<PAGE>
Filed Pursuant to Rule 424(b)(5)
File No. 333-67667
[LOGO]
140,146 SHARES
KEY ENERGY SERVICES, INC.
COMMON STOCK
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This prospectus relates to 140,146 shares of our common stock issued
in connection with the acquisition of certain assets of Alliance Drilling
Corporation. The terms of this acquisition were determined by direct
negotiations with the owners of the business, and the shares of common stock
issued are valued at prices reasonably related to current market prices. Our
common stock is listed on the New York Stock Exchange under the symbol "KEG."
The last reported sale price of our common stock on December 20, 2000 was
$8.3125 per share.
We will pay all expenses of this offering. No underwriting discounts
or commissions will be paid in connection with the issuance of common stock in
business combination transactions or acquisitions, although finder's fees may
be paid with respect to specific acquisitions. Any person receiving a finder's
fee may be deemed to be an underwriter within the meaning of Section 2(11) of
the Securities Act of 1933.
INVESTING IN OUR COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON
PAGE S-2 OF THIS PROSPECTUS SUPPLEMENT AND PAGE 6 OF THE PROSPECTUS DATED JUNE
21, 1999.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these securities or
passed upon the adequacy or accuracy of this prospectus supplement or the
prospectus. Any representation to the contrary is a criminal offense.
The date of this prospectus supplement is December 21, 2000.
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TABLE OF CONTENTS
<TABLE>
<CAPTION>
Prospectus Supplement Page
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<S> <C>
The Offering S-1
Risk Factors S-2
Use Of Proceeds S-3
Price Range Of Common Stock And Dividend Policy S-3
Selected Financial Data S-4
Cautionary Note Regarding Forward-Looking Statements S-5
Management's Discussion And Analysis Of Financial Condition And Results Of Operations S-5
Business S-17
Management S-23
Certain Relationships And Related Transactions S-29
Ownership Of Capital Stock S-30
Plan Of Distribution S-31
Legal Matters S-31
Experts S-31
Index to Consolidated Financial Statements F-1
<CAPTION>
Prospectus Page
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<S> <C>
Where You Can Find More Information 3
Key Energy Services, Inc. 4
The Offering 4
Ratio of Earnings of Fixed Charges 5
Forward-Looking Statements 6
Risk Factors 6
Acquisition Terms 11
Selling Security Holders and Plan of Distribution 12
Description of Debt Securities 13
Description of Capital Stock 17
Description of Warrants 18
Legal Matters 18
Experts 19
</TABLE>
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You should rely only on the information contained in this prospectus
and prospectus supplement. We have not authorized anyone to provide you with
information that is different. This prospectus supplement and the prospectus
may only be used where it is legal to sell these securities. The information
in this prospectus and prospectus supplement is only accurate as of the date
of this document.
i
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THE OFFERING
Common stock offered........................ 140,146 shares
Common stock to be outstanding
after the Offering (1)...................... 97,967,690 shares
Use of proceeds............................. The shares of common stock
offered by this prospectus
are being issued in exchange
for substantially all the
assets of Alliance Drilling
Corporation. The Company
intends to use the assets in
the operation of its
business. The Company will
not receive any cash
proceeds in exchange for
issuance of the shares.
New York Stock Exchange symbol............. KEG
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(1) Based on 97,827,544 shares of common stock outstanding as of December
20, 2000. Excludes shares of common stock reserved for future issuance.
S-1
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RISK FACTORS
RISK ASSOCIATED WITH OIL AND GAS INDUSTRY--OUR BUSINESS IS DEPENDENT ON
CONDITIONS IN THE OIL AND GAS INDUSTRY, ESPECIALLY THE PRODUCTION EXPENDITURES
OF OIL AND GAS COMPANIES.
The demand for our services is directly influenced by current and
anticipated oil and gas prices, oil and gas production costs, government
regulation, conditions in the worldwide oil and gas industry, and particularly
on the level of development, exploration and production activity of, and
corresponding spending by, oil and gas companies. Most of our operations are
in the United States where the demand for well servicing and related services
has been subject to significant historical fluctuations. When oil or gas
prices are weak, fewer wells are drilled, resulting in less drilling and less
maintenance work for us. Oil and gas prices have increased recently, and as a
result, demand for our services also has increased. However, periods of
diminished oil and gas prices can be expected in the future, and demand for
our services may decrease during those or other periods. In light of these and
other factors relating to the oil and gas industry, our historical operating
results may not be indicative of future performance. In addition, reductions
in oil or gas prices can result in a reduction in the trading price of our
common stock, even if the reduction in oil or gas prices does not affect our
business generally.
S-2
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USE OF PROCEEDS
We will not receive any proceeds of this offering other than the value
of the businesses or properties we acquire in the proposed acquisitions.
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock is currently traded on the New York Stock Exchange,
under the symbol "KEG." The following tables sets forth, for the periods
indicated, the high and low sales prices of our common stock on the New York
Stock Exchange for the first quarter of fiscal 2001, fiscal 2000 and fiscal
1999, as derived from published sources.
<TABLE>
<CAPTION>
HIGH LOW
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<S> <C> <C>
Fiscal Year Ending 2001:
First Quarter..................................... 11 7/16 7 1/16
Fiscal Year Ending 2000:
Fourth Quarter.................................... 11 7/8 8 1/16
Third Quarter..................................... 12 1/4 5
Second Quarter.................................... 6 7/8 3 7/8
First Quarter..................................... $ 5 13/16 $ 3 3/8
Fiscal Year Ending 1999:
Fourth Quarter.................................... 4 1/2 2 15/16
Third Quarter..................................... 5 5/8 3 1/16
Second Quarter.................................... 11 3/8 3 5/16
First Quarter..................................... $ 14 15/16 6 1/8
</TABLE>
We did not pay dividends on our common stock during the fiscal years
ended June 30, 2000, 1999 or 1998. We do not intend, for the foreseeable
future, to pay dividends on our common stock. In addition, we are
contractually restricted from paying dividends under the terms of our existing
credit facilities.
On December 20, 2000, the last reported sale price for our Common
Stock was $8.3125 per share.
S-3
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SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
FISCAL YEAR ENDED JUNE 30,
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2000 1999(1) 1998 1997 1996(1)
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(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
OPERATING DATA:
Revenues................................ $ 637,732 $ 491,817 $ 424,543 $ 165,773 $66,007
Operating costs:
Direct costs.......................... 462,386 371,428 293,448 114,598 47,112
Depreciation, depletion and amortization 70,972 62,074 31,001 11,076 4,701
General and administrative............ 58,772 53,108 38,987 17,447 6,011
Bad debt expense...................... 1,648 5,928 826 98 131
Debt issuance costs................... -- 6,307 -- -- --
Restructuring charge.................. -- 4,504 -- -- --
Interest.............................. 71,930 67,401 21,476 7,879 2,477
Income before income taxes and minority
interest.............................. (27,976) (78,933) 38,805 14,675 5,575
Net income.............................. (18,959) (53,258) 24,175 9,098 3,586
INCOME PER COMMON SHARE:
Basic................................. $ (0.23) $ (1.94) $ 1.41 $ 0.81 $ 0.46
Diluted............................... $ (0.23) $ (1.94) $ 1.23 $ 0.66 $ 0.45
Average common shares outstanding:
Basic................................. 83,815 27,501 17,153 11,216 7,789
Assuming full dilution................ 83,815 27,501 24,024 17,632 7,941
Common shares outstanding at period end. 97,210 82,738 18,267 12,298 10,414
Market price per common share at period end $ 9.64 $ 3.56 13.12 17.81 8.19
Cash dividends paid on common shares.... $ -- $ -- $ -- $ -- $ --
BALANCE SHEET DATA:
Cash.................................. $109,873 $ 23,478 $ 25,265 $ 41,704 $ 4,211
Current assets........................ 253,589 132,543 127,557 93,333 27,481
Property and equipment................ 920,437 871,940 547,537 227,255 96,127
Property and equipment, net........... 760,561 769,562 499,152 208,186 87,207
Total assets.......................... 1,246,265 1,148,138 698,640 320,095 121,722
Current liabilities................... 97,624 73,151 48,029 33,142 24,339
Long-term debt, including current portion 666,600 699,978 399,779 174,167 46,825
Stockholders' equity.................. 382,887 288,094 154,928 73,179 41,624
OTHER DATA:
Adjusted EBITDA(2).................... $116,574 $ 67,281 $ 92,108 $ 33,728 $12,884
Net cash (used in) provided by:
Operating activities................ 37,051 (13,427) 40,925 843 7,121
Investing activities................ (37,766) (294,654) (306,339) (80,749) (13,551)
Financing Activities................ 87,110 306,294 248,975 117,399 9,366
Working capital..................... 155,965 59,392 79,528 60,191 3,142
Book value per common share(3)...... $ 3.94 $ 3.47 $ 8.48 $ 5.95 $ 4.00
</TABLE>
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(1) THE FINANCIAL DATA FOR THE YEAR ENDED JUNE 30, 1996 INCLUDES THE
ALLOCATED PURCHASE PRICE OF WELLTECH EASTERN AND THE RESULTS OF THEIR
OPERATIONS, BEGINNING MARCH 27, 1996. THE FINANCIAL DATA FOR THE YEAR
ENDED JUNE 30, 1999 INCLUDES THE ALLOCATED PURCHASE PRICE OF DAWSON
PRODUCTION SERVICES, INC. AND THE RESULTS OF THEIR OPERATIONS BEGINNING
SEPTEMBER 15, 1998.
(2) ADJUSTED EBITDA IS NET INCOME BEFORE INTEREST EXPENSE, INCOME TAXES,
DEPRECIATION, DEPLETION AND AMORTIZATION, BAD DEBT EXPENSE, DEBT
ISSUANCE COSTS CHARGED TO EARNINGS, RESTRUCTURING CHARGE AND
EXTRAORDINARY ITEMS. ADJUSTED EBITDA IS PRESENTED BECAUSE OF ITS
ACCEPTANCE AS A COMPONENT OF A COMPANY'S POTENTIAL VALUATION IN
COMPARISON TO COMPANIES IN THE SAME INDUSTRY AND OF A COMPANY'S ABILITY
TO SERVICE OR INCUR DEBT. MANAGEMENT INTERPRETS TRENDS INDICATED BY
CHANGES IN ADJUSTED EBITDA AS AN INDICATOR OF THE EFFECTIVENESS OF ITS
STRATEGIES IN ACHIEVING REVENUE GROWTH AND CONTROLLING DIRECT AND
INDIRECT COSTS OF SERVICES PROVIDED. INVESTORS SHOULD CONSIDER THAT
THIS MEASURE DOES NOT TAKE INTO CONSIDERATION DEBT SERVICE, INTEREST
EXPENSES, COSTS OF CAPITAL, IMPAIRMENTS OF LONG LIVED ASSETS,
DEPRECIATION OF PROPERTY, THE COST OF REPLACING EQUIPMENT OR INCOME
TAXES. ADJUSTED EBITDA SHOULD NOT BE CONSIDERED AS AN ALTERNATIVE TO
NET INCOME, INCOME BEFORE INCOME TAXES, CASH FLOWS FROM OPERATING
ACTIVITIES OR ANY OTHER MEASURE OF FINANCIAL PERFORMANCE PRESENTED IN
ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES. ADJUSTED
EBITDA IS NOT A MEASURE OF FINANCIAL PERFORMANCE UNDER GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES AND IS NOT INTENDED TO REPRESENT CASH
FLOW. ADJUSTED EBITDA MAY NOT BE COMPARABLE TO SIMILARLY TITLED
MEASURES OF OTHER COMPANIES.
(3) BOOK VALUE PER COMMON SHARE IS STOCKHOLDERS' EQUITY AT PERIOD END
DIVIDED BY THE NUMBER OF OUTSTANDING COMMON SHARES AT PERIOD END.
S-4
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The statements in this document that relate to matters that are not
historical facts are "forward-looking statements" within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. When used in this document and the documents incorporated by reference,
words such as "anticipate," "believe," "expect," "plan," "intend," "estimate,"
"project," "will," "could," "may," "predict" and similar expressions are
intended to identify forward-looking statements. Further events and actual
results may differ materially from the results set forth in or implied in the
forward-looking statements. Factors that might cause such a difference include:
o fluctuations in world-wide prices and demand for oil and
natural gas;
o fluctuations in the level of oil and natural gas exploration
and development activities;
o fluctuations in the demand for well servicing, contract
drilling and ancillary oilfield services;
o the existence of competitors, technological changes and
developments in the industry;
o the existence of operating risks inherent in well servicing,
contract drilling and ancillary oilfield services; and
o general economic conditions, the existence of regulatory
uncertainties, the possibility of political instability in any
of the countries in which we conduct business, in addition to
the other matters discussed herein.
The following discussion provides information to assist in the
understanding of our financial condition and results of operations. It should
be read in conjunction with the consolidated financial statements and related
notes appearing elsewhere in this prospectus supplement. Please note that
certain reclassifications have been made to the fiscal 1999 and 1998 financial
data presented below to conform to the fiscal 2000 presentation. The
reclassifications consist primarily of reclassifying as drilling revenues and
expenses, revenues and expenses from the limited drilling operations conducted
by certain of our well servicing divisions that were previously included in
well servicing revenues and expenses in order to report the results of all
drilling operations separately.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2000 VERSUS THREE MONTHS ENDED SEPTEMBER 30,
1999
Our revenue for the first quarter of fiscal 2001 totaled
$191,679,000, representing an increase of $41,787,000, or 28.0% as compared to
the prior year period. The increase in the current period reflects higher
activity levels and improved rates. Our net income for the first quarter of
fiscal 2001 totaled $8,707,000, or $0.09 per share, versus a net loss of
$9,451,000, or $0.11 per share, for the prior year period.
OPERATING REVENUES
WELL SERVICING. Well servicing revenues for the quarter ended
September 30, 2000 increased $35,748,000, or 27.3%, to $166,565,000 from
$130,817,000 for the three months ended September 30, 1999. The increase in
revenues was primarily due to an increase in the number of hours worked and
the effect of higher rig and fluid hauling rates.
CONTRACT DRILLING. Revenues from contract drilling activities for the
quarter ended September 30, 2000 increased $5,687,000, or 34.6%, to
$22,145,000 from $16,458,000 for the three months ended September 30, 1999.
The increase in revenues was primarily due to an increase in equipment
utilization and the effect of higher prices.
S-5
<PAGE>
OIL AND NATURAL GAS PRODUCTION. Revenues from oil and natural gas
production activities for the quarter ended September 30, 2000 increased
$70,000, or 3.5%, to $2,090,000 from $2,020,000 for the three months ended
September 30, 1999. The increase in revenues was due to higher oil and natural
gas prices which were partially offset by lower production volumes.
OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the quarter ended
September 30, 2000 increased $12,472,000, or 12.6%, to $111,686,000 from
$99,214,00 for the three months ended September 30, 1999. The increase was
primarily due to a higher level of activity, increased wages and the cost of
bringing crews and previously idle equipment on line. Well servicing expenses,
as a percentage of well servicing revenue, decreased to 67.1% for the three
months ended September 30, 2000 from 75.8% for the three months ended
September 30, 1999.
CONTRACT DRILLING. Expenses related to contract drilling activities
for the quarter ended September 30, 2000 increased $3,187,000, or 22.3%, to
$17,458,000 from $14,271,000 for the three months ended September 30, 1999.
The increase was primarily due to higher wages and the cost of bringing crews
and previously idle equipment on line and was partially offset by a shift away
from turnkey contracts to footage and day rates. Contract drilling expenses,
as a percentage of contract drilling revenues, decreased to 78.8% for the
three months ended September 30, 2000 from 86.7% for the three months ended
September 30, 1999.
OIL AND NATURAL GAS PRODUCTION. Expenses related to oil and natural
gas production activities for the quarter ended September 30, 2000 increased
$323,000, or 32.3%, to $1,323,000 from $1,000,000 for the three months ended
September 30, 1999. Oil and natural gas production costs decreased to $6.98
per BOE for the three months ended September 30, 2000 from $7.32 per BOE for
the three months ended September 30, 1999. The increase in production costs is
primarily due to increased rates for electricity and other operating services
partially offset by lower production volumes.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
Our depreciation, depletion and amortization expense for the quarter
ended September 30, 2000 increased $1,490,000, or 8.9% to $18,311,000 from
$16,821,000 for the three months ended September 30, 1999. The increase is due
to increased capital expenditures during the past twelve months as we
refurbished equipment and increased utilization of its contract drilling
equipment (which it depreciates based on utilization).
GENERAL AND ADMINISTRATIVE EXPENSES
Our general and administrative expenses for the quarter ended
September 30, 2000 increased $455,000, or 3.3% to $14,367,000 from $13,912,000
for the three months ended September 30, 1999. The increase was due to higher
administrative costs necessitated by growth of our operations as a result of
improved industry conditions. Despite the increased costs, general and
administrative expenses, as a percentage of revenues, decreased to 7.5% for
the three months ended September 30, 2000 from 9.3% for the three months ended
September 30, 1999.
INTEREST EXPENSE
Our interest expense for the quarter ended September 30, 2000
decreased $1,277,000, or 7.3% to $16,111,000, from $17,388,000 for the three
months ended September 30, 1999. The decrease was primarily due to a
significant reduction in our long-term debt using proceeds from our equity
offering and operating cash flow and was partially offset by higher interest
rates on our floating rate debt. Included in the interest expense was the
amortization of debt issuance costs of $1,408,000 and $1,255,000 for the three
months ended September 30, 2000 and 1999, respectively.
S-6
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BAD DEBT EXPENSE
Our bad debt expense for the quarter ended September 30, 2000
decreased $283,000, or 59.3% to $194,000 from $477,000 for the three months
ended September 30, 1999. The decrease was largely due to an improvement in
market conditions for our customers.
EXTRAORDINARY GAIN
During the three months ended September 30, 2000, we repurchased
$10,996,000 of our long-term debt which resulted in an after-tax gain of
$1,197,000.
INCOME TAXES
Our income tax expense for the quarter ended September 30, 2000
increased $8,459,000 to an expense of $4,719,000 from a benefit of $3,740,000
for the three months ended September 30, 1999. The increase in income tax
expense is due to the increase in pretax income. Our effective tax rate for
the three months ended September 30, 2000 and 1999 was 39% and 28%,
respectively. The effective tax rates are different from the statutory rate of
35% because of the disallowance of certain goodwill amortization, other
non-deductible expenses and state and local taxes. We do not expect to be
required to remit federal income taxes for the next few fiscal years because
of the availability of net operating loss carry forwards from fiscal 1999 and
previous years.
FISCAL YEAR ENDED JUNE 30, 2000 VERSUS FISCAL YEAR ENDED JUNE 30, 1999
Our results of operations for the year ended June 30, 2000 reflect
the impact of the recent industry recovery resulting from increased commodity
prices which in turn caused increased demand for our equipment and services
during fiscal 2000. The positive impact of this increased demand on our
operating results was partially offset by increased operating expenses
incurred as a result of the increase in our business activity.
Our revenues for the year ended June 30, 2000 increased $145,915,000,
or 29.7%, to $637,732,000 from $491,817,000 in fiscal 1999, while net income
for fiscal 2000 increased $34,299,000 to a net loss of $18,959,000 from a net
loss of $53,258,000 in fiscal 1999. The increase in revenues is due to
improved operating conditions and higher rig hours, the full year effect of
the acquisitions completed during the early portion of fiscal 1999 and, to a
lesser extent, higher pricing. The decrease in net loss is the result of
improved operating conditions, higher pricing, and cost reduction initiatives.
In addition, fiscal 1999 included non-recurring charges for debt issuance
costs and restructuring initiatives as well as higher bad debt expense.
OPERATING REVENUES
WELL SERVICING. Well servicing revenues for the year ended June 30,
2000 increased $125,835,000 or 29%, to $559,492,000 from $433,657,000 in
fiscal 1999. The increase was due to increased demand for our well servicing
equipment and services, the full year effect of the acquisitions completed
during the early portion of fiscal 1999 and, to a lesser extent, higher
pricing.
CONTRACT DRILLING. Contract drilling revenues for the year ended June
30, 2000 increased $17,815,000, or 35.2%, to $68,428,000 from $50,613,000 in
fiscal 1999. The increase was due to increased demand for our contract
drilling equipment and services, the full year effect of the acquisition
completed during the early portion of fiscal 1999 and, to a lesser extent,
higher pricing.
OIL AND NATURAL GAS PRODUCTION. Oil and natural gas production
revenues for the year ended June 30, 2000 increased $2,930,000, or 45.3%, to
$9,391,000 from $6,461,000 in fiscal 1999. The increase was due to a 44%
increase in the price of oil and gas received on a barrel of oil equivalent
(BOE) basis in fiscal 2000 compared to fiscal 1999, partially offset by a 2%
decrease in the volume of oil and gas produced on a BOE basis.
S-7
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OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the year ended June 30,
2000 increased $74,975,000, or 23.1%, to $399,940,000 from $324,965,000 in
fiscal 1999. The increase in expenses is due to higher utilization of our well
servicing equipment, higher labor costs and the overall increase in our well
servicing business. Despite the increased costs, well servicing expenses as a
percent of well servicing revenues decreased from 74.9% for fiscal 1999 to
71.5% for fiscal 2000. The margin improvement is due to improved operating
efficiencies and the effects of higher pricing.
CONTRACT DRILLING. Contract drilling expenses for the year ended June
30, 2000, increased $14,743,000, or 33.8%, to $58,299,000 from $43,556,000 in
fiscal 1999. The increase is due to higher utilization of our contract
drilling equipment, higher labor costs and the overall increase in our
contract drilling business. Despite the increased costs, contract drilling
expenses as a percentage of contract drilling revenues decreased from 86.1% in
fiscal 1999 to 85.2% in fiscal 2000. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing.
OIL AND NATURAL GAS PRODUCTION. Oil and natural gas production
expenses for the year ended June 30, 2000, increased $1,240,000, or 42.7%, to
$4,147,000 from $2,907,000 in fiscal 1999. The increase is due to higher
production costs partially offset by lower production. Oil and natural gas
production costs increased from $5.50 per BOE in fiscal 1999 to $6.60 per BOE
in fiscal 2000. The increase in cost per BOE is primarily due to increased
costs incurred in bringing previously dormant wells back into production.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
Our depreciation, depletion and amortization expense for the year
ended June 30, 2000 increased $8,898,000, or 14.3%, to $70,972,000 from
$62,074,000 in fiscal 1999. The increase is due to higher capital expenditures
incurred during fiscal 2000 as we refurbished equipment and increased
utilization of our contract drilling equipment (which it depreciates based on
utilization).
GENERAL AND ADMINISTRATIVE EXPENSES
Our general and administrative expenses for the year ended June 30,
2000 increased $5,664,000, or 10.7%, from $53,108,000 to $58,772,000 in fiscal
2000. The increase was due to higher administrative costs necessitated by the
growth of our operations as a result of the fiscal 1999 acquisitions and
improved industry conditions. Despite the increased costs, general and
administrative expenses as a percentage of total revenues declined from 10.8%
in fiscal 1999 to 9.2% in fiscal 2000.
INTEREST EXPENSE
Our interest expense for the year ended June 30, 2000 increased
$4,529,000, or 6.7%, to $71,930,000 from $67,401,000 in fiscal 1999. The
increase was primarily due to the full year effect of the debt incurred in
connection with the acquisitions completed during the early portion of fiscal
1999, and, to a lesser extent, higher interest rates during fiscal 2000
Partially offset by the impact of the long-term debt reduction during fiscal
2000.
BAD DEBT EXPENSE
Our bad debt expense for the year ended June 30, 2000 decreased
$4,280,000, or 72.2%, to $1,648,000 from $5,928,000 in fiscal 1999. The
decrease was primarily due to improved industry conditions for our customers
and, to a lesser extent, the centralization of our internal credit approval
process.
EXTRAORDINARY GAIN
During the fourth quarter of fiscal 2000, we repurchased $10,190,000
of our 5% Convertible Subordinated Notes which resulted in an after-tax gain
of $1,611,000.
S-8
<PAGE>
INCOME TAXES
Our income tax benefit for the year ended June 30, 2000 decreased
$18,269,000 to $7,406,000 from $25,675,000 in fiscal 1999. The decrease in
income tax benefit is due to the decrease in pretax loss. Our effective tax
benefit rate for fiscal 2000 and 1999 was 26.5% and 32.5%, respectively. The
fiscal 2000 effective tax benefit rate is different from the statutory rate
of 35% because of the disallowance of certain goodwill amortization and other
non-deductible expenses. The decrease in the fiscal 2000 effective tax
benefit rate was due to an increase in the amount of disallowed items
primarily as a result of the full year effect of the goodwill amortization of
the acquisitions completed during the early portion of fiscal 1999. We do not
expect to be required to remit significant federal income taxes for the next
few fiscal years because of the availability of net operating loss
carryforwards from fiscal 2000 and previous years.
CASH FLOW
The net cash provided by operating activities for the year ended
June 30, 2000 increased $50,478,000 to a positive $37,051,000 from a negative
$13,427,000 in fiscal 1999. The increase is due to higher revenues resulting
from increased demand for our equipment and services, the full year effect of
the acquisitions completed during the early portion of fiscal 1999 and, to a
lesser extent, higher pricing, partially offset by higher operating and
general and administrative expenses resulting from increased business
activity.
The net cash we used in investing activities for the year ended June
30, 2000 decreased $256,888,000, or 87.2%, to $37,766,000 from $294,654,000
in fiscal 1999. The decrease is due to no acquisitions having occurred during
fiscal 2000 partially offset by higher capital expenditures.
The net cash provided by our financing activities for the year ended
June 30, 2000 decreased $219,184,000, or 71.6%, to $87,110,000 from
$306,929,000 in fiscal 1999. The decrease is primarily the result of
significantly decreased borrowings during fiscal 2000 and, to a lesser
extent, the repayment of long-term debt partially offset by proceeds from our
equity offering and the Production Payment.
