EXHIBIT 13
| Helmerich & Payne, Inc. |
| ANNUAL REPORT FOR FISCAL 2003 |
Helmerich & Payne, Inc.
Helmerich & Payne, Inc. is the holding Company for Helmerich & Payne International Drilling Co., an international drilling contractor with land and offshore platform operations in the United States, South America, Africa, and Europe. Holdings also include commercial real estate properties in the Tulsa, Oklahoma, area and an energy-weighted portfolio of publicly-traded securities valued at approximately $170 million as of September 30, 2003. At the end of 2002, the Company completed the spin-off of Cimarex Energy Co. to shareholders. Cimarex, the Company’s former exploration and production division, was merged with Key Production Company, Inc. and currently trades on the New York Stock Exchange under the symbol XEC.
FINANCIAL HIGHLIGHTS
Years Ended September 30,
2003
2002
(in thousands, except per share amounts)
$
515,284
$
551,879
17,873
53,706
17,873
63,517
0.35
1.07
0.35
1.26
0.32
0.305
246,301
312,064
1,415,835
1,227,313
1
President’s Letter
To the Co-owners of Helmerich & Payne, Inc.
It seems every year the oil and gas business plays an important role on the stage of political and economic events. Few years can match 2003 for the sheer number of headline stories. In the heart of the Middle East, Operation Iraqi Freedom brought the quick overthrow of Saddam Hussein. During the time leading up to the war, Venezuela sustained a crippling two-month nationwide strike, threatening an important source of U.S. crude oil. In the spring, record low natural gas inventories and declining production rates prompted Federal Reserve Chairman Alan Greenspan to warn of a potential natural gas shortage and the serious consequences it posed to economic recovery. Later in the summer, the Northeast sustained a sweeping electrical blackout that stranded 50 million customers.
With this backdrop, the President hoped to sign legislation representing the first serious effort in decades at shaping a national energy policy. Before failing by two votes to another Democratic filibuster, the energy bill had mushroomed to over a thousand pages and an estimated cost of some $100 billion, bearing only a weak resemblance to the President’s original request.
The energy bill represented an unworkable combination: too much pork and too little beef. Pork barrel spending included increased subsidies for ethanol and soybean based fuel mandates, add-ons like aid for an energy efficient shopping mall in Syracuse, and even money for a pet rainforest project in Iowa. While spending ballooned to more than three times the Administration’s stated limit, one of the President’s priorities, the approval for exploration in Alaska’s Arctic National Wildlife Refuge, was thrown overboard early in the Congressional
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negotiations. In the end, too little was done to streamline and open access to high potential natural gas exploratory plays on Federal lands, and to promote nuclear power, and to develop clean burning coal technology. All three are important components to a balanced U.S. energy supply.
What are the prospects for the passage of an energy bill during the upcoming election year?
Any attempt should speak clearly to the practical challenges of fueling the world’s largest economy. Lewis Lehrman finds that voice in his piece, “Energetic America,” where he argues for an energy policy that promotes a diverse supply base that is both affordable and dependable. He points out that we are in a time when effective economic and energy policies are indispensable to national security issues, and states, “Combined with President Bush’s supply-side tax policy, an unselfconscious supply-side energy and regulatory policy will lead to abundant and cheaper energy, growth of economic opportunity, and full employment.”
However future politics get sorted out, oil and gas will remain at the center of the energy picture for years to come. Your Company plays an important role in providing new supplies to help meet this growing demand. As we go forward, we look to the opportunities ahead.
| Sincerely, | ||
|
||
| Hans Helmerich | ||
| President | ||
| December 15, 2003 |
3
Contract Drilling Operations
The Company’s first full year as a stand-alone drilling contractor was accompanied by a number of unusual factors: high oil and natural gas prices, a second war in the Persian Gulf, and a major strike in Venezuela, which resulted in turmoil within PDVSA, the Company’s largest customer in South America. The Baker Hughes U.S. Land Rig Count increased by over 30 percent in fiscal 2003, but the journey was bumpy and cautious. The Company delivered 19 third generation FlexRigs* to the U.S. market in 2003, expanding its capacity in this segment by nearly one-third. One of the uncertainties ahead is the U.S. offshore platform market, which softened considerably in 2003. The Company’s South American markets also remain weak due in large part to socio-economic and political factors. During 2003, the Company introduced its first generation FlexRig into two new international markets.
U.S. Land Operations
On average, the Company worked 14 more rigs during the year than in 2002, but lower dayrates, combined with higher training and depreciation expenses associated with the FlexRig3 project, muted financial results for 2003 compared to 2002. At the close of the year, 68 out of 83 available rigs were working. The Company’s fleet of 43 FlexRigs and 11 highly mobile rigs maintained an average utilization of 95 percent during the year, while the remaining 29 conventional rigs had an average utilization rate of 58 percent. Demand continues to be weakest in the deep-drilling end of the business where soft rates are under increasing price competition. Out of the Company’s 16 deep-rated conventional rigs, 11 were idle at the close of the fiscal year. By contrast, the Company had only one idle
* The term “FlexRig” used throughout this Annual Report is a Company trademark Registered in the U.S. Patent and Trademark Office.
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rig out of the remaining 13 conventional rigs rated at 20,000 feet or less. The FlexRig, with its flexible depth capacity range of 8,000 to 18,000 feet, has shifted the Company’s fleet capability toward the larger medium-depth segment of the drilling market, and this is having a positive impact on the Company’s activity rate.
At the close of 2003, the Company had 27 FlexRig3s operating, and the results in the field continue to prove their value. Of the 173 wells completed by FlexRig3s this past year, better than two out of three have come in ahead of customer-estimated drilling times. The Company’s investment in employee screening, training, and team building for the FlexRig3 is also paying dividends. Eighteen months into the FlexRig3 project, the Company has achieved a retention rate of 78 percent on the initial training effort. Well-trained and stable crews have enabled the project to achieve outstanding field results, and more customers and their non-operating partners are seeing how FlexRigs can lower well costs, reduce well cycle times, and increase productivity. Throughout 2003, FlexRig3s were nearly 100 percent utilized and working at premium dayrates.
Overall, the U.S. land market appears to be in the early stages of a cyclical transition. Drilling services, as well as other oilfield services and supplies, typically gain more pricing power as supply and demand tighten because of reduced industry capacity. It is in this market phase that the distinct advantages of the FlexRig technology will be most apparent to customers as they begin to refocus on total project costs.
5
U.S. Offshore Operations
Activity in the offshore platform segment declined by almost one-third during 2003, with five of the Company’s 12 offshore platform rigs under contract in the Gulf of Mexico at year-end. The Company also operated one rig in the Gulf of Mexico and two rigs offshore California under management contracts during 2003. The overall profit margin in the offshore segment is likely to come under increasing pressure during the coming year as some of the working rigs are on long-term projects that have reached the full development stage and will likely alternate between operating rates and the lower standby rates. Out of the seven rigs that are idle in the Company’s fleet, six are capable of returning to work on short notice and the seventh will require shipyard maintenance. The Company retains a large share of the offshore platform market and has considerable design and construction experience in conventional, spar, and deep-water tension-leg platform rigs. The Company is well positioned to compete for any opportunities that emerge in the coming year; however, we expect that any recovery in the platform market will be slow due to long project lead times.
International Operations
An average of 12 rigs were fully employed in 2003, compared to 16 rigs in 2002. Ecuador remained the most active country with an average of seven rigs working, followed by Venezuela with an average of four rigs, and Colombia and Bolivia each with less than a full rig year of activity. Operations in Venezuela are improving as seven rigs were working shortly after the close of the fiscal year, and an eighth rig is expected to start work in the second quarter. Despite numerous challenges presented in Venezuela, we are encouraged by the recent increase in activity.
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Venezuela still has promising growth potential, and the Company has the best-equipped and maintained rig fleet in the country.
Two first generation FlexRigs were committed to short-term international contracts in 2003. The first is working for a U.S. based independent in Hungary where, at year-end, it was drilling its third well after a smooth, incident-free start-up. Having previously used a FlexRig in U.S. operations, the customer desired to see the technology, versatility, and mobility of these rigs employed in an important international project. The second FlexRig was deployed for a major international operator under a multi-well contract in the central African nation of Chad. This project is scheduled to begin drilling in December 2003.
Outlook
Looking to 2004 and beyond, we see significant opportunities for a growing international business and believe the Company brings a distinctive combination of experience and innovation to this market. The FlexRig will play an important role in capturing this potential, as we endeavor to introduce this unique technology to international markets. While this transition year was not what we had hoped for financially, the Company improved operating performance, expanded its capacity, and is well positioned in high potential markets to participate in future opportunities. The most critical dimension of quality is our performance in the area of health, safety, and the environment (HSE) and, during 2003, the Company logged one of its best years on record. After the close of the fiscal year, two of our largest customers, ExxonMobil and Royal Dutch Shell, separately recognized the Company’s land and offshore operations for leadership and excellence in HSE.
7
Financial & Operating Review
8
9
Management’s Discussion & Analysis of Results of Operations and
Financial Condition
RISK FACTORS AND FORWARD-LOOKING STATEMENTS
The following discussion should be read in conjunction with the consolidated
financial statements and related notes included elsewhere herein. The
Company’s future operating results may be affected by various trends and
factors, which are beyond the Company’s control. These include, among other
factors, fluctuations in oil and natural gas prices, expiration or termination
of drilling contracts, currency exchange gains and losses, changes in general
economic conditions, rapid or unexpected changes in technologies, risks of
foreign operations, uninsured risks, and uncertain business conditions that
affect the Company’s businesses. Accordingly, past results and trends should
not be used by investors to anticipate future results or trends.
With the exception of historical information, the matters discussed in
Management’s Discussion & Analysis of Results of Operations and Financial
Condition include forward-looking statements. These forward-looking statements
are based on various assumptions. The Company cautions that, while it believes
such assumptions to be reasonable and makes them in good faith, assumed facts
almost always vary from actual results. The differences between assumed facts
and actual results can be material. The Company is including this cautionary
statement to take advantage of the “safe harbor” provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf
of, the Company. The factors identified in this cautionary statement and those
factors discussed under Risk Factors beginning on page 5 of the Company’s
Report on Form 10-K for fiscal 2003 are important factors (but not necessarily all important factors)
that could cause actual results to differ materially from those expressed in
any forward-looking statement made by, or on behalf of, the Company.
10
SPIN-OFF AND MERGER TRANSACTIONS
On September 30, 2002, Helmerich & Payne, Inc. completed its distribution of
100 percent of the common stock of Cimarex Energy Co. to the Company’s
shareholders and the merger of Key Production Company, Inc. into a subsidiary
of Cimarex making Key a wholly owned subsidiary of Cimarex. The Cimarex Energy
Co. stock distribution was recorded as a dividend and resulted in a decrease to
consolidated stockholders’ equity of approximately $152.2 million. The Company
and its subsidiaries continue to own and operate contract drilling and real
estate businesses, while Cimarex Energy Co. is a separate, publicly traded
company that owns and operates an exploration and production business. The
Company does not own any common stock of Cimarex Energy Co. (See note 2 of the
Consolidated Financial Statements for complete description of the transaction.)
As a result of the transaction, the Company is reporting the results of its
former exploration and production division (Cimarex Energy Co.) as
discontinued operations.
