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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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COMMISSION FILE NUMBER 1-7573
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PARKER DRILLING COMPANY
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(Exact name of registrant as specified in its charter)
Delaware 73-0618660
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1401 Enclave Parkway, Suite 600, Houston, Texas 77077
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(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code (281) 406-2000
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Securities registered pursuant to Section 12(b) of the Act:
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED:
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Common Stock, par value $.16 2/3 per share New York Stock Exchange
9.75% Senior Notes due 2006 New York Stock Exchange
10.125% Senior Notes due 2009 New York Stock Exchange
5.5% Convertible Subordinated Notes due 2004 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the agreement is an accelerated filer (as
defined in Exchange Act Rule 12-b2). Yes [X] No [ ]
The aggregate market value of our common stock held by non-affiliates on
June 30, 2002 was $287.6 million. At January 31, 2003, there were 92,793,349
shares of common stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF OUR DEFINITIVE PROXY STATEMENT FOR THE 2003
ANNUAL MEETING OF SHAREHOLDERS ARE INCORPORATED BY REFERENCE IN
PART III
1
Amendment No. 1
Explanatory Note:
As described in Note 17 of notes to the consolidated financial
statements Parker Drilling Company has revised certain financial and other data
to give affect to discontinued operations and to reflect the adoption of
Statement of Financial Accounting Standards No. 145. The reclassifications had
no effect on previously reported net income (loss) or net income (loss) per
share. Corresponding changes resulting from the reclassification of the
discontinued operations were also made to Item 1. Business, Item 2. Properties,
Item 6. Selected Financial Data, Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations and Item 8. Financial Statements
and Supplementary Data. Additionally, we have updated certain other information
in Item 1 and Item 7 to reflect recent events.
2
TABLE OF CONTENTS
PAGE NO.
PART I
Item 1. Business 5
Item 2. Properties 14
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of Security Holders 19
Item 4A. Executive Officers 19
PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters 20
Item 6. Selected Financial Data 21
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations 22
Item 7A. Quantitative and Qualitative Disclosures about Market Risk 35
Item 8. Financial Statements and Supplementary Data 36
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure 82
Item 9A. Controls and Procedures 82
PART III
Item 10. Directors and Executive Officers of the Registrant 83
Item 11. Executive Compensation 83
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters 83
Item 13. Certain Relationships and Related Transactions 83
PART IV
Item 15. Exhibits, Financial Statement Schedule and Reports on Form 8-K 84
Signatures 88
3
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K/A contains statements that are "forward-looking statements"
within the meaning of Section 27A of the Securities Act and Section 21E of the
Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements
contained in this Form 10-K/A, other than statements of historical facts, are
"forward-looking statements" for purposes of these provisions, including any
statements regarding:
o prices and demand for oil and natural gas;
o levels of oil and natural gas exploration and production activities;
o demand for contract drilling and drilling related services and demand
for rental tools;
o our future operating results, including our efforts to reduce costs and
our projected net loss from continuing operations;
o our future rig utilization, dayrates and rental tool activity;
o our future capital expenditures and investments in the acquisition and
refurbishment of rigs and equipment;
o reducing our debt, including our liquidity and the sources and
availability of funds to reduce our debt;
o future sales of our assets;
o the outcome of pending and future legal proceedings, including the
outcome of our dispute with the Ministry of State Revenues of the
Republic of Kazakhstan;
o our recovery of insurance proceeds in respect of our damaged rigs in
Nigeria and the Gulf of Mexico;
o maintenance of the borrowing base under our credit facilities; and
o expansion and growth of our operations.
In some cases, you can identify these statements by forward-looking words
such as "anticipate," "believe," "could," "estimate," "expect," "intend,"
"outlook," "may," "should," "will" and "would" or similar words. Forward-looking
statements are based on certain assumptions and analyses made by our management
in light of their experience and perception of historical trends, current
conditions, expected future developments and other factors they believe are
relevant. Although our management believes that their assumptions are reasonable
based on information currently available, those assumptions are subject to
significant risks and uncertainties, many of which are outside of our control.
The following factors, as well as any other cautionary language in this Form
10-K/A, provide examples of risks, uncertainties and events that may cause our
actual results to differ materially from the expectations we describe in our
forward-looking statements:
o worldwide economic and business conditions that adversely affect market
conditions and/or the cost of doing business,
o the pace of recovery in the U.S. economy and the demand for natural gas,
o fluctuations in the market prices of oil and gas,
o imposition of unanticipated trade restrictions and political instability,
o operating hazards and uninsured risks,
o political instability, terrorism or war,
o governmental regulations, including changes in tax laws or ability to
remit funds to the U.S., that adversely affect the cost of doing
business,
o adverse environmental events,
o adverse weather conditions,
o changes in concentration of customer and supplier relationships,
o unexpected cost increases for upgrade and refurbishment projects,
o unanticipated cancellation of contracts by operators without cause,
o breakdown of equipment and other operational problems,
o changes in competition, and
o other similar factors (some of which are discussed in documents referred
to in this Form 10-K/A).
Each forward-looking statement speaks only as of the date of this Form
10-K/A, and we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise. You should be aware that the occurrence of the events
described above and elsewhere in this Form 10-K/A could have a material adverse
effect on our business, results of operations and financial condition.
4
PART I
Item 1. BUSINESS
GENERAL DEVELOPMENT
Parker Drilling Company was incorporated in the state of Oklahoma in 1954
after having been established in 1934 by its founder, Gifford C. Parker. The
founder was the father of Robert L. Parker, chairman and a principal
stockholder, and the grandfather of Robert L. Parker Jr., president and chief
executive officer. In March 1976, the state of incorporation of the Company was
changed to Delaware through the merger of the Oklahoma Corporation into its
wholly owned subsidiary Parker Drilling Company, a Delaware corporation. Unless
otherwise indicated, the terms "Company," "we," "us," and "our," refers to
Parker Drilling Company together with its subsidiaries and "Parker Drilling"
refers solely to the parent, Parker Drilling Company. We make available free of
charge on our website at www.parkerdrilling.com, or on the Securities and
Exchange Commission website at www.sec.gov, our annual reports on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to
those reports as soon as reasonably practicable after we electronically file
such material with, or furnish to, the Securities and Exchange Commission.
OUR COMPANY
We are a leading worldwide provider of contract drilling and drilling
related services. Since beginning operations in 1934, we have operated in 55
foreign countries and the United States, making us among the most geographically
diverse drilling contractors in the world. Due to our extensive experience and
expertise in drilling difficult wells and operating in remote, harsh and
ecologically sensitive areas, operators look to us to provide oil and gas
exploration and development drilling around the world.
Our revenues are derived from three segments: international drilling, U.S.
drilling and rental tools.
o Our core international land drilling operations are focused
primarily in the Commonwealth of Independent States (former Soviet
Union referred to herein as "CIS") and the Asia Pacific region. Our
international offshore drilling operations are focused in the
transition zones, which are coastal waters that include lakes, bays,
rivers and marshes, of Nigeria and the Caspian Sea.
o Our core U.S. drilling operations are comprised of barge drilling in
the transition zones of the Gulf of Mexico.
o Through our subsidiary Quail Tools, we provide premium rental tools
that are used for land and offshore oil and gas drilling and
workover activities, serving major and independent oil and gas
exploration and production companies operating in the Gulf of
Mexico, West Texas and Rocky Mountain regions.
We also manage and provide labor resources for drilling rigs owned by
third parties, which are generally oil companies that prefer to own the rig
equipment but do not have the technical expertise or labor resources to operate
the rig.
5
OUR RIG FLEET
The diversity of our rig fleet, both in terms of geographic location and
asset class, enables us to provide a broad range of services to oil and gas
operators worldwide. As of June 30, 2003, our fleet of rigs available for
service consisted of:
o seven land rigs in the CIS, which include premium and specialized
deep drilling rigs capable of drilling to depths from 10,000 to
25,000 feet;
o two land rigs in the CIS, which are owned by AralParker, a joint
venture in which we own a 50 percent interest, both of which are
capable of drilling to depths of over 25,000 feet;
o 12 land rigs in the Asia Pacific region (one of which was in transit
to the region) and three land rigs in Africa and the Middle East;
o four barge drilling rigs in the transition zone waters of Nigeria;
o the world's largest arctic-class barge rig in the Caspian Sea; and
o 22 barge drilling and workover rigs in the transition zones of the
Gulf of Mexico, consisting of nine deep drilling rigs, five
intermediate drilling rigs and eight workover and shallow drilling
rigs.
In addition to the fleet of rigs we own that are available for service, we
also own non-core assets that are held for sale. As of June 30, 2003, our fleet
of rigs held for sale consisted of seven shallow water jackup rigs and four
offshore platform rigs, located in the Gulf of Mexico and 17 land rigs and
related inventory and spare parts located in Latin America. We have classified
these non-core assets as assets held for sale and their related operations as
discontinued operations.
OUR RENTAL TOOLS BUSINESS
Quail Tools, our rental tools business based in New Iberia, Louisiana, is
a provider of premium rental tools used for land and offshore oil and gas
drilling and workover activities. Quail Tools offers a full line of drill pipe,
drill collars, tubing, high- and low-pressure blowout preventers, choke
manifolds, casing scrapers, and junk and cement mills. Approximately two-thirds
of Quail Tools' equipment is utilized in offshore and coastal water operations.
Founded in 1978, Quail Tools was acquired by Parker Drilling in 1996. Quail
Tools' base of operations is a 55,000 square foot facility on a 15-acre complex
in New Iberia. Since we acquired Quail Tools, we have expanded operations with
the addition of a 44,000 square foot facility on an 11-acre complex in
Victoria, Texas, and a 10,000 square foot facility on nearly 10 acres in Odessa,
Texas, to serve a growing oil and gas market in that region. The newest
location, in Evanston, Wyoming, opened in the summer of 2002. Quail Tools'
principal customers are major and independent oil and gas exploration and
production companies operating in the Gulf of Mexico, West Texas and Rocky
Mountain regions.
OUR MARKET AREAS
Our core operations are subject to different industry trends depending on
location. International markets differ from the U.S. market in terms of
competition, nature of customers, equipment and experience requirements.
Although, the contract drilling industry is a competitive and cyclical business
characterized by high capital requirements and difficulty in finding and
retaining qualified field personnel, we believe that participants in this
industry typically generate substantial cash flows and economic returns during
cyclical peaks, such as the one experienced in 2001.
International Markets
The majority of the international drilling markets in which we operate
have one or more of the following characteristics: (i) a small number of
competitors; (ii) customers which typically are major, large independent or
foreign national oil companies; (iii) drilling programs in remote locations with
little infrastructure and/or harsh environments requiring specialized drilling
equipment with a large inventory of spare parts and other ancillary equipment;
and (iv) difficult (i.e., high pressure, deep, hazardous or geologically
challenging) wells requiring considerable experience to drill. Due to the long
lead time in the development and implementation of international drilling
projects, international markets are attractive to us because they usually allow
us to secure long-term contracts and higher dayrates when compared with drilling
operations in the U.S. Gulf of Mexico.
6
U.S. Gulf of Mexico
The drilling industry in the U.S. Gulf of Mexico is highly cyclical and is
typically driven by general economic activity and changes in actual or
anticipated oil and gas prices. Utilization and dayrates typically move in
conjunction with oil and gas prices. Assuming gas prices remain above historical
averages, we believe there should be increased exploration and development
drilling activity in the U.S. Gulf of Mexico. In addition, the United States
government has provided incentives for operators to develop deeper gas reserves.
We believe that these incentives will benefit the utilization of our barge rigs
that are capable of drilling deep gas wells, as well as our rental tools
business.
OUR STRATEGY
Our strategy is to maintain our position as a leading worldwide provider
of contract drilling and drilling related services while we seek to return to
profitability. Key elements in implementing our strategy include:
Significantly Reducing Our Debt and Enhancing Our Liquidity
Our goal is to reduce our debt by approximately $200.0 million. We intend
to accomplish this goal from cash currently on hand, cash generated from
operations and cash generated by the sale of non-core assets. An initial step in
our debt reduction plan was accomplished by the purchase of approximately $14.8
million of our 5.5% convertible notes due 2004 on the open market in May 2003,
which reduced the outstanding aggregate principal amount to $109.7 million as of
June 30, 2003.
We continue to actively pursue the sale of our non-core assets to further
enhance our debt reduction capabilities. We wrote down these assets to their
estimated fair value in the second quarter of 2003. These assets had a carrying
value of approximately $145.6 million as of June 30, 2003. We may also seek to
sell other assets.
We believe that our liquidity will be sufficient to repay our 5.5%
convertible notes on their stated maturity in August 2004. As of June 30, 2003,
after giving effect to the proposed offering of the $175.0 million of senior
notes, $50.0 million of borrowings under our proposed new term loan facility and
the application of the collective net proceeds therefrom to repurchase our
outstanding 9.75% senior notes, pay the related purchase price premium and
consent fees and pay the costs related to the $175.0 million of new senior notes
and the proposed new senior secured credit facility, we would have had
approximately $152.2 million of liquidity. This liquidity would have been
comprised of $62.9 million of cash on hand, $39.3 million of undrawn
availability under our new revolving credit facility (assuming the maximum
possible borrowing base of $50.0 million upon completion of the appraisal of our
rental tools equipment and deducting $10.7 million of outstanding letters of
credit) and $50.0 million of availability under our new delayed draw term loan
(which may only be used to repay our 5.5% convertible notes).
Increasing the Utilization of Our Barge and Land Rigs
One of our strategic objectives is to increase the utilization of our
barge and land rigs, which has been at historically low levels for the past 18
months. To achieve this objective we have restructured the management and
marketing for our various operating regions, including positioning our regional
managers to be more responsive to our customers by locating some of our
management and marketing personnel closer to our customers' key decision makers
and having each operating region accountable for its profitability. We have
also revised the compensation structure for many of our managers and marketing
personnel to provide them with incentives directly related to the profitability
of their operating region.
Controlling Our Costs and Minimizing Our Capital Expenditures
We continue to be vigilant in our efforts to conserve cash by reducing our
general and administrative expenses and limiting our capital expenditures. We
anticipate that general and administrative expenses will be reduced from $24.7
million in 2002 to less than $20.0 million in 2003 and our capital expenditures
will not exceed $50.0 million in 2003 . We reduced our general and
administrative expenses in the first six months of 2003 by reducing our
corporate workforce in 2002 and by limiting administrative costs and we will
continue to make reductions as appropriate for the level of our operations. Our
capital expenditure program calls for limiting expenditures to scheduled ongoing
maintenance projects, our preventive maintenance program and capital projects
that we believe have the potential to yield an attractive rate of return.
7
Pursuing Strategic Growth Opportunities
We intend to pursue selective strategic growth opportunities after we
complete a significant portion of our planned debt reduction and sales of
non-core assets.
OUR COMPETITIVE STRENGTHS
Our competitive strengths have historically contributed to our operating
performance and we believe the following strengths should enable us to
capitalize on future opportunities:
Geographically Diverse Operations and Assets
We currently operate in 15 countries and have operated in 55 foreign
countries and the United States since our founding in 1934, making us among the
most geographically diverse drilling contractors in the world. Our core
international land drilling operations focus primarily on the CIS, where we had
nine land rigs as of June 30, 2003, and the Asia Pacific region, where we had 12
land rigs (one of which was in transit to the region), including seven
helicopter transportable rigs, as of June 30, 2003. Our international offshore
drilling operations focus on the transition zones of Nigeria, where we have four
of the eight rigs in the market, and the Caspian Sea. We own and operate the
world's largest arctic-class barge rig in the Caspian Sea. We also have 22
drilling and workover barges in the transition zones of the Gulf of Mexico.
Significant Experience in Our Core International Markets
Our reputation and experience have led operators to look to us as a
pioneer for the exploration of oil and gas in new frontiers around the world. We
have been one of the pioneers in arctic drilling services and have considerable
experience with the technology required to drill in these ecologically sensitive
areas. Although originally developed for the North Slope of Alaska, this
technological expertise in arctic drilling is an asset to us in marketing our
services to operators in international markets with similar environmental
considerations, such as the Caspian Sea, Western Siberia and Sakhalin Island.
Our expertise in drilling deep, difficult wells, in addition to our arctic
experience, helped us become the first western drilling contractor to enter
Russia, in 1991, and Kazakhstan, which is now one of our most active markets, in
1993. We were the first western contract driller to enter China, in 1980, and
have continued to provide drilling services to this market.
Strong Market Position in the Transition Zones of the Gulf of Mexico
We are one of only two drilling companies with a significant presence in
the transition zones of the Gulf of Mexico. This area historically has been the
world's largest market for shallow water barge drilling, but in recent months
barge utilization and dayrates have been depressed despite relatively strong
natural gas prices. We believe that with 22 drilling and workover barges devoted
to this market we are well positioned to take advantage of opportunities as this
market recovers.
High Margin Rental Tool Business
Quail Tools, our rental tools business based in New Iberia, Louisiana, is
a provider of premium rental tools used for land and offshore oil and gas
drilling and workover activities. Quail Tools' principal customers are major and
independent oil and gas exploration and production companies. Quail Tools has
facilities in New Iberia, Louisiana; Victoria, Texas; Odessa, Texas and
Evanston, Wyoming.
Outstanding Safety Record
We believe that we have an outstanding safety record in the operation of
our barge and land rigs. Our safety record, as evidenced by our low total
recordable incidence rate, has been better than the industry average in each of
the last six years. Our safety record has contributed to our success in
obtaining drilling contracts, as well as contracts to manage and provide labor
resources to drilling rigs owned by third parties.
8
DRILLING OPERATIONS
International Barge Drilling
Our international barge drilling operations are focused in the transition
zones of Nigeria and the Caspian Sea. Barge rigs are utilized because of their
ability to carry drilling equipment on board and navigate in shallow waters up
to 25 feet where conventional jackup rigs are unable to operate. Although
commodity prices also affect demand for international drilling, international
markets typically are more attractive than U.S. markets because the increased
capital and equipment requirements usually allow contractors to secure long-term
contracts and higher dayrates when compared with drilling operations in the U.S.
Gulf of Mexico.
We are a leading provider of barge rigs in Nigeria, with four of the
eight rigs in this market. We have operated in Nigeria since 1996. However,
significant civil unrest in Nigeria has resulted in suspensions of drilling
operations on our working rigs in 2003. We also own and operate the world's
largest arctic-class barge rig in the Caspian Sea. The operator of this barge
rig has given notice of termination at the end of the contract's term in
September 2003. Although we anticipate that this rig will resume operating in
the future, we have not yet reached an agreement for its continued operation.
CIS
Nine of our rigs are currently located in the oil and gas producing
regions of the CIS. We were the first Western drilling contractor to enter this
market, in 1991, and it continues to be a major area of operations. Two of the
three rigs we leased to SaiPar B.V., the Company's joint venture with
Saipem, a drilling subsidiary of Eni S.p.A., in Kazakhstan's Karachaganak field,
were released from contract in 2002. In the Tengiz field in Kazakhstan, we
operate through AralParker, a joint venture with a local Kazakhstan company. In
November 2002, we received a notification from our customer that operations
would be suspended after completion of wells currently being drilled pending
resolution of funding issues among its partners. The suspension was lifted in
early 2003, resulting in minimal financial impact and negligible disruptions to
our drilling operations. In Russia, we had one rig under contract throughout
2002, and we mobilized a new rig to Sakhalin Island, which we designed,
constructed and sold to Exxon Neftegas Limited. Drilling operations under an
operations and maintenance contract with this customer commenced in June 2003.
U.S. Barge Drilling and Workover
The U.S. market for our barge drilling rigs is the transition zones of the
Gulf of Mexico, primarily in Louisiana and, to a lesser extent, Alabama and
Texas. This area historically has been the world's largest market for shallow
water barge drilling. With 22 drilling and workover barges, we are one of two
companies with a significant presence in this market.
Asia Pacific/Middle East/Africa
As of June 30, 2003, we had 12 land rigs located in the Asia Pacific
region (one of which was in transit to the region) two land rigs in Africa and
one land rig in the Middle East. Included are seven helicopter transportable
rigs which facilitate exploration in areas of difficult access, like the
mountainside and jungle terrain of Indonesia and Papua New Guinea.
Project Management
We are active in managing and providing labor resources for drilling rigs
owned by third parties. As of June 30, 2003, we manage drilling rigs owned by
third parties in China, Kazakhstan, Kuwait, New Zealand, Papua New Guinea and
Russia.
9
COMPETITION
The contract drilling industry is a competitive and cyclical business
characterized by high capital requirements and difficulty in finding and
retaining qualified field personnel.
In the Gulf of Mexico barge drilling and workover markets, we compete with
one major contractor. In the jackup and platform markets, there are numerous
U.S. offshore contractors. In international land markets, we compete with a
number of international drilling contractors but also with smaller local
contractors in certain markets. However, due to the high capital costs of
operating in international land markets as compared to the U.S. land market, the
high cost of mobilizing land rigs from one country to another, and the technical
expertise required, there are usually fewer competitors in international land
markets. In international land and offshore markets, experience in operating in
challenging environments and customer alliances have been factors in the
selection of us in certain cases, as well as our patented drilling equipment for
remote drilling projects. We believe that the market for drilling contracts,
both land and offshore, will continue to be highly competitive for the
foreseeable future. Certain competitors have greater financial resources than we
do, which may enable them to better withstand industry downturns, compete more
effectively on the basis of price, build new rigs or acquire existing rigs.
Our management believes that Quail Tools is one of the leading rental tool
companies in the offshore Gulf of Mexico and the Gulf Coast land markets. Some
of Quail Tools' competitors are substantially larger and have greater financial
resources than Quail Tools.
CUSTOMERS
We believe that we have developed a reputation for providing efficient,
safe, environmentally conscious and innovative drilling services. An increasing
trend indicates that a number of our customers have been seeking to establish
exploration or development drilling programs based on partnering relationships
or alliances with a limited number of preferred drilling contractors. Such
relationships or alliances can result in longer-term work and higher
efficiencies that increase profitability for drilling contractors at a lower
overall well cost for oil and gas operators. We are currently a preferred
contractor for operators in certain United States and international locations,
which our management believes is a result of our quality of equipment,
personnel, safety records, service and experience.
Our drilling and rental tool customer base consists of major, independent
and foreign-owned oil and gas companies. In 2002, ChevronTexaco Corporation,
Tengizchevroil, a consortium led by ChevronTexaco and including Exxon Mobil
Corporation, and Royal Dutch Shell accounted for approximately 17 percent, 13
percent and 10 percent, respectively, of our total revenues, including
discontinued operations. Our ten most significant customers collectively
accounted for approximately 66 percent of our total revenues in 2002, including
discontinued operations.
