<PAGE>
Filed Pursuant to Rule
424(B)(5)
SEC File No. 333-83551
PROSPECTUS SUPPLEMENT
(To Prospectus dated August 3, 1999)
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7,000,000 Shares
UNIT CORPORATION
[UNIT CORPORATION LOGO APPEARS HERE]
Common Stock
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Unit Corporation is offering 7,000,000 shares of common stock. The common
stock is listed on the New York Stock Exchange under the symbol "UNT". The
last reported sale price of the common stock on the New York Stock Exchange on
September 23, 1999, was $7.625 per share.
Unit is engaged in the land contract drilling of natural gas and oil wells and
the exploration, development, acquisition and production of natural gas and
oil properties.
<TABLE>
<CAPTION>
Per Share Total
<S> <C> <C>
Public offering price................................. $7.625 $53,375,000
Underwriting discounts and commissions................ $0.42 $2,940,000
Proceeds, before expenses, to Unit.................... $7.205 $50,435,000
</TABLE>
See "Risk Factors" on pages S-8 to S-13 for factors that should be considered
before investing in the shares of Unit.
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Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or passed upon the
accuracy or adequacy of this prospectus supplement or the accompanying
prospectus. Any representation to the contrary is a criminal offense.
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The underwriters may, under certain circumstances, purchase up to 1,050,000
additional shares from Unit at the public offering price, less underwriting
discounts and commissions. Delivery and payment for the shares will be on
September 29, 1999.
Prudential Securities
CIBC World Markets
Raymond James & Associates, Inc.
September 23, 1999
<PAGE>
[Included immediately following the cover page of the prospectus supplement are
two maps. The first map is entitled "Drilling Rig Distribution" and it
identifies the current geographic location of our drilling rig fleet and
the drilling rigs to be acquired. The second map is entitled "Proved Reserve
Concentration" and it identifies the geographic location of our primary natural
gas and oil reserves.]
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Prospectus Supplement Page
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<S> <C>
Summary............................... S-1
Risk Factors.......................... S-8
Use of Proceeds....................... S-14
Price Range of Common Stock and
Dividend Policy...................... S-14
Capitalization........................ S-15
Selected Consolidated Financial Data.. S-16
Management's Discussion and Analysis
of Financial Condition and Results of
Operations........................... S-18
Pending Acquisition................... S-23
Business.............................. S-24
Management............................ S-34
Shares Eligible for Future Sale....... S-36
Underwriting.......................... S-38
Legal Opinions........................ S-40
Experts............................... S-40
Independent Accountants............... S-40
Glossary of Certain Oil and Gas
Terms................................ S-41
Index to Financial Statements......... F-1
</TABLE>
<TABLE>
<CAPTION>
Prospectus Page
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<S> <C>
About This Prospectus................................................. 2
Where You Can Find More Information about the Company................. 2
The Company........................................................... 3
Forward-Looking Statements............................................ 3
Ratio of Earnings to Fixed Charges.................................... 4
Use of Proceeds....................................................... 4
Description of Debt Securities........................................ 4
Description of Capital Stock.......................................... 16
Description of Warrants............................................... 19
Plan of Distribution.................................................. 21
Legal Matters......................................................... 23
Independent Accountants............................................... 23
</TABLE>
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You should rely only on the information contained or incorporated by
reference in this prospectus supplement and the accompanying prospectus. We
have not authorized anyone to provide you with different information. We are
not making an offer of these securities in any jurisdiction where the offer or
sale is not permitted. You should not assume that the information contained in
this prospectus supplement and the accompanying prospectus is accurate as of
any date other than the date on the front cover of this prospectus supplement.
<PAGE>
SUMMARY
This summary highlights information contained elsewhere in this prospectus
supplement. This summary may not contain all of the information that investors
should consider before investing in the common stock of Unit. You should read
this entire prospectus supplement and the accompanying prospectus carefully. We
have included technical terms important to an understanding of our business
under "Glossary of Certain Oil and Gas Terms."
The Company
We are engaged in the land contract drilling of natural gas and oil wells
and the exploration, development, acquisition and production of natural gas and
oil properties. The majority of our contract drilling and exploration and
production activities are oriented toward drilling for and producing natural
gas. We estimate that over 90% of our wells drilled for third parties over the
past three years were natural gas prospects and, as of December 31, 1998, 89%
of our reserves were natural gas. We were founded in 1963 as a contract
drilling company and our current contract drilling operations are focused
primarily in the natural gas producing provinces of the Oklahoma and Texas
areas of the Anadarko and Arkoma Basins. Our primary exploration and production
operations are also conducted in the Anadarko and Arkoma Basins. In 1994, we
commenced contract drilling operations in the Texas Gulf Coast area and in 1995
we commenced exploration and production operations in that region.
We generated record revenues and production volumes during 1998 despite the
21% decline in average natural gas prices and the 33% decline in average oil
prices we received as compared with 1997. We also enjoyed a rig utilization
rate of approximately 67% during this same period, which compares favorably to
the industry average. For 1998, revenues were $93.3 million and EBITDA was
$30.7 million compared to $91.9 million and $38.0 million for 1997. For the six
months ended June 30, 1999, revenues were $39.2 million and EBITDA was $10.0
million compared to $50.3 million and $16.1 million for the same period during
1998.
On August 12, 1999, we signed a definitive agreement with Parker Drilling
Company, a Tulsa, Oklahoma based contract drilling company, to purchase 13 high
performance drilling rigs and certain related equipment and yards for $40.0
million in cash and one million shares of Unit common stock. All 13 of the rigs
are diesel electric SCR rigs, which offer superior control and efficiency,
particularly in deep, directional or horizontal applications. Seven of the rigs
are currently under contract with various operators in the Rocky Mountains.
Three of the remaining rigs are located in South Louisiana and three are
located in South Texas.
Land Drilling Operations
Our wholly-owned subsidiary, Unit Drilling, operates our entire land
drilling business. We are a leading provider of contract land drilling services
to independent oil and gas companies in the United States.
As of September 1, 1999, we had a well-balanced rig fleet consisting of 34
land drilling rigs, capable of medium and deep drilling applications. The fleet
includes 22 rigs capable of drilling to depths of 15,000 feet or greater, seven
of which are capable of drilling to depths of 20,000 feet or greater. We have
30 rigs located in the gas rich Mid Continent region, giving us the second
largest drilling fleet operating in what is our primary market. With the
completion of the Parker Acquisition, we will have the second largest fleet of
rigs capable of drilling below 15,000 feet operating in the Rocky Mountain
market, also a prolific natural gas producing region. Eleven of the 13 Parker
rigs have a capability of drilling to depths of 20,000 feet or more, with the
remaining two having depth ratings of 16,000 feet.
We believe our operating and technical staff is highly regarded within the
industry. Our 57 senior drilling supervisors, including rig managers, have an
average of over 10 years of industry experience, with approximately six of
those years having been served with us.
S-1
<PAGE>
We believe that our above average utilization rate during the industry
downturn in 1998 was a result of our superior equipment and operations
personnel as well as the location of our rig fleet. During 1998, we experienced
a rig utilization rate of 67%. As of August 31, 1999, we had a utilization rate
of 59% versus 53% at March 31, 1999, and 44% at June 30, 1999.
During 1998, we drilled 198 wells with total footage drilled of 2.2 million
feet as compared to 1.7 million feet in 1997. Our revenues and EBITDA from land
drilling operations have increased from $17 million and $1.2 million,
respectively, for the year ended December 31, 1994, to $53.5 million and $7.9
million for the year ended December 31, 1998. For the six months ended June 30,
1999, our revenues were $22.4 million and EBITDA was $1.2 million compared to
$30.4 million and $4.8 million for the same period in 1998.
Exploration and Production Operations
Our wholly-owned subsidiary, Unit Petroleum, conducts our exploration and
production activities. We have developed an expertise in our core areas,
primarily the Anadarko and Arkoma Basins, having drilled a total of 523 gross
wells resulting in a 78% success rate during the past ten years of activity.
Our drilling and acquisition activities in the Mid Continent and other areas of
operation have enabled us to exceed our goal of adding new reserves at a
minimum rate of 150% of production in each of the past 15 years. Our ability to
replace reserves, primarily through internally generated prospects, has allowed
us to achieve an average annual reserve replacement of 231% and finding and
development costs of $0.73 per Mcfe over the past 10 years.
As a source of future reserve and production growth, we currently have an
inventory of over 250 drilling prospects, 78 of which are included in our
proved reserve base as proved undeveloped and 80% of which are located in our
core Mid Continent region where we have historically had a high degree of
success. Ninety-eight percent of these prospects were generated internally, and
we plan to drill approximately 50 prospects during 1999 and, depending on oil
and gas prices, approximately 80 to 100 in 2000.
As of December 31, 1998, we had estimated net proved reserves of 180.8 Bcfe
with a PV-10 value of approximately $137 million. If evaluated using prices
realized at June 30, 1999, our PV-10 value would have been $158 million.
Approximately 74% of our proved reserves were classified as proved developed
reserves and 89% were natural gas at year end 1998. We currently operate
properties constituting 70% of our proved developed PV-10 value. At August 30,
1999, our production was approximately 50 MMcfe per day.
Our revenues and EBITDA from exploration and production operations increased
from $26.0 million and $14.9 million, respectively, for the year ended December
31, 1994 to $39.7 million and $22.8 million, respectively, for the year ended
December 31, 1998. For the six months ended June 30, 1999, our revenues and
EBITDA were $16.4 million and $8.4 million, respectively, compared to $19.8
million and $11.1 million for the same period in 1998.
Business Strategy
Our corporate strategy is to maximize our equity value through profitable
growth and utilization of our contract drilling equipment and profitable growth
of our natural gas and oil reserves and production.
Focus on Natural Gas. We focus both our contract drilling and exploration
and production operations on gaining critical mass in major natural gas
producing regions, which has resulted in our strong contract drilling and
exploration and production presence in the Mid Continent region, and to a
lesser extent in South Texas. As of June 30, 1999, 100% of our operating rigs
were drilling for natural gas, and 89% and 94% of our proved reserves and
prospect inventory were natural gas properties.
S-2
<PAGE>
Conservative Fiscal Policy. To maintain our financial flexibility and
minimize our financial risk, we attempt to fund the majority of our capital
expenditures with our cash flow from operations. In addition, our general
corporate policy is to seek to maintain a conservative debt to cash flow from
operations ratio and a conservative debt to total capitalization ratio, which
was 40% at June 30, 1999. We believe our policy minimizes our financial risks
during the periods of depressed natural gas and oil prices and provides us
financial flexibility to pursue strategic acquisitions as they may arise.
Experienced Personnel. Our contract drilling and exploration and production
personnel have significant experience and technical insight in managing
contract drilling and exploration and production operations in the Anadarko and
Arkoma Basins, our core operating areas.