RESULTS OF OPERATIONS
All per share amounts included in the Results of Operations discussion are
stated on a diluted basis. Helmerich & Payne, Inc.’s net income for 2003 was
$17,873,000 ($0.35 per share), compared with net income of $63,517,000 ($1.26
per share) in 2002, and $144,254,000 ($2.84 per share) in 2001. Included in
net income was income from discontinued operations of $9,811,000 ($0.19 per
share) in 2002, and $63,787,000 ($1.26 per share) in 2001. Also included in the
Company’s net income, but not related to its operations, were after-tax gains
from the sale of investment securities of $3,346,000 ($0.07 per
share) in 2003, $15,206,000 ($0.30 per share) in 2002, and $691,000 ($0.01 per
share)
11
in 2001. Also included in net income is the Company’s portion of income or loss
from its equity affiliates, Atwood Oceanics, Inc. and a 50-50 joint venture
with Atwood called Atwood Oceanics West Tuna Pty. Ltd. (dissolved in 2003).
From equity affiliates, the Company recorded a loss of $0.03 per share in 2003,
and net income of $0.06 and $0.04 per share in 2002 and 2001, respectively.
Consolidated revenues were $515,284,000 in 2003, $551,879,000 in 2002, and
$542,571,000 in 2001. From 2001 to 2003 revenues attributable to contract
drilling operations fell slightly each year. However, total revenues increased
from 2001 to 2002 due to a larger gain realized on the sale of a portion of the
Company’s equity portfolio. U.S. land revenues rose steadily from 2001 to
2003, while international drilling revenues declined significantly during the
same period. Although U.S. offshore platform revenues were relatively flat
from 2001 to 2002, there was a drop of approximately 15 percent in offshore
platform revenues from 2002 to 2003. Revenue reductions in the offshore
platform business were mainly due to a drop in rig utilization to 51 percent in
2003, from 83 percent in 2002, and 98 percent in 2001. The increase in U.S.
land revenues was fueled by the Company’s increasing rig fleet due to the
construction of FlexRigs over the three-year period. The average number of
U.S. land rigs available was 76 in 2003, 57 in 2002, and 42 in 2001. Although
rig availability increased, rig utilizations fell for the Company’s U.S. land
rig fleet to 81 percent in 2003, compared with 84 percent in 2002, and 97
percent in 2001. International rig revenues declined as rig utilizations in
that sector fell to 39 percent in 2003, from 51 percent in 2002, and 56 percent
in 2001. The Company’s international rig utilization was impacted by
significant
reductions in activity in Venezuela and Colombia since 2001. Cutbacks in
drilling budgets for the government-
12
owned oil company, PDVSA, reduced drilling in Venezuela. In Colombia,
completion of development of a customer’s major oilfield has dramatically
reduced drilling activity there.
Revenues from investments were $7,953,000 in 2003, $28,076,000 in 2002, and
$10,967,000 in 2001. Included in revenues was the aggregate of pre-tax gains,
losses, and write-downs relating to the Company’s portfolio of equity
securities which were $5,529,000 in 2003, $24,820,000 in 2002, and $1,189,000
in 2001. Interest and dividend income fell in each year due to reduced cash
positions, lower interest rates, and a reduction in the Company’s equity
portfolio. Total interest and dividend income was $2,467,000 in 2003,
$3,624,000 in 2002, and $9,128,000 in 2001.
Direct operating costs in 2003 were $345,537,000 or 68 percent of operating
revenues, compared with $361,669,000 or 69 percent of operating revenues in
2002, and $330,181,000 or 62 percent of operating revenues in 2001. Direct
operating costs were lower as a percentage of revenues in 2001, primarily due
to the higher average revenue per day and lower daily direct operating costs
per day during 2001 in the U.S. land rig segment. Industry rig activity was
relatively high in 2001, resulting in higher dayrates for the Company.
Depreciation expense was $82,513,000 in 2003, $61,447,000 in 2002, and
$49,532,000 in 2001. Depreciation rose significantly over the two-year period
as the Company placed into service 13 new rigs in 2002, and 19 new rigs in
2003. The Company anticipates depreciation expense to increase again during
2004, as a full year of depreciation expense is incurred
on rigs placed into service in 2003, and as new rigs are constructed and
employed in the field.
13
The Company’s methodology of reporting business segments and general and
administrative expenses has been changed in 2003. This change was driven by
last year’s spin-off of our Exploration and Production Company and to better
reflect the way the Company manages its contract drilling businesses.
The number of contract drilling business segments reported have increased to
three to reflect the Company’s U.S. offshore platform operations separately
from the U.S. land rig operations. Formerly, the combined U.S. segments were
reported as one segment. It is important to note that total operating profit
for U.S. operations and the international contract drilling segment has not
changed. U.S. Land and Offshore Platform segments have simply been separated.
Expenses within the Company’s contract drilling business segments have been
broken out to delineate direct operating costs from associated general and
administrative costs. Formerly, both costs were included in operating costs on
the consolidated statements of income. The associated general and
administrative costs of the contract drilling segments have been reclassified
to general and administrative expense on the consolidated statements of income.
These general and administrative costs are still included in the applicable
contract drilling segment. No other numbers on the consolidated statements of
income were changed or affected by this reclassification.
With the reclassifications, general and administrative expenses totaled
$41,003,000 for 2003, $36,563,000 for 2002, and $28,180,000 for 2001. The 30
percent increase from 2001 to 2002 was primarily the
14
result of increases in employee benefits relating to pension, medical
insurance, and 401(k) matching. Employee salaries and bonuses also contributed
to the increase, as well as increases in property and casualty insurance costs.
With the construction of the FlexRigs, training expenses were also a
contributor to the increase from 2001 to 2002. General and administrative
expenses rose again from 2002 to 2003 due to additional increases in pension
and medical insurance expense, along with increases in property and casualty
insurance costs.
Interest expense rose to $12,289,000 in 2003, compared with $980,000 in 2002,
and $1,701,000 in 2001. The Company issued a total of $200,000,000 of
intermediate-term debt, half of which was placed just prior to the end of
fiscal year 2002, and the other half placed at the very beginning of fiscal
year 2003. Additionally, the Company also drew on its bank line of credit
during 2003, with $30,000,000 drawn at the end of the year.
The provision for income taxes totaled $14,649,000 in 2003, $40,573,000 in
2002, and $54,689,000 in 2001. Effective income tax rates on income from
continuing operations were 43 percent in 2003, 44 percent in 2002, and 41
percent in 2001. The increase in effective tax rates from 2001 to 2002 was a
result of currency fluctuations, primarily in Venezuela, resulting in
additional taxes for inflationary gains and monetary corrections in 2002.
There was less of such an effect in 2003, but international income at higher
effective tax rates combined with the impact of state income taxes, kept the
overall Company tax rate at a relatively high level.
15
COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2003 AND 2002
Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses.
The Company’s operating profit in its U.S. land rig operations fell by 39
percent from 2002 to 2003, despite the fact that commodity prices were very
strong during the year. Historically high crude oil and natural gas prices,
and an increasing industry rig count in the United States were all strong
signals for an up cycle that could benefit oil service and contract drilling
companies. However, in spite of increasing rig activity, average dayrates and
margins per rig day fell during the year. Even with higher industry rig
counts, the additional capacity added by companies like Helmerich & Payne,
along with intense rig-on-rig price competition, delayed improvements in
dayrates and margins. More specifically with Helmerich & Payne, 2002 dayrates
were aided by the remaining term left on some of the contracts for work
relating to FlexRig2s that were completed and commenced work during 2001.
Those relatively high dayrates and
16
margins did not continue at those levels during 2003 after contracts expired.
The Company’s increase in rig capacity was brought about by its FlexRig3
construction program that began during 2002 and extended through 2003. During
2003, 19 FlexRig3s were completed and put into service. Two first generation
FlexRig’s were sent overseas for work in Hungary and Chad. As a result of the
construction program, the Company’s investment in drilling equipment rose
significantly, thereby resulting in an increase in depreciation expense.
Although the Company will have more rigs available for service next year, and
although industry fundamentals are positive going in to 2004, a drop in
dayrates or rig utilization could cause U.S. land rig operating profit to
decrease next year.
COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2003 AND 2002
Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses
and exclude the effects of offshore platform management contracts.
17
During the year, the Company continued to experience a reduction in activity
days and rig utilization in its U.S. offshore platform rig operations. Total
revenue and revenue per day during 2003 were aided by the recognition of
revenue due to early termination of contracts. During the fourth quarter of
2003, one platform rig was stacked and two rigs that were working at full
dayrate were changed to standby status, thereby likely causing a reduction of
the first quarter 2004 operating profit for the U.S. offshore rig segment of
approximately 50 percent from that of the fourth quarter of 2003. Capital
expenditures were reduced dramatically due to the fact that there were no new
platform rigs under construction during 2003, whereas two new platform rigs
were completed during 2002. It is anticipated that during 2004, the U.S.
offshore platform market will continue to be soft, unless and until commodity
pricing or other circumstances significantly increase demand for platform rigs.
COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2003 AND 2002
Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses
and exclude the effects of offshore platform management contracts.
18
Rig activity, revenues, and operating profit in the Company’s international
operations declined from 2002 to 2003. The general softness in the
international markets was broad based and resulted in lower utilizations in
each of the countries in which the Company operated during the 2002-2003
period. The Company’s Venezuelan operations, where the largest number of
Company international rigs are located, were also hampered by an attempted
coup, which resulted in a strike by workers at PDVSA, the government-owned oil
company.
During 2002, the Company recorded an estimated devaluation loss totaling
$1,200,000 in Argentina when that country experienced a dramatic economic
collapse. As a result of the collapse, the government stopped the outflow of
dollars from the country and required that former dollar obligations be paid in
Argentina pesos. During 2003, the Company was able to reduce its 2002
estimated loss by approximately $980,000 relating to the Argentina currency
devaluation.
In Venezuela, approximately 60 percent of the Company’s billings are in U.S.
dollars and 40 percent are in bolivars, the local currency. As a result, the
Company is exposed to risk of currency devaluation in Venezuela. Devaluation
losses for Venezuelan operations totaled $624,000 in 2003 and $4,393,000 in
2002. The Company anticipates devaluation losses in Venezuela during 2004, but
is unable to predict the extent of the devaluation. If 2004 rig activity
levels are similar to 2003, and if a 25 percent to 50 percent devaluation would
occur, the Company could experience potential devaluation losses ranging from
approximately $3,200,000 to $5,100,000. (See MD&A section entitled Foreign
Currency Exchange Rate
Risk for important details regarding potential devaluation losses.)
19
In addition to potential devaluation, next year’s average dayrate and profit
margin per rig, as well as rig utilizations are difficult to predict and, while
not expected to decline during 2004, are subject to unpredictable markets that
could produce significant volatility.
COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2003 AND 2002
Operating profit increased by approximately 30 percent from 2002 to 2003 in the
Company’s Real Estate division, primarily due to the sale of approximately 15
acres of raw land from the Company’s Southpark investment. Pre-tax profit from
the sale of land was approximately $2.2 million. Depreciation expense
increased in 2003 due to the acceleration of depreciation on the Company’s
headquarters building, which will be razed in 2004. Overall combined occupancy
and resulting revenues generated from all the other real estate properties did
not materially fluctuate from 2002 to 2003.
20
COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2002 AND 2001
Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses.
U.S. land operating profit declined by 55 percent from 2001 to 2002 as overall
industry rig counts declined from a cyclical high brought on by a spike in
natural gas prices during 2001. The significant reduction in industry rig
counts that followed during 2002 brought about lower dayrates, rig margins, and
rig utilizations compared with 2001 levels. Although utilization rates declined
during 2002, activity days increased due to an additional 17 rigs put into
service in the U.S. land rig market. This increase was due to FlexRig
construction and movement of land rigs from South American operations to the
U.S. During 2002, the Company completed the final five rigs of its 12-rig
FlexRig2 program commenced in 2001. It also placed eight FlexRig3s into
service and added four more rigs to the U.S. fleet that were moved from South
American operations. Capital spending in U.S. land rig operations
21
increased as the Company embarked on its FlexRig3, 25-rig construction project.