CONTRACTS
Most drilling contracts are awarded based on competitive bidding. The
rates specified in drilling contracts are generally on a dayrate basis, and vary
depending upon the rig employed, equipment and services supplied, geographic
location, term of the contract, competitive conditions and other variables. Our
contracts generally provide for a basic dayrate during drilling operations, with
lower rates or no payment for periods of equipment breakdown, adverse weather or
other conditions that may be beyond our control. When a rig mobilizes to or
demobilizes from an operating area, a contract may provide for different
dayrates, specified fixed payments or no payment during the mobilization or
demobilization. Some of our contracts may provide the customer with an option to
purchase the rig that is employed under the contract. Contracts to employ our
drilling rigs have a term based on a specified period of time or the time
required to drill a specified well or number of wells. The contract term in some
instances may be extended by the customer exercising options for the drilling of
additional wells or for an additional term, or by exercising a right of first
refusal. Most drilling contracts permit the customer to terminate the contract
at the customer's option without paying a termination fee. Due to various
reasons, including a change in market conditions, our customers may seek
renegotiation of drilling contracts to reduce their obligations or may seek to
suspend or terminate their contracts. Some contracts may be terminated by the
customer under various circumstances such as the loss or destruction of the
drilling unit or the suspension of drilling operations for a specified period of
time as a result of a breakdown of major equipment.
10
We generally receive a lump sum fee to move our equipment to the drilling
site, which in most cases approximates the cost incurred by us. U.S. contracts
are generally for one to three wells with options to drill additional wells,
while international contracts are more likely to be for multi-well long-term
programs.
Rental tool contracts are typically on a dayrate basis with rates based on
type of equipment, investment and competition.
INSURANCE AND INDEMNIFICATION
In our drilling contracts, we generally seek to obtain indemnification
from our customers for some of the risks related to our drilling services. To
the extent that we are unable to transfer such risks to customers by contract or
indemnification agreements, we generally seek protection through insurance. To
address the hazards inherent in our business, we maintain insurance coverage
that includes physical damage coverage, third party general liability insurance,
employer's liability, environmental and pollution coverage and other coverage.
We believe that our insurance coverage is customary for the industry and
adequate for our business. However, there is no assurance that such insurance
will adequately protect us against all liability from all of the consequences of
the hazards we may encounter in our drilling operations.
EMPLOYEES
The following table sets forth the composition of our employees as of
December 31, 2002 and December 31, 2001.
December 31,
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2002 2001
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International drilling operations 1,748 2,444
U.S. drilling operations 834 878
Rental tool operations 135 140
Corporate and other 181 192
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Total employees 2,898 3,654
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11
ENVIRONMENTAL CONSIDERATIONS
Our operations are subject to numerous federal, state local and foreign
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. Numerous governmental
agencies, such as the U.S. Environmental Protection Agency, or EPA, issue
regulations to implement and enforce such laws, which often require difficult
and costly compliance measures that carry substantial administrative, civil and
criminal penalties or may result in injunctive relief for failure to comply.
These laws and regulations may require the acquisition of a permit before
drilling commences, restrict the types, quantities and concentrations of various
substances that can be released into the environment in connection with drilling
and production activities, limit or prohibit construction or drilling activities
on certain lands lying within wilderness, wetlands, ecologically sensitive and
other protected areas, require remedial action to prevent pollution from former
operations, and impose substantial liabilities for pollution resulting from our
operations. Changes in environmental laws and regulations occur frequently, and
any changes that result in more stringent and costly compliance could adversely
affect our operations and financial position, as well as those of similarly
situated entities operating in the Gulf Coast market. While our management
believes that we are in substantial compliance with current applicable
environmental laws and regulations, there is no assurance that compliance can be
maintained in the future.
The drilling of oil and gas wells is subject to various federal, state,
local and foreign laws, rules and regulations. As an owner or operator of both
onshore and offshore facilities including mobile offshore drilling rigs in or
near waters of the United States, we may be liable for the costs of removal and
damages arising out of a pollution incident to the extent set forth in the
Federal Water Pollution Control Act, as amended by the Oil Pollution Act of
1990, or OPA, the Outer Continental Shelf Lands Act, or OCSLA, the Comprehensive
Environmental Response, Compensation and Liability Act, or CERCLA, and the
Resource Conservation and Recovery Act, or RCRA, each as amended from time to
time. In addition, we may also be subject to applicable state law and other
civil claims arising out of any such incident.
The OPA and regulations promulgated pursuant thereto impose a variety of
regulations on "responsible parties" related to the prevention of oil spills and
liability for damages resulting from such spills. A "responsible party" includes
the owner or operator of a vessel, pipeline or onshore facility, or the lessee
or permittee of the area in which an offshore facility is located. The OPA
assigns liability of oil removal costs and a variety of public and private
damages to each responsible party.
The liability for a mobile offshore drilling rig is determined by whether
the unit is functioning as a vessel or is in place and functioning as an
offshore facility. If operating as a vessel, liability limits of $600 per gross
ton or $500,000, whichever is greater, apply. If functioning as an offshore
facility, the mobile offshore drilling rig is considered a "tank vessel" for
spills of oil on or above the water surface, with liability limits of $1,200 per
gross ton or $10.0 million. To the extent damages and removal costs exceed this
amount, the mobile offshore drilling rig will be treated as an offshore facility
and the offshore lessee will be responsible up to higher liability limits for
all removal costs plus $75.0 million. A party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Few defenses exist to the
liability imposed by the OPA. The OPA also imposes ongoing requirements on a
responsible party, including proof of financial responsibility (to cover at
least some costs in a potential spill) and preparation of an oil spill
contingency plan for offshore facilities and vessels in excess of 300 gross
tons. Amendments to the OPA adopted in 1996 require owners and operators of
offshore facilities that have a worst case oil spill potential of more than
1,000 barrels to demonstrate financial responsibility in amounts ranging from
$10.0 million in specified state waters to $35.0 million in federal Outer
Continental Shelf waters, with higher amounts, up to $150.0 million, in certain
limited circumstances where the U.S. Minerals Management Service believes such a
level is justified by the risks posed by the quantity or quality of oil that is
handled by the facility. However, such OPA amendments did not reduce the amount
of financial responsibility required for "tank vessels." Since our offshore
drilling rigs are typically classified as tank vessels, the recent amendments to
the OPA are not expected to have a significant effect on our operations. A
failure to comply with ongoing requirements or inadequate cooperation in a spill
may even subject a responsible party to civil or criminal enforcement actions.
12
In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
Outer Continental Shelf. Specific design and operational standards may apply to
Outer Continental Shelf vessels, rigs, platforms, vehicles and structures.
Violations of environmentally related lease conditions or regulations issued
pursuant to the OCSLA can result in substantial civil and criminal penalties as
well as potential court injunctions curtailing operations and the cancellation
of leases. Such enforcement liabilities can result from either governmental or
citizen prosecution.
All of our operating U.S. barge drilling rigs have zero-discharge
capabilities as required by law. In addition, in recognition of environmental
concerns regarding dredging of inland waters and permitting requirements, we
conduct negligible dredging operations, with approximately two-thirds of our
offshore drilling contracts involving directional drilling, which minimizes the
need for dredging. However, the existence of such laws and regulations has had
and will continue to have a restrictive effect on us and our customers.
CERCLA, also known as "Superfund," and comparable state laws impose
liability without regard to fault or the legality of the original conduct, on
certain classes of persons who are considered to be responsible for the release
of a "hazardous substance" into the environment. While CERCLA exempts crude oil
from the definition of hazardous substances for purposes of the statute, our
operations may involve the use or handling of other materials that may be
classified as hazardous substances. CERCLA assigns strict liability to each
responsible party for all response and remediation costs, as well as natural
resource damages. Few defenses exist to the liability imposed by CERCLA. We have
received an information request under CERCLA designating a potentially
responsible party with respect to a Superfund site in Freeport, Texas. We are
currently evaluating our relationship to the site and have not yet estimated the
amount or impact on our operations or financial position of any costs related to
the site.
RCRA generally does not regulate most wastes generated by the exploration
and production of oil and gas. RCRA specifically excludes from the definition of
hazardous waste "drilling fluids, produced waters, and other wastes associated
with the exploration, development, or production of crude oil, natural gas or
geothermal energy." However, these wastes may be regulated by EPA or state
agencies as solid waste. Moreover, ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes, and waste oils, may be regulated as
hazardous waste. Although the costs of managing solid and hazardous wastes may
be significant, we do not expect to experience more burdensome costs than
similarly situated companies involved in drilling operations in the Gulf Coast
market.
The drilling industry is dependent on the demand for services from the oil
and gas exploration and development industry, and accordingly, is affected by
changes in laws relating to the energy business. Our business is affected
generally by political developments and by federal, state, local and foreign
regulations that may relate directly to the oil and gas industry. The adoption
of laws and regulations, both U.S. and foreign, that curtail exploration and
development drilling for oil and gas for economic, environmental and other
policy reasons may adversely affect our operations by limiting available
drilling opportunities.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The Company operates in three segments, U.S. drilling operations,
international drilling operations and rental tools. Information about the
Company's business segments and operations by geographic areas for the years
ended December 31, 2002, 2001 and 2000 is set forth in Note 11 in the notes to
the consolidated financial statements.
13
Item 2. PROPERTIES
We lease office space in Houston for our corporate headquarters.
Additionally, we own and lease office space and operating facilities in various
locations, but only to the extent necessary for administrative and operational
support functions. We own a ten-story building in Tulsa, Oklahoma, our previous
corporate headquarters, which is vacant and classified as an asset held for
sale.
Land Rigs
The following table shows, as of June 30, 2003, the locations and drilling
depth ratings of our land rigs available for service. Eight of these rigs were
under contract and the remainder were available for contract as of June 30,
2003.
Drilling Depth Rating in Feet
-----------------------------------------
10,000 10,000 Over
Region or less to 25000 25,000 Total
- -------------------------- ------- -------- ------ -----
Asia Pacific 3 9 -- 12
CIS (1) 2 4 3 9
Africa 1 1 -- 2
Middle East (2) -- 1 -- 1
------- ------- ------- -------
Total 6 15 3 24
======= ======= ======= =======
(1) Two of these rigs are owned by AralParker.
(2) This rig is being moved to Turkmenistan.
In addition, we have six land rigs in the Asia Pacific region classified
as cold stacked which would need to be refurbished at a significant cost before
being placed back into service.
14
Barge Rigs
A schedule of our deep, intermediate, and workover and shallow drilling
barge rigs located in the Gulf of Mexico as of June 30, 2003, nine of which were
under contract and the remainder of which were available for contract as of June
30, 2003, is set forth below:
Year Built Maximum
or Last Drilling
U.S. Horsepower Refurbished Depth (Feet)
- ------------------------------ ---------- ----------- ------------
Deep drilling:
Rig No. 15 1,000 1998 15,000
Rig No. 50 2,000 2001 25,000
Rig No. 51 2,000 1993 25,000
Rig No. 53 1,600 1995 20,000
Rig No. 54 2,000 1995 25,000
Rig No. 55 2,000 2001 25,000
Rig No. 56 2,000 1992 25,000
Rig No. 57 1,500 1997 20,000
Rig No. 76 3,000 1997 30,000
Intermediate drilling:
Rig No. 8 1,000 1995 14,000
Rig No. 17 1,000 1993 13,000
Rig No. 20 1,000 2001 12,500
Rig No. 21 1,200 2001 13,000
Rig No. 23 1,000 1993 11,500
Workover and shallow drilling:
Rig No. 6 (1) 700 1995 -
Rig No. 9 (1) 650 1996 -
Rig No. 12 1,100 1990 14,000
Rig No. 16 800 1994 8,500
Rig No. 18 800 1993 8,500
Rig No. 24 1,000 1992 11,500
Rig No. 25 1,000 1993 11,500
Rig No. 26 (1) 650 1996 -
(1) Workover rig.
15
A schedule of our international deep drilling barges as of June 30, 2003,
four of which were under contract and one of which was available for contract
as of June 30, 2003, is set forth below:
Year Built Maximum
or Last Drilling
International Horsepower Refurbished Depth (Feet)
- ------------- ---------- ----------- ------------
Nigeria:
Rig No. 72 3,000 2002 30,000
Rig No. 73 3,000 2002 30,000
Rig No. 74(1) 3,000 1997 30,000
Rig No. 75 3,000 1999 30,000
Caspian Sea:
Rig No. 257 3,000 1999 30,000
(1) This rig has been evacuated due to community unrest in Nigeria.
16
The following table presents our utilization rates and rigs available for
service for the years ended December 31, 2002 and 2001.
Year Ended
December 31,
-------------------
Transition Zone Rig Data 2002 2001
- ------------------------------------------------------ ---- ----
U.S. barge deep drilling:
Rigs available for service (1) 9.0 9.0
Utilization rate of rigs available for service (2) 78% 93%
U.S. barge intermediate drilling:
Rigs available for service (1) 5.0 5.0
Utilization rate of rigs available for service (2) 38% 80%
U.S. barge workover and shallow drilling:
Rigs available for service (1) 8.0 8.0
Utilization rate of rigs available for service (2) 32% 53%
International barge drilling:
Rigs available for service (1) 5.0 5.0
Utilization rate of rigs available for service (2) 85% 97%
International Land Rig Data
- ------------------------------------------------------
Rigs available for service (1): 41.0 41.0
Utilization rate of rigs available for service (2): 42% 49%
(1) The number of rigs available for service is determined by calculating the
number of days each rig was in our fleet and was under contract or
available for contract. For example, a rig under contract or available for
contract for six months of a year is 0.5 rigs available for service for
such year. Rigs available for service exclude rigs classified as assets
held for sale. Our method of computation of rigs available for service may
or may not be comparable to other similarly titled measures of other
companies.
(2) Rig utilization rates are based on a weighted average basis assuming 365
days availability for all rigs available for service. Rigs acquired or
disposed of are treated as added to or removed from the rig fleet as of
the date of acquisition or disposal. Rigs that are in operation or fully
or partially staffed and on a revenue-producing standby status are
considered to be utilized. Rigs under contract that generate revenues
during moves between locations or during mobilization or demobilization
are also considered to be utilized. Our method of computation of rig
utilization may or may not be comparable to other similarly titled
measures of other companies.
17
Assets Related to Discontinued Operations
We are currently attempting to sell a number of rigs and have therefore
classified them as assets held for sale. As of June 30, 2003, these rigs
consisted of the following:
Land Rigs
Drilling Depth Rating in Feet
--------------------------------------------
10,000 10,000 Over
or less to 25000 25,000 Total
------- -------- ------ -----
Latin America - 12 (1) 5 17
(1) One of these rigs was sold in July 2003.
Platform Rigs
Year Built Maximum
or Last Drilling
U.S. Horsepower Refurbished Depth (Feet)
- -------------- ---------- ----------- ------------
Rig No. 2 1,000 1981 12,000
Rig No. 3 1,000 1995 12,000
Rig No. 10 (1) 650 1982 -
Rig No. 41 1,000 1997 12,500
(1) Workover rig.
Jackup Rigs
Maximum Maximum
Water Drilling
U.S. Design (1) Depth (Feet) Depth (Feet)
- -------------- ------------------------------ ------------ ------------
Rig No. 11 (2) Bethlehem JU-200 (MC) 200 -
Rig No. 14 (3) Baker Marine Big Foot (IS) 85 20,000
Rig No. 15 Baker Marine Big Foot III (IS) 100 20,000
Rig No. 20 Bethlehem JU-100 (MC) 110 25,000
Rig No. 21 Baker Marine BMC-125 (MC) 120 20,000
Rig No. 22 Le Tourneau Class 51 (MC) 173 15,000
Rig No. 25 Le Tourneau Class 150-44 (IC) 215 20,000
(1) IC -- independent leg, cantilevered; IS -- independent leg, slot; MC --
mat-supported, cantilevered.
(2) Workover rig.
(3) In September 2003, a malfunction caused this rig to become partially
submerged in the water. We are currently assessing the damage to the rig.
18
Item 3. LEGAL PROCEEDINGS
We are a party to certain legal proceedings that have resulted from the
ordinary conduct of our business. In the opinion of our management, none of
these proceedings is expected to have a material adverse effect on us.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS OK
There were no matters submitted to Parker Drilling Company security
holders during the fourth quarter of 2002.
Item 4A. EXECUTIVE OFFICERS
Officers are elected each year by the board of directors following the
annual meeting for a term of one year and until the election and qualification
of their successors. The current executive officers of the Company and their
ages, positions with the Company and business experience are presented below:
(1) Robert L. Parker, 79, chairman, joined Parker Drilling in 1948
and was elected vice president in 1950. He was elected
president in 1954 and chief executive officer and chairman in
1969. Since 1991, he has held only the position of chairman.
(2) Robert L. Parker Jr., 54, president and chief executive
officer, joined Parker Drilling in 1973 as a contract
representative and was named manager of U.S. operations later
in 1973. He was elected a vice president in 1973, executive
vice president in 1976 and was named president and chief
operating officer in October 1977. In December 1991, he was
elected chief executive officer. He has been a director since
1973.
(3) Robert F. Nash, 59, senior vice president and chief operating
officer, joined Parker Drilling in November 2001. Mr. Nash
joined us following a 26-year career with Halliburton, during
which time he held numerous senior management positions with
responsibility for operations, technical development,
manufacturing, procurement, inventory management and sales and
marketing. He also has considerable experience with mergers,
acquisitions, divestitures and reorganizations.
(4) James W. Whalen, 61, senior vice president and chief financial
officer, joined Parker Drilling in October 2002. Mr. Whalen
served as chief commercial officer for Coral Energy from
February 1998 through January 2000. From August 1992 until
February 1998, he served as chief financial officer for Tejas
Gas Corporation. From August 1981 until August 1992, he held
several executive positions at Coastal Corporation including
senior vice president, finance.
(5) W. Kirk Brassfield, 47, vice president and corporate
controller, joined Parker Drilling in March 1998 as corporate
controller and chief accounting officer. From 1991 through
March 1998, Mr. Brassfield served in various positions,
including subsidiary controller and director of financial
planning of MAPCO Inc., a diversified energy company. From
1979 through 1991, Mr. Brassfield served at the public
accounting firm, KPMG.
(6) John R. Gass, 51, vice president of operations, joined Parker
Drilling in 1977 and has served in various management
positions in our international divisions. In 1985, he became
the division manager of Africa and the Middle East. In 1987,
he directed our core drilling operations in South Africa. In
1989, he was promoted to international contract manager. He
was elected vice president, frontier areas in January 1996,
and vice president of sales and contracts in March 1999. He
assumed his current position in September 2003.
19
(7) Denis Graham, 53, vice president of engineering, joined Parker
Drilling in 2000. Mr. Graham was previously the senior vice
president of technical services for Diamond Offshore Inc., an
international offshore drilling contractor. His experience
with Diamond Offshore ranged from 1978 through 1999 in the
areas of offshore drilling rig design, new construction,
conversions, marine operations, maintenance and regulatory
compliance.
(8) Ronald C. Potter, 50, vice president and general counsel,
re-joined Parker Drilling in June 2003. From 2001 through May
2003, Mr. Potter was our outside legal counsel as a
shareholder of Conner & Winters, P.C. in Tulsa, Oklahoma. From
1980 to 2001, he served Parker Drilling in various positions,
most recently as chief legal counsel and corporate secretary.
OTHER PARKER DRILLING COMPANY OFFICER
(9) David W. Tucker, 47, treasurer and director of investor
relations, joined the Company in 1978 as a financial analyst
and served in various financial and accounting positions
before being named chief financial officer of the Company's
wholly owned subsidiary, Hercules Offshore Corporation, in
February 1998. Mr. Tucker was elected treasurer in 1999 and
assumed the responsibilities of director of investor relations
in 2002.
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Parker Drilling Company common stock is listed for trading on the New York
Stock Exchange under the symbol "PKD". At the close of business on December 31,
2002, there were 2,790 holders of record of Parker Drilling common stock. Prices
on Parker Drilling's common stock for the years ended December 31, 2002 and
2001, were as follows:
2003 2002 2001
---------------- ----------------- -----------------
Quarter High Low High Low High Low
- ------- ------ ------ ------ ------ ------ ------
First $ 2.56 $ 1.91 $ 4.82 $ 3.10 $ 7.53 $ 4.75
Second 3.12 1.83 4.74 2.95 7.40 5.21
Third - - 3.50 1.40 6.29 2.25
Fourth - - 2.65 1.73 4.07 2.56
No dividends have been paid on common stock since February 1987.
Restrictions contained in Parker Drilling's existing bank revolving loan
facility prohibit the payment of dividends and the indenture for the Senior
Notes restricts the payment of dividends. The Company has no present intention
to pay dividends on its common stock in the foreseeable future because of the
restrictions noted.
20
Item 6. SELECTED FINANCIAL DATA (Dollars in Thousands)
The following tables present selected historical consolidated financial
data derived from the audited financial statements of Parker Drilling for the
years ended December 31, 2002, 2001, 2000 and 1999, the four months ended
December 31, 1998 and the fiscal year ended August 31, 1998. In June 2003, our
board of directors approved a plan to sell our non-core assets, which included,
as of June 30, 2003, our Latin American assets, consisting of 17 land rigs and
related inventory and spare parts, and our U.S. offshore assets, consisting of
seven jackup and four platform rigs. The two operations that constitute this
plan of disposition meet the requirements of discontinued operations under the
provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." Accordingly, our consolidated financial statements for the
years ended December 31, 2002, 2001, 2000 and 1999, the four months ended
December 31, 1998 and the fiscal year ended August 31, 1998 have been
reclassified to present our Latin America operations and our U.S. jackup and
platform drilling operations as discontinued operations. The financial data for
the year ended December 31, 2000 have also been reclassified to reflect the
adoption of SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No.
64, Amendment of FASB Statement No. 13, and Technical Corrections," which
resulted in the reclassification of the extraordinary gain on early
extinguishment of debt to other income and the related deferred taxes to income
tax expense. The following financial data should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements and related notes appearing elsewhere
in this Form 10-K/A.
