accompanying notes are an integral part of these statements.
19
Consolidated Statements of Income
HELMERICH & PAYNE, INC.
Years Ended September 30,
2001
2000
1999
(in thousands,
except per share amounts)
REVENUES:
Sales and other operating revenues ....................................
Income from investments..................................................
$816,262
10,592
$599,122
31,973
$556,562
7,757
...............................................................................................
826,854
631,095
564,319
COSTS AND EXPENSES:
Operating costs ..............................................................
Depreciation, depletion and amortization .............................
Dry holes and abandonments ............................................
Taxes, other than income taxes ..........................................
General and administrative ...............................................
Interest .........................................................................
...............................................................................................
413,378
87,309
34,042
41,640
15,415
(32)
591,752
316,933
110,851
22,692
29,202
11,578
3,076
494,332
332,330
109,167
11,727
25,478
14,198
6,481
499,381
INCOME BEFORE INCOME TAXES AND
EQUITY IN INCOME OF AFFILIATES .................................
235,102
136,763
64,938
INCOME TAX EXPENSE ......................................................
93,027
57,684
25,706
EQUITY IN INCOME OF AFFILIATES
net of income taxes .........................................................
2,179
3,221
3,556
NET INCOME.....................................................................
$144,254
$182,300
$ 42,788
EARNINGS PER COMMON SHARE:
BASIC ..........................................................................
DILUTED ......................................................................
$0562.88
$0562.84
$
$
1.66
1.64
$ 0.87
$ 0.86
AVERAGE COMMON SHARES OUTSTANDING:
BASIC ..........................................................................
DILUTED ......................................................................
50,096
50,772
49,534
50,035
49,243
49,817
The accompanying notes are an integral part of these statements.
20
Consolidated Statements of Shareholders’ Equity
HELMERICH & PAYNE, INC.
Common Stock
Shares
Amount
Additional
Paid-in
Capital
Unearned
Compensation
Retained
Earnings
Treasury Stock
Shares
Amount
(in thousands, except per share amounts)
Accumulated
Other
Comprehensive
Income (Loss)
Total
Balance, Sept. 30, 1998 ............ 53,529
$5,353 $59,004
$(5,605)
$716,875 4,146 $(37,168)
$54,689 $ 793,148
Comprehensive income:
Net income...........................
Other comprehensive income
Unrealized gains on available-
for-sale securities, net..........
Comprehensive income ............
Cash dividends ($.28 per share)..
Exercise of stock options ...........
Tax benefit of stock-based awards
Stock issued under Restricted
Stock Award Plan...................
Amortization of deferred
compensation .......................
Balance, Sept. 30, 1999 ............ 53,529
Comprehensive income:
Net income...........................
Other comprehensive income,
Unrealized gains on available-
for-sale securities,net ..........
Comprehensive income ............
Cash dividends ($.285 per share)
Exercise of stock options ...........
Purchase of stock for treasury......
Tax benefit of stock-based awards
Stock issued under Restricted
Stock Award Plan...................
Amortization of deferred
compensation .......................
Balance, Sept. 30, 2000 ............ 53,529
Comprehensive income:
Net income...........................
Other comprehensive income,
Unrealized gains on available-
for-sale securities,net .............
Derivatives instruments losses, net
Total other comprehensive income
Comprehensive income ............
Cash dividends ($.30 per share)..
Exercise of stock options ...........
Purchase of stock for treasury.....
Tax benefit of stock-based awards
Amortization of deferred
compensation ......................
42,788
20,493
2,201
69
(13,866)
(226)
1,710
137
(289)
(17)
152
5,353
61,411
1,407
(4,487)
159
745,956 3,903
(35,306)
75,182
82,300
30,882
4,491
31
(14,448)
(366)
21
3,253
(450)
157
(248)
(10)
91
5,353
66,090
1,458
(3,277)
77
813,885 3,548
(32,412)
106,064
144,254
(55,769)
(986)
7,965
6,269
(15,047)
(646)
774
5,808
(23,198)
42,788
20,493
63,281
(13,866)
3,911
69
1,566
848,109
82,300
30,882
113,182
(14,448)
7,744
(450)
31
1,535
955,703
144,254
(55,769)
(986)
(56,755)
87,499
(15,047)
13,773
(23,198)
6,269
1,465
$(1,812)
13
$943,105 3,676 $(49,802)
1,478
$49,309 $1,026,477
21
Balance, Sept. 30, 2001 ............ 53,529
$5,353 $80,324
The accompanying notes are an integral part of these statements.
Consolidated Statements of Cash Flows
HELMERICH & PAYNE, INC.
Years Ended September 30,
2001
2000
1999
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ........................................................................
Adjustments to reconcile net income to net
cash provided by operating activities:
$(144,254
$(182,300
$( 42,788
Depreciation, depletion and amortization...........................
Dry holes and abandonments .........................................
Equity in income of affiliates before income taxes................
Amortization of deferred compensation .............................
Gain on sale of securities and non-monetary investment income
Gain on sale of property, plant and equipment....................
Other - net ..................................................................
Change in assets and liabilities:
Accounts receivable ..................................................
Inventories ..............................................................
Prepaid expenses and other .......................................
Accounts payable .....................................................
Accrued liabilities .....................................................
Deferred income taxes ...............................................
Other noncurrent liabilities ..........................................
...........................................................................................
Net cash provided by operating activities ...................
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including dry hole costs ...........................
Acquisition of business, net of cash aquired ..............................
Proceeds from sale of property, plant and equipment ..................
Purchase of investments.......................................................
Proceeds from sale of securities .............................................
110,851
22,692
(5,196)
1,535
(24,000)
(2,479)
944
(7,032)
(411)
(7,780)
6,575
7,557
21,133
(4,853)
119,536
109,167
11,727
(5,735)
1,566
(2,547)
(6,900)
2,148
19,797
214
(5,079)
(16,147)
2,367
559
4,769
115,906
201,836
158,694
(131,932)
(122,951)
87,309
34,042
(4,383)
1,478
(1,189)
(4,895)
906
(39,747)
(2,062)
(4,874)
34,840
9,065
21,641
2,471
134,602
278,856
(274,670)
(2,279)
13,173
18,044
24,439
12,569
9,990
(537)
2,803
Net cash used in investing activities ..........................
(239,337)
(101,319)
(110,695)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable.................................................
Payments made on notes payable...........................................
Dividends paid ....................................................................
Purchases of stock for treasury ..............................................
Proceeds from exercise of stock options...................................
Net cash used in financing activities..........................
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS......................................................................
CASH AND CASH EQUIVALENTS, beginning of period .................
CASH AND CASH EQUIVALENTS, end of period .........................
(5,000)
(14,175)
(450)
5,437
(14,188)
102,000
(141,800)
(13,849)
2,932
(50,717)
(15,047)
(23,198)
13,601
(24,644)
14,875
108,087
$(122,962
86,329
21,758
$0108,087
(2,718)
24,476
$(021,758
The accompanying notes are an integral part of these statements.
22
Notes to Consolidated Financial Statements
HELMERICH & PAYNE, INC.
September 30, 2001,2000 and 1999
NOTE 1 SUMMARY OF ACCOUNTING POLICIES
CONSOLIDATION -
The consolidated financial statements include the accounts of
Helmerich & Payne, Inc. (the Company), and all of its wholly-
owned subsidiaries. Fiscal years of the Company's foreign con-
solidated operations end on August 31 to facilitate reporting of
consolidated results.
TRANSLATION OF FOREIGN CURRENCIES -
The Company has determined that the functional currency for its
foreign subsidiaries is the U.S. dollar. The foreign currency transac-
tion loss for 2001, 2000, and 1999 was $494,000, $664,000, and
$21,000, respectively.
USE OF ESTIMATES -
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make esti-
mates and assumptions that affect the amounts reported in the con-
solidated financial statements and accompanying notes. Actual
results could differ from those estimates.
PROPERTY, PLANT AND EQUIPMENT -
The Company follows the successful efforts method of accounting
for oil and gas properties. Under this method, the Company capital-
izes all costs to acquire mineral interests in oil and gas properties, to
drill and equip exploratory wells which find proved reserves and to
drill and equip development wells. Geological and geophysical
costs, delay rentals and costs to drill exploratory wells which do not
find proved reserves are expensed. Capitalized costs of producing
oil and gas properties are depreciated and depleted by the unit-of-
production method based on proved oil and gas reserves as deter-
mined by the Company and its independent engineers. Reserves
are recorded for capitalized costs of undeveloped leases based on
management's estimate of recoverability. Costs of surrendered
leases are charged to the reserve.