Key Elements of Our Land Contract Drilling Strategy
High Quality Equipment and Premium Service. We have positioned ourselves as
a leader in the land contract drilling industry by providing high quality rigs
and premium service to our market. The proposed acquisition of the 13 SCR rigs,
11 of which have drilling capabilities of 20,000 feet or more, is
representative of our commitment to provide superior equipment to our customers
in order to meet the demands in our markets. With this acquisition, we will
have 18 SCR rigs, representing 38% of our rig fleet.
Selectively Expand Rig Fleet. The land drilling rig market is highly
cyclical and we have developed considerable experience in dealing with these
cycles in our history of over 36 years in this business. At the present time,
we believe there is substantial positive leverage in the land contract drilling
industry due to recent consolidations within the industry and the demand for
natural gas. As a consequence, through the Parker Acquisition we are adding to
our rig fleet at what we believe is an opportune time.
Retain Key Personnel During Down Cycles. We believe our experienced
personnel make significant contributions to our success, and we work to retain
them during the up and down cycles in our industry. High personnel retention
helps us to maintain the operational quality, consistency and continuity of our
operations. As of August 31, 1999, 43% of our senior drilling supervisors had
been employed with us for over 10 years.
Key Elements of Our Exploration and Production Strategy
Low-Risk Exploration and Exploitation. We focus on low cost reserve growth
primarily through the exploration and exploitation of regions and properties in
our core operating areas with a known history of production. This strategy has
enabled us to achieve consistent reserve growth, as evidenced by our five year
annual reserve replacement of 219% and finding and development costs over that
period of $.81 per Mcfe. Over that period, we have drilled 339 wells with an
81% success rate.
Internal Prospect Generation. Our exploration team has consistently been
able to add to an attractive prospect inventory which has historically served
as our primary source of reserve growth. Over the last five years, we have
maintained an average inventory of over 180 prospects, with over 98% of the 339
wells drilled having been internally generated.
S-3
<PAGE>
The Offering
<TABLE>
<C> <S>
Shares offered by Unit.............................. 7,000,000 shares (1)
Total shares outstanding after this offering........ 33,810,675 shares (1)(2)
Use of proceeds..................................... To fund the cash portion
of the purchase price of
the rig acquisition
discussed under "Pending
Acquisition," to repay
indebtedness under our
existing revolving
credit facility and for
general corporate
purposes.
New York Stock Exchange symbol...................... UNT
</TABLE>
(1) Does not include up to 1,050,000 shares of common stock that the
underwriters may purchase if they exercise their over-allotment option.
(2) Includes 1,000,000 shares issuable to Parker Drilling Company upon
consummation of the Parker Acquisition and excludes 735,100 shares of
common stock issuable upon exercise of outstanding stock options.
Risk Factors
You should consider the risk factors before investing in our common stock
and the impact from various events that could adversely affect our business.
See "Risk Factors."
S-4
<PAGE>
Summary Consolidated Financial Data
You should read the following summary consolidated financial data along with
the section entitled "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and our consolidated financial statements
and the related notes included elsewhere in this prospectus supplement.
<TABLE>
<CAPTION>
Six Months
Ended
Year Ended December 31, June 30,
---------------------------- ---------------------------
1996 1997 1998 1998 1999
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(unaudited) (unaudited)
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Revenues:
Contract drilling...... $ 28,819 $ 46,199 $ 53,528 $ 30,383 $ 22,370
Oil and natural gas.... 43,013 45,581 39,703 19,759 16,436
Other.................. 238 84 106 161 370
-------- -------- -------- -------- --------
Total Revenues........ 72,070 91,864 93,337 50,303 39,176
-------- -------- -------- -------- --------
Expenses:
Contract drilling:
Operating costs........ 24,259 36,419 43,729 24,540 20,252
Depreciation........... 2,944 4,216 5,766 2,874 2,811
Oil and natural gas:
Operating costs........ 13,409 13,201 14,328 7,276 6,595
Depreciation, depletion
and amortization...... 10,807 12,625 16,069 7,531 7,943
General and
administrative........ 4,122 4,621 4,891 2,507 2,474
Interest............... 3,162 2,921 4,815 2,359 2,432
-------- -------- -------- -------- --------
Total expenses........ 58,703 74,003 89,598 47,087 42,507
-------- -------- -------- -------- --------
Income (loss) before
income taxes........... 13,367 17,861 3,739 3,216 (3,331)
-------- -------- -------- -------- --------
Total income taxes
(benefit)............ 5,034 6,737 1,493 1,256 (1,183)
-------- -------- -------- -------- --------
Net income (loss)....... $ 8,333 $ 11,124 $ 2,246 $ 1,960 $ (2,148)
======== ======== ======== ======== ========
Net income (loss) per
common share:
Basic.................. $ .37 $ .46 $ .09 $ .08 $ (.08)
======== ======== ======== ======== ========
Diluted................ $ .37 $ .45 $ .09 $ .08 $ (.08)
======== ======== ======== ======== ========
Statement of Cash Flow
Data:
Cash from (used by):
Operating activities... $ 20,664 $ 34,350 $ 33,513 $ 21,612 $ 11,571
Investing activities... (32,887) (43,026) (52,783) (34,222) (11,499)
Financing activities... 12,236 8,587 19,258 12,746 (63)
Other Financial Data:
EBITDA: (1)
Contract drilling...... $ 3,738 $ 8,691 $ 7,852 $ 4,839 $ 1,248
Oil and natural gas.... 26,632 29,206 22,782 11,144 8,392
Capital expenditures.... 34,111 45,115 53,654 34,567 12,144
Cash flow (2)........... 27,471 35,342 26,364 13,947 7,659
<CAPTION>
As of June 30, 1999
---------------------------
Historical As Adjusted (3)
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(in thousands)
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Working capital.................................... $ 136 $ 136
Property, plant and equipment, net................. 195,931 244,131
Total assets....................................... 220,425 268,625
Long-term debt..................................... 72,900 62,700
Shareholders' equity............................... 109,988 168,388
</TABLE>
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(1) EBITDA represents earnings before interest, income taxes, depreciation,
depletion and amortization. EBITDA is included as a supplemental disclosure
because it is a financial measure commonly used in our industry. EBITDA,
however, should not be considered in isolation or as a substitute for net
income, cash flow from operating activities or other income or cash flow
data prepared in accordance with generally accepted accounting principles
or as a measure of our profitability or liquidity.
(2) Cash flow represents cash flow from operating activities prior to changes
in operating assets and liabilities.
(3) Adjusted to give effect to the completion of the Parker Acquisition and the
sale of 7,000,000 shares of common stock in this offering and the
application of the net proceeds as described in "Use of Proceeds."
S-5
<PAGE>
Summary Operating Data
The following table sets forth summary data with respect to our contract
drilling operations and our natural gas and oil operations for the periods
indicated.
<TABLE>
<CAPTION>
Six Months
Ended
Year Ended December 31, June 30,
-------------------------------------- -------------
1994 1995 1996 1997 1998 1998 1999
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<S> <C> <C> <C> <C> <C> <C> <C>
Contract Drilling
Operations Data:
Number of operational
rigs at period end...... 25 22 24 34 (1) 34 34 34
Average number of rigs
owned during period..... 25 25 22.7 25.1 34 34 34
Average number of rigs
utilized (2)............ 9.5 10.9 14.7 20.0 22.9 25.3 19.5
Utilization rate (2)..... 38% 44% 65% 80% 67% 74% 57%
Number of wells drilled.. 95 111 130 167 198 114 88
Average revenue per day
(3)..................... $4,894 $5,081 $5,351 $6,309 $6,394 $6,641 $6,352
Total footage drilled
(feet in thousands)..... 1,027 1,196 1,468 1,736 2,203 1,267 905
Exploration and Production
Operations Data:
Production:
Natural gas (MMcf)....... 9,659 12,059 13,025 13,816 16,465 7,854 7,667
Oil (MBbls).............. 406 577 579 493 443 229 183
Average sales price:
Natural gas (per Mcf).... $ 1.85 $ 1.61 $ 2.20 $ 2.42 $ 1.90 $ 1.94 $ 1.64
Oil (per Bbl)............ 15.13 16.65 20.40 19.19 12.81 13.78 13.62
Average production costs
(per Mcfe) (4).......... .58 .64 .68 .64 .61 .63 .59
Finding and development
costs (per Mcfe)........ .64 .49 .69 1.18 1.23 1.31 .98
Annual reserve
replacement ratio (5)... 325% 242% 216% 158% 156% -- --
</TABLE>
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(1) Includes ten rigs acquired in the fourth quarter of 1997.
(2) Utilization rates are based on a 365-day year and are calculated by
dividing the average number of rigs utilized by the average number of rigs
owned during the period, including stacked rigs. A rig is considered
utilized when it is operating or being moved, assembled or dismantled under
contract.
(3) Represents total revenues from contract drilling operations divided by the
number of days rigs were being utilized for the period.
(4) Production costs include lease operating expenses and production and ad
valorem taxes.
(5) The annual reserve replacement ratio is calculated on a Mcfe basis by
dividing the estimated reserves added during a year from exploitation,
development and exploration activities, acquisitions of proved reserves and
revisions of previous estimates, excluding property sales, by the natural
gas and oil volumes produced during that year.
S-6
<PAGE>
Summary Reserve and Acreage Data
The following table sets forth summary information with respect to our
proved oil and gas reserves for the periods indicated, as estimated by us and
of which approximately 99% have been reviewed by Ryder Scott Company, L.P.,
petroleum consultants. For additional information relating to our oil and gas
reserves, see Note 14 "Oil and Natural Gas Information (Unaudited)" to our
consolidated financial statements included elsewhere in this prospectus
supplement.
<TABLE>
<CAPTION>
As of December 31,
--------------------------------------------
1994 1995 1996 1997 1998
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Estimated Proved Reserves:
Natural Gas (MMcf)............... 93,360 108,728 129,161 145,384 161,318
Oil (MBbls)...................... 4,308 5,428 5,204 4,131 3,245
MMcfe............................ 119,205 141,297 160,386 170,167 180,791
PV-10 (in thousands) (1)......... $ 85,018 $121,720 $263,744 $167,187 $137,073
Standardized measure of
discounted future net cash flows
(in thousands) (1).............. $ 78,268 $103,138 $200,652 $138,827 $124,368
Percent proved developed......... 85% 87% 84% 80% 74%
Acreage:
Gross acres:
Developed....................... 371,601 580,304 494,753 471,864 608,116
Undeveloped..................... 21,514 24,810 29,245 56,814 75,721
Net acres:
Developed....................... 101,516 118,187 116,302 119,902 131,416
Undeveloped..................... 11,540 12,866 19,124 45,086 58,134
</TABLE>
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(1) Weighted average natural gas prices used in the estimates of net proved
reserves and the calculation of the standardized measure of discounted
future net cash flows and PV-10 were $1.70, $1.95, $3.63 $2.33 and $2.08
per Mcf at December 31, 1994, 1995, 1996, 1997 and 1998, respectively. The
weighted average oil prices used in the estimate of net proved reserves and
the calculation of the standardized measure of discounted future net cash
flows and PV-10 were $16.00, $18.08, $24.57, $17.39 and $11.10 per Bbl at
December 31, 1994, 1995, 1996, 1997 and 1998.