Year Ended December 31,
-------------------------------------------------------
2002 2001 2000 1999
---------- ---------- ---------- ----------
Drilling and rental revenues:
U.S. drilling $ 74,181 $ 114,377 $ 85,539 $ 74,990
International drilling 188,514 177,464 126,633 108,591
Rental tools 47,510 65,629 42,833 27,656
---------- ---------- ---------- ----------
Total drilling and rental revenues 310,205 357,470 255,005 211,237
---------- ---------- ---------- ----------
Total drilling and rental operating expenses 252,362 267,746 220,714 200,911
---------- ---------- ---------- ----------
Drilling and rental operating income 57,843 89,724 34,291 10,326
Construction contract operating income 2,462 -- -- --
General and administration expense 24,728 21,721 20,392 16,312
Provision for reduction in carrying
value of certain assets and reorganization expense 1,140 7,500 7,805 11,005
---------- ---------- ---------- ----------
Total operating income 34,437 60,503 6,094 (16,991)
---------- ---------- ---------- ----------
Other income and (expense):
Interest expense (52,409) (53,015) (57,036) (55,928)
Other income (expense), net (143) 4,926 34,466 41,743
---------- ---------- ---------- ----------
Total other income and (expense) (52,552) (48,089) (22,570) (14,185)
---------- ---------- ---------- ----------
Income (loss) before income taxes (18,115) 12,414 (16,476) (31,176)
Income tax expense (benefit) (2,836) 11,429 (218) (2,760)
---------- ---------- ---------- ----------
Income (loss) from continuing operations (15,279) 985 (16,258) (28,416)
Discontinued operations, net of taxes (25,631) 10,074 (2,787) (9,481)
Cumulative effect of change in accounting principle (73,144) -- -- --
---------- ---------- ---------- ----------
Net income (loss) $ (114,054) $ 11,059 $ (19,045) $ (37,897)
========== ========== ========== ==========
Four Months Year
Ended Ended
December 31, August 31,
1998 1998
------------ ------------
Drilling and rental revenues:
U.S. drilling $ 33,223 $ 142,080
International drilling 40,428 135,721
Rental tools 10,245 32,723
------------ ------------
Total drilling and rental revenues 83,896 310,524
------------ ------------
Total drilling and rental operating expenses 76,403 249,248
------------ ------------
Drilling and rental operating income 7,493 61,276
General and administration expense 5,904 17,273
------------ ------------
Total operating income 1,589 44,003
------------ ------------
Other income and (expense):
Interest expense (17,427) (49,389)
Other income (expense), net 741 9,864
------------ ------------
Total other income and (expense) (16,686) (39,525)
------------ ------------
Income (loss) before income taxes (15,097) 4,478
Income tax expense (benefit) (1,716) 9,605
------------ ------------
Income (loss) from continuing operations (13,381) (5,127)
Discontinued operations, net of taxes (1,252) 33,219
------------ ------------
Net income (loss) $ (14,633) $ 28,092
============ ============
21
Item 6. SELECTED FINANCIAL DATA (Dollars in Thousands) (continued)
<Table>
<Caption>
Four Fiscal
Months Year
Year Ended December 31, Ended Ended
----------------------------------------------- December 31, August 31,
2002 2001 2000 1999 1998 1998
-------- ---------- ---------- ---------- ------------ ----------
BALANCE SHEET DATA:
Cash and cash equivalents $ 51,982 $ 60,400 $ 62,480 $ 45,501 $ 24,314 $ 45,254
Property, plant and equipment, net 641,278 695,529 663,525 661,402 729,873 727,840
Assets held for sale 896 1,800 6,860 17,063 11,010 8,118
Total assets 953,325 1,105,777 1,107,419 1,082,743 1,159,326 1,200,544
Total long-term debt, including
current portion 589,930 592,172 597,627 653,631 661,883 651,559
Stockholders' equity $300,626 $ 412,143 $ 399,163 $ 329,421 $ 363,950 $ 377,962
</Table>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
Outlook and Overview
The year 2002 was marked by an overall decline in rig activity and cash
flow for the Company. We incurred a net loss from continuing operations of $15.3
million before the cumulative effect of the change in accounting principle,
compared to net income from continuing operations of $1.0 million in 2001. Rig
utilization, dayrates and rental activity decreased substantially in the our
Gulf of Mexico drilling markets, continuing a trend that started in the fourth
quarter of 2001. The Company's international markets began to improve late in
2001, experiencing significantly higher utilization in the fourth quarter, most
notably in the Asia Pacific region and Kazakhstan; however, these gains were
partially offset by downtime due to barge rig inspections and refurbishments in
Nigeria.
The financial results for the first half of 2003 continued to reflect the
current depressed conditions in most drilling markets. Despite high utilization
for jackup rigs in the Gulf of Mexico, the dayrates for jackups and barges in
this market continue to remain at depressed levels. Utilization for
international land drilling operations, while ending its downward trend that
began during the second quarter of 2002, remains at depressed levels. Our rental
tool business has responded favorably to the recent increase in activity in the
Gulf of Mexico.
Dayrates in the Gulf of Mexico drilling market were depressed during the
first half of 2003 despite natural gas prices remaining at historically high
levels during the period. We believe this can be attributed to several factors,
including: operators addressing debt reduction issues, lack of acceptable well
prospects for major oil companies and funding issues for independent operators.
Although our jackup utilization increased from 75 percent in the first quarter
of 2003 to 82 percent in the second quarter of 2003, our jackup dayrates
decreased during the same period. Barge drilling activity results were more
predictable for the current operating environment with barge utilization and
dayrates declining during the second quarter of 2003 when compared with the
first quarter of 2003, despite a brief increase in activity during May and June
2003. We anticipate that the Gulf of Mexico barge drilling market will remain
flat throughout the third quarter of 2003 and most likely into the fourth
quarter of 2003, but we anticipate utilization and dayrates should begin to
increase during the first quarter of 2004 if natural gas prices remain at
current levels.
22
Gross margins in our rental tool business in the Gulf of Mexico increased
during the first half of 2003 when compared to the first half of 2002.
Contributing to the increases has been the opening of Quail Tools' new Evanston,
Wyoming operation that continues to establish a solid customer base. Our outlook
for the rental tools business for the remainder of 2003 is positive, and we
anticipate that the year over year growth for the remainder of 2003 will equal
or exceed that of the first two quarters of 2003.
The Commonwealth of Independent States (former Soviet Union, referred to
herein as "CIS") is our leading market of international land operations. In
addition to our established operations in Kazakhstan and Russia, one of our
subsidiaries, in cooperation with Calik Enerji, A.S., has recently signed a
three-year, two rig contract to provide drilling services to Turkmenneft State
Concern in Turkmenistan. Our remaining international land operations showed
little signs of improvement during the second quarter of 2003 due primarily to
our Asia Pacific operation. However, we expect this area to improve during the
third and fourth quarters of 2003 as a result of a recent contract extension in
Indonesia, two new contracts in New Zealand and a new contract in Bangladesh.
The new contracts in New Zealand and Bangladesh are anticipated to last from
nine to twelve months. As bidding activity increases in the Asia Pacific market,
we are hopeful that this market will continue to grow. We are also continuing
our pursuit of opportunities to increase our presence in Russia through, among
other means, alliances with operators who are making long-term investments.
International barge drilling was negatively impacted during the first half
of 2003 by continued community unrest in Nigeria that has resulted in the
shutdown and evacuation of one barge rig since March 2003. We are unable to
access, evaluate and repair any damage to the evacuated barge rig due to the
ongoing community unrest. Although we believe that any damage to this rig will
be covered by our insurance policy, under the terms of our insurance coverage we
are responsible for the first $250,000 of the cost of repairs plus 20 percent of
the cost of repairs in excess of $250,000. We have estimated the total
cost of repairing the damage to the rig to be approximately $7.5 million.
Accordingly, we recorded a charge of approximately $1.7 million in the three
months ended June 30, 2003, to account for the portion of the estimated repair
costs that will not be covered by insurance. The operator of our barge rig
operation in the Caspian Sea has given notice of termination at the end of the
contract's four-year term in September 2003. Although we anticipate that this
rig will resume operating in the future, we do not expect any increase in our
international barge drilling operations in the near term.
In June 2003, our board of directors approved a plan to sell our non-core
assets to generate funds to enhance our debt reduction capabilities. As of June
30, 2003, our fleet of rigs held for sale consisted of seven shallow water
jackup rigs and four offshore platform rigs located in the Gulf of Mexico and 17
land rigs and related inventory and spare parts located in Latin America. In
July 2003, we sold one of our Latin American land rigs. We identified these
assets for sale based on the relatively low utilization rates of the land rigs
and platform rigs and the wide fluctuations in the dayrates for the jackup rigs.
The operations that constitute this plan of disposition meet the requirements of
discontinued operations under the provisions of Statement of Financial
Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." Accordingly, our consolidated financial
statements for the six months ended June 30, 2002 and the years ended December
31, 2002, 2001 and 2000 have been reclassified to present our Latin America
operations and our U.S. jackup and platform drilling operations as discontinued
operations. The assets held for sale have been written down to their estimated
fair value, resulting in a non-cash impairment charge of $54.0 million
recognized in the second quarter of 2003. We will continue to report separately
the results of operations of these discontinued operations until the closing of
the actual sales.
Our goal is to reduce our debt by approximately $200.0 million. We intend
to accomplish this goal from cash currently on hand, cash generated from
operations and cash generated by the sale of our non-core assets. An initial
step in our debt reduction plan was accomplished by the purchase of
approximately $14.8 million of our 5.5% convertible notes due 2004 on the open
market in May 2003, which reduced the outstanding aggregate principal amount to
approximately $109.7 million as of June 30, 2003. The convertible notes mature
on August 1, 2004.
23
We continue to be vigilant in our efforts to conserve cash by reducing our
general and administrative expenses and limiting our capital expenditures. We
anticipate that general and administrative expenses will be reduced from $24.7
million in 2002 to less than $20.0 million in 2003 and our capital expenditures
will not exceed $50.0 million in 2003. We reduced our general and administrative
expenses in the first six months of 2003 by reducing our corporate workforce in
2002 and by limiting administrative costs and we will continue to make
reductions as appropriate for the level of our operations. Our capital
expenditure program calls for limiting expenditures to scheduled ongoing
maintenance projects, our preventive maintenance program and capital projects
that we believe have the potential to yield an attractive rate of return.
We currently project a net loss from continuing operations for the year
ending December 31, 2003, of approximately $0.38 to $0.42 per share of common
stock. This projection takes into consideration the estimated fees and expenses
payable by us related to the proposed offering of the new senior notes, the
proposed new senior secured credit facility, the tender offer and consent
solicitation related to the 9.75% senior notes and the consent solicitation
related to the 10.125% senior notes and the purchase price premium and costs
related to the tender offer for our 9.75% senior notes. Certain of these
estimated fees and expenses of indebtedness will be capitalized as debt issuance
cost and amortized over the life of the new debt. This projection also takes
into consideration the slower than anticipated market reaction to increases in
commodity prices that continue to affect a number of our drilling markets.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
We recorded a loss from continuing operations of $15.3 million, for the
year ended December 31, 2002 before discontinued operations and the cumulative
effect of a change in accounting principle, compared to income from continuing
operations of $1.0 million for the year ended December 31, 2001. We recorded a
loss from discontinued operations of $25.6 million for the year ended December
31, 2002 as compared to income from discontinued operations of $10.1 million for
2001. The change in accounting principle related to our adoption of Statement of
Financial Accounting Standards, or SFAS, No. 142, "Goodwill and Other Intangible
Assets." resulted in recording the impairment of goodwill, effective the first
quarter of 2002, in the amount of $73.1 million.
Year Ended December 31,
------------------------------------------
2002 2001
------------------ ------------------
Drilling and rental revenues: (Dollars in Thousands)
U.S. drilling $ 74,181 24% $114,377 32%
International drilling 188,514 61% 177,464 50%
Rental tools 47,510 15% 65,629 18%
-------- -------- -------- --------
Total drilling and rental revenues $310,205 100% $357,470 100%
======== ======== ======== ========
Our revenues decreased $47.3 million from $357.5 million in 2001 to $310.2
million for the year ended December 31, 2002. This reduction in revenues was
attributed to reduced drilling activity world-wide, most notably in the Gulf of
Mexico, due to the economic downturn in the United States and increased
inventories of oil and natural gas.
U.S. barge drilling revenues decreased $40.2 million in 2002 to $74.2
million due primarily to decreased dayrates and reduced utilization. The Gulf of
Mexico market declined significantly during the fourth quarter of 2001 and
continued throughout 2002 due primarily to a reduction in drilling activity by
operators. This reduction in drilling activity was in response to declining
demand and prices for natural gas and the economic recession in the United
States that began during mid-2001. Although prices for natural gas had risen,
uncertainty regarding the economy and international issues had caused operators
to be hesitant to significantly increase drilling in 2002. Utilization for the
barge rigs decreased from 76 percent in 2001 to 49 percent in 2002 with a 10
percent decrease in dayrates.
24
International drilling revenues increased $11.0 million to $188.5 million
in 2002 as compared to 2001. International land drilling revenues increased
$17.7 million to $115.2 million during 2002 as compared to 2001. International
land drilling revenues in the CIS region increased $10.3 million in 2002.
Revenues increased $7.4 million in our Tengiz operations in 2002 as compared to
2001 primarily due to increased utilization. Revenues from our interest in
SaiPar increased $6.2 million due to increased rig lease rates in 2002 and from
early termination fees for the two rigs released by the operator in July and
December 2002. The early termination fees totaled $3.7 million. Revenues
increased in the Asia Pacific region by $6.1 million related primarily to
increased utilization and dayrates in Papua New Guinea. Additionally, we
increased the number of labor contracts in Kuwait from two rigs in 2001 to six
rigs in 2002 resulting in additional revenues of $1.4 million.
International offshore drilling revenues decreased $6.7 million to $73.4
million when compared to 2001, primarily attributable to Nigeria. During the
second and third quarters, two of our four barge rigs operating in Nigeria
incurred downtime for required American Bureau of Shipping inspections and
repairs that resulted in a combined total of five months with no revenues.
Shortly after returning to work the drilling contracts for these two barge rigs
concluded and only one contract was subsequently renewed. At December 31, 2002,
three of the four barge rigs were drilling.
Rental tool revenues decreased $18.1 million due to the decline in
drilling activity in the Gulf of Mexico and decreased land drilling in West
Texas, which reduced the demand for rental tools. Revenues decreased $9.1
million in the New Iberia, Louisiana operations, $6.6 million in the Victoria,
Texas, operations and $3.2 million from the Odessa, Texas, operations. Quail
Tools opened a new operation in Evanston, Wyoming, in July, 2002 which
contributed $0.8 million in revenues in 2002.
Year Ended December 31,
----------------------------------
2002 2001
--------------- ---------------
Drilling and rental operating income: (Dollars in Thousands)
U.S. drilling (1) $ 25,855 35% $ 50,653 44%
International drilling (1) 74,242 39% 64,336 36%
Rental tools (1) 25,700 54% 42,624 65%
Depreciation and amortization (67,954) (67,889)
-------- --------
Total drilling and rental operating income (2) $ 57,843 $ 89,724
======== ========
Construction contract operating income 2,462 --
General and administrative expense (24,728) (21,721)
Provision for reduction in carrying
value of certain assets (1,140) --
Reorganization expense -- (7,500)
-------- --------
Total operating income $ 34,437 $ 60,503
======== ========
(1) Drilling and rental gross margin - drilling and rental revenues less
direct drilling and rental operating expenses, excluding depreciation and
amortization expense; drilling and rental gross margin percentages -
drilling and rental gross margin as a percent of drilling and rental
revenues.
(2) Drilling and rental operating income - drilling and rental revenues less
direct drilling and rental operating expenses including depreciation and
amortization expense.
25
Drilling and rental operating income of $57.8 million in 2002 reflects a
decrease of $31.9 million from the $89.7 million recognized during the year
ended December 31, 2001. The U.S. and international drilling segments recorded
gross margin percentages of 35 percent and 39 percent, respectively, in 2002 as
compared to 44 percent and 36 percent in 2001. U.S. gross margins decreased
$24.8 million to $25.9 million for the year ended December 31, 2002 due to
declining revenues as discussed above. In response to declining revenues, U.S.
operations instituted cost controls for labor, materials and supplies. As a
result, the gross margin percentage increased during the fourth quarter to 39
percent from 36 percent during the third quarter on comparable revenues.
International drilling gross margin increased $9.9 million to $74.2
million during the year ended December 31, 2002 as compared to 2001.
International land drilling gross margin increased $13.9 million to $48.7
million. Gross margin in the CIS region increased $11.4 million with Kazakhstan
and Russia operations each increasing gross margin by approximately $5.7
million. The Kazakhstan increase was primarily attributable to increased
utilization in the Tengiz field and the early termination fees received for the
two rigs released that were previously operating in the Karachaganak field. The
gross margin increase in Russia was due to higher than anticipated mobilization
and start up costs incurred in 2001 that resulted in a significant loss. Asia
Pacific region gross margin increased $2.5 million to $17.5 million during 2002.
Improvement in Asia Pacific is primarily related to increased revenues in Papua
New Guinea that resulted in increased gross margin of $2.3 million.
International offshore drilling gross margins decreased $4.0 million to $25.5
million during 2002. This decrease in gross margin is primarily attributed to
Nigeria where two of the four barge rigs incurred a combined total of five
months downtime during the second and third quarters due to ABS inspections and
repairs. In addition, these two rigs both completed their respective contracts
toward the end of the third quarter and only one contract was renewed in the
fourth quarter.
Rental tool gross margin decreased $16.9 million to $25.7 million during
2002 as compared to the year ended December 31, 2001. Gross margin decreased
primarily due to the $18.1 million decline in revenues during 2002. The gross
margin percentage decreased during 2002 to 54 percent from 65 percent for 2001
due to the significant fixed costs related to the rental tool operation.
During the first quarter of 2002, we announced a new contract to build and
operate a rig to drill extended reach wells to offshore targets from a
land-based location on Sakhalin Island, Russia for an international consortium.
The revenue and expense for the project are recognized as construction contract
revenue and expense. The estimated profit from the engineering, construction,
mobilization and rig-up fees is calculated on a percentage of completion basis,
of which $2.5 million was recognized during the year ended December 31, 2002.
General and administrative expense increased $3.0 million to $24.7 million
for the year ended December 31, 2002. The increase is primarily due to severance
costs related to reductions in corporate personnel, significant increase in the
vacation accrual, professional fees and required maintenance on our former
corporate headquarters in Tulsa currently held for sale. With regards to the
vacation accrual we adopted a paid time off policy in 2002, significantly
increasing the required vacation accrual.
The $1.1 million provision for reduction in carrying value of certain
assets is to increase the allowance for doubtful accounts for a U.S. customer
who filed for bankruptcy protection during the second quarter of 2002. The $7.5
million of reorganization costs recorded in 2001 includes employee moving
expenses and severance costs related to the consolidation and relocation of our
corporate and international drilling management to Houston, Texas, from Tulsa,
Oklahoma. The reorganization of certain senior management positions and
management of drilling operations accompanied the relocation.
26
Interest expense decreased $0.6 million in 2002 compared to 2001. Savings
of $2.9 million associated with the three $50.0 million interest rate swap
agreements including $0.3 million from the amortization of gain on the
termination of the interest rate swap agreements were offset by $1.5 million
less interest capitalized and $0.6 million higher interest due to the higher
interest rate on the exchange notes. Other expense of $4.3 million for the year
ended December 31, 2002 includes $3.6 million related to the exchange offer and
$0.4 million of costs incurred for the attempted purchase of Australia Oil and
Gas Corporation Limited.
Income tax expense for the year ended December 31, 2002 consists of
foreign tax expense of $14.2 million and a deferred tax benefit of $17.1
million. Foreign taxes increased $1.4 million due to increased taxes in the
Kazakhstan and the Asia Pacific regions. The deferred tax benefit was recognized
due to the loss generated during 2002.
ANALYSIS OF DISCONTINUED OPERATIONS
Year Ended December 31,
-------------------------
2002 2001
---------- ----------
Discontinued operations drilling revenues: (Dollars in Thousands)
U.S. jackup and platform drilling $ 39,297 $ 76,432
Latin America drilling 40,444 54,063
---------- ----------
Total discontinued operations drilling revenues $ 79,741 $ 130,495
========== ==========
Discontinued operations operating income (loss):
U.S. jackup and platform drilling (1) $ 1,799 $ 27,676
Latin America drilling (1) 10,080 12,707
Depreciation and amortization (30,549) (29,370)
---------- ----------
Total discontinued operations operating income
(loss) (2) (18,670) 11,013
Other income (expense) - net 535 220
Provision for impairment of assets (360) --
Tax expense (7,136) (1,159)
---------- ----------
Income (loss) from discontinued operations $ (25,631) $ 10,074
========== ==========
(1) Drilling gross margin - drilling revenues less direct drilling operating
expenses, excluding depreciation and amortization expense.
(2) Drilling operating income (loss) - drilling revenues less direct drilling
operating expenses, including depreciation and amortization expense.
U.S. jackup and platform drilling revenues decreased $37.1 million in 2002
from 2001. Revenues for the jackup rigs decreased $27.8 million during 2002 as
compared to 2001. The seven jackup rigs experienced a 44 percent decrease in
average dayrates during 2002 as compared to 2001, while utilization for the
jackups remained relatively constant in year-to-year comparisons. Revenues for
the platform rigs decreased $9.3 million to $1.6 million, as all four platform
rigs were stacked the last three quarters of 2002. The significant decrease in
gross margin relates almost entirely to the 44 percent decrease in average
dayrates for the jackup rigs.
Latin America revenues decreased $13.6 million in 2002 as compared to
2001. The decrease primarily related to reduced utilization in Colombia and
Bolivia. During the fourth quarter of 2001, Colombia and Bolivia had six rigs
and one rig working, respectively. At December 31, 2002, Colombia had three rigs
working and Bolivia had no rig activity. In Colombia, we had four drilling rigs
working for a customer when the operator terminated all drilling activity in May
of 2002. Since then one rig has gone back to work for this particular customer.
The drilling market in Bolivia, which diminished significantly in mid-2001,
showed no signs of recovery throughout 2002, primarily due to reduced demand for
natural gas from Brazil. Contributing to the reduced demand in 2002 were delays
in receiving the Bolivian government's commitment to a new gas pipeline to the
west coast of South America to enable the
27
exporting of natural gas to Mexico and the United States. Revenues in Bolivia
decreased $9.7 million to $1.0 million in 2002.
Latin America's discontinued operations gross margin declined $2.6 million
primarily due to decreased drilling activity in Colombia and Bolivia. The
decreased gross margins in Colombia and Bolivia were partially offset by
increased gross margins in Ecuador and Peru. The contract in Ecuador was
completed in the third quarter of 2002. The contract in Peru will continue
through 2003.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
We recorded income from continuing operations of $1.0 million for the year
ended December 31, 2001, compared to a loss from continuing operations of $16.3
million for the year ended December 31, 2000. Income from discontinued
operations was $10.1 million for the year ended December 31, 2001 as compared to
a loss from discontinued operations of $2.8 million for 2000.
Year Ended December 31,
----------------------------------------------
2001 2000
-------------------- --------------------
Drilling and rental revenues: (Dollars in Thousands)
U.S. drilling $114,377 32% $ 85,539 33%
International drilling 177,464 50% 126,633 50%
Rental tools 65,629 18% 42,833 17%
-------- -------- -------- --------
Total drilling and rental
revenues $357,470 100% $255,005 100%
======== ======== ======== ========
Our revenues increased $102.4 million to $357.5 million in 2001 as
compared to 2000. U.S. barge rig revenues increased $30.5 million to $114.4
million due primarily to increased dayrates for the drilling barge rigs.
Dayrates increased 31 percent for the barge rigs as compared to the previous
year. U.S. land drilling revenues decreased $1.7 million due to the sale of our
last remaining U.S. land rig, Rig 245, in November 2000.
International drilling revenues increased $50.8 million to $177.5 million
in 2001 as compared to the year ended December 31, 2000. International land
drilling revenues increased $42.9 million to $97.4 million during 2001. Revenues
in the CIS region, which includes Kazakhstan and Russia, increased $32.3 million
to $63.1 million during 2001 as compared to 2000. Kazakhstan increased $30.0
million in 2001 as one rig was added to the Tengiz operation and three rigs were
added to the Karachaganak joint venture with Saipem. Russia increased by $2.3
million as one rig commenced operations during 2001. Revenues increased $16.8
million in the Asia Pacific region due primarily to increased rig utilization in
Indonesia, Papua New Guinea and New Zealand. Revenues decreased $6.2 million in
the Africa/Middle East region due to completion of land drilling contracts in
Madagascar and Nigeria in 2000. International offshore drilling revenues
increased $7.9 million to $80.0 million during 2001 as compared to 2000.