In accordance with Statement of Financial Accounting Standards
(SFAS) No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of," the Company
recognizes impairment losses for long-lived assets used in opera-
tions when indicators of impairment are present and the undiscounted
cash flows are not sufficient to recover the carrying amount of the
asset. The Company recognized impairment charges of approxi-
mately $8.9 million, $4.0 million and $10.1 million in 2001, 2000,
and 1999, respectively, for proved Exploration and Production prop-
erties which are included in depreciation, depletion, and amortiza-
tion expense. After-tax, the impairment charge reduced 2001,
2000, and 1999 net income by approximately $5.5 million, $2.5 mil-
lion, and $6.2 million, respectively. On a diluted basis the impair-
ment charges reduced earnings per share in 2001, 2000, and 1999
by $0.11, $0.05, and $0.13, respectively. The Company evaluates
impairment of exploration and production assets on a field by field
basis. Fair value on all long-lived assets is based on discounted
future cash flows or information provided by sales and purchases of
similar assets.
Substantially all property, plant and equipment other than oil and
gas properties is depreciated using the straight-line method based
on the following estimated useful lives:
Contract drilling equipment . . . . . . . . . . . . . . . . . . . . . . . . .4 -15
Real estate buildings and equipment . . . . . . . . . . . . . . . . .10- 50
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-33
YEARS
As a result of an economic evaluation of useful lives of its drilling
equipment, the Company extended the depreciable life of its rig equip-
ment from ten to 15 years. This change will provide a better matching
of revenues and depreciation expense over the useful life of the equip-
ment. This change, effective October 1, 2000, reduced depreciation
expense for 2001 by approximately $30 million.
CASH AND CASH EQUIVALENTS -
Cash and cash equivalents consist of cash in banks and investments
readily convertible into cash which mature within three months from
the date of purchase.
INVENTORIES -
Inventories, primarily materials and supplies, are valued at the lower
of cost (moving average or actual) or market.
SHIPPING COSTS -
The Company’s shipping and handling costs are included under
operating costs for all periods presented.
DRILLING REVENUES -
Contract drilling revenues are comprised primarily of daywork drilling
contracts for which the related revenues and expenses are recognized
as work progresses. Fiscal 2000 and 1999 contract drilling revenues
also include revenues of $4,109,000, and $40,790,000, respectively,
from a rig construction contract for which revenues were recognized
based on the percentage-of-completion method, measured by the per-
centage that incurred costs to date bear to total estimated costs. The
Company does not currently have any third party rig construction con-
tracts.
GAS IMBALANCES -
The Company recognizes revenues from gas wells on the sales
method, and a liability is recorded for permanent imbalances resulting
from gas wells in which the Company has sold more production than it
is entitled.
INVESTMENTS -
The cost of securities used in determining realized gains and losses is
based on the average cost basis of the security sold. Net income in
2001 includes a loss of approximately $1.4 million, $0.03 per share on
a diluted basis, resulting from the Company’s assessment that the
decline in market value of certain available-for-sale securities below
their financial cost basis was other than temporary. Net income in
2000 included approximately $6.6 million, $0.13 per share on a diluted
basis, on gains related to non-monetary transactions within the
Company’s available-for-sale security invested portfolio which were
accounted for at fair value.
Investments in companies owned from 20 to 50 percent are accounted
for using the equity method with the Company recognizing its propor-
tionate share of the income or loss of each investee. The Company
owned approximately 22% of Atwood Oceanics, Inc. (Atwood) at both
September 30, 2001 and 2000. The quoted market value of the
Company's investment was $78,000,000 and $125,063,000 at
September 30, 2001 and 2000, respectively. Retained earnings at
September 30, 2001 includes approximately $25,514,000 of undistrib-
uted earnings of Atwood.
23
Summarized financial information of Atwood is as follows:
Gross revenues ..............................................................
Costs and expenses ........................................................
Net income ....................................................................
Helmerich & Payne, Inc.’s equity in net income,
net of income taxes ....................................................
Current assets ................................................................
Noncurrent assets ...........................................................
Current liabilities .............................................................
Noncurrent liabilities ........................................................
Shareholders’ equity ........................................................
2001
$ 147,540
120,395
$ 27,145
$ 3,596
$ 45,891
304,857
19,144
85,948
245,656
2000
(in thousands)
$ 134,514
111,366
$ 23,148
$ 3,221
$ 63,951
248,334
17,484
77,332
217,469
1999
$ 150,009
122,289
$ 27,720
$ 3,556
$ 50,532
243,072
19,013
82,362
192,229
Helmerich & Payne, Inc.’s investment...................................
$ 52,153
$ 46,353
$ 41,157
INCOME TAXES -
Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax
basis of the Company’s assets and liabilities.
OTHER POST EMPLOYMENT BENEFITS -
The Company sponsors a health care plan that provides post retirement medical benefits to retired employees. Employees who retire after
November 1, 1992 and elect to participate in the plan pay the entire estimated cost of such benefits.
The Company has accrued a liability for estimated workers compensation claims incurred. The liability for other benefits to former or inactive
employees after employment but before retirement is not material.
EARNINGS PER SHARE -
Basic earnings per share is based on the weighted-average number of common shares outstanding during the period. Diluted earnings per
share includes the dilutive effect of stock options and restricted stock.
EMPLOYEE STOCK-BASED AWARDS -
Employee stock-based awards are accounted for under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" and related information. Fixed plan common stock options do not result in compensation expense, because the exercise price of
the stock equals the market price of the underlying stock on the date of grant.
TREASURY STOCK -
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock.
Gains and losses on the subsequent reissuance of shares are credited or charged to additional paid-in-capital using the average-cost method.
CAPITALIZATION OF INTEREST –
The Company capitalizes interest on major projects during construction. Interest is capitalized on borrowed funds, with the rate based on the
average interest rate on related debt. Capitalized interest for 2001, 2000, and 1999 was $1.3 million, $0.4 million, and $0.1 million, respectively.
INTEREST RATE RISK MANAGEMENT -
The Company uses derivatives as part of an overall operating strategy to moderate certain financial market risks and is exposed to interest rate
risk from long-term debt. To manage this risk, in October 1998, the Company entered into an interest rate swap to exchange floating rate for
fixed rate interest payments through October 2003, the remaining life of the debt. The difference to be paid or received is accrued and recog-
nized as an adjustment of interest expense. As of September 30, 2001, the Company’s interest rate swap had a notional principal amount of
$50 million.
The Company’s accounting policy for these instruments is based on its designation of such instruments as hedging transactions. An instrument
is designated as a hedge based in part on its effectiveness in risk reduction and one-to-one matching of derivative instruments to underlying
transactions. The Company records all derivatives on the balance sheet at fair value.
For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure of variability in expected future cash
flows that is attributable to a particular risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of
other comprehensive income in stockholders’ equity and reclassified into earnings in the same period or periods during which the hedged trans-
action affects earnings. The change in value of the derivative instrument in excess of the cumulative change in the present value of the future
cash flows of the risk being hedged, if any, is recognized in the current earnings during the period of change.
The Company’s interest rate swap has been designated as a cash flow hedge and is 100% effective in hedging the exposure of variability in the
future interest payments attributable to the debt because the terms of the interest swap correlate with the terms of the debt.
Gains and losses from termination of interest rate swap agreements are deferred and amortized as an adjustment to interest expense over the
original term of the terminated swap agreement.
NOTE 2 NOTES PAYABLE AND LONG-TERM DEBT
At September 30, 2001, the Company had committed bank lines totaling $85 million; $50 million expires October 2003 and $35 million expires
May 2002. Additionally, the Company had uncommitted credit facilities totaling $10 million. Collectively, the Company had $50 million in out-
standing borrowings and outstanding letters of credit totaling $10.6 million against these lines at September 30, 2001. As described above,
concurrent with a $50 million borrowing under the facility that expires October 2003, the Company entered into an interest rate swap with a
notional value of $50 million and an expiration date of October 2003. The swap effectively converts this $50 million facility from a floating rate
of LIBOR plus 50 basis points to a fixed effective rate of 5.38 percent. Excluding the impact of the interest rate swap, the average interest rate
for the borrowings at September 30, 2001, was approximately 5.66 percent on a 360 day basis.