FISCAL YEAR ENDED JUNE 30, 1999 VERSUS FISCAL YEAR ENDED JUNE 30, 1998
Our results of operations for the year ended June 30, 1999 reflect
the impact of a significant and unprecedented decline in demand for our
equipment and services in all of our lines of business experienced from
December 1998 to March 1999. We believe that the decline in demand for its
equipment and services during fiscal 1999 was due solely to the adverse
impact on its customers' capital spending caused by a decline in oil prices
to a twelve-year low of below $11.00 per barrel in December 1998, and, to a
lesser extent, a significant decline in natural gas prices (see Major
Developments During Fiscal 2000--Industry Recovery). Near the beginning of
this decline, during the first four months of fiscal 1999, we completed seven
acquisitions. While the positive impact of these fiscal 1999 acquisitions (as
well as the impact of a full 12 months of the prior fiscal year's
acquisitions) on our revenues compensated for the negative revenue impact of
the decline in business, the acquisitions could not compensate for and could
only partially offset our decline in net income (see Note 3 to Consolidated
Financial Statements--Business and Property Acquisitions).
Our revenues for the year ended June 30, 1999 increased $67,274,000,
or 15.8%, to $491,817,000 in fiscal 1999 from $424,543,000 in fiscal 1998,
while net income for fiscal 1999 decreased $77,433,000 to a net loss of
$53,258,000 in fiscal 1999, from a positive $24,175,000 in fiscal 1998. The
increase in revenues was primarily due to well servicing and contract
drilling acquisitions completed during the latter portion of fiscal 1998 and
the early portion of fiscal 1999, partially offset by a significant decline
in equipment utilization and, to a lesser extent, pricing of oilfield
services throughout fiscal 1999. The decrease in net income is due to the
decline in equipment utilization and, to a lesser extent, pricing of oilfield
services during most of fiscal 1999 and the existence of a high level of
fixed costs and expenses, including depreciation, depletion and amortization,
general and administrative, and interest. In addition, fiscal 1999 included
charges for bad debt expense, debt issuance costs and restructuring that were
far greater than such charges taken during fiscal 1998.
S-9
<PAGE>
OPERATING REVENUES
WELL SERVICING. Well servicing revenues for the year ended June 30,
1999 increased $77,419,000 or 21.7%, to $433,657,000 in fiscal 1999 from
$356,238,000 in fiscal 1998. The increase in revenues was primarily due to
acquisitions completed during the latter portion of fiscal 1998 and the early
portion of fiscal 1999 partially offset by a significant decline in equipment
utilization and, to a lesser extent, pricing of oilfield services throughout
fiscal 1999.
CONTRACT DRILLING. Revenues from contract drilling activities for
the year ended June 30, 1999 decreased $7,586,000, or 13%, to $50,613,000 in
fiscal 1999 from $58,199,000 in fiscal 1998. The decrease in revenues was
primarily due to a significant decline in equipment utilization and, to a
lesser extent, pricing of oilfield services throughout fiscal 1999 partially
offset by acquisitions completed during the latter portion of fiscal 1998 and
the early portion of fiscal 1999.
OIL AND NATURAL GAS PRODUCTION. Revenues from oil and natural gas
production activities for the year ended June 30, 1999 decreased $569,000, or
8%, to $6,461,000 in fiscal 1999 from $7,030,000 in fiscal 1998. The decrease
in revenues was primarily due to a 21% decrease in the price of oil and gas
received on a barrel of oil equivalent ("BOE") basis in fiscal 1999, compared
to fiscal 1998, partially offset by a 16% increase, from fiscal 1998 to
fiscal 1999, in the volume of oil and gas produced on a BOE basis.
OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the year ended June 30,
1999 increased $77,360,000, or 31.2%, to $324,965,000 in fiscal 1999 from
$247,605,000 in fiscal 1998. The increase was primarily due to acquisitions
completed during the latter portion of fiscal 1998 and the early portion of
fiscal 1999 partially offset by a significant decline in equipment
utilization and, to a lesser extent, pricing of oilfield services throughout
fiscal 1999. Well servicing expenses, as a percentage of well servicing
revenue, increased to 75% for fiscal 1999 from 69.5% for fiscal 1998. The
increase was due to a shift in revenue mix from higher margin, higher priced
well services to lower margin, lower priced well services, reduced pricing
for well services, and a lag in reducing costs in response to declines in
utilization and revenues.
CONTRACT DRILLING. Expenses related to contract drilling activities
for the year ended June 30, 1999 increased $696,000, or 1.6%, from
$42,860,000 in fiscal 1998 to $43,556,000 in fiscal 1999. The increase was
primarily due to acquisitions completed during the latter portion of fiscal
1998 and the early portion of fiscal 1999 offset by a decline in equipment
utilization and, to a lesser extent, pricing of oilfield services throughout
fiscal 1999. Contract drilling expenses, as a percentage of contract drilling
revenues, increased to 86.1% in fiscal 1999 from 73.6% in fiscal 1998. The
increase was due to reduced pricing for contract drilling and a lag in
reducing costs in response to declines in utilization and revenues.
OIL AND NATURAL GAS PRODUCTION. Expenses related to oil and natural
gas production activities for the year ended June 30, 1999 decreased $76,000,
or 3%, to $2,907,000 in fiscal 1999 from $2,983,000 in fiscal 1998. Oil and
natural gas production costs decreased to $5.50 per BOE in fiscal 1999 from
$6.55 per BOE in fiscal 1998. The decrease per BOE is primarily due to an
increase in gas production as compared to oil production, from the prior
year, resulting from to an acquisition of natural gas properties during the
latter portion of fiscal 1998 and development drilling of natural gas wells
during fiscal 1998 and the early portion of fiscal 1999.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
Our depreciation, depletion and amortization expense for the year
ended June 30, 1999 increased $31,073,000, or 100%, to $62,074,000 in fiscal
1999 from $31,001,000 in fiscal 1998. The increase is primarily due to an
increase in oilfield service depreciation resulting from the well servicing
and contract drilling acquisitions completed during the latter portion of
fiscal 1998 and the early portion of fiscal 1999.
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<PAGE>
GENERAL AND ADMINISTRATIVE EXPENSES
Our general and administrative expenses for the year ended June 30,
1999 increased $14,121,000, or 36%, to $53,108,000 in fiscal 1999 from
$38,987,000 in fiscal 1998. The increase was primarily due to well servicing
and contract drilling acquisitions completed during the latter portion of
fiscal 1998 and the early portion of fiscal 1999.
INTEREST EXPENSE
Our interest expense for the year ended June 30, 1999 increased
$45,925,000, or 214%, to $67,401,000 in fiscal 1999 from $21,476,000 in
fiscal 1998. The increase was primarily due to additional debt incurred in
connection with the well servicing and contract drilling acquisitions
completed during the latter portion of fiscal 1998 and the early portion of
fiscal 1999 and, to a lesser extent, higher interest rates and amortization
of additional debt issuance costs (see Note 5 to Consolidated Financial
Statements--Long Term Debt).
BAD DEBT EXPENSE
Our bad debt expense for the year ended June 30, 1999 increased
$5,102,000, or 618%, to $5,928,000 in fiscal 1999 from $826,000 in fiscal
1998. The increase was primarily due to the significant decline in commodity
prices and a corresponding deterioration in market conditions in fiscal 1999
causing a small number of our customers to become insolvent.
DEBT ISSUANCE COSTS
During fiscal 1999, we recorded an expense of $6,307,000, which
represented the write-off of debt issuance costs. The debt issuance costs
were associated with our bridge loan which was subsequently repaid using the
proceeds from our private offering of our 14% Senior Subordinated Notes.
RESTRUCTURING CHARGE
In response to an industry downturn caused by historically low oil
and gas prices and the resulting slowdown in business, on December 7, 1998,
we announced a company-wide restructuring plan to reduce operating costs
beyond those achieved through our consolidation efforts. The plan involved a
reduction in the size of management and on-site work force, salary reductions
averaging 21% for senior management, the combination of previously separate
operating divisions and the elimination of redundant overhead and facilities.
The restructuring plan resulted in pretax charges to earnings of
approximately $6.7 million in the second quarter ending December 31, 1998 and
$1.5 million in the third quarter ending March 31, 1999. However, due to an
increase in oil and gas prices beginning during the fourth quarter, we
amended our restructuring plan to decrease the number of planned employee
terminations. Increased demand for our services made such terminations
unnecessary and would have, in management's opinion, restricted our ability
to provide services to customers. Consequently, we did not utilize
approximately $3.7 million of the pretax charges. Essentially all of the
unutilized portion of the restructuring charge was reversed in the quarter
ending June 30, 1999 resulting in a total pretax charge for the fiscal year
ended June 30, 1999 of approximately $4.5 million. The charges include
severance payments and other termination benefits for 97 employees, lease
commitments related to closed facilities and environmental studies performed
on closed leased yard locations.
INCOME TAXES
Our income tax expense for the year ended June 30, 1999 decreased
$40,305,000 to a benefit of $25,675,000 in fiscal 1999 from an expense of
$14,630,000 in fiscal 1998. The decrease in income taxes is due to the
decrease in pretax income. Our effective tax benefit rate for fiscal 1999 and
fiscal 1998 was 32.5% and 37.7%, respectively. The fiscal 1999 effective tax
benefit rate is different from the statutory rate of 35% because of the
disallowance of certain goodwill amortization, other non-deductible expenses
and state and local taxes. We do not expect to be required to remit federal
income taxes for the next few fiscal years because of the availability of net
operating loss carry forwards from fiscal 1999 and previous years.
S-11
<PAGE>
CASH FLOW
The net cash provided by our operating activities for the year ended
June 30, 1999 decreased $54,352,000 to a negative $13,427,000 in fiscal 1999
from a positive $40,925,000 in fiscal 1998. The decrease is primarily due to
the decline in equipment utilization and, to a lesser extent, pricing of
oilfield services during throughout fiscal 1999 and the existence of a high
level of fixed costs, including general and administrative expenses and
interest.
The net cash we used in investing activities for the year ended June
30, 1999 decreased $11,685,000, or 4%, to $294,654,000 in fiscal 1999 from
$306,339,000 in fiscal 1998. The decrease is primarily due to decreased
capital expenditures resulting from reduced equipment utilization.
The net cash provided by our financing activities for the year ended
June 30, 1999 increased $57,319,000 or 23%, to $306,294,000 in fiscal 1999
from $248,975,000 in fiscal 1998. The increase is primarily the result of
proceeds from borrowings and the Equity Offering.
LIQUIDITY AND CAPITAL RESOURCES
We have historically funded our operations, acquisitions, capital
expenditures and working capital requirements from cash flow from operations,
bank borrowings and the issuance of equity and long-term debt. We believe
that the current reserves of cash and cash equivalents, access to our
existing credit lines, access to capital markets and internally generated
cash flow from operations are sufficient to finance the cash requirements of
our current and future operations.
As of September 30, 2000, we had working capital (excluding the
current portion of long-term debt) of approximately $89,253,000 which
includes cash and cash equivalents of approximately $2,635,000 as compared to
working capital (excluding the current portion of long-term debt) of
approximately $175,396,000, which includes cash and cash equivalents of
approximately $109,873,000 as of June 30, 2000. The decrease in working
capital is primarily due to the use of cash to repay long-term debt during
the quarter ended September 30, 2000. Working capital, excluding the change
in cash, actually increased for the three months ended September 30, 2000
which was the result of timing differences related to cash receipts and
disbursements. Receivables are higher due to the increase in revenues caused
by the increased utilization of our equipment base and payables are also
higher due to the addition of more employees and greater costs related to the
increased equipment utilization.
CAPITAL EXPENDITURES
Capital expenditures for fiscal 2001 are expected to equal or exceed
fiscal 2000 levels. Expenditures will be directed toward selectively
refurbishing our assets as business conditions warrant. We will continue to
evaluate opportunities to acquire or divest assets or businesses to enhance
our primary operations. Such capital expenditures, acquisitions and
divestitures are at our discretion and will depend on management's view of
market conditions as well as other factors.
LONG-TERM DEBT
SENIOR CREDIT FACILITY
As of September 30, 2000, we had a borrowing capacity of
approximately $323 million under our senior credit facility (the "Senior
Credit Facility") with a syndicate of banks led by PNC Bank, N.A. which
consisted of a $150,000,000 revolving loan facility and $173,223,907 in
Tranche B term loans. In addition, up to $20,000,000 of letters of credit can
be issued under the Senior Credit Facility, but any outstanding letters of
credit reduce the borrowing availability under the revolving loan facility.
As of September 30, 2000, approximately $23,000,000 was drawn under the
revolving loan facility and approximately $15,132,000 of letters of credit
related to workmen's compensation insurance were outstanding.
The revolving loan bears interest based upon, at our option, the
prime rate plus a variable margin of 0.75% to 2.00% or a Eurodollar rate plus
a variable margin of 2.25% to 3.50%. The Tranche B loans bear interest based
S-12
<PAGE>
upon, at the Company's option, the prime rate plus 2.50% or a Eurodollar rate
plus 4.00%. The Credit Facility has customary affirmative and negative
covenants including a maximum debt to capitalization ratio, a minimum
interest coverage ratio, a maximum senior leverage ratio, a minimum net worth
and minimum EBITDA ratio as well as restrictions on capital expenditures,
acquisitions and dispositions.
The revolving loans and the Tranche A term loan bear interest at
rates based upon, at our option, either the prime rate plus a margin ranging
from 0.75% to 2.00% or a Eurodollar rate plus a margin ranging from 2.25% to
3.50%, in each case depending upon the ratio of our total debt (less cash on
hand over $5 million) to our trailing 12-month EBITDA, as adjusted. The
Tranche B term loan bears interest at rates based upon, at our option, either
the prime rate plus 2.50% or a Eurodollar rate plus 4.00%. We pay commitment
fees on the unused portion of the revolving loan at a varying rate (depending
upon the pricing ratio) of between 0.25% and 0.50%.
During fiscal 2000, we repaid approximately $22.2 million under the
term loans while increasing net borrowings under the revolver by $3 million.
As a result, at June 30, 2000, the principal amount outstanding under (i) the
Tranche A term loan was approximately $23 million, (ii) the Tranche B term
loan was approximately $176 million and (iii) the revolver was approximately
$93 million. Additionally, at June 30, 2000, we had outstanding letters of
credit totaling approximately $15 million related to its workman's
compensation insurance.
Since June 30, 2000, a portion of the net proceeds from the Equity
Offering (see Note 10 to the Consolidated Financial Statements--Stockholders'
Equity) was used to repay the entire outstanding balance of the Tranche A
term loan, and $2.3 million of the Tranche B term loan, reducing the
principal amount outstanding under the Tranche B term loan to approximately
$174 million. The Tranche B term loan prepayments were applied to reduce
mandatory repayment installments of the Tranche B term loan pro rata, thereby
equally reducing all amortization payments without altering the amortization
schedule. In addition, $65 million of the net proceeds from the Equity
Offering was used to repay a portion of the senior credit facility revolver
reducing the amount outstanding under the revolver immediately thereafter to
approximately $28 million. The remainder of the net proceeds of the Equity
Offering was used to retire other long term debt. The principal amount
outstanding under the revolver has since been further reduced to $23 million
as of September 28, 2000. See Note 5 to Consolidated Financial
Statements--Long Term Debt for further discussion of the Senior Credit
Facility.
14% SENIOR SUBORDINATED NOTES
On January 22, 1999, pursuant to Rule 144A and Regulation S under
the Securities Act, we completed the private placement of 150,000 units (the
"Units") consisting of $150,000,000 of 14% Senior Subordinated Notes due 2009
(the "14% Senior Subordinated Notes") and 150,000 warrants to purchase
2,032,565 shares of common stock at an exercise price of $4.88125 per share
(the "Unit Warrants"). The cash proceeds from the private placement, net of
fees and expenses, were used to repay substantially all of the remaining
$148.6 million principal amount (plus accrued interest) owed under our bridge
loan facility arranged in connection with the acquisition of Dawson.
On and after January 15, 2004, we may redeem some or all of the 14%
Senior Subordinated Notes at any time at varying redemption prices in excess
of par, plus accrued interest. In addition, before January 15, 2002, we may
redeem up to 35% of the aggregate principal amount of the Senior Subordinated
Notes with the proceeds of certain offerings of equity at 114% of par, plus
accrued interest.
The Unit Warrants have separated from the 14% Senior Subordinated
Notes and became exercisable on January 25, 2000. On the date of issuance,
the value of the Unit Warrants was estimated at $7,434,000 and is classified
as a discount to the 14% Senior Subordinated Notes on our consolidated
balance sheet. The discount is being amortized to interest expense over the
term of the 14% Senior Subordinated Notes. The 14% Senior Subordinated Notes
mature and the Unit Warrants expire on January 15, 2009. The 14% Senior
Subordinated Notes are subordinate to our senior indebtedness, which, as
defined in the indenture under which the 14% Senior Subordinated Notes were
issued, includes borrowings under the Credit Agreement and the Dawson 9 3/8%
Senior Notes.
At June 30, 2000, $150,000,000 principal amount of the 14% Senior
Subordinated Notes remained outstanding. The 14% Senior Subordinated Notes
pay interest semi-annually on January 15 and July 15 of each year.
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<PAGE>
Interest of approximately $10,092,000 and $10,500,000 was paid on July 15,
1999 and January 15, 2000, respectively. As of June 30, 2000, 52,000 Unit
Warrants had been exercised. We received approximately $3.7 million in
proceeds from the exercise of the Unit Warrants leaving 98,000 Unit Warrants
outstanding.
5% CONVERTIBLE SUBORDINATED NOTES
On September 25, 1997, we completed an initial closing of our
private placement of $200 million of 5% Convertible Subordinated Notes due
2004 (the "5% Convertible Subordinated Notes"). On October 7, 1997, we
completed a second private placement of an additional $16 million of the 5%
Convertible Subordinated Notes pursuant to the exercise of the remaining
portion of the over-allotment option granted to the initial purchasers of the
5% Convertible Subordinated Notes. The placements were made as private
offerings pursuant to Rule 144A and Regulation S under the Securities Act.
The 5% Convertible Subordinated Notes are subordinate to our senior
indebtedness, which, as defined in the indenture under which the 5%
Convertible Subordinated Notes were issued, includes borrowings under the
Credit Agreement, the 14% Senior Subordinated Notes and the Dawson 9 3/8%
Senior Notes. The 5% Convertible Subordinated Notes are convertible, at the
holder's option, into shares of common stock at a conversion price of $38.50
per share, subject to certain adjustments.
The 5% Convertible Subordinated Notes are redeemable, at our option,
on or after September 15, 2000, in whole or part, together with accrued and
unpaid interest. The initial redemption price is 102.86% for the year
beginning September 15, 2000 and declines ratably thereafter on an annual
basis.
During the quarter ended June 30, 2000, we repurchased (and
canceled) $10,190,000 principal amount of the 5% Convertible Subordinated
Notes, leaving $205,810,000 principal amount of the 5% Convertible
Subordinated Notes outstanding at June 30, 2000. Since June 30, 2000, we
repurchased (and canceled) an additional $10,196,000 principal amount of the
5% Convertible Subordinated Notes, leaving $195,614,000 outstanding as of
September 28, 2000. Interest on the 5% Convertible Subordinated Notes is
payable on March 15 and September 15. Interest of approximately $5.4 million
was paid on September 15, 1999 and March 15, 2000.
7% CONVERTIBLE SUBORDINATED DEBENTURES
In July 1996, we completed a $52,000,000 private placement of 7%
Convertible Subordinated Debentures due 2003 (the "7% Convertible
Subordinated Debentures") pursuant to Rule 144A under the Securities Act. The
7% Convertible Subordinated Debentures are subordinate to our senior
indebtedness, which, as defined in the indenture under which the 7%
Convertible Subordinated Debentures were issued, includes borrowings under
the Credit Agreement, the 14% Senior Subordinated Notes and the Dawson 9 3/8%
Senior Notes.
The Debentures are convertible, at any time prior to maturity, at
the holders' option, into shares of common stock at a conversion price of
$9.75 per share, subject to certain adjustments. In addition, holders who
converted prior to July 1, 1999 were entitled to receive a payment, in cash
or common stock (at our option) generally equal to 50% of the interest
otherwise payable from the date of conversion through July 1, 1999.
The 7% Convertible Subordinated Debentures are redeemable, at our
option, on or after July 15, 1999, at a redemption price of 104%, decreasing
1% per year on each anniversary date thereafter.
During fiscal 2000, $3,600,000 in principal amount of the 7%
Convertible Subordinated Debentures was converted into 369,229 shares of
common stock. An additional 11,261 shares of common stock were issued
representing 100% of the interest otherwise payable from January 1, 2000
through July 1, 2000. The additional 11,261 shares of common stock,
representing 100% of the interest otherwise payable from January 1, 2000
through July 1, 2000, are included in equity. In addition, the proportional
amount of unamortized debt issuance costs associated with the converted 7%
Convertible Subordinated Debentures was charged to additional paid-in capital
at the time of conversion.
At June 30, 2000, $1,000,000 principal amount of the 7% Convertible
Subordinated Debentures remained outstanding. On August 31, 2000, $985,000
principal amount of the 7% Convertible Subordinated Debentures were
surrendered for conversion by the holders thereof and 101,025 shares of
common stock were issued on September 1,
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<PAGE>
2000. On September 1, 2000, the remaining $15,000 principal amount of the
outstanding 7% Convertible Subordinated Debentures was redeemed at 103% of
the principal amount plus accrued interest, leaving none outstanding as of
September 28, 2000. Interest on the 7% Convertible Subordinated Debentures
was payable on January 1 and July 1 of each year. Interest of approximately
$161,000 was paid on July 1, 1999 and January 1, 2000.
DAWSON 9 3/8% SENIOR NOTES
As the result of the Dawson acquisition, we, our subsidiaries and
U.S. Trust Company of Texas, N.A., as trustee ("U.S. Trust"), entered into a
Supplemental Indenture dated September 21, 1998 (the "Supplemental
Indenture"), pursuant to which we assumed the obligations of Dawson under the
Indenture dated February 20, 1997 (the "Dawson Indenture") between Dawson and
U.S. Trust. Most of our subsidiaries guaranteed those obligations and the
senior notes due 2007 (the "Dawson 9 3/8% Senior Notes") issued pursuant to
the Dawson Indenture were equally and ratably secured with the obligations
under the Credit Agreement. On November 17, 1998, we completed a cash tender
offer to purchase the full $140,000,000 outstanding principal amount of
Dawson 9 3/8% Senior Notes at 101% of the aggregate principal amount of the
notes, using borrowings under the Credit Agreement. Under the tender offer,
$138,594,000 in principal amount of the Dawson 9 3/8% Senior Notes was
redeemed and a premium of $1,386,000 was paid. In addition, accrued interest
of $4,078,000 was paid at redemption.
At June 30, 1999, $1,406,000 principal amount of the Dawson 9 3/8%
Notes remained outstanding. During the quarter ended June 30, 2000, we
repurchased $300,000 principal amount of the Dawson 9 3/8% Senior Notes,
leaving $1,106,000 principal amount of the Dawson 9 3/8% Senior Notes
outstanding at June 30, 2000. Since June 30, 2000, we repurchased an
additional $800,000 principal amount of the Dawson 9 3/8% Senior Notes,
leaving $306,000 principal amount outstanding as of September 28, 2000.
Interest on the Dawson 9 3/8% Senior Notes is payable on February 1 and
August 1 of each year. Interest of approximately $65,906 was paid on August
1, 1999 and February 1, 2000.
IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS
The Financial Accounting Standards Board has recently issued the
following accounting standard which will be adopted by Key in the future.
In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" which, as amended, is
effective for fiscal years beginning after June 15, 2000. This statement
establishes accounting and reporting standards for derivative instruments and
for hedging activities. Key will adopt this statement effective July 1, 2000.
The oil and gas collars currently in place will be marked to market through
the income statement until such time as they are documented as hedges.
IMPACT OF INFLATION ON OPERATIONS
Management is of the opinion that inflation has not had a significant
impact on our business.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
At September 30, 2000, we had long-term debt outstanding of
$558,154,000. Of this amount $340,931,000, or 61.1%, bears interest at fixed
rates as follows:
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<PAGE>
<TABLE>
<CAPTION>
(000'S)
BALANCE AT
9/30/00
-----------------
<S> <C>
5% Convertible Subordinated Notes Due 2004......................................... $195,614
14% Senior Subordinated Notes Due 2009............................................. 143,836
Dawson 9 3/8% Senior Notes Due 2007................................................ 306
Other (rates generally ranging from 8.0% to 8.5%).................................. 1,175
-----------------
$340,931
-----------------
</TABLE>
The remaining $217,223,000 of debt outstanding as of September 30,
2000 bears interest at floating rates which averaged approximately 10.27% at
September 30, 2000. A 10% increase in short-term interest rates on the
floating-rate debt outstanding at September 30, 2000 would equal
approximately 103 basis points. Such an increase in interest rates would
increase our fiscal 2001 interest expense by approximately $2.2 million
assuming borrowed amounts remain outstanding.
The above sensitivity analysis for interest rate risk excludes
accounts receivable, accounts payable and accrued liabilities because of the
short-term maturity of such instruments.
FOREIGN CURRENCY RISK
Our net assets, net earnings and cash flows from our Argentina
subsidiaries are currently not exposed to foreign currency risk, as
Argentina's currency is tied to the U.S. dollar. Our net assets, net earnings
and cash flows from our Canadian subsidiary is based on the U.S. dollar
equivalent of such amounts measured in Canadian dollars. Assets and
liabilities of the Canadian operations are translated to U.S. dollars using
the applicable exchange rate as of the end of a reporting period. Revenues,
expenses and cash flow are translated using the average exchange rate during
the reporting period.
A 10% change in the Canadian-to-U.S. Dollar exchange rate would not
be material to our net assets, net earnings or cash flows.
COMMODITY PRICE RISK
Our major market risk exposure for our oil and natural gas
production operations is in the pricing applicable to oil and natural gas
sales. Realized pricing is primarily driven by the prevailing worldwide price
for crude oil and spot market for natural gas. Pricing for oil and natural
gas production has been volatile and unpredictable for several years.
We periodically enter into financial hedging activities with respect
to a portion of our projected oil and natural gas production through
commodity option or collar contracts. We pay a premium for option contracts.