Revenues in the Caspian Sea (Barge Rig 257) decreased $1.6 million while
revenues in Nigeria increased $9.5 million. Barge Rig 257 revenues decreased
primarily due to reduced rates received during the lengthy rig move after
completion of the first well. Revenues for the four barge rigs in Nigeria
improved due to increased drilling operations on full dayrates. In 2000 the rigs
were on reduced standby rates for approximately six months due to several
episodes of community unrest.
Rental tool revenues increased $22.8 million in 2001 as compared to 2000
due to the increased level of drilling activity in the Gulf of Mexico.
Contributing to this increase was the New Iberia, Louisiana, operation in the
amount of $10.3 million, $6.3 million from the Victoria, Texas, operation and
$6.2 million from the Odessa, Texas, operation which commenced operations in May
2000.
28
Year Ended December 31,
----------------------------------
2001 2000
--------------- ---------------
Drilling and rental operating income: (Dollars in Thousands)
U.S. drilling (1) $ 50,653 44% $ 30,077 35%
International drilling (1) 64,336 36% 35,307 28%
Rental tools (1) 42,624 65% 26,839 63%
Depreciation and amortization (67,889) (57,932)
-------- --------
Total drilling and rental operating
income (2) $ 89,724 $ 34,291
======== ========
General and administrative expense $(21,721) $(20,392)
Provision for reduction in carrying
value of certain assets -- (7,805)
Reorganization expense (7,500) --
-------- --------
Total operating income $ 60,503 $ 6,094
======== ========
(1) Drilling and rental gross margin - drilling and rental revenues less
direct drilling and rental operating expenses, excluding depreciation and
amortization expense; drilling and rental gross margin percentages -
drilling and rental gross margin as a percent of drilling and rental
revenues.
(2) Drilling and rental operating income - drilling and rental revenues less
direct drilling and rental operating expenses including depreciation and
amortization expense.
Drilling and rental operating income of $89.7 million in 2001 reflected an
increase of $55.4 million from the $34.3 million recognized during the year
ended December 31, 2000. The U.S. and international drilling segments recorded
gross margin percentages during 2001 of 44 percent and 36 percent, respectively,
as compared to 35 percent and 28 percent in 2000. U.S. gross margins increased
$20.6 million. U.S. drilling gross margin was positively impacted during 2001 by
increasing dayrates in the Gulf of Mexico from the barge rigs which increased
approximately 31 percent in 2001 as compared to the prior year. International
drilling gross margin increased $29.0 million to $64.3 million during the year
ended December 31, 2001 as compared to 2000. International land drilling gross
margin increased $22.3 million to $12.6 million. Gross margin for the
international land drilling operations increased in Kazakhstan from 33 percent
to 45 percent, Papua New Guinea from 27 percent to 48 percent, and New Zealand
from 20 percent to 39 percent, primarily due to higher utilization during 2001.
Gross margin in Russia decreased $5.4 million due to higher than anticipated
mobilization and start up costs. The international offshore drilling gross
margin increased $6.7 million to $29.5 million, with gross margin increasing
from 32 percent to 37 percent during 2001 as compared to 2000.
Rental tool gross margin increased $15.8 million to $42.6 million during
2001 as compared to the year ended December 31, 2000. Gross margin increased
primarily due to the $22.8 million increase in revenues during 2001. The gross
margin percentage increased during 2001 to 65 percent from 63 percent for the
previous year due principally to higher revenues without a corresponding
increase in fixed cost.
29
Depreciation and amortization expense increased $10.0 million to $67.9
million in 2001. Depreciation expense recorded in connection with capital
additions for the years 1999, 2000 and 2001, was the primary reason for the
increase. General and administrative expenses increased $1.3 million in 2001 as
compared to 2000. This increase was primarily attributed to increased travel
costs, professional fees, information technology projects and higher occupancy
costs associated with our new corporate office in Houston.
We recognized $7.5 million in reorganization costs, which includes
employee-moving expenses and severance costs, during 2001. In September 2001, we
opened our new corporate office in Houston. The reorganization included the
consolidation of its corporate and international drilling activities from Tulsa,
Oklahoma, with our U.S. offshore drilling operations already domiciled in
Houston. The reorganization of certain senior management positions and the
management of drilling operations accompanied the relocation.
Interest expense decreased $4.0 million due to the $50.5 million repayment
of convertible notes during the fourth quarter of 2000 and $1.6 million of
interest being capitalized to construction projects during the year ended
December 31, 2001, as compared to $0.5 million capitalized during 2000. Gain on
disposition of assets decreased $20.6 million to $1.8 million for the year ended
December 31, 2001. During the year 2000, we sold our one million shares of Unit
Corporation common stock and recognized a pre-tax gain of $7.4 million and we
sold Rig 245 in Alaska for $20.0 million and recognized a pre-tax gain of $14.9
million.
Income tax expense for 2001 consists of foreign tax expense of $12.8 million and
deferred tax benefit of $1.9 million. The deferred tax benefit is due to the
reduction in the valuation allowance of $9.6 million offsetting deferred tax
expense of $8.2 million. The reduction was the result of a change in estimate
relating to the realization of net operating loss carryforwards, or NOL's. At
December 31, 2000, we carried a valuation account reserving part of the NOL's
set to expire during the tax year ended August 31, 2001. Due to higher than
projected taxable income for the 2001 tax year, we utilized more NOL's than
originally anticipated resulting in the deferred tax benefit. As of December 31,
2001, the remaining valuation allowance was $9.9 million.
ANALYSIS OF DISCONTINUED OPERATIONS
Year Ended December 31,
--------------------------
2001 2000
---------- ----------
Discontinued operations drilling revenues: (Dollars in Thousands)
U.S. jackup and platform drilling $ 76,432 $ 62,877
Latin America drilling 54,063 58,467
---------- ----------
Total discontinued operations drilling revenues $ 130,495 $ 121,344
========== ==========
Discontinued operations operating income (loss):
U.S. jackup and platform drilling (1) $ 27,676 $ 19,142
Latin America drilling (1) 12,707 16,911
Depreciation and amortization (29,370) (27,128)
---------- ----------
Total discontinued operations operating income
(loss) (2) 11,013 8,925
Other income (expense) - net 220 (4,462)
Provision for impairment of assets -- (495)
Tax expense (1,159) (6,755)
---------- ----------
Income (loss) from discontinued operations $ 10,074 $ (2,787)
========== ==========
(1) Drilling gross margin - drilling revenues less direct drilling operating
expenses, excluding depreciation and amortization expense.
(2) Drilling operating income (loss) - drilling revenues less direct drilling
operating expenses, including depreciation and amortization expense.
30
U.S. jackup and platform drilling revenues consisting of the seven jackup
rigs and four platform rigs increased $13.6 million during 2001 as compared to
2000. Dayrates increased 40 percent for the jackup rigs as compared to the
previous year. The increase in dayrates was partially offset by decreased
utilization from 86 percent in 2000 to 78 percent in 2001. The decrease in
utilization was due primarily to the slowdown in the Gulf of Mexico jackup
market during the fourth quarter of 2001. Jackup utilization during the fourth
quarter of 2001 was 52 percent as compared to approximately 87 percent during
the first three quarters of 2001.
U.S. jackup and platform drilling gross margin was positively impacted
during 2001 by increasing dayrates in the Gulf of Mexico. Jackup rig utilization
decreased from 86 percent in 2000 to 78 percent in 2001 due primarily to a
slowdown in the Gulf of Mexico jackup market during the fourth quarter. This
slowdown negatively impacted jackup rig dayrates, which declined approximately
23 percent from the first three quarters of 2001.
Revenues in the Latin America region decreased $4.4 million to $54.1
million during 2001. Revenues in Bolivia decreased $12.1 million during 2001 due
primarily to an oversupply of natural gas in Bolivia due to reduced demand for
Bolivian natural gas from Brazil, resulting in a significant decrease in rig
utilization. Partially offsetting the decrease in Bolivia was an increase in
revenues of $8.7 million in Colombia. During 2001 rig utilization increased in
Colombia to 92 percent from 83 percent in 2000. Latin America gross margins
decreased $4.2 million primarily due to the reduced activity in Bolivia
LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2002, the Company had cash and cash equivalents of
$52.0 million, a decrease of $8.4 million from December 31, 2001. The net cash
provided by operating activities was $33.2 million for 2002. Due to reduced
revenues during 2002, accounts and notes receivable decreased $8.9 million.
Lower utilization and reduced capital spending resulted in a decrease of $19.8
million to accounts payable and accrued liabilities.
Net cash used in investing activities was $38.7 million in 2002. This
included $45.2 million for capital expenditures net of proceeds from the sale of
assets of $6.5 million. Net cash used in financing activities was $2.9 million
in 2002. This included $5.5 million repayment of debt net of $2.6 million
proceeds from the settlement of three interest rate swap agreements.
As of December 31, 2001, we had cash and cash equivalents of $60.4
million, a decrease of $2.1 million from December 31, 2000. The primary sources
of cash in 2001 were $116.0 million provided by operating activities and $7.6
million from the disposition of assets. Proceeds from the disposition of assets
included the sale of various non-marketable rigs and components and
reimbursements from customers for equipment lost in the hole.
The primary uses of cash in 2001 were $122.0 million for capital
expenditures and $5.0 million for repayment of debt. Major projects during the
year included modifications to Jackup Rig 22 as a result of its scheduled
five-year Coast Guard inspection, completion of Rig 216 to work in the
Karachaganak field in Kazakhstan, and purchase of drill pipe and other rental
tools for Quail Tools. Repayment of debt included $4.5 million on a five-year
note with Boeing Capital Corporation for Barge Rig 75 in Nigeria.
The Company has total long-term debt, including the current portion, of
$589.9 million at December 31, 2002. The Company has a $50.0 million revolving
credit facility with a group of banks led by Bank of America. This facility is
available for working capital requirements, general corporate purposes and to
support letters of credit. The revolver is collateralized by accounts
receivable, inventory and certain barge rigs located in the Gulf of Mexico. The
facility contains customary affirmative and negative covenants. Availability
under the revolving credit facility is subject to certain borrowing base
limitations based on 80 percent of eligible receivables plus 50 percent of
supplies in inventory, less the amount utilized in support of letters of credit.
Currently, the borrowing base of $41.2 million is reduced by $15.7 million in
outstanding letters of credit, resulting in available revolving credit of $25.5
million. As of December 31, 2002 no amounts have been drawn down against the
revolving credit facility. The revolver terminates on
31
October 22, 2003. The Company expects to renew or replace the revolving loan
facility by the end of the third quarter of 2003.
The Company anticipates that funds required for capital spending in 2003
will be met from existing cash and cash provided by operations. It is
management's present intention to limit capital spending, net of reimbursements
from customers, to approximately $50 million in 2003. Should new drilling
projects or other opportunities requiring additional capital arise, or should
revenues not meet management's expectations, the Company may utilize the
revolving credit facility. In addition, the Company may seek project financing
or equity participation from outside alliance partners or customers to fund
certain capital projects. The Company cannot predict whether such financing or
equity participation would be available on terms acceptable to the Company.
The Company is exposed to interest rate risk from its fixed-rate debt. The
Company had hedged against the risk of changes in the fair value associated with
its 9.75% Senior Notes by entering into three fixed-to-variable interest rate
swap agreements with a total notional amount of $150.0 million. For the year
ended December 31, 2002, the interest rate swap agreements reduced interest
expense by $2.9 million.
On July 24, 2002, the Company terminated all the interest rate swap
agreements and received $3.5 million. A gain totaling $2.6 million will be
recognized as a reduction to interest expense over the remaining term (ending
November 2006) of the debt instrument, of which $0.3 million was recognized
during 2002.
See Note 4 of the notes to the consolidated financial statements for
information regarding the Company's exchange offer which was completed May 2,
2002.
The following tables summarize the Company's future contractual
obligations and other commercial commitments as of December 31, 2002.
After 5
1 Year 2 - 3 Years 4 - 5 Years Years Total
---------- ----------- ----------- ---------- ----------
(Dollars in Thousands)
Contractual cash obligations:
Long-term debt (1) $ 6,486 $ 129,565 $ 214,192 $ 235,612 $ 585,855
Operating leases (2) 3,317 4,301 3,643 2,145 13,406
---------- ----------- ----------- ---------- ----------
Total contractual cash obligations $ 9,803 $ 133,866 $ 217,835 $ 237,757 $ 599,261
========== =========== =========== ========== ==========
Commercial commitments:
Revolving credit facility (3) $ -- $ -- $ -- $ -- $ --
Standby letters of credit (3) 15,667 -- -- -- 15,667
---------- ----------- ----------- ---------- ----------
Total commercial commitments $ 15,667 $ -- $ -- $ -- $ 15,667
========== =========== =========== ========== ==========
(1) Long-term debt includes the 9.75% Senior Notes, the 10.125% Senior Notes,
the 5.5% Convertible Subordinated Notes, the secured 10.1278% promissory note
and the capital lease. For additional information, see Note 4 in the notes to
the consolidated financial statements.
(2) Operating leases consist of lease agreements in excess of one year for
office space, equipment, vehicles and personal property. For additional
information, see Note 12 in the notes to the consolidated financial statements.
(3) The Company has available a $50.0 million revolving credit facility. As of
December 31, 2002, none has been drawn down, but $15.7 million of availability
has been used to support letters of credit that have been issued. The revolving
credit facility expires in October 2003.
32
The Company does not have any unconsolidated special-purpose entities,
off-balance-sheet financing arrangements or guarantees of third-party financial
obligations. The Company has no energy or commodity contracts.
OTHER MATTERS
BUSINESS RISKS
Internationally, the Company specializes in drilling geologically
challenging wells in locations that are difficult to access and/or involve harsh
environmental conditions. The Company's international services are primarily
utilized by major and national oil companies in the exploration and development
of reserves of oil. In the United States, the Company primarily drills offshore
in the Gulf of Mexico with barge, jackup and platform rigs for major and
independent oil and gas companies. Business activity is dependent on the
exploration and development activities of the major, independent and national
oil and gas companies that make up the Company's customer base. Generally,
temporary fluctuations in oil and gas prices do not materially affect these
companies' exploration and development activities, and consequently do not
materially affect the operations of the Company, except for the Gulf of Mexico,
where drilling contracts are generally for a shorter term, and oil and gas
companies tend to respond more quickly to upward or downward changes in prices.
Many international contracts are of longer duration and oil and gas companies
have committed to longer-term projects to develop reserves and thus our
international operations are not as susceptible to shorter term fluctuations in
prices. However, sustained increases or decreases in oil and natural gas prices
could have an impact on customers' long-term exploration and development
activities, which in turn could materially affect the Company's operations.
Generally, a sustained change in the price of oil would have a greater impact on
the Company's international operations while a sustained change in the price of
natural gas would have a greater effect on U.S. operations. Due to the locations
in which the Company drills, the Company's operations are subject to
interruption, prolonged suspension and possible expropriation due to political
instability and local community unrest. Further, the Company is exposed to
liability issues from pollution arising out of its operations and to loss of
revenues in the event of a blowout. The majority of the political and
environmental risks are transferred to the operator by contract or otherwise
insured.
CRITICAL ACCOUNTING POLICIES
We consider certain accounting policies related to impairment of property,
plant and equipment, impairment of goodwill, the valuation of deferred tax
assets and revenue recognition to be critical accounting policies due to the
estimation processes involved in each. Other significant accounting policies are
summarized in Note 1 in the notes to the consolidated financial statements.
Impairment of property, plant and equipment
Our management periodically evaluates our property, plant and equipment to
determine that their net carrying value is not in excess of their net realizable
value. These evaluations are performed when we have realized sustained
significant declines in utilization and dayrates and recovery is not
contemplated in the near future. Our management considers a number of factors
such as estimated future cash flows, appraisals and current market value
analysis in determining net realizable value. Assets are written down to their
fair value if it is below its net carrying value.
In June 2003, our board of directors approved a plan to sell our Latin
America assets consisting of 17 land rigs and related inventory and spare parts
and our U.S. offshore assets consisting of seven jackup rigs and four platform
rigs. We are actively marketing the assets through an independent broker. At
June 30, 2003, the net book value of the assets to be sold exceeded the fair
value and as a result an impairment charge including estimated sales expenses
was recognized in the amount of $54.0 million. One Latin America land rig and
related spare parts were sold to a third party for $1.8 million in July, 2003.
Impairment of goodwill
Our management periodically assesses whether the excess of cost over net
assets acquired is impaired based on the estimated fair value of the operation
to which it relates, which value is generally determined based on estimated
future cash flows of that operation. If the estimated fair value is in excess of
the carrying value of the operation, no further analysis is performed. If the
fair value of each operation, to which goodwill has been assigned, is less than
the carrying value, we will deduct the fair value of the tangible and intangible
assets and compare the residual amount to the carrying value of the goodwill to
determine if impairment should be recorded.
33
In 2002, SFAS No. 142, "Goodwill and Other Intangible Assets," became
effective and as a result, we discontinued the amortization of $189.1 million of
goodwill. In lieu of amortization, we performed an initial impairment review of
goodwill and as a result impaired goodwill by $73.1 million. We will perform an
annual impairment review, in December, hereafter. The impairment was recognized
as a cumulative effect of a change in accounting principle. We performed our
annual impairment review during the fourth quarter of 2002 with no additional
impairment required.
Accounting for income taxes
As part of the process of preparing the consolidated financial statements,
we are required to estimate the income taxes in each of the jurisdictions in
which we operate. This process involves estimating the actual current tax
exposure together with assessing temporary differences resulting from differing
treatment of items, such as depreciation, amortization and certain accrued
liabilities for tax and accounting purposes. These differences and the net
operating loss carryforwards result in deferred tax assets and liabilities,
which are included within our consolidated balance sheet. We must then assess
the likelihood that the deferred tax assets will be recovered from future
taxable income, and to the extent we believe that recovery is not likely, we
must establish a valuation allowance. To the extent we establish a valuation
allowance or increase or decrease this allowance in a period, we must include an
expense or reduction of expense within the tax provision in the statement of
operations.
Revenue Recognition
We recognize revenues and expenses on dayrate contracts as the drilling
progresses (percentage of completion method) because we do not bear the risk of
completion of the well. For meterage contracts, we recognize the revenues and
expenses upon completion of the well (completed contract method). Revenues from
rental activities are recognized ratably over the rental term which is generally
less than six months.
RECENT ACCOUNTING PRONOUNCEMENTS
In April 2002, the Financial Accounting Standards Board, referred to as
the FASB, issued SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and
No. 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No.
145 is effective for fiscal years beginning after May 15, 2002. We adopted this
standard in the first quarter of 2003 and it did not have a significant effect
on our results of operations or our financial position. The statements of
operations and cash flows have been restated to reflect our adoption of SFAS No.
145 and, accordingly, the extraordinary gain on the extinguishment of debt has
been reclassified to other income and the related taxes to income tax expense.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 is effective for exit
or disposal activities initiated after December 31, 2002. The adoption of this
standard has not had any impact on our financial position or results of
operations.
In November 2002, the FASB issued Interpretation No. 45, or FIN 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, including
Indirect Guarantees of Indebtedness of Others." The interpretation requires
disclosure about the nature and terms of obligations under certain guarantees
that we have issued. The interpretation also clarifies that a guarantor is
required to recognize, at inception of a guarantee, a liability for the fair
value of the obligation undertaken in issuing a guarantee. The initial
recognition and initial measurement provisions are applicable on a prospective
basis to guarantees issued or modified after December 31, 2002. The disclosure
requirements in this interpretation are effective immediately. We do not expect
to be impacted by the issuance of FIN 45.
On December 31, 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation -- Transition and Disclosure -- An Amendment of SFAS
No. 123." The standard provides additional transition guidance for companies
that elect to voluntarily adopt the accounting provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." SFAS No. 148 does not change the
provisions of SFAS No. 123 that permit entities to continue to apply the
intrinsic value method of Accounting Principals Board Opinion, or APB, No. 25,
"Accounting for Stock Issued to Employees." As we continue to follow APB No. 25,
our accounting for stock-based compensation will not change as a result of SFAS
No. 148. SFAS No. 148 does require certain new disclosures in both annual and
interim financial statements. The interim disclosure provisions have been
included in the notes to our consolidated financial statements.
On January 17, 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities, An Interpretation of Accounting Research Bulletin No. 51."
The primary objectives of FIN 46 are to provide guidance on how to identify
entities for which control is achieved through means other than through voting
rights (variable interest entities, or VIE) and how to determine when and which
business enterprise should consolidate the VIE. This new model for consolidation
applies to an entity in which either (1) the equity investors do not have a
controlling financial interest or (2) the equity investment at risk is
insufficient to finance that entity's activities without receiving additional
subordinated financial support from other parties. We are consolidating
AralParker, a company in which we own a 50 percent equity interest, because we
exert significant influence and have a financial interest in the form of a loan,
in addition to our equity interest.
34
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
We are exposed to interest rate risk from our fixed-rate debt. In January
2002, we hedged against a portion of the risk of changes in fair value
associated with our $214.2 million 9.75% senior notes by entering into three
fixed-to-variable interest rate swap agreements with a total notional amount of
$150.0 million. We assumed no ineffectiveness as each interest rate swap
agreement met the short-cut method requirements under SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," for fair value hedges of
debt instruments. As a result, changes in the fair value of the interest rate
swap agreements were offset by changes in the fair value of the debt and no net
gain or loss was recognized in earnings. During the six months ended June 30,
2002 the interest rate swap agreements reduced interest expense by $2.3 million.
On July 24, 2002, we terminated all the interest rate swap agreements and
received $3.5 million. A gain totaling $2.6 million will be recognized as a
reduction to interest expense or included in any gain or loss if the debt is
extinguished prior to its stated maturity, over the remaining term (ending
November 2006) of the debt instrument, of which $0.4 million was recognized
during the six months ended June 30, 2003.
35
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders Parker Drilling Company
In our opinion, the consolidated financial statements listed in the index
appearing under Item 15(a)(1) of the Form 10-K/A, present fairly, in all
material respects, the financial position of Parker Drilling Company and its
subsidiaries at December 31, 2002 and 2001, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2002, in conformity with accounting principles generally accepted in the
United States of America. In addition, in our opinion, the financial statement
schedule listed in the index appearing under Item 15(a)(2) of the Form 10-K/A,
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
These financial statements and financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these financial statements in accordance
with auditing standards generally accepted in the United States of America which
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, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As discussed in Note 3 to the consolidated financial statements, in 2002,
the Company changed its method of accounting for goodwill as a result of
adopting the provisions of Statement of Financial Accounting Standards No. 142
"Goodwill and Other Intangible Assets."
As discussed in Note 17 to the consolidated financial statements, the
Company has reclassified certain amounts in its consolidated statement of
operations to reflect certain discontinued operations and the adoption of SFAS
No. 145.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
January 29, 2003, except for Note 17,
as to which the date is September 19, 2003.