Under the various credit agreements, the Company must meet certain requirements regarding levels of debt, net worth and earnings.
24
NOTE 3 INCOME TAXES
The components of the provision (benefit) for income taxes are as follows:
Years Ended September 30,
2001
CURRENT:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 57,607
8,870
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,680
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
73,157
DEFERRED:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TOTAL PROVISION:
14,020
4,701
1,149
19,870
$ 93,027
2000
(in thousands)
1999
$ 325,736
8,766
3,366
37,868
12,318
6,146
1,352
19,816
$ 57,684
$ 9,684
15,963
1,744
27,391
(842)
(771)
(72)
(1,685)
$ 25,706
The amounts of domestic and foreign income are as follows:
Years Ended September 30,
2001
2000
(in thousands)
1999
INCOME BEFORE INCOME TAXES AND
EQUITY IN INCOME OF AFFILIATES:
Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $208,288
26,814
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$129,373
7,390
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $235,102 $136,763
$ 41,693
23,245
$ 64,938
Effective income tax rates on income as compared to the U.S. Federal income tax rate are as follows:
2000
Years Ended September 30,
2001
U.S. Federal income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends received deduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effect of foreign taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-conventional fuel source credits utilized . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35%
--
2
--
3
40%
35%
--
5
--
2
42%
The components of the Company’s net deferred tax liabilities are as follows:
2001
September 30,
2000
(in thousands)
DEFERRED TAX LIABILITIES:
Property, plant and equipment
Available-for-sale securities
Pension provision
Equity investments
Other
Total deferred tax liabilities
DEFERRED TAX ASSETS:
Financial accruals
Other
Total deferred tax assets
$ 101,674
33,937
3,194
15,637
506
154,948
6,746
3,763
10,509
$ 75,653
72,583
4,075
12,734
1,217
166,262
9,612
—00
9,612
NET DEFERRED TAX LIABILITIES
$ 144,439
$156,650
1999
35%
(1)
5
(1)
2
40%
25
NOTE 4 SHAREHOLDERS’ EQUITY
In January 2000, the board of directors authorized the repurchase of up to 1,000,000 shares of the Company’s common stock in
the open market or private transactions. The repurchased shares will be held in treasury and used for general corporate purposes
including use in the Company’s benefit plans. During fiscal 2001, the Company purchased 773,800 shares at a cost of approxi-
mately $23,198,000 and in fiscal 2000 purchased 20,600 shares at a cost of approximately $450,000. The Company did not pur-
chase any shares is fiscal 1999. As of September 30, 2001, the Company is authorized to repurchase up to 205,600 additional
shares.
The Company has several plans providing for common-stock based awards to employees and to non-employee directors. The
plans permit the granting of various types of awards including stock options and restricted stock. Awards may be granted for no
consideration other than prior and future services. The purchase price per share for stock options may not be less than market
price of the underlying stock on the date of grant. Stock options expire ten years after grant.
The Company has reserved 3,135,509 shares of its treasury stock to satisfy the exercise of stock options issued under the 1990
and 1996 Stock Option Plans. Effective after December 6, 2000, additional options are no longer granted under these Plans.
Options granted under the 1996 Plan vest over a four-year period. In fiscal 2001, 843,800 options were granted under the 1996 Plan.
In March 2001, the Company adopted the 2000 Stock Incentive Plan (the "Stock Incentive Plan"). The Stock Incentive Plan was
effective December 6, 2000, and will terminate December 6, 2010. Under this plan, the Company is authorized to grant options
for up to 3,000,000 shares of the Company’s common stock at an exercise price not less than the fair market value of the com-
mon stock on the date of grant. Up to 450,000 shares of the total authorized may be granted to participants as restricted stock
awards. There was no activity under this plan during fiscal 2001.
In fiscal 2000 and 1999, 10,000 and 17,000 shares of restricted stock, respectively, were granted at a weighted-average price of
$24.75 and $17.00, respectively, which approximated fair market value at the date of grant. Unearned compensation of $248,000
and $289,000 for fiscal 2000 and 1999, respectively, is being amortized over a five-year period as compensation expense. There
were no restricted stock grants in fiscal 2001.
The following summary reflects the stock option activity and related information (shares in thousands):
2001
2000
1999
Weighted-Average
Weighted-Average
Weighted-Average
Options Exercise Price
Options Exercise Price
Options Exercise Price
Outstanding at October 1,
2,955
$22.94
2,574
$21.34
2,090
$22.09
Granted
Exercised
Forfeited/Expired
Outstanding on September 30,
Exercisable on September 30,
Shares available on September 30,
for options that may be granted
844
(644)
(19)
3,136
1,078
3,000
32.36
21.34
25.57
$25.78
$23.82
24.75
15.44
23.00
$22.94
$22.40
767
(364)
(22)
2,955
1,046
1,777
16.81
14.28
13.51
$21.34
$20.13
726
(238)
(4)
2,574
782
2,537
The following table summarizes information about stock options at September 30, 2001 (shares in thousands):
Outstanding Stock Options
Exercisable Stock Options
Range of
Exercise Prices
to
$16.50
$12.00
Weighted-Average
Remaining Contractural
Life
3.7 years
Weighted-Average
Exercise Price
$13.78
Options
374
$16.51
$26.51
$12.00
to
to
to
$26.50
$38.31
$38.31
1,511
1,251
3,136
7.3 years
8.2 years
7.2 years
$22.08
$33.84
$25.78
26
Options
284
511
283
1,078
Weighted-Average
Exercise Price
$13.77
$22.18
$36.85
$23.82
The following table reflects pro forma net income and earnings per share had the Company elected to adopt the fair value method
of SFAS No. 123, “Accounting for Stock-Based Compensation,” in measuring compensation cost beginning with 1997 employee
stock-based awards.
Years Ended September 30,
2001
2000
1999
(in thousands, except per share data)
Net Income:
As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$144,254
$139,211
Basic earnings per share:
As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$0 02.88
$ 002.78
Diluted earnings per share:
As reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$0 02.84
$0 02.74
$ 82,300
$ 78,788
$ 001.66
$ 001.59
$ 001.64
$ 001.57
$ 42,788
$040,268
$000 .87
$ 000.82
$0 00.86
$0 00.81
These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized
to expense over the vesting period, and additional options may be granted in future years.
The weighted-average fair values of options at their grant date during 2001, 2000, and 1999 were $13.01, $10.80, and $6.81, respectively.
The estimated fair value of each option granted is calculated using the Black-Scholes option-pricing model. The following summarizes
the weighted-average assumptions used in the model:
Expected years until exercise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected stock volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2001
4.5
43%
1.8%
5.2%
2000
5.5
41%
.8%
6.0%
1999
5.5
38%
1.2%
6.0%
On September 30, 2001, the Company had 49,852,797 outstanding common stock purchase rights ("Rights") pursuant to terms of
the Rights Agreement dated January 8, 1996. Under the terms of the Rights Agreement each Right entitled the holder thereof to
purchase from the Company one half of one unit consisting of one one-thousandth of a share of Series A Junior Participating
Preferred Stock ("Preferred Stock"), without par value, at a price of $90 per unit. The exercise price and the number of units of
Preferred Stock issuable on exercise of the Rights are subject to adjustment in certain cases to prevent dilution. The Rights will be
attached to the common stock certificates and are not exercisable or transferrable apart from the common stock, until ten business
days after a person acquires 15% or more of the outstanding common stock or ten business days following the commencement of a
tender offer or exchange offer that would result in a person owning 15% or more of the outstanding common stock. In the event the
Company is acquired in a merger or certain other business combination transactions (including one in which the Company is the sur-
viving corporation), or more than 50% of the Company’s assets or earning power is sold or transferred, each holder of a Right shall
have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the
exercise price of the Right. The Rights are redeemable under certain circumstances at $0.01 per Right and will expire, unless earlier
redeemed, on January 31, 2006. As long as the Rights are not separately transferrable, the Company will issue one half of one
Right with each new share of common stock issued.