These financial hedging activities are intended to support oil and natural
gas prices at targeted levels and to manage our exposure to oil and gas price
fluctuations. Realized gains or losses from the settlement of these financial
hedging instruments are recognized in oil and gas sales when the associated
production occurs. The gains and losses realized as a result of these hedging
activities are substantially offset in the cash market when the hedged
commodity is delivered.
As of September 30, 2000, we had oil and natural gas price collars
in place which represented 4,000 barrels of oil production per month and
approximately 30,000 Mmbtu of gas production per month. The total fiscal 2001
hedged oil and natural gas volumes represent 26% and 18% respectively, of
expected calendar year total production.
The following table sets forth the future volumes hedged by year and
the weighted-average strike price of the option contracts at September 30,
2000:
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<PAGE>
<TABLE>
<CAPTION>
MONTHLY INCOME
----------------------
OIL GAS TERM STRIKE PRICE PER FAIR
(BBLS) (MMBTU) BBL/MMBTU VALUE
-------- ---------- ------------------- ------------------ ----------
<S> <C> <C> <C> <C> <C>
At September 30, 2000.......... ---
Oil Collars................ 4,000 --- Oct 2000 - Feb 2001 $ 22.20 - $26.50 99,820
5,000 Mar 2001 - Feb 2002 $ 19.70 - $23.70 272,580
Gas Collars................ 30,000 Oct 2000 - Feb 2001 $ 2.60 - $3.19 300,450
40,000 Mar 2001 - Feb 2002 $ 2.40 - $2.91 670,560
</TABLE>
(The strike prices for oil are based on the NYMEX spot price for
West Texas Intermediate; the strike prices for gas are based on the Inside
FERC-West Texas Waha spot price).
BUSINESS
THE COMPANY
We are the largest onshore, rig-based well servicing contractor in
the world, with approximately 1,400 well service rigs and 1,200 fluid hauling
vehicles as of June 30, 2000. We provide a complete range of well services to
major and independent oil and natural gas production companies, including:
rig-based well maintenance, workover, completion, and recompletion services
(including horizontal recompletions); oilfield trucking services; and
ancillary oilfield services. We conduct well servicing operations onshore in
the continental United States in the following regions: Gulf Coast (including
South Texas, Central Gulf Coast of Texas and South Louisiana), Permian Basin
of West Texas and Eastern New Mexico, Mid-Continent (including the Anadarko,
Hugoton and Arkoma Basins and ArkLaTex region), Four Corners (including the
San Juan, Piceance, Uinta, and Paradox Basins), Eastern (including the
Appalachian, Michigan and Illinois Basins), Rocky Mountains (including the
Denver-Julesberg, Powder River, Wind River, Green River and Williston
Basins), and California (the San Joaquin Basin), and internationally in
Argentina and Ontario, Canada. We are also a leading onshore drilling
contractor, with 73 land drilling rigs as of June 30, 2000. We conduct land
drilling operations in a number of major domestic producing basins, as well
as in Argentina and in Ontario, Canada. We also produces and develops oil and
natural gas reserves in the Permian Basin region and Texas Panhandle.
Our principal executive offices are located at Two Tower Center,
20th Floor, East Brunswick, New Jersey 08816. Our phone number is (732)
247-4822 and website address is www.keyenergy.com.
BUSINESS STRATEGY
We have built our leadership position through the consolidation of
smaller, less viable competitors. This consolidation, together with a
continuing decline in the number of available domestic well service rigs due
to attrition, cannibalization and transfers outside of the United States, has
given us the opportunity to capitalize on improved market conditions which
existed during fiscal 2000. We have focused on maximizing results by reducing
debt, building strong customer alliances, refurbishing rigs and related
equipment, and training personnel to maintain a qualified and safe employee
base.
REDUCING DEBT. Over the past fiscal year, we have significantly
reduced debt and strengthened our balance sheet. At June 30, 2000, our
long-term funded debt net of cash (net funded debt) was approximately
$534,816,000 and its net funded debt to capitalization was approximately 58%
as compared to approximately $656,194,000 and 69%, respectively, at June 30,
1999. We expect to be able to continue to reduce debt from available cash
flow from operations and from anticipated interest savings resulting from
prior and future debt reductions and future debt refinancings.
BUILDING STRONG CUSTOMER ALLIANCES. We seek to maximize customer
satisfaction by offering a broad range of equipment and services in
conjunction with highly trained and motivated employees. As a result, we are
able to offer proactive solutions for most of the situations encountered at
the wellsite. We ensure consistent high standards of quality and customer
satisfaction by continually evaluating our performance. We maintain strong
alliances with several major oil and natural gas production companies as well
as several independent oil and natural gas production companies and believes
that such alliances improve the stability of demand for its oilfield services.
S-17
<PAGE>
REFURBISHING RIGS AND RELATED EQUIPMENT. We intend to continue
actively refurbishing our rigs and related equipment to maximize the
utilization of our rig fleet. The increase in cash flow, both from operations
and from anticipated interest savings from reduced levels of debt, combined
with the increased revolver availability, has provided ample liquidity and
resources necessary to make the capital expenditures to refurbish such
equipment.
TRAINING AND DEVELOPING EMPLOYEES. We have, and will continue to,
devote significant resources to the training and professional development of
our employees with a special emphasis on safety. We currently have two
training centers in Texas and one training center in California to improve
our employees' understanding of operating and safety procedures. We recognize
the historically high turn-over rate in the industry and are committed to
offering compensation, benefits and incentive programs for our employees that
are attractive and competitive in the industry, in order to ensure a steady
stream of qualified, safe personnel to provide quality service to our
customers.
MAJOR DEVELOPMENTS DURING FISCAL 2000
INDUSTRY RECOVERY
During the fourth quarter of calendar year 1997, an imbalance began
to develop in the supply and the demand for crude oil. Reduced demand was
fueled by the Asian recession and two consecutive unusually warm winters in
North America. The supply of crude oil increased as a result of increased
production quotas by the Organization of Petroleum Exporting Countries
("OPEC") and renewed production by Iraq. The resulting excess supply of crude
oil caused significant declines in crude oil prices during calendar year 1998
and the first quarter of calendar year 1999. Crude oil prices averaged $14 to
$15 per barrel during calendar year 1998 compared to $20 to $21 per barrel
during calendar year 1997 and reached a 12-year low of below $11.00 per
barrel in December 1998. Natural gas prices were also lower during the second
half of calendar year 1998 as unusually warm winters in North America during
calendar years 1997 and 1998 resulted in weaker demand with prices reaching a
low of approximately $1.60 per Mcf in early calendar year 1999. Reduced
prices for crude oil and natural gas led to a sharp decline in the demand for
oilfield services as oil and natural gas companies significantly reduced
capital spending for exploration, development and production activities well
into calendar year 1999. Our operations were significantly impacted by the
downturn in the industry throughout fiscal 1999, and, in response to this
downturn, we reduced operating and administrative costs and delayed capital
spending.
In March 1999, OPEC and other non-OPEC oil-producing countries,
substantially reduced production to a point which, together with improving
demand for oil, caused crude oil prices to recover significantly through the
spring and summer of 1999. In addition, these oil producing countries agreed
to production quotas to be adjusted based on demand in order to keep crude
oil prices in the range of $22 to $28 per barrel. The successful
implementation and subsequent adherence to these quotas, along with improving
demand, have led to increased crude oil prices during fiscal 2000 with WTI
Cushing prices averaging $25.97 per barrel during such period. In addition,
domestic natural gas prices increased significantly due to increased demand
during that period with Nymex Henry Hub prices averaging $3.04 per Mcf during
such period.
This increase in commodity prices led to a steady, sequential
increase in the demand for our services and equipment during fiscal 2000 as
our customers increased their exploration and development activity in our
primary market areas. This increase in demand resulted in sequential
increases in revenues, cash flow and net income in each quarter of fiscal
2000 over the same quarter of fiscal 1999. We expect demand for our services
to remain at or above current levels as long as commodity prices remain at or
near their current levels.
The level of our revenues, cash flows, losses and earnings are
substantially dependent upon, and affected by, the level of domestic and
international oil and gas exploration and development activity (see
Management's Discussion and Analysis of Results of Operations and Financial
Condition).
DEBT REDUCTION
During fiscal 2000, we significantly reduced our long-term debt and
strengthened our balance sheet. At June 30, 2000, our net funded debt was
approximately $534,816,000 and our net funded debt to capitalization was
approximately 59% as compared to approximately $656,194,000 and 69%,
respectively, at June 30, 1999. Proceeds
S-18
<PAGE>
from the Equity Offering (defined below), the Production Payment (defined
below) and exercises of options and warrants, and cash flow from operations
were used to accomplish this reduction in net funded debt (see Management's
Discussion and Analysis of Results of Operations and Financial
Condition--Long-Term Debt).
EQUITY OFFERING
On June 30, 2000, we closed the public offering of 11,000,000 shares
of common stock at $9.625 per share, or approximately $106 million (the
"Equity Offering"). Net proceeds from the Equity Offering were approximately
$101 million, approximately $25.3 million of which was used to immediately
repay a portion of our senior credit facility term loans (approximately $23
million for the Tranche A term loan and approximately $2.3 million for the
Tranche B term loan) and $65 million of which was subsequently used to repay
a portion of the senior credit facility revolver. After these repayments, the
Tranche A term loan had been paid in full, the Tranche B term loan had been
reduced to approximately $174 million, and the revolver had been reduced to
approximately $28 million. The remainder of the net proceeds were used to
retire other long-term debt. As a result of the Equity Offering, total shares
outstanding as of June 30, 2000 were approximately 96.8 million, an increase
of approximately 12.8% over the amount outstanding immediately prior to the
Equity Offering (see Note 10 to Consolidated Financial Statements--Stockholders'
Equity).
VOLUMETRIC PRODUCTION PAYMENT
In March 2000, we sold a part of our future oil and natural gas
production from Odessa Exploration Incorporated ("Odessa Exploration"), a
wholly owned subsidiary, for gross proceeds of $20 million pursuant to an
agreement under which the purchaser is entitled to receive a share of the
production from certain oil and natural gas properties in amounts ranging
from 3,500 to 10,000 barrels of oil and 58,800 to 122,100 Mmbtu of natural
gas per month over a six year period ending February 2006. The total volume
of the forward sale is approximately 486,000 barrels of oil and 6.135 million
Mmbtus of natural gas. The transaction is referred to elsewhere in this
report as the "Production Payment."
DESCRIPTION OF BUSINESS SEGMENTS
We operate in three business segments which are well servicing,
contract drilling and oil and natural gas production. Our operations are
conducted both domestically and internationally in Argentina and Canada. The
following is a description of each of these business segments (for financial
information regarding these business segments, see Note 15 to Consolidated
Financial Statements--Business Segment Information).
WELL SERVICING
We provide a full range of well services, including rig-based
services, oilfield trucking services and ancillary oilfield services,
necessary to maintain and workover oil and natural gas producing wells.
Rig-based services include: maintenance of existing wells, workovers of
existing wells, completion of newly drilled wells, recompletion of existing
wells (including horizontal recompletions) and plugging and abandonment of
wells at the end of their useful lives.
WELL SERVICE RIGS
Our well service rig fleet performs four major rig services to oil
and natural gas operators.
MAINTENANCE SERVICES. We estimate that there are approximately
600,000 producing oil wells and approximately 300,000 producing natural gas
wells in the United States. We provide the well service rigs, equipment and
crews for maintenance services, which are performed on both oil and natural
gas wells, but which are more commonly required on oil wells. While some oil
wells in the United States flow oil to the surface without mechanical
assistance, most require pumping or some other method of artificial lift. Oil
wells that require pumping characteristically require more maintenance than
flowing wells due to the operation of the mechanical pumping equipment
installed. Few natural gas wells have mechanical pumping systems in the
wellbore, and, as a result, maintenance work on natural gas wells is less
frequent.
S-19
<PAGE>
Maintenance services are required throughout the life of most
producing natural gas and oil wells to ensure efficient and continuous
operation. These services consist of routine mechanical repairs necessary to
maintain production from the well, such as repairing inoperable pumping
equipment in an oil well or replacing defective tubing in a natural gas well,
and removing debris such as sand and paraffin from the well. Other services
include pulling the rods, tubing, pumps and other downhole equipment out of
the wellbore to identify and repair a production problem.
Maintenance services are often performed on a series of wells in
proximity to each other and typically require less than 48 hours per well to
complete. The general demand for maintenance services is closely related to
the total number of producing oil and natural gas wells in a geographic
market, and maintenance services are generally the most stable type of well
service activity. The average cost of a maintenance job typically ranges
between $800 and $1,500, excluding the costs of parts, services and other
vendors at the wellsite.
WORKOVER SERVICES. In addition to periodic maintenance, producing
oil and natural gas wells occasionally require major repairs or
modifications, called "workovers". Workover services are performed to enhance
the current production of existing wells. Such services include extensions of
existing wells to drain new formations either through deepening wellbores to
new zones or through drilling of horizontal lateral wellbores to improve
reservoir drainage patterns. In less extensive workovers, our rigs are used
to seal off depleted zones in existing wellbores and access previously
bypassed productive zones. Our workover rigs are also used to convert former
producing wells to injection wells through which water or carbon dioxide is
then pumped into the formation for enhanced recovery operations. Other
workover services include: major subsurface repairs such as casing repair or
replacement, recovery of tubing and removal of foreign objects in the
wellbore, repairing downhole equipment failures, plugging back the bottom of
a well to reduce the amount of water being produced with the oil and natural
gas, cleaning out and recompleting a well if production has declined, and
repairing leaks in the tubing and casing. These extensive workover operations
are normally performed by a well service rig with a workover package, which
may include rotary drilling equipment, mud pumps, mud tanks and blowout
preventers depending upon the particular type of workover operation. Most of
our well service rigs are designed for and can be equipped to perform complex
workover operations.
Workover services are more complex and time consuming than routine
maintenance operations and consequently may last from a few days to several
weeks. These services are almost exclusively performed by well service rigs.
The average cost of a workover project typically ranges between $5,000 and
$50,000, excluding the costs of parts, services and other vendors at the
wellsite, and is usually less expensive than drilling a new well.
The demand for workover services is more sensitive to expectations
relating to, and changes in, oil and natural gas prices than the demand for
maintenance services. As oil and natural gas prices increase, the level of
workover activity tends to increase as operators seek to increase production
by enhancing the efficiency of their wells at higher commodity prices with
correspondingly higher rates of return.
COMPLETION SERVICES. Our completion services prepare a newly drilled
natural gas or oil well for production. The completion process may involve
selectively perforating the well casing to access producing zones,
stimulating and testing these zones and installing downhole equipment. We
typically provide a well service rig and may also provide other equipment
such as a workover package, to assist in the completion process. Producers
use well service rigs to complete their wells because the rigs have
specialized equipment, properly trained employees and the experience
necessary to perform these services. However, during periods of weak drilling
rig demand, drilling contractors may compete with service rigs for completion
work.
The completion process typically requires a few days to several
weeks, depending on the nature and type of the completion, and generally
requires additional auxiliary equipment that can be provided for an
additional fee. The demand for well completion services is directly related
to drilling activity levels, which are highly sensitive to expectations
relating to, and changes in, oil and natural gas prices. As the number of
newly drilled wells decreases, the number of completion jobs correspondingly
decreases. The average cost of a completion typically ranges between $5,000
and $50,000, excluding the costs of parts, services and other vendors at the
wellsite.
S-20
<PAGE>
PLUGGING AND ABANDONMENT SERVICES. Well service rigs and workover
equipment are also used in the process of permanently closing oil and natural
gas wells at the end of their productive lives. Plugging and abandonment work
can be performed with a well servicing rig along with wireline and cementing
equipment. The services generally include the sale or disposal of equipment
salvaged from the well as part of the compensation received and require
compliance with state regulatory requirements. The demand for oil and natural
gas does not significantly affect the demand for plugging and abandonment
services, as well operators are required by state regulations to plug a well
that it is no longer productive. The need for these services is also driven
by lease, and/or operator policy requirements.
OILFIELD TRUCKING
We provide liquid/vacuum truck services and fluid transportation and
disposal services for operators whose wells produce saltwater and other
fluids, in addition to oil and natural gas. These trucks are also utilized in
connection with drilling and workover projects, which tend to produce and use
large amounts of various oilfield fluids. We also own a number of salt water
disposal wells. In addition, we provide haul/ equipment trucks that are used
to move large pieces of equipment from one wellsite to the next.
ANCILLARY OILFIELD SERVICES
We provide ancillary oilfield services, which include among others:
hot oiling; wireline; frac tank rentals; well site construction; roustabout
services; fishing and other tool rentals; supplying blowout preventers
(BOPs); and foam units and air drilling services. Demand and pricing for
these services are generally related to demand for our well service and
drilling rigs.
CONTRACT DRILLING
We provide contract drilling services to major oil companies and
independent oil producers onshore the continental United States in the
Permian Basin, the Four Corners region, Michigan, the Northeast, and the
Rocky Mountains and internationally in Argentina and Ontario, Canada.
Drilling services are primarily provided under standard dayrate, footage or
turnkey contracts. Drilling rigs vary in size and capability and may include
specialized equipment. The majority of our drilling rigs are equipped with
mechanical power systems and have depth ratings ranging from 4,500 feet to
20,000 feet for an average of approximately 8,700 feet.
OIL AND NATURAL GAS PRODUCTION
We are engaged in the production of oil and natural gas in the
Permian Basin and Panhandle regions of West Texas through Odessa Exploration.
Odessa Exploration manages interests in oil and natural gas producing
properties for its own account and for drilling partnerships which it
sponsors. Odessa Exploration operates oil and natural gas wells on behalf of
over 250 working interest owners as well as for its own account.
FOREIGN OPERATIONS
We also operate each of our business segments discussed above in
Argentina and Ontario, Canada. Our foreign operations currently own 24 well
servicing rigs, 45 oilfield trucks and seven drilling rigs in Argentina and
one well servicing rig, two oilfield trucks and three drilling rigs in
Ontario, Canada.
CUSTOMERS
Our customers include major oil and natural gas production
companies, foreign national oil and natural gas production companies and
independent oil and gas production companies. No single customer in fiscal
2000 accounted for 10% or more of our consolidated revenues.
S-21
<PAGE>
COMPETITION AND OTHER EXTERNAL FACTORS
Despite the significant consolidation in the domestic well servicing
industry, there are several smaller companies that compete in our well
servicing markets. Nonetheless, we believe that our performance, equipment,
safety, pricing, and availability of equipment to meet customer needs and
availability of experienced, skilled personnel is superior to that of our
competitors.
In the well servicing markets, an important competitive factor in
establishing and maintaining long-term customer relationships is having an
experienced, skilled and well-trained work force. In recent years, many of
our larger customers have placed increased emphasis on the safety records and
quality of the crews, equipment and services provided by their contractors.
We have, and will continue to, devote substantial resources toward employee
safety and training programs. Many of our competitors, particularly small
contractors, have not undertaken similar training programs for their
employees. Management believes that our safety record and reputation for
quality equipment and service are among the best in the industry.
We compete with other regional and national oil and natural gas
drilling contractors, some of which have larger rig fleets with greater
average depth capabilities and a few that have better capital resources.
Management believes that the drilling industry is less consolidated than the
well servicing industry, resulting in a drilling market that is more price
competitive. Nonetheless, we believe that we are competitive in terms of
drilling performance, equipment, safety, pricing, availability of equipment
to meet customer needs and availability of experienced, skilled personnel in
those regions in which it operates.
The need for oilfield services fluctuates, in part, in relation to
the demand for oil and natural gas. As demand for those commodities
increases, service and maintenance requirements increase as oil and natural
gas producers attempt to maximize the producing efficiency of their wells in
a higher priced environment.
EMPLOYEES
As of June 30, 2000, we employed approximately 7,436 persons
(approximately 7,374 in oilfield and drilling services, nine in oil and
natural gas production and 53 in corporate). Our employees are not
represented by a labor union and are not covered by collective bargaining
agreements. We have not experienced work stoppages associated with labor
disputes or grievances and consider our relations with our employees to be
satisfactory.
ENVIRONMENTAL REGULATIONS
Our oilfield service operations, oil and natural gas production and
drilling activities are subject to various local, state and federal laws and
regulations intended to protect the environment. Our operations routinely
involve the handling of waste materials, some of which are classified as
hazardous substances. Consequently, the regulations applicable to our
operations include those with respect to containment, disposal and
controlling the discharge of any hazardous oilfield waste and other
non-hazardous waste material into the environment, requiring removal and
cleanup under certain circumstances, or otherwise relating to the protection
of the environment. Laws and regulations protecting the environment have
become more stringent in recent years, and may in certain circumstances
impose "strict liability," rendering a party liable for environmental damage
without regard to negligence or fault on the part of such party. Such laws
and regulations may expose us to liability for the conduct of, or conditions
caused by, others, or for our acts, which were in compliance with all
applicable laws at the times such acts were performed. Cleanup costs and
other damages arising as a result of environmental laws, and costs associated
with changes in environmental laws and regulations could be substantial and
could have a material adverse effect on our financial condition. From time to
time, claims have been made and litigation has been brought against us under
such laws. However, the costs incurred in connection with such claims and
other costs of environmental compliance have not had any material adverse
effect on our operations or financial statements in the past, and management
is not currently aware of any situation or condition that it believes is
likely to have any such material adverse effect in the future. Management
believes that it conducts the company's operations in substantial compliance
with all material federal, state and local regulations as they relate to the
environment. Although we have incurred certain costs in complying with
environmental laws and regulations, such amounts have not been material to
our financial results during the past three fiscal years.
S-22
<PAGE>
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information regarding the
persons who are members of our Board of Directors, key employees or executive
officers. Our directors will continue to hold office until the next annual
meeting of shareholders or until a successor has been elected and qualified.
<TABLE>
<CAPTION>
NAME POSITION AGE
---- -------- ---
<S> <C> <C>
Francis D. John...................... Chairman of the Board, President, Chief 46
Executive Officer and Chief Operating
Officer
Thomas K. Grundman................... Executive Vice President of 40
International Operations, Chief
Financial Officer Chief Accounting
Officer
James J. Byerlotzer.................. Executive Vice President of Domestic 54
Operations
David J. Breazzano................... Director 44
Kevin P. Collins..................... Director 50
William D. Fertig.................... Director 44
William D. Manly..................... Director 77
W. Phillip Marcum.................... Director 56
Morton Wolkowitz..................... Director 72
</TABLE>
Francis D. John has been Chairman of the Board since August 1996 and
the Chief Executive Officer since October 1989. Mr. John re-assumed the
duties of Chief Operating Officer effective April 1999. He has been a
Director and President since June 1988 and served as the Chief Financial
Officer from October 1989 through July 1997. Before joining the Company, he
was Executive Vice President of Finance and Manufacturing of Fresenius
U.S.A., Inc. Mr. John previously held operational and financial positions
with Unisys, Mack Trucks and Arthur Andersen. He received a BS from Seton
Hall University and an MBA from Fairleigh Dickinson University.
Thomas K. Grundman has been an Executive Vice President and the
Chief Financial Officer and Treasurer since July 1999 and the Chief
Accounting Officer since November 1999. Effective December 1999, Mr. Grundman
became Executive December 1999, Mr. Grundman became Executive Vice President
of International Operations. Effective August 2000, he resigned as Treasurer.
He joined the Company in April 1999 as Sr. Vice President of Strategic and
Business Development. From late 1996 through April 1999, Mr. Grundman was
Senior Vice President at PNC Bank, N.A. where he ran the Oil and Gas
Corporate Finance Group and was responsible for providing financing and
advisory services in all sectors of the energy industry. From 1984 through
1996, Mr. Grundman held several positions at Chase Manhattan Bank and its
predecessor institutions, most recently as a Managing Director in the oil and
gas group. Mr. Grundman holds a BS in Finance from Syracuse University.
James J. Byerlotzer has been Executive Vice President of Domestic
Well Service and Drilling Operations since July 1999. Effective December
1999, Mr. Byerlotzer's title was changed to Executive Vice President of
Domestic Operations. He joined the Company in September 1998 as Vice
President--Permian Basin Operations after the Company's acquisition of Dawson
Production Services, Inc. ("Dawson"). From February 1997 to September 1998,
he served as the Senior Vice President and Chief Operating Office of Dawson.
From 1981 to 1997, Mr. Byerlotzer was employed by Pride Petroleum Services,
Inc. ("Pride"). Beginning in February 1996, Mr. Byerlotzer served as the Vice
President--Domestic Operations of Pride. Prior to that time, he served as
Vice President--Permian Basin of Pride and in various other operating
positions in Pride's Gulf Coast and California operations. Mr. Byerlotzer
holds a BA from the University of Missouri in St. Louis.
David J. Breazzano has been a Director since October 1997. Mr.
Breazzano is one of the founding principals at DDJ Capital Management, LLC,
an investment management firm established in 1996. Mr. Breazzano previously
served as a Vice President and Portfolio Manager at Fidelity Investments
("Fidelity") from 1990 to 1996. Prior to joining Fidelity, Mr. Breazzano was
President and Chief Investment Officer of the T. Rowe Price Recovery
S-23
<PAGE>
Fund. He is also a director of Waste Systems International, Inc. and Samuels
Jewelers, Inc. He holds a BS from Union College and an MBA from Cornell
University.
Kevin P. Collins has been a Director since March 1996. Mr. Collins
has been a managing member of the Old Hill Company LLC since 1997. From 1992
to 1997, he served as a principal of JHP Enterprises, Ltd., and from 1985 to
1992, as Senior Vice President of DG Investment Bank, Ltd., both of which
were engaged in providing corporate finance and advisory services. Mr.
Collins was a director of WellTech, Inc. ("WellTech") from January 1994 until
March 1996 when WellTech was merged into the Company. Mr. Collins is also a
director of The Penn Traffic Company, Metretek Technologies, Inc. and London
Fog Industries. He holds a BS and an MBA from the University of Minnesota.
William D. Fertig has been a Director since April 2000. Mr. Fertig
has been a Principal, Manager of Sales and Training at McMahan Securities Co.