As a result of capital expenditures for U.S. land operations of $236.3 million
in 2002, compared with $136.7 million in 2001, depreciation expense rose by
approximately 58 percent during 2002.
COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2002 AND 2001
Operating statistics for per day revenue, expense and margin do not include reimbursements of “out-of-pocket” expenses
and exclude the effects of offshore platform management contracts.
Two new offshore platform rigs were completed and placed in service
during 2002 at high dayrates, but with short-term contracts. As a result,
average rig revenue per day and average margins per day improved from
2001 to 2002. More than offsetting this improvement was a decline in
activity days of eight percent, the beginning signs of an overall reduction
in that market that continued into 2003.
22
COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2002 AND 2001
Operating statistics for per day revenue, expense and margin do not include
reimbursements of “out-of-pocket” expenses and exclude the effects of offshore
platform management contracts.
Rig utilization, total activity days, and total revenues declined from 2001 to
2002, resulting in operating profit declining by approximately 54 percent. The
most significant declines in activity and profitability were in Company
operations located in Colombia and Argentina. Colombia’s rig utilizations fell
from 69 percent during 2001 to 31 percent during 2002. Additionally, the
number of rigs available in Colombia fell from seven during the first quarter
of 2001 to three by the end of 2001. Those four rigs were moved to the United
States. Accordingly, profitability in Colombia declined sharply during 2002.
Operating profit for Company operations in Venezuela and Argentina also
declined during 2002. Devaluation losses in Venezuela were $4,393,000 in 2002,
and $796,000 in 2001. (See MD&A section entitled Foreign Currency Exchange
Risk for more detail regarding potential devaluation losses.)
23
COMPARISON OF THE YEARS ENDED SEPTEMBER 30, 2002 AND 2001
Revenues and operating profit declined from 2001 to 2002 in the Company’s Real
Estate division, due to a sale of raw land which resulted in approximately $2
million of operating profit during 2001. Depreciation was higher in 2001 due to
the acceleration of depreciation for a building that was razed during 2002.
Earnings from ongoing leasing operations were up only slightly from 2001 to
2002.
CRITICAL ACCOUNTING POLICIES
The Company’s consolidated financial statements are impacted by the accounting
policies used and the estimates and assumptions made by management during their
preparation. The following is a discussion of the critical accounting policies
related to property, plant and equipment, impairment of long-lived assets,
self-insurance accruals, and revenue recognition. Other significant accounting
policies are summarized in Note 1 in the notes to the consolidated financial
statements.
Property, plant and equipment, including renewals and betterments, are stated
at cost, while maintenance and repairs are expensed currently. Interest costs
applicable to the construction of qualifying assets are capitalized as a
component of the cost of such assets. The Company provides for the depreciation
of property, plant and equipment using the straight-line method over the
estimated useful lives of the assets.
24
Upon retirement or other disposal of fixed assets, the cost and related
accumulated depreciation are removed from the respective accounts and any gains
or losses are recorded in results of operations.
The Company reviews its long-lived assets, including property and equipment,
for impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. An impairment loss exists
when estimated undiscounted cash flows expected to result from the use of the
asset and its eventual disposition are less than its carrying amount. Any
impairment loss recognized represents the excess of the asset’s carrying value
as compared to its estimated fair value, which is determined based on the
present value of estimated cash flows from the asset and appraisals or sales
prices of comparable assets. There were no long-lived asset impairment losses
in the Company’s continuing operations during the years ended September 30,
2003, 2002, and 2001. However, should industry market conditions deteriorate
from those existing currently, impairment losses could be recorded in the
future. All of the Company’s drilling rigs are transportable and are therefore
not limited to one area or country. Drilling rigs can be moved from countries
where demand is low to countries experiencing high demand for drilling
services. When making determinations of location for drilling rigs, the
Company considers both long and short-term views of demand and other reasonable
business considerations.
The Company is self-insured or maintains high deductibles for certain losses
relating to worker’s compensation, general, product, and auto liabilities.
Generally, deductibles are $2 million per occurrence on claims that fall under
these
coverages. Insurance is also purchased on rig properties and generally
deductibles are $1 million per occurrence.
25
Excess insurance is purchased over these coverages to limit the Company’s
exposure to catastrophic claims, but there can be no assurance that such
coverage will respond or be adequate in all circumstances. Retained losses are
estimated and accrued based upon our estimates of the aggregate liability for
claims incurred, and using the Company’s historical loss experience and
estimation methods that are believed to be reliable.
Revenues and costs on daywork contracts are recognized daily as the work
progresses. For certain contracts, we receive lump-sum payments for the
mobilization of rigs and other drilling equipment. Revenues earned, net of
direct costs incurred for the mobilization, are deferred and recognized over
the term of the related drilling contract. Other lump-sum payments received
from customers relating to specific contracts are deferred and amortized to
income as services are performed. Costs incurred to relocate rigs and other
drilling equipment to areas in which a contract has not been secured are
expensed as incurred.
LIQUIDITY AND CAPITAL RESOURCES
The Company’s capital spending for continuing operations was $246,301,000 for
2003, $312,064,000 in 2002, and $184,668,000 in 2001. Net cash provided from
operating activities for those same time periods were $96,504,000 in 2003,
$151,774,000 in 2002, and $127,435,000 in 2001. In addition to the net cash
provided by operating activities, the
Company also generated net proceeds from the sale of portfolio securities of
$18,215,000 in 2003, $47,146,000 in 2002, and $24,438,000 in 2001.
During 2000, the Company announced a program (FlexRig2 program) under which it
would construct 12 new FlexRigs at an approximate cost
26
of between $7.5 and $8.25 million each. During 2001, the Company completed
construction on seven of those 12 rigs. Additionally, the Company announced in
2001 that it would embark on another construction project (FlexRig3 program) to
build an additional 25 FlexRigs at an approximate cost of $11 million each.
During 2002, the Company completed the remaining five rigs in the FlexRig2
program and the first eight rigs in the FlexRig3 program. During 2003, the
remaining 17 rigs originally planned in the FlexRig3 program were completed.
Another seven FlexRig3s were scheduled for construction, two of which were
completed by the end of fiscal 2003, and five are scheduled to be completed by
March, 2004.
The Company expects to fund its 2004 capital spending of approximately
$100,000,000 with internally generated cash flows, its bank line of credit
and/or from funds generated by the sale of stock from its investment portfolio.
In August 2002, the Company entered into a $200 million intermediate-term
unsecured debt obligation with staged maturities from five to 12 years and a
weighted average interest rate of 6.31 percent. Funding of the notes occurred
on August 15, 2002, and October 15, 2002, in equal amounts of $100 million.
The terms of the debt obligations require the Company to maintain a minimum
ratio of debt to total capitalization. Proceeds from
the intermediate-term debt were used to repay the balance of the Company’s
outstanding debt of $50 million in September 2002, help fund the Company’s rig
construction program and for other general corporate purposes.
On September 30, 2003, the Company had a committed unsecured line of credit
totaling $125 million, with short-term loans totaling $30 million and letters
of credit totaling $13.7 million outstanding against the line.
27
The line of credit matures in July 2004 and bears interest of LIBOR + .87
percent to 1.125 percent depending on certain financial ratios of the Company.
The Company must maintain certain financial ratios including debt to total
capitalization and debt to earnings before interest, taxes, depreciation, and
amortization, and maintain certain levels of liquidity and tangible net worth.
The strength of the Company’s balance sheet is substantial, with current ratios
for September 30, 2003, and 2002 at 2.2 and 2.5, respectively, and with debt to
total capitalization of 18 percent and 10 percent, respectively. Additionally,
the Company manages a large portfolio of marketable securities that, at the
close of 2003, had a market value of $169,546,000. The Company’s investments in
Atwood Oceanics, Inc., Schlumberger, Ltd., and ConocoPhillips made up almost 90
percent of the portfolio’s market value on September 30, 2003. The value of
the portfolio is subject to fluctuation in the market and may vary considerably
over time. Excluding the Company’s equity-method investments, the portfolio is
recorded at fair value on the Company’s balance sheet for each reporting
period. During 2003, the Company paid a dividend
of $0.32 per share, or a total of $16,015,268, representing the 31st
consecutive year of dividend increases.
STOCK PORTFOLIO HELD BY THE COMPANY
28
MATERIAL COMMITMENTS
The Company has no off balance sheet arrangements, as defined by SEC rules. The
Company’s contractual obligations as of September 30, 2003, including payments
due by year are as follows (in thousands):
An actuarial study of the Company’s pension plan projects that no funding will
be required in fiscal years 2004 or 2005. After 2005, funding requirements, if
any, will be subject to returns on plan assets and other external factors.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Foreign Currency Exchange Rate Risk.
The Company has international operations
in Hungary, Chad, and in several South American countries, as well as a labor
contract for work off the coast of Equatorial Guinea. With the exception of
Venezuela, the Company’s exposure to currency valuation losses is usually
minimal due to the fact that virtually all billings and receipts in other
countries are in U.S. dollars. Even though the Company’s contract with its
customers in Argentina was in U.S. dollars, the Company recorded a devaluation
loss as Argentina experienced a dramatic economic collapse during 2002. As a
result of the economic collapse, the government stopped the outflow of dollars
from the country and required that former dollar obligations be paid in
Argentina pesos,
29
resulting in the Company recording an estimated loss of $1,200,000
in 2002. The Company was able to reduce this estimated loss by
approximately $980,000 during 2003. At the present time, the
Company has two rigs located in Argentina, one of which will begin
working during early 2004.
The Company is exposed to risks of currency devaluation in Venezuela
primarily as a result of bolivar receivable balances and bolivar cash
balances. In Venezuela, while approximately 60 percent of the Company’s
invoice billings to the Venezuelan state oil company, PDVSA, are in
U.S. dollars and 40 percent are in the local currency, the bolivar, PDVSA
typically pays all amounts owed in bolivars. The Company, historically,
has usually been able to convert the bolivars received in payment of
the dollar-based billings into dollars in a timely manner and thus avoid,
in large measure, devaluation losses pertaining to these dollar-based
invoices. In January 2003, the Venezuelan government put into effect
exchange controls that fixed the exchange rate at 1600 Bolivars to one
U.S. dollar and also prohibited the Company, as well as other companies,
from converting the bolivar into U.S. dollars through the central bank.
As a result of these exchange controls, the Company has been unable
since January 2003 to convert its bolivar cash balances into U.S. dollars.
As of September 30, 2003, the Company’s bolivar balance was approximately
14 billion bolivars or approximately $8.8 million. Historically, the
Company has kept bolivar cash balances at necessary minimum levels
to fund local operating costs.
As part of the exchange controls regulation, the Venezuelan government
provided a mechanism by which companies could request conversion
of bolivars into U.S. dollars. In compliance with such regulations, the
30
Company on October 1, 2003, submitted a request to the Venezuelan government
seeking permission to dividend earnings, which effectively will convert 14
billion bolivars into approximately $8.8 million. The Company is unable to
predict if or when this request will be approved.
From August of 2002 to August of 2003, there was a 13 percent devaluation of
the bolivar. As a result, the Company experienced a $624,000 devaluation loss
for 2003. This 13 percent devaluation loss may not be reflective of the actual
potential for future devaluation losses because of the exchange controls that
are currently in place. While the Company is unable to predict future
devaluation in Venezuela, if fiscal 2004 activity levels are similar to fiscal
2003 and if a 25 percent to 50 percent devaluation should occur, the Company
could experience potential currency devaluation losses ranging from
approximately $3,200,000 to $5,100,000.