S-7
<PAGE>
RISK FACTORS
You should carefully consider the following risk factors, in addition to the
other information set forth in this prospectus supplement and the accompanying
prospectus, before purchasing shares of our common stock. Each of these risk
factors could adversely affect our business, operating results and financial
condition, as well as adversely affect the value of an investment in our common
stock. This investment involves a high degree of risk.
Oil and gas prices are volatile, and low prices have negatively affected
our financial results and could do so in the future.
Our revenues, operating results, cash flow and future rate of growth depend
substantially upon prevailing prices for oil and gas. Historically, oil and gas
prices and markets have been volatile, and they are likely to continue to be
volatile in the future. Oil and gas prices declined substantially in 1998 and,
despite recent improvement, could decline again. These declines had a
significant negative impact on our financial results for 1998 and the first
half of 1999. We incurred a net loss for the quarterly periods ending March 31
and June 30, 1999. Depressed prices in the future would have a negative impact
on our future financial results. Because our reserves are predominantly gas,
changes in gas prices may have a particularly large impact on our financial
results.
Prices for oil and gas are subject to wide fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors that are beyond our control.
These factors include:
. political conditions in oil producing regions, including the Middle East;
. the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;
. the price of foreign imports;
. actions of governmental authorities;
. the domestic and foreign supply of oil and gas;
. the level of consumer demand;
. weather conditions;
. domestic and foreign government regulations;
. the price, availability and acceptance of alternative fuels; and
. overall economic conditions.
These factors and the volatile nature of the energy markets make it impossible
to predict with any certainty the future prices of oil and gas.
Our contract drilling operations depend on levels of activity in the oil
and gas exploration and production industry.
Our contract drilling operations depend on the level of activity in oil and
gas exploration and production in our operating markets. Both short-term and
long-term trends in oil and gas prices affect the level of that activity.
Because oil and gas prices are volatile, the level of exploration and
production activity can also be volatile. Decreased oil and gas prices during
1998 and early 1999 adversely affected our contract drilling activity by
lowering the utilization of our rigs and reducing the day rates we charge for
our rigs. During this period, a number of oil and gas companies announced
reductions in capital spending for exploration and development, and others have
completed or announced consolidating transactions that have or are likely to
S-8
<PAGE>
continue to result in additional reductions. Although oil and gas prices have
recently improved, we expect that in the near term our customers will continue
a cautious approach to exploration and development spending until price gains
prove to be sustainable. Any decrease from current oil and gas prices would
depress the level of exploration and production activity. This, in turn, would
likely result in a decline in the demand for our drilling services and would
have an adverse effect on our contract drilling revenues, cash flows and
profitability. As a result, the future demand for our drilling services is
uncertain.
We may not successfully complete or integrate the planned Parker
Acquisition.
If the Parker Acquisition is closed, we will increase our drilling rig fleet
by approximately 38 percent and also significantly increase the number of
employees involved in our contract drilling operations. In order to benefit
from this transaction, we will have to integrate these assets and personnel in
an effective manner, which could require substantial attention of management.
This transaction represents a greater commitment to our contract drilling
segment, which is a highly competitive and sometimes volatile business. If we
are unable to effectively integrate these assets and personnel or if the
contract drilling business suffers a significant decline, our business and
prospects generally could be adversely affected to a material extent.
The closing of the Parker Acquisition is subject to several conditions, and
we cannot assure you that this acquisition will be completed. However, we
currently expect that the conditions to this acquisition will be met and that
it will be completed shortly following the completion of this offering. If it
is not completed by October 31, 1999, Unit or Parker can terminate the purchase
agreement.
The industries in which we operate are highly competitive, and many of our
competitors have greater resources than we do. In particular, the contract
drilling industry has intense price competition and excess rig supply.
The drilling industry in which we operate is very competitive. Most drilling
contracts are awarded on the basis of competitive bids, which also results in
intense price competition. In the markets in which we operate, the number of
rigs available for use exceeds the demand for rigs, which increases this price
competition. Many of our competitors in the contract drilling industry have
greater financial and human resources than we do. These resources may enable
them to better withstand periods of low rig utilization, to compete more
effectively on the basis of price and technology, to build new rigs or acquire
existing rigs and to provide rigs more quickly than we do in periods of high
rig utilization.
The oil and gas industry is also highly competitive. We compete in the areas
of property acquisitions and oil and gas exploration, development, production
and marketing with major oil companies, other independent oil and natural gas
concerns and individual producers and operators. In addition, we must compete
with major and independent oil and natural gas concerns in recruiting and
retaining qualified employees. Many of our competitors in the oil and gas
industry have substantially greater financial and other resources than we do.
Shortages of experienced personnel for our contract drilling operations
could limit our ability to meet the demand for our services.
In recent years, the number of oil and gas drilling rigs in operation has
declined substantially. As a result, a large number of experienced personnel in
this industry have moved to other industries or fields. If the demand for
contract drilling services should increase significantly, we and most other
contract drilling contractors may have difficulties in employing enough
qualified and experienced personnel to be able to meet that demand completely.
Our operations have significant capital requirements, and our substantial
indebtedness could have important consequences to you.
We have experienced and expect to continue to experience substantial working
capital needs due to our growth in drilling operations and our active
exploration, development and exploitation programs. We currently
S-9
<PAGE>
have, and will continue to have, a large amount of indebtedness. At June 30,
1999, we had a long-term debt to total capitalization ratio of 40%. At August
31, 1999, our long-term debt outstanding was $70.8 million. As of August 31,
1999, the amount available for borrowing under our credit facility was $85
million, of which $67.8 was outstanding. Although we expect that a portion of
the net proceeds from this offering will be used to repay indebtedness,
additional financing may be required in the future to fund our operations.
Our level of indebtedness, the cash flow needed to satisfy our indebtedness
and the covenants governing our indebtedness could
. limit funds available for financing capital expenditures, our drilling
program or other activities or cause us to curtail these activities;
. limit our flexibility in planning for, or reacting to changes in, our
business;
. place us at a competitive disadvantage to some of our competitors that
are less leveraged than us;
. make us more vulnerable during periods of low oil and gas prices or in
the event of a downturn in our business; and
. prevent us from obtaining additional financing on acceptable terms or
limit amounts available under our existing or any future credit
facilities.
Our ability to meet our debt service obligations will depend on our future
performance. We cannot assure you that we will be able to meet our debt service
requirements. In addition, lower oil and gas prices could result in future
reductions in the amount available for borrowing under our credit facility,
reducing our liquidity and even triggering mandatory loan repayments.
If the requirements of our indebtedness are not satisfied, a default would
be deemed to occur and our lenders would be entitled to accelerate the payment
of the outstanding indebtedness. If this occurs, we cannot assure you that we
would have sufficient funds available or could obtain the financing required to
meet our obligations.
Our future performance depends upon our ability to find or acquire
additional oil and gas reserves that are economically recoverable.
In general, production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. Unless we successfully replace the reserves that we produce,
our reserves will decline, resulting eventually in a decrease in oil and gas
production and lower revenues and cash flow from operations. Historically, we
have succeeded in increasing reserves after taking production into account
through exploitation, development and exploration. We have conducted such
activities on our existing oil and gas properties as well as on newly acquired
properties. We may not be able to continue to replace reserves from such
activities at acceptable costs. Low prices of oil and gas may further limit the
kinds of reserves that can economically be developed. Lower prices also
decrease our cash flow and may cause us to decrease capital expenditures.
We are continually identifying and evaluating opportunities to acquire oil
and gas properties, including acquisitions that would be significantly larger
than those consummated to date by us. We cannot assure you that we will
successfully consummate any acquisition, that we will be able to acquire
producing oil and gas properties that contain economically recoverable reserves
or that any acquisition will be profitably integrated into our operations.
Our natural gas and oil operations involve a high degree of business and
financial risk which could adversely affect us.
Exploitation, development and exploration involve numerous risks that may
result in dry holes, the failure to produce oil and gas in commercial
quantities and the inability to fully produce discovered reserves. The cost
S-10
<PAGE>
of drilling, completing and operating wells is substantial and uncertain.
Numerous factors beyond our control may cause the curtailment, delay or
cancellation of drilling operations, including:
. unexpected drilling conditions;
. pressure or irregularities in formations;
. equipment failures or accidents;
. adverse weather conditions;
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs or delivery
crews and the delivery of equipment.
Exploratory drilling is a speculative activity. Although we may disclose our
overall drilling success rate, those rates may decline. Although we may discuss
drilling prospects that we have identified or budgeted for, we may ultimately
not lease or drill these prospects within the expected time frame, or at all.
Lack of drilling success will have an adverse effect on our future results of
operations and financial condition.
Our hedging arrangements might limit the benefit of increases in natural
gas prices.
In order to reduce our exposure to short-term fluctuations in the price of
oil and gas, we sometimes enter into hedging arrangements. Our hedging
arrangements apply to only a portion of our production and provide only partial
price protection against declines in oil and gas prices. These hedging
arrangements may expose us to risk of financial loss and limit the benefit to
us of increases in prices.
Estimates of our reserves are uncertain and may prove to be inaccurate, and
oil and gas price declines may lead to an impairment of our oil and gas
assets.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and their values, including many factors beyond the control of the
producer. The reserve data included or incorporated by reference in this
prospectus supplement or the accompanying prospectus represent only estimates.
Reservoir engineering is a subjective and inexact process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner. Estimates of economically recoverable oil and gas reserves depend on a
number of variable factors, including historical production from the area
compared with production from other producing areas, and assumptions
concerning:
. the effects of regulations by governmental agencies;
. future oil and gas prices;
. future operating costs;
. severance and excise taxes;
. development costs; and
. workover and remedial costs.
Some or all of these assumptions may in fact vary considerably from actual
results. For these reasons, estimates of the economically recoverable
quantities of oil and gas attributable to any particular group of properties,
classifications of those reserves based on risk of recovery, and estimates of
the future net cash flows from reserves prepared by different engineers or by
the same engineers but at different times may vary substantially. Accordingly,
reserve estimates may be subject to downward or upward adjustment. Actual
production, revenues and expenditures with respect to our reserves will likely
vary from estimates, and those variances may be material.
The information regarding discounted future net cash flows included in or
incorporated by reference in this prospectus supplement or the accompanying
prospectus should not be considered as the current market value of
S-11
<PAGE>
the estimated oil and gas reserves attributable to our properties. As required
by the SEC, the estimated discounted future net cash flows from proved reserves
are based on prices and costs as of the date of the estimate, while actual
future prices and costs may be materially higher or lower. Actual future net
cash flows also will be affected by the following factors:
. the amount and timing of actual production;
. supply and demand for oil and gas;
. increases or decreases in consumption; and
. changes in governmental regulations or taxation.
In addition, the 10% discount factor, which is required by the SEC to be
used in calculating discounted future net cash flows for reporting purposes, is
not necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with our operations or the oil
and gas industry in general.