L.P. since 1990. Mr. Fertig previously served as a Senior Vice President and
Manager of Convertible Sales at Drexel Burnham Lambert prior to joining
McMahan Securities in 1990, and from 1979 to 1989, served as Vice President
and Convertible Securities Sales Manager at Credit Suisse First Boston. He
holds a BS from Allegheny College and an MBA from NYU Graduate Business
School.
William D. Manly has been a Director since December 1989. He retired
from his position as an Executive Vice President of Cabot Corporation in
1986, a position he had held since 1978. Mr. Manly is a director of
Metallamics, Inc. and CitiSteel, Inc. He holds a BS and an MS from the
University of Notre Dame.
W. Phillip Marcum has been a Director since March 1996. Mr. Marcum
was a director of WellTech from January 1994 until March 1996 when WellTech
was merged into the Company. From October 1995 until March 1996, Mr. Marcum
was the acting Chairman of the Board of Directors of WellTech. He has been
Chairman of the Board, President and Chief Executive Officer of Metretek
Technologies, Inc., formerly known as Marcum Natural Gas Services, Inc.
("Metretek Technologies"), since January 1991 and is a director of
TestAmerica, Inc. He holds a BBA from Texas Tech University.
Morton Wolkowitz has been a Director since December 1989. Mr.
Wolkowitz served as President and Chief Executive Officer of Wolkow Braker
Roofing Corporation, a company that provided a variety of roofing services,
from 1958 through 1989. Mr. Wolkowitz has been a private investor since 1989.
He holds a BS from Syracuse University.
DIRECTOR COMPENSATION
No director who is also an employee of the Company or any of its
subsidiaries received any fees from the Company for his services as a
Director or as a member of any committee of the Board. During the fiscal year
ended June 30, 2000 all other Directors ("Non-employee Directors") received a
fee equal to $3,000 per month for each month of service and are reimbursed
for travel and other expenses directly associated with Company business.
Additionally, during fiscal 2000 the Company paid the premiums with respect
to life insurance for the benefit of Messrs. Collins and Marcum in the amount
of $2,906 and $5,389, respectively. On April 18, 2000, Messrs Collins, Manly,
Marcum, Breazzano and Wolkowitz were granted options under the Key Energy
Group, Inc. 1997 Incentive Plan as amended from time to time (the "1997
Incentive Plan") to purchase 50,000 shares of Common Stock. On April 27,
2000, Mr. Fertig was also granted options under the 1997 Incentive Plan to
purchase 50,000 shares of Common Stock. The options granted on April 18, 2000
and April 27, 2000 vest in four equal annual installments commencing on the
date of grant of each of the options.
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<PAGE>
EXECUTIVE COMPENSATION
The following table reflects the compensation for services to the
company for the years ended June 30, 2000, 1999 and 1998 for (i) our Chief
Executive Officer, (ii) our four most highly compensated executive officers
other than the Chief Executive Officer who were serving as executive officers
at June 30, 2000 and (iii) two former executive officers for whom disclosure
would have been provided pursuant to clause (ii) above but for the fact that
such individuals were not serving as executive officers at June 30, 2000 (the
"Named Executive Officers").
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG TERM
ANNUAL COMPENSATION COMPENSATION
------------------------- AWARDS
OTHER ------------- ------------
ANNUAL SHARES ALL OTHER
SALARY BONUS COMPENSATION UNDERLYING COMPENSATION
NAME AND PRINCIPAL POSITION YEAR ($) ($) ($) OPTIONS (1) ($)
--------------------------- ---- --------- --------- ------------ ------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Francis D. John.............. 2000 589,519 307,776 -- 2,000,000 --
President, Chief Executive 1999 429,000 (2) -- -- 1,200,000 --
Officer and Chief Operating 1998 395,000 -- -- -- --
Officer
Thomas K. Grundman........... 2000 203,845 100,000 -- 500,000
Executive Vice President 1999 35,259 -- -- 300,000 --
International Operations,
Chief Financial Officer,
Chief Accounting Officer and
Treasurer(3)
James J. Byerlotzer.......... 2000 185,000 89,000 -- 300,000 100,000(4)
Executive Vice President - 1999 121,153 -- -- 260,000 75,000 (4)
Domestic Operation (5)
D. Kirk Edwards.............. 2000 165,000 -- -- -- --
Senior Vice President of 1999 164,551 -- -- 150,000 --
Human Resources And 1998 172,562 39,437 -- -- --
Information Technology (6)
Danny R. Evatt............... 2000 147,788 10,000 -- -- --
Vice President of Financial 1999 137,500 -- -- 90,000 --
Operations and Chief 1998 125,000 30,000 -- -- --
Information Officer (7)
</TABLE>
-------------------
(1) Represents the number of shares issuable pursuant to vested and
non-vested stock options granted during the applicable fiscal year.
(2) Reflects a salary decrease of 38% effective December 1, 1998 as
compared to the salary in effect at July 1, 1998.
(3) Mr. Grundman joined the Company as an executive officer in April 1999.
Mr. Grundman resigned as Treasurer effective July 18, 2000.
(4) Represents payments to Mr. Byerlotzer pursuant to a non-competition
agreement entered into in connection with the Company's acquisition of
Dawson Production Services, Inc.
(5) Mr. Byerlotzer joined the Company as an executive officer in September
1998.
(6) Mr. Edwards ceased serving as an executive officer effective March
2000, but his employment continued through June 30, 2000.
(7) Mr. Evatt ceased serving as an executive officer in November 1999, but
his employment continued through June 30, 2000.
S-25
<PAGE>
The following table sets forth certain information relating to
options granted under the 1997 Incentive Plan and outside the 1997 Incentive
Plan to the Named Executive Officers during fiscal 2000. We did not grant any
stock appreciation rights during fiscal 2000.
OPTION GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
INDIVIDUAL
GRANTS
NUMBER OF % OF TOTAL
SECURITIES OPTIONS
OF GRANTED TO GRANT
UNDERLYING EMPLOYEES EXERCISE DATE
OPTIONS IN FISCAL YEAR PRICE EXPIRATION PRESENT
NAME GRANTED (1) PER SHARE DATE VALUE (2)
---- ------------- ----------------- ---------- ------------ -----------
<S> <C> <C> <C> <C> <C>
Francis D. John.................. 1,000,000 (3) 27.1% $ 8.50 04/18/10 $5,262,199
200,000 (4) 5.4% $ 8.875 04/27/10 1,098,871
800,000 (5) 21.7% $ 9.50 05/08/10 4,581,208
Thomas K. Grundman............... 500,000 (6) 13.6% $ 8.50 04/18/10 2,681,099
James J. Byerlotzer.............. 300,000 (7) 8.1% $ 8.50 04/18/10 1,578,660
D. Kirk Edwards.................. 0 N/A N/A N/A N/A
Danny R. Evatt................... 0 N/A N/A N/A N/A
</TABLE>
---------------------------
(1) Based on options to purchase a total of 3,687,500 shares of Common
Stock granted during fiscal 2000.
(2) The grant date value of stock options was estimated using the
Black-Scholes option pricing model with the following assumptions:
expected volatility--67%; risk-free interest rate--6.4%; time of
exercise--5 years; and no dividend yield.
(3) These options were granted on April 18, 2000, and vest in four
installments commencing on the date of grant as follows: 500,000 on
April 18, 2000, provided the stock price has reached $13; 166,667 on
April 18, 2001, provided the stock price has reached $15; 166,667 on
April 18, 2002, provided the stock price has reached $17; and 166,666
on April 18, 2003, provided the stock price has reached $20. Regardless
of price triggers, all options vest on April 18, 2008.
(4) These options were granted on April 27, 2000 and vest in four annual
installments commencing on the date of grant as follows: 100,000 on
April 27, 2000; 33,333 on April 27, 2001; 33,334 on April 27, 2002; and
33,334 on April 27, 2003.
(5) These options were granted outside the Plan on May 8, 2000 and vest in
four annual installments commencing on the date of grant as follows:
400,000 on May 8, 2000, 133,333 on May 8, 2001, 133,333 on May 8, 2002
and 133,334 on May 8, 2003.
(6) These options were granted on April 18, 2000, and vest in four equal
annual installments commencing on the date of grant as follows: 125,000
on April 18, 2000, provided the stock price has reached $13; 125,000 on
April 18, 2001, provided the stock price has reached $15; 125,000 on
April 18, 2002, provided the stock price has reached $17; and 125,000
on April 18, 2003, provided the stock price has reached $20. Regardless
of price triggers, all options vest on April 18, 2008.
(7) These options were granted on April 18, 2000, and vest in four equal
annual installments commencing on the date of grant as follows: 75,000
on April 18, 2000, provided the stock price has reached $13; 75,000 on
April 18, 2001, provided the stock price has reached $15; 75,000 on
April 18, 2002, provided the stock price has reached $17; and 75,000 on
April 18, 2003, provided the stock price has reached $20. Regardless of
price triggers, all options vest on April 18, 2008.
S-26
<PAGE>
The following table sets forth certain information as of June 30, 2000
relating to the value of unexercised options held by the Named Executive
Officers.
AGGREGATED OPTION EXERCISES AND VALUES AS OF FISCAL YEAR END
<TABLE>
<CAPTION>
SHARES NUMBER OF UNXERCISED VALUE OF UNEXERCISED
ACQUIRED VALUE OPTIONS AT IN-THE MONEY-OPTIONS AT
ON REALIZED JUNE 30, 2000 JUNE 30, 2000(2)
EXERCISE(#) ($) (1) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---------- ---------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Francis D. John............ 0 0 1,825,000 1,750,000 $6,543,750 $ 1,875,000
Thomas K. Grundman......... 0 0 150,000 650,000 $ 993,750 $ 1,556,250
James J. Byerlotzer........ 0 0 130,000 430,000 $ 840,625 $ 1,178,125
D. Kirk Edwards............ 55,000 $562,812 0 130,000 $ 0 $ 840,625
Danny R. Evatt............. 38,334 $388,132 15,000 71,666 $ 0 $ 454,162
</TABLE>
---------------
(1) The dollar values in this column are calculated by determining the
difference between the fair market value of the Company's common stock
on the date of exercise of the relevant options and the exercise price
of such options. The fair market value on the date of exercise is based
on the last sale price of the Company's common stock on the NYSE on
such date.
(2) The dollar values in this column are calculated by determining the
difference between the fair market value of the Common Stock for which
the relevant options are exercisable as of the end of the fiscal year
and the exercise price of the options. The fair market value is based
on the last sale price of the Common Stock on the NYSE on June 30, 2000
of $9.625.
EMPLOYMENT AGREEMENTS WITH EXECUTIVE OFFICERS
Effective as of July 1, 1999, we entered into an employment
agreement with Mr. John, which provides that Mr. John will serve as Chairman
of the Board, President and Chief Executive Officer for a five-year term
commencing July 1, 1999 and continuing until June 30, 2004 with an automatic
one-year renewal on each anniversary date commencing July 1, 2000, unless
terminated no later than 30 days before a renewal. Under this agreement, Mr.
John's annual base salary is $575,000 per year subject to annual review by
the Board of Directors; PROVIDED, HOWEVER, that his base salary may be
increased, but not decreased. This agreement also provides that he will be
entitled to (i) participate in our Performance Compensation Plan, with
performance criteria to be approved by the Compensation Committee, (ii)
receive additional bonuses at the discretion of the Compensation Committee,
and (iii) participate in the 1997 Incentive Plan. In addition to salary and
bonus, Mr. John is entitled to group life insurance in an amount equal to $5
million, reimbursement of expenses, various perquisites and a personal
umbrella policy in the amount of $5 million. Also, if Mr. John is subject to
the tax imposed by Section 4999 of the Internal Revenue Code, the Company has
agreed to reimburse him for such tax on an after-tax basis.
In the event that Mr. John's employment agreement is terminated by
us without "Cause" or by Mr. John for "Good Reason", death, "Disability", or
as a result of a "Change of Control," all as defined in the agreement, Mr.
John will be entitled to receive: (i) accrued but unpaid salary to the date
of termination; (ii) any prior year bonus earned but not paid and a pro rata
bonus for the year in which the termination occurs; (iii) a severance payment
in the amount of three times the sum of the average of his total annual
compensation (i.e., salary plus bonus) for the preceding three years; (iv)
immediate vesting and exercisability of all stock options held by him (to the
extent not already vested and exercisable) for the remainder of the original
term of the option; (v) any other amounts earned, accrued or owing to Mr.
John, but not yet paid including any and all obligations to be performed with
respect to applicable benefits or perquisites to be provided to him following
his termination; and (vi) continued participation in medical, dental, and
life insurance coverage until Mr. John receives equivalent coverage and
benefits under the plans and programs of a subsequent employer, or the death
of the latter of Mr. John or his spouse. In the event that Mr. John's
employment is terminated for "Cause" or as a result of his resignation, he
will be entitled to receive (a) accrued unpaid salary to the date of the
termination, (b) any prior year-end bonus earned but not paid; and (c) the
vested portion of stock options which he then holds.
Furthermore, Mr. John's new employment agreement further provides
for a three-year non-competition provision in the event that he is receiving
severance payments pursuant to the terms of his employment agreement
S-27
<PAGE>
or, in the event that no payments are being made pursuant to the agreement, a
one-year prohibition against competition applies. In the event Mr. John's
employment is terminated as a result of a Change of Control, the agreement
provides that the non-competition provision will not apply.
We entered into an employment agreement with Mr. Grundman effective
as of July 1, 1999, which was amended effective July 1, 2000. This agreement
is for a three-year term and thereafter for successive one-year terms unless
terminated 60 days prior to the commencement of an extension term. Under this
agreement, Mr. Grundman initially receives an annual base compensation of
$200,000, which can be increased but not decreased, and is eligible for
additional annual incentive bonuses. If, during the term of his employment
agreement, Mr. Grundman is terminated by us for any reason other than for
cause, or if he terminates his employment because of a material breach by us
or following a change of control, he will be entitled to severance
compensation equal to his base compensation in effect at the time of
termination payable in equal installments over a 36-month period following
termination; provided, however, that if termination results from a change of
control, severance compensation will be payable in a lump sum on the date of
termination. Also, if Mr. Grundman is subject to the tax imposed by Section
4999 of the Internal Revenue Code, the Company has agreed to reimburse him
for such tax on an after-tax basis.
We entered into an employment agreement with Mr. Byerlotzer
effective as of July 1, 1999 for a three-year term and thereafter for
successive one-year terms unless terminated 30 days prior to the commencement
of an extension term. Under the agreement, Mr. Byerlotzer receives an annual
base compensation of $185,000 and is eligible for additional annual incentive
bonuses. If during the term of his employment agreement Mr. Byerlotzer is
terminated by us for any reason other than for "Cause", or if he terminates
his employment because of a material breach by us or following a change of
control, he will be entitled to severance compensation equal to his base
compensation in effect at the time of termination payable in equal
installments over a 24-month period following termination; provided, however,
that if termination results from a change of control, severance compensation
will be payable in a lump sum on the date of termination.
We entered into an employment agreement with Mr. Edwards effective
as of July 1, 1996. The agreement is for a three-year term and thereafter for
successive one-year terms unless terminated 30 days prior to the commencement
of the extension term. Under this agreement, Mr. Edwards initially received
annual base compensation of $165,000, and is eligible for an additional
annual incentive bonus of up to 30% of his base compensation. Mr. Edward's
employment agreement provides that if during the term of his employment
agreement Mr. Edwards is terminated by us for any reason other than for
cause, or if he terminates his employment because of a material breach by us
of following a change of control, he is entitled to severance compensation
equal to two times his base compensation in effect at the time of termination
payable in equal installments over a 24-month period following termination;
provided, however, that if termination results from a change of control,
severance compensation is payable in a lump sum on the date of termination.
Mr. Edwards ceased serving as an executive officer effective March 1, 2000,
however, his employment agreement remains in effect.
We entered into an employment agreement with Mr. Evatt effective as
of July 1, 1999 for a three-year term, and thereafter for successive one-year
terms unless terminated 30 days prior to the commencement of an extension
term. Under the new agreement, Mr. Evatt initially received annual base
compensation of $145,000 per year and was eligible for additional incentive
bonuses. If during the term of his agreement Mr. Evatt was terminated by us
for any reason other than for cause, he was entitled to receive severance
compensation equal to his base compensation, payable in equal installments
over a 24-month period following the termination; provided, however, that if
termination resulted from a change of control, severance compensation was
payable in a lump sum on the date of termination. Mr. Evatt ceased serving as
an executive officer effective as of November 11, 1999, however his
employment agreement remained in effect through August 1, 2000. Effective
August 1, 2000, we entered into a severance agreement with Mr. Evatt pursuant
to which we (i) made a one-time severance payment to Mr. Evatt in the amount
of $290,000 and (ii) agreed to immediately vest certain options to acquire
shares of Common Stock.
S-28
<PAGE>
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In connection with the negotiation of the terms of a five-year
employment agreement with Mr. Francis D. John, Chairman of the Board,
President and Chief Executive Officer, and as an inducement to Mr. John to
enter into such employment agreement, we entered into a separate agreement
with Mr. John dated as of August 2, 1999, which as amended through June 30,
2000, provides that $5 million in loans previously made by us to Mr. John,
together with the accrued interest payable thereon, will be forgiven ratably
during the ten year period commencing on July 1, 2000 and ending on June 30,
2010. The agreement provides that the foregoing forgiveness of indebtedness
is predicated and conditioned upon Mr. John remaining employed by us during
such period. In addition, in the event that we terminate Mr. John for "Cause"
(as defined in the agreement), or in the event that Mr. John voluntarily
terminates his employment, the agreement further provides that the entire
remaining principal balance of these loans, together with accrued interest
payable thereon, will become immediately due and payable by Mr. John.
However, in the event that Mr. John's employment is terminated for "Good
Reason", or as a result of Mr. John's death or "Disability", or as a result
of a "Change in Control" (all as defined in that agreement), the agreement
stipulates that the remaining principal balance outstanding on the loans,
together with accrued interest thereon will be forgiven. This agreement
further provides that with respect to any forgiveness of the payment of
principal and interest on the loans, Mr. John will be entitled to receive a
"gross-up" payment in an amount sufficient for him to pay any federal, state,
or local income taxes that may be due and payable by him with respect to the
forgiveness of such indebtedness (principal and interest).
During fiscal 1998, Metretek Technologies, a diversified provider of
products and services to the natural gas industry and a company for which W.
Phillip Marcum, one of our directors, serves as Chairman of the Board,
President and Chief Executive Officer, sold certain assets held by its wholly
owned subsidiary, Marcum Gas Transmission, to Odessa. Metretek Technologies
sold the assets for a total consideration of $700,000. Metretek Technologies
also granted Odessa a right of first refusal to participate in future
projects developed by Marcum Gas Transmission on terms and conditions
identical to those provided to Marcum Gas Transmission.
During fiscal 1998, we deposited $250,000 in a money market account
as collateral to secure a bank loan made to a business entity in which Danny
R. Evatt, then the Chief Information Officer and Vice President of Financial
Operations, owns an interest. Such amount was returned during fiscal 2000.
In fiscal 1999, an investment management firm in which David J.
Breazzano, one our directors, is a principal, purchased $25 million principal
amount of our borrowings under a bridge loan agreement which has since been
repaid in full.
In fiscal 1999, we entered into a consulting agreement with an
investment banking firm in which Kevin P. Collins, one of our directors, is a
principal, pursuant to which such firm provided financial advisory services
us in connection with equity offering completed in fiscal 1999 and for which
such firm received a total of $167,000.
In connection with the negotiation of an employment agreement with
Thomas K. Grundman, our Executive Vice President of International Operations,
Chief Financial Officer, Chief Accounting Officer and Treasurer, we made a
$240,000 short-term loan and a $150,000 relocation loan to assist Mr.
Grundman's relocation to our executive offices. Interest on these loans
accrues at a rate of 6.125% per annum. The short-term loan has been repaid.
The relocation loan together with accrued interest will be forgiven in three
installments of $50,000 each on July 1, 2000, 2001 and 2002; provided,
however, that if Mr. Grundman's employment is terminated during such period
in a way that (i) triggers severance obligations, all amounts owed shall be
immediately forgiven or (ii) does not trigger severance obligations, all
amounts owed shall be immediately due and payable. This agreement further
provides that with respect to any forgiveness of the payment of principal and
interest on the loans, Mr. Grundman will be entitled to receive a "gross-up"
payment in an amount sufficient for him to pay any federal, state, or local
income taxes that may be due and payable by him with respect to the
forgiveness of such indebtedness (principal and interest).
S-29
<PAGE>
OWNERSHIP OF CAPITAL STOCK
MANAGEMENT
The following table sets forth as of October 23, 2000, the number of
shares of common stock beneficially owned by each (i) director, (ii)
executive officer, and (iii) all of our directors and executive officers as a
group. Except as noted below, each holder has sole voting and investment
power with respect to all shares of common stock listed as owned by such
person.
<TABLE>
<CAPTION>
PERCENTAGE OF
NUMBER OF OUTSTANDING
NAME OF BENEFICIAL OWNER SHARES(1) SHARES(2)
------------------------ ---------- ---------
<S> <C> <C>
Francis D. John(3)........................................................... 2,987,414 3.0%
Kevin P. Collins(4).......................................................... 184,238 *
William D. Fertig(5)......................................................... 17,500 *
William D. Manly(6)........................................................... 181,875 *
W. Philip Marcum(7).......................................................... 184,238 *
David J. Breazzano(8)........................................................ 159,166 *
Morton Wolkowitz(9).......................................................... 570,716 *
James J. Byerlotzer(10)...................................................... 196,167 *
Thomas K. Grundman(11)....................................................... 210,000 *
Directors and Executive Officers as a group (9 persons)...................... 4,691,314 4.6%
</TABLE>
------------------------
* Less than 1%
(1) Includes all shares with respect to which each director or executive
officer directly or indirectly, through any contract, arrangement,
understanding, relationship or otherwise, has or shares the power to
vote or to direct voting of such shares and/or to dispose or to direct
the disposition of such shares. Includes shares that may be purchased
under currently exercisable stock options and warrants.
(2) Based on 97,030,360 shares of common stock outstanding at October 23,
2000, plus, for each beneficial owner, those number of shares
underlying currently exercisable options or warrants held by each
executive officer or director.
(3) Includes 2,910,000 shares issuable upon exercise of vested options and
6,914 shares issuable pursuant to currently exercisable warrants. Does
not include 1,625,000 shares issuable pursuant to options that have not
vested.
(4) Includes 179,166 shares issuable upon the exercise of vested options.
Does not include 90,834 shares issuable pursuant to options that have
not vested.
(5) Includes 12,500 shares issuable upon the exercise of vested options.
Does not include 37,500 shares issuable pursuant to options that have
not vested.
(6) Includes 179,166 shares issuable upon the exercise of vested options.
Does not include 90,834 shares issuable pursuant to options that have
not vested.
(7) Includes 179,166 shares issuable upon the exercise of vested options.
Does not include 90,834 shares issuable pursuant to options that have
not vested.
(8) Includes 109,166 shares issuable upon the exercise of vested. Does not
include 90,834 shares issuable pursuant to options that have not
vested.
(9) Includes 173,500 shares issuable upon the exercise of vested options
and 6,914 shares issuable pursuant to currently exercisable warrants.
Does not include 101,500 shares issuable pursuant to options that have
not vested.
(10) Includes 174,167 shares issuable upon the exercise of vested options.
Does not include 385,833 shares issuable pursuant to options that have
not vested.
(11) Includes 200,000 shares issuable upon the exercise of vested options.
Does not include 600,000 shares issuable pursuant to options that have
not vested.
S-30
<PAGE>
In addition, the following Named Executive Officers who were not
executive officers of the Company at October 23, 2000 beneficially own (based on
available information) common stock as follows: D. Kirk Edwards--201,400 shares
(includes 27,500 shares issuable upon the exercise of vested options); Danny R.
Evatt--81,666 shares (includes 15,000 share issuable upon the exercise of vested
options).
CERTAIN BENEFICIAL OWNERS
The following table sets forth, as of October 23, 2000, certain
information regarding the beneficial ownership of common stock by each person,
other than our directors or executive officers, who is known to own beneficially
more than 5% of our outstanding shares of common stock.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY OWNED AT
OCTOBER 23, 2000
-----------------------------------
NAME AND ADDRESS OF BENEFICIAL OWNER, IDENTITY OF GROUP NUMBER PERCENT
------------------------------------------------------- --------------- ---------------
<S> <C> <C>
Perkins, Wolf, McDonnell and Company(1)...................................... 5,954,450 6.1%
53 W. Jackson Blvd., Suite 722
Chicago, Ill 60604
T. Rowe Price Associates, Inc. (2)........................................... 7,232,100 7.5%
100 E. Pratt Street
Baltimore, MD 21202
West Highland Capital, Inc.(3)............................................... 10,000,000 10.3%
Estero Partners, LLC
Lang H. Gerhard
West Highland Partners, L.P.
300 Drakes Landing Road, Suite 290
Greenbrae, CA 94904
</TABLE>
---------------------
(1) As reported on Schedule 13G filed with the SEC on February 14, 2000.
(2) As reported on Schedule 13G filed with the SEC on February 7, 2000.
(3) As reported on Schedule 13G (Amendment No. 1) filed with the SEC on
February 11, 2000.
PLAN OF DISTRIBUTION
Well will issue common stock from time to time in connection with
acquisitions by us or our subsidiaries of other businesses, assets or
securities. We expect that the terms of the acquisitions involving the
issuance of securities covered by this prospectus will be determined by
direct negotiations with the owners or controlling persons of the businesses,
assets or securities to be acquired by us or our subsidiaries. No
underwriting discounts or commissions will be paid in connection with the
issuance of our common stock, although finders' fees may be paid from time to
time with respect to specific mergers or acquisitions. Any person receiving
such fees may be deemed to be an underwriter within the meaning of the
Securities Act.
LEGAL MATTERS
Certain legal matters in connection with this offering will be
passed upon for us by Porter & Hedges, L.L.P.
EXPERTS
Our consolidated financial statements as of December 31, 1999 and
1998, and for each of the years in the three-year period ended December 31,
1999, have been included or incorporated by reference herein in reliance upon
the report of KPMG LLP, independent certified public accountants,
incorporated by reference herein, and upon the authority of such firm as
experts in accounting and auditing.