NOTE 5 EARNINGS PER SHARE
A reconciliation of the weighted-average common shares outstanding on a basic and diluted basis is as follows:
(in thousands)
Basic weighted-average shares . . . . . . . . . . . . . . . . . . . . . . . .
Effect of dilutive shares:
Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted weighted-average shares . . . . . . . . . . . . . . . . . . . . . . . . .
2001
50,096
644
32
676
50,772
2000
49,534
492
9
501
50,035
1999
49,243
561
13
574
49,817
Restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 1,250,750 shares of common stock at a
weighted-average price of $33.84 were outstanding at September 30, 2001 but were not included in the computation of diluted earnings per
common share. Inclusion of these shares would be antidilutive.
At September 30, 2000, restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 533,000 shares of
common stock at a price of $36.84 were outstanding but were not included in the computation of diluted earnings per common share.
Inclusion of these shares would be antidilutive.
At September 30, 1999, restricted stock of 180,000 shares at a weighted-average price of $37.73 and options to purchase 540,000 shares of
common stock at a price of $36.84 were outstanding but were not included in the computation of diluted earnings per common share.
Inclusion of these shares would be antidilutive.
27
NOTE 6 FINANCIAL INSTRUMENTS
Notes payable bear interest at market rates and are carried at cost which approximates fair value. The estimated fair value of the
Company’s interest rate swap is ($1,590,553) at September 30, 2001, based on forward-interest rates derived from the year-end
yield curve as calculated by the financial institution that is a counterparty to the swap. The estimated fair value of the Company’s
available-for-sale securities is primarily based on market quotes.
The following is a summary of available-for-sale securities, which excludes those accounted for under the equity method of
accounting (see Note 1):
Gross Gross Estimated
Equity Securities:
September 30, 2001
September 30, 2000
Unrealized Unrealized Fair
Cost Gains Losses Value
(in thousands)
$63,778
$86,901
$ 84,257
$173,137
$3,136
$2,065
$144,899
$257,973
During the years ended September 30, 2001, 2000, and 1999, marketable equity available-for-sale securities with a fair value at
the date of sale of $24,439,000, $12,640,000, and $2,803,000, respectively, were sold. The gross realized gains on such sales of
available-for-sale securities totaled $3,314,000, $12,576,000, and $2,547,000, respectively, and the gross realized losses totaled
$0, $0, and $0 respectively.
NOTE 7 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The table below presents changes in the components of accumulated other comprehensive income (loss).
Balance at September 30, 1998 . . . . . . . . . . . . . . . . . . . . . . . .
1999 Change:
Unrealized Appreciation
(Depreciation) on Securities
$ 54,689
Pre-income tax amount . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized gains in net income (net of $968 income tax) . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 1999 . . . . . . . . . . . . . . . . . . . . . . . .
2000 Change:
Pre-income tax amount . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized gains in net income (net of $9,120 income tax) .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2000 . . . . . . . . . . . . . . . . . . . . . . . .
2001 Change:
Pre-income tax amount . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized gains in net income (net of $452 income tax) . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at September 30, 2001 . . . . . . . . . . . . . . . . . . . . . . . .
NOTE 8 EMPLOYEE BENEFIT PLANS
35,600
(13,528)
(1,579)
20,493
75,182
73,810
(28,048)
(14,880)
30,882
106,064
(88,762)
33,730
(737)
(55,769)
$ 50,295
Interest
Rate Swap
$
(1,590)
604
(986)
$ (986)
Total
$ 54,689
35,600
(13,528)
(1,579)
20,493
75,182
73,810
(28,048)
(14,880)
30,882
106,064
(90,352)
34,334
(737)
(56,755)
$ 49,309
The following tables set forth the Company’s disclosures required by SFAS No. 132, “Employers’ Disclosures About Pensions and
Other Postretirement Benefits”.
Change in benefit obligation:
Years ended September 30, 2001
2000
(in thousands)
Benefit obligation at beginning of year .......................................................
Service cost................................................................................................
Interest cost................................................................................................
Actuarial loss .............................................................................................
Benefits paid...............................................................................................
Benefit obligation at end of year .................................................................
$44,838
3,851
3,330
903
(1,189)
$51,733
$36,995
3,427
2,741
3,059
(1,384)
$44,838
Change in plan assets:
Years ended September 30, 2001
2000
(in thousands)
Fair value of plan assets at beginning of year ............................................
Actual return (loss) on plan assets .............................................................
Benefits paid...............................................................................................
Fair value of plan assets at end of year .....................................................
Funded status of the plan...........................................................................
Unrecognized net actuarial (gain) loss .......................................................
Unrecognized prior service cost .................................................................
Unrecognized net transition asset ..............................................................
Prepaid benefit cost....................................................................................
$60,611
(5,435)
(1,189)
$53,987
$ 2,254
6,720
548
(540)
$ 8,982
$(58,517
3,478
(1,384)
$(60,611
$(15,773
(5,016)
786
(1,079)
$(10,464
28
Weighted-average assumptions:
Years Ended September 30,
Discount rate ......................................................................
Expected return on plan .....................................................
Rate of compensation increase ..........................................
Components of net periodic pension expense:
2001
7.50%
9.00%
5.00%
Years Ended September 30,
2001
Service cost ........................................................................
Interest cost ........................................................................
Expected return on plan assets ..........................................
Amortization of prior service cost .......................................
Amortization of transition asset ..........................................
Recognized net actuarial gain ............................................
Net pension expense ..........................................................
$ 3,851
3,330
(5,415)
238
(540)
17
$ 1,481
2000
7.50%
9.00%
5.00%
2000
(in thousands)
$ 3,427
2,741
(5,226)
238
(540)
(303)
$ (337
1999
7.50%
9.00%
5.00%
1999
$ 3,700
2,468
(4,606)
238
(540)
14
$ 1,274
Defined Contribution Plan:
Substantially all employees on the United States payroll of the Company may elect to participate in the Company sponsored
Thrift/401(k) Plan by contributing a portion of their earnings. The Company contributes amounts equal to 100 percent of the first five
percent of the participant’s compensation subject to certain limitations. Expensed Company contributions were $4,935,000,
$3,545,000, and $3,315,000 in 2001, 2000, and 1999, respectively.
NOTE 9 ACCRUED LIABILITIES
Accrued liabilities consist of the following:
September 30,
2001
2000
(in thousands)
Royalties payable .......................................................................................
Taxes payable - operations.........................................................................
Ad valorem tax............................................................................................
Income taxes payable.................................................................................
Workers compensation claims....................................................................
Payroll and employee benefits....................................................................
Loss contingency (see note 13) .................................................................
Other ..........................................................................................................
.....
$13,527
9,996
354
739
2,585
5,676
10,000
10,749
$53,626
$18,918
6,861
7,783
—
2,840
4,055
—
6,158
$46,615
NOTE 10 SUPPLEMENTAL CASH FLOW INFORMATION
Years Ended September 30,
2001
Cash payments:
Interest paid........................................................................
Income taxes paid ..............................................................
$05,030
$73,039
2000
(in thousands)
$02,491
$39,673
1999
$05,705
$27,843
NOTE 11 RISK FACTORS
CONCENTRATION OF CREDIT -
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of temporary cash investments and
trade receivables. The Company places temporary cash investments with established financial institutions and invests in a diversified portfolio of
highly rated, short-term money market instruments. The Company's trade receivables are primarily with companies in the oil and gas industry. The
Company normally does not require collateral except for certain receivables of customers in its natural gas marketing operations.
CONTRACT DRILLING OPERATIONS -
International drilling operations are significant contributors to the Company’s revenues and net profit. It is possible that operating results could be
affected by the risks of such activities, including economic conditions in the international markets in which the Company operates, political and eco-
nomic instability, fluctuations in currency exchange rates, changes in international regulatory requirements, international employment issues, and the
burden of complying with foreign laws. These risks may adversely affect the Company’s future operating results and financial position.
The Company believes that its rig fleet is not currently impaired based on an assessment of future cash flows of the assets in question. However, it
is possible that the Company’s assessment that it will recover the carrying amount of its rig fleet from future operations may change in the near term.