We periodically review the carrying value of our oil and gas properties
under the full cost accounting rules of the SEC. Under these rules, capitalized
costs of proved oil and gas properties may not exceed the present value of
estimated future net revenues from proved reserves, discounted at 10%.
Application of the ceiling test generally requires pricing future revenue at
the unescalated prices in effect as of the end of each fiscal quarter and
requires a write-down for accounting purposes if the ceiling is exceeded, even
if prices were depressed for only a short period of time. We may be required to
write down the carrying value of our oil and gas properties when oil and gas
prices are depressed or unusually volatile. If a write-down is required, it
would result in a charge to earnings, but would not impact cash flow from
operating activities. Once incurred, a write-down of oil and gas properties is
not reversible at a later date.
Our operations present inherent risks of loss that, if not insured or
indemnified against, could adversely affect our results of operations.
Our drilling operations are subject to many hazards inherent in the drilling
industry, including blowouts, cratering, explosions, fires, loss of well
control, loss of hole, damaged or lost drilling equipment and damage or loss
from inclement weather. Our exploration and production operations are subject
to these and similar risks Any of these events could result in personal injury
or death, damage to or destruction of equipment and facilities, suspension of
operations, environmental damage and damage to the property of others.
Generally, drilling contracts provide for the division of responsibilities
between a drilling company and its customer, and we seek to obtain
indemnification from our drilling customers by contract for some of these
risks. To the extent that we are unable to transfer these risks to drilling
customers by contract or indemnification agreements, we seek protection through
insurance which our management considers to be adequate. However, we cannot
assure you that our insurance or indemnification agreements will adequately
protect us against liability from all of the consequences of the hazards
described above. The occurrence of an event not fully insured or indemnified
against, or the failure of a customer to meet its indemnification obligations,
could result in substantial losses. In addition, we cannot assure you that
insurance will be available to cover any or all of these risks. Even if
available, the insurance might not be adequate to cover all of our losses, or
we might decide against obtaining that insurance because of high premiums or
other costs.
In addition, we are not the operator of some of our wells. As a result, our
operating risks for those wells and our ability to influence the operations for
those wells are less subject to our control. Operators of those wells may act
in ways that are not in our best interests.
Governmental and environmental regulations could adversely affect our
business.
Our business is subject to federal, state and local laws and regulations on
taxation, the exploration for and development, production and marketing of oil
and gas and safety matters. Many laws and regulations require
S-12
<PAGE>
drilling permits and govern the spacing of wells, rates of production,
prevention of waste, unitization and pooling of properties and other matters.
These laws and regulations have increased the costs of planning, designing,
drilling, installing, operating and abandoning our oil and gas wells and other
facilities. In addition, these laws and regulations, and any others that are
passed by the jurisdictions where we have production, could limit the total
number of wells drilled or the allowable production from successful wells,
which could limit our revenues.
Our operations are also subject to complex environmental laws and
regulations adopted by the various jurisdictions where we operate. We could
incur liability to governments or third parties for any unlawful discharge of
oil, gas or other pollutants into the air, soil or water, including
responsibility for remedial costs. We could potentially discharge these
materials into the environment in any of the following ways:
. from a well or drilling equipment at a drill site;
. from gathering systems, pipelines, transportation facilities and storage
tanks;
. damage to oil and natural gas wells resulting from accidents during
normal operations; and
. blowouts, cratering and explosions.
Because the requirements imposed by laws and regulations are frequently
changed, we cannot assure you that laws and regulations enacted in the future,
including changes to existing laws and regulations, will not adversely affect
our business. In addition, because we acquire interests in properties that have
been operated in the past by others, we may be liable for environmental damage
caused by the former operators.
Year 2000 risks could cause a business disruption that adversely affects
our operations and financial condition.
Failure by us, our customers, our suppliers or other third parties to become
Year 2000 compliant on a timely basis could cause us to have a material
business disruption. We have not yet received adequate assurances of Year 2000
compliance from many third parties that are important to our operations. If we
experience a business disruption because of Year 2000 failures, our operations
and financial performance could be adversely affected. See "Managements'
Discussion and Analysis of Financial Condition and Results of Operations" for a
more complete discussion of our Year 2000 risks.
Our shareholders Rights Plan and provisions of Delaware law and our charter
and by-laws could discourage change in control transactions and prevent
shareholders from receiving a premium on their investment.
Our by-laws provide for a classified board of directors with staggered terms
and our charter authorizes the board of directors to set the terms of preferred
stock. In addition, our charter and Delaware law contain provisions that impose
restrictions on business combinations with interested parties. We have also
adopted a shareholders' rights plan. Because of our shareholders' rights plan
and these provisions of our charter and by- laws and Delaware law, persons
considering unsolicited tender offers or other unilateral takeover proposals
may be more likely to negotiate with our board of directors rather than pursue
non-negotiated takeover attempts. As a result, these provisions may make it
more difficult for our shareholders to benefit from transactions that are
opposed by an incumbent board of directors.
S-13
<PAGE>
USE OF PROCEEDS
The net proceeds to Unit from this offering are approximately $50.2 million
($57.8 million if the underwriters' over-allotment option is exercised in
full), after deducting underwriting discounts and commissions and estimated
expenses of $175,000. We intend to use $40.0 million of net proceeds to pay the
cash portion of the purchase price payable for the Parker Acquisition. Pending
that application, we may repay a portion of our indebtedness outstanding under
our revolving credit facility. See "Pending Acquisition."
To the extent the net proceeds are used to repay a portion of the
outstanding indebtedness under our revolving credit facility, the cash amount
due at the closing of the Parker Acquisition will then be funded by advances
under our revolving credit facility. We cannot assure you, however, that the
Parker Acquisition will be completed. If the Parker Acquisition is not
completed, we intend to use the net proceeds to repay a portion of our
indebtedness outstanding under our revolving credit facility. At August 31,
1999, the outstanding balance under our revolving credit facility totaled $67.8
million, with an average interest rate of approximately 6.6%. Our revolving
credit facility converts into a three-year term loan on May 1, 2002. Our debt
was incurred primarily to fund our capital expenditure program and working
capital requirements.
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock is traded on the New York Stock Exchange under the symbol
"UNT." The following table sets forth the high and low sale prices per share of
our common stock, as reported in the New York Stock Exchange composite
transactions, for the periods indicated:
<TABLE>
<CAPTION>
High Low
------ -----
<S> <C> <C>
1997
First Quarter.............................................. $12.25 $7.50
Second Quarter............................................. 11.87 7.87
Third Quarter.............................................. 15.37 9.62
Fourth Quarter............................................. 15.81 8.44
1998
First Quarter.............................................. $ 9.81 $6.44
Second Quarter............................................. 9.87 5.50
Third Quarter.............................................. 6.31 3.75
Fourth Quarter............................................. 6.94 3.62
1999
First Quarter.............................................. $ 7.00 $3.50
Second Quarter............................................. 8.25 4.87
Third Quarter (through September 23, 1999)................. 9.00 7.37
</TABLE>
On September 23, 1999, the last reported sales price of the common stock on
the New York Stock Exchange was $7.625 per share. Most of our shareholders
maintain their shares in "street name" accounts and are not, individually,
shareholders of record. As of August 30, 1999, the common stock was held by
2,450 holders of record.
We have not declared or paid any cash dividends on shares of our common
stock since organization and currently intend to continue our policy of
retaining earnings from our operations. We are prohibited, by certain loan
agreement provisions, from declaring and paying dividends (other than stock
dividends) during any fiscal year in excess of 25% of our consolidated net
income of the preceding fiscal year, and only if working capital provided from
operations during the prior year is equal to or greater than 175% of current
maturities of long-term debt at the end of the prior year.
S-14
<PAGE>
CAPITALIZATION
The following table sets forth at June 30, 1999:
. our historical capitalization; and
. our as adjusted capitalization after giving effect to
(i) the completion of the Parker Acquisition,
(ii) the completion of this offering, and
(iii) the application of the net proceeds from this offering as set
forth in "Use of Proceeds."
This table should be read along with our consolidated financial statements
and related notes included elsewhere in this prospectus supplement.
<TABLE>
<CAPTION>
June 30, 1999
----------------------
Historical As Adjusted
---------- -----------
(in thousands)
<S> <C> <C>
Current portion of long-term debt...................... $ 1,000 $ 1,000
======== ========
Long-term debt:
Bank revolving credit facility........................ $ 69,900 $ 59,700
Other long-term debt.................................. 3,000 3,000
-------- --------
Total long-term debt................................. 72,900 62,700
-------- --------
Shareholders' equity:
Common stock, $.20 par value, 40,000,000 shares
authorized, 25,740,160
shares issued and outstanding; 33,740,160 shares
issued and
outstanding, as adjusted (1) ........................ 5,148 6,748(2)
Capital in excess of par value........................ 82,867 139,667(2)
Retained earnings..................................... 21,973 21,973
-------- --------
Total shareholders' equity........................... 109,988 168,388
-------- --------
Total capitalization................................. $182,888 $231,088
======== ========
</TABLE>
- --------
(1) Does not include 844,000 and 735,100 shares of common stock reserved for
issuance upon exercise of outstanding options as of June 30, 1999 and the
date of this prospectus supplement, respectively.
(2) Reflects the issuance of (i) 7,000,000 shares of common stock by us at a
public offering price of $7.625 per share, resulting in net proceeds of
$50.2 million, of which $1.4 million (equal to the par value of the shares
issued) is reflected in common stock and $48.8 million is reflected in
capital in excess of par value and (ii) 1,000,000 shares of common stock in
connection with the Parker Acquisition valued as of the date of the asset
purchase agreement, of which $200,000 (equal to the par value of the shares
issued) is reflected in common stock and $8.0 million is reflected in
capital in excess of par value.
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<PAGE>
SELECTED CONSOLIDATED FINANCIAL DATA
The selected consolidated financial data presented below is derived from our
consolidated financial statements. The selected financial information presented
below for the six month periods ended June 30, 1998 and 1999 is derived from
our unaudited consolidated financial statements and includes, in the opinion of
management, all normal and recurring adjustments necessary to present fairly
the data for such periods. This information should be read along with the
consolidated financial statements and the related notes and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included elsewhere in this prospectus supplement. The selected consolidated
financial data provided below is not necessarily indicative of the future
results of operations or financial performance of Unit.