S-31
<PAGE>
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
AUDITED FINANCIAL STATEMENTS
Consolidated Balance Sheets...................................................................... F-2
Consolidated Statements of Operations............................................................ F-3
Consolidated Statements of Comprehensive Income.................................................. F-4
Consolidated Statements of Cash Flows............................................................ F-5
Consolidated Statements of Stockholders' Equity.................................................. F-6
Notes to Consolidated Financial Statements....................................................... F-7
Independent Auditors' Report..................................................................... F-34
UNAUDITED FINANCIAL STATEMENTS
Consolidated Balance Sheets as of September 30, 2000 (unaudited) and June 30, 2000............... F-35
Unaudited Consolidated Statements of Operations for the Three Months Ended
September 30, 2000 and 1999................................................................. F-36
Unaudited Consolidated Statements of Cash Flows for the Three Months Ended
September 30, 2000 and...................................................................... F-37
Unaudited Consolidated Statements of Comprehensive Income for the Three Months Ended
September 30, 2000 and...................................................................... F-38
Notes to Consolidated Financial Statements....................................................... F-39
</TABLE>
F-1
<PAGE>
KEY ENERGY SERVICES, INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
JUNE 30, 2000 JUNE 30, 1999
------------- ----------------
(THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C>
ASSETS
Current Assets:
Cash................................................................... $109,873 $23,478
Accounts receivable, net of allowance for doubtful accounts
($3,189--2000, $6,790--1999)......................................... 123,203 91,998
Inventories............................................................ 10,028 12,742
Income taxes receivable................................................ 5,588 916
Prepaid expenses and other current assets.............................. 4,897 3,409
-------------- ---------------
Total current assets....................................................... 253,589 132,543
-------------- ---------------
Property and equipment:
Well servicing equipment............................................... 670,392 655,578
Contract drilling equipment............................................ 105,454 88,766
Motor vehicles......................................................... 55,011 45,133
Oil and gas properties and other related equipment, successful
efforts method....................................................... 43,855 42,925
Furniture and equipment................................................ 11,013 8,452
Buildings and land..................................................... 34,712 31,086
-------------- ---------------
Total property and equipment............................................... 920,437 871,940
Accumulated depreciation & depletion....................................... (159,876) (102,378)
-------------- ---------------
Net property and equipment................................................. 760,561 769,562
-------------- ---------------
Goodwill, net.......................................................... 198,633 205,423
Deferred costs, net.................................................... 18,855 23,779
Notes receivable -- related parties.................................... 5,150 2,835
Other assets........................................................... 9,477 13,996
-------------- ---------------
Total assets............................................................... $1,246,265 $1,148,138
============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable....................................................... $ 35,801 $ 18,527
Other accrued liabilities.............................................. 26,398 25,291
Accrued interest....................................................... 15,994 13,079
Current portion of long-term debt...................................... 14,655 16,254
Current portion of deferred revenue.................................... 4,776 --
-------------- ---------------
Total current liabilities.................................................. 97,624 73,151
-------------- ---------------
Long-term debt, less current portion....................................... 651,945 683,724
Deferred revenue, less current portion 12,255 --
Non-current accrued expenses 1,847 1,739
Deferred tax liability..................................................... 99,707 101,430
Commitments and contingencies..............................................
Stockholders' equity:
Common stock, $.10 par value; 100,000,000 shares authorized,
97,209,504 and 83,155,072 shares issued, at June 30, 2000 and
June 30, 1999, respectively.......................................... 9,723 8,317
Additional paid-in capital............................................. 413,962 301,615
Treasury stock, at cost; 416,666 shares at June 30, 2000 and
June 30, 1999........................................................ (9,682) (9,682)
Accumulated other comprehensive income................................. 8 9
Retained earnings (deficit)............................................ (31,124) (12,165)
-------------- ---------------
Total stockholders' equity................................................. 382,887 288,094
-------------- ---------------
Total liabilities and stockholders' equity................................. $1,246,265 $1,148,138
============== ===============
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS.
F-2
<PAGE>
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
------------------------------------------------------
2000 1999 1998
---------------- -------------- ---------------
(THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
REVENUES:
Well servicing........................................ $559,492 $433,657 $356,238
Contract drilling..................................... 68,428 50,613 58,199
Oil and gas production................................ 9,391 6,461 7,030
Other, net............................................ 421 1,086 3,076
---------------- -------------- ---------------
637,732 491,817 424,543
---------------- -------------- ---------------
COSTS AND EXPENSES:
Well servicing........................................ 399,940 324,965 247,605
Contract drilling..................................... 58,299 43,556 42,860
Oil and gas production................................ 4,147 2,907 2,983
Depreciation, depletion and amortization.............. 70,972 62,074 31,001
General and administrative............................ 58,772 53,108 38,987
Bad debt expense...................................... 1,648 5,928 826
Debt issuance costs................................... -- 6,307 --
Interest.............................................. 71,930 67,401 21,476
Corporate restructuring............................... -- 4,504 --
---------------- -------------- ---------------
665,708 570,750 385,738
Income (loss) before income taxes......................... (27,976) (78,933) 38,805
---------------- -------------- ---------------
Income tax benefit (expense).............................. 7,406 25,675 (14,630)
---------------- -------------- ---------------
INCOME (LOSS) BEFORE EXTRAORDINARY GAIN $ (20,570) $ (53,258) $ 24,175
Extraordinary gain on extinguishment of debt, less
applicable income taxes of $580 (See Note 5).......... 1,611 -- --
---------------- -------------- ---------------
NET INCOME (LOSS)......................................... $ (18,959) $ (53,258) $ 24,175
================ ============== ===============
EARNINGS (LOSS) PER SHARE:
Basic - before extraordinary gain..................... $ (0.25) $ (1.94) $ 1.41
Extraordinary gain, net of tax........................ 0.02 -- --
---------------- -------------- ---------------
Basic -- after extraordinary gain..................... $ (0.23) $ (1.94) $ 1.41
================ ============== ===============
Diluted--before extraordinary gain..................... $ (0.25) $ (1.94) $ 1.23
Extraordinary gain, net of tax........................ 0.02 -- --
---------------- -------------- ---------------
Diluted - after extraordinary gain.................... $ (0.23) $ (1.94) $ 1.23
================ ============== ===============
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic................................................. 83,815 27,501 17,153
Diluted............................................... 83,815 27,501 24,024
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS.
F-3
<PAGE>
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
----------------------------------------------
2000 1999 1998
------------- ------------- ------------
(THOUSANDS)
<S> <C> <C> <C>
NET INCOME (LOSS)................................................ $(18,959) $(53,258) $24,175
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Unrealized gains on available-for-sale securities, net of
tax........................................................ --- --- 1,525
Reversal of unrealized gains on available-for-sale securities,
net of tax................................................. --- (1,525) ---
Foreign currency translation gain (Loss), net of tax............. (1) 9 ---
------------- ------------- ------------
COMPREHENSIVE INCOME (LOSS), NET OF TAX.......................... $(18,960) $(54,774) $25,700
============= ============= ============
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS.
F-4
<PAGE>
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
----------------------------------------------
2000 1999 1998
------------- ------------- ------------
(THOUSANDS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income / (loss).......................................... $ (18,959) $ (53,258) $ 24,175
ADJUSTMENTS TO RECONCILE INCOME FROM OPERATIONS TO
NET CASH PROVIDED BY (USED IN) OPERATIONS:
Depreciation, depletion and amortization..................... 70,972 62,074 31,001
Bad debt expense............................................. 1,648 5,928 826
Amortization of deferred debt costs.......................... 5,919 5,216 2,459
Restructuring charge......................................... -- 233 --
Deferred income taxes........................................ (1,818) (25,675) 7,287
(Gain) loss on sale of assets................................ 25 111 (189)
Other non-cash items......................................... -- 13 1,313
CHANGE IN ASSETS AND LIABILITIES NET OF EFFECTS FROM THE
ACQUISITIONS:
(Increase) decrease in accounts receivable................... (32,853) 9,741 (3,999)
(Increase) decrease in other current assets.................. (5,483) (432) (4,051)
Increase (decrease) in accounts payable, accrued interest
and accrued expenses....................................... 18,875 (17,378) (17,897)
Other assets and liabilities................................. (1,275) -- --
------------- ------------- ------------
Net cash provided (used) by operating activities............. 37,051 (13,427) 40,925
------------- ------------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures--well servicing.......................... (26,469) (26,776) (44,284)
Capital expenditures--contract drilling....................... (8,282) (1,063) (5,385)
Capital expenditures--oil and gas............................. (917) (287) (7,849)
Capital expenditures--other................................... (2,505) (3,181) (1,748)
Proceeds from sale of fixed assets........................... 2,722 7,110 1,279
Notes receivable from related parties........................ (2,315) (2,835) --
Cash received in acquisitions................................ -- 27,008 2,903
Acquisitions--well servicing -- (292,638) (172,536)
Acquisitions--contract drilling............................... -- -- (49,440)
Acquisitions--oil and gas..................................... -- -- (9,298)
Acquisitions--minority interest............................... -- -- (3,426)
Purchase of marketable equity securities..................... -- -- (9,979)
Other assets and liabilities................................. -- (1,992) (6,576)
------------- ------------- ------------
Net cash from (used) in vesting activities................... (37,766) (294,654) (306,339)
------------- ------------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt and capital lease obligations.... (53,268) (487,376) (237,424)
Borrowings under line-of-credit.............................. 12,000 328,411 280,770
Proceeds from equity offering, net of expenses............... 100,571 180,441 --
Purchase of treasury stock................................... -- -- (9,682)
Proceeds from long-term debt................................. -- 142,566 216,000
Proceeds paid for debt issuance costs........................ -- (15,274) (9,270)
Proceeds from other long-term debt........................... -- 150,000 3,316
Proceeds from forward sale, net of expenses.................. 18,236 -- --
Proceeds from stock option warrants.......................... -- 7,434 --
Proceeds from warrants exercised............................ 8,473 -- 4,223
Proceeds from stock options exercised........................ 1,098 92 1,042
------------- ------------- ------------
Net cash provided by (used in) financing activities.......... 87,110 306,294 248,975
------------- ------------- ------------
Net increase (decrease) in cash.............................. 86,395 (1,787) (16,439)
Cash at beginning of period.................................. 23,478 25,265 41,704
------------- ------------- ------------
Cash at end of period........................................ $109,873 $ 23,478 $ 25,265
============= ============= ============
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS.
F-5
<PAGE>
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK ACCUMULATED
--------------------- ADDITIONAL OTHER
NUMBER AMOUNT AT PAID-IN TREASURY RETAINED COMPREHENSIVE
OF SHARES PAR CAPITAL STOCK EARNINGS INCOME TOTAL
---------- ---------- ----------- ----------- ----------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE AT JUNE 30, 1997......... 12,298 $1,230 $55,031 --- $16,918 --- $73,179
---------- ---------- ----------- ----------- ----------- ------------- ----------
Issuance of common stock for
acquisition of assets........ 225 22 5,912 --- --- --- 5,934
Issuance of common stock for
acquisition of companies..... 340 34 7,895 --- --- --- 7,929
Exercise of warrants............. 609 61 4,162 --- --- --- 4,223
Exercise of options.............. 209 21 1,021 --- --- --- 1,042
Conversion of 7% Debentures...... 5,062 506 45,282 --- --- --- 45,788
Purchase of treasury stock....... --- --- --- (9,682) --- --- (9,682)
Mark-to-market of available for
sale securities, net of tax.. --- --- --- --- --- 1,525 1,525
Other ......................... (58) (6) --- --- --- --- (6)
Net income (loss)................ --- --- --- --- 24,175 --- 24,175
---------- ---------- ----------- ----------- ----------- ------------- ----------
BALANCE AT JUNE 30, 1998......... 18,685 $1,868 $119,303 $ (9,682) $ 41,093 $1,525 $154,107
---------- ---------- ----------- ----------- ----------- ------------- ----------
Reversal of unrealized gain on
available for sale securities --- --- --- --- --- (1,525) (1,525)
Foreign currency translation
adjustment, net of tax....... --- --- --- --- --- 9 9
Issuance of warrants with 14%
Notes........................ --- --- 7,434 --- --- --- 7,434
Issuance of common stock in
equity offering, net of
offering costs............... 64,245 6,425 174,016 --- --- --- 180,441
Issued to lender in lieu of fee.. 200 20 980 --- --- --- 1,000
Exercise of options.............. 15 2 92 --- --- --- 94
Other ......................... 10 2 (210) --- --- --- (208)
Net income (loss)................ --- --- --- --- (53,258) --- (53,258)
---------- ---------- ----------- ----------- ----------- ------------- ----------
BALANCE AT JUNE 30, 1998......... 83,155 $8,317 $301,615 $ (9,682) $ (12,165) $ 9 $288,094
---------- ---------- ----------- ----------- ----------- ------------- ----------
Foreign currency translation
adjustment, net of tax....... --- --- --- --- --- (1) (1)
Exercise of warrants............. 2,431 243 8,230 --- --- --- 8,473
Exercise of options.............. 241 24 1,074 --- --- --- 1,098
Conversion of 7% Debentures...... 380 38 3,568 --- --- --- 3,606
Issuance of common stock in equity
offering, net of offering costs 11,000 1,100 99,471 --- --- --- 100,571
Other............................ 3 1 4 --- --- --- 5
Net income (loss)................ --- --- --- --- (18,959) --- (18,959)
---------- ---------- ----------- ----------- ----------- ------------- ----------
BALANCE AT JUNE 30, 2000......... 97,210 $9,723 $413,962 $(9,682) $(31,124) $ 8 $382,887
========== ========== =========== =========== =========== ============= ==========
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS.
F-6
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
THE COMPANY
Key Energy Services, Inc. (the "Company" or "Key"), is the largest
onshore, rig-based well servicing contractor in the world, with approximately
1,400 well service rigs and 1,200 oilfield trucks as of June 30, 2000. The
Company provides a complete range of well services to major and independent
oil and natural gas producing companies, including: rig-based well
maintenance, workover, completion, and recompletion services (including
horizontal recompletions); oilfield trucking; and ancillary oilfield
services. Key conducts well servicing operations onshore in the continental
United States in the following regions: Gulf Coast (including South Texas,
Central Gulf Coast of Texas, and South Louisiana), Permian Basin of West
Texas and Eastern New Mexico, Mid-Continent (including the Anadarko, Hugoton
and Arkoma Basins and ArkLaTex region), Four Corners (including the San Juan,
Piceance, Uinta, and Paradox Basins), Eastern (including the Appalachian,
Michigan and Illinois Basins), Rocky Mountains (including the
Denver-Julesberg, Powder River, Wind River, Green River and Williston
Basins), and California (the San Joaquin Basin), and internationally in
Argentina and Ontario, Canada. The Company is also a leading onshore drilling
contractor, with 73 land drilling rigs as of June 30, 2000. Key conducts land
drilling operations in a number of major domestic producing basins, as well
as in Argentina and in Ontario, Canada. Key also produces and develops oil
and natural gas reserves in the Permian Basin and Texas Panhandle.
BASIS OF PRESENTATION
The Company's consolidated financial statements include the accounts
of the Company and its wholly-owned subsidiaries. All significant
inter-company transactions and balances have been eliminated. The accounting
policies presented below have been followed in preparing the accompanying
consolidated financial statements.
ESTIMATES AND UNCERTAINTIES
Preparation of the accompanying consolidated financial statements in
conformity with generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported amount of assets
and liabilities and disclosures of contingent assets and liabilities at the
date of the consolidated financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could
differ from those estimates.
INVENTORIES
Inventories, which consist primarily of oilfield service parts and
supplies held for consumption and parts and supplies held for sale at the
Company's various retail supply stores, are valued at the lower of average
cost or market.
F-7
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
PROPERTY AND EQUIPMENT
The Company provides for depreciation and amortization of oilfield
service and related equipment using the straight-line method, excluding its
drilling rigs, over the following estimated useful lives of the assets:
<TABLE>
<CAPTION>
DESCRIPTION YEARS
----------- -----
<S> <C>
Well service rigs.................................... 25
Motor vehicles....................................... 5
Furniture and equipment.............................. 3-7
Buildings and improvements........................... 10-40
Gas processing facilities............................ 10
Disposal wells....................................... 15-30
Trucks, trailers and related equipment............... 7-15
</TABLE>
The components of a well service rig that generally require
replacement during the rig's life are depreciated over their estimated useful
lives, which range from three to 15 years. The basic rigs, excluding
components, have estimated useful lives from date of original manufacture
ranging from 25 to 35 years. Salvage values are assigned to the rigs based on
an estimate of 10%.
Effective July 1, 1998, the Company made certain changes in the
estimated useful lives of its well service rigs, increasing the lives from 17
years to 25 years. This change decreased the net loss for the twelve months
ended June 30, 1999 by approximately $3,100,000 ($0.11 per share-basic). Had
this change been made effective July 1, 1997, the effect would have increased
net income for the fiscal year ended June 30, 1998 by $1,317,000 ($0.08 per
share-basic). This change was made to better reflect the expected utilization
of these assets over time, to better provide matching of revenues and
expenses and to better reflect the industry standard in regards to estimated
useful lives of workover rigs.
Effective July 1, 1997 the Company changed its method of calculating
depreciation on its drilling rigs from the straight-line method to the
units-of-production method. This method takes into consideration the number
of days the rigs are actually in service each month and depreciation is
recorded for at least 15 days each month for each rig that is available for
service. The Company believes that this method more appropriately reflects
its financial results by better matching revenues with expenses and to better
reflect how the assets are to be used over time. The effect of this change on
net income for fiscal 1998 was not material.
The Company uses the successful efforts method of accounting for its
oil and gas properties. Under this method, all costs associated with
productive wells and nonproductive development wells are capitalized while
nonproductive exploration costs and geological and geophysical costs (if
any), are expensed. Capitalized costs relating to proved properties are
depleted using the units-of-production method.
The Company has adopted FASB Statement No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
This statement requires that long-lived assets including certain identifiable
intangibles, held and used by the Company, be reviewed for impairment
whenever events or changes in circumstances indicate that the carrying amount
of an asset may not be recoverable. For purposes of applying this statement,
the Company groups its long-lived assets, including goodwill, on a
yard-by-yard basis and compares the estimated future cash flows of each yard
to the yard's net carrying value including allocable goodwill. The Company
would record an impairment, reducing the yard's net carrying value to an
estimated fair value, if the
F-8
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
estimated future cash flows were less than the yard's net carrying value.
Since adoption of this statement no impairment losses have been required.
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
The Company uses derivative financial instruments, primarily
commodity option contracts to reduce the exposure of its oil and gas
producing operations to changes in the market price of natural gas and crude
oil and to fix the price for natural gas and crude oil independently of the
physical sale.
The financial instruments that the Company accounts for as hedging
contracts must meet the following criteria: the underlying asset or liability
must expose the Company to price risk that is not offset in another asset or
liability, the hedging contract must reduce that price risk, and the
instrument must be designated as a hedge at the inception of the contract and
throughout the contract period. In order to qualify as a hedge, there must be
clear correlation between changes in the fair value of the financial
instrument and the fair value of the underlying asset or liability such that
changes in the market value of the financial instrument will be offset by the
effect of price rate changes on the exposed items.
Premiums paid for commodity option contracts, which qualify as
hedges, are amortized to oil and gas sales over the terms of the contracts.
Unamortized premiums are included in other assets in the consolidated balance
sheet. Amounts receivable under the commodity option contracts are accrued as
an increase in oil and gas sales for the applicable periods.
In June 1998, the FASB issued Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value.
SFAS 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met.
Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income statement.
Companies must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. SFAS 133 is effective for fiscal
years beginning after June 15, 2000 and will be adopted as of July 1, 2000 by
the Company. SFAS 133 cannot be applied retroactively and must be applied to
(a) derivative instruments and (b) certain derivative instruments embedded in
hybrid contracts that were issued, acquired, or substantively modified after
December 31, 1997 (and, at the Company's election, before January 1, 1998.)
The oil and gas collars currently in place will be marked to market through
the income statement until such time as they are documented as hedges.
COMPREHENSIVE INCOME
The Company adopted Statement of Financial Accounting Standards No.
130, "Reporting Comprehensive Income" ("SFAS 130") effective July 1, 1998.
SFAS 130 establishes standards for reporting and presentation of
comprehensive income and its components. SFAS 130 requires that all items
that are required to be recognized under accounting standards as components
of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements. In
accordance with the provisions of SFAS 130, the Company has presented the
components of comprehensive income in its Consolidated Statements of
Comprehensive Income.
F-9
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
ENVIRONMENTAL
The Company is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and may
require the Company to remove or mitigate the adverse environmental effects
of the disposal or release of petroleum or chemical substances at various
sites. Environmental expenditures are expensed or capitalized depending on
their future economic benefit. Expenditures that relate to an existing
condition caused by past operations and that have no future economic benefits
are expensed. Liabilities for expenditures of a non-capital nature are
recorded when environmental assessment and/or remediation is probable, and
the costs can be reasonably estimated.
GOODWILL
Net Goodwill, totaling $198.6 million and $205.4 million at June 30,
2000 and 1999, respectively, represents the cost in excess of fair value of
the net tangible and identifiable intangible assets acquired and liabilities
assumed in purchase transactions. Goodwill is being amortized on a
straight-line basis over periods ranging from ten to 25 years. Amortization
of goodwill for fiscal 2000, 1999 and 1998 was $9,840,000, $9,202,000 and
$1,442,000, respectively. The carrying amount of unamortized goodwill is
reviewed for potential impairment loss whenever events or changes in
circumstances indicate that the carrying amount of goodwill may not be
recoverable (see Property and Equipment above, for further discussion).
DEFERRED COSTS
Deferred costs totaling $30,998,000 and $30,488,000 at June 30, 2000
and 1999, respectively, represent debt issuance costs and are recorded net of
accumulated amortization of $12,142,000 and $6,709,000 at June 30, 2000 and
1999, respectively. Deferred costs are amortized to interest expense using
the straight-line method over the life of each applicable debt instrument or
as related debt is retired. This method approximates the amortization which
would be recorded using the effective interest method. Amortization of
deferred costs totaled $5,176,000, $4,664,000 and $2,006,000 for fiscal 2000,
1999 and 1998, respectively.
INCOME TAXES
The Company accounts for income taxes based upon Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS
109"). Under SFAS 109, deferred tax assets and liabilities are recognized for
the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using
statutory tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or settled. The
effect on deferred tax assets and liabilities of a change in tax rate is
recognized in income in the period that includes the statutory enactment
date. A valuation allowance for deferred tax assets is recognized when it is
more likely than not that the benefit of deferred tax assets will not be
realized.
The Company and its eligible subsidiaries file a consolidated U.S.
federal income tax return. Certain subsidiaries that are consolidated for
financial reporting purposes are not eligible to be included in the
consolidated U.S. federal income tax return and separate provisions for
income taxes have been determined for these entities or groups of entities.
F-10
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
EARNINGS PER SHARE
The Company accounts for earnings per share under Statement of
Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS 128").
Under SFAS 128, basic earnings per common share is determined by dividing net
earnings applicable to common stock by the weighted average number of common
shares actually outstanding during the year. Diluted earnings per common
share is based on the increased number of shares that would be outstanding
assuming conversion of dilutive outstanding convertible securities using the
"as if converted" method.
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
----------------------------------------------
2000 1999 1998
------------ ------------ -------------
(THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
BASIC EPS COMPUTATION:
NUMERATOR
Income (loss) before extraordinary gain...................... $ (20,570) $ (53,258) 24,175
Extraordinary gain, net of tax............................... 1,611 -- --
------------ ------------ -------------
Net income (loss)............................................ $ (18,959) $ (53,258) $ 24,175
============ ============ =============
DENOMINATOR
Weighted average common shares outstanding................... 83,815 27,501 17,153
------------ ------------ -------------
BASIC EPS:
Before extraordinary gain.................................... $ (0.25) $ (1.94) 1.41
Extraordinary gain, net of tax............................... (0.02) -- --
------------ ------------ -------------
After extraordinary gain......................................... $ (0.23) $ (1.94) $ 1.41
============ ============ =============
DILUTED EPS COMPUTATION:
NUMERATOR
Income (loss) before extraordinary gain...................... $ (20,570) $ (53,258) $ 24,175
Effect of dilutive securities, tax effected:
Convertible securities....................................... -- -- --
------------ ------------ -------------
Income (loss) before extraordinary gain................... $ (20,570) $ (53,258) $ 29,506
Extraordinary gain, net of tax............................ 1,611 -- --
------------ ------------ -------------
Net income (loss)......................................... $ (18,959) $ (53,258) $ 29,506
============ ============ =============
DENOMINATOR
Weighted average common shares outstanding................... 83,815 27,501 17,153
Warrants..................................................... -- -- 141
Stock options................................................ -- -- 1,266
7% Convertible Debentures.................................... -- -- 1,191
5% Convertible Notes......................................... -- -- 4,273
------------ ------------ -------------
83,815 27,501 24,024
</TABLE>
F-11
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
----------------------------------------------
2000 1999 1998
------------ ------------ -------------
(THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
DILUTED EPS:
Before extraordinary gain.................................... $ (0.25) $ (1.94) $ 1.23
Extraordinary gain, net of tax............................... 0.02 -- --
------------ ------------ -------------
After extraordinary gain..................................... $ (0.23) $ (1.94) $ 1.23
============ ============ =============
</TABLE>
The fiscal 2000 and 1999 earnings per share calculations exclude the
Company's convertible debt, outstanding warrants and stock options, because
the effects of such instruments on earning per share would be anti-dilutive.
CONCENTRATION OF CREDIT RISK
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist primarily of temporary cash
investments and trade receivables. The Company restricts investment of
temporary cash investments to financial institutions with high credit
standing and, by policy, limits the amount of credit exposure to any one
financial institution. The Company's customer base primarily consists of
multi-national, foreign national and independent oil and natural gas
producers. This may affect the Company's overall exposure to credit risk
either positively or negatively, in as much as its customers are affected by
economic conditions in the oil and gas industry, which have historically been
cyclical. However, accounts receivable are well diversified among many
customers and a significant portion of the receivables are from major oil
companies, which management believes minimizes potential credit risk.