OIL AND GAS OPERATIONS -
In estimating future cash flows attributable to the Company’s exploration and production assets, certain assumptions are made with regard to com-
modity prices received and costs incurred. Due to the volatility of commodity prices, it is possible that the Company’s assumptions used in estimat-
ing future cash flows for exploration and production assets may change in the near term.
29
NOTE 12 NEW ACCOUNTING STANDARDS
Effective October 1, 2000, the Company adopted Statement of Financial Accounting Standards No. 133 (SFAS 133), "Accounting for Derivative
Instruments and Hedging Activities," as amended, which establishes accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities. SFAS 133, as amended, requires that all derivatives be recorded on
the balance sheet at fair value. Upon adoption at October 1, 2000, the effect of complying with SFAS 133, as amended, was immaterial to the
Company’s results of operations and financial position.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends FASB
Statement No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Statement requires that the fair value of a liabil-
ity for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that
the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Statement is effective for financial
statements issued for fiscal years beginning after June 15, 2002. The effect of this standard on the Company’s results of operations and financial
position is being evaluated.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This Statement supersedes
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and amends Accounting
Principles Board Opinion No. 30, "Reporting the Results of Operations – Reporting the Effects of Disposal of a Segment of a Business and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The Statement retains the basic framework of SFAS No. 121, resolves
certain implementation issues of SFAS No. 121, extends applicability to discontinued operations, and broadens the presentation of discontinued
operations to include a component of an entity. The Statement will be applied prospectively and is effective for financial statements issued for fiscal
years beginning after December 15, 2001. Adoption of the Statement is not expected to have any initial impact on the Company’s results of opera-
tions or financial position.
NOTE 13 CONTINGENT LIABILITIES AND COMMITMENTS
LITIGATION SETTLEMENT -
As previously discussed in the Company’s filings on Forms 8-K dated March 16, 2001, and June 13, 2001, and in the Company’s Form 10-Q filed on
August 13, 2001, the Company is a defendant in Verdin v. R&B Falcon Drilling USA, Inc., et al., a civil action in the United States District Court,
Galveston, Texas. The lawsuit alleges, among other things, that the company and many other defendant companies whose collective operations
represent a substantial majority of the U.S. offshore drilling industry, conspired to fix wages and benefits paid to drilling employees. Plaintiff con-
tends that this alleged conduct violates federal and state antitrust laws. Plaintiff sought treble damages, attorneys’ fees and costs on behalf of him-
self and an alleged class of offshore workers.
In May 2001, the Company reached an agreement in principle with Plaintiff’s counsel to settle all claims pending court approval of the settlement. In the
third quarter of fiscal 2001, the Company accrued $3.25 million to contract drilling expense based on the pending settlement. The total settlement liability
is $10 million of which $6.75 million will be paid by the Company’s insurer. The Company does not believe that the settlement will have a material
adverse affect on its business or financial position.
KANSAS AD VALOREM SETTLEMENT -
In fiscal 1997, the Company was assessed with approximately $6.7 million of Kansas ad valorem taxes which had been reimbursed to the Company
for the period from October 1983 through June 1988 by interstate pipelines transporting natural gas to end users. In fiscal 1997, based on the
assessment, natural gas revenues were reduced by $2.7 million and interest expense was increased by $4.0 million. In March 1998, approximately
$6.1 million of the unpaid assessment was placed in an escrow account pending resolution of this matter. Since March 1998, the escrow account
and the related liability continued to accrue interest income and interest expense of approximately $1.0 million.
The Federal Energy Regulatory Commission approved settlements between the Company and three of the pipelines. The last of these settlements
was final in May 2001. The Company paid approximately $3.9 million out of its escrow account for the settlement of all three pipeline proceedings. The
three settlements were approximately $3.1 million less than the amount the Company accrued for this liability. The impact of these settlements in the
third quarter of fiscal 2001 was to increase natural gas revenues by approximately $1.1 million, reduce interest expense by approximately $2.0 million
and reduce the liability by $3.1 million. At September 30, 2001, the Company continues to escrow approximately $337,000 to cover reimbursement lia-
bility in the remaining two pipeline proceedings. The Company believes this amount will be adequate to cover future reimbursement liability.
COMMITMENTS -
The Company, on a regular basis, makes commitments for the purchase of contract drilling equipment. At September 30, 2001, the Company has
commitments of approximately $230 million for the purchase of drilling equipment.
NOTE 14 SEGMENT INFORMATION
The Company operates principally in the contract drilling industry, which includes a Domestic segment and an International segment, and in the
oil and gas industry, which includes an Exploration and Production segment and a Natural Gas Marketing segment. The contract drilling opera-
tions consist of contracting Company-owned drilling equipment primarily to major oil and gas exploration companies. The Company’s primary
international areas of operation include Venezuela, Colombia, Ecuador, Argentina and Bolivia. Oil and gas activities include the exploration for
and development of productive oil and gas properties located primarily in Oklahoma, Texas, Kansas, and Louisiana, as well as, the marketing of
natural gas for third parties. The Natural Gas Marketing segment also markets most of the natural gas produced by the Exploration and
Production segment retaining a market based fee from the sale of such production. The Company also has a Real Estate segment whose opera-
tions are conducted exclusively in the metropolitan area of Tulsa, Oklahoma. The primary areas of operations include a major shopping center
and several multi-tenant warehouses. Each reportable segment is a strategic business unit which is managed separately as an autonomous busi-
ness. Other includes investments in available-for-sale securities and corporate operations. The "other" component of Total Assets also includes
the Company’s investment in equity-owned investments.
The Company evaluates performance of its segments based upon operating profit or loss from operations before income taxes which includes
revenues from external and internal customers; operating costs; depreciation, depletion and amortization; dry holes and abandonments and taxes
other than income taxes. The accounting policies of the segments are the same as those described in Note 1, Summary of Accounting Policies.
Intersegment sales are accounted for in the same manner as sales to unaffiliated customers.
30
Summarized financial information of the Company’s reportable segments for each of the years ended September 30, 2001, 2000,
and 1999 is shown in the following table:
(in thousands)
2001:
Contract Drilling
External
Sales
Inter-
Segment
Total
Sales
Depreciation
Operating Depletion &
Amortization
Profit
Total
Assets
Additions
to Long-Lived
Assets
Domestic . . . . . . . . . . . . . . . . . . . . $332,399 $(04,487 $336,886 $107,691
28,475
International Services . . . . . . . . . . 154,890
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 487,289
136,166
Oil & Gas Operations
154,890
491,776
4,487
Exploration and Production . . . . . . 217,194
Natural Gas Marketing . . . . . . . . . 100,111
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 317,305
11,018
Real Estate . . . . . . . . . . . . . . . . . . . .
11,242
Other . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminations . . . . . . . . . . . . . . . . . . .
95,579
5,254
100,833
6,315
217,194
100,111
317,305
12,563
11,242
(6,032)
1,545
(6,032)
$025,890
18,838
44,728
$0,506,173
268,947
775,120
$144,063
38,022
182,085
38,104
170
38,274
2,264
2,043
190,907
14,598
205,505
22,621
361,261
89,733
269
90,002
1,190
1,393
Total . . . . . . . . . . . . . . . . . . . . . $826,854 $(00,000 $826,854 $243,314
$ 87,309
$1,364,507
$274,670
2000:
Contract Drilling
Domestic . . . . . . . . . . . . . . . . . . . . $214,531 $(03,048 $217,579 $035,808
9,753
International . . . . . . . . . . . . . . . . . 136,549
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 351,080
45,561
Oil & Gas Operations
136,549
354,128
3,048
$035,310
38,096
73,406
$0,342,278
259,892
602,170
$040,722
13,825
54,547
Exploration and Production . . . . . . 157,583
80,907
Natural Gas Marketing . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 238,490
8,999
Real Estate . . . . . . . . . . . . . . . . . . . .
32,526
Other . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminations . . . . . . . . . . . . . . . . . . .
157,583
80,907
238,490
10,544
32,526
(4,593)
1,545
(4,593)
66,604
5,271
71,875
5,346
33,462
164
33,626
1,598
2,221
174,466
21,897
196,363
24,235
436,724
65,804
175
65,979
2,909
8,497
Total . . . . . . . . . . . . . . . . . . . . . $631,095 $(00,000 $631,095 $122,782
$110,851
$1,259,492
$131,932
1999:
Contract Drilling
Domestic . . . . . . . . . . . . . . . . . . . . $213,647 $(02,457 $216,104 $030,154
29,845
International . . . . . . . . . . . . . . . . . 182,987
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 396,634
59,999
Oil & Gas Operations
182,987
399,091
2,457
$031,164
36,178
67,342
$0,371,766
271,746
643,512
$057,975
17,293
75,268
Exploration and Production . . . . . .