<TABLE>
<CAPTION>
Six Months
Year Ended December 31, Ended June 30,
------------------------------------------------ ----------------------
1994 1995 1996 1997 1998 1998 1999
-------- -------- -------- -------- -------- ----------- ----------
(unaudited) (unaudited)
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Revenues:
Contract drilling...... $ 16,952 $ 20,211 $ 28,819 $ 46,199 $ 53,528 $ 30,383 $ 22,370
Oil and natural gas.... 26,001 31,187 43,013 45,581 39,703 19,759 16,436
Other.................. 942 1,676 238 84 106 161 370
-------- -------- -------- -------- -------- -------- --------
Total revenues....... 43,895 53,074 72,070 91,864 93,337 50,303 39,176
-------- -------- -------- -------- -------- -------- --------
Expenses:
Contract drilling:
Operating costs........ 14,909 18,041 24,259 36,419 43,729 24,540 20,252
Depreciation........... 2,030 2,596 2,944 4,216 5,766 2,874 2,811
Oil and natural gas:
Operating costs........ 8,799 12,003 13,409 13,201 14,328 7,276 6,595
Depreciation,
depletion
and amortization...... 8,281 10,223 10,807 12,625 16,069 7,531 7,943
General and
administrative........ 3,574 3,893 4,122 4,621 4,891 2,507 2,474
Interest............... 1,654 3,235 3,162 2,921 4,815 2,359 2,432
-------- -------- -------- -------- -------- -------- --------
Total expenses....... 39,247 49,991 58,703 74,003 89,598 47,087 42,507
-------- -------- -------- -------- -------- -------- --------
Income (loss) before
income taxes........... 4,648 3,083 13,367 17,861 3,739 3,216 (3,331)
-------- -------- -------- -------- -------- -------- --------
Total income taxes
(benefit)........... 20 (668) 5,034 6,737 1,493 1,256 (1,183)
-------- -------- -------- -------- -------- -------- --------
Income (loss) from
continuing operations.. 4,628 3,751 8,333 11,124 2,246 1,960 (2,148)
-------- -------- -------- -------- -------- -------- --------
Discontinued operations:
Income (loss) from
operations of
discontinued
operations (net of
income tax benefit of
$69 in 1995).......... 166 (112) -- -- -- -- --
Gain from sale of
discontinued
operations (net of
income taxes of $221
in 1995).............. -- 360 -- -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Income from
discontinued
operations.......... 166 248 -- -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)....... $ 4,794 $ 3,999 $ 8,333 $ 11,124 $ 2,246 $ 1,960 $ (2,148)
======== ======== ======== ======== ======== ======== ========
Net income (loss) per
common share:
Continuing operations:
Basic.................. $ .22 $ .18 $ .37 $ .46 $ .09 $ .08 $ (.08)
======== ======== ======== ======== ======== ======== ========
Diluted................ $ .22 $ .18 $ .37 $ .45 $ .09 $ .08 $ (.08)
======== ======== ======== ======== ======== ======== ========
Net income (loss):
Basic.................. $ .23 $ .19 $ .37 $ .46 $ .09 $ .08 $ (.08)
======== ======== ======== ======== ======== ======== ========
Diluted................ $ .23 $ .19 $ .37 $ .45 $ .09 $ .08 $ (.08)
======== ======== ======== ======== ======== ======== ========
Statement of Cash Flows
Data:
Cash from (used by):
Operating activities... $ 13,093 $ 10,975 $ 20,644 $ 34,350 $ 33,513 $ 21,612 $ 11,571
Investing activities... (26,007) (15,652) (32,887) (43,026) (52,783) (34,222) (11,499)
Financing activities... 11,840 2,570 12,236 8,587 19,258 12,746 (63)
Other Financial Data:
EBITDA (1).............. $ 17,062 $ 19,438 $ 30,608 $ 37,981 $ 30,740 $ 16,144 $ 10,010
Capital expenditures.... 28,227 20,634 34,111 45,115 53,654 34,567 12,144
Cash flow (2)........... 14,694 15,752 27,471 35,342 26,364 13,947 7,659
</TABLE>
S-16
<PAGE>
<TABLE>
<CAPTION>
As of December 31, As of June 30,
-------------------------------------------- ----------------------
1994 1995 1996 1997 1998 1998 1999
-------- -------- -------- -------- -------- ----------- ----------
(unaudited) (unaudited)
(in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance Sheet Data:
Working capital........ $ 1,911 $ 2,919 $ 7,446 $ 6,319 $ 1,553 $ 65 $ 136
Property, plant and
equipment, net........ 90,505 96,019 117,706 169,974 197,160 191,009 195,931
Total assets........... 103,933 110,922 137,993 202,497 223,064 219,681 220,425
Long-term debt......... 37,300 41,100 40,600 54,100 72,900 66,400 72,900
Shareholders' equity... 52,607 56,606 78,210 108,865 111,290 111,104 109,988
</TABLE>
- --------
(1) EBITDA represents earnings before interest, income taxes, depreciation,
depletion and amortization. EBITDA is included as a supplemental disclosure
because it is a financial measure commonly used in our industry. EBITDA,
however, should not be considered in isolation or as a substitute for net
income, cash flow from operating activities or other income or cash flow
data prepared in accordance with generally accepted accounting principles
or as a measure of our profitability or liquidity.
(2) Cash flow represents cash flow from operating activities prior to changes
in operating assets and liabilities.
S-17
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financial Condition
Unit's bank loan agreement provides for a total loan facility of $100
million, with a current available borrowing value of $85 million. The available
borrowing value under the revolving credit facility is subject to a semi-annual
redetermination, each April 1 and October 1, calculated as the sum of a
percentage of the discounted future value of our oil and natural gas reserves,
as determined by the banks, plus the greater of (i) 50 percent of the appraised
value of our contract drilling rigs or (ii) two times the previous 12 months
cash flow from the contract drilling rigs, limited in either case to $20
million. The revolving credit facility terminates on May 1, 2002 with a three
year term loan thereafter. At June 30, 1999, borrowings under our credit
agreement totaled $69.9 million. The average bank debt interest rate in the
second quarter of 1999 was 6.4 percent compared to the average interest rate of
7.0 percent in the second quarter of 1998. A facility fee of .375 of 1 percent
is charged for any unused portion of the available borrowing value.
Unit's shareholders' equity at June 30, 1999, was $110.0 million resulting
in a ratio of long-term debt-to-total capitalization of 40 percent. Our primary
source of liquidity and capital resources in the near and long-term will
consist of cash flow from operating activities, available borrowings under our
credit agreement and proceeds from this offering. At June 30, 1999 and December
31, 1998, Unit had working capital of $136,000 and $1.6 million, respectively.
Net cash provided by operating activities for the first six months of 1999 was
$11.6 million as compared to $21.6 million for the first six months of 1998.
During the first six months of 1998 net cash provided by operations contained a
$5.2 million dollar reduction in accounts receivable while the 1999 net cash
provided by operations was negatively effected by lower net income due to lower
natural gas prices, lower contract drilling utilization and dayrates.
During the first six months of 1999, we had capital additions of $9.9
million of which approximately 74 percent was for oil and natural gas
exploration and development drilling while the remainder was used in our
contract drilling operations. Due to lower natural gas prices, we slowed our
development drilling during the first six months of 1999. Depending, in part,
on commodity pricing, we anticipate we will spend approximately $20 million on
our oil and natural gas capital expenditure program in 1999 and approximately
$5.0 million on our current contract drilling fleet. These expenditures are
anticipated to be within the constraints of available cash to be provided by
our operating activities and our credit agreement. Since a large portion of our
capital expenditures are discretionary and directed toward increasing reserves
and future growth, current operations are not dependent on our ability to
obtain funds outside of the credit agreement.
On August 12, 1999, we entered into a definitive agreement with Parker
Drilling Company, a Tulsa Oklahoma based contract drilling company, to purchase
13 drilling rigs and certain related equipment and yards for $40.0 million in
cash and 1,000,000 shares of common stock. The 13 rigs are electric "SCR" deep
drilling rigs, with power ratings from 1,000 to 4,000 horsepower and drilling
depth capabilities from 16,000 to in excess of 30,000 feet. Seven of the rigs
are currently under contract with various operators and located in the Rocky
Mountains. Three of the remaining rigs are located in South Louisiana and three
are located in South Texas. The acquisition will open new market areas for our
contract drilling segment and increase our rig fleet to 47 rigs. Closing of
this purchase is subject to several conditions, including securing any required
governmental approvals and financing for the cash portion of the purchase
price.
On November 20, 1997, we acquired Hickman Drilling Company pursuant to an
Agreement and Plan of Merger entered into by and between us, Hickman Drilling
Company and all of the holders of the outstanding capital stock of Hickman
Drilling Company. As part of this acquisition, the former shareholders of
Hickman hold, as of June 30, 1999, promissory notes in the aggregate principal
amount of $4,000,000. These notes are payable in equal annual installments on
January 2, 2000 through January 2, 2003. The notes bear interest at the Chase
Prime Rate which at December 31, 1998 and June 30, 1999, was 7.75 percent.
S-18
<PAGE>
Due to a settlement agreement which terminated at December 31, 1997, we have
a liability of $1.3 million at June 30, 1999, representing proceeds received
from a natural gas purchaser as prepayment for natural gas. The $1.3 million is
payable in equal annual payments from June 1, 2000 to June 1, 2002.
The average spot market natural gas prices we received during the first six
months of 1999 was $1.69 per Mcf, $.25 per Mcf less than during the same period
in 1998. The average oil price we received during the first six months of 1999
was $13.62 per barrel, $.16 per barrel less than the average received in 1998.
Prices for natural gas are influenced by weather conditions and supply
imbalances, particularly in the domestic market, and by world wide oil price
levels. Domestic oil price levels continue to be primarily influenced by world
market developments. Since natural gas comprises approximately 89 percent of
our reserves, large drops in spot market natural gas prices have a significant
adverse effect on the value of our reserves and further price declines could
also cause us to reduce the carrying value of its oil and natural gas
properties. Such decreases, if sustained, would also adversely effect our
future cash flow due to reduced oil and natural gas revenues and, if continued
over an extended period, would adversely impact the demand for our contract
drilling rigs. Declines in natural gas and oil prices could also adversely
effect the semi-annual determination of the loan value under our credit
agreement since this determination is calculated on the value of our oil and
natural gas reserves and our drilling rigs. Any such reduction would reduce the
amount available to us under our credit agreement which, in turn, would impact
our ability to carry out our capital projects.
Our ability to utilize our drilling rigs at any given time is dependent on a
number of factors, including but not limited to, competition from other
contractors, the price of both oil and natural gas, the availability of labor
and our ability to supply the type of equipment required. We expect these
factors will continue to influence our rig utilization throughout 1999 and into
2000.
In the third quarter of 1994, the board of directors authorized us to
purchase up to 1,000,000 shares of our outstanding common stock on the open
market. Since that time, 160,100 shares have been repurchased at prices ranging
from $2.50 to $9.69 per share. In the first quarter of 1999 and 1998, 25,000
and 19,863 of the purchased shares, respectively, were used as our matching
contribution to its 401(k) Employee Thrift Plan. At December 31, 1998, 25,000
treasury shares were held by us and at June 30, 1999, no such shares were held.
Year 2000 Statement
We have initiated a comprehensive assessment of our information technology
("IT") and non-information technology ("non-IT") systems to try and ensure that
these systems will be Year 2000 compliant. The Year 2000 problem exists because
many existing computer programs use only the last two digits to define the
year. Therefore, these computer programs do not recognize years that begin with
a "20" and assume that all years begin with a "19". If not corrected many
computer applications could fail or create erroneous results which could cause
disruption of operations not only for us but also for our customers and
suppliers, so we have also initiated an assessment of our customers' and
suppliers' efforts to become Year 2000 compliant.