Historically, credit losses have been insignificant. Receivables are
generally not collateralized, although the Company may generally secure a
receivable at any time by filing a mechanic's or material-man's lien on the
well serviced. The Company maintains reserves for potential credit losses,
and such losses have been within management's expectations.
The Company did not have any one customer who represented 10% or
more of consolidated revenues for the fiscal year ended June 30, 2000 or 1999.
STOCK-BASED COMPENSATION
The Company accounts for stock option grants to employees using the
intrinsic value method of accounting prescribed by APB Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APB 25"). Under the Company's
stock incentive plans, the price of the stock on the grant date is the same
as the amount an employee must pay to exercise the option to acquire the
stock; accordingly, the options have no intrinsic value at grant date, and in
accordance with the provisions of APB 25, no compensation cost is recognized.
In October 1995, the FASB issued Statement of Financial Accounting
Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation", which
sets forth alternative accounting and disclosure requirements for stock-based
compensation arrangements. SFAS 123 does not rescind the existing accounting
for employee stock-based compensation under APB 25. Companies may continue to
follow the current accounting to measure and recognize employee stock-based
compensation; however, SFAS 123 requires disclosure of pro forma net income
and earnings per share that would have been reported under the "fair value"
based recognition provisions of SFAS 123. The Company has disclosed in Note
10 the pro forma information required under SFAS 123.
F-12
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
FOREIGN CURRENCY GAINS AND LOSSES
The local currency is the functional currency for all of the
Company's foreign operations (Argentina and Canada). The cumulative
translation gains and losses, resulting from translating each foreign
subsidiary's financial statements from the functional currency to U.S.
dollars, is included in other comprehensive income and accumulated in equity
until a partial or complete sale or liquidation of the Company's net
investment in the foreign entity.
CASH AND CASH EQUIVALENTS
The Company considers all unrestricted highly liquid investments
with less than a three-month maturity when purchased, as cash equivalents.
RECLASSIFICATIONS
Certain reclassifications have been made to the fiscal 1999 and 1998
consolidated financial statements to conform to the fiscal 2000 presentation.
2. RESTRUCTURING CHARGE
In response to an industry downturn caused by historically low oil
and gas prices and the resulting slowdown in business, on December 7, 1998,
the Company announced a company-wide restructuring plan to reduce operating
costs beyond those achieved through the Company's consolidation efforts. The
plan involved a reduction in the size of management and on-site work force,
salary reductions averaging 21% for senior management, the combination of
previously separate operating divisions and the elimination of redundant
overhead and facilities. The restructuring plan resulted in pretax charges to
earnings of approximately $6.7 million in the second quarter ending December
31, 1998 and $1.5 million in the third quarter ending March 31, 1999.
However, due to an increase in oil and gas prices beginning during the
Company's fourth fiscal quarter, the Company amended its restructuring plan
to decrease the number of planned employee terminations. Increased demand for
the Company's services made such terminations unnecessary and would have, in
management's opinion, restricted the Company's ability to provide services to
its customers. Consequently, the Company did not utilize approximately $3.7
million of the pretax charges. Essentially all of the unutilized portion of
the restructuring charge was reversed in the fourth quarter ending June 30,
1999 resulting in a total pretax charge for the fiscal year ended June 30,
1999 of approximately $4.5 million. The charges include severance payments
and other termination benefits for approximately 97 employees, lease
commitments related to closed facilities and environmental studies performed
on closed yard locations.
F-13
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
2. RESTRUCTURING CHARGE (CONTINUED)
The Company has completed the plan at June 30, 2000. There remained
approximately $180,000 for COBRA benefits to terminated employees and $53,000
for contractual payments to an employee at June 30, 1999. The major
components of the restructuring charge and costs incurred through June 30,
1999 were as follows:
<TABLE>
<CAPTION>
COST INCURRED
RESTRUCTURING THROUGH BALANCE AS OF
DESCRIPTION CHARGE JUNE 30, 1999 JUNE 30, 1999
----------- --------------- ---------------- ---------------
(IN THOUSANDS)
<S> <C> <C> <C>
Severance/Employee costs............................. $ 4,457 $ (4,224) $ 233
Lease commitments.................................... 27 (27) --
Environmental clean-up............................... 20 (20) --
--------------- ---------------- ---------------
Total................................................ $ 4,504 $ (4,271) $ 233
=============== ================ ===============
</TABLE>
3. BUSINESS AND PROPERTY ACQUISITIONS
DAWSON PRODUCTION SERVICES, INC.
In September 1998, the Company completed the acquisition of all of
the capital stock of Dawson Production Services, Inc. ("Dawson") for an
aggregate consideration of approximately $382.6 million, including
approximately $207.1 million of cash paid for the Dawson stock and for
transactional fees and approximately $175.5 million of net liabilities
assumed.
Expenditures for the Dawson acquisition, including acquisition
costs, less cash acquired were as follows (in thousands):
<TABLE>
<CAPTION>
<S> <C>
Fair value of assets acquired, including goodwill............................................. $ 409,722
Liabilities assumed........................................................................... (199,439)
Liabilities for employee termination costs and lease termination costs........................ (3,162)
--------------
Cash paid, including acquisition related expenditures and the cost of Dawson common
stock previously held.................................................................... 207,121
Less: Cash acquired........................................................................... (27,008)
--------------
Net cash used for the acquisition............................................................. $ 180,113
==============
</TABLE>
At the time of the closing, Dawson owned approximately 527 well
service rigs, 200 oilfield trucks, and 21 production testing units in South
Texas and the Gulf Coast, East Texas and Louisiana, the Permian Basin of West
Texas and New Mexico, the Anadarko Basin of Texas and Oklahoma, California,
and in the inland waters of the Gulf of Mexico.
In connection with the Dawson acquisition, the Company recognized
liabilities for the estimated costs to involuntarily terminate employees of
Dawson and to exit certain activities of Dawson, primarily Dawson's lease
liability for its corporate offices. As of June 30, 1999, the Company had
completed its severance plan, terminating 44 former Dawson employees. At June
30, 1999, the Company had $592,000 accrued, representing the estimated lease
termination costs of Dawson's former corporate offices.
F-14
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
3. BUSINESS AND PROPERTY ACQUISITIONS (CONTINUED)
OTHER FISCAL 1999 ACQUISITIONS
In addition to its acquisition of Dawson, the Company acquired the
assets and/or capital stock of six well servicing and contract drilling
businesses during fiscal 1999, increasing its rig and truck fleet by a total
of approximately 93 well service rigs, 4 drilling rigs and 185 oilfield
trucks (and related equipment) for an aggregate purchase price of
approximately $93.7 million in cash. Each of the acquisitions was accounted
for using the purchase method and the results of the operations, generated
from the acquired assets, are included in the Company's results of operations
as of the completion date of each acquisition.
ACQUISITIONS COMPLETED PRIOR TO JUNE 30, 1998
During fiscal 1998, the Company purchased the capital stock of 17
companies and purchased the assets of 13 other companies. The Company paid
cash of approximately $244 million, excluding purchase price adjustments, and
issued common stock and warrants to purchase the Company's common stock
valued at approximately $13.8 million. Each of the acquisitions was accounted
for using the purchase method and the results of operations of the
acquisitions were included in the Company's results of operations as of the
date of completion of each acquisition.
PRO FORMA RESULTS OF OPERATIONS--(UNAUDITED)
The following unaudited pro forma results of operations have been
prepared as though the Dawson acquisition and the significant fiscal 1998
acquisitions (Ram Oil Well Service, Inc., Rowland Trucking Co., Inc., Big A
Well Service Co., Sunco Trucking Co., Justis Supply Co., Inc., Dunbar Well
Service, Inc., J.W. Gibson Well Service Co., Updike Brothers, Inc. and Lakota
Drilling Co.) had been acquired on July 1, 1997 with adjustments to record
specifically identifiable decreases in direct costs and general and
administrative expenses related to the termination of individual employees.
Pro forma amounts are not necessarily indicative of the results that may be
reported in the future.
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
-----------------------------------------
1999 1998
--------------- -------------
<S> <C> <C>
Revenue............................................................... $ 524,924 $ 685,296
Net income (loss)..................................................... (58,211) 13,164
Basic earnings (loss) per share....................................... (2.12) 0.77
</TABLE>
4. COMMITMENTS AND CONTINGENCIES
Various suits and claims arising in the ordinary course of business
are pending against the Company. Management does not believe that the
disposition of any of these items will result in a material adverse impact to
the consolidated financial position, results of operations or cash flows of
the Company.
In order to retain qualified senior management, the Company enters
into employment agreements with its executive officers. These employment
agreements run for periods ranging from three to five years, but can be
automatically extended on a yearly basis unless terminated by the Company or
the executive officer. In addition to providing a base salary for each
executive officer, the employment agreements provide for severance payments
for each executive officer varying from 1 to 3 years of the executive
officer's base salary. The current annual base salaries for the executive
officers covered under such employment agreements total approximately
$1,125,000. The
F-15
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
4. COMMITMENTS AND CONTINGENCIES (CONTINUED)
Company also enters into employment agreements with other key employees as it
deems necessary in order to retain qualified personnel.
5. LONG-TERM DEBT
The components of long-term debt are as follows:
<TABLE>
<CAPTION>
JUNE 30,
--------------------------------
2000 1999
------------- ---------------
(THOUSANDS)
<S> <C> <C>
Senior Credit Facility(i)
Revolving Loans........................................................ $ 93,000 $ 90,000
Tranche A Term Loan............................................... 22,987 43,366
Tranche B Term Loan............................................... 175,961 177,761
14% Senior Subordinated Notes Due 2009(iii)............................ 143,650 142,907
5% Convertible Subordinated Notes Due 2004(iv)......................... 205,810 216,000
7% Convertible Subordinated Debentures Due 2003(v)..................... 1,000 4,600
Dawson 9 3/8% Senior Notes Due 2007(vi)................................ 1,106 1,406
Capital Leases......................................................... 21,911 20,306
Other notes payable.................................................... 1,175 3,632
------------- ---------------
666,600 699,978
Less current portion................................................... 14,655 16,254
------------- ---------------
Long-term debt......................................................... $ 651,945 $ 683,724
============= ===============
</TABLE>
(I) SENIOR CREDIT FACILITY
On June 6, 1997, the Company entered into an agreement (the "Initial
Credit Agreement") with PNC Bank, N.A. ("PNC"), as administrative agent, and
a syndication of other lenders pursuant to which the lenders provided a $255
million credit facility, consisting of a $120 million seven-year term loan
and a $135 million five-year revolver. The interest rate on the term loan was
LIBOR plus 2.75%. The interest rate on the revolver varied based on LIBOR and
the level of the Company's indebtedness. On September 25, 1997, the Company
repaid the term loan and a portion of the then outstanding amounts under the
revolver by applying the proceeds from the Company's private placement of the
5% Convertible Subordinated Notes discussed below.
Effective November 6, 1997, the Company entered into an Amended and
Restated Credit Agreement (the "Amended Credit Agreement") with PNC, as
administrative agent and lender, pursuant to which PNC agreed to make
revolving credit loans of up to a maximum loan commitment of $200 million.
Borrowings under the Amended Credit Agreement were, at the Company's option,
either (i) Eurodollar Loans with interest payable quarterly at LIBOR plus
1.25%, (ii) Base Rate Loans with interest payable quarterly at the greater of
PNC Prime Rate or the Federal Funds Effective Rate plus 0.50%, or (iii) a
combination thereof. Effective December 3, 1997, PNC completed the
syndication of the Amended Credit Agreement. In connection therewith, PNC, as
administrative agent, a syndication of lenders and the Company entered into a
First Amendment to the Amended Credit Agreement providing for, among other
things, an increase in the maximum commitment to $250 million from $200
million.
The terms of the Amended Credit Agreement remained unchanged until
the Company's acquisition of Dawson in September 1998. In connection with the
acquisition of Dawson, the Company entered into a $550,000,000 Second Amended
and Restated Credit Agreement, dated as of June 6, 1997, as amended and
restated
F-16
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000, 1999 AND 1998
5. LONG-TERM DEBT (CONTINUED)
through September 14, 1998, among the Company, PNC Bank, National
Association, as Administrative Agent, Norwest Bank Texas, N.A., as Collateral
Agent, PNC Capital Markets, Inc., as Arranger, and the other lenders named
from time to time parties thereto (as subsequently amended, the "Current
Credit Agreement").
The Current Credit Agreement provides for a senior credit facility
consisting of $150 million in revolving loans, $150 million in Tranche A term
loans and $200 million in Tranche B term loans. Amounts paid on the term
loans cannot be reborrowed. In addition, up to $20 million of letters of
credit can be issued under the Current Credit Agreement, but any outstanding
letters of credit reduces borrowing availability under the revolving loans.
The Tranche A term loans mature in sixteen consecutive quarterly installments
commencing December 14, 1999 with quarterly installment amounts equal to the
applicable percentage for a particular quarter multiplied by the unamortized
principal amount: 4% for installments 1-4, 6% for installments 5-8, 7% for
installments 9-12 and 8% for installments 13-16. The Tranche B term loans
mature in nineteen consecutive quarterly installments commencing December 14,
1999 with quarterly installment amounts equal to the applicable percentage
for a particular quarter multiplied by the unamortized principal amount:
0.25% for installments 1-16, 24% for installments 17-18 and 48% for the final
installment. The commitment to make revolving loans will be reduced to $125
million and $100 million, on September 14, 2001 and September 14, 2002,
respectively. The revolving commitment will terminate on September 14, 2003,
and all the revolving loans must be paid on or before that date.
The revolving loans and the Tranche A term loan bear interest at
rates based upon, at the Company's option, either the prime rate plus a
margin ranging from 0.75% to 2.00% or a Eurodollar rate plus a margin ranging
from 2.25% to 3.50%, in each case depending upon the ratio of the Company's
total debt (less cash on hand over $5 million) to the Company's trailing
12-month EBITDA, as adjusted. The Tranche B term loan bears interest at rates
based upon, at the Company's option, either the prime rate plus 2.50% or a
Eurodollar rate plus 4.00%. The Company pays commitment fees on the unused
portion of the revolving loan at a varying rate (depending upon the pricing
ratio) of between 0.25% and 0.50%.
The Current Credit Agreement contains various financial covenants,
including: (i) consolidated debt-to-capitalization ratio at generally
decreasing levels varying between 79% and 65%, (ii) consolidated interest
coverage ratio at generally increasing levels varying between 2.00-to-1.00
and 3.50-to-1.00, (iii) consolidated senior leverage ratio at generally
decreasing levels varying between 2.50-to-1.00 and 2.00-to-1.00, and (iv)
trailing 12-month EBITDA, as adjusted, at generally increasing levels varying
between $50 million and $150 million. In addition, the Company must maintain
a consolidated fixed charge coverage ratio at generally decreasing levels
varying between 1.25-to-1.00 and 1.00 to 1.00. The covenants for consolidated
senior leverage ratio and consolidated interest coverage ratio are not
imposed until the quarter ending March 31, 2001, and the covenant levels for
consolidated debt-to-capitalization and trailing 12-month EBITDA, as
adjusted, will remain fixed at 79% and $50 million, respectively, for the
same period. The Company is also required to maintain a consolidated
liquidity level of at least $30 million.
The Current Credit Agreement subjects the Company to other
restrictions, including restrictions upon the Company's ability to incur
additional debt, liens and guarantee obligations, to merge or consolidate
with other persons, to sell assets, to make dividends, purchases of our stock
or subordinated debt, to make capital expenditures in excess of levels
ranging from $37.5 million in fiscal 1999 to $65 million in fiscal 2004, or
to make investments, loans and advances or changes to debt instruments and
organizational documents. The Company will not be permitted to make
acquisitions unless (i) its consolidated debt to capitalization ratio is not
more than 60% or (ii) its consolidated debt to capitalization ratio is not
increased and the acquisition is funded solely with capital stock. The
Company must also maintain consolidated net worth not less than $195 million
plus (i) 75% of consolidated net income for each fiscal quarter beginning
with the period ending December 31, 1998, (ii) 75% of the net cash
F-17
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
5. LONG-TERM DEBT (CONTINUED)
proceeds from issuance of capital stock after September 14, 1998 and (iii) 75%
of the increase in consolidated net worth resulting from the conversion of the
5% Convertible Subordinated Notes or other convertible debt issued after
September 14, 1998. All obligations under the senior credit facility are
guaranteed by most of the Company's subsidiaries and are secured by
substantially all the Company's assets, including the Company's accounts
receivable, inventory and equipment. Unless required percentages of the
lenders otherwise agree, the term loans under the Current Credit Agreement,
must be prepaid from 75% of the Company's excess cash flow (as defined) for
each fiscal year until the Company's debt-to capitalization ratio (as defined)
is less than 60% and 50% of the Company's excess cash flow for each fiscal
year thereafter.
At June 30, 1999, the principal amount outstanding under the Tranche
A term loan the Tranche B term loan and the revolver was $43.4 million, $177.8
million and $89.6 million, respectively. During fiscal 2000, the Company
repaid approximately $22.2 million under the term loans while increasing net
borrowings under the revolver by $3 million. As a result, at June 30, 2000,
the principal amount outstanding under the Tranche A term loan, the Tranche B
term loan and the revolver was reduced to approximately $23.0, $176.0 million
and $93.0 million, respectively. Additionally, the Company had outstanding
letters of credit of $15,132,000 and $10,832,000 as of June 30, 2000 and 1999,
respectively, related to its workman's compensation insurance.
Since June 30, 2000, a portion of the net proceeds from the Company's
equity offering (see Note 10) was used to repay the entire outstanding balance
of the Tranche A term loan and $2.3 million of the Tranche B term loan thereby
reducing the principal amount outstanding under the Tranche B term loan to
approximately $174 million. The Tranche B term loan prepayments were applied
to reduce each of the mandatory repayment installments of the Tranche B term
loan pro rata, thereby equally reducing all amortization payments without
altering the amortization schedule. In addition, $65 million of the net
proceeds from the Equity Offering were used to reduce the principal amount
outstanding under the revolver to $28 million. The remainder of the net
proceeds of the Equity Offering was used to retire other long-term debt. In
addition, the principal amount outstanding under the revolver has been further
reduced to $23 million as of September 28, 2000.
(II) BRIDGE LOAN
In connection with the Dawson acquisition, the Company entered into a
bridge loan agreement in the amount of $150,000,000, dated as of September 14,
1998, among the Company, Lehman Brothers Inc., as Arranger, and Lehman
Commercial Paper Inc., as Administrative Agent, and the other lenders party
thereto (the "Bridge Loan Agreement"). Interest under the Bridge Loan
Agreement accrued at LIBOR plus 6.50% and was payable on the 16th day of each
month beginning October 16, 1998. The Bridge Loan was repaid in January 1999
with proceeds from the Company's issuance of the 14% Senior Subordinated Notes.
(III) 14% SENIOR SUBORDINATED NOTES
On January 22, 1999 pursuant to Rule 144A and Regulation S under the
Securities Act of 1933, as amended (the "Securities Act"), the Company
completed the private placement of 150,000 units (the "Units") consisting of
$150,000,000 of 14% Senior Subordinated Notes due 2009 (the "14% Senior
Subordinated Notes") and 150,000 warrants to purchase 2,032,565 shares of
common stock at an exercise price of $4.88125 per share (the "Unit Warrants").
The cash proceeds from the private placement, net of fees and expenses, were
used to repay substantially all of the remaining $148.6 million principal
amount (plus accrued interest) owed under the Bridge Loan Agreement.
F-18
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
5. LONG-TERM DEBT (CONTINUED)
On and after January 15, 2004, the Company may redeem some or all of
the 14% Senior Subordinated Notes at any time at varying redemption prices in
excess of par, plus accrued interest. In addition, before January 15, 2002,
the Company may redeem up to 35% of the aggregate principal amount of the 14%
Senior Subordinated Notes with the proceeds of certain offerings of equity at
114% of par, plus accrued interest.
The Unit Warrants have separated from the 14% Senior Subordinated
Notes and became exercisable on January 25, 2000. On the date of issuance, the
value of the Unit Warrants was estimated at $7,434,000 and is classified as a
discount to the 14% Senior Subordinated Notes on the Company's consolidated
balance sheet. The discount is being amortized to interest expense over the
term of the 14% Senior Subordinated Notes. The 14% Senior Subordinated Notes
mature and the Unit Warrants expire on January 15, 2009. The 14% Senior
Subordinated Notes are subordinate to the Company's senior indebtedness,
which, as defined in the indenture under which the 14% Senior Subordinated
Notes were issued, includes borrowings under the Current Credit Agreement and
the Dawson 9 3/8% Senior Notes.
In the event of a change in control of the Company, as defined in the
indenture under which the 14% Senior Subordinated Notes were issued, each
holder of 14% Senior Subordinated Notes will have the right, at the holder's
option, to require the Company to repurchase all or any part of the holder's
14% Senior Subordinated Notes, within 60 days of such event, at a price equal
to 100% of the principal amount thereof, together with accrued and unpaid
interest thereon.
At June 30, 2000, $150,000,000 principal amount of the 14% Senior
Subordinated Notes remained outstanding. The 14% Senior Subordinated Notes pay
interest semi-annually on January 15 and July 15 of each year, beginning July
15, 1999. Interest of approximately $10,092,000 was paid on July 15, 1999 and
$10,500,000 was paid on January 15, 2000. As of June 30, 2000, 52,000 Unit
Warrants had been exercised, producing approximately $3,700,000 of proceeds to
the Company and leaving 98,000 Unit Warrants outstanding.
(IV) 5% CONVERTIBLE SUBORDINATED NOTES
On September 25, 1997, the Company completed an initial closing of
its private placement of $200 million of 5% Convertible Subordinated Notes due
2004 (the "5% Convertible Subordinated Notes"). On October 7, 1997, the
Company completed a second closing of its private placement of an additional
$16 million of the 5% Convertible Subordinated Notes pursuant to the exercise
of the remaining portion of the over-allotment option granted to the initial
purchasers of the 5% Convertible Subordinated Notes. The placements were made
as private offerings pursuant to Rule 144A and Regulation S under the
Securities Act. The 5% Convertible Subordinated Notes are subordinate to the
Company's senior indebtedness, which, as defined in the indenture under which
the 5% Convertible Subordinated Notes were issued, includes borrowings under
the Current Credit Agreement, the 14% Senior Subordinated Notes and the Dawson
9 3/8% Senior Notes. The 5% Convertible Subordinated Notes are convertible, at
the holder's option, into shares of the Company's common stock at a conversion
price of $38.50 per share, subject to certain adjustments.
The 5% Convertible Subordinated Notes are redeemable, at the
Company's option, on or after September 15, 2000, in whole or part, together
with accrued and unpaid interest. The initial REDEMPTION price is 102.86% for
the year beginning September 15, 2000 and declines ratably thereafter on an
annual basis.
In the event of a change in control of the Company, as defined in the
indenture under which the Notes were issued, each holder of 5% Convertible
Subordinated Notes will have the right, at the holder's option, to require the
F-19
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
5. LONG-TERM DEBT (CONTINUED)
Company to repurchase all or any part of the holder's 5% Convertible
Subordinated Notes, within 60 days of such event, at a price equal to 100% of
the principal amount thereof, together with accrued and unpaid interest
thereon.
During the quarter ended June 30, 2000, the Company repurchased (and
canceled) $10,190,000 principal amount of the 5% Convertible Subordinated
Notes, leaving $205,810,000 principal amount of the 5% Convertible
Subordinated Notes outstanding at June 30, 2000. This repurchase resulted in
an after-tax gain of $1,611,000. Since June 30, 2000, the Company repurchased
(and canceled) $10,196,000 principal amount of the 5% Convertible Subordinated
Notes leaving $195,614,000 outstanding as of September 28, 2000. Interest on
the 5% Convertible Subordinated Notes is payable on March 15 and September 15.
Interest of approximately $5.4 million was paid on September 15, 1999 and
March 15, 2000.
(V) 7% CONVERTIBLE SUBORDINATE DEBENTURES
In July 1996, the Company completed a $52,000,000 private placement
of 7% Convertible Subordinated Debentures due 2003 (the "7% Convertible
Subordinated Debentures") pursuant to Rule 144A under the Securities Act. The
7% Convertible Subordinated Debentures are subordinate to the Company's senior
indebtedness, which, as defined in the indenture under which the 7%
Convertible Subordinated Debentures were issued, includes borrowings under the
Current Credit Agreement, the 14% Senior Subordinated Notes and the Dawson
9 3/8% Senior Notes.
The Debentures are convertible, at any time prior to maturity, at the
holders' option, into shares of the Company's common stock at a conversion
price of $9.75 per share, subject to certain adjustments. In addition, holders
who converted prior to July 1, 1999 were entitled to receive a payment, in
cash or the Company's common stock (at the Company's option) generally equal
to 50% of the interest otherwise payable from the date of conversion through
July 1, 1999.
The 7% Convertible Subordinated Debentures are redeemable, at the
option of the Company, on or after July 15, 1999, at a redemption price of
104%, decreasing 1% per year on each anniversary date thereafter. In the event
of a change in control of the Company, as defined in the indenture under which
the 7% Convertible Subordinated Debentures were issued, each holder will have
the right, at the holder's option, to require the Company to repurchase all or
any part of the holder's 7% Convertible Subordinated Debentures within 60 days
of such event at a price equal to 100% of the principal amount thereof,
together with accrued and unpaid interest thereon.
During fiscal 1998, $47,400,000 in principal amount of the Debentures
was converted into 4,861,538 shares of the Company's common stock. An
additional 165,423 shares of common stock were issued representing 50% of the
interest otherwise payable from the date of conversion through July 1, 1999
and an additional 35,408 shares of common stock were issued as an inducement
to convert. The additional 165,423 shares of common stock, representing 50% of
the interest otherwise payable from the date of conversion through July 1,
1999, are included in equity. The fair value of the additional 35,408 shares
of common stock issued as inducement to convert was $710,186 and is recorded
as interest expense in the consolidated statement of operations. In addition,
the proportional amount of unamortized debt issuance costs associated with the
converted 7% Convertible Subordinated Debentures was charged to additional
paid-in capital at the time of conversion.