Natural Gas Marketing . . . . . . . . .
95,953
55,259
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 151,212
8,671
Real Estate . . . . . . . . . . . . . . . . . . . .
7,802
Other . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminations . . . . . . . . . . . . . . . . . . .
95,953
55,259
151,212
10,202
7,802
(3,988)
1,531
(3,988)
11,245
4,418
15,663
5,338
38,658
174
38,832
1,427
1,566
151,898
15,156
167,054
22,816
276,317
44,333
261
44,594
1,445
1,644
Total . . . . . . . . . . . . . . . . . . . . . $564,319 $(00,000 $564,319 $081,000
$109,167
$1,109,699
$122,951
The following table reconciles segment operating profit per the table on page 31 to income before taxes and equity in income of
affiliate as reported on the Consolidated Statements of Income (in thousands).
Years Ended September 30,
2001
2000
1999
Segment operating profit ......................................................
Unallocated amounts:
Income from investments.....................................................
General and administrative expense ...................................
Interest expense ..................................................................
Corporate depreciation ........................................................
Other corporate expense .....................................................
Total unallocated amounts ...............................................
Income before income taxes and equity in
$243,314
$122,782
$(81,000
10,592
(15,415)
32
(2,043)
(1,378)
(8,212)
31,973
(11,578)
(3,076)
(2,152)
(1,186)
13,981
7,757
(14,198)
(6,481)
(1,565)
(1,575)
(16,062)
income of affiliates ...............................................................
$235,102
$136,763
$ 64,938
31
The following tables present revenues from external customers and long-lived assets by country based on the location of service
provided (in thousands).
Years Ended September 30,
2001
2000
1999
Revenues
United States ...................................................................
Venezuela ........................................................................
Colombia .........................................................................
Other Foreign...................................................................
Total.............................................................................
Long-Lived Assets
United States ...................................................................
Venezuela ........................................................................
Colombia .........................................................................
Other Foreign...................................................................
Total.............................................................................
Long-lived assets are comprised of property, plant and equipment.
$671,964
43,409
27,045
84,436
$826,854
$616,472
84,856
16,195
100,881
$818,404
$494,546
34,922
42,509
59,118
$631,095
$477,593
37,001
26,361
132,650
$673,605
$381,332
59,481
60,838
62,668
$564,319
$479,753
62,931
46,621
101,910
$691,215
Revenues from one company doing business with the contract drilling segment accounted for approximately 14.9 percent, 15.2
percent, and 17.5 percent of the total consolidated revenues during the years ended September 30, 2001, 2000 and 1999,
respectively. Revenues from another company doing business with the contract drilling segment accounted for approximately 8.0
percent, 7.4 percent, and 12 percent of total consolidated revenues in the years ended September 30, 2001, 2000, and 1999,
respectively. Collectively, the receivables from these customers were approximately $32.6 million and $17.4 million at September
30, 2001 and 2000, respectively.
NOTE 15 SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
All of the Company’s oil and gas producing activities are located in the United States.
Results of Operations from Oil and Gas Producing Activities -
Years Ended September 30,
2001
Revenues ............................................................................
Production costs ..................................................................
Exploration expense and valuation provisions .......................
Depreciation, depletion and amortization ..............................
Income tax expense .............................................................
Total cost and expenses....................................................
Results of operations (excluding corporate overhead
$217,194
37,418
46,093
38,104
34,986
156,601
2000
(in thousands)
$157,583
26,685
30,832
33,462
23,447
114,426
and interest costs) ............................................................
$060,593
$ 43,157
1999
$95,953
23,058
22,992
38,658
3,437
88,145
$ 7,808
Capitalized Costs -
September 30,
2001
2000
(in thousands)
Proved properties.....................................................................................................
Unproved properties ................................................................................................
Total costs ............................................................................................................
Less - Accumulated depreciation, depletion and amortization.................................
Net ........................................................................................................................
$486,772
34,901
521,673
357,094
$164,579
Costs Incurred Relating to Oil and Gas Producing Activities -
Years Ended September 30,
2001
Property acquisition:
Proved .............................................................................
Unproved..........................................................................
Exploration...........................................................................
Development........................................................................
Total .................................................................................
$ 00,738
18,612
44,166
41,459
$104,975
2000
(in thousands)
$00,105
11,040
43,833
18,843
$73,821
$430,675
27,050
457,725
314,091
$143,634
1999
$00, 89
14,385
22,292
19,167
$55,933
32
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) -
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demon-
strate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating
methods. The following is an analysis of proved oil and gas reserves as estimated by Netherland, Sewell & Associates, Inc. at September
30, 2001 and 2000. Amounts at Sepbember 30, 1999 were estimated by the Company and reviewed by independent engineers.
Proved reserves at September 30, 1998 ...................................................................
Revisions of previous estimates ................................................................................
Extensions, discoveries and other additions..............................................................
Production..................................................................................................................
Purchases of reserves-in-place .................................................................................
Sales of reserves-in-place .........................................................................................
Proved reserves at September 30, 1999 ...................................................................
Revisions of previous estimates ................................................................................
Extensions, discoveries and other additions..............................................................
Production..................................................................................................................
Purchases of reserves-in-place .................................................................................
Sales of reserves-in-place .........................................................................................
Proved reserves at September 30, 2000 ...................................................................
Revisions of previous estimates ................................................................................
Extensions, discoveries and other additions..............................................................
Production..................................................................................................................
Purchases of reserves-in-place .................................................................................
Sales of reserves-in-place .........................................................................................
OIL (Bbls)
4,761,313
570,126
151,829
(649,370)
4,833,898
1,316,714
1,119,314
(880,304)
1,502
(85,987)
6,305,137
(700,329)
1,144,709
(818,356)
434
GAS (Mmcf)
251,626
11,771
22,491
(44,240)
77
(2,105)
239,620
17,363
52,569
(46,923)
242
(373)
262,498
(17,018)
12,748
(42,387)
496
Proved reserves at September 30, 2001 ...................................................................
5,931,595
216,337
Proved developed reserves at
September 30, 1999...............................................................................................
September 30, 2000...............................................................................................
September 30, 2001...............................................................................................
4,828,071
5,847,217
4,865,569
229,765
217,334
198,103
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) -
The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves" (Standardized
Measure) is a disclosure requirement under Financial Accounting Standards Board Statement No. 69 "Disclosures About Oil and
Gas Producing Activities". The Standardized Measure does not purport to present the fair market value of a company's proved oil
and gas reserves. This would require consideration of expected future economic and operating conditions, which are not taken into
account in calculating the Standardized Measure.
Under the Standardized Measure, future cash inflows were estimated by applying year-end prices to the estimated future production
of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on
year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the Company's tax basis in the associated proved oil and gas properties. Tax credits and per-
manent differences were also considered in the future income tax calculation. Future net cash inflows after income taxes were dis-
counted using a ten percent annual discount rate to arrive at the Standardized Measure.
At September 30,
2001
2000
Future cash inflows ....................................................................................................
Future costs -
Future production and development costs ............................................................
Future income tax expense ...................................................................................
Future net cash flows.................................................................................................
10% annual discount for estimated timing of cash flows ...........................................
Standardized Measure of discounted future net cash flows ......................................
(in thousands)
$ 467,886
$1,377,922
(174,703)
(81,253)
211,930
(67,891)
$ 144,039
(317,898)
(331,672)
728,352
(240,281)
$( 488,071
33
Changes in Standardized Measure Relating to Proved Oil and Gas Reserves (Unaudited) _
Years Ended September 30,
2001
2000
(in thousands)
1999
Standardized Measure - Beginning of year............................
Increases (decreases) -
Sales, net of production costs ............................................
Net change in sales prices, net of production costs ...........
Discoveries and extensions, net of related future
development and production costs.................................
Changes in estimated future development costs ...............
Development costs incurred ...............................................
Revisions of previous quantity estimates ...........................