In late August 2003, the Venezuelan state petroleum company agreed, on a
prospective basis, to pay a portion of the Company’s dollar-based invoices in
U.S. dollars. While this is a positive development in light of the existing
exchange controls, there is no guarantee as to how long this arrangement will
continue. Were this agreement to end, the Company would revert back to
receiving these payments in bolivars and thus increase bolivar cash balances
and exposure to devaluation.
Commodity Price Risk.
The demand for contract drilling services is a result of
exploration and production companies spending money to explore and develop
drilling prospects in
search for crude oil and natural gas. Their appetite for such spending is
driven by their cash flow and financial strength, which is very dependent,
among other things, on crude oil and natural gas commodity prices. Crude oil
31
prices are determined by a number of factors including supply and
demand, worldwide economic conditions, and geopolitical factors.
Crude oil and natural gas prices have been volatile and very difficult
to predict. This difficulty has led many exploration and production
companies to base their capital spending on much more conservative
estimates of commodity prices. As a result, demand for contract
drilling services is not always purely a function of the movement of
commodity prices.
Interest Rate Risk.
The Company’s interest rate risk exposure results primarily
from short-term rates, mainly LIBOR-based on borrowings from its commercial
banks. To reduce the impact of fluctuations in interest rates, the Company
maintains a portion of its total debt portfolio in fixed-rate debt. On
September 30, 2003, the amount of the Company’s fixed-rate debt was
approximately 87 percent of total debt. In the past, the Company has entered
into financial instruments such as interest rate swaps and may consider this
and other financial instruments in the future to manage the portfolio mix
between fixed and floating rate debt and to mitigate the impact of changes in
interest rates based on management’s assessment of future interest rates,
volatility of the yield curve, and the Company’s ability to access the capital
markets in a timely manner.
Based on the outstanding borrowings under variable-rate debt instruments on
September 30, 2003, a change in the average interest rate of 100 basis points
would result in a change in net income and cash flows before income taxes on an
annual basis of approximately $0.2 million and $0.3 million, respectively.
32
The following tables provide information as of September 30, 2003 and 2002
about the Company’s interest rate risk sensitive instruments:
INTEREST RATE RISK
(dollars in thousands)
INTEREST RATE RISK
(dollars in thousands)
Equity Price Risk.
On September 30, 2003, the Company owned stocks in other
publicly held companies with a total market value of $169,546,000. These
securities are subject to a wide variety and number of market-related risks
that could substantially reduce or increase the market value of the Company’s
holdings. Except for the Company’s holdings in its equity affiliate, Atwood
Oceanics, Inc., the portfolio is recorded at fair value on its balance sheet
with changes in unrealized after-tax value reflected in the equity section of
its balance sheet. Any reduction in market value would have an impact on the
Company’s debt ratio and financial strength. The total market value of the
portfolio of securities was $175,668,000 at September 30, 2002.
33
Report of Independent Auditors
The Board of Directors and Shareholders
We have audited the accompanying consolidated balance sheets of Helmerich &
Payne, Inc. as of September 30, 2003 and 2002, and the related consolidated
statements of income, shareholders’ equity, and cash flows for each of the
three years in the period ended September 30, 2003. These financial statements
are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Helmerich &
Payne, Inc. at September 30, 2003 and 2002, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
September 30, 2003, in conformity with accounting principles generally accepted
in the United States.
ERNST & YOUNG LLP
Tulsa, Oklahoma
34
Consolidated Statements of Income
The accompanying notes are an integral part of these statements.
35
Consolidated Balance Sheets
ASSETS
The accompanying notes are an integral part of these statements.
36
LIABILITIES AND SHAREHOLDERS’ EQUITY
The accompanying notes are an integral part of these statements.
37
Consolidated Statements of Shareholders’ Equity
[Additional columns below]
[Continued from above table, first column(s) repeated]
The accompanying notes are an integral part of these statements.
38
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these statements.
39
Notes to Consolidated Financial Statements
September 30, 2003, 2002 and 2001
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Helmerich &
Payne, Inc. (the Company), and all of its wholly-owned subsidiaries. Fiscal
years of the Company’s foreign consolidated operations end on August 31 to
facilitate reporting of consolidated results.
BASIS OF PRESENTATION
On September 30, 2002, the Company distributed 100 percent of the common stock
of Cimarex Energy Co. to the Company’s shareholders. Cimarex Energy Co. held
the Company’s exploration and production business and has been accounted for as
discontinued operations in the accompanying consolidated financial statements.
Unless indicated otherwise, the information in the notes to consolidated
financial statements relates to the continuing operations of the Company (see
Note 2).
As described below, the Company increased the number of business segments it is
reporting and how it classifies certain general and administrative expenses in
2003. These changes were driven by the new organization of the Company as a
result of last year’s spin-off of the exploration and production business and
to better reflect the way the Company now manages its contract drilling
businesses. All prior periods reflect these changes.
The number of contract drilling business segments reported have increased to
three to reflect the Company’s U.S. Offshore Platform operations separately
from the U.S. Land operations. Formerly, the combined U.S. segments were
reported as one segment. Total operating profit for U.S. operations and the
International contract drilling segment has not changed. Prior year segment
disclosures have been changed to reflect the increased number of reported
segments for all periods presented (see Note 15).
General and administrative expenses within the Company’s contract drilling
business segments have been reclassified to delineate direct operating costs
from associated general and administrative costs. Formerly, both costs were
included in operating costs on the consolidated statements of income. The
associated general and administrative costs of the contract drilling segments
of $15,353,000, $16,172,000, and $11,553,000 for 2003, 2002 and 2001,
respectively have been reclassified to general and administrative expense on
the consolidated statements of income for all periods presented. General and
administrative costs within the contract drilling segments continue to be
included in segment operating profit. No other amounts on the consolidated
statements of income were changed or affected by this reclassification.
Prior year amounts for Investments and Other Assets have been reclassified to
conform to current year classification.
Included in the Company’s operating revenues for the fiscal year ended
September 30, 2003 are reimbursements for “out-of-pocket” expenses of $31.0
million. Previously, the Company recognized reimbursements received as a
reduction to the related operating costs. Emerging Issues Task Force (EITF)
No. 01-14, “Income Statement Characterization of Reimbursements Received for
Out of Pocket Expenses Incurred” requires that reimbursements received for
“out-of-pocket” expenses be included in operating revenues. The effect of EITF
01-14 resulted in a reclassification to fiscal year 2002 and 2001, that
increased operating revenues and direct operating costs by $41.0 million and
$33.3 million, respectively. These reclassifications had no impact on net
income.
40
TRANSLATION OF FOREIGN CURRENCIES
The Company has determined that the functional currency for its foreign
subsidiaries is the U.S. dollar. Foreign currency transaction gain (losses)
were $422,000, ($5,473,000) and ($494,000), for 2003, 2002 and 2001,
respectively. These amounts are included in direct operating costs.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the amounts reported in the consolidated financial statements and
accompanying notes. Actual results could differ from those estimates.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at cost less accumulated depreciation.
Substantially all property, plant and equipment are depreciated using the
straight-line method based on the estimated useful lives of the assets
(contract drilling equipment, 4-15 years; real estate buildings and equipment,
10-50 years; and other, 3-33 years). The Company charges the cost of
maintenance and repairs to direct operating cost, while betterments and
refurbishments are capitalized.
VALUATION OF LONG-LIVED ASSETS
The Company periodically evaluates the carrying value of long-lived assets to
be held and used, including intangible assets, when events or circumstances
warrant such a review. The Company recognizes impairment losses for long-lived
assets used in operations when indicators of impairment are present and the
undiscounted cash flows expected to be generated by the asset are not
sufficient to recover the carrying amount of the asset. On October 1, 2002 the
Company adopted Statement of Financial Accounting Standard (“SFAS”) No. 144
“Accounting for the Impairment or Disposal of Long-Lived Assets,” which did not
impact the Company’s results of operations or financial position.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents consist of cash in banks and investments readily
convertible into cash which mature within three months from the date of
purchase.
Currently, the Company is unable to convert bolivar cash balances in Venezuela
into U.S. dollars or to transfer any such funds out of Venezuela as a result of
exchange controls put in place by the Venezuelan government. (See Note 12 for
further discussion.)
INVENTORIES AND SUPPLIES
Inventory and supplies are primarily replacement parts and supplies held for
use in our drilling operations. Inventory and supplies are valued at the lower
of cost (moving average or actual) or market value.
41
DRILLING REVENUES
Contract drilling revenues are comprised primarily of daywork drilling
contracts for which the related revenues and
expenses are recognized as work progresses. For certain contracts, the Company
receives lump-sum payments
for the mobilization of rigs and other drilling equipment. Revenues earned,
net of direct costs incurred for the
mobilization, are deferred and recognized over the term of the related drilling
contract. Costs incurred to relocate
rigs and other drilling equipment to areas in which a contract has not been
secured are expensed as incurred.
INVESTMENTS
The cost of securities used in determining realized gains and losses is based
on the average cost basis of the
security sold. Net income in 2002 and 2001 includes a loss of approximately
$0.5 million, $0.01 per share on
a diluted basis, and $1.4 million, $0.03 per share on a diluted basis,
respectively, resulting from the Company’s
assessment that the decline in market value of certain available-for-sale
securities below their financial cost
basis was other than temporary. There were no losses in 2003 as the result of
a decline in market values
that were considered other than temporary by the Company.
Investments in companies owned from 20 to 50 percent are accounted for using
the equity method with the
Company recognizing its proportionate share of the income or loss of each
investee. The Company owned
approximately 21.7% of Atwood Oceanics, Inc. (Atwood) at both September 30,
2003 and 2002. The quoted
market value of the Company’s investment was $71,970,000 and $87,750,000 at
September 30, 2003 and
2002, respectively. Retained earnings at September 30, 2003 includes
approximately $28,306,000 of
undistributed earnings of Atwood.
Summarized financial information of Atwood is as follows:
42
INCOME TAXES
Deferred income taxes are computed using the liability method and are provided
on all temporary differences
between the financial basis and the tax basis of the Company’s assets and
liabilities.
OTHER POST EMPLOYMENT BENEFITS
The Company sponsors a health care plan that provides post retirement medical
benefits to retired employees.
Employees who retire after November 1, 1992 and elect to participate in the
plan pay the entire estimated
cost of such benefits.
The Company has accrued a liability for estimated workers compensation claims
incurred. The liability for other
benefits to former or inactive employees after employment but before retirement
is not material.
EARNINGS PER SHARE
Basic earnings per share is based on the weighted-average number of common
shares outstanding during the
period. Diluted earnings per share includes the dilutive effect of stock
options and restricted stock.
EMPLOYEE STOCK-BASED AWARDS
Employee stock-based awards are accounted for under Accounting Principles Board
Opinion No. 25, “Accounting
for Stock Issued to Employees” and related interpretations. Fixed plan common
stock options generally do
not result in compensation expense, because the exercise price of the options
issued by the Company equals
the market price of the underlying stock on the date of grant. The plans under
which the Company issues
stock based awards are described more fully in Note 5. The following table
illustrates the effect on net
income and earnings per share as if the Company had applied the fair value
recognition provisions of SFAS
No. 123, “Accounting for Stock-Based Compensation.”
43
These pro forma amounts may not be representative of future disclosures since
the estimated fair value of stock
options is amortized to expense over the vesting period, and additional options
may be granted in future years.
TREASURY STOCK
Treasury stock purchases are accounted for under the cost method whereby the
entire cost of the acquired
stock is recorded as treasury stock. Gains and losses on the subsequent
reissuance of shares are credited
or charged to additional paid-in-capital using the average-cost method.