During fiscal 2000, $3,600,000 in principal amount of the Debentures
was converted into 369,229 shares of the Company's common stock. An additional
11,261 shares of common stock were issued representing 100% of the interest
otherwise payable from January 1, 2000 through July 1, 2000.
F-20
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
5. LONG-TERM DEBT (CONTINUED)
The additional 11,261 shares of common stock, representing 100% of
the interest otherwise payable from January 1, 2000 through July 1, 2000, are
included in equity. In addition, the proportional amount of unamortized debt
issuance costs associated with the converted 7% Convertible Subordinated
Debentures was charged to additional paid-in capital at the time of conversion.
At June 30, 2000, $1,000,000 principal amount of the 7% Convertible
Subordinated Debentures remained outstanding. On August 31, 2000, $985,000
principal amount of the 7% Convertible Subordinated Debentures were
surrendered for conversion by the holders thereof and 101,025 shares of common
stock were issued on September 1, 2000. The remaining $15,000 principal amount
of the outstanding 7% Convertible Subordinated Debentures were redeemed at
103% of the principal amount plus accrued interest leaving none outstanding as
of September 28, 2000. Interest on the 7% Convertible Subordinated Debentures
was payable on January 1 and July 1 of each year. Interest of approximately
$161,000 was paid on July 1, 1999 and January 1, 2000.
(VI) DAWSON 9 3/8% SENIOR NOTES
As the result of the Dawson acquisition (see Note 3), the Company,
its subsidiaries and U.S. Trust Company of Texas, N.A., trustee ("U.S.
Trust"), entered into a Supplemental Indenture dated September 21, 1998 (the
"Supplemental Indenture"), pursuant to which the Company assumed the
obligations of Dawson under the Indenture dated February 20, 1997 (the
"Dawson Indenture") between Dawson and U.S. Trust. Most of the Company's
subsidiaries guaranteed those obligations and the senior notes due 2007 (the
"Dawson 9 3/8% Senior Notes") issued pursuant to the Dawson Indenture were
equally and ratably secured with the obligations under the Current Credit
Agreement. On November 17, 1998 the Company completed a cash tender offer to
purchase the full $140,000,000 outstanding principal amount of Dawson 9 3/8%
Senior Notes at 101% of the aggregate principal amount of the notes, using
borrowings under the Current Credit Agreement. Under the tender offer,
$138,594,000 in principal amount of the Dawson 9 3/8% Senior Notes was
redeemed and a premium of $1,386,000 was paid. In addition, accrued interest
of $4,078,000 was paid at redemption.
At June 30, 1999, $1,406,000 principal amount of the Dawson 9 3/8%
Senior Notes remained outstanding. During the quarter ended June 30, 2000,
the Company repurchased $300,000 principal amount of the Dawson 9 3/8% Senior
Notes, leaving $1,106,000 principal amount of the Dawson 9 3/8% Senior Notes
remained outstanding at June 30, 2000. Since June 30, 2000, the Company
repurchased $800,000 principal amount of the Dawson 9 3/8% Senior Notes,
leaving $306,000 principal amount outstanding as of September 28, 2000.
Interest on the Dawson 9 3/8% Senior Notes is payable on February 1 and
August 1 of each year. Interest of approximately $65,906 was paid on August
1, 1999 and February 1, 2000.
CAPITALIZED EXPENSES, REPAYMENT SCHEDULE AND INTEREST EXPENSE
The Company capitalized a total of approximately $16,370,000 in fees
and expenses in connection with its various financings during fiscal 1999.
F-21
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
5. LONG-TERM DEBT (CONTINUED)
Presented below is a schedule of the repayment requirements of
long-term debt for each of the next five years and thereafter as of June 30,
2000:
<TABLE>
<CAPTION>
PRINCIPAL
FISCAL YEAR END AMOUNT
--------------- -------------
(IN THOUSANDS)
<S> <C>
2001..................................................................................... $ 14,655
2002..................................................................................... 15,687
2003..................................................................................... 16,732
2004..................................................................................... 172,988
2005..................................................................................... 205,067
Thereafter................................................................................. 241,471
-------------
$ 666,600
=============
</TABLE>
The Company's interest expense for the years ended June 30, 2000, 1999
and 1998 consist of the following:
<TABLE>
<CAPTION>
2000 1999 1998
-------------- -------------- ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash Payments for interest..................................... $ 61,956 $ 52,397 $ 16,441
Commitment & agency fees paid.................................. 1,139 527 860
Accretion of discount on notes................................. 743 552 --
Amortization of capitalized loan payments...................... 5,176 4,664 2,459
Net change in accruals......................................... 2,916 9,261 1,716
-------------- -------------- ------------
$ 71,930 $ 67,401 $ 21,476
============== ============== ============
</TABLE>
6. DEBT ISSUANCE COSTS
During fiscal 1999, the Company recorded an expense item of $6,307,000,
which represented the write-off of debt issuance costs. The debt issuance costs
were associated with the Bridge Loan Agreement, which was subsequently paid
primarily with the proceeds from the Company's private placement of 14% Senior
Subordinated Notes (see Note 5). During fiscal 2000, the Company expensed
$338,000 of debt issuance costs related to the conversion of 7% Notes and other
prepayments of debt.
7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair
values of the Company's financial instruments at June 30, 2000 and 1999. FASB
Statement No. 107, "Disclosures about Fair Value of Financial Instruments",
defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties.
F-22
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
7. FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED)
<TABLE>
<CAPTION>
2000 1999
------------------------------- -------------------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Financial Assets:
Cash & cash equivalents................... $ 109,873 $ 109,873 $ 23,478 $ 23,478
Accounts receivable, net.................. 123,203 123,203 91,998 91,998
Notes receivable--affiliate............... 5,150 5,150 2,385 2,385
Commodity collar contracts................ -- (778) 717 --
Financial Liabilities:
Accounts payable.......................... 34,091 34,091 18,527 18,527
Long-term debt
Senior Credit Facility.................. 291,948 291,948 311,127 311,127
5% Convertible Subordinated Notes....... 205,810 160,532 216,000 137,160
7% Convertible Subordinated Debentures.. 1,000 1,130 4,600 3,450
14% Senior Subordinated Notes........... 143,650 162,325 142,907 153,750
Dawson 9 3/8% Senior Notes.............. 1,106 1,029 1,406 1,336
Capital lease liabilities............... 21,911 21,911 20,306 20,306
Other debt.............................. 1,175 1,175 3,632 3,632
</TABLE>
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments:
Cash, trade receivables and trade payables: The carrying amounts
approximate fair value because of the short maturity of those instruments.
Commodity option contracts: The carrying amount of the commodity
option contracts is comprised of the unamortized premiums paid for the option
contracts. The fair value of the commodity option contracts is estimated using
the discounted forward prices of each options index price, for the term of
each option contract.
Notes receivable-affiliate: The amounts reported relate to notes
receivable from officers of the Company.
Long-term debt: The fair value of the Company's long-term debt is
based upon the quoted market prices for the various notes and debentures at
June 30, 2000 and 1999, and the carrying amounts outstanding under the
Company's senior credit facility.
8. DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to manage
well-defined commodity price risks. The Company is exposed to credit losses in
the event of non-performance by the counter-parties to its commodity hedges.
The Company only deals with reputable financial institutions as
counter-parties and anticipates that such counter-parties will be able to
fully satisfy their obligations under the contracts. The Company does not
obtain collateral or other security to support financial instruments subject
to credit risk but monitors the credit standing of the counter-parties.
F-23
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
8. DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED)
The Company utilizes option or collar contracts to hedge the effect
of price changes on future oil and gas production. The objective of its
hedging activities is to achieve more predictable revenues and cash flows. If
market prices of oil and gas exceeded the strike price of put options, the
options would expire unexercised, therefore reducing the effective price
received for oil and gas sales by the cost of the related option. If the
strike price of put options exceeds the market prices of oil and gas, the
Company would receive payment from the counter-party of the contract equal to
the contracted volumes times the difference between the market price and the
strike price, increasing the effective price received for oil and gas sales by
the amount received from the counter-party. If the market price of oil and gas
is outside the "collar" on collar contracts, the Company will pay or receive
payment which will increase or decrease the effective price received for oil
and gas sales.
Gains and amortization of premiums paid on option contracts are
recognized as an adjustment to sales revenue when the related transactions
being hedged are finalized.
The net effect of the Company's commodity hedging activities
decreased oil and gas revenues for the year ended June 30, 2000 by $822,270
and increased oil and gas revenues for the year ended June 30, 1999 by
$158,500.
The following table sets forth the future volumes hedged by year and
the weighted-average strike price of the option contracts at June 30, 2000 and
1999:
<TABLE>
<CAPTION>
MONTHLY INCOME
------------------------
OIL GAS STRIKE PRICE
(BBLS) (MMBTU) TERM PER BBL/MMBTU
--------- ----------- ------------------------ -------------------
<S> <C> <C> <C> <C>
At June 30, 2000
Oil Collars...................... 4,000 -- May 2000 - Feb. 2001 $22.20 - $26.50
5,000 -- Mar 2001 - Feb. 2002 $19.70 - $23.70
Gas Collars...................... 30,000 May 2000 - Feb. 2001 $ 2.60 - $ 3.19
40,000 Mar 2001 - Feb. 2002 $ 2.40 - $ 2.91
At June 30, 1999
Oil.............................. 5,000 -- Jun 1999 - May 2000 $ 17.00
Oil.............................. 17,000 -- Jul 1999 - Jun 2000 $ 18.00
Gas.............................. -- 100,000 Jun 1999 - May 2000 $ 2.50
</TABLE>
(The strike prices for oil are based on the NYMEX spot price for West
Texas Intermediate; the strike prices for gas are based on the Inside FERC-West
Texas Waha spot price).
9. OTHER ACCRUED LIABILITIES
Other accrued liabilities consist of the following:
<TABLE>
<CAPTION>
JUNE 30,
--------------------------------
2000 1999
------------- ---------------
(THOUSANDS)
<S> <C> <C>
Accrued payroll, taxes and employee benefits........................... $ 15,261 $ 15,423
State sales, use and other taxes....................................... 2,465 2,044
Oil and gas revenue distribution....................................... 1,714 267
Other.................................................................. 6,958 7,557
------------- ---------------
Total.................................................................. $ 26,398 $ 25,291
============= ===============
</TABLE>
F-24
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
10. STOCKHOLDERS' EQUITY
EQUITY OFFERINGS
On June 30, 2000, the Company closed the public offering of
11,000,000 shares of common at $9.625 per share, or approximately $106 million
(the "Equity Offering"). Net proceeds from the Equity Offering of
approximately $101 million were used to repay a portion of the Company's term
loan borrowings and revolving line of credit under its senior credit facility
and to retire other long-term debt.
On May 7, 1999, the Company closed the public offering of 55,300,000
shares of common stock (300,000 shares of which were sold pursuant to the
underwriters' over-allotment option discussed below) at $3.00 per share, or
$166 million (the "Prior Public Offering"). Concurrently therewith, the
Company closed the offering of an additional 3,508,772 shares of common stock
at $2.85 per share, or $10 million (the "Prior Concurrent Offering" and
together with the Prior Public Offering, the "Prior Equity Offerings"). In
addition, on June 7, 1999, the underwriters of the Prior Public Offering
exercised an over-allotment option to purchase an additional 5,436,000 million
shares to cover over-allotments. Net proceeds from the Prior Equity Offerings
of approximately $180.4 million were used to repay a portion of the Company's
term loan borrowings under its senior credit facility.
STOCK INCENTIVE PLANS
On January 13, 1998 the Company's shareholders approved the Key
Energy Group, Inc. 1997 Incentive Plan, as subsequently amended (the "1997
Incentive Plan"). The 1997 Incentive Plan is an amendment and restatement of
the plans formerly known as the "Key Energy Group, Inc. 1995 Stock Option
Plan" (the "1995 Option Plan") and the "Key Energy Group, Inc. 1995 Outside
Directors Stock Option Plan" (the "1995 Directors Plan") (collectively, the
"Prior Plans").
All options previously granted under the Prior Plans and outstanding
as of November 17, 1997 (the date on which the Company's board of directors
adopted the plan) were assumed and continued, without modification, under the
1997 Incentive Plan.
Under the 1997 Incentive Plan, the Company may grant the following
awards to key employees, directors who are not employees ("Outside Directors")
and consultants of the Company, its controlled subsidiaries, and its parent
corporation, if any: (i) incentive stock options ("ISOs") as defined in
Section 422 of the Internal Revenue Code of 1986, as amended (the "Code"),
(ii) "nonstatutory" stock options ("NSOs"), (iii) stock appreciation rights
("SARs"), (iv) shares of the restricted stock, (v) performance shares and
performance units, (vi) other stock-based awards and (vii) supplemental tax
bonuses (collectively, "Incentive Awards"). ISOs and NSOs are sometimes
referred to collectively herein as "Options".
The Company may grant Incentive Awards covering an aggregate of the
greater of (i) 3,000,000 shares of the Company's common stock and (ii) 10% of
the shares of the Company's common stock issued and outstanding on the last
day of each calendar quarter, provided, however, that a decrease in the number
of issued and outstanding shares of the Company's common stock from the
previous calendar quarter shall not result in a decrease in the number of
shares available for issuance under the 1997 Incentive Plan. As a result of
the Company's equity offering discussed above, as of June 30, 2000, the number
of shares of the Company's common stock that may be covered by Incentive
Awards has increased to approximately 9.68 million.
F-25
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
10. STOCKHOLDERS' EQUITY (CONTINUED)
Any shares of the Company's common stock that are issued and are
forfeited or are subject to Incentive Awards under the 1997 Incentive Plan
that expire or terminate for any reason will remain available for issuance
with respect to the granting of Incentive Awards during the term of the 1997
Incentive Plan, except as may otherwise be provided by applicable law. Shares
of the Company's common stock issued under the 1997 Incentive Plan may be
either newly issued or treasury shares, including shares of the Company's
common stock that the Company receives in connection with the exercise of an
Incentive Awards. The number and kind of securities that may be issued under
the 1997 Incentive Plan and pursuant to then outstanding Incentive Awards are
subject to adjustments to prevent enlargement or dilution of rights resulting
from stock dividends, stock splits, recapitalizations, reorganization or
similar transactions.
The maximum number of shares of the Company's common stock subject to
Incentive Awards that may be granted or that may vest, as applicable, to any
one Covered Employee (defined below) during any calendar year shall be 500,000
shares, subject to adjustment under the provisions of the 1997 Incentive Plan.
The maximum aggregate cash payout subject to Incentive Awards
(including SARs, performance units and performance shares payable in cash, or
other stock-based awards payable in cash) that may be granted to any one
Covered Employee during any calendar year is $2,500,000. For purposes of the
1997 Incentive Plan, "Covered Employees" means a named executive officer who
is one of the group covered employees as defined in Section 162(m) of the Code
and the regulation promulgated thereunder (i.e., generally the chief executive
officer and the other four most highly compensated executives for a given
year).
The 1997 Incentive Plan is administrated by the Compensation
Committee appointed by the Board of Directors (the "Committee") consisting of
not less than two directors each of whom is (i) an "outside director" under
Section 162(m) of the Code and (ii) a "non-employee director" under Rule 16b-3
of the Securities Exchange Act of 1934. In addition, subject to applicable
shareholder approval requirements, the Company may issue NSOs outside the 1997
Incentive Plan.
The exercise price of options issued under the 1997 Incentive Plan
and outside the 1997 Incentive Plan is the fair market value per share on the
date the options are granted. The exercise of NSOs results in a U.S. tax
deduction to the Company equal to the income tax effect of the difference
between the exercise price and the market price at the exercise date. The
following table summarizes the stock option activity related to the Company's
plans (shares in thousands):
<TABLE>
<CAPTION>
FISCAL YEAR ENDING JUNE 30,
-----------------------------------------------------------------------
2000 1999 1998
--------------------- ---------------------- --------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------- --------- -------- ---------- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding-beginning of fiscal year..... 6,920 $ 5.55 2,292 $ 10.33 2,086 $ 8.13
Granted............................... 3,688 8.61 5,443 4.32 415 18.65
Exercised............................. (241) 4.56 (15) 6.36 (209) 5.00
Forfeited............................. (897) 9.80 (800) 10.87 -- --
------- --------- -------- ---------- ------- ---------
Outstanding, June 30..................... 9,470 6.37 6.920 5.55 2,292 10.33
======= ======== =======
Exercisable-end of fiscal year........... 4,370 1,020 672
======= ======== =======
</TABLE>
F-26
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
10. STOCKHOLDERS' EQUITY (CONTINUED)
The foregoing stock option activity summary reflects that effective as
of September 4, 1998, the Committee authorized the cancellation and reissue of
stock options for employees that were not executive offices for the purpose of
changing the exercise price and vesting schedule of such options. A total of
473,556 stock options were cancelled, with a weighted average price of
approximately $13.09 per share, and reissued with an exercise price of $7.125
per share. The vesting of the new options is ratable over a three-year period
from the date of grant.
The following table summarizes information about the stock options
outstanding at June 30, 2000 (shares in thousands):
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------- ----------------------------
NUMBER OF NUMBER OF
SHARES WEIGHTED- SHARES
OUTSTANDING AVERAGE WEIGHTED- EXERCISABLE WEIGHTED-
AT REMAINING AVERAGE AT AVERAGE
JUNE 30, CONTRACTUAL EXERCISE JUNE 30, EXERCISE
RANGE OF EXERCISE PRICES 2000 LIFE PRICE 2000 PRICE
------------------------ ------------ ------------ ---------- ------------- -----------
<S> <C> <C> <C> <C> <C>
$ 3.00 - $ 5.00..................... 4.112 7.51 $ 3.28 2,639 $ 3.54
$ 6.00 - $ 6.8125................... 90 9.00 6.63 -- --
$ 7.125 - $ 8.375.................... 1,382 7.75 7.28 778 7.39
$ 8.50 - $ 9.50..................... 3,510 9.00 8.76 578 9.27
$ 11.125 - $ 20.50.................... 375 6.00 13.25 375 13.25
</TABLE>
The Company applies the intrinsic value method of APB 25 in accounting
for its employee stock incentive plans. Accordingly, no compensation expense has
been recognized for any stock options issued under the employee plans. Had
compensation expense for stock options granted to employees been recognized
based on the fair value at the grant dates, using the methodology prescribed by
SFAS 123, the Company's net income (loss) and earnings per share would have been
reduced to pro forma amounts indicated below:
<TABLE>
<CAPTION>
2000 1999 1998
-------------- -------------- ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Net income (loss):
As reported................................................. $ (18,959) $ (53,258) $ 24,175
Pro forma................................................... (25,684) (57,057) 22,343
Earnings per share of common stock:
As reported................................................. $ (0.23) $ (1.94) $ 1.41
Pro forma................................................... (0.31) (2.07) 1.31
Earnings per share of common stock-assuming Dilution:
As reported................................................. $ (0.23) $ (1.94) $ 1.23
Pro forma................................................... $ (0.31) (2.07) 1.14
</TABLE>
SFAS 123 does not apply to options granted prior to January 1, 1995;
therefore; the pro forma effect disclosed above may not be representative of pro
forma amounts in future years.
The total fair value of stock options granted during 2000, 1999 and
1998 was $19,541,000, $15,695,000 and $7,994,000, respectively. The fair value
of each stock option grant was estimated on the date of grant using the
Black-Sholes option-pricing model, based on the following weighted-average
assumptions.
F-27
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
10. STOCKHOLDERS' EQUITY (CONTINUED)
<TABLE>
<CAPTION>
YEAR OF GRANT
------------------------------------------------
2000 1999 1998
-------------- -------------- ------------
<S> <C> <C> <C>
Risk-free interest rate........................................ 6.40% 5.09% 5.79%
Expected life of options....................................... 5 years 5 years 5 years
Expected volatility of the Company's stock price............... 67% 98% 136%
Expected dividends............................................. none none none
</TABLE>
11. INCOME TAXES
Components of income tax expense (benefit) are as follows:
<TABLE>
<CAPTION>
FISCAL YEAR ENDED JUNE 30,
------------------------------------------------
2000 1999 1998
-------------- -------------- ------------
(THOUSANDS)
<S> <C> <C> <C>
Federal and State:
Current..................................................... $(5,588) $ -- $ 7,343
Deferred....................................................
U.S..................................................... (1,818) (25,560) 7,287
Foreign................................................. -- (115) --
-------------- -------------- ------------
$(7,406) $(25,675) $14,630
============== ============== ============
</TABLE>
The Company paid $9,024,000 for income taxes in fiscal 1998. No income
tax payments were made for fiscal 2000 or 1999.
Income tax expense (benefit) from continuing operations differs from
amounts computed by applying the statutory federal rate as follows:
<TABLE>
<CAPTION>
FISCAL YEAR ENDED JUNE 30,
------------------------------------------------
2000 1999 1998
-------------- -------------- ------------
(THOUSANDS)
<S> <C> <C> <C>
Income tax computed at statutory rate.......................... (35.0)% (35.0)% 35.0%
Amortization of goodwill disallowance.......................... 7.0 2.0 1.1
Meals and entertainment disallowance........................... 1.3 0.3 0.7
State taxes.................................................... 0.0 0.0 0.7
Change in valuation allowance and other........................ 0.2 0.2 0.2
-------------- -------------- ------------
(26.5)% (32.5)% 37.7%
============== ============== ============
</TABLE>
F-28
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
11. INCOME TAXES (CONTINUED)
Deferred tax assets (liabilities) are comprised of the following:
<TABLE>
<CAPTION>
FISCAL YEAR ENDED
JUNE 30
---------------------------------
2000 1999
------------- --------------
(THOUSANDS)
<S> <C> <C>
Net operating loss and tax credit carry forwards $ 88,491 $ 97,689
Property and equipment...................... (175,511) (163,594)
Self insurance reserves..................... 1,616 1,578
Allowance for bad debts..................... 1,129 2,612
Acquisition expenses, expensed for tax...... (626) (4,773)
Other....................................... 862 112
-------------- --------------
Net deferred tax liability.................. (84,039) (66,376)
Valuation allowance of deferred tax assets.. (15,668) (35,054)
-------------- --------------
Net deferred tax liability, net of valuation
allowance................................... $(99,707) $(101,430)
============== ==============
</TABLE>
A valuation allowance is provided when it is more likely than not that
some portion of the deferred tax assets will not be realized. Due to
uncertainties arising from a lack of earnings history and based on management's
future expectations, it does not appear more likely than not that the Company
will be able to utilize all the available carryforwards prior to their ultimate
expiration.
The Company estimates that as of June 30, 2000, the Company will have
available approximately $249,253,000 of net operating loss carryforwards (which
begin to expire in fiscal 2001). Approximately $51,272,000 of the net operating
loss carryforwards are subject to an annual limitation of approximately
$1,012,000, under Sections 382 and 383 of the Internal Revenue Code.
12. LEASING ARRANGEMENTS
The Company leases certain property and equipment under non-cancelable
operating leases that generally expire at various dates through fiscal 2002. The
term of the operating leases generally run from 24 to 60 months with varying
payment dates throughout each month.
As of June 30, 2000 the future minimum lease payments under
non-cancelable operating leases are as follows (in thousands):
<TABLE>
<CAPTION>
LEASE
FISCAL YEAR ENDING JUNE 30 PAYMENTS
-------------------------- ---------------
<S> <C>
2001................................................. $ 2,221
2002................................................. 1,555
2003................................................. 1,209
2004................................................. 1,147
2005................................................. 1,110
---------------
$ 7,242
===============
</TABLE>
Operating lease expense was approximately $6,459,698, $7,313,000 and
$8,002,000, for the fiscal years ended June 30, 2000, 1999 and 1998,
respectively.
F-29
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
13. EMPLOYEE BENEFIT PLANS
In order to retain quality personnel, the Company maintains 401(k)
plans as part of its employee benefits package. From July 1, 1998 through
December 31, 1998, the Company matched 100% of employee contributions into its
401(k) plan up to a maximum of $1,000 per participant per year, with such
contributions totaling $907,509. From January 1, 1999 to March 31, 2000, the
Company elected not to match employee contributions. Commencing April 1, 2000,
the Company matches, 100% of employee contributions into its 401(k) plan up to a
maximum of $250 per participant per year. The Company's matching contributions
for fiscal 2000 and 1999 were $77,000 and $907,509, respectively.
14. TRANSACTIONS WITH RELATED PARTIES
In connection with the negotiation of the terms of a five-year
employment agreement with Mr. Francis D. John, Chairman of the Board, President
and Chief Executive Officer of the Company, and as an inducement to Mr. John to
enter into such employment agreement, the Company entered into a separate
agreement with Mr. John, dated as of August 2, 1999, which as amended through
June 30, 2000, provides that $5 million in loans previously made by the Company
to Mr. John, together with the accrued interest payable thereon, will be
forgiven ratably during the ten year period commencing on July 1, 2001 and
ending on June 30, 2010. The agreement provides that the foregoing forgiveness
of indebtedness is predicated and conditioned upon Mr. John remaining employed
by the Company during such period. In addition, in the event that Mr. John is
terminated by the Company for "Cause" (as defined in the agreement), or in the
event that Mr. John voluntarily terminates his employment with the Company, the
agreement further provides that the entire remaining principal balance of these
loans, together with accrued interest payable thereon, will become immediately
due and payable by Mr. John. However, in the event that Mr. John's employment is
terminated for "Good Reason", or as a result of Mr. John's death or
"Disability", or as a result of a "Change in Control" (all as defined in that
agreement), the agreement stipulates that the remaining principal balance
outstanding on the loans, together with accrued interest thereon will be
forgiven.
During fiscal 1998, Metretek Technologies, a diversified provider of
products and services to the natural gas industry and a company for which W.
Phillip Marcum, one of the Directors of the Company, serves as Chairman of the
Board, President and Chief Executive Officer, sold certain assets held by its
wholly owned subsidiary, Marcum Gas Transmission, to Odessa. Metretek
Technologies sold the assets for a total consideration of $700,000. Metretek
Technologies also granted Odessa a right of first refusal to participate in
future projects developed by Marcum Gas Transmission on terms and conditions
identical to those provided in future projects developed by Marcum Gas
Transmission on terms and conditions identical to those provided to Marcum Gas
Transmission.