Accretion of discount ..........................................................
Net change in income taxes ...............................................
Purchases of reserves-in-place..........................................
Sales of reserves-in-place..................................................
Changes in production rates and other ..............................
Standardized Measure - End of year .....................................
$(488,071
$ 232,618
$ 125,927
(179,776)
(400,679)
29,387
10,667
17,311
(15,298)
68,021
160,776
619
(35,060)
$(144,039
(130,898)
261,926
156,840
(36,994)
13,587
57,730
30,951
(114,762)
542
(700)
17,231
$ 488,071
(72,895)
142,970
38,164
(11,095)
16,558
17,713
16,700
(40,671)
96
(1,390)
541
$ 232,618
NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
(in thousands, except per share amounts)
2001
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
Revenues .............................................................................
Gross profit ..........................................................................
Net income ...........................................................................
Basic net income per share ..................................................
Diluted net income per share ...............................................
$192,550
59,614
33,840
.68
.67
$221,569
72,939
41,749
.83
.82
$217,222
67,607
40,437
.80
.79
$195,513
50,325
28,228
.56
.56
2000
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
Revenues .............................................................................
Gross profit ..........................................................................
Net income ...........................................................................
Basic net income per share ..................................................
Diluted net income per share ...............................................
$149,581
37,852
20,461
.41
.41
$151,848
36,256
19,273
.39
.39
$151,968
32,605
18,557
.37
.37
$177,698
44,704
24,009
.48
.48
Gross profit represents total revenues less operating costs, depreciation, depletion and amortization, dry holes and abandonments, and
taxes, other than income taxes.
The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the aver-
age number of common shares outstanding.
Net income in the second quarter of 2001 includes an after-tax charge of $2.4 million ($0.05 per share, on a diluted basis) related to the
write-down of producing properties in accordance with SFAS No. 121.
Net income in the third quarter of 2001 includes an after-tax gain of approximately $1.9 million ($0.04 per share, on a diluted basis)
related to a 1997 Kansas ad valorem assessment that was settled at less than the original liability. The after-tax gain increased natural
gas revenues by approximately $.7 million and decreased interest expense by approximately $1.2 million.
Net income in the fourth quarter of 2001 includes an after-tax charge of $2.8 million ($0.06 per share, on a diluted basis) related to the
write-down of producing properties in accordance with SAFS No. 121.
Net income in the first quarter of 2000 includes approximately $6.3 million ($0.13 per share, on a diluted basis) on gains related to a
non-monetary dividend received and a gain on the conversion of shares of common stock of a Company investee pursuant to that
investee being acquired.
Net income in the fourth quarter of 2000 includes an after-tax charge of $2.5 million ($0.05 per share, on a diluted basis) related to the
write-down of producing properties in accordance with SFAS No. 121.
34
Report of Independent Auditors
HELMERICH & PAYNE, INC.
The Board of Directors and Shareholders
Helmerich & Payne, Inc.
We have audited the accompanying consolidated balance sheets of Helmerich &
Payne, Inc. as of September 30, 2001 and 2000, and the related consolidated
statements of income, shareholders' equity, and cash flows for each of the three
years in the period ended September 30, 2001. These financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Helmerich & Payne, Inc. at
September 30, 2001 and 2000, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended September 30, 2001,
in conformity with accounting principles generally accepted in the United States.
Tulsa, Oklahoma
November 19, 2001
Stock Price Information
Closing Market Price Per Share
2001
2000
QUARTERS HIGH LOW HIGH
First ..................................................
Second .............................................
Third .................................................
Fourth...............................................
$ 44.19
58.51
51.23
32.77
$ 28.94
39.63
30.82
23.74
$ 27.44
31.00
37.75
38.31
LOW
$ 19.13
20.00
29.06
30.06
Dividend Information
QUARTERS
Paid Per Share Total Payment
2001 2000
2001
2000
STOCKHOLDERS’ MEETING
The annual meeting of stockholders will be held
on March 6, 2002. A formal notice of the meet-
ing, together with a proxy statement and form of
proxy, will be mailed to shareholders on or about
January 25, 2002.
STOCK EXCHANGE LISTING
Helmerich & Payne, Inc. Common Stock is traded
on the New York Stock Exchange with the ticker
symbol “HP.” The newspaper abbreviation most
commonly used for financial reporting is “HelmP.”
Options on the Company’s stock are also traded
on the New York Stock Exchange.
STOCK TRANSFER AGENT AND REGISTRAR
As of December 14, 2001, there were 1,090
record holders of Helmerich & Payne, Inc. com-
mon stock as listed by the transfer agent’s
records.
Our Transfer Agent is responsible for our share-
holder records, issuance of stock certificates,
and distribution of our dividends and the IRS
Form 1099. Your requests, as shareholders,
concerning these matters are most efficiently
answered by corresponding directly with The
Transfer Agent at the following address:
UMB Bank
Security Transfer Division
928 Grand Blvd., 13th Floor
Kansas City, MO 64106
Telephone: (800) 884-4225
(816) 860-5000
FORM 10-K
The Company's Annual Report on Form 10-K,
which has been submitted to the Securities and
Exchange Commission, is available free of
charge upon written request.
ADDITIONAL INFORMATION
In a continuing effort to find timely and cost effec-
tive communications solutions to serve the needs
of our shareholders, we are discontinuing the
printing and distribution of our traditional quarterly
shareholder reports. Effective the first quarter
ending December 31, 2001, quarterly reports on
Form 10-Q, earnings releases and financial
statements will be made available on the investor
relations section of the Company's Web site.
Quarterly reports on Form 10-Q, earnings releases
and financial statements will also be available
free of charge upon written request.
First .................................................. $.075 $.070
.070
Second ..............................................
.070
Third .................................................
.075
Fourth................................................
.075
.075
.075
$3,748,896
3,776,612
3,796,489
3,765,488
$3,474,612
3,475,623
3,484,189
3,740,863
DIRECT INQUIRIES TO:
Investor Relations
Helmerich & Payne, Inc.
Utica at Twenty-First
Tulsa, Oklahoma 74114
Telephone: (918) 742-5531
Internet Address: http://www.hpinc.com
35
Eleven-Year Financial Review
HELMERICH & PAYNE, INC.
Years Ended September 30, 2001 2000 1999
REVENUES AND INCOME* (cid:2)
Contract Drilling Revenues..........................................................
Crude Oil Sales...........................................................................
Natural Gas Sales .......................................................................
Gas Marketing Revenues............................................................
Real Estate Revenues.................................................................
Dividend Income .........................................................................
Other Revenues ..........................................................................
Total Revenues†..........................................................................
Net Cash Provided by Continuing Operations† ..........................
Income from Continuing Operations ...........................................
Net Income .................................................................................
PER SHARE DATA
Income from Continuing Operations(cid:3) :
Basic ......................................................................................
Diluted....................................................................................
Net Income(cid:3) :
Basic ......................................................................................
Diluted....................................................................................
Cash Dividends ...........................................................................
Shares Outstanding*...................................................................
FINANCIAL POSITION
Net Working Capital* ..................................................................
Ratio of Current Assets to Current Liabilities ..............................
Investments* ...............................................................................
Total Assets* ...............................................................................
Long-Term Debt* ........................................................................
Shareholders’ Equity* .................................................................
CAPITAL EXPENDITURES*
Contract Drilling Equipment ........................................................
Wells and Equipment ..................................................................
Real Estate .................................................................................
Other Assets (includes undeveloped leases) ..............................
Discontinued Operations.............................................................
Total Capital Outlays ...................................................................
PROPERTY, PLANT AND EQUIPMENT AT COST*
Contract Drilling Equipment ........................................................
Producing Properties ..................................................................
Undeveloped Leases ..................................................................
Real Estate .................................................................................
Other ...........................................................................................
Discontinued Operations.............................................................
Total Property, Plant and Equipment...........................................