CAPITALIZATION OF INTEREST
The Company capitalizes interest on major projects during construction.
Interest is capitalized on borrowed
funds, with the rate based on the average interest rate on related debt.
Capitalized interest for 2003, 2002
and 2001 was $1.8 million, $2.5 million and $1.1 million, respectively.
INTEREST RATE RISK MANAGEMENT
The Company uses derivatives as part of an overall operating strategy to
moderate certain financial market risks
and is exposed to interest rate risk from long-term debt. To manage this risk,
in October 1998, the Company
entered into an interest rate swap to exchange floating rate for fixed rate
interest payments through October
2003, the remaining life of the debt. The difference to be paid or received is
accrued and recognized as an
adjustment of interest expense. As of September 30, 2003, the Company’s
interest rate swap had a notional
principal amount of $50 million.
The Company’s accounting policy for these instruments is based on its
designation of such instruments as hedging
transactions. An instrument is designated as a hedge based in part on its
effectiveness in risk reduction and
one-to-one matching of derivative instruments to underlying transactions. The
Company records all derivatives
on the balance sheet at fair value.
For derivative instruments that are designated and qualify as a cash flow hedge
(i.e., hedging the exposure of
variability in expected future cash flows that is attributable to a particular
risk), the effective portion of the gain
or loss on the derivative instrument is reported as a component of other
comprehensive income in stockholders’
equity and reclassified into earnings in the same period or periods during
which the hedged transaction
affects earnings. The change in value of the derivative instrument in excess
of the cumulative change in the
present value of the future cash flows of the risk being hedged, if any, is
recognized in the current earnings
during the period of change.
Gains and losses from termination of interest rate swap agreements are deferred
and amortized as an adjustment
to interest expense over the original term of the terminated swap agreement.
The Company has one derivative, an interest rate swap, that is discussed
further in Note 3.
44
NOTE 2 DISCONTINUED OPERATIONS
On September 30, 2002, the Company’s distribution of 100 percent of the common
stock of Cimarex Energy Co.
and the merger of Key Production Company, Inc. with Cimarex was completed. In
connection with the distribution,
approximately 26.6 million shares of the Cimarex Energy Co. common stock on a
diluted basis were distributed
to shareholders of the Company of record on September 27, 2002. The Cimarex
Energy Co. stock distribution
was recorded as a dividend and resulted in a decrease to consolidated
shareholders’ equity of approximately
$152.2 million. The Company does not own any common stock of Cimarex Energy
Co.
Under terms of a tax sharing agreement, each party has agreed to indemnify the
other in respect of all taxes
for which it is responsible under the tax sharing agreement. Cimarex is
responsible for all taxes related to the
exploration and production business for all of past and future periods,
including all taxes arising from the Cimarex
business prior to the time that Cimarex was formed, and agrees to hold the
Company harmless in respect of
those taxes. Cimarex is entitled to receive all refunds and credits of taxes
previously paid with respect to the
exploration and production business. Cimarex will not receive the benefit of
any loss or similar tax attribute
arising during the time that losses from the Cimarex business are included in
the Company’s consolidated federal
income tax return. The Company remains responsible for all taxes related to
the business of the Company
other than the exploration and production business and has agreed to indemnify
Cimarex in respect of any
liability for any such taxes.
Summarized results of discontinued operations for the years ended September 30,
2002 and 2001,
are as follows:
45
NOTE 3 NOTES PAYABLE AND LONG-TERM DEBT
At September 30, 2003, the Company had $200 million in long-term debt
outstanding at fixed rates and
maturities as summarized in the following table. Funding of the notes occurred
on August 15, 2002 and
October 15, 2002 in equal amounts of $100 million.
The terms of the debt obligations require the Company to maintain a minimum
ratio of debt to total capitalization.
The proceeds of the debt issuances were used to repay $50 million of
outstanding debt, fund the Company’s
rig construction program and for other general corporate purposes.
At September 30, 2003, the Company had a committed unsecured line of credit
totaling $125 million. Short-term
loans totaling $30 million and letters of credit totaling $13.7 million were
outstanding against the line, leaving
$81.3 million available to borrow. The weighted average interest rate on
short-term loans at September 30,
2003 was 2.0 percent. Under terms of the line of credit, the Company must
maintain certain financial ratios
including debt to total capitalization and debt to earnings before interest,
taxes, depreciation, and amortization,
and maintain certain levels of liquidity and tangible net worth. A non-use fee
of 0.15 percent per annum is
calculated on the average daily unused amount, payable quarterly. The interest
rate varies based on LIBOR
plus .875 to 1.125 percent depending on ratios described above. The line of
credit matures in July, 2004.
Subsequent to September 30, 2003, the Company has paid $10 million of
short-term debt.
At September 30, 2003, the Company held an unassociated interest rate swap tied
to 30-day LIBOR in the
amount of $50 million which matured on October 27, 2003. The swap instrument
was originally designated
as a hedge of a $50 million loan that was paid off in September 2002. The swap
liability was valued at
approximately $0.1 million on September 30, 2003.
The interest rate swap liability was valued at approximately $1.7 million on
the date the $50 million debt was
paid off. The $1.7 million is being amortized over the remaining life of the
swap as interest expense. In fiscal
2003, $1.6 million was amortized and included in interest expense. Changes to
the value of the interest rate
swap subsequent to the date the $50 million debt was paid are recorded to
income.
46
NOTE 4 INCOME TAXES
The components of the provision (benefit) for income taxes from continuing
operations are as follows:
47
NOTE 5 SHAREHOLDERS’ EQUITY
In December 2001, the board of directors authorized the repurchase of up to
2,000,000 shares per calendar year
of the Company’s common stock in the open market or private transactions. The
repurchased shares will be
held in treasury and used for general corporate purposes including use in the
Company’s benefit plans. During
fiscal 2001 the Company purchased 773,800 shares at a cost of approximately
$23,198,000 under previous
authorizations from the board of directors. The Company did not purchase any
shares in fiscal 2003 or 2002.
The Company has several plans providing for common-stock based awards to
employees and to non-employee
directors. The plans permit the granting of various types of awards including
stock options and restricted stock.
Restricted stock may be granted for no consideration other than prior and
future services. The purchase price
per share for stock options may not be less than market price of the underlying
stock on the date of grant.
Stock options expire ten years after grant.
In March 2001, the Company adopted the 2000 Stock Incentive Plan (the “Stock
Incentive Plan”). The Stock
Incentive Plan was effective December 6, 2000 and will terminate December 6,
2010. Under this plan, the
Company is authorized to grant options for up to 3,000,000 shares of the
Company’s common stock at an
exercise price not less than the fair market value of the common stock on the
date of grant. Up to 450,000
shares of the total authorized may be granted to participants as restricted
stock awards. In fiscal 2003 and 2002,
610,700 and 819,800 options, respectively, were granted under the 2000 plan.
There were no restricted
stock grants in fiscal 2003 or 2002. There was no activity under this plan
during fiscal 2001.
On September 30, 2002, the Company distributed 100 percent of the common stock
of Cimarex Energy Co. to the
Company’s shareholders. The distribution was recorded as a dividend and
resulted in a decrease to consolidated
shareholders equity of approximately $152.2 million. Any options held by
Cimarex employees at the distribution
date were automatically forfeited per the terms of the Company’s stock
incentive plans. Both vested and unvested
options held by remaining participants at September 30, 2002 were adjusted (the
number of options and exercise
price) to reflect the change in the value of Company common stock as the result
of the spin-off of Cimarex. The
adjustment was made in such a way that the aggregate intrinsic value of the
options and the ratio of the exercise
price per share to the market value per share remained the same.
48
The following summary reflects the stock option activity for the Company’s
common stock and related information for
2003, 2002, and 2001. (shares in thousands):
The following table summarizes information about stock options at September 30,
2003 (shares in thousands):
The weighted-average fair values of options at their grant date during 2003,
2002, and 2001 was $10.72, $12.47, and $13.01, respectively. The estimated
fair value of each option granted is calculated using the Black-Scholes
option-pricing model. The following summarizes the weighted-average
assumptions used in the model:
On September 30, 2003, the Company had 50,140,364 outstanding common stock
purchase rights (“Rights”) pursuant
to terms of the Rights Agreement dated January 8, 1996. Under the terms of the
Rights Agreement each Right entitled
the holder thereof to purchase from the Company one half of one unit consisting
of one one-thousandth of a share of
Series A Junior Participating Preferred Stock (“Preferred Stock”), without par
value, at a price of $90 per unit. The exercise
price and the number of units of Preferred Stock issuable on exercise of the
Rights are subject to adjustment in certain
cases to prevent dilution. The Rights will be attached to the common stock
certificates and are not exercisable or
transferrable apart from the common stock, until ten business days after a
person acquires 15 percent or more of
49
the outstanding common stock or ten business days following the commencement of
a tender offer or exchange
offer that would result in a person owning 15 percent or more of the
outstanding common stock. In the event
the Company is acquired in a merger or certain other business combination
transactions (including one in which
the Company is the surviving corporation), or more than 50 percent of the
Company’s assets or earning power
is sold or transferred, each holder of a Right shall have the right to receive,
upon exercise of the Right, common
stock of the acquiring company having a value equal to two times the exercise
price of the Right. The Rights
are redeemable under certain circumstances at $0.01 per Right and will expire,
unless earlier redeemed, on
January 31, 2006. As long as the Rights are not separately transferrable, the
Company will issue one half of
one Right with each new share of common stock issued.
NOTE 6 EARNINGS PER SHARE
A reconciliation of the weighted-average common shares outstanding on a basic
and diluted basis is as follows:
At September 30, 2003, options to purchase 1,030,791 shares of common stock at
a weighted-average
price of $27.86 were outstanding, but were not included in the computation of
diluted earnings per common
share. Inclusion of these shares would be antidilutive.
Restricted stock of 44,675 shares at a weighted-average price of $30.38 and
options to purchase 451,421
shares of common stock at a weighted-average price of $27.98 were outstanding
at September 30, 2002,
but were not included in the computation of diluted earnings per common share.
Inclusion of these shares
would be antidilutive.
At September 30, 2001, restricted stock of 120,018 shares at a weighted-average
price of $37.73 and options
to purchase 1,250,750 shares of common stock at a price of $33.84 were
outstanding, but were not included
in the computation of diluted earnings per common share. Inclusion of these
shares would be antidilutive.
50
NOTE 7 FINANCIAL INSTRUMENTS
The Company had $200 million of long-term debt outstanding at September 30,
2003, which had an estimated
fair value of $226.5 million. The debt was valued based on the prices of
similar securities with similar terms
and credit ratings. The Company used the expertise of an outside investment
banking firm to assist with the
estimate of the fair value of the long-term debt. The Company’s line of credit
and notes payable bear interest
at market rates and are carried at cost which approximates fair value. The
estimated fair value of the Company’s
interest rate swap is a liability of $0.1 million at September 30, 2003, based
on forward-interest rates derived from
the year-end yield curve as calculated by the financial institution that is a
counterparty to the swap. The estimated
fair value of the Company’s available-for-sale securities is primarily based on
market quotes.
The following is a summary of available-for-sale securities, which excludes
those accounted for under the equity
method of accounting (see Note 1):
During the years ended September 30, 2003, 2002, and 2001, marketable equity
available-for-sale securities
with a fair value at the date of sale of $18,215,000, $46,692,000, and
$24,438,000, respectively, were sold.
The gross realized gains on such sales of available-for-sale securities totaled
$8,582,000, $25,893,000, and
$3,314,000, respectively, and the gross realized losses totaled $3,053,000,
$232,000, and $0, respectively.