During fiscal 1998, the Company deposited $250,000 in money market
account as collateral to secure a bank loan made to a business entity in which
Danny R. Evatt, then the Chief Information Officer and Vice President of
Financial Operations of the Company, owns an interest. Such amount was returned
to the Company during fiscal 2000.
In fiscal 1999, an investment management firm in which David J.
Breazzano, one of the Company's directors, is a principal, purchased $25 million
principal amount of the Company's borrowings under a bridge loan agreement which
has since been repaid in full.
In fiscal 1999, the Company entered into a consulting agreement with an
investment banking firm in which Kevin P. Collins, one of the Company's
directors, is a principal, pursuant to which such firm provided financial
F-30
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
14. TRANSACTIONS WITH RELATED PARTIES (CONTINUED)
advisory services to the Company in connection with equity offering completed in
fiscal 1999 and for which such firm received a total of $167,000.
In connection with the negotiation of an employment agreement with
Thomas K. Grundman, the Company's Executive Vice President of International
Operations, Chief Financial Officer, Chief Accounting Officer and Treasurer, the
Company made a $240,000 short-term loan and a $150,000 relocation loan to assist
Mr. Grundman's relocation to the Company's executive offices. Interest on these
loans accrues at a rate of 6.125% per annum. The short-term loan has been
repaid. The relocation loan together with accrued interest will be forgiven in
three installments of $50,000 each on July 1, 2000, 2001 and 2002; PROVIDED,
HOWEVER, that if Mr. Grundman's employment is terminated during such period in a
way that (i) triggers severance obligations, all amounts owed shall be
immediately forgiven or (ii) does not trigger severance obligations, all amounts
owed shall be immediately due and payable.
15. BUSINESS SEGMENT INFORMATION
The Company operates in three business segments: well servicing,
contract drilling and oil and natural gas production.
Well Servicing: the Company's operations provide well servicing
(ongoing maintenance of existing oil and natural gas wells), workover (major
repairs or modifications necessary to optimize the level of production from
existing oil and natural gas wells) and production services (fluid hauling and
fluid storage tank rental).
Contract Drilling: The Company provides contract drilling services for
major and independent oil companies onshore the continental United States,
Argentina and Ontario, Canada.
Oil and Natural Gas Production: The Company produces crude oil and
natural gas, in the Permian Basin and Panhandle areas of West Texas. The
Company's management evaluates the performance of its operating segments based
on net income and operating profits (revenues less direct operating expenses).
Corporate expenses include general corporate expenses associated with managing
all reportable operating segments. Corporate assets consist principally of cash
and cash equivalents, deferred debt financing costs and deferred income tax
assets.
F-31
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
15. BUSINESS SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
CONTRACT OIL AND NATURAL CORPORATE/
WELL SERVICING DRILLING GAS PRODUCTION OTHER TOTAL
-------------- ------------ --------------- ------------ ---------------
<S> <C> <C> <C> <C> <C>
2000
Operating revenues............... $559,492 68,428 $9,391 $421 $637,732
Operating profit................. $159,552 10,129 5,244 421 175,346
Depreciation, depletion and
amortization.................. 62,680 6,105 1,955 232 70,972
Interest expense................. 2,300 -- -- 69,630 71,930
Net income (loss) before
extraordinary gain............ 48,062 (1,664) 2,508 (69,476) (20,570)
Identifiable assets.............. 635,304 89,574 35,682 287,072 1,047,632
Capital expenditures (excluding
acquisitions)................. 30,098 8,282 917 2,505 41,802
1999
Operating revenues............... $433,657 $50,613 $6,461 $1,086 $491,817
Operating profit................. 108,692 7,057 3,554 1,086 120,389
Depreciation, depletion and
amortization.................. 52,638 6,586 2,422 428 62,074
Interest expense................. 1,659 18 -- 65,724 67,401
Net income (loss)*............... 15,447 (4,093) 552 (65,164) (53,258)
Identifiable assets.............. 651,781 81,074 36,707 173,153 942,715
Capital expenditures (excluding
acquisitions)................. 26,776 1,063 287 3,181 31,307
1998
Operating revenues............... $356,238 $58,199 $7,030 $3,076 $424,543
Operating profit................. 108,633 15,339 4,047 3,076 131,095
Depreciation, depletion and
amortization.................. 24,334 4,176 2,043 448 31,001
Interest expense................. 624 19 (13) 20,846 21,476
Net income (loss)*............... 37,991 3,681 1,115 (18,612) 24,175
Identifiable assets.............. 352,014 109,873 37,265 154,552 653,704
Capital expenditures (excluding
acquisitions)................. 44,284 5,385 7,849 1,748 59,266
</TABLE>
-------------------
* Net income (loss) for the contract drilling segment includes a portion
of well servicing general and administrative expenses allocated on a
percentage of revenue basis.
Operating revenues and operating profit for the Company's foreign
operations, which includes Argentina and Canada, were $37.2 million and $5.3
million, respectively, for the year ended June 30, 2000. Operating revenues and
operating profit for the Company's foreign operations, which includes Argentina
and Canada, were $26.7 million and $5.2 million, respectively, for the year
ended June 30, 1999 and $32.5 million and $6.5 million, respectively, for the
year ended June 30, 1998. The Company had $66.9 million and $54.5 million of
identifiable assets as of June 30, 2000 and 1999, respectively, related to its
foreign operations.
F-32
<PAGE>
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2000, 1999 AND 1998
16. SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------------
2000 1999 1998
------ ------ ------
(IN THOUSANDS)
<S> <C> <C> <C>
Fair value of common stock issued in purchase transaction -- -- $ 13,863
Fair value of common stock issued to lender in lieu of fees -- 1 --
Fair value of common stock issued upon the conversion of
long term debt......................................... 3,600 -- 100,826
Capital lease obligations.............................. 10,758 17,120 --
</TABLE>
17. UNAUDITED SUPPLEMENTARY INFORMATION -- QUARTERLY RESULTS OF OPERATIONS
Summarized quarterly financial data for 2000 and 1999 are as follows:
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
--------------- ----------- ------------- ----------------
IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
2000
Revenues............................... $149,892 $159,389 $158,551 $169,900
Earnings (loss) from operations........ (13,191) (7,953) (5,730) (1,102)
Net earnings (loss).................... (9,451) (5,693) (4,150) (1,276)
Earnings per share..................... (0.11) (0.07) (0.05) (0.01)
Weighted average common shares and
equivalents outstanding............. 82,738 82,738 84,633 85,567
1999
Revenues............................... $115,587 $143,646 $104,923 127,661
Earnings (loss) from operations........ 3,157 (14,780) (48,153) (19,157)
Net earnings (loss).................... 1,837 (9,797) (32,051) (13,247)
Earnings (loss) per share.............. 0.10 (0.54) (1.75) (0.24)
Weighted average common shares and
equivalents outstanding............. 18,268 18,291 18,293 55,245
</TABLE>
18. VOLUMETRIC PRODUCTION PAYMENT
In March 2000, Key sold a part of its future oil and natural gas
production from Odessa Exploration Incorporated, its wholly owned subsidiary,
for gross proceeds of $20 million pursuant to an agreement under which the
purchaser is entitled to receive a share of the production from certain oil and
natural gas properties in amounts ranging from 3,500 to 10,000 barrels of oil
and 58,800 to 122,100 Mmbtu of natural gas per month over a six year period
ending February 2006. The total volume of the forward sale is approximately
486,000 barrels of oil and 6.135 million Mmbtus of natural gas.
F-33
<PAGE>
INDEPENDENT AUDITORS' REPORT
To The Board of Directors
Key Energy Services, Inc. :
We have audited the accompanying consolidated balance sheets of Key
Energy Services, Inc. and subsidiaries as of June 30, 2000 and 1999, and the
related consolidated statements of operation, stockholders' equity and
comprehensive income, and cash flows for each of the years in the three-year
period ended June 30, 2000. In connection with our audits of the consolidated
financial statements, we also have audited the financial statement schedule
listed in the Index at Item 14. These consolidated financial statements and
financial statement schedule are the responsibility of the Company's management.
Our responsibility is to express an opinion on these consolidated financial
statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Key Energy Services, Inc. and subsidiaries as of June 30, 2000 and 1999, and the
results of their operations and their cash flows for each of the years in the
three-year period ended June 30, 2000, in conformity with generally accepted
accounting principles. Also, in our opinion, the related financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material respects, the
information set forth therein.
KPMG LLP
Midland, Texas
August 31, 2000
F-34
<PAGE>
KEY ENERGY SERVICES, INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000 JUNE 30, 2000
-------------------- -----------------
(UNAUDITED)
(THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C>
ASSETS
Current assets:
Cash.......................................................... $2,635 $109,873
Accounts receivable, net of allowance for doubtful
accounts of $3,424 and $3,189, at September 30, 2000
and June 30, 2000, respectively............................... 138,460 123,203
Inventories................................................... 12,613 10,028
Prepaid income taxes.......................................... --- 5,588
Prepaid expenses and other current assets..................... 5,552 4,897
-------------------- -----------------
Total current assets.............................................. 159,260 253,589
-------------------- -----------------
Property and equipment:
Oilfield service equipment.................................... 677,366 670,392
Contract drilling equipment................................... 105,434 105,454
Motor vehicles................................................ 57,535 55,011
Oil and gas properties and other related equipment,
successful efforts method..................................... 43,977 43,855
Furniture and equipment....................................... 12,966 11,013
Buildings and land............................................ 34,787 34,712
-------------------- -----------------
932,065 920,437
Accumulated depreciation & depletion.............................. (174,858) (159,876)
-------------------- -----------------
Net property and equipment........................................ 757,207 760,561
-------------------- -----------------
Goodwill, net................................................. 196,176 198,633
Deferred costs, net........................................... 17,605 18,855
Notes receivable - related parties............................ 5,100 5,150
Other assets.................................................. 9,408 9,477
-------------------- -----------------
Total assets...................................................... $1,144,756 $1,246,265
-------------------- -----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.............................................. $33,760 $35,801
Other accrued liabilities..................................... 30,609 26,398
Accrued interest.............................................. 5,638 15,994
Current portion of long-term debt............................. 8,596 14,655
-------------------- -----------------
Total current liabilities......................................... 78,603 92,848
-------------------- -----------------
Long-term debt, less current portion.............................. 549,558 651,945
Deferred revenue.................................................. 15,899 17,031
Non-current accrued expenses...................................... 1,936 1,847
Oil and natural gas collars....................................... 1,343 -
Deferred tax liability............................................ 105,304 99,707
Commitments and contingencies..................................... - -
Stockholders' equity:
Common stock, $.10 par value; 100,000,000 shares
authorized, 97,444,859 and 97,209,504 shares issued
respectively at September 30, 2000 and
June 30, 2000, respectively................................... 9,746 9,723
Additional paid-in capital.................................... 415,086 413,962
Treasury stock, at cost; 416,666 shares at
September 30, 2000 and June 30, 2000.......................... (9,682) (9,682)
Accumulated other comprehensive income (loss)................. (620) 8
Retained earnings (deficit)................................... (22,417) (31,124)
-------------------- -----------------
Total stockholders' equity........................................ 392,113 382,887
-------------------- -----------------
Total liabilities and stockholders' equity........................ $1,144,756 1,246,265
==================== =================
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
F-35
<PAGE>
KEY ENERGY SERVICES, INC.
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
THREE MONTHS ENDED
SEPTEMBER 30,
--------------------------------
2000 1999
------------ ----------------
(THOUSANDS, EXCEPT PER SHARE
DATA)
<S> <C> <C>
REVENUES:
Well servicing......................................................... $166,565 $130,817
Contract drilling...................................................... 22,145 16,458
Oil and natural gas production......................................... 2,090 2,020
Other, net............................................................. 879 597
------------ ----------------
191,679 149,892
------------ ----------------
COSTS AND EXPENSES:
Well servicing......................................................... 111,686 99,214
Contract drilling...................................................... 17,458 14,271
Oil and natural gas production......................................... 1,323 1,000
Depreciation, depletion and amortization............................... 18,311 16,821
General and administrative............................................. 14,367 13,912
Bad debt expense....................................................... 194 477
Interest............................................................... 16,111 17,388
------------ ----------------
179,450 163,083
------------ ----------------
Income (loss) before income taxes...................................... 12,229 (13,191)
Income tax benefit (expense)........................................... (4,719) 3,740
------------ ----------------
INCOME (LOSS) BEFORE EXTRAORDINARY GAIN 7,510 (9,451)
Extraordinary gain on extinguishment of debt, less applicable income
taxes of $752........................................................ 1,197 -
------------ ----------------
NET INCOME (LOSS)........................................................... $8,707 $ (9,451)
============ ================
EARNINGS (LOSS) PER SHARE:
Basic - before extraordinary gain...................................... $0.08 $(0.11)
Extraordinary gain, net of tax......................................... 0.01 -
------------ ----------------
Basic - after extraordinary gain....................................... $0.09 $(0.11)
============ ================
Diluted - before extraordinary gain.................................... $0.08 $(0.11)
Extraordinary gain, net of tax......................................... 0.01 -
------------ ----------------
Diluted - after extraordinary gain.......................................... $0.09 $(0.11)
============ ================
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic.................................................................. 96,880 82,738
Diluted................................................................ 100,472 82,738
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
F-36
<PAGE>
KEY ENERGY SERVICES, INC.
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
THREE MONTHS ENDED
SEPTEMBER 30,
--------------------------------
2000 1999
------------ ----------------
(THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)............................................................... $8,707 $(9,451)
ADJUSTMENTS TO RECONCILE INCOME FROM OPERATIONS TO NET CASH PROVIDED
BY (USED IN) OPERATIONS:........................................................
Depreciation, depletion and amortization........................................ 18,311 16,821
Amortization of deferred debt costs and warrants................................ 1,408 1,255
Bad debt expense................................................................ 194 477
Deferred income taxes........................................................... 4,719 (3,740)
Gain on sale of assets.......................................................... 1 (6)
Extraordinary gain, net of tax.................................................. (1,197) -
Other non-cash items............................................................ 1,461 916
CHANGE IN ASSETS AND LIABILITIES, NET OF EFFECTS FROM THE ACQUISITIONS:
(Increase) decrease in accounts receivable................................... (15,451) (20,677)
(Increase) decrease in other current assets.................................. 2,348 (3,733)
Increase (decrease) in accounts payable, accrued interest and accrued expenses (8,181) 3,928
Other assets and liabilities................................................. 791 (185)
------------ ---------
Net cash provided by (used in) operating activities............................. 13,111 (14,395)
------------ ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures - Well servicing........................................... (10,929) (3,722)
Capital expenditures - Contract drilling........................................ (228) (1,100)
Capital expenditures - Oil and gas.............................................. (123) (77)
Capital expenditures - Other.................................................... (2,005) (1,233)
Proceeds from sale of fixed assets.............................................. 102 127
Notes receivable from related parties........................................... - (1,915)
------------ ---------
Net cash from (used in) investing activities.................................... (13,183) (7,920)
------------ ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of long-term debt and capital lease obligations....................... (111,328) (1,314)
Borrowings under line-of-credit................................................. 4,000 12,000
Equity offering expenses........................................................ (163) -
Proceeds from stock options exercised........................................... 333 -
Other........................................................................... (8) 522
------------ ---------
Net cash provided by (used in) financing activities............................. (107,166) 11,208
------------ ---------
Net increase (decrease) in cash and cash equivalents............................ (107,238) (11,107)
Cash and cash equivalents at beginning of period................................ 109,873 23,478
------------ ---------
Cash and cash equivalents at end of period...................................... $2,635 $12,371
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
F-37
<PAGE>
KEY ENERGY SERVICES, INC.
UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPTEMBER 30,
-----------------------------------------
2000 1999
------------------ -------------------
(THOUSANDS)
<S> <C> <C>
NET INCOME (LOSS)............................................ $8,707 $(9,451)
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Derivative transition adjustment (See Note 8)............ (778) -
Amortization of derivative transition adjustment
See Note 8).............................................. 146 -
Foreign currency translation gain (loss), net of tax..... 4 -
------------------ -------------------
COMPREHENSIVE INCOME (LOSS), NET OF TAX $8,079 $(9,451)
================== ===================
</TABLE>
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS.
F-38
<PAGE>
KEY ENERGY SERVICES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000 AND 1999
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
The consolidated financial statements of Key Energy Services, Inc.
(the "Company") and its wholly-owned subsidiaries as of September 30, 2000
and for the three month periods ended September 30, 2000 and 1999 are
unaudited. Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted in this Form 10-Q
pursuant to the rules and regulations of the Securities and Exchange
Commission. However, in the opinion of management, these interim financial
statements include all the necessary adjustments to fairly present the
results of the interim periods presented. These unaudited interim
consolidated financial statements should be read in conjunction with the
audited financial statements included in the Company's Annual Report on Form
10-K for the fiscal year ended June 30, 2000. The results of operations for
the three month period ended September 30, 2000 are not necessarily
indicative of the results of operations for the full fiscal year ending June
30, 2001.
RECLASSIFICATIONS AND ADJUSTMENTS
Certain reclassifications have been made to the consolidated
financial statements for the three month period ended September 30, 1999 to
conform to the presentation for the three month period ended September 30,
2000.
2. EARNINGS PER SHARE
The Company accounts for earnings per share based upon Statement of
Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS 128").
Under SFAS 128, basic earnings per common share are determined by dividing
net earnings applicable to common stock by the weighted average number of
common shares actually outstanding during the period. Diluted earnings per
common share is based on the increased number of shares that would be
outstanding assuming exercise of dilutive stock options and warrants and
conversion of dilutive outstanding convertible securities using the "as if
converted" method.
F-39
<PAGE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPTEMBER 30,
-------------------------------------
2000 1999
------------- ------------
<S> <C> <C>
BASIC EPS COMPUTATION:
NUMERATOR
Income (loss) before extraordinary gain........................ $ 7,510 $ (9,451)
Extraordinary gain, net of tax................................. 1,197 -
------------- ------------
Net income (loss).............................................. $ 8,707 $ (9,451)
============= ============
DENOMINATOR
Weighted average common shares outstanding..................... 96,880 82,738
------------- ------------
BASIC EPS:
Before extraordinary gain...................................... $ 0.08 $ (0.11)
Extraordinary gain, net of tax................................. 0.01 -
------------- ------------
After extraordinary gain....................................... $ 0.09 $ (0.11)
------------- ------------
DILUTED EPS COMPUTATION:
NUMERATOR
Income (loss) before extraordinary gain........................ $ 7,510 $ (9,451)
Effect of dilutive convertible securities, tax effected........ 5 -
Extraordinary gain, net of tax................................. 1,197 -
------------- ------------
Net income (loss).............................................. $ 8,712 $ (9,451)
------------- ------------
DENOMINATOR
Weighted average common shares outstanding..................... 96,880 82,738
Warrants....................................................... 75 -
Stock options.................................................. 3,437 -
7% Convertible Debentures...................................... 70 -
5% Convertible Notes........................................... 10 -
------------- ------------
100,472 82,738
------------- ------------
DILUTED EPS:
Before extraordinary gain...................................... $ 0.08 $ (0.11)
Extraordinary gain, net of tax................................. 0.01 -
------------- ------------
After extraordinary gain....................................... $ 0.09 $ (0.11)
============= ============
</TABLE>
The earnings per share calculation for the three month period ended
September 30, 1999 excludes the Company's convertible debt, outstanding
warrants and stock options, because the effects of such instruments on
earnings per share would be anti-dilutive.
3. ACQUISITIONS
There were no acquisitions by the Company during the three months
ended September 30, 2000 or the three months ended September 30, 1999.
F-40
<PAGE>
4. STOCKHOLDERS' EQUITY
EQUITY OFFERING
On June 30, 2000, the Company closed the public offering of
11,000,000 shares of common stock at $9.625 per share, or approximately $106
million (the "Equity Offering"). Net proceeds from the Equity Offering of
approximately $101 million were used to repay a portion of the Company's term
loan borrowings and revolving line of credit under its senior credit facility
and to retire other long-term debt.
5. COMMITMENTS AND CONTINGENCIES
Various suits and claims arising in the ordinary course of business
are pending against the Company. Management does not believe that the
disposition of any of these items will result in a material adverse impact to
the consolidated financial position, results of operations or cash flows of
the Company.
6. INDUSTRY SEGMENT INFORMATION
The Company operates in three business segments: well servicing,
contract drilling and oil and natural gas production.
WELL SERVICING: The Company's operations provide well servicing
(ongoing maintenance of existing oil and natural gas wells), workover (major
repairs or modifications necessary to optimize the level of production from
existing oil and natural gas wells) and production services (fluid hauling
and fluid storage tank rental).
CONTRACT DRILLING: The Company provides contract drilling services
for major and independent oil companies onshore the continental United
States, Argentina and Ontario, Canada.
OIL AND NATURAL GAS PRODUCTION: The Company produces crude oil and
natural gas, in the Permian Basin and Panhandle areas of West Texas.
<TABLE>
<CAPTION>
OIL AND
WELL CONTRACT NATURAL GAS CORPORATE
SERVICING DRILLING PRODUCTION /OTHER TOTAL
--------------- ------------- ---------------- ------------- ---------
<S> <C> <C> <C> <C> <C>
THREE MONTHS ENDED SEPTEMBER 30, 2000
Operating revenues........................ $166,565 $22,145 $2,090 $879 $191,679
Operating profit ......................... 54,879 4,687 767 879 61,212
Depreciation, depletion and amortization.. 15,689 1,806 570 246 18,311
Interest expense.......................... 657 - - 15,454 16,111
Net income (loss) before extraordinary
gain*................................... 21,778 654 (13) (14,909) 7,510
Identifiable assets....................... 634,123 87,850 35,234 191,373 948,580
Capital expenditures ..................... 10,929 228 123 2,005 13,285
Three Months Ended September 30, 1999
Operating revenues........................ $130,817 $16,458 $2,020 $597 $149,892
Operating profit.......................... 31,603 2,187 1,020 597 35,407
Depreciation, depletion and amortization.. 14,282 1,782 570 187 16,821
Interest expense.......................... 374 - - 17,014 17,388
Net income (loss) *....................... 8,149 (722) 302 (17,180) (9,451)
Identifiable assets....................... 648,420 76,833 36,196 187,888 949,337
Capital expenditures...................... 3,722 1,100 77 1,233 6,132
</TABLE>
--------------------
* Net income (loss) for the contract drilling segment includes a portion of well
servicing general and administrative expenses allocated on a percentage of
revenue basis.
Operating revenues for the Company's foreign operations for the
three months ended September 30, 2000 and 1999 were $11.6 million and $8.0
million, respectively. Operating profits for the Company's foreign operations
for the three months ended September 30, 2000 and 1999 were $2.5 million and
$1.5 million, respectively. The
F-41
<PAGE>
Company had $63.7 million and $60.5 million of identifiable assets as of
September 30, 2000 and 1999, respectively, related to foreign operations.
7. VOLUMETRIC PRODUCTION PAYMENT
In March 2000, Key sold a part of its future oil and natural gas
production from Odessa Exploration Incorporated, its wholly owned subsidiary,
for gross proceeds of $20 million pursuant to an agreement under which the
purchaser is entitled to receive a share of the production from certain oil
and natural gas properties in amounts ranging from 3,500 to 10,000 barrels of
oil and 58,800 to 122,100 Mmbtu of natural gas per month over a six year
period ending February 2006. The total volume of the forward sale is
approximately 486,000 barrels of oil and 6.135 million Mmbtu of natural gas.
8. DERIVATIVE INSTRUMENTS
As of July 1, 2000, the Company adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133) as amended by
SFAS No. 137 and No. 138. SFAS No. 133 establishes accounting and reporting
standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and hedging activities. It requires
the recognition of all derivative instruments as assets or liabilities in the
Company's balance sheet and measurement of those instruments at fair value.
The accounting treatment of changes in fair value is dependent upon whether
or not a derivative instrument is designated as a hedge and if so, the type
of hedge. For derivatives designated as cash flow hedges, changes in fair
value are recognized in other comprehensive income until the hedged item is
recognized in earnings.
The Company periodically hedges a portion of its oil and natural gas
production through collar agreements. The purpose of the hedges is to provide
a measure of stability in the volatile environment of oil and natural gas
prices and to manage exposure to commodity price risk under existing sales
commitments. The Company's risk management objective is to lock in a range of
pricing for expected production volumes. This allows the Company to forecast
future earnings within a predictable range. The Company meets this objective
by entering into a collar arrangement which allows for an acceptable cap and
floor price.
The Company does not enter into derivative instruments for any
purpose other than for economic hedging. The Company does not speculate using
derivative instruments. The Company has identified the following derivative
instruments:
Freestanding derivatives - On March 30, 2000 the Company entered
into a collar arrangement for a 22 month time period whereby the Company will
pay if the specified price is above the cap index and the counterparty will
pay if the price should fall below the floor index. The combination of the
floor and cap results in a determinable cash flow for those production
streams over that time period.
Prior to the adoption of SFAS No. 133, these collars were accounted
for as cash flow type hedges. Accordingly, the transition adjustment resulted
in recording a $778,000 liability for the fair value of the collars to
accumulated other comprehensive income, of which $146,000 was recognized in
earnings during the quarter. It is estimated that $470,000 of this transition
adjustment will be recognized in earnings over the next twelve months. While
this arrangement was intended to be an economic hedge, as of July 1, 2000 the
Company had not documented the oil and natural gas collars as cash flow
hedges and therefore has included a change of $565,000 for the increase in
the fair value of the liability as of September 30, 2000 in other income and
expense. As of October 1, 2000, the Company has documented these collars as
cash flow hedges.
Embedded derivatives - The Company is party to a production payment
that meets the definition of an embedded derivative under SFAS No. 133. As of
July 1, 2000, the Company has determined and documented that the production
payment is excluded from the scope of SFAS No. 133 under the normal
purchases/sales exclusion.
F-42