484,927
22,815
192,962
99,140
9,066
3,909
14,035
826,854
278,856
144,254
144,254
2.88
2.84
2.88
2.84
.30
49,853
349,992
24,601
131,056
78,921
8,991
14,482
23,052
631,095
201,836
82,300
82,300
1.66
1.64
1.66
1.64
.285
49,980
394,715
9,479
81,533
54,263
8,663
3,569
12,097
564,319
158,694
42,788
42,788
.87
.86
.87
.86
.28
49,626
210,191
2.73
200,286
1,364,507
50,000
1,026,477
186,250
3.36
304,326
1,259,492
50,000
955,703
88,720
2.23
238,475
1,109,699
50,000
848,109
173,856
74,580
1,144
28,904
__
278,484
1,028,015
486,772
34,901
50,579
86,300
__
49,774
54,764
2,880
24,514
__
68,639
29,947
1,435
22,930
__
131,932
122,951
891,749
430,674
27,050
50,649
80,268
__
881,269
421,552
25,337
49,065
71,139
__
1,686,567
1,480,390
1,448,362
* 000’s omitted.
†Chemical operations were sold August 30, 1996. Prior year amounts have been restated to exclude discontinued operations.
Includes $13.6 million ($.28 per share, on a diluted basis) effect of impairment charge for adoption of SFAS No. 121 in 1995 and
cumulative effect of change in accounting for income taxes of $4,000,000 ($.08 per share, on a diluted basis) in 1994.
(cid:2) See Note 14 for segment presentation of revenues.
36
(cid:3)
1998
1997
1996
1995
1994
1993
1992
1991
427,713
10,333
87,646
52,469
8,587
4,117
45,775
636,640
113,533
101,154
101,154
2.03
2.00
2.03
2.00
.275
49,383
315,327
20,475
87,737
66,306
8,224
5,268
14,522
517,859
165,568
84,186
84,186
1.69
1.67
1.69
1.67
.26
50,028
58,861
1.47
200,400
1,090,430
50,000
793,148
62,837
1.66
323,510
1,033,595
__
780,580
206,794
38,970
854
19,681
__
266,299
829,217
414,770
20,977
48,451
65,120
__
109,036
35,024
1,095
16,022
__
161,177
643,619
395,812
14,109
47,682
59,659
__
244,338
15,378
60,500
57,817
8,076
3,650
3,496
393,255
121,420
45,426
72,566
.92
.91
1.47
1.46
.2525
49,771
51,803
1.83
229,809
821,914
__
645,970
79,269
21,142
752
7,003
1,581
109,747
568,110
392,562
9,242
46,970
53,547
__
1,378,535
1,160,881
1,070,431
203,325
13,227
33,851
34,729
7,560
3,389
10,640
306,721
84,010
5,788
9,751
.12
.12
.20
.20
.25
49,529
50,038
1.74
156,908
707,061
__
562,435
80,943
19,384
873
9,717
859
111,776
501,682
384,755
8,051
46,642
55,655
13,937
1,010,722
182,781
13,161
45,261
51,874
7,396
3,621
6,058
310,152
74,463
17,108
24,971
.35
.35
.51
.51
.2425
49,420
76,238
2.63
87,414
621,689
__
524,334
53,752
40,916
902
9,695
618
105,883
444,432
377,371
11,729
47,827
48,612
13,131
943,102
149,661
15,392
52,446
63,786
7,620
3,535
8,283
300,723
72,493
22,158
24,550
.46
.45
.51
.50
.24
49,275
104,085
3.24
84,945
610,504
3,600
508,927
24,101
23,142
436
5,901
629
54,209
418,004
340,176
10,010
47,502
45,085
12,545
873,322
112,833
16,369
38,370
40,410
7,541
4,050
6,646
226,219
60,414
8,973
10,849
.19
.19
.22
.22
.2325
49,152
82,800
3.31
87,780
585,504
8,339
493,286
43,049
21,617
690
16,984
158
82,498
404,155
329,264
12,973
47,286
43,153
11,962
848,793
105,364
17,374
35,628
10,055
7,542
5,285
20,020
201,268
50,006
19,608
21,241
.41
.41
.44
.44
.23
48,976
108,212
4.19
96,471
575,168
5,693
491,133
56,297
34,741
2,104
6,793
2,594
102,529
370,494
312,438
5,552
46,671
36,423
11,838
783,416
37
Eleven-Year Operating Review
HELMERICH & PAYNE, INC.
Years Ended September 30,
2001
2000
1999
CONTRACT DRILLING
Drilling Rigs, United States ................................................................
Drilling Rigs, International..................................................................
Contract Wells Drilled, United States.................................................
Total Footage Drilled, United States* .................................................
Average Depth per Well, United States .............................................
Percentage Rig Utilization, United States ..........................................
Percentage Rig Utilization, International............................................
59
32
346
4,415
12,761
97
56
48
40
335
4,058
12,115
87
47
46
44
242
2,938
12,142
75
53
PETROLEUM EXPLORATION AND DEVELOPMENT
Gross Wells Completed .....................................................................
Net Wells Completed .........................................................................
Net Dry Holes ....................................................................................
123
69.5
17.0
81
42.7
9.1
49
23.9
7.1
PETROLEUM PRODUCTION
Net Crude Oil and Natural Gas Liquids
Produced (barrels daily).................................................................
Net Oil Wells Owned — Primary Recovery........................................
Net Oil Wells Owned — Secondary Recovery...................................
Secondary Oil Recovery Projects ......................................................
Net Natural Gas Produced
(thousands of cubic feet daily) .......................................................
Net Gas Wells Owned........................................................................
2,242
113
55
4
2,405
107.1
55.5
3
1,779
124
54
5
116,128
493
128,204
453
121,206
439
REAL ESTATE MANAGEMENT
Gross Leasable Area (square feet)* ..................................................
Percentage Occupancy......................................................................
1,652
93
1,652
91
1,652
95
TOTAL NUMBER OF EMPLOYEES
Helmerich & Payne, Inc. and Subsidiaries .........................................
4,245
3,606
3,440
* 000’s omitted.
38
1998
1997
1996
1995
1994
1993
1992
1991
46
44
242
2,938
12,142
95
88
38
39
246
2,753
11,192
88
91
41
36
233
2,499
10,724
82
85
41
35
212
1,933
9,119
71
84
47
29
162
1,842
11,367
69
88
42
29
128
1,504
11,746
53
68
39
30
100
1,085
10,853
42
69
46
25
106
1,301
12,274
47
69
62
35.7
4.2
100
49.3
9.6
63
35.3
7.3
59
27.4
5.9
44
15
1.7
42
15.9
4.3
54
17.8
4.3
45
20.2
4.3
1,921
124
53
5
2,700
133
49
5
117,431
436
110,859
410
2,212
176.9
63.8
12
94,358
378
2,214
186
64
12
72,387
354
2,431
202
71
14
72,953
341
2,399
202
71
14
78,023
307
2,334
220
74
14
75,470
289
2,152
227
55
12
66,617
278
1,652
97
1,652
95
1,654
94
1,652
87
1,652
83
1,656
86
1,656
87
1,664
86
3,340
3,627
3,309
3,245
2,787
2,389
1,928
1,758
39
Directors
Officers
W. H. Helmerich, III
Chairman of the Board
Hans Helmerich
President and Chief Executive Officer
George S. Dotson
Vice President,
President of Helmerich & Payne
International Drilling Co.
Douglas E. Fears
Vice President and
Chief Financial Officer
Steven R. Mackey
Vice President, Secretary,
and General Counsel
Steven R. Shaw
Vice President,
Exploration & Production
W. H. Helmerich, III
Chairman of the Board
Tulsa, Oklahoma
Hans Helmerich
President and Chief Executive Officer
Tulsa, Oklahoma
William L. Armstrong**
Chairman
Transland Financial Services, Inc.
Denver, Colorado
Glenn A. Cox*
President and Chief Operating Officer, Retired
Phillips Petroleum Company
Bartlesville, Oklahoma
George S. Dotson
Vice President,
President of Helmerich & Payne
International Drilling Co.
Tulsa, Oklahoma
L. F. Rooney, III*
Chief Executive Officer
Manhattan Construction Company
Tulsa, Oklahoma
Edward B. Rust, Jr.*
Chairman and Chief Executive Officer
State Farm Insurance Companies
Bloomington, Illinois
George A. Schaefer**
Chairman and Chief Executive Officer, Retired
Caterpillar Inc.
Peoria, Illinois
John D. Zeglis**
Chairman and Chief Executive Officer
AT&T Wireless Services
Basking Ridge, New Jersey
* Member, Audit Committee
** Member, Human Resources Committee
40