36
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Dollars in Thousands Except Per Share and Weighted Average Shares Outstanding)
Year Ended December 31,
------------------------------------------------
2002 2001 2000
------------ ------------ ------------
Drilling and rental revenues:
U.S. drilling $ 74,181 $ 114,377 $ 85,539
International drilling 188,514 177,464 126,633
Rental tools 47,510 65,629 42,833
------------ ------------ ------------
Total drilling and rental revenues 310,205 357,470 255,005
------------ ------------ ------------
Drilling and rental operating expenses:
U.S. drilling 48,326 63,724 55,462
International drilling 114,272 113,128 91,326
Rental tools 21,810 23,005 15,994
Depreciation and amortization 67,954 67,889 57,932
------------ ------------ ------------
Total drilling and rental operating expenses 252,362 267,746 220,714
------------ ------------ ------------
Drilling and rental operating income 57,843 89,724 34,291
------------ ------------ ------------
Construction contract revenue 86,818 -- --
Construction contract expense 84,356 -- --
------------ ------------ ------------
Net construction contract operating income 2,462 -- --
------------ ------------ ------------
General and administration expense 24,728 21,721 20,392
Provision for reduction in carrying
value of certain assets 1,140 -- 7,805
Reorganization expense -- 7,500 --
------------ ------------ ------------
Total operating income 34,437 60,503 6,094
------------ ------------ ------------
Other income and (expense):
Interest expense (52,409) (53,015) (57,036)
Interest income 851 3,553 3,691
Gain on disposition of assets 2,997 1,757 22,398
Minority interest 278 -- --
Other (4,269) (384) 8,377
------------ ------------ ------------
Total other income and (expense) (52,552) (48,089) (22,570)
------------ ------------ ------------
Income (loss) before income taxes (18,115) 12,414 (16,476)
Income tax expense (benefit) (2,836) 11,429 (218)
------------ ------------ ------------
Income (loss) from continuing operations (15,279) 985 (16,258)
Discontinued operations, net of taxes (25,631) 10,074 (2,787)
Cumulative effect of change in accounting principle (73,144) -- --
------------ ------------ ------------
Net income (loss) $ (114,054) $ 11,059 $ (19,045)
============ ============ ============
Basic earnings (loss) per share:
Income (loss) from continuing operations $ (0.16) $ 0.01 $ (0.20)
Discontinued operations, net of taxes $ (0.28) $ 0.11 $ (0.03)
Cumulative effect of change in accounting principle $ (0.79) $ -- $ --
Net income (loss) $ (1.23) $ 0.12 $ (0.23)
Diluted earnings (loss) per share:
Income (loss) from continuing operations $ (0.16) $ 0.01 $ (0.20)
Discontinued operations, net of taxes $ (0.28) $ 0.11 $ (0.03)
Cumulative effect of change in accounting principle $ (0.79) $ -- $ --
Net income (loss) $ (1.23) $ 0.12 $ (0.23)
Number of common shares used in computing earnings per share:
Basic 92,444,773 92,008,877 81,758,825
Diluted 92,444,773 92,691,033 81,758,825
See accompanying notes to the consolidated financial statements.
37
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
December 31,
--------------------------
ASSETS 2002 2001
- ----------------------------------------------------------- ---------- ----------
Current assets:
Cash and cash equivalents $ 51,982 $ 60,400
Accounts and notes receivable, net of allowance
for bad debts of $4,762 in 2002 and $2,988 in 2001 89,363 99,874
Rig materials and supplies 17,161 22,200
Other current assets 8,631 8,978
---------- ----------
Total current assets 167,137 191,452
---------- ----------
Property, plant and equipment, at cost:
Drilling equipment 1,099,211 1,063,454
Rental tools 81,325 74,085
Buildings, land and improvements 27,905 26,887
Other 31,371 25,606
Construction in progress 6,279 26,142
---------- ----------
1,246,091 1,216,174
Less accumulated depreciation and amortization 604,813 520,645
---------- ----------
Property, plant and equipment, net 641,278 695,529
---------- ----------
Deferred charges and other assets:
Goodwill, net of accumulated amortization of $108,412
in 2002 and $35,268 in 2001 115,983 189,127
Rig materials and supplies 9,450 9,201
Assets held for disposition 896 1,800
Debt issuance costs 6,330 8,247
Other 12,251 10,421
---------- ----------
Total deferred charges and other assets 144,910 218,796
---------- ----------
Total assets $ 953,325 $1,105,777
========== ==========
See accompanying notes to the consolidated financial statements.
38
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Continued)
(Dollars in Thousands)
December 31,
----------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2002 2001
- ---------------------------------------------------------------- ------------ ------------
Current liabilities:
Current portion of long-term debt $ 6,486 $ 5,007
Accounts payable 14,377 33,521
Accrued liabilities 36,365 38,152
Accrued income taxes 4,347 7,054
------------ ------------
Total current liabilities 61,575 83,734
------------ ------------
Long-term debt 583,444 587,165
Deferred income taxes -- 16,152
Other long-term liabilities 7,680 6,583
Commitments and contingencies (Note 12)
Stockholders' equity:
Preferred stock, $1 par value, 1,942,000 shares
authorized, no shares outstanding -- --
Common stock, $0.16 2/3 par value, authorized
140,000,000 shares, issued and outstanding
92,793,349 shares (92,053,796 shares in 2001) 15,465 15,342
Capital in excess of par value 434,998 432,845
Accumulated other comprehensive income-net unrealized
gain on investments available for sale (net of taxes of
$0 in 2002 and $227 in 2001) 664 403
Retained earnings (accumulated deficit) (150,501) (36,447)
------------ ------------
Total stockholders' equity 300,626 412,143
------------ ------------
Total liabilities and stockholders' equity $ 953,325 $ 1,105,777
============ ============
See accompanying notes to the consolidated financial statements.
39
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31,
----------------------------------------
2002 2001 2000
---------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (114,054) $ 11,059 $ (19,045)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation and amortization 67,954 67,889 57,932
Gain on disposition of assets (3,432) (2,316) (17,920)
Cumulative effect of change in accounting principle 73,144 -- --
Gain on early retirement of debt -- -- (6,150)
Provision for reduction in carrying value
of certain assets 1,500 -- 8,300
Deferred tax expense (benefit) (17,120) (1,899) (9,088)
Discontinued operations 30,549 29,370 27,128
Other 6,045 4,625 5,320
Change in assets and liabilities:
Accounts and notes receivable 8,851 24,158 (47,954)
Rig materials and supplies 2,390 (3,807) (1,981)
Other current assets 347 (4,366) 11,150
Accounts payable and accrued liabilities (19,834) (4,484) 18,356
Accrued income taxes (1,843) (2,784) 1,098
Other assets (1,316) (1,440) 125
---------- ---------- ----------
Net cash provided by operating activities 33,181 116,005 27,271
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of assets 6,451 7,628 31,912
Capital expenditures (net of reimbursements) (45,181) (122,033) (98,525)
Proceeds from sale of short-term investments -- 799 16,925
---------- ---------- ----------
Net cash used in investing activities (38,730) (113,606) (49,688)
---------- ---------- ----------
See accompanying notes to the consolidated financial statements.
40
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(Continued)
(Dollars in Thousands)
Year Ended December 31,
------------------------------------
2002 2001 2000
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from common stock offering, net $ -- $ -- $ 87,313
Payments for early retirement of debt -- -- (43,477)
Principal payments under debt obligations (5,489) (5,034) (4,854)
Proceeds from interest rate swap agreements 2,620 -- --
Other -- 555 414
-------- -------- --------
Net cash provided by (used in)
financing activities (2,869) (4,479) 39,396
-------- -------- --------
Net increase (decrease) in cash and cash equivalents (8,418) (2,080) 16,979
Cash and cash equivalents at beginning of year 60,400 62,480 45,501
-------- -------- --------
Cash and cash equivalents at end of year $ 51,982 $ 60,400 $ 62,480
======== ======== ========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 52,532 $ 53,257 $ 56,608
Income taxes $ 19,454 $ 14,956 $ 14,527
Supplemental noncash investing and financing activity:
Net unrealized gain (loss) on investments
available for sale (net of taxes of $0 in 2002,
$37 in 2001 and $717 in 2000) $ 261 $ 64 $ (1,274)
Capital lease obligation $ 1,255 $ -- $ --
See accompanying notes to the consolidated financial statements.
41
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(Dollars and Shares in Thousands)
Retained Accumulated
Capital in Earnings Other
Common Excess of (Accumulated Comprehensive
Shares Stock Par Value Deficit) Income (Loss)
------------- ------------- ------------- ------------- -------------
Balances, December 31, 1999 77,372 $ 12,895 $ 343,374 $ (28,461) $ 1,613
Activity in employees' stock plans 552 92 2,656 -- --
Issuance of 13,800,000
common shares 13,800 2,300 85,013 -- --
Other comprehensive income-net
unrealized loss on investments
(net of taxes of $717) -- -- -- -- (1,274)
Net loss (total comprehensive
loss of $20,319) -- -- -- (19,045) --
------------- ------------- ------------- ------------- -------------
Balances, December 31, 2000 91,724 15,287 431,043 (47,506) 339
Activity in employees' stock plans 330 55 1,802 -- --
Other comprehensive income-net
unrealized gain on investments
(net of taxes of $37) -- -- -- -- 64
Net loss (total comprehensive
loss of $11,123) -- -- -- 11,059 --
------------- ------------- ------------- ------------- -------------
Balances, December 31, 2001 92,054 15,342 432,845 (36,447) 403
Activity in employees' stock plans 739 123 2,153 -- --
Other comprehensive income-net
unrealized gain on investments
(net of taxes of $0) -- -- -- -- 261
Net loss (total comprehensive
loss of $113,793) -- -- -- (114,054) --
------------- ------------- ------------- ------------- -------------
Balances, December 31, 2002 92,793 $ 15,465 $ 434,998 $ (150,501) $ 664
============= ============= ============= ============= =============
See accompanying notes to the consolidated financial statements.
42
PARKER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
Consolidation - The consolidated financial statements include the accounts
of Parker Drilling Company ("Parker Drilling") and all of its majority-owned
subsidiaries and a company in which a subsidiary of Parker Drilling has a 50
percent stock ownership but exerts significant influence over its operation. A
subsidiary of Parker Drilling also has a 50 percent interest in another company,
which is accounted for under the equity method (collectively, the "Company").
Operations - The Company provides land and offshore contract drilling
services and rental tools on a worldwide basis to major, independent and
foreign-owned oil and gas companies. At December 31, 2002, the Company's rig
fleet consists of 27 barge drilling and workover rigs, seven offshore jackup
rigs, four offshore platform rigs and 41 land rigs. The Company specializes in
the drilling of deep and difficult wells, drilling in remote and harsh
environments, drilling in transition zones and offshore waters, and in providing
specialized rental tools. The Company also provides a range of services that are
ancillary to its principal drilling services, including engineering and
logistics, as well as project management activities.
Drilling Contracts and Rental Revenues - The Company recognizes revenues and
expenses on dayrate contracts as the drilling progresses
(percentage-of-completion method) because the Company does not bear the risk of
completion of the well. For meterage contracts, the Company recognizes the
revenues and expenses upon completion of the well (completed-contract method).
Revenues from rental activities are recognized ratably over the rental term
which is generally less than six months.
Construction Contract - The Company has historically only constructed
drilling rigs for its own use. At the request of one of its significant
customers, the Company entered into a contract to design, construct, mobilize
and sell ("construction contract") a specialized drilling rig to drill extended
reach wells to offshore targets from a land-based location on Sakhalin Island,
Russia, for an international consortium of oil and gas companies. The Company
also entered into a contract to subsequently operate the rig on behalf of the
consortium. Generally Accepted Accounting Principles ("GAAP") requires that
revenues received and costs incurred related to the construction contract be
accounted for and reported on a gross basis and income for the related fees
should be recognized on a percentage of completion basis. Because this
construction contract is not a part of the Company's historical or normal
operations, the revenues and costs related to this contract have been shown as a
separate component in the statement of operations. Construction costs in excess
of funds received from the customer are accumulated and reported as part of
other current assets. At December 31, 2002 and 2001, a net receivable
(construction costs less progress payments) of $5.3 million and $6.0 million,
respectively, are included in other current assets.
Cash and Cash Equivalents - For purposes of the balance sheet and the
statement of cash flows, the Company considers cash equivalents to be all highly
liquid debt instruments that have a remaining maturity of three months or less
at the date of purchase.
43
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Property, Plant and Equipment - The Company provides for depreciation of
property, plant and equipment primarily on the straight-line method over the
estimated useful lives of the assets after provision for salvage value. The
depreciable lives for land drilling equipment approximate 15 years. The
depreciable lives for offshore drilling equipment generally range from 15 to 20
years. The depreciable lives for certain other equipment, including drill pipe
and rental tools, range from three to seven years. Depreciable lives for
buildings and improvements range from 10 to 30 years. Interest totaling
approximately $0.1 million, $1.6 million and $0.5 million was capitalized during
the years ended December 31, 2002, 2001 and 2000, respectively. When properties
are retired or otherwise disposed of, the related cost and accumulated
depreciation are removed from the accounts and any gain or loss is included in
operations. Management periodically evaluates the Company's assets to determine
that their net carrying value is not in excess of their net realizable value.
Management considers a number of factors such as estimated future cash flows,
appraisals and current market value analysis in determining net realizable
value. Assets are written down to their fair value if it is below its net
carrying value.
Goodwill - Effective January 1, 2002, the Company adopted Statement of
Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible
Assets." In accordance with this accounting principle, goodwill is no longer
amortized but will be assessed for impairment on at least an annual basis (see
Note 3 for additional details regarding goodwill).
Rig Materials and Supplies - Since the Company's international drilling
generally occurs in remote locations, making timely outside delivery of spare
parts uncertain, a complement of parts and supplies is maintained either at the
drilling site or in warehouses close to the operations. During periods of high
rig utilization, these parts are generally consumed and replenished within a
one-year period. During a period of lower rig utilization in a particular
location, the parts, like the related idle rigs, are generally not transferred
to other international locations until new contracts are obtained because of the
significant transportation costs, which would result from such transfers. The
Company classifies those parts which are not expected to be utilized in the
following year as long-term assets. Rig materials and supplies are valued at the
lower of cost or market value.
Other Assets - Other assets include the Company's investment in marketable
equity securities. Equity securities that are classified as available for sale
are stated at fair value as determined by quoted market prices. Unrealized
holding gains and losses are excluded from current earnings and are included in
comprehensive income, net of taxes, in a separate component of stockholders'
equity until realized. At December 31, 2002 and 2001, the fair value of equity
securities totaled $1.3 million and $1.8 million, respectively.
In computing realized gains and losses on the sale of equity securities, the
cost of the equity securities sold is determined using the specific cost of the
security when originally purchased.
Other Long-Term Obligations - Included in this account is the accrual of
workers' compensation liability, which is not expected to be paid within the
next year.
Income Taxes - Deferred tax liabilities and assets are determined based on
the difference between the financial statement and tax basis of assets and
liabilities using enacted tax rates in effect for the year in which the
differences are expected to reverse.
44
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Earnings (Loss) Per Share (EPS) - Basic earnings (loss) per share is
computed by dividing net income (loss), by the weighted average number of common
shares outstanding during the period. The effects of dilutive securities, stock
options and convertible debt are included in the diluted EPS calculation, when
applicable.
Concentrations of Credit Risk - Financial instruments, which potentially
subject the Company to concentrations of credit risk, consist primarily of trade
receivables with a variety of national and international oil and gas companies.
The Company generally does not require collateral on its trade receivables.
At December 31, 2002 and 2001, the Company had deposits in domestic banks
in excess of federally insured limits of approximately $51.6 million and $57.6
million, respectively. In addition, the Company had deposits in foreign banks at
December 31, 2002 and 2001 of $4.8 million and $3.5 million, respectively, which
are not federally insured.
The Company's drilling customer base consists of major, independent and
foreign-owned oil and gas companies. For fiscal year 2002 and 2001 respectively,
ChevronTexaco was the Company's largest customer with approximately 17 percent
of total revenues in 2002 and 15 percent in 2001. In 2002, Tengizchevroil, a
joint venture with four oil companies, was the second largest customer with 13
percent of total revenues. Shell Petroleum Development Company of Nigeria was
the Company's largest customer for 2000 with approximately 10 percent of total
revenues.
Derivative Financial Instruments - The Company adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended by
SFAS Nos. 137 and 138. These statements require that every derivative instrument
be recorded on the balance sheet as either an asset or liability measured by its
fair value. These statements also establish new accounting rules for hedge
transactions, which depend on the nature of the hedge relationship.
The Company uses derivative instruments to hedge exposure to interest rate
risk. For hedges which meet the SFAS No. 133 criteria, the Company formally
designates and documents the instrument as a hedge of a specific underlying
exposure, as well as the risk management objective and strategy for undertaking
each hedge transaction.
Fair Value of Financial Instruments - The carrying amount of the Company's
cash and cash equivalents and short-term and long-term debt had fair values that
approximated their carrying amounts, except for the Company's 5.5% Convertible
Subordinated Notes which had a carrying value of $124.5 million and a fair
market value of $115.3 million at December 31, 2002.
Stock-Based Compensation - The Company has elected the disclosure-only
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation."
Accordingly, no compensation cost has been recognized for the Company's stock
option plans when the option price is equal to or greater than the fair market
value of a share of the Company's common stock on the date of grant. Pro forma
net income and earnings per share are reflected in the following tables as if
compensation cost had been determined based on the fair value of the options at
their applicable grant date, according to the provisions of SFAS No. 123.
45
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Year Ended December 31,
-----------------------
2002 2001 2000
---------- ---------- ----------
(Dollars in Thousands)
Income (loss) from continuing operations:
As reported $ (15,279) $ 985 $ (16,258)
Compensation expense, net of tax (2,597) (3,361) (2,960)
---------- ---------- ----------
Pro forma $ (17,876) $ (2,376) $ (19,218)
========== ========== ==========
Diluted earnings (loss) per share from
continuing operations:
As reported $ (0.16) $ 0.01 $ (0.20)
Compensation expense, net of tax (0.03) (0.04) (0.04)
---------- ---------- ----------
Pro forma $ (0.19) $ (0.03) $ (0.24)
========== ========== ==========
The fair value of each option grant is estimated using the Black-Scholes
option pricing model with the following assumptions:
Expected dividend yield 0.0%
Expected stock volatility 51.6% in 2000
56.3% in 2001
56.9% in 2002
Risk-free interest rate 3.0% - 6.7%
Expected life of options 5 - 7 years
Options granted in 2002, 2001 and 2000 under the 1997 Stock Plan had an
estimated fair value of $1,759,000, $4,326,000 and $203,000 respectively.
Accounting Estimates - The preparation of financial statements in
conformity with GAAP requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
46
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 2 - Disposition of Assets
On November 20, 2000, the Company sold its last remaining U.S. land rig,
Rig 245 in Alaska, for $20.0 million. The Company recognized a pre-tax gain of
$14.9 million during the fourth quarter of 2000.
Note 3 - Goodwill
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets." In accordance with this accounting principle, goodwill
is no longer amortized but will be assessed for impairment on at least an annual
basis.
As an initial step in the implementation process, the Company identified
four reporting units that would be tested for impairment. The four units qualify
as reporting units in that they are one level below an operating segment, or an
individual operating segment and discrete financial information exists for each
unit. The four reporting units identified by segment are as follows:
U.S. drilling segment: Barge rigs
Jackup and Platform rigs (1)
International drilling segment: Nigeria barge rigs
Rental tools segment: Rental tools business
(1) The jackup and platform rigs were aggregated due to the similarities in
the markets served.
As required under the transitional accounting provisions of SFAS No. 142,
the Company completed both steps required to identify and measure goodwill
impairment at each reporting unit. The first step involved identifying all
reporting units with carrying values (including goodwill) in excess of fair
value, which was estimated by an independent business valuation consultant using
the present value of estimated future cash flows. The reporting units for which
the carrying value exceeded fair value were then measured for impairment by
comparing the implied fair value of the reporting unit goodwill, determined in
the same manner as in a business combination, with the carrying amount of
goodwill. The jackup and platform rigs reporting unit was the only unit where
impairment was identified. As a result, goodwill related to the jackup and
platform rigs was impaired by $73.1 million and was recognized as a cumulative
effect of a change in accounting principle retroactive to the first quarter. The
Company will perform its annual impairment review during the fourth quarter of
each year. The review in the fourth quarter 2002, resulted in no additional
impairment.
47
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 3 - Goodwill (continued)
The following is a summary of the change in goodwill by reporting unit for
the years ended December 31, 2000, 2001 and 2002 (dollars in thousands):
International
U.S. Drilling Drilling Rental Tools
Segment Segment Segment
-------------------------------- ---------- -------------
Barge Jackup & Nigeria Rental Tools
Rigs Platform Rigs Barge Rigs Business
---------- ------------- ---------- ------------
Balance as of January 1, 2000 $ 63,110 $ 78,771 $ 23,198 $ 39,011
Goodwill amortization (2,367) (2,797) (864) (1,453)
Impairment losses -- -- -- --
-------- -------- -------- --------
Balance as of December 31, 2000 60,743 75,974 22,334 37,558
Goodwill amortization (2,334) (2,830) (863) (1,454)
Impairment losses -- -- -- --
-------- -------- -------- --------
Balance as of December 31, 2001 58,409 73,144 21,471 36,104
Goodwill amortization -- -- -- --
Impairment losses -- (73,144) -- --
-------- -------- -------- --------
Balance as of December 31, 2002 $ 58,409 $ -- $ 21,471 $ 36,104
======== ======== ======== ========
48
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 3 - Goodwill (continued)
The following is a summary of pro forma net income (loss) and earnings
(loss) per share as adjusted to remove the amortization of goodwill (dollars in
thousands, except per share amounts):
Year Ended December 31,
-------------------------------
2001 2000
---------- ----------
Net income (loss) - as reported $ 11,059 $ (19,045)
Goodwill amortization 7,481 7,481
Income tax impact (1) (1,131) (1,131)
---------- ----------
Net income (loss) - as adjusted $ 17,409 $ (12,695)
========== ==========
Basic earnings (loss) per share:
Net income (loss) - as reported $ 0.12 $ (0.23)
Goodwill amortization 0.08 0.09
Income tax impact (1) (0.01) (0.02)
---------- ----------
Net income (loss) - as adjusted $ 0.19 $ (0.16)
========== ==========
Diluted earnings (loss) per share:
Net income (loss) - as reported $ 0.12 $ (0.23)
Goodwill amortization 0.08 0.09
Income tax impact (1) (0.01) (0.02)
---------- ----------
Net income (loss) - as adjusted $ 0.19 $ (0.16)
========== ==========
(1) Certain goodwill amounts are non-deductible for tax purposes; therefore,
the income tax impact reflects only the deductible goodwill amortization.
49
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt
December 31,
--------------------------
2002 2001
-------- --------
(Dollars in Thousands)
Senior Notes payable in November 2006 with interest of 9.75% payable
semi-annually in May and November, net of unamortized premium of $790 and
$2,085 at December 31, 2002 and 2001, respectively
(effective interest rate of 9.62%) $214,982 $452,065
Deferred gain related to interest rate swap agreements, net of
amortization of $257 2,363 --
Senior Notes payable in November 2009 with interest of 10.125% payable
semi-annually in May and November, net of unamortized premium of $922 at
December 31, 2002
(effective interest rate of 10.03%) 236,534 --
Convertible Subordinated Notes payable in August 2004
with interest of 5.5% payable semi-annually in
February and August 124,509 124,509
Secured promissory note to Boeing Capital Corporation
with interest at 10.1278%, principal and interest
payable monthly over a 60-month term 10,588 15,589
Capital Lease and Other 954 9
-------- --------
Total debt 589,930 592,172
Less current portion 6,486 5,007
-------- --------
Total long-term debt $583,444 $587,165
======== ========
50
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt (continued)
The aggregate maturities of long-term debt for the five years ending
December 31, 2007 are as follows (000's): 2003 - $6,486; 2004 - $129,565; 2005 -
$0; 2006 - $214,192; 2007 - $0.