Evaluation of our IT systems began in house during 1997. Our IT systems
consist mainly of office computers, related computer programs and management
financial information software. We believe substantially all of our hardware is
Year 2000 compliant and during the first week in April 1999, we converted our
related computer programs, software and data base on the AS400 computer system
making it Year 2000 compliant. We spent approximately $130,000 bringing our
systems compliant by the end of the second quarter of 1999.
Our non-IT systems consist of office equipment and other systems associated
with our oil and natural gas properties and our drilling rigs. We began
assessing these non-IT systems and the associated cost during the fourth
quarter of 1998. Currently, we anticipate that the cost and replacement of any
such equipment due to the ongoing assessment will be minimal and that the
assessment will be completed prior to December 31, 1999.
S-19
<PAGE>
During the third quarter of 1998, we issued questionnaires to our key
suppliers and customers to assess their preparedness for Year 2000. We received
responses from 41 percent of these entities. During the first quarter of 1999,
we issued second request questionnaires to those key suppliers and customers
who did not respond to the questionnaires issued during the third quarter of
1998. At August 30, 1999, we had received responses from 68 percent of the
entities targeted in the two questionnaires. Approximately 90 percent of the
responses we have received indicated the entities were aware of and are in the
process of resolving their Year 2000 issues.
As noted, we currently believe that nearly all of our internal systems and
equipment are Year 2000 compliant at the end of the second quarter of 1999 and
the associated costs have not had a material adverse effect on our results of
operations and financial condition. However, the failure to properly assess or
timely remediate a material Year 2000 problem could result in a disruption in
our normal business activities or operations. Such failures, depending on the
extent and nature, could materially and adversely effect our operations and
financial condition. As a result, we will continue to evaluate our Year 2000
exposure, both internally and externally. Since a portion of the overall
evaluation of our Year 2000 readiness will, of necessity, be based on the
information to be supplied by, and the readiness of, our key suppliers and
customers, we cannot currently determine the impact, if any, such third parties
will have on our Year 2000 exposure. As noted, we intend to evaluate this
information as, if and when it is made available to us. The failure by key
third parties to correct their Year 2000 problems could adversely affect Unit.
We intend to develop contingency plans as appropriate to minimize disruption in
our normal business activities or operations if it is determined there is a
significant Year 2000 risk. These plans might include the use of alternative
service providers or product suppliers. Currently, we do not have any
contingency plans in place based on our Year 2000 assessments completed to
date.
Our assessment of our Year 2000 issues involve many assumptions. Our
assumptions might prove to be inaccurate, and actual results could differ
significantly from the assumptions. In addition, third party representations or
certifications as to Year 2000 compliance might prove to be inaccurate. We have
not retained any experts or advisors to independently verify our Year 2000
compliance or the Year 2000 compliance of our key customers and suppliers.
Results of Operations
Six Months 1999 versus Six Months 1998
We had a net loss for the first six months of 1999 of $2,148,000 as compared
to net income of $1,960,000 for the first six months of 1998. Declines in
natural gas prices, oil and natural gas production, contract drilling dayrates
and rig utilization all contributed to the net loss and were partially offset
by a $315,000 gain from insurance proceeds received as a result of tornado
damage as discussed below.
Oil and natural gas revenues decreased 17 percent in the first six months of
1999 as compared to the first six months of 1998. Oil and natural gas
production decreased 20 and two percent, respectively, between the comparative
periods, while average oil and natural gas prices received by us decreased one
and 15 percent, respectively. Natural gas production was lower due to reduced
natural gas reserve replacement as we reduced our development drilling program
in response to declining natural gas prices while oil production has declined
due to our focus on replacing natural gas reserves as opposed to oil reserves
over the past several years.
Oil and natural gas operating margins (revenues less operating costs)
declined from 63 percent in the first six months of 1998 to 60 percent in the
first six months of 1999 due to lower natural gas and oil prices and production
in 1999. Total operating costs decreased nine percent. Depreciation, depletion
and amortization ("DD&A") increased five percent between the comparative
periods due to an increase in our average DD&A rate per Mcfe from $.81 in the
first six months of 1998 to $.89 for the first six months of 1999.
Contract drilling revenues decreased 26 percent for the comparative six
month periods as rig utilization decreased from an average of 25.3 rigs
operating in the first six months of 1998 to 19.5 rigs in the first six
S-20
<PAGE>
months of 1999 and dayrates on daywork contracts dropped 10 percent. Contract
drilling operating margins (revenue less operating costs) dropped from 19
percent to nine percent between the comparative periods.
General and administrative expense decreased one percent during the
comparative six month periods. Interest expense increased three percent due to
a 22 percent increase in the average long-term debt outstanding in the first
six months of 1999 compared to the first six months of 1998. The average
interest rate incurred by us decreased from 7.5 percent to 6.5 percent.
On May 3, 1999, our contract drilling offices in Moore, Oklahoma were struck
by a tornado destroying two of our buildings and damaging various vehicles and
drilling equipment. In May 1999, we received $500,000 of insurance proceeds
related to the destruction of the buildings and, as a result, in the second
quarter of 1999 recognized a gain of $315,000 recorded as part of other
revenues. Other claims relating to the contents of the two buildings and
damaged equipment and damage removal covered under other insurance policies are
in the process of being filed. At this time, the proceeds we may receive are
not determinable under the additional claims, but we do not expect any
financial loss to be incurred from these claims.
1998 versus 1997
Net income for 1998 was $2,246,000, compared with $11,124,000 in 1997.
Increases in the number of rigs utilized and increased natural gas production
were more than offset by substantial decreases in the average price received
for both oil and natural gas and to a lesser extent from reduced oil production
and contract drilling rates.
Oil and natural gas revenues decreased 13 percent in 1998 due to a 21
percent and 33 percent decrease in average natural gas and oil prices received,
respectively along with a 10 percent reduction in oil production. These
decreases were partially offset by a 19 percent increase in natural gas
production. Oil production declined from 1997 levels due to our emphasis over
the past three years in drilling development wells which focused on replacing
and increasing natural gas reserves. Average natural gas spot market prices
received by us decreased 20 percent. The natural gas previously subject to a
settlement agreement, which ended at December 31, 1997 and contained provisions
for prices higher than current spot market prices, is now being sold at spot
market prices consistent with the rest of the natural gas sold by us. The
impact of higher prices received under the settlement agreement increased pre-
tax income by approximately $540,000 in 1997.
In 1998, revenues from contract drilling operations increased by 16 percent
as average rig utilization increased from 20.0 rigs operating in 1997 to 22.9
rigs operating in 1998. Daywork revenues per rig per day decreased three
percent between the comparative years. During the first three quarters of 1998,
our monthly rig utilization consistently remained at or above 23 rigs with
daywork revenue per rig per day declining by eight percent from the January
1998 rate. In the fourth quarter utilization dropped 27 percent from the
previous quarter and dayrates decreased another six percent. Total daywork
revenues represented 64 percent of total drilling revenues in 1998 and 72
percent in 1997. Turnkey and footage contracts typically provide for higher
revenues since a greater portion of the expense of drilling the well is born by
the drilling contractor.
Operating margins (revenues less operating costs) for our natural gas and
oil operations were 64 percent in 1998 compared to 71 percent in 1997.
Decreased operating margins resulted primarily from the decrease in average
natural gas and oil prices received by us between the two years. Total
operating costs were nine percent higher in 1998 compared to 1997 as we
continue to add producing properties.
Operating margins for contract drilling decreased from 21 percent in 1997 to
18 percent in 1998. Margins in 1998 were lower primarily due to decreases in
both daily rig rates and rig utilization in the fourth quarter of 1998. Total
operating costs for contract drilling were up 20 percent in 1998 versus 1997
due to increased drilling rig utilization and costs associated with the
November 1997 Hickman Acquisition.
Contract drilling depreciation increased 37 percent in response to increased
rig utilization and additional drilling capital expenditures throughout 1997
and 1998. Depreciation, depletion and amortization ("DD&A") of
S-21
<PAGE>
oil and natural gas properties increased 27 percent as we increased our
equivalent barrels of production by 14 percent and our average DD&A rate per
Mcfe increased 11 percent to $.83 in 1998.
General and administrative expenses increased six percent as certain
employee costs increased. Interest expense increased 65 percent as our average
outstanding debt increased 65 percent during 1998. The average interest rate
decreased from 7.28 percent in 1997 to 7.11 percent in 1998.
1997 versus 1996
Net income for 1997 was $11,124,000, compared with $8,333,000 in 1996.
Increases in rig utilization, contract drilling day rates, average natural gas
prices received and natural gas production from new wells drilled during the
year all combined to produce the increase in 1997 net income.
Oil and natural gas revenues increased six percent in 1997 due to a six
percent and 10 percent increase in natural gas production and average natural
gas prices received, respectively. These increases were partially offset by a
15 percent decline in oil production and a six percent decrease in average oil
prices received by us in 1997. Oil production declined from 1996 levels due to
our emphasis over the past two years in drilling development wells which
focused on replacing and increasing natural gas reserves. Average natural gas
spot market prices received by us increased 11 percent while volumes produced
from certain wells included under a settlement agreement, which ended at
December 31, 1997 and contained provisions for prices higher than current spot
market prices, dropped seven percent. The impact of higher prices received
under the settlement agreement increased pre-tax income by approximately
$540,000 and $650,000 in 1997 and 1996, respectively.
In 1997, revenues from contract drilling operations increased by 60 percent
as average rig utilization increased from 14.7 rigs operating in 1996 to 20.0
rigs operating in 1997, and daywork revenues per rig per day increased 22
percent. During the first three quarters of 1997, our monthly rig utilization
consistently remained above 18 rigs with daywork revenue per rig per day
steadily climbing by 15 percent. In October utilization dropped slightly below
18 rigs before we acquired nine rigs through the Hickman Acquisition in late
November 1997 and another rig in December 1997, raising our rig count to 34
rigs and our utilization in December to 26.2 rigs. Daywork revenue per rig per
day continued to rise in the fourth quarter, but our average dayrate declined
nine percent in December compared to November since the acquired rigs, due to
their depth capabilities, earned lower dayrates. Total daywork revenues
represented 72 percent of total drilling revenues in 1997 and 68 percent in
1996. Turnkey and footage contracts typically provide for higher revenues since
a greater portion of the expense of drilling the well is born by the drilling
contractor.
Operating margins (revenues less operating costs) for our natural gas and
oil operations were 71 percent in 1997 compared to 69 percent in 1996.
Increased operating margins resulted primarily from the increase in natural gas
production and the increase in natural gas prices received by us between the
two years. Total operating costs were two percent lower in 1997 compared to
1996.