51
NOTE 8 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The table below presents changes in the components of accumulated other
comprehensive income (loss).
52
NOTE 9 EMPLOYEE BENEFIT PLANS
In July 2003, the Company revised the Helmerich & Payne, Inc. Employee
Retirement Plan (“Pension Plan” ) to
close the Pension Plan to new participants effective October 1, 2003, and
reduce benefit accruals for current
participants through September 30, 2006, at which time benefit accruals will be
discontinued and the plan
frozen. These revisions to the Pension Plan had no effect upon pension expense
accruals for fiscal 2003.
The following tables set forth the Company’s disclosures required by SFAS No.
132, “Employers’ Disclosures
About Pensions and Other Postretirement Benefits.”
Change in benefit obligation:
Change in plan assets:
Weighted-average assumptions:
53
COMPONENTS OF NET PERIODIC PENSION EXPENSE:
DEFINED CONTRIBUTION PLAN
Substantially all employees on the United States payroll of the Company may
elect to participate in the
Company sponsored Thrift/401(k) Plan by contributing a portion of their
earnings. The Company contributes
amounts equal to 100 percent of the first five percent of the participant’s
compensation subject to certain
limitations. Expensed Company contributions were $5,568,000, $5,226,000, and
$4,499,000 in 2003,
2002, and 2001, respectively.
54
NOTE 10 OTHER CURRENT ASSETS AND ACCRUED LIABILITIES
Prepaid expenses and other consist of the following:
Accrued liabilities consist of the following:
NOTE 11 SUPPLEMENTAL CASH FLOW INFORMATION
55
NOTE 12 RISK FACTORS
CONCENTRATION OF CREDIT
Financial instruments which potentially subject the Company to concentrations
of credit risk consist primarily of temporary cash investments and trade
receivables. The Company places temporary cash investments with established
financial institutions and invests in a diversified portfolio of highly rated,
short-term money market instruments. The Company’s trade receivables are
primarily with companies in the oil and gas industry and are typically not
secured by collateral. The Company provides an allowance for doubtful
accounts, when necessary, to cover estimated credit losses. Such an allowance
is based on managements knowledge of customer accounts. No significant credit
losses have been experienced by the Company.
SELF-INSURANCE
The Company self-insures a significant portion of its expected losses under its
worker’s compensation, general, and automobile liability programs in the United
States. Insurance coverage has been purchased for individual claims that
exceed $2 million. The Company records estimates for incurred outstanding
liabilities for unresolved worker’s compensation, general liability claims and
for claims that are incurred but not reported. Estimates are based on historic
experience and statistical methods that the Company believes are reliable.
Nonetheless, insurance estimates include certain assumptions and management
judgments regarding the frequency and severity of claims, claims development,
and settlement practices. Unanticipated changes in these factors may produce
materially different amounts of expense that would be reported under these
programs.
CONTRACT DRILLING OPERATIONS
International drilling operations are significant contributors to the Company’s
revenues and net profit. It is possible that operating results could be
affected by the risks of such activities, including economic conditions in the
international markets in which the Company operates, political and economic
instability, fluctuations in currency exchange rates, changes in international
regulatory requirements, international employment issues, and the burden of
complying with foreign laws. These risks may adversely affect the Company’s
future operating results and financial position.
The Company is exposed to risks of currency devaluation in Venezuela primarily
as a result of bolivar receivable balances and bolivar cash balances. In
Venezuela, while approximately 60 percent of the Company’s billings to the
Venezuelan oil company, PDVSA, are in U.S. dollars and 40 percent are in the
local currency, the bolivar, PDVSA typically pays all amounts owed in bolivars.
The Company, historically, has usually been able to convert the bolivars
received in payment of the dollar-based billings into U.S. dollars in a timely
manner. In January 2003, the Venezuelan government put into effect exchange
controls that fixed the exchange rate at 1600 bolivars to one U.S. dollar and
also prohibited the Company, as well as other companies, from converting the
bolivar into U.S. dollars. As a result of these exchange controls, the Company
has been unable since January 2003 to convert its bolivar cash balances into
U.S. dollars. As of September 30, 2003, the Company’s bolivar balance was
approximately 14 billion bolivars or approximately $8.8 million. Historically,
the Company has kept bolivar cash balances at necessary minimum levels to fund
local operating costs. In compliance with applicable
56
regulations the Company on October 1, 2003, submitted a request to the
Venezuelan government seeking permission to convert existing bolivar balances
into U.S. dollars. The Company is unable to predict if or when this request
will be approved.
As stated above, the Company is exposed to risks of currency devaluation in
Venezuela primarily as a result of bolivar receivable balances and bolivar cash
balances. From August of 2002 to August of 2003, there was a 13 percent
devaluation of the bolivar. As a result, the Company experienced a $624,000
devaluation loss. This 13 percent devaluation loss may not be reflective of
the actual potential for future devaluation losses because of the exchange
controls that are currently in place. While the Company is unable to predict
future devaluation in Venezuela, if fiscal 2004 activity levels are similar to
fiscal 2003 and if a 25 to 50 percent devaluation would occur, the Company
could experience potential currency devaluation losses ranging from
approximately $3,200,000 to $5,100,000.
In late August 2003, the Venezuelan state petroleum company agreed, on a
go-forward basis, to pay a portion of the Company’s dollar-based invoices in
U.S. dollars. While this is a positive development in light of the existing
exchange controls, there is no guarantee as to how long this arrangement will
continue. Were this agreement to end, The Company would revert back to
receiving these payments in Bolivars and thus increase Bolivar cash balances
and exposure to devaluation.
Recent events in Venezuela have created greater governmental instability. In
the event that extended labor strikes occur or turmoil increases, the Company
could experience shortages in material and supplies necessary to operate some
or all of its Venezuelan drilling rigs.
The Company believes that its rig fleet is not currently impaired based on an
assessment of future cash flows of the assets in question. However, it is
possible that the Company’s assessment that it will recover the carrying amount
of its rig fleet from future operations may change in the near term.
NOTE 13 NEW ACCOUNTING STANDARDS
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement
Obligations.” This Statement addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and
the associated asset retirement costs. The Statement requires that the fair
value of a liability for an asset retirement obligation be recognized in the
period in which it is incurred if a reasonable estimate of fair value can be
made, and that the associated asset retirement costs be capitalized as part of
the carrying amount of the long-lived asset. The Statement is effective for
financial statements issued for fiscal years beginning after June 15, 2002.
There was no impact on the Company’s results of operations and financial
position upon adopting SFAS No. 143 on October 1, 2002.
57
NOTE 14 CONTINGENT LIABILITIES AND COMMITMENTS
COMMITMENTS
The Company, on a regular basis, makes commitments for the purchase of contract
drilling equipment. At September 30, 2003, the Company has commitments of
approximately $35 million for the purchase of drilling equipment.
LEASES
In May 2003, the Company signed a six-year lease for approximately 114,000
square feet of office space near downtown Tulsa. The lease will be effective
as the Company moves during the first quarter of fiscal 2004. Future annual
minimum lease payments under this noncancelable lease and other noncancelable
leases as of September 30, 2003 were as follows: (in thousands)
Total rent expense was $1,108,000, $1,027,000 and $736,000 for 2003, 2002 and
2001, respectively.
NOTE 15 SEGMENT INFORMATION
The Company operates principally in the contract drilling industry. The
Company’s contract drilling business includes the following operating segments:
U.S. Land, U.S.Offshore Platform, and International. The contract drilling
operations consist primarily of contracting Company-owned drilling equipment
primarily to major oil and gas exploration companies. The
Company’s primary
international areas of operation include Venezuela, Colombia, Ecuador,
Argentina and Bolivia. The Company also has a Real Estate segment whose
operations are conducted exclusively in the metropolitan area of Tulsa,
Oklahoma. The primary areas of operations include a major shopping center and
several multi-tenant warehouses. Each reportable segment is a strategic
business unit which is managed separately. Other includes Investments and
corporate operations. As described in Note 2 the Company’s oil and gas
operations were distributed to Company shareholders on September 30, 2002.
Such operations have been treated as discontinued operations and have been
excluded from these segment disclosures.
The Company evaluates performance of its segments based upon operating profit
or loss from operations before income taxes which includes revenues from
external and internal customers; direct operating costs;
58
depreciation; and allocated general and administrative costs; but excludes
corporate costs for other depreciation and other income and expense. General
and administrative costs are allocated to the segments based primarily on
specific identification, and to the extent that such identification was not
practical, on other methods which the Company believes to be a reasonable
reflection of the utilization of services provided. The accounting policies of
the segments are the same as those described in Note 1, Summary of Accounting
Policies. Intersegment sales are accounted for in the same manner as sales to
unaffiliated customers.
Summarized financial information of the Company’s reportable segments for each
of the years ended September 30, 2003, 2002, and 2001 is shown in the
following table:
59
The following table reconciles segment operating profit per the table on page
59 to income before taxes and equity in income (loss) of affiliates as reported
on the Consolidated Statements of Income (in thousands).
The following tables present revenues from external customers and long-lived
assets by country based on the location of service provided (in thousands).
Long-lived assets are comprised of property, plant and equipment.
Revenues from one company doing business with the contract drilling segment
accounted for approximately 15.7 percent, 16.3 percent, and 23.9 percent of the
total consolidated revenues during the years ended September 30, 2003, 2002,
and 2001, respectively. Revenues from another company doing business with the
contract drilling segment accounted for approximately 14.6 percent, 14.7
percent, and 12.8 percent of total consolidated revenues in the years ended
September 30, 2003, 2002, and 2001, respectively. Revenues from another
company doing business with the contract drilling segment accounted for
approximately 11.5 percent, 12.3 percent, and 8.4 percent of total consolidated
revenues in the years ended September 30, 2003, 2002, and 2001, respectively.
Collectively, the receivables from these customers were approximately $36.0
million and $35.0 million at September 30, 2003 and 2002, respectively.
60
NOTE 16 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
(in thousands, except per share amounts)
Gross profit represents total revenues less operating costs and depreciation.
The sum of earnings per share for the four quarters may not equal the total
earnings per share for the year due to changes in the average number of common
shares outstanding.
Net income in the fourth quarter of 2003 includes after-tax gains on sale of
available-for-sale securities of $3.2 million, $0.06 per share, on a diluted
basis.
Net income in the fourth quarter of 2003 includes an after-tax equity loss in
loss of affiliates of $2 million, $0.04 per share, on a diluted basis.
Net income in the third quarter of 2002 includes after-tax gains on sale of
available-for-sale securities of $15.2 million, $0.30 per share, on a diluted
basis.
61
Stockholders’ Meeting
The annual meeting of stockholders will be held
on March 3, 2004. A formal notice of the
meeting, together with a proxy statement and
form of proxy will be mailed to shareholders
on or about January 27, 2004.
Stock Exchange Listing
Helmerich & Payne, Inc. Common Stock is
traded on the New York Stock Exchange with
the ticker symbol “HP.” The newspaper abbreviation most commonly used for financial
reporting is “HelmP.” Options on the Company’s
stock are also traded on the New York
Stock Exchange.
Stock Transfer Agent and Registrar
As of December 15, 2003, there were 1,017
record holders of Helmerich & Payne, Inc.
common stock as listed by the transfer
agent’s records.