The Senior Notes were initially issued in November 1996 and in March 1998
in amounts of $300 million (Series B) and $150 million (Series C) at 9.75%. The
$300 million issue was sold at a $2.4 million discount while the $150 million
issue was sold at a premium of $5.7 million. In May 1998, a registration
statement was filed by the Company which offered to exchange the Series B and C
Notes for new Series D Notes. The form and terms of the Series D Notes are
identical in all material respects to the form and terms of the Series B and C
Notes, except for certain transfer restrictions and registration rights relating
to the Series C Notes. All of the Series B Notes except $189 thousand and all of
the Series C Notes were exchanged for new Series D Notes per this offering. As
discussed in Note 6, the Company entered into various interest rate swap
agreements to modify the interest characteristics of the Senior Notes.
On May 2, 2002, the Company announced it had successfully completed the
exchange of $235.6 million in principal amount of new 10.125% Senior Notes due
2009 ("New Notes") for a like amount of its 9.75% Senior Notes due 2006
("Outstanding Notes"), pursuant to an exchange offer described in the Offering
Circular dated April 1, 2002 (the "Exchange Offer"). The consummation of the
Exchange Offer was effected without registration, in reliance on the
registration exemption provided by Section 4(2) of the Securities Act of 1933,
as amended, which applies to offers and sales of securities that do not involve
a public offering, and Regulation D promulgated under that act. On July 1, 2002,
the Company filed a registration statement on Form S-4 offering to exchange the
New Notes for notes of the Company having substantially identical terms in all
material respects as the Outstanding Notes (the "Exchange Notes"). The offer to
exchange the New Notes for Exchange Notes was consummated on September 17, 2002.
The New Notes and Exchange Notes will be governed by the terms of the indenture
executed by the Company, the Subsidiary Guarantors and the trustee dated May 2,
2002, the terms of which are substantially the same as the terms of the 1998
Indenture, as amended by the Fourth Supplemental Indenture, as described below.
In connection with the Exchange Offer, the Company solicited consents to
certain amendments to the definitions and covenants in the indenture under which
the Outstanding Notes were issued, which all participants in the Exchange Offer
were deemed to have accepted. As a result of the participation in the Exchange
Offer of more than 50 percent of the holders of the Outstanding Notes, the
amendments to the 1998 Indenture were agreed, and which amendments have been
effected by the execution of the Fourth Supplemental Indenture by the Company,
the Subsidiary Guarantors and the trustee (as amended, the "1998 Indenture"). As
a result of the Exchange Offer, the Company incurred and expensed fees of
approximately $4.0 million.
51
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt (continued)
In July 1997, the Company issued $175 million of Convertible Subordinated
Notes due 2004. The Notes bear interest at 5.5% payable semi-annually in
February and August. The Notes are convertible at the option of the holder into
shares of common stock of Parker Drilling at $15.39 per share at any time prior
to maturity. The Notes are currently redeemable at the option of the Company at
certain stipulated prices. During the fourth quarter of 2000, the Company
repurchased on the open market $50.5 million principal amount of the 5.5% Notes
at an average price of 86.11 percent of face value, recognizing an extraordinary
gain of $3.9 million, net of $2.2 million of tax. The Note repurchases were
funded with proceeds from an equity offering in September 2000, whereby the
Company sold 13.8 million shares of common stock for net proceeds of
approximately $87.3 million. The amount of outstanding Notes at December 31,
2002 was $124.5 million.
On October 22, 1999, the Company entered into a $50.0 million revolving
loan facility with a group of banks led by Bank of America. The facility is
available for working capital requirements, general corporate purposes and to
support letters of credit and bears interest at prime plus 0.50% or LIBOR plus
2.50%. At December 31, 2002, no amounts have been drawn down against the
facility but $15.7 million of availability of $41.2 million (borrowing base at
December 31, 2002) has been used to support letters of credit that have been
issued. The revolver is collateralized by accounts receivable, inventory and
certain barge rigs located in the Gulf of Mexico. The facility will terminate on
October 22, 2003. The Company plans to renew or replace the revolving loan
facility by the end of the third quarter of 2003.
On October 7, 1999, a wholly owned subsidiary of the Company entered into a
loan agreement with Boeing Capital Corporation for the refinancing of a portion
of the capital cost of barge Rig 75. The loan principal of approximately $24.8
million plus interest is being repaid in 60 monthly payments of approximately
$0.5 million. The loan is collateralized by barge Rig 75 and is guaranteed by
Parker Drilling. The amount of principal outstanding at the end of 2002 was
$10.6 million.
Each of the 10.125% and the 9.75% Senior Notes, 5.5% Convertible
Subordinated Notes and the revolving loan facility contains customary
affirmative and negative covenants, including restrictions on incurrence of debt
and sales of assets. The revolving loan facility contains covenants which
require minimum adjusted tangible net worth, fixed charge coverage ratio and
limits annual capital expenditures. The revolving loan facility prohibits
payment of dividends and the indenture for the Senior Notes restricts the
payment of dividends.
52
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 5 - Guarantor/Non-Guarantor Consolidating Condensed Financial Statements
Set forth on the following pages are the consolidating condensed financial
statements of the restricted subsidiaries and our subsidiaries which are not
restricted by the Senior Notes. All of the Company's Senior Notes are guaranteed
by substantially all wholly owned subsidiaries of Parker Drilling. There are
currently no restrictions on the ability of the subsidiaries to transfer funds
to Parker Drilling in the form of cash dividends, loans or advances. Parker
Drilling is a holding company with no operations, other than through its
subsidiaries. In prior years, the non-guarantors were inconsequential,
individually and in the aggregate, to the consolidated financial statements and
separate financial statements of the guarantors were not presented because
management had determined that they would not be material to investors.
In August, 2002, Parker Drilling Company International Limited ("PDCIL")
entered into an agreement to sell two of its rigs in Kazakhstan to AralParker, a
Kazakhstan joint venture company owned 50 percent by PDCIL and 50 percent by a
Kazakhstan company. Because PDCIL has significant influence over the business
affairs of AralParker, its financial statements are consolidated with those of
the Company.
AralParker, Casuarina Limited (a wholly owned captive insurance company)
and Parker Drilling Investment Company are all non-guarantor subsidiaries whose
aggregate financial position and results of operations are no longer deemed to
be inconsequential and, accordingly the Company is providing consolidating
condensed financial information of the parent, Parker Drilling, the guarantor
subsidiaries, and the non-guarantor subsidiaries for the year ended December 31,
2002.
53
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
Year Ended December 31, 2002
---------------------------------------------------------------------
Parent Guarantor Non-Guarantor Eliminations Consolidated
------ --------- ------------- ------------ ------------
Drilling and rental revenues $ -- $ 280,003 $ 27,772 $ 2,430 $ 310,205
Drilling and rental operating expenses 3 158,498 23,477 2,430 184,408
Depreciation and amortization 1 64,776 3,299 (122) 67,954
--------- --------- -------- --------- ---------
Drilling and rental operating income (loss) (4) 56,729 996 122 57,843
--------- --------- -------- --------- ---------
Construction contract revenue -- 86,818 -- -- 86,818
Construction contract expense -- 84,356 -- -- 84,356
--------- --------- -------- --------- ---------
Net construction contract operating income -- 2,462 -- -- 2,462
--------- --------- -------- --------- ---------
General and administrative expense (1) 361 24,467 -- (100) 24,728
Provision for reduction in carrying
value of certain assets -- 1,140 -- -- 1,140
--------- --------- -------- --------- ---------
Total operating income (loss) (365) 33,584 996 222 34,437
--------- --------- -------- --------- ---------
Other income and (expense):
Interest expense (56,602) (43,106) (1,551) 48,850 (52,409)
Interest income 44,264 3,760 1,677 (48,850) 851
Other income (expense) - net (4,491) 7,839 109 (4,451) (994)
Equity in net earnings of subsidiaries (113,980) -- -- 113,980 --
--------- --------- -------- --------- ---------
Total other income and (expense) (130,809) (31,507) 235 109,529 (52,552)
--------- --------- -------- --------- ---------
Income (loss) before income taxes (131,174) 2,077 1,231 109,751 (18,115)
Income tax expense (benefit): (17,120) 14,284 -- -- (2,836)
--------- --------- -------- --------- ---------
Income (loss) from continuing operations (114,054) (12,207) 1,231 109,751 (15,279)
Discontinued operations, net of taxes -- (25,631) -- -- (25,631)
Cumulative effect of change in accounting
principle -- (73,144) -- -- (73,144)
--------- --------- -------- --------- ---------
Net income (loss) $(114,054) $(110,982) $ 1,231 $ 109,751 $(114,054)
========= ========= ======== ========= =========
(1) All field operations general and administrative expenses are included in
operating expenses.
54
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
December 31, 2002
-----------------------------------------------------------------------
Parent Guarantor Non-Guarantor Eliminations Consolidated
------ --------- ------------- ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents $ 43,254 $ 6,218 $ 2,510 $ -- $ 51,982
Accounts and notes receivable, net 81,551 100,400 19,080 (111,668) 89,363
Rig materials and supplies -- 17,161 -- -- 17,161
Other current assets -- 8,567 27 37 8,631
--------- ----------- -------- ----------- ---------
Total current assets 124,805 132,346 21,617 (111,631) 167,137
--------- ----------- -------- ----------- ---------
Property, plant and equipment, net 151 614,088 40,633 (13,594) 641,278
Assets held for sale -- 896 -- -- 896
Goodwill, net -- 115,983 -- -- 115,983
Investment in subsidiaries and intercompany
advances 808,784 531,959 21,521 (1,362,264) --
Other noncurrent assets 12,556 15,440 (103) 138 28,031
--------- ----------- -------- ----------- ---------
Total assets $ 946,296 $ 1,410,712 $ 83,668 $(1,487,351) $ 953,325
========= =========== ======== =========== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt $ 5,532 $ 954 $ -- $ -- $ 6,486
Accounts payable and accrued liabilities 25,106 150,455 7,218 (132,037) 50,742
Accrued income taxes 1,069 3,278 -- -- 4,347
--------- ----------- -------- ----------- ---------
Total current liabilities 31,707 154,687 7,218 (132,037) 61,575
--------- ----------- -------- ----------- ---------
Long-term debt 583,444 -- -- -- 583,444
Deferred income tax (45,473) 45,473 -- -- --
Other long-term liabilities 1,409 6,271 -- -- 7,680
Intercompany payables 74,583 490,099 44,557 (609,239) --
Stockholders' equity:
Common stock 15,465 61,748 121 (61,869) 15,465
Capital in excess of par value 434,998 1,024,953 5,330 (1,030,283) 434,998
Accumulated other comprehensive income 664 -- -- -- 664
Accumulated deficit (150,501) (372,519) 26,442 346,077 (150,501)
--------- ----------- -------- ----------- ---------
Total stockholders' equity 300,626 714,182 31,893 (746,075) 300,626
--------- ----------- -------- ----------- ---------
Total liabilities and
stockholders' equity $946,296 $ 1,410,712 $ 83,668 $(1,487,351) $ 953,325
========= =========== ======== =========== =========
55
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31, 2002
------------------------------------------------------------------
Parent Guarantor Non-Guarantor Eliminations Consolidated
------ --------- ------------- ------------ ------------
Cash flows from operating activities:
Net income (loss) $(114,054) $(110,982) $ 1,231 $ 109,751 $(114,054)
Adjustments to reconcile net income (loss)
to net cash provided by (used) in operating
activities:
Depreciation and amortization 1 64,776 3,299 (122) 67,954
Gain on disposition of assets (15) (8,049) 3 4,629 (3,432)
Cumulative effect of change in accounting
principle -- 73,144 -- -- 73,144
Provision for reduction in carrying value
of certain assets -- 1,500 -- -- 1,500
Deferred income taxes (17,120) -- -- -- (17,120)
Discontinued operations -- 30,549 -- -- 30,549
Expenses not requiring cash 6,874 4,060 -- (4,889) 6,045
Equity in net earnings of subsidiaries 113,980 -- -- (113,980) --
Change in operating assets and liabilities 28,477 (25,608) (5,853) (8,421) (11,405)
--------- --------- -------- --------- ---------
Net cash provided by (used) in operating
activities 18,143 29,390 (1,320) (13,032) 33,181
--------- --------- -------- --------- ---------
Cash flows from investing activities:
Proceeds from the sale of assets 144 6,307 -- -- 6,451
Capital expenditures (net of reimbursements) (81) (45,181) (43,932) 44,013 (45,181)
--------- --------- -------- --------- ---------
Net cash provided by (used) in investing
activities 63 (38,874) (43,932) 44,013 (38,730)
--------- --------- -------- --------- ---------
Cash flows from financing activities:
Principal payments under debt obligations (5,489) -- -- -- (5,489)
Proceeds from interest rate swap agreements 2,620 -- -- -- 2,620
Intercompany advances, net (23,020) 7,630 46,371 (30,981) --
--------- --------- -------- --------- ---------
Net cash provided by (used) in financing
activities (25,889) 7,630 46,371 (30,981) (2,869)
--------- --------- -------- --------- ---------
Net change in cash and cash equivalents (7,683) (1,854) 1,119 -- (8,418)
Cash and cash equivalents at beginning of year 50,937 8,072 1,391 -- 60,400
--------- --------- -------- --------- ---------
Cash and cash equivalents at end of year $ 43,254 $ 6,218 $ 2,510 $ -- $ 51,982
========= ========= ======== ========= =========
56
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 6 - Derivative Financial Instruments
The Company is exposed to interest rate risk from its fixed-rate debt. The
Company has hedged against a portion of the risk of changes in fair value
associated with its $214.2 million 9.75% Senior Notes by entering into three
fixed-to-variable interest rate swap agreements with a total notional amount of
$150.0 million. The terms of the interest rate swap agreements are as follows:
Months Notional Amount Fixed Rate Floating Rate
------ --------------- ---------- -------------
(Dollars in Thousands)
December 2001 -
November 2006 $50,000 9.75% Three-month LIBOR
plus 446 basis points
January 2002 -
November 2006 $50,000 9.75% Three-month LIBOR
plus 475 basis points
January 2002 -
November 2006 $50,000 9.75% Three-month LIBOR
plus 482 basis points
The Company assumes no ineffectiveness as each interest rate swap agreement
meets the short-cut method requirements under SFAS No. 133 for fair value hedges
of debt instruments. As a result, changes in the fair value of the interest rate
swap agreements are offset by changes in the fair value of the debt and no net
gain or loss is recognized in earnings. During the year ended December 31, 2002,
the interest rate swap agreements reduced interest expense by $2.9 million.
On July 24, 2002, the Company terminated all the interest rate swap
agreements and received $3.5 million. A gain totaling $2.6 million will be
recognized as a reduction to interest expense over the remaining term (ending
November 2006) of the debt instrument, of which $0.3 million was recognized
during 2002.
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes
Income (loss) before income taxes, discontinued operations and cumulative
effect of change in accounting principle is summarized below (dollars in
thousands):
Year Ended December 31,
--------------------------------
2002 2001 2000
-------- -------- --------
United States $(34,351) $ 19 $(19,931)
Foreign 16,236 12,395 3,455
-------- -------- --------
$(18,115) $ 12,414 $(16,476)
======== ======== ========
Income tax expense (benefit) related to continuing operations is summarized as
follows (dollars in thousands):
Year Ended December 31,
--------------------------------
2002 2001 2000
-------- -------- --------
Current:
United States:
Federal $ 104 $ 530 $ --
State -- -- --
Foreign 14,180 12,798 11,084
Deferred:
United States:
Federal (17,120) (1,846) (10,988)
State (53) (314)
-------- -------- --------
$ (2,836) $ 11,429 $ (218)
======== ======== ========
58
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes (continued)
Total income tax expense (benefit) differs from the amount computed by
multiplying income (loss) before income taxes by the U.S. federal income tax
statutory rate. The reasons for this difference are as follows (dollars in
thousands):
Year Ended December 31,
--------------------------------------------------------------
2002 2001 2000
------------------ ------------------ ------------------
% of % of % of
Pre-Tax Pre-Tax Pre-Tax
Amount Income Amount Income Amount Income
------- ------- ------- ------- ------- -------
Computed expected tax
expense (benefit) $(6,340) (35%) $ 4,345 35% $(8,095) (49%)
Foreign taxes, net of
federal benefit 8,986 50% 8,319 67% 5,830 35%
Change in valuation
allowance (2,927) (16%) (9,593) (77%) (6,097) (37%)
Foreign corporation
income (loss) (5,506) (30%) 8,193 66% 6,582 41%
Permanent Differences 2,780 15% 509 4% 509 3%
Other 171 1% (344) (3%) 1,053 6%
------- ------- ------- ------- ------- -------
Actual tax expense
(benefit) $(2,836) (15%) $11,429 92% $ (218) (1%)
======= ======= ======= ======= ======= =======
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes (continued)
The components of the Company's tax assets and (liabilities) as of December
31, 2002 and 2001 are shown below (dollars in thousands):
December 31,
--------------------
2002 2001
-------- --------
Deferred tax assets:
Net operating loss carryforwards $ 49,529 $ 56,025
Alternative minimum tax carryforwards 401 983
Reserves established against realization of certain assets 2,937 1,874
Accruals not currently deductible for tax purposes 5,814 6,388
-------- --------
58,681 65,270
Deferred tax liabilities:
Property, plant and equipment (43,337) (65,079)
Goodwill (8,335) (6,180)
Unrealized gain on investments held for sale -- (227)
-------- --------
Net deferred tax (liability) asset 7,009 (6,216)
Valuation allowance (7,009) (9,936)
-------- --------
Deferred income tax liability $ -- $(16,152)
======== ========
The change in the valuation allowance in 2002 is the result of higher
utilization of net operating loss carryforwards previously reserved because they
were expected to expire unused. The Company has a remaining valuation allowance
of $7,009,000 with respect to its net deferred tax asset for the amount of net
operating loss carryforwards expected to expire unused. However, the amount of
the asset considered realizable could be different in the near term if estimates
of future taxable income change.
At December 31, 2002, the Company had $141,510,000 of net operating loss
carryforwards. For tax purposes the net operating loss carryforwards expire over
a 20-year period ending December 31 as follows: 2007 - $10,141,000; 2008 -
$11,968,000; 2009 - $6,700,000; thereafter - $112,701,000.
60
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity
In September 2000, the Company sold 13.8 million common shares in a public
offering, resulting in net proceeds (after deducting issuance costs) of $87.3
million. The proceeds were used to acquire, upgrade and refurbish certain
offshore and land drilling rigs and for general corporate purposes, including
the repayment of debt.
Stock Plans
The Company's employee and non-employee director stock plans are
summarized as follows:
The 1994 Non-Employee Director Stock Option Plan ("Director Plan")
provides for the issuance of options to purchase up to 200,000 shares of Parker
Drilling's common stock. The option price per share is equal to the fair market
value of a Parker Drilling share on the date of grant. The term of each option
is 10 years, and an option first becomes exercisable six months after the date
of grant. All shares available for issuance under this plan have been granted.
The 1994 Executive Stock Option Plan provides that the directors may grant
a maximum of 2,400,000 shares to key employees of the Company and its
subsidiaries through the granting of stock options, stock appreciation rights
and restricted and deferred stock awards. The option price per share may not be
less than 50 percent of the fair market value of a share on the date the option
is granted, and the maximum term of a non-qualified option may not exceed 15
years and the maximum term of an incentive option is 10 years. All shares
available for issuance under this plan have been granted.
The 1997 Stock Plan initially authorized 4,000,000 shares to be available
for granting to officers and key employees who, in the opinion of the board of
directors, were in a position to contribute to the growth, management and
success of the Company. This plan was approved by the board of directors as a
"broad-based" plan under the interim rules of the New York Stock Exchange and,
as a result, more than 50 percent of the awards under this plan have been made
to non-executive employees. The option price per share may not be less than the
fair market value on the date the option is granted for incentive options and
not less than par value of a share of common stock for non-qualified options.
The maximum term of an incentive option is 10 years and the maximum term of a
non-qualified option is 15 years. The plan was amended in July 1999, April 2001
and September 2002, to grant authority to the compensation committee to issue
awards and to authorize 2,000,000; 1,000,000; and 1,800,000 additional shares,
respectively, for issuance, which shares were registered with the SEC. As of
December 31, 2002, there were 1,227,700 shares available for granting.