Operating margins for contract drilling increased from 16 percent in 1996 to
21 percent in 1997. Margins in 1997 improved due to increases in daily rig
rates and utilization. Total operating costs for contract drilling were up 50
percent in 1997 versus 1996 due to increased drilling rig utilization.
Contract drilling depreciation increased 43 percent in response to increased
rig utilization and additional drilling capital expenditures throughout 1997.
Depreciation, depletion and amortization ("DD&A") of oil and natural gas
properties increased 17 percent as we increased our equivalent Mcf of
production by two percent and our average DD&A rate per Mcfe increased 15
percent to $.75 in 1997.
General and administrative expenses increased 12 percent as certain employee
costs and outside services increased. Interest expense decreased eight percent
as the average interest rate on our outstanding bank debt decreased from 7.69
percent in 1996 to 7.27 percent in 1997. Average bank debt also decreased four
percent during 1997.
S-22
<PAGE>
Prior to 1996, our effective income tax rate was significantly impacted by
our net operating loss carry forwards. As of December 31, 1995, our net
operating loss and statutory depletion carry forwards were fully recognized for
financial reporting purposes; therefore, our effective income rate in 1996 and
1997 increased to approximately the statutory rate.
PENDING ACQUISITION
In August 1999, we entered into a definitive asset purchase agreement with
Parker Drilling Company and one of its wholly owned subsidiaries to acquire
substantially all of Parker's onshore lower 48 United States drilling rigs
which consists of the following 13 high performance SCR drilling rigs as well
as certain related equipment:
<TABLE>
<CAPTION>
Approximate
Depth
Capabilities
Rig Type (feet)
-------- ------------
<S> <C>
Ideco E-3000.................................................. 30,000
OIME E-3000................................................... 30,000
OIME E-3000................................................... 30,000
OIME E-3000................................................... 30,000
OIME E-3000................................................... 30,000
OIME E-4000................................................... 40,000
OIME E-2000................................................... 20,000
Continental Emsco D-3 E....................................... 16,000
Continental Emsco C-1 E....................................... 20,000
Continental Emsco D-3 E....................................... 16,000
Continental Emsco C-1 E....................................... 20,000
Continental Emsco C-1 E....................................... 20,000
OIME E-2000................................................... 25,000
</TABLE>
We believe these rigs offer superior control and efficiency, particularly in
deep, directional and horizontal applications.
The purchase price for the Parker Acquisition is $40 million in cash and
1,000,000 shares of our common stock. The asset purchase agreement contains
certain conditions precedent to closing, including that we obtain all required
governmental consents. We expect to use a substantial portion of the net
proceeds of this offering to pay the cash portion of the purchase price payable
in the Parker Acquisition. See "Use of Proceeds." This acquisition is expected
to close shortly after the closing of this offering. If it is not closed by
October 31, 1999 either party may terminate it. While we are not currently
aware of any condition that will not be met, we cannot assure you that this
acquisition will close.
Of the thirteen drilling rigs being acquired from Parker, seven are located
in the Rocky Mountain region (primarily Wyoming and Utah), three are located in
Texas and three are located in Louisiana. The rigs located in the Rocky
Mountain region are all currently operating under drilling contracts, while the
other rigs are idle.
We anticipate that the acquisition of these rigs will expand our market
penetration for contract drilling services in at least two respects. First, we
will be involved in the Rocky Mountain region for the first time and we will
substantially expand our Gulf Coast capabilities. Second, most of the rigs that
we will acquire are capable of drilling to greater depths than the majority of
our current rigs.
We expect to employ substantially all of Parker's personnel who have been
involved in the operation of these rigs. Thus, we believe that we will also
benefit from the addition of a number of experienced personnel for our drilling
operations.
S-23
<PAGE>
BUSINESS
Overview
We are engaged in the land contract drilling of natural gas and oil wells
and the exploration, development, acquisition and production of natural gas and
oil properties. The majority of our contract drilling and exploration and
production activities are oriented toward drilling for and producing natural
gas. We estimate that over 90% of our wells drilled for third parties over the
past three years were natural gas prospects and, as of December 31, 1998, 89%
of our reserves were natural gas. We were founded in 1963 as a contract
drilling company and our current contract drilling operations are focused
primarily in the natural gas producing provinces of the Oklahoma and Texas
areas of the Anadarko and Arkoma Basins. Our primary exploration and production
operations are also conducted in the Anadarko and Arkoma Basins. In 1994, we
commenced contract drilling operations in the Texas Gulf Coast area and in 1995
we commenced oil and gas operations in that region.
Our principal office is located at 1000 Kensington Tower I, 7130 South
Lewis, Tulsa, Oklahoma, 74136, and our telephone number is (918) 493-7700.
Land Contract Drilling Operations
We drill onshore oil and natural gas wells for a wide range of customers
through our wholly owned subsidiary, Unit Drilling Company. A land drilling rig
consists, in part, of engines, drawworks or hoists, derrick or mast,
substructure, pumps to circulate the drilling fluid, blowout preventers and
drill pipe. We conduct an active maintenance and replacement program under
which components are upgraded on an individual basis. Over the life of a
typical rig, due to the normal wear and tear of operating 24 hours a day,
several of the major components, such as engines, mud pumps and drill pipe, are
replaced or rebuilt on a periodic basis as required, while other components,
such as the substructure, mast and drawworks, can be utilized for extended
periods of time with proper maintenance. We also own additional equipment used
in the operation of our rigs, including large air compressors, trucks and other
support equipment.
On November 20, 1997, we acquired Hickman Drilling Company pursuant to a
merger in which all of the holders of the outstanding capital stock of Hickman
Drilling received, in aggregate, 1,300,000 shares of our common stock and
promissory notes in the aggregate principal amount of $5,000,000, payable in
five equal annual installments commencing January 2, 1999. The acquisition
included nine land contract drilling rigs with depth capacities ranging from
9,500 to 17,000 feet, spare drilling equipment and approximately $2.1 million
in working capital. As part of the acquisition, we retained Hickman Drilling
Company's Woodward, Oklahoma corporate office as a regional office for our
contract drilling operations.
In December 1997, we also purchased a Mid-Continent U-36A, 650 horsepower
rig with a 13,000 foot depth capacity and spare components from two additional
rigs for $1,000,000, of which $200,000 was paid at closing and the balance is
to be paid over a period ending no later than three years.
With these acquisitions our drilling rig fleet expanded to 34 rigs with
depth capacities ranging from 7,000 to 25,000 feet. At August 30, 1999, 30 of
our rigs were located in the Anadarko and Arkoma Basins of Oklahoma and Texas
while four of our larger horsepower rigs were located in South Texas. In the
Anadarko and Arkoma Basins, we primarily focus on the utilization of our medium
depth rigs which have a depth range of 8,000 to 14,000 feet. These medium depth
rigs are suited to the contract drilling currently undertaken by operators in
these two basins.
At present, we do not have a shortage of drilling rig related equipment.
During 1996 and through 1997, we increased our drill pipe acquisitions since
certain grades of drill pipe were in high demand due to increased rig
utilization. However, at any given time, our ability to utilize our full
complement of drilling rigs is dependent upon the availability of qualified
labor, drilling supplies and equipment as well as demand. Should industry
S-24
<PAGE>
conditions improve rapidly, there is no assurance that sufficient supplies of
drill pipe, other drilling equipment and qualified labor will be readily
available, not only within Unit, but in the industry as a whole.
The following table sets forth, for each of the periods indicated, certain
data concerning our contract drilling operations:
<TABLE>
<CAPTION>
Six Months
Year Ended December 31, Ended
-------------------------------------- June 30,
1994 1995 1996 1997 1998 1999
------ ------ ------ ------ ------ ----------
<S> <C> <C> <C> <C> <C> <C>
Number of operational rigs
at period end.............. 25 22 24 34 (1) 34 34
Average number of rigs owned
during period.............. 25 25 22.7 25.1 34 34
Average number of rigs
utilized (2)............... 9.5 10.9 14.7 20.0 22.9 19.5
Utilization rate (2)........ 38% 44% 65% 80% 67% 57%
Number of wells drilled..... 95 111 130 167 198 88
Average revenue per day
(3)........................ $4,894 $5,081 $5,351 $6,309 $6,394 $6,352
Total footage drilled (feet
in thousands).............. 1,027 1,196 1,468 1,736 2,203 905
</TABLE>
- --------
(1) Includes 10 rigs acquired in the fourth quarter of 1997.
(2) Utilization rates are based on a 365-day year and are calculated by
dividing the average number of rigs utilized by the average number of rigs
owned during the period, including stacked rigs. A rig is considered
utilized when it is operating or being moved, assembled or dismantled under
contract.
(3) Represents total revenues from contract drilling operations divided by the
number of days rigs were being utilized for the period.
S-25
<PAGE>
The following table sets forth, as of August 31, 1999, the type and
approximate depth capability of each of our drilling rigs:
<TABLE>
<CAPTION>
Approximate
Depth
Capability
Rig Number Type (feet)
---------- ---- -----------
<S> <C> <C>
1 U-15 Unit Rig 11,000
2 BDW 650 13,000
3 BDW 650 13,500
4 U-15 Unit Rig 11,000
5 U-15 Unit Rig 11,000
6 BDW 800 15,000
7 U-15 Unit Rig 11,000
8 Gardner Denver 800 15,000
9 BDW 800 15,000
10 BDW 450T 9,500
11 Gardner Denver 700 15,000
12 BDW 800 15,000
14 Gardner Denver 700 15,000
15 Mid-Continent 914-C 20,000
16 U-15 Unit Rig 11,000
17 Brewster N-75A 15,000
18 BDW 650 12,000
19 Gardner Denver 500 12,000
20 Gardner Denver 700 15,000
21 Gardner Denver 700 15,000
22 BDW 800 15,000
23 Gardner Denver 700 15,000
24 Gardner Denver 700 15,000
25 Gardner Denver 700 15,000
29 Brewster N-75A 15,000
30 BDW 1350-M 20,000
31 SU-15 North Texas Machine 12,000
32 Brewster N-75 15,000
34 National 110-UE 20,000
35 Continental Emsco C-1-E 20,000
36 Gardner Denver 1500-E 25,000
37 Mid-Continent 914-EC 20,000
38 Mid-Continent 1220-E 25,000
39 U-36-A 13,000
</TABLE>
During the past 15 years, our contract drilling services encountered
significant competition due to depressed levels of activity in contract
drilling. In the last six months of 1996 and throughout 1997 and the first
three quarters of 1998, our drilling operation showed significant improvements
in rig utilization. However, in late 1998 and through the first six months of
1999, we and the industry as a whole experienced a significant reduction in
demand. Although we have started to experience an increase in demand during the
third quarter of 1999, we anticipate that competition within the industry will,
for the foreseeable future, continue to adversely affect us.