Our Transfer Agent is responsible for our
shareholder records, issuance of stock
certificates, and distribution of our dividends
and the IRS Form 1099. Your requests, as
shareholders, concerning these matters are
most efficiently answered by corresponding
directly with The Transfer Agent at the
following address:
Additional Information
Quarterly reports on Form 10-Q, earnings
releases, and financial statements are made
available on the investor relations section of
the Company’s Web site. Also located on the
investor relations section of the Company’s
Web site are certain corporate governance
documents, including the following: the charters
of the committees of the Board of Directors;
the Company’s Corporate Governance
Guidelines; the Code of Ethics for Principal
Executive Officer and Senior Financial
Officers; certain Audit Committee Practices
and a description of the means by which
employees and other interested persons
may communicate certain concerns to the
Company’s Board of Directors, including the
communication of such concerns confidentially and anonymously via the Company’s
ethics hotline at 1-800-205-4913. Quarterly
reports, earnings releases, financial statements
and the various corporate governance
documents are also available free of charge
upon written request.
Direct Inquiries To:
Investor Relations
Internet Address: http://www.hpinc.com
62
Years Ended September 30
2003
2002
2001
507,331
523,803
531,604
345,537
361,669
330,181
82,513
61,447
49,532
79,281
100,687
151,891
7,953
28,076
10,967
12,289
980
1,701
41,003
36,563
28,180
17,873
53,706
80,467
17,873
63,517
144,254
0.35
1.07
1.58
0.35
1.26
2.84
*$000’s omitted, except per share data.
Certain
prior year amounts have been reclassified to conform to current year
classifications. (see note 1)
†
All data
excludes discontinued operations except net income.
43
26
13
40
40
36
12
12
10
32
33
37
127
111
96
97
96
100
67
78
96
81
84
97
51
83
98
39
51
56
2000
1999
1998
1997
1996
1995
1994
1993
384,762
431,741
479,592
353,355
274,208
229,316
206,991
167,956
248,568
290,048
322,861
228,958
184,703
158,815
148,210
114,858
77,317
70,092
58,187
48,291
39,592
37,364
31,038
29,397
58,877
71,601
98,544
76,106
49,913
33,137
27,743
23,701
32,063
7,422
45,152
11,746
5,992
11,279
6,944
9,494
2,730
5,389
336
34
678
407
385
925
23,306
24,629
21,299
15,636
15,222
14,019
14,126
12,422
36,470
32,115
80,790
48,801
25,844
18,464
13,216
8,978
82,300
42,788
101,154
84,186
72,566
9,751
24,971
24,550
.73
.65
1.60
.97
.52
.38
.27
.18
1.64
.86
2.00
1.67
1.46
.20
.51
.50
107,632
21,758
24,476
27,963
16,892
19,543
29,447
61,656
179,884
82,893
49,179
65,802
48,128
50,038
76,238
104,085
307,425
240,891
200,400
323,510
229,809
156,908
87,414
84,945
526,723
553,769
548,555
392,489
329,377
286,678
235,067
209,877
1,200,854
1,073,465
1,053,200
987,432
786,351
707,061
624,827
610,935
50,000
50,000
50,000
—
—
—
—
3,600
955,703
848,109
793,148
780,580
645,970
562,435
524,334
508,927
65,820
78,357
217,597
114,626
83,411
89,709
59,379
27,823
6
6
6
—
—
—
—
—
32
34
30
29
30
30
36
31
10
10
10
9
11
11
11
11
40
39
44
39
36
35
29
29
88
89
90
77
77
76
76
71
99
79
100
—
—
—
—
—
82
68
94
99
88
73
66
48
85
69
94
99
88
73
66
48
94
95
99
63
70
66
79
70
47
53
88
91
85
84
88
68
2003
2002
% Change
(in thousands, except operating statistics)
$
273,993
$
232,446
17.9
%
—
(809
)
—
201,398
165,394
21.8
—
(648
)
—
9,304
10,087
(7.8
)
44,726
26,311
70.0
$
18,565
$
30,493
(39.1
)
22,588
17,478
29.2
%
$
11,436
$
12,397
(7.8
)
$
8,221
$
8,561
(4.0
)
$
3,215
$
3,836
(16.2
)
83
66
25.8
81
%
84
%
(3.6
)
2003
2002
% Change
(in thousands, except operating statistics)
$
112,633
$
132,249
(14.8
)%
60,589
79,301
(23.6
)
2,939
3,451
(14.8
)
12,799
10,809
18.4
$
36,306
$
38,688
(6.2
)
2,233
3,286
(32.0
)%
$
38,239
$
30,424
25.7
$
17,822
$
16,263
9.6
$
20,417
$
14,161
44.2
12
12
0.0
51
%
83
%
(38.6
)
2003
2002
% Change
(in thousands, except operating statistics)
$
109,812
$
151,392
(27.5
)%
81,461
115,294
(29.3
)
3,110
2,634
18.1
20,092
20,336
(1.2
)
$
5,149
$
13,128
(60.8
)
4,515
5,956
(24.2
)%
$
19,603
$
21,161
(7.4
)
$
14,140
$
14,599
(3.1
)
$
5,463
$
6,562
(16.7
)
32
33
(3.0
)
39
%
51
%
(23.5
)
2003
2002
% Change
(in thousands)
$
10,893
$
8,525
27.8
%
1,789
1,617
10.6
2,535
1,844
37.5
$
6,569
$
5,064
29.7
2002
2001
% Change
(in thousands, except operating statistics)
$
232,446
$
226,344
2.7
%
(809
)
(4,487
)
(82.0
)
165,394
133,650
23.8
(648
)
(2,553
)
(74.6
)
10,087
6,479
55.7
26,311
16,701
57.5
$
30,493
$
67,580
(54.9
)
17,478
15,098
15.8
%
$
12,397
$
14,315
(13.4
)
$
8,561
$
8,175
4.7
$
3,836
$
6,140
(37.5
)
66
49
34.7
84
%
97
%
(13.4
)
2002
2001
% Change
(in thousands, except operating statistics)
$
132,249
$
128,459
3.0
%
79,301
75,810
4.6
3,451
2,962
16.5
10,809
9,576
12.9
$
38,688
$
40,111
(3.5
)
3,286
3,572
(8.0
)%
$
30,424
$
28,995
4.9
$
16,263
$
15,734
3.4
$
14,161
$
13,261
6.8
12
10
20.0
83
%
98
%
(15.3
)
2002
2001
% Change
(in thousands, except operating statistics)
$
151,392
$
170,270
(11.1
)%
115,294
120,845
(4.6
)
2,634
2,112
24.7
20,336
18,838
8.0
$
13,128
$
28,475
(53.9
)
5,956
7,283
(18.2
)%
$
21,161
$
19,683
7.5
$
14,599
$
13,334
9.5
$
6,562
$
6,349
3.4
33
37
(10.8
)
51
%
56
%
(8.9
)
2002
2001
% Change
(in thousands)
$
8,525
$
11,018
(22.6
)%
1,617
2,419
(33.2
)
1,844
2,284
(19.3
)
$
5,064
$
6,315
(19.8
)
September 30, 2003
Number of Shares
Cost Basis
Market Value
(in thousands, except share amounts)
3,000,000
$
56,655
$
71,970
1,480,000
23,511
71,632
140,000
3,486
7,665
6,303
18,279
$
89,955
$
169,546
Total
2004
2005
2006
2007
2008
After 2008
$
30,000
$
30,000
$
—
$
—
$
—
$
—
$
—
200,000
—
—
—
25,000
—
175,000
8,146
1,285
1,048
1,311
1,385
1,385
1,732
36,415
35,530
530
355
—
—
—
$
274,561
$
66,815
$
1,578
$
1,666
$
26,385
$
1,385
$
176,732
(a)
See Note 3 “Long-term Debt” to the Company’s Consolidated Financial
Statements.
(b)
See Note 14 “Commitments and Contingencies” to the Company’s Consolidated
Financial Statements.
After
Fair Value
2004
2005
2006
2007
2008
2008
Total
@ 9/30/03
—
—
—
$
25,000
—
$
175,000
$
200,000
$
226,500
—
—
—
5.5
%
—
6.4
%
6.4
%
—
$
30,000
—
—
—
—
—
$
30,000
$
30,000
—
—
—
—
—
—
(a
)
—
(a) LIBOR plus an increment of .875% to 1.25% depending on certain financial
ratios.
After
Fair Value
2003
2004
2005
2006
2007
2007
Total
@ 9/30/02
—
—
—
—
$
12,500
$
87,500
$
100,000
$
109,700
—
—
—
—
5.5
%
6.4
%
6.4
%
—
—
—
—
—
—
—
(b
)
(1,700
)
(b) At September 30, 2002, the Company held an interest rate swap on $50
million face value debt to receive variable interest payments based on 30-day
LIBOR rates and pay fixed interest payments of 5.4% through October 27, 2003.
Helmerich & Payne, Inc.