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
Information regarding the Company's stock option plans is summarized
below:
1994 Director Plan
--------------------
Weighted
Average
Exercise
Shares Price
-------- --------
Shares under option:
Outstanding at December 31, 1999 200,000 $ 8.431
Granted -- --
Exercised -- --
Cancelled -- --
-------- --------
Outstanding at December 31, 2000 200,000 8.431
Granted -- --
Exercised -- --
Cancelled -- --
-------- --------
Outstanding at December 31, 2001 200,000 8.431
Granted -- --
Exercised -- --
Cancelled -- --
-------- --------
Outstanding at December 31, 2002 200,000 $ 8.431
======== ========
62
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
1994 Option Plan
------------------------------------------------
Incentive Options Non-Qualified Options
---------------------- ----------------------
Weighted Weighted
Average Average
Exercise Exercise
Shares Price Shares Price
--------- --------- --------- ---------
Shares under option:
Outstanding at December 31, 1999 622,564 $ 7.227 1,586,936 $ 6.975
Granted -- -- -- --
Exercised -- -- (18,750) 2.250
Cancelled -- -- -- --
--------- --------- --------- ---------
Outstanding at December 31, 2000 622,564 7.227 1,568,186 7.032
Granted -- -- -- --
Exercised (17,000) 4.500 (1,250) 2.250
Cancelled -- -- -- --
--------- --------- --------- ---------
Outstanding at December 31, 2001 605,564 7.303 1,566,936 7.036
Granted -- -- -- --
Exercised -- -- -- --
Cancelled -- -- -- --
--------- --------- --------- ---------
Outstanding at December 31, 2002 605,564 $ 7.303 1,566,936 $ 7.036
========= ========= ========= =========
63
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
1997 Stock Plan
------------------------------------------------
Incentive Options Non-Qualified Options
---------------------- ----------------------
Weighted Weighted
Average Average
Exercise Exercise
Shares Price Shares Price
--------- --------- --------- ---------
Shares under option:
Outstanding at December 31, 1999 2,794,125 $ 8.038 2,065,575 $ 6.523
Granted 50,000 5.938 15,000 5.062
Exercised (92,094) 3.188 (24,370) 3.188
Cancelled (30,130) 8.564 (2,870) 3.188
--------- --------- --------- ---------
Outstanding at December 31, 2000 2,721,901 8.158 2,053,335 6.556
Granted -- -- 1,485,000 5.167
Exercised (137,061) 3.193 (31,915) 3.188
Cancelled -- -- -- --
--------- --------- --------- ---------
Outstanding at December 31, 2001 2,584,840 8.421 3,506,420 6.000
Granted -- -- 1,385,000 2.301
Exercised (10,196) 3.188 (8,053) 3.188
Cancelled (84,884) 9.020 (105,817) 6.391
--------- --------- --------- ---------
Outstanding at December 31, 2002 2,489,760 $ 8.422 4,777,550 $ 4.924
========= ========= ========= =========
64
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
Outstanding Options
-----------------------
Weighted
Average Weighted
Remaining Average
Number of Contractual Exercise
Plan Exercise Prices Shares Life Price
- -------------------------- ------------------- --------- ----------- --------
1994 Director Plan $ 3.281 - $ 6.125 40,000 4.4 years $ 4.827
$ 8.875 - $ 12.094 160,000 5.5 years $ 9.332
1994 Executive Option Plan
Incentive option $ 4.500 217,554 3.0 years $ 4.500
Incentive option $ 8.875 388,010 5.4 years $ 8.875
Non-qualified $ 2.250 434,946 3.0 years $ 2.250
Non-qualified $ 8.875 1,131,990 5.4 years $ 8.875
1997 Stock Plan
Incentive option $ 3.188 - $ 5.938 791,430 3.4 years $ 3.362
Incentive option $ 8.875 - $ 12.188 1,698,330 4.2 years $ 10.780
Non-qualified $ 2.240 - $ 6.070 3,653,380 5.2 years $ 3.651
Non-qualified $ 8.875 - $ 10.813 1,124,170 4.6 years $ 9.060
Exercisable Options
---------------------
Weighted
Average
Number of Exercise
Plan Exercise Prices Shares Price
- -------------------------- ------------------- --------- --------
1994 Director Plan $ 3.281 - $ 6.125 40,000 $ 4.827
$ 8.875 - $ 12.094 160,000 $ 9.332
1994 Executive Option Plan
Incentive option $ 4.500 217,554 $ 4.500
Incentive option $ 8.875 388,010 $ 8.875
Non-qualified $ 2.250 434,946 $ 2.250
Non-qualified $ 8.875 1,131,990 $ 8.875
1997 Stock Plan
Incentive option $ 3.188 - $ 5.938 778,930 $ 3.321
Incentive option $ 8.875 - $ 12.188 1,698,330 $ 10.780
Non-qualified $ 2.240 - $ 6.070 1,894,630 $ 3.820
Non-qualified $ 8.875 - $ 10.813 1,124,170 $ 9.060
65
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
The Company has three additional stock plans which provide for the
issuance of stock for no cash consideration to officers and key non-officer
employees. Under two of the plans, each employee receiving a grant of shares may
dispose of 15 percent of the grant on each annual anniversary date from the date
of grant for the first four years and the remaining 40 percent on the fifth-year
anniversary. These two plans have a total of 11,375 shares reserved and
available for granting. Shares granted under the third plan are fully vested no
earlier than 24 months from the effective date of the grant and not later than
36 months. The third plan has a total of 1,562,195 shares reserved and available
for granting. No shares were granted under these plans in 2002, 2001 and 2000.
In prior years the Company purchased shares from certain of its employees,
who received stock through its stock option plan, at fair market value. At
December 31, 2001, 604,870 shares were held in Treasury which includes 98,293
shares purchased by the Company at the fair market value of $289,479. These
shares were issued to the Stock Bonus Plan as the Company's matching
contribution. The Plan was funded in January 2002. At December 31, 2002, 506,577
shares were held in Treasury.
66
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
Stock Reserved For Issuance
The following is a summary of common stock reserved for issuance:
December 31,
------------------------
2002 2001
---------- ----------
Stock plans 12,441,135 10,659,380
Stock bonus plan 1,577,221 81,715
Convertible notes 8,090,254 8,090,254
---------- ----------
Total shares reserved for issuance 22,108,610 18,831,349
========== ==========
Stockholder Rights Plan
The Company adopted a stockholder rights plan on June 25, 1998, to assure
that the Company's stockholders receive fair and equal treatment in the event of
any proposed takeover of the Company and to guard against partial tender offers
and other abusive takeover tactics to gain control of the Company without paying
all stockholders a fair price. The rights plan was not adopted in response to
any specific takeover proposal. Under the rights plan, the Company's board of
directors declared a dividend of one right to purchase one one-thousandth of a
share of a new series of junior participating preferred stock for each
outstanding share of common stock. The plan was amended on September 22, 1998,
to eliminate the restriction on the board of directors' ability to redeem the
shares for two years in the event the majority of the board of directors does
not consist of the same directors that were in office as of June 25, 1998
("Continuing Directors"), or directors that were recommended to succeed
Continuing Directors by a majority of the Continuing Directors.
The rights may only be exercised 10 days following a public announcement
that a third party has acquired 15 percent or more of the outstanding common
shares of the Company or 10 days following the commencement of, or announcement
of an intention to make a tender offer or exchange offer, the consummation of
which would result in the beneficial ownership by a third party of 15 percent or
more of the common shares. When exercisable, each right will entitle the holder
to purchase one one-thousandth share of the new series of junior participating
preferred stock at an exercise price of $30, subject to adjustment. If a person
or group acquires 15 percent or more of the outstanding common shares of the
Company, each right, in the absence of timely redemption of the rights by the
Company, will entitle the holder, other than the acquiring party, to purchase
for $30, common shares of the Company having a market value of twice that
amount.
The rights, which do not have voting privileges, expire June 30, 2008, and
at the Company's option, may be redeemed by the Company in whole, but not in
part, prior to expiration for $0.01 per right. Until the rights become
exercisable, they have no dilutive effect on earnings per share.
67
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 9 - Reconciliation of Income and Number of Shares Used to Calculate Basic
and Diluted Earnings Per Share (EPS)
For the Year Ended December 31, 2002
-------------------------------------------------
Loss Shares Per-Share
(Numerator) (Denominator) Amount
------------- -------------- --------------
Basic EPS:
Loss from continuing
operations $ (15,279,000) 92,444,773 $ (0.16)
Discontinued operations,
net of taxes (25,631,000) (0.28)
Cumulative effect
of change in accounting
principle (73,144,000) (0.79)
------------- --------------
Net loss $(114,054,000) $ (1.23)
============= ==============
Effect of dilutive
securities:
Stock options -- -- --
Diluted EPS:
Loss from continuing
operations $ (15,279,000) $ (0.16)
Discontinued operations,
net of taxes (25,631,000) (0.28)
Cumulative effect
of change in accounting
principle (73,144,000) (0.79)
------------- --------------
Net loss $(114,054,000) $ (1.23)
============= ==============
For the Year Ended December 31, 2001
-------------------------------------------------
Loss Shares Per-Share
(Numerator) (Denominator) Amount
------------- -------------- --------------
Basic EPS:
Income from continuing
operations $ 985,000 92,008,877 $ 0.01
Discontinued operations,
net of taxes 10,074,000 0.11
------------- --------------
Net income $ 11,059,000 $ 0.12
============= ==============
Effect of dilutive
securities:
Stock options -- 682,156 --
Diluted EPS:
Income from continuing
operations 985,000 92,691,033 0.01
Discontinued operations,
net of taxes 10,074,000 0.11
------------- --------------
Net income plus assumed
conversions $ 11,059,000 $ 0.12
============= ==============
68
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 9 - Reconciliation of Income and Number of Shares Used to Calculate Basic
and Diluted Earnings Per Share (EPS) (continued)
For the Year Ended December 31, 2000
-------------------------------------------------
Loss Shares Per-Share
(Numerator) (Denominator) Amount
------------- -------------- --------------
Basic EPS:
Loss from continuing
operations $ (16,258,000) 81,758,825 $ (0.20)
Discontinued operations,
net of taxes (2,787,000) (0.03)
------------- --------------
Net loss $ (19,045,000) $ (0.23)
============= ==============
Effect of dilutive
securities:
Stock options -- -- --
Diluted EPS:
Loss from continuing
operations (16,258,000) (0.20)
Discontinued operations,
net of taxes (2,787,000) (0.03)
------------- --------------
Net loss $ (19,045,000) $ (0.23)
============= ==============
The Company has outstanding $124,509,000 of 5.5% Convertible Subordinated
Notes, which are convertible into 8,090,254 shares of common stock at $15.39 per
share. The Notes have been outstanding since their issuance in July 1997, but
were not included in the computation of diluted EPS because the assumed
conversion of the Notes would have had an anti-dilutive effect on EPS. For the
year ended December 31, 2002, options to purchase 9,639,810 shares of common
stock at prices ranging from $2.24 to $12.1875, which were outstanding during
the period, were not included in the computation of diluted EPS because the
assumed exercise of the options would have had an anti-dilutive effect on EPS
due to the net loss incurred for 2002. For the fiscal year ended December 31,
2001, options to purchase 6,049,000 shares of common stock at prices ranging
from $5.00 to $12.1875, which were outstanding during the period, were not
included in the computation of diluted EPS because the options' exercise price
was greater than the average market price of the common shares during the
period. For the year ended December 31, 2000, options to purchase 7,166,036
shares of common stock, respectively, at prices ranging from $2.25 to $12.1875,
were outstanding but not included in the computation of diluted EPS because the
assumed exercise of the options would have had an anti-dilutive effect on EPS
due to the net loss during 2000.
69
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 10 - Employee Benefit Plans
The Parker Drilling Company Stock Bonus Plan ("Plan") was adopted
effective September 1980 for eligible employees of Parker Drilling and its
subsidiaries who have completed three months of service with the Company. It was
amended in 1983 to qualify as a 401(k) plan under the Internal Revenue Code
which permits a specified percentage of an employee's salary to be voluntarily
contributed on a pre-tax basis and to provide for a Company matching feature.
The Plan was amended and restated generally effective January 1, 2001, to comply
with certain tax laws. The Plan was further amended effective January 1, 2002 to
reflect certain provisions of the Economic Growth and Tax Relief Reconciliation
Act of 2001 ("EGTRRA"). Participants may contribute from one percent to 15
percent of eligible earnings and direct contributions to one or more of 13
investment funds. The Plan provides for dollar-for-dollar matching contributions
by the Company up to three percent of a participant's compensation and $0.50 for
every dollar contributed from three percent to five percent. The Company's
matching contribution is made in Parker Drilling common stock and vests
immediately. Each Plan year, additional Company contributions can be made, at
the discretion of the board of directors, in amounts not exceeding the
permissible deductions under the Internal Revenue Code. The Company issued
544,844; 343,289; and 361,855 shares to the Plan in 2002, 2001, and 2000 with
the Company recognizing expense of $1,472,437; $1,927,100; and $1,742,193 in
each of the periods, respectively.
70
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments
The Company is organized into three primary business segments: U.S.
drilling operations, international drilling operations, and rental tools. This
is the basis management uses for making operating decisions and assessing
performance.
Year Ended December 31,
-----------------------------------
Operations by Industry Segment 2002 2001 2000
- ------------------------------------------ --------- ----------- -----------
(Dollars in Thousands)
Drilling and rental revenues:
U.S. drilling $ 74,181 $ 114,377 $ 85,539
International drilling 188,514 177,464 126,633
Rental tools 47,510 65,629 42,833
--------- ----------- -----------
Total drilling and rental revenues 310,205 357,470 255,005
--------- ----------- -----------
Drilling and rental operating income:
U.S. drilling 6,272 24,928 5,015
International drilling 38,587 34,892 12,497
Rental tools 12,984 29,904 16,779
--------- ----------- -----------
Total drilling and rental operating income 57,843 89,724 34,291
Net construction contract operating income 2,462 -- --
General and administrative expense (24,728) (21,721) (20,392)
Provision for reduction in
carrying value of certain assets (1,140) -- (7,805)
Reorganization expense -- (7,500) --
--------- ----------- -----------
Total operating income 34,437 60,503 6,094
Interest expense (52,409) (53,015) (57,036)
Minority interest 278 -- --
Other income (expense) - net (421) 4,926 34,466
--------- ----------- -----------
Income (loss) before income taxes $ (18,115) $ 12,414 $ (16,476)
========= =========== ===========
Identifiable assets:
U.S. drilling $ 307,811 $ 343,357 $ 356,090
International drilling 418,665 424,022 412,839
Rental tools 69,998 70,36 57,550
--------- ----------- -----------
Total identifiable assets 796,474 837,744 826,479
Corporate assets 156,851 268,033 280,940
--------- ----------- -----------
Total assets $ 953,325 $ 1,105,777 $ 1,107,419
========= =========== ===========
71
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments (continued)
Year Ended December 31,
----------------------------------
Operations by Industry Segment 2002 2001 2000
- ---------------------------------------- ------- -------- -------
(Dollars in Thousands)
Capital expenditures:
U.S. drilling $ 6,248 $ 41,366 $22,221
International drilling 22,452 53,732 55,215
Rental tools 14,864 24,210 16,168
Corporate 1,617 2,725 4,921
------- -------- -------
Total capital expenditures $45,181 $122,033 $98,525
======= ======== =======
Depreciation and amortization:
U.S. drilling $19,029 $ 24,996 $25,195
International drilling 34,246 28,313 20,865
Rental tools 12,361 12,302 11,147
Corporate 2,318 2,278 725
------- -------- -------
Total depreciation and amortization $67,954 $ 67,889 $57,932
======= ======== =======
72
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11- Business Segments (continued)
Year Ended December 31,
---------------------------------------
Operations by Geographic Area 2002 2001 2000
- -------------------------------------- --------- ----------- -----------
(Dollars in Thousands)
Drilling and rental revenues:
United States $ 121,691 $ 180,006 $ 128,372
Asia Pacific 38,294 32,246 15,373
Africa and Middle East 53,916 58,988 55,671
CIS 96,304 86,230 55,589
--------- ----------- -----------
Total drilling and rental revenues 310,205 357,470 255,005
--------- ----------- -----------
Drilling and rental operating income
(loss):
United States 19,256 54,832 21,795
Latin America (968) (4) (155)
Asia Pacific 14,069 11,250 (1,947)
Africa and Middle East 9,340 11,832 8,409
CIS 16,146 11,814 6,189
--------- ----------- -----------
Total drilling and rental operating
income (loss) 57,843 89,724 34,291
Net construction contract operating
income 2,462 -- --
General and administrative expense (24,728) (21,721) (20,392)
Provision for reduction in
carrying value of certain assets (1,140) -- (7,805)
Reorganization expense -- (7,500) --
--------- ----------- -----------
Total operating income 34,437 60,503 6,094
Interest expense (52,409) (53,015) (57,036)
Minority interest 278 -- --
Other income (expense) - net (421) 4,926 34,466
--------- ----------- -----------
Income (loss) before income taxes $ (18,115) $ 12,414 $ (16,476)
========= =========== ===========
Identifiable assets:
United States $ 534,660 $ 681,756 $ 702,639
Latin America 88,985 93,722 93,896
Asia Pacific 46,385 39,963 41,602
Africa and Middle East 99,496 94,986 119,607
CIS 183,799 195,350 149,675
--------- ----------- -----------
Total identifiable assets $ 953,325 $ 1,105,777 $ 1,107,419
========= =========== ===========
73
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies
At December 31, 2002, the Company had a $50.0 million revolving credit
facility available for general corporate purposes and to support letters of
credit. As of December 31, 2002, $15.7 million of availability has been reserved
to support letters of credit that have been issued. At December 31, 2002, no
amounts had been drawn under the revolving credit facility.
The Company has various lease agreements for office space, equipment,
vehicles and personal property. These obligations extend through 2009 and are
typically non-cancelable. Most leases contain renewal options and certain of the
leases contain escalation clauses. Future minimum lease payments at December 31,
2002, under operating leases with non-cancelable terms in excess of one year,
are as follows:
2003 $ 3,317
2004 2,264
2005 2,037
2006 2,328
2007 1,315
Thereafter 2,145
----------
Total $ 13,406
==========
Total rent expense for all operating leases amounted to $10.9 million for
2002, $5.5 million for 2001, and $3.7 million for 2000.
Each of the executive officers entered into an employment agreement with
the Company that became effective during 2002. The term of each agreement is for
three years and each provide for automatic extensions of two years, with the
exception of Mr. Brassfield and Mr. Wingerter, whose agreements are for two
years, and Mr. Robert L. Parker whose agreement is for one year. The employment
agreements provide for the following benefits:
*payment of current salary, which may be increased upon review by CEO (or
the Board of Directors in case of CEO and Chairman) on an annual
basis but cannot be reduced except with consent of the executive,
*for payment of target bonuses of up to 100 percent of salary based on
meeting certain incentives (75 percent for Mr. Nash and Mr. Whalen
and 50 percent for Mr. Wingerter and Mr. Brassfield), and
*to be eligible to receive stock options and to participate in other
benefits, including without limitation, paid vacation, 401(k) plan,
health insurance and life insurance.
74
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies (continued)
If the executive's employment is terminated, including by reason of death
or disability or retirement, but excluding termination for cause or termination
as a result of the resignation of the executive, unless for good reason (based
on definitions of cause and good reason in the agreements), the executive is
entitled to receive:
*salary for remainder of month of the termination,
*bonus for the prior year if earned and yet unpaid,
*remainder of vacation pay for the year,
*a severance payment equal to two times the sum of the highest salary and
bonus over the previous three years, except for Mr. Brassfield and
Mr. Wingerter whose payment will be based on a 1.5 times multiplier
("Additional Benefit"), and
*continued health benefits for two years, except for Mr. Brassfield and
Mr. Wingerter who will receive these benefits for 1.5 years ("Other
Benefits").
In consideration for these benefits the executive agrees to perform his
customary duties set forth in the employment agreement, and further covenants
not to solicit business except on behalf of the Company during his employment
and to refrain from hiring employees of the Company or to compete against the
Company for a period of one year following his termination.
In addition to the above benefits, each employment agreement provides that
in the event of a change in control, as defined in the agreement, the term of
the employment agreement will be extended for three years. If the executive is
terminated during this three year period for any reason except for cause or the
executive resigns during the first two years after the change in control for
good reason, the Additional Benefit payable shall be based on three times salary
and bonus, payable in a lump sum, and the Other Benefits shall also be provided
for three years. In certain circumstances, the Company has agreed to make the
executive whole for excise taxes that may apply with respect to payments made
after a change in control. The benefits provided under the employment agreements
executed by the executive officers are in lieu of and replace the benefits under
the Severance Compensation and Consulting Agreements previously executed by the
executive officers, which Severance Compensation and Consulting Agreements have
been terminated.
In addition to the executive officers, six other officers and key
employees entered into employment agreements that were effective on November 1,
2002, with three agreements with officers providing for similar severance
benefits, including change in control provisions, and the remaining agreements
providing similar benefits at lower levels without change in control provisions.
75
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies (continued)
The drilling of oil and gas wells is subject to various federal, state,
local and foreign laws, rules and regulations. The Company, as an owner or
operator of both onshore and offshore facilities operating in or near waters of
the United States, may be liable for the costs of removal and damages arising
out of a pollution incident to the extent set forth in the Federal Water
Pollution Control Act, as amended by the Oil Pollution Act of 1990 ("OPA") and
the Outer Continental Shelf Lands Act. In addition, the Company may also be
subject to applicable state law and other civil claims arising out of any such
incident. Certain of the Company's facilities are also subject to regulations of
the Environmental Protection Agency ("EPA") that require the preparation and
implementation of spill prevention, control and countermeasure plans relating to
possible discharge of oil into navigable waters. Other regulations of the EPA
may require certain precautions in storing, handling and transporting hazardous
wastes. State statutory provisions relating to oil and natural gas generally
include requirements as to well spacing, waste prevention, production
limitations, pollution prevention and cleanup, obtaining drilling and dredging
permits and similar matters.
On July 6, 2001, the Ministry of State Revenues of Kazakhstan ("MSR")
issued an Act of Audit to the Kazakhstan branch ("PKD Kazakhstan") of Parker
Drilling Company International Limited ("PDCIL"), a wholly owned subsidiary of
the Company, assessing additional taxes of approximately $29.0 million for the
years 1998-2000. The assessment consisted primarily of adjustments in corporate
income tax based on a determination by the Kazakhstan tax authorities that
payments by Offshore Kazakhstan International Operating Company, ("OKIOC"), to
PDCIL of $99.0 million, in reimbursement of costs for modifications to Rig 257,
performed by PDCIL prior to the importation of the drilling rig into Kazakhstan,
are income to PKD Kazakhstan, and therefore, taxable to PKD Kazakhstan. PKD
Kazakhstan filed an Act of Non-Agreement that such reimbursements should not be
taxable and requested that the Act of Audit be revised accordingly. In November
2001, the MSR rejected PKD Kazakhstan's Act of Non-Agreement, prompting PKD
Kazakhstan to seek judicial review of the assessment. On December 28, 2001, the
Astana City Court issued a judgment in favor of PKD Kazakhstan, finding that the
reimbursements to PDCIL were not income to PKD Kazakhstan and not otherwise
subject to tax based on the U.S.-Kazakhstan Tax Treaty. The MSR appealed the
decision of the Astana City Court to the Civil Panel of the Supreme Court, which
confirmed the decision of the Astana City Court that the reimbursements were not
income to PKD Kazakhstan in March 2002. Although the court agreed with the MSR's
position on certain minor issues, no additional taxes will be payable as a
result of this assessment. The MSR has until the end of March 2003 to appeal the
decision of the Civil Panel to the Supervisory Panel of the Supreme Court of
Kazakhstan. It may also reopen the case thereafter if material new evidence is
discovered. In addition, the Company has filed a petition with the U.S. Treasury
Department for competent authority review, which is a tax treaty procedure to
resolve disputes as to which country may tax income covered under the treaty.
The U.S. Treasury Department has granted our petition and has initiated
proceedings with the MSR which is ongoing.
The Company is a party to various other lawsuits and claims arising out of
the ordinary course of business. Management, after review and consultation with
legal counsel, considers that any liability resulting from these matters would
not materially affect the results of operations, the financial position or the
net cash flows of the Company.
76
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 13 - Related Party Transactions
On February 27, 1995, the Company entered into a Split Dollar Life
Insurance Agreement with Robert L. Parker and the Robert L. Parker and Catherine
M. Parker Family Trust under Indenture dated 23rd day of July 1993 ("Trust")
pursuant to which the Company agreed to provide life insurance protection for
Mr. and Mrs. Robert L. Parker in the event of the death of Mr. and Mrs. Parker
(the "Agreement"). The Agreement provided that the Trust would acquire and own a
life insurance policy with face amount of $13.2 million and that the Company
would pay the premiums subject to reimbursement by the Trust out of the proceeds
of the policy, with interest to accrue on the premium payments made by the
Company from and after January 1, 2000, at the one-year Treasury bill rate. The
repayment of the premiums was secured by an Assignment of Life Insurance Policy
as Collateral of same date as the Agreement. On October 14, 1996, the Agreement
was amended to provide that interest accrual would be deferred until February
28, 2003, in consideration for the Company's termination of a separate life
insurance policy on the life of Robert L. Parker. On April 19, 2000, the
Agreement was amended and restated to replace the previous policy with two
policies, one for $8.0 million on the life of Robert L. Parker and one for $7.7
million on the lives of both Mr. and Mrs. Robert L. Parker. Mr. Robert L. Parker
Jr., the Company's CEO and son of Robert L. Parker will receive one third of the
net proceeds of the policies.