November 19, 2003
Years Ended September 30,
2003
2002
2001
(in thousands, except per share amounts)
$
507,331
$
523,803
$
531,604
7,953
28,076
10,967
515,284
551,879
542,571
345,537
361,669
330,181
82,513
61,447
49,532
41,003
36,563
28,180
12,289
980
1,701
481,342
460,659
409,594
33,942
91,220
132,977
14,649
40,573
54,689
(1,420
)
3,059
2,179
17,873
53,706
80,467
—
9,811
63,787
$
17,873
$
63,517
$
144,254
$
0.36
$
1.08
$
1.61
—
0.19
1.27
$
0.36
$
1.27
$
2.88
$
0.35
$
1.07
$
1.58
—
0.19
1.26
$
0.35
$
1.26
$
2.84
50,039
49,825
50,096
50,596
50,345
50,772
September 30,
2003
2002
(in thousands)
$
38,189
$
46,883
91,088
92,604
22,533
22,511
45,721
16,753
197,531
178,751
158,770
150,175
1,490,389
1,235,784
45,004
72,303
56,247
48,925
87,570
82,310
1,679,210
1,439,322
621,005
541,877
1,058,205
897,445
1,329
942
$
1,415,835
$
1,227,313
September 30,
2003
2002
(in thousands, except share data)
$
30,000
$
—
29,630
41,045
28,988
31,854
88,618
72,899
200,000
100,000
181,737
131,401
28,229
27,843
409,966
259,244
5,353
5,353
—
—
83,302
82,489
840,776
838,929
(10
)
(190
)
33,668
16,180
963,089
942,761
45,838
47,591
917,251
895,170
$
1,415,835
$
1,227,313
Common Stock
Additional
Paid-in
Unearned
Retained
Shares
Amount
Capital
Compensation
Earnings
(in thousands, except per share amounts)
53,529
$
5,353
$
66,090
$
(3,277
)
$
813,885
144,254
(15,047
)
7,965
6,269
1,465
13
53,529
5,353
80,324
(1,812
)
943,105
63,517
(152,201
)
(15,492
)
1,099
88
156
978
1,466
53,529
5,353
82,489
(190
)
838,929
17,873
(16,026
)
441
372
180
53,529
$
5,353
$
83,302
$
(10
)
$
840,776
Accumulated
Treasury Stock
Other
Comprehensive
Shares
Amount
Income (Loss)
Total
(in thousands, except per share amounts)
3,548
$
(32,412
)
$
106,064
$
955,703
144,254
(55,769
)
(55,769
)
(986
)
(986
)
(56,755
)
87,499
(15,047
)
(646
)
5,808
13,773
774
(23,198
)
(23,198
)
6,269
1,478
3,676
(49,802
)
49,309
1,026,477
63,517
(25,449
)
(25,449
)
(68
)
(68
)
(7,612
)
(7,612
)
(33,129
)
30,388
(152,201
)
(15,492
)
(181
)
2,455
3,554
23
(244
)
978
1,466
3,518
(47,591
)
16,180
895,170
17,873
15,005
15,005
982
982
1,501
1,501
17,488
35,361
(16,026
)
(129
)
1,753
2,194
372
180
3,389
$
(45,838
)
$
33,668
$
917,251
Years Ended September 30,
2003
2002
2001
(in thousands)
$
17,873
$
53,706
$
80,467
82,513
61,447
49,532
2,290
(5,014
)
(3,593
)
180
1,122
1,135
(5,529
)
(24,347
)
(1,189
)
(3,689
)
(1,392
)
(4,201
)
336
791
876
1,516
24,148
(49,405
)
251
1,042
(68
)
(29,355
)
24,381
(11,411
)
(11,415
)
(3,769
)
29,290
(1,281
)
955
18,435
41,225
24,133
15,291
1,589
(5,429
)
2,276
78,631
98,068
46,968
96,504
151,774
127,435
(246,301
)
(312,064
)
(184,668
)
—
—
(2,279
)
6,720
4,135
11,984
—
(5,656
)
—
18,215
47,146
24,438
(221,366
)
(266,439
)
(150,525
)
151,331
100,000
—
(21,331
)
(50,000
)
—
(16,026
)
(15,221
)
(15,047
)
—
—
(23,198
)
2,194
3,554
13,601
116,168
38,333
(24,644
)
—
62,792
157,286
—
(55,232
)
(88,813
)
—
(13,171
)
—
—
(5,611
)
68,473
(8,694
)
(81,943
)
20,739
46,883
128,826
108,087
$
38,189
$
46,883
$
128,826
September 30
2003
2002
2001
(in thousands)
$
144,766
$
149,157
$
147,541
157,568
120,872
120,195
$
(12,802
)
$
28,285
$
27,346
$
(1,414
)
$
4,206
$
3,596
$
72,182
$
71,813
$
45,891
447,464
372,717
304,857
40,504
24,416
19,144
215,757
143,981
85,948
263,385
276,133
245,656
$
56,655
$
58,937
$
52,153
September 30
2003
2002
2001
(in thousands)
$
17,873
$
63,517
$
144,254
112
909
908
(4,387
)
(3,354
)
(5,951
)
$
13,598
$
61,072
$
139,211
$
0.36
$
1.27
$
2.88
$
0.27
$
1.23
$
2.78
$
0.35
$
1.26
$
2.84
$
0.27
$
1.21
$
2.74
September 30
2002
2001
(in thousands)
$
172,827
$
317,580
15,138
102,125
5,327
38,338
$
9,811
$
63,787
(In thousands)
Issue Amount
Maturity Date
Interest Rate
August 15, 2007
5.51
%
August 15, 2009
5.91
%
August 15, 2012
6.46
%
August 15, 2014
6.56
%
2003
2002
2001
Weighted-Average
Weighted-Average
Weighted-Average
Options
Exercise Price
Options
Exercise Price
Options
Exercise Price
3,875
$
20.28
3,136
$
25.78
2,955
$
22.94
611
27.74
820
29.89
844
32.36
(130
)
16.93
(181
)
19.61
(644
)
21.34
—
—
926
—
—
—
(29
)
23.85
(826
)
28.15
(19
)
25.57
4,327
$
21.41
3,875
$
20.28
3,136
$
25.78
2,575
19.34
1,935
$
19.07
1,078
$
23.82
1,597
2,195
3,000
Outstanding Stock Options
Exercisable Stock Options
Range of
Weighted-Average
Weighted-Average
Weighted-Average
Exercise Prices
Options
Remaining Life
Exercise Price
Options
Exercise Price
380
1.9
$
10.58
380
$
10.58
1,376
5.2
$
17.03
1,195
$
16.76
2,571
7.5
$
25.35
1,000
$
25.74
4,327
6.3
$
21.41
2,575
$
19.34
2003
2002
2001
4.5
4.5
4.5
45
%
48
%
43
%
.75
%
.8
%
.8
%
3.1
%
4.0
%
5.2
%
2003
2002
2001
(in thousands)
50,039
49,825
50,096
555
508
644
2
12
32
557
520
676
50,596
50,345
50,772
Gross Unrealized
Gross Unrealized
Estimated Fair
Cost
Gains
Losses
Value
(in thousands)
$
33,300
$
64,276
$
0
$
97,576
$
46,325
$
43,846
$
3,772
$
86,399
Unrealized Appreciation
Interest
Minimum
(Depreciation)
Rate
Pension
on Securities
Swap
Liability
Total
(in thousands)
$
106,064
$
—
$
—
$
106,064
(88,762
)
(1,590
)
—
(90,352
)
33,730
604
—
34,334
(737
)
—
—
(737
)
(55,769
)
(986
)
—
(56,755
)
50,295
(986
)
—
49,309
(16,228
)
(127
)
(12,277
)
(28,632
)
6,167
48
4,665
10,880
—
11
—
11
(15,388
)
—
—
(15,388
)
(25,449
)
(68
)
(7,612
)
(33,129
)
24,846
(1,054
)
(7,612
)
16,180
29,731
—
2,421
32,152
(11,298
)
—
(920
)
(12,218
)
—
982
—
982
(3,428
)
—
—
(3,428
)
15,005
982
1,501
17,488
$
39,851
$
(72
)
$
(6,111
)
$
33,668
Years Ended September 30,
2003
2002
(in thousands)
$
68,134
$
51,733
5,401
4,769
4,423
3,835
(8,444
)
(1,232
)
6,269
11,036
(4,609
)
(2,007
)
$
71,174
$
68,134
Years Ended September 30,
2003
2002
(in thousands)
$
48,286
$
53,987
9,958
(3,694
)
(4,609
)
(2,007
)
$
53,635
$
48,286
$
(17,539
)
$
(19,848
)
15,052
24,929
20
284
(9,856
)
(12,277
)
$
(12,323
)
$
(6,912
)
Years Ended September 30,
2003
2002
2001
6.25
%
6.75
%
7.50
%
8.00
%
8.00
%
9.00
%
5.00
%
5.00
%
5.00
%
Years Ended September 30,
2003
2002
2001
(in thousands)
$
5,401
$
4,769
$
3,851
4,423
3,835
3,330
(3,807
)
(4,804
)
(5,415
)
180
238
238
—
(540
)
(540
)
1,550
120
17
84
—
—
$
7,831
$
3,618
$
1,481
September 30,
2003
2002
(in thousands)
$
322
$
337
32,619
9,304
2,993
—
9,787
7,112
$
45,721
$
16,753
September 30,
2003
2002
(in thousands)
$
8,386
$
7,660
2,820
2,506
6,768
7,032
1,535
6,016
9,479
8,640
$
28,988
$
31,854
Years Ended September 30,
2003
2002
2001
(in thousands)
$
11,375
$
477
$
1,546
$
5,838
$
9,779
$
42,523
Fiscal Year
Amount
$
1,285
1,048
1,311
1,385
1,385
1,732
$
8,146
Additions
External
Inter-
Total
Operating
Total
to Long-Lived
(in thousands)
Sales
Segment
Sales
Profit
Depreciation
Assets
Assets
$
273,993
$
—
$
273,993
$
18,565
$
44,726
$
728,707
$
216,590
112,633
—
112,633
36,306
12,799
170,580
7,191
109,812
—
109,812
5,149
20,092
243,918
12,733
496,438
—
496,438
60,020
77,617
1,143,205
236,514
10,893
1,439
12,332
6,569
2,535
31,472
7,628
7,953
—
7,953
—
2,361
241,158
2,159
—
(1,439
)
(1,439
)
—
—
—
—
$
515,284
$
—
$
515,284
$
66,589
$
82,513
$
1,415,835
$
246,301
$
231,637
$
809
$
232,446
$
30,493
$
26,311
$
555,137
$
236,254
132,249
—
132,249
38,688
10,809
173,474
48,273
151,392
—
151,392
13,128
20,336
254,940
23,157
515,278
809
516,087
82,309
57,456
983,551
307,684
8,525
1,491
10,016
5,064
1,844
26,562
3,181
28,076
—
28,076
—
2,147
217,200
1,199
—
(2,300
)
(2,300
)
—
—
—
—
$
551,879
$
—
$
551,879
$
87,373
$
61,447
$
1,227,313
$
312,064
$
221,857
$
4,487
$
226,344
$
67,580
$
16,701
$
366,193
$
136,740
128,459
—
128,459
40,111
9,576
139,980
7,323
170,270
—
170,270
28,475
18,838
268,947
38,022
520,586
4,487
525,073
136,166
45,115
775,120
182,085
11,018
1,545
12,563
6,315
2,284
22,621
1,190
10,967
—
10,967
—
2,133
367,123
1,393
—
(6,032
)
(6,032
)
—
—
—
—
$
542,571
$
—
$
542,571
$
142,481
$
49,532
$
1,164,864
$
184,668
Years Ended September 30,
2003
2002
2001
$
66,589
$
87,373
$
142,481
7,953
28,076
10,967
(25,650
)
(20,391
)
(16,627
)
(12,289
)
(980
)
(1,701
)
(2,361
)
(2,147
)
(2,133
)
(300
)
(711
)
(10
)
(32,647
)
3,847
(9,504
)
$
33,942
$
91,220
$
132,977
Years Ended September 30,
2003
2002
2001
$
405,472
$
400,487
$
372,301
31,763
50,763
49,163
50,783
47,501
37,839
6,081
11,612
28,886
21,185
41,516
54,382
$
515,284
$
551,879
$
542,571
$
867,365
$
698,316
$
448,119
75,179
72,630
84,856
46,778
49,353
33,520
12,984
14,339
16,195
55,899
62,807
67,361
$
1,058,205
$
897,445
$
650,051
2003
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
$
113,313
$
126,320
$
137,025
$
138,626
14,021
19,024
26,788
27,401
607
2,574
8,162
6,530
.01
.05
.16
.13
.01
.05
.16
.13
2002
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
$
143,883
$
132,344
$
152,049
$
123,603
37,378
24,093
47,477
19,815
18,127
8,129
22,551
4,899
15,604
10,872
28,218
8,823
.36
.16
.46
.10
.31
.22
.57
.18
.36
.16
.45
.10
.31
.22
.56
.17
Directors
Officers
W. H. Helmerich, III
W. H. Helmerich, III
Chairman of the Board
Chairman of the Board
Tulsa, Oklahoma
Hans Helmerich
Hans Helmerich
President and Chief Executive Officer
President and Chief Executive Officer
Tulsa, Oklahoma
George S. Dotson
Vice President,
William L. Armstrong**(***)
President of Helmerich & Payne
Chairman
International Drilling Co.
Transland Financial Services, Inc.
Denver, Colorado
Douglas E. Fears
Vice President and
Glenn A. Cox*(***)
Chief Financial Officer
President and Chief Operating Officer,
Retired
Phillips Petroleum Company
Steven R. Mackey
Bartlesville, Oklahoma
Vice President, Secretary,
and General Counsel
George S. Dotson
Vice President,
Gordon K. Helm
President of Helmerich & Payne
Controller
International Drilling Co.
Tulsa, Oklahoma
Paula Marshall-Chapman**(***)
President and Chief Executive Officer
The Bama Companies, Inc.
Tulsa, Oklahoma
L. F. Rooney, III*(***)
Chief Executive Officer
Manhattan Construction Company
Tulsa, Oklahoma
Edward B. Rust, Jr.*(***)
Chairman and Chief Executive Officer
State Farm Insurance Companies
Bloomington, Illinois
John D. Zeglis**(***)
Chairman and Chief Executive Officer
AT&T Wireless Services
Basking Ridge, New Jersey
UMB Bank
Security Transfer Division
928 Grand Blvd., 13th Floor
Kansas City, MO 64106
(816) 860-5000
Helmerich & Payne, Inc.
1437 South Boulder Avenue
Tulsa, Oklahoma 74119
Telephone: (918) 742-5531