As of December 31, 2002, the accrued amount of premiums paid by the
Company on the policies and to be reimbursed by the Trust to the Company was
$4.7 million. Due to the adoption of the Sarbanes-Oxley Act of 2002 ("SOX"),
additional loans to executive officers and directors may be prohibited, although
continuance of loans in existence as of July 30, 2002, are allowed; provided
there is no modification to such loans. Because the advancement of additional
annual premiums by the Company may be considered a prohibited loan under SOX,
the Company elected to not advance the $0.6 million premium that was due in
December 2002 pending further clarification from the SEC as to how the Company's
obligation to advance these premiums under the Agreement can be honored without
violating SOX.
Note 14 - Supplementary Information
At December 31, 2002, accrued liabilities included $8.5 million of accrued
interest expense, $4.4 million of workers' compensation and health plan
liabilities and $7.0 million of accrued payroll and payroll taxes. At December
31, 2001, accrued liabilities included $8.2 million of accrued interest expense,
$5.3 million of workers' compensation and health plan liabilities and $10.4
million of accrued payroll and payroll taxes. Other long-term obligations
included $4.7 million and $3.8 million of workers' compensation liabilities as
of December 31, 2002 and 2001, respectively.
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 15 - Selected Quarterly Financial Data (Unaudited)
Quarter
-----------------------------------------------------------------------------------
Year 2002 First Second Third Fourth Total
- ------------------------------- ----------- ----------- ----------- ----------- -----------
(Dollars in Thousands Except Per Share Amounts)
Revenues $ 77,228 $ 75,333 $ 79,759 $ 77,885 $ 310,205
Drilling and rental
operating income $ 13,758 $ 10,932 $ 16,961 $ 16,192 $ 57,843
Operating income $ 8,099 $ 5,359 $ 10,494 $ 10,485 $ 34,437
Loss from continuing
operations $ (1,793) $ (7,672) $ (176) $ (5,638) $ (15,279)
Discontinued operations,
net of taxes $ (9,276) $ (3,817) $ (7,844) $ (4,694) $ (25,631)
Cumulative effect of change
in accounting principle (2) $ (73,144) $ -- $ -- $ -- $ (73,144)
Net loss $ (84,213) $ (11,489) $ (8,020) $ (10,332) $ (114,054)
Basic loss per share:
Loss from continuing
operations $ (0.02) $ (0.08) $ (0.00) $ (0.06) $ (0.16)
Discontinued operations,
net of taxes $ (0.10) $ (0.04) $ (0.09) $ (0.05) $ (0.28)
Cumulative effect of change
in accounting principle (2) $ (0.79) $ -- $ -- $ -- $ (0.79)
Net loss $ (0.91) $ (0.12) $ (0.09) $ (0.11) $ (1.23)
Diluted loss per share: (1)
Loss from continuing
operations $ (0.02) $ (0.08) $ (0.00) $ (0.06) $ (0.16)
Discontinued operations,
net of taxes $ (0.10) $ (0.04) $ (0.09) $ (0.05) $ (0.28)
Cumulative effect of change
in accounting principle (2) $ (0.79) $ -- $ -- $ -- $ (0.79)
Net loss $ (0.91) $ (0.12) $ (0.09) $ (0.11) $ (1.23)
(1) As a result of shares issued during the year, earnings per share for the
year's four quarters, which are based on weighted average shares
outstanding during each quarter, do not equal the annual earnings per
share, which is based on the weighted average shares outstanding during
the year.
(2) The first quarter includes recognition of $73.1 million goodwill
impairment related to the jackup and platform rigs resulting from the
adoption of SFAS No. 142. The impairment provision was included in the
second quarter Form 10-Q, retroactive to January 1, 2002.
78
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 15 - Selected Quarterly Financial Data (continued) (Unaudited)
Quarter
-----------------------------------------------------------------------------------
Year 2001 First Second Third Fourth Total
- --------------------------- ----------- ----------- ----------- ----------- -----------
(Dollars in Thousands Except Per Share Amounts)
Revenues $ 78,351 $ 95,262 $ 96,812 $ 87,045 $ 357,470
Drilling and rental
operating income $ 17,498 $ 25,257 $ 26,196 $ 20,773 $ 89,724
Operating income $ 12,627 $ 15,054 $ 18,965 $ 13,857 $ 60,503
Income (loss) from
continuing operations $ (3,708) $ (5,769) $ (507) $ 10,969 $ 985
Discontinued operations,
net of taxes $ 5,232 $ 8,461 $ 3,532 $ (7,151) $ 10,074
Net income (2) $ 1,524 $ 2,692 $ 3,025 $ 3,818 $ 11,059
Basic earnings (loss) per
share: (1)
Income (loss) from
continuing operations $ (0.04) $ (0.06) $ (0.01) $ 0.12 $ 0.01
Discontinued operations,
net of taxes $ 0.06 $ 0.09 $ 0.04 $ (0.08) $ 0.11
Net income $ 0.02 $ 0.03 $ 0.03 $ 0.04 $ 0.12
Diluted earnings (loss) per
share: (1)
Income (loss) from
continuing operations $ (0.04) $ (0.06) $ (0.01) $ 0.12 $ 0.01
Discontinued operations,
net of taxes $ 0.06 $ 0.09 $ 0.04 $ (0.08) $ 0.11
Net income $ 0.02 $ 0.03 $ 0.03 $ 0.04 $ 0.12
(1) As a result of shares issued during the year, earnings per share for the
year's four quarters, which are based on weighted average shares
outstanding during each quarter, do not equal the annual earnings per
share, which is based on the weighted average shares outstanding during
the year.
(2) The fourth quarter includes a $9.6 million deferred tax benefit resulting
from a reversal of a valuation allowance. See Note 7.
79
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 16 - Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standard Board ("FASB") issued SFAS
No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002 and establishes an
accounting standard requiring the recording of the fair value of liabilities
associated with the retirement of long-term assets in the period in which the
liability is incurred. Accordingly, we adopted this standard in the first
quarter of 2003. We do not expect this standard to have a material impact on our
financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 was effective January
1, 2002. This statement supersedes SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and amends
Accounting Principles Board Opinion ("APB") No. 30 for the accounting and
reporting of discontinued operations, as it relates to long-lived assets. Our
adoption of SFAS No. 144 did not affect our financial position or results of
operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and
Technical Corrections." SFAS No. 145 is effective for fiscal years beginning
after May 15, 2002. We will adopt this standard in 2003 and do not expect it to
have a significant effect on our results of operations or our financial
position. (See Note 17)
In July 2002, the FASB issued SFAS No. 146, "Accounting For Costs
Associated with Exit or Disposal Activities." SFAS No. 146 is effective for exit
or disposal activities initiated after December 31, 2002. We do not expect the
adoption of this standard to have any impact on our financial position or
results of operations.
On December 31, 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure-An Amendment of SFAS No.
123." The standard provides additional transition guidance for companies that
elect to voluntarily adopt the accounting provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." SFAS No. 148 does not change the
provisions of SFAS No. 123 that permit entities to continue to apply the
intrinsic value method of APB No. 25, "Accounting for Stock Issued to
Employees." As we continue to follow APB No. 25, our accounting for stock-based
compensation will not change as a result of SFAS No. 148. SFAS No. 148 does
require certain new disclosures in both annual and interim financial statements.
The required annual disclosures are effective immediately and have been included
in Note 1 of the notes to the consolidated financial statements. The new interim
disclosure provisions will be effective in the first quarter of 2003.
80
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 16 - Recent Accounting Pronouncements (continued)
In November 2002, the FASB issued FASB Interpretation ("FIN") 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantee of Indebtedness of Others." FIN 45 requires that upon
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions for
initial recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's initial
application may not be revised or restated to reflect the effect of the
recognition and measurement provisions of the interpretation. The disclosure
requirements are effective for financial statements of both interim and annual
periods that end after December 15, 2002. The Company is not a guarantor under
any significant guarantees and thus this interpretation is not expected to have
a significant effect on the Company's financial position or results of
operations.
On January 17, 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities, An Interpretation of Accounting Research Bulletin No. 51."
The primary objectives of FIN 46 are to provide guidance on how to identify
entities for which control is achieved through means other than through voting
rights (variable interest entities ("VIE")) and how to determine when and which
business enterprise should consolidate the VIE. This new model for consolidation
applies to an entity in which either (1) the equity investors do not have a
controlling financial interest or (2) the equity investment at risk is
insufficient to finance that entity's activities without receiving additional
subordinated financial support from other parties. See Note 1 of the notes to
the consolidated financial statements regarding our consolidation of AralParker,
a company in which we own a 50 percent equity interest. We are consolidating
this company because we exert significant influence and have a financial
interest in the form of a loan, in addition to our equity interest.
Note 17 - Subsequent Event
Discontinued Operations - In June 2003, the Company's board of directors
approved a plan to sell its Latin American assets consisting of 17 land rigs and
related inventory and spare parts and its Gulf of Mexico offshore assets
consisting of seven jackup rigs and four platform rigs. The Company is actively
marketing the assets through an independent broker and expects to complete the
sales by the end of December, 2003. At June 30, 2003, the net book value of the
assets to be sold exceeded the estimated fair value and as a result an
impairment charge including estimated sales expenses has been recognized in the
amount of $54.0 million. One Latin America land rig and related spare parts were
sold to a third party for $1.8 million in July, 2003.
81
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 17 - Subsequent Event (continued)
The two operations that constitute this plan of disposition meet the
requirements of discontinued operations under the provisions of SFAS No. 144
"Accounting for the Impairment or Disposal of Long-Lived Assets." The
consolidated financial statements have been restated to present the Latin
America operations and the U.S. jackup and platform drilling operations as
discontinued operations. The discontinued operations assets of $145.6 million at
June 30, 2003 are mainly comprised of the estimated fair value of drilling rigs
and related spare parts and supplies. The discontinued operations liabilities of
$7.7 million at June 30, 2003 consist mainly of deferred revenue and estimated
accrued costs to sell the assets. The prior periods presented have been
reclassified to reflect the discontinued operations.
Year Ended December 31,
--------------------------------
2002 2001 2000
-------- --------- ---------
(Dollars in Thousands)
Discontinued operations drilling revenues:
U.S. jackup and platform drilling $ 39,297 $ 76,432 $ 62,877
Latin America drilling 40,444 54,063 58,467
-------- --------- ---------
Total discontinued operations drilling revenues $ 79,741 $ 130,495 $ 121,344
======== ========= =========
Discontinued operations operating income (loss):
U.S. jackup and platform drilling $ 1,799 $ 27,676 $ 19,142
Latin America drilling 10,080 12,707 16,911
Depreciation and amortization (30,549) (29,370) (27,128)
-------- --------- ---------
Total discontinued operations operating
income (loss) (18,670) 11,013 8,925
Other income (expense) - net 535 220 (4,462)
Provision for impairment of assets (360) -- (495)
Tax expense (7,136) (1,159) (6,755)
-------- --------- ---------
Income (loss) from discontinued operations $(25,631) $ 10,074 $ (2,787)
======== ========= =========
During the first quarter of 2003, the Company adopted SFAS No. 145.
Pursuant to the provisions of SFAS No. 145, the Company reclassified the $6.2
million gain on early retirement of debt recognized in 2001 from an
extraordinary gain to an ordinary gain (other income) and included the related
deferred income taxes of $2.2 million in income tax expense.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
This item is not applicable to the Company in that disclosure is required
under Regulation S-X by the Securities and Exchange Commission only if the
Company had changed independent auditors and, if it had, only under certain
circumstances.
Item 9A. CONTROLS AND PROCEDURES
Within the 90-day period prior to the filing of this report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the chief executive officer and chief
financial officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures (as defined in Rule 13a-14 (c)
under the Securities Exchange Act of 1934). Based upon that evaluation, the
chief executive officer and chief financial officer concluded that the Company's
disclosure controls and procedures are effective in timely alerting them to
material information relating to the Company (including its consolidated
subsidiaries) required to be included in the Company's periodic SEC filings.
There have been no significant changes in our internal controls or in
other factors that could significantly affect these controls subsequent to the
date of their evaluation.
82
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is shown in Item 4A "Executive
Officers" and hereby incorporated by reference from the information appearing
under the captions "Proposal One - Election of Directors" in the Company's
definitive proxy statement for the Annual Meeting of Stockholders held April 30,
2003. The Company's definitive proxy was filed on March 26, 2003 with the
Securities and Exchange Commission ("Commission").
Item 11. EXECUTIVE COMPENSATION
Notwithstanding the foregoing, in accordance with the instructions to Item
402 of Regulations S-K, the information contained in the Company's proxy
statement under the sub-heading "Compensation Committee Report on Executive
Compensation" and "Performance Graph" shall not be deemed to be filed as part of
or incorporated by reference into this Form 10-K/A:
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by this item is hereby incorporated by reference
from the information appearing under the captions "Principal Stockholders and
Security Ownership of Management" and "Equity Compensation Plan Information" in
the Company's definitive proxy statement for the Annual Meeting of Stockholders
held April 30, 2003. The Company's definitive proxy was filed on March 26, 2003
with the Commission.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is hereby incorporated by reference
to such information appearing under the caption "Other Information" and "Related
Transactions" in the Company's definitive proxy statement for the Annual Meeting
of Stockholders held April 30, 2003. The Company's definitive proxy was filed on
March 26, 2003 with the Commission.
83
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements of Parker Drilling Company and subsidiaries which are
included in Part II, Item 8:
PAGE
Report of Independent Accountants 36
Consolidated Statement of Operations for the years ended
December 31, 2002, 2001 and 2000 37
Consolidated Balance Sheet as of December 31, 2002 and 2001 38
Consolidated Statement of Cash Flows for the years ended
December 31, 2002, 2001 and 2000 40
Consolidated Statement of Stockholders' Equity for the years
ended December 31, 2002, 2001 and 2000 42
Notes to the Consolidated Financial Statements 43
PAGE
----
(2) Financial Statement Schedule:
Schedule II - Valuation and qualifying accounts 87
(3) Exhibits:
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------
3(a)** - Corrected Restated Certificate of Incorporation of the
Company, as amended on September 21, 1998
(incorporated by reference to Exhibit 3(c) to the
Company's Annual Report on Form 10-K for the fiscal
year ended August 31, 1998).
3(b)** - Rights Agreement dated as of July 14, 1998 between the
Company and Norwest Bank Minnesota, N.A., as rights
agent (incorporated by reference to Form 8-A filed
July 15, 1998.)
3(c)** - Amendment No. 1 to the Rights Agreement dated as of
September 22, 1998 between the Company and Norwest
Bank Minnesota, N.A., as rights agent.
3(d)** - By-laws of the Company, as amended January 31, 2003.
4(a)** - Indenture dated as of March 11, 1998 among the
84
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------
Company, as issuer, certain Subsidiary Guarantors (as
defined therein) and Chase Bank of Texas, National
Association, as Trustee (incorporated by reference to
Exhibit 4.5 to the Company's S-4 Registration
Statement No. 333-49089 dated April 1, 1998).
4(b)** - Indenture dated as of July 25, 1997, between the
Company and Chase B Bank of Texas, National
Association, f/k/a Texas Commerce Bank National
Association, as Trustee, respecting 5 1/2% Convertible
Subordinated Notes due 2004 (incorporated by reference
to Exhibit 4.7 to the Company's S-3 Registration
Statement No. 333-30711).
4(c)** - Loan and Security Agreement dated as of October 22,
1999, between the Company and Bank of America,
National Association, as agent for the lenders,
regarding the $50.0 million revolving line of credit
for loans and letters of credit due October 22, 2003
(incorporated by reference to Exhibit 4(c) to the
Annual Report on Form 10-K for the year ended December
31, 2000).
4(d)** - Indenture dated as of May 2, 2002 between the Company
and JPMorgan Chase Bank, as Trustee, respecting the
10.125% Senior Notes due 2009 (incorporated by
reference to Exhibit 4.1 to the Company's S-4
Registration Statement No. 333-91708).
4.1*** - First Supplemental Indenture dated as of May 3, 2000
between the Company and Chase Bank of Texas, National
Association as Trustee, Respecting 9 3/4% Senior Notes
Due 2006.
4.2*** - Second Supplemental Indenture dated as of June 5, 2001
between the Company and Chase Bank of Texas, National
Association, as Trustee, respecting 9 3/4% Senior
Notes Due 2006.
4.3*** - Fifth Supplemental Indenture dated as of February 1,
2003 between the Company and Chase Bank of Texas
National Association as Trustee, respecting 9 3/4%
Senior Notes Due 2006.
10(a)** - Amended and Restated Parker Drilling Company Stock
Bonus Plan, effective as of January 1, 1999
(incorporated herein by reference to Exhibit 10(a) to
the Company's Quarterly Report on Form 10-Q for the
three months ended March 31, 1999).*
10(b)** - 1994 Parker Drilling Company Deferred Compensation
Plan (incorporated herein by reference to Exhibit
10(h) to Annual Report on Form 10-K for the year ended
August 31, 1995).*
10(c)** - 1994 Non-Employee Director Stock Option Plan
(incorporated herein by reference to Exhibit 10(i) to
Annual Report on Form 10-K for the year ended August
31, 1995).*
10(d)** - 1994 Executive Stock Option Plan (incorporated herein
by reference to Exhibit 10(j) to Annual Report on Form
10-K for the year ended August 31, 1995).*
10(e)** - Third amended and restated 1997 Stock Plan effective
July 24, 2002.*
85
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------
10(f)** - Waiver, Release and Confidentiality Agreement entered
into between James W. Linn and Parker Drilling Company
dated July 17, 2001 (incorporated by reference to
Exhibit 10(f) to Annual Report on Form 10-K for the
year ended December 31, 2001).*
10(g)** - Form of Indemnification Agreement entered into between
Parker Drilling Company and each director and
executive officer of Parker Drilling Company, dated on
or about October 15, 2002.*
10(h)** - Form of Employment Agreement entered into between
Parker Drilling Company and each executive officer of
Parker Drilling Company, effective as of November 2,
2002.*
10(i)** - Separation Agreement and Release entered into between
James Davis and Parker Drilling Company effective
September 26, 2002.*
21** - Subsidiaries of the Registrant.
23*** - Consent of Independent Accountants.
31.1*** - Robert L. Parker Jr., President and Chief Executive
Officer, Certification pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2*** - James W. Whalen, Senior Vice President and Chief
Financial Officer, Certification pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
32.1*** - Robert L. Parker Jr., President and Chief Executive
Officer, Certification pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2*** - James W. Whalen, Senior Vice President and Chief
Financial Officer, Certification pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
* Management Contract, Compensatory Plan or Agreement
** Previously filed in Form 10-K.
*** Furnished with this Form 10-K/A.
(b) Reports on Form 8-K: None.
86
PARKER DRILLING COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Dollars in Thousands)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ------------------------------------- ---------- ---------- ---------- ----------
BALANCE CHARGED BALANCE
AT TO COST AT END
BEGINNING AND OF
CLASSIFICATIONS OF PERIOD EXPENSES DEDUCTIONS PERIOD
- ------------------------------------- ---------- ---------- ---------- ----------
Year ended December 31, 2002:
Allowance for doubtful accounts
and notes $ 2,988 $ 1,904 $ 129 $ 4,763
Reduction in carrying value of
rig materials and supplies $ 2,406 $ 2,400 $ 1,363 $ 3,443
Deferred tax valuation
allowance $ 9,936 $ (2,927) $ -- $ 7,009
Year ended December 31, 2001:
Allowance for doubtful accounts
and notes $ 3,755 $ 360 $ 1,127 $ 2,988
Reduction in carrying value of
rig materials and supplies $ 2,491 $ 1,455 $ 1,540 $ 2,406
Deferred tax valuation
allowance $ 24,939 $ (9,593) $ 5,410 $ 9,936
Year ended December 31, 2000:
Allowance for doubtful accounts
and notes $ 5,677 $ 860 $ 2,782 $ 3,755
Reduction in carrying value of
rig materials and supplies $ 1,539 $ 780 $ (172) $ 2,491
Deferred tax valuation
allowance $ 39,109 $ (6,097) $ 8,073 $ 24,939
87
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PARKER DRILLING COMPANY
By /s/ Robert L. Parker Jr. Date: September 25, 2003
-----------------------------
Robert L. Parker Jr.
President and Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
By: /s/ Robert L. Parker Chairman of the Board and Director September 25, 2003
--------------------------------------
Robert L. Parker
By: /s/ Robert L. Parker Jr. President and Chief Executive September 25, 2003
-------------------------------------- Officer and Director
Robert L. Parker Jr. (Principal Executive Officer)
By: /s/ James W. Whalen Senior Vice President and September 25, 2003
-------------------------------------- Chief Financial Officer
James W. Whalen (Principal Financial Officer)
By: /s/ Robert F. Nash Senior Vice President and September 25, 2003
-------------------------------------- Chief Operating Officer
Robert F. Nash
By: /s/ W. Kirk Brassfield Vice President and September 25, 2003
-------------------------------------- Corporate Controller
W. Kirk Brassfield (Principal Accounting Officer)
By: /s/ James E. Barnes Director September 25, 2003
--------------------------------------
James E. Barnes
By: /s/ Bernard J. Duroc-Danner Director September 25, 2003
--------------------------------------
Bernard J. Duroc-Danner
By: /s/ David L. Fist Director September 25, 2003
--------------------------------------
David L. Fist
By: /s/ Dr. Robert M. Gates Director September 25, 2003
--------------------------------------
Dr. Robert M. Gates
By: /s/ John W. Gibson Director September 25, 2003
--------------------------------------
John W. Gibson
By: /s/ Simon G. Kukes Director September 25, 2003
--------------------------------------
Simon G. Kukes
By: /s/ James W. Linn Director September 25, 2003
--------------------------------------
James W. Linn
By: /s/ R. Rudolph Reinfrank Director September 25, 2003
--------------------------------------
R. Rudolph Reinfrank
88
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
--------- ------------------------------------------------------
4.1*** - First Supplemental Indenture dated as of May 3, 2000
between the Company and Chase Bank of Texas, National
Association as Trustee, Respecting 9 3/4% Senior Notes
Due 2006
4.2*** - Second Supplemental Indenture dated as of June 5, 2001
between the Company and Chase Bank of Texas, National
Association, as Trustee, respecting 9 3/4% Senior
Notes Due 2006.
4.3*** - Fifth Supplemental Indenture dated as of February 1,
2003 between the Company and Chase Bank of Texas
National Association as Trustee, respecting 9 3/4%
Senior Notes Due 2006.
23*** - Consent of Independent Accountants.
31.1*** - Robert L. Parker Jr., President and Chief Executive
Officer, Certification pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2*** - James W. Whalen, Senior Vice President and Chief
Financial Officer, Certification pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
32.1*** - Robert L. Parker Jr., President and Chief Executive
Officer, Certification pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2*** - James W. Whalen, Senior Vice President and Chief
Financial Officer, Certification pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
- ------------------
*** - Furnished with this Form 10-K/A.
91