Drilling Contracts. Most of our drilling contracts are obtained through
competitive bidding. Generally, the contracts are for a single well with the
terms and rates varying depending upon the nature and duration of the work, the
equipment and services supplied and other matters. The contracts obligate us to
pay certain
S-26
<PAGE>
operating expenses, including wages of drilling personnel, maintenance expenses
and incidental rig supplies and equipment. Usually, the contracts are
terminable by the customer on short notice upon payment of a fee. We generally
indemnify our customers against certain types of claims by our employees and
claims arising from surface pollution caused by spills of fuel, lubricants and
other solvents within our control. Customers generally indemnify us against
claims arising from other surface and subsurface pollution other than claims
resulting from our gross negligence.
The contracts may provide for compensation to us on a day rate, footage or
turnkey basis, with additional compensation for special risks and unusual
conditions. Under daywork contracts, we provide the drilling rig with the
required personnel to the operator who supervises the drilling of the
contracted well. Our compensation is based on a negotiated rate for each day
the rig is utilized. Footage contracts usually require us to bear some of the
drilling costs in addition to providing the rig. We are compensated on a rate
per foot drilled basis upon completion of the well. Under turnkey contracts, we
contract to drill a well to a specified depth and provide most of the equipment
and services required. We bear the risk of drilling the well to the contract
depth and are compensated when the contract provisions have been satisfied.
Turnkey drilling operations, in particular, might result in losses if we
underestimate the costs of drilling a well or if unforeseen events occur. To
date, we have not experienced significant losses in performing turnkey
contracts. For 1998, turnkey revenue represented approximately 15% of our
contract drilling revenues while for the first six months of 1999 it represents
27%. Because the proportion of turnkey drilling is currently dictated by market
conditions and the desires of customers using our services, we are unable to
predict whether the portion of drilling conducted on a turnkey basis will
increase or decrease in the future.
Customers. During the fiscal year ended December 31, 1998, ten contract
drilling customers accounted for approximately 24% of our total revenues.
Approximately five percent of our total revenues were generated by drilling on
oil and natural gas properties of which we were the operator (including
properties owned by limited partnerships for which Unit acted as general
partner). This drilling was pursuant to contracts containing terms and
conditions comparable to those contained in our customary drilling contracts
with non-affiliated operators.
Exploration and Production Operations
In 1979, we began to develop our exploration and production operations to
diversify our source of revenues which, up to that time, were derived from our
contract drilling. We develop, produce and sell oil and natural gas and acquire
producing properties, through our wholly owned subsidiary, Unit Petroleum
Company.
As of December 31, 1998, we had 3,245 Mbbls and 161,318 MMcf of estimated
proved oil and natural gas reserves. Our producing oil and natural gas
interests, undeveloped leaseholds and related assets are located primarily in
Oklahoma, Texas, Louisiana and New Mexico and to a lesser extent in Arkansas,
North Dakota, Colorado, Montana, Alabama, Mississippi, Arkansas, Illinois,
Nebraska and Canada. As of December 31, 1998, we had an interest in a total of
2,499 wells in the United States and served as the operator of 524 wells. We
also had an interest in 64 wells located in Canada. Our technical staff
generates the majority of our development and exploration prospects. When we
are the operator of a property, we generally employ our own drilling rigs and
our own engineering staff supervises the drilling operation.
We intend to continue the growth in our oil and natural gas operations
utilizing funds generated from operations and our bank revolving line of
credit.
Approximately 107 Bcfe (or 59%) of our proved reserves are located in the
Anadarko Basin which is a geographic area encompassing Western Oklahoma and the
Texas Panhandle. This basin is considered a mature gas producing field that is
characterized by multiple producing horizons and long-lived reserves. Producing
wells often have additional reserves "behind pipe" or additional zones with
producing capabilities that are not completed initially in the well bore. These
zones are categorized as proved developed non-producing, and
S-27
<PAGE>
require recompletion or work over activities to be performed in order to
convert to proved producing and thereby increase the well's cash flow. A
significant number of our properties are located on 640 acre producing units
which in some cases may enable an additional well or wells, known as increased
density or infill wells, to be drilled on the same acreage with out adversely
effecting the existing production.
Well and Leasehold Data. Our oil and natural gas exploration and development
drilling activities and the number of wells in which we had an interest, which
were producing or capable of producing, were as follows for the periods
indicated:
<TABLE>
<CAPTION>
Year Ended December 31, Six Months
-------------------------------------- Ended
1996 1997 1998 June 30, 1999
------------ ------------ ------------ --------------
Gross Net Gross Net Gross Net Gross Net
----- ------ ----- ------ ----- ------ --------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Wells drilled:
Exploratory:
Oil.................... -- -- -- -- -- -- -- --
Natural gas............ -- -- -- -- -- -- -- --
Dry.................... -- -- -- -- 1 .26 1 1
----- ------ ----- ------ ----- ------ ------ -------
Total................. -- -- -- -- 1 .26 1 1
===== ====== ===== ====== ===== ====== ====== =======
Development:
Oil.................... 10 8.35 10 4.84 4 .44 -- --
Natural gas............ 55 19.46 57 23.85 52 19.26 12 4.79
Dry.................... 7 4.26 15 9.27 21 10.62 3 1.27
----- ------ ----- ------ ----- ------ ------ -------
Total................. 72 32.07 82 37.96 77 30.32 15 6.06
===== ====== ===== ====== ===== ====== ====== =======
<CAPTION>
As of December 31,
-------------------------------------- As of
1996 1997 1998 June 30, 1999
------------ ------------ ------------ --------------
Gross Net Gross Net Gross Net Gross Net
----- ------ ----- ------ ----- ------ --------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Oil and natural gas
wells producing or
capable of producing:
Oil--USA............... 717 197.71 684 197.67 726 196.64 726 196.64
Oil--Canada............ -- -- -- -- -- -- -- --
Gas--USA............... 1,530 242.09 1,545 260.40 1,773 286.73 1,793 294.55
Gas--Canada............ 64 1.60 64 1.60 64 1.60 64 1.60
----- ------ ----- ------ ----- ------ ------ -------
Total................. 2,311 441.40 2,293 459.67 2,563 484.97 2,583 492.79
===== ====== ===== ====== ===== ====== ====== =======
</TABLE>
S-28
<PAGE>
The following table summarizes our acreage as of the end of each of the
years indicated:
<TABLE>
<CAPTION>
Developed Undeveloped
Acreage Acreage
--------------- -------------
Gross Net Gross Net
------- ------- ------ ------
<S> <C> <C> <C> <C>
1998
USA............................................... 569,076 130,440 52,958 35,371
Canada............................................ 39,040 976 22,763 22,763
------- ------- ------ ------
Total........................................... 608,116 131,416 75,721 58,134
======= ======= ====== ======
1997
USA............................................... 432,824 118,926 37,844 26,116
Canada............................................ 39,040 976 18,970 18,970
------- ------- ------ ------
Total........................................... 471,864 119,902 56,814 45,086
======= ======= ====== ======
1996
USA............................................... 455,713 115,326 29,245 19,124
Canada............................................ 39,040 976 -- --
------- ------- ------ ------
Total........................................... 494,753 116,302 29,245 19,124
======= ======= ====== ======
</TABLE>
Price and Production Data. Our average sales price, oil and natural gas
production volumes and average production cost per Mcfe of production for the
periods indicated were as follows:
<TABLE>
<CAPTION>
Six Months
Year Ended December 31, Ended
----------------------- June 30,
1996 1997 1998 1999
------- ------- ------- ----------
<S> <C> <C> <C> <C>
Average sales price per barrel of oil
produced:
USA....................................... $ 20.40 $ 19.19 $ 12.81 $ 13.62
Canada.................................... N/A N/A N/A N/A
Average sales price per Mcf of natural gas
produced:
USA....................................... $ 2.21 $ 2.43 $ 1.90 $ 1.64
Canada.................................... $ 1.18 $ 0.93 $ 1.46 $ 1.69
Oil production (MBbls):
USA....................................... 579 493 443 183
Canada.................................... -- -- -- --
------- ------- ------- -------
Total.................................... 579 493 443 183
======= ======= ======= =======
Natural gas production (MMcf):
USA....................................... 12,974 13,742 16,427 7,651
Canada.................................... 51 74 38 16
------- ------- ------- -------
Total.................................... 13,025 13,816 16,465 7,667
======= ======= ======= =======
Average production expense per Mcfe:
USA....................................... $ 0.68 $ 0.64 $ 0.61 $ 0.59
Canada.................................... $ 0.27 $ 0.33 $ 0.54 $ 0.62
</TABLE>
S-29
<PAGE>
Reserves. The following table sets forth our estimated proved developed and
undeveloped oil and natural gas reserves at the end of each of the years
indicated:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1996 1997 1998
------- ------- -------
<S> <C> <C> <C>
Oil (MBbls):
USA.................................................... 5,204 4,131 3,245
Canada................................................. -- -- --
------- ------- -------
Total................................................. 5,204 4,131 3,245
======= ======= =======
Natural gas (MMcf):
USA.................................................... 128,408 144,661 160,795
Canada................................................. 753 723 523
------- ------- -------
Total................................................. 129,161 145,384 161,318
======= ======= =======
</TABLE>
Marketing. The marketing of oil and gas production is subject to the
availability of pipelines, crude oil hauling and other transportation,
processing and refining facilities and the existence of adequate markets.
Generally, our oil and gas production is located in areas where commercial
production can be rapidly effectuated.
Most of our natural gas production is sold on a monthly basis under short-
term contracts at the "spot market" prices then currently available. Because
none of our gas is committed to long-term fixed-price contracts, we are
positioned to take advantage of rising prices for gas; however, we are also
subject to price declines. Generally, our oil production is sold on a monthly
basis at the posted prices then currently available. No purchaser of our
natural gas or oil production during 1998 exceeded 10% of our revenues.
We have previously engaged in oil and gas hedging activities and continue to
consider various hedging arrangements to realize commodity prices which we deem
favorable at the time we enter into these arrangements and to manage our
exposure to price fluctuations. In the first quarter of 1999, we entered into
natural gas swap transactions which covered approximately 20% of our daily
natural gas production for the period from March 1, 1999 to June 30, 1999. We
have recently entered into natural gas swap transactions covering approximately
25% of our daily natural gas production for the period from September 1, 1999
to October 31, 1999 at $2.52 per MMBtu.
Competition
All of our lines of business are highly competitive. Competition in land
contract drilling traditionally involves such factors as price, efficiency,
condition of equipment, availability of labor and equipment, reputation and
customer relations. Some of our competitors in the land contract drilling
business are substantially larger than we are and have appreciably greater
financial and other resources. As a result of the decrease in demand for land
contract drilling services over the past decade, a surplus of certain types of
drilling rigs currently exists within the industry while inventories of certain
components such as specific grades of drill pipe have been depleted from
continued use. Accordingly, the competitive environment within which we operate
is uncertain and extremely price oriented.
Our oil and natural gas operations likewise encounter strong competition
from major oil companies, independent operators, and others. Many of these
competitors have appreciably greater financial, technical and other resources
and are more experienced in the exploration for and production of oil and
natural gas than we are.
Governmental Regulations
The production and sale of oil and natural gas is highly affected by various
state and federal regulations. All states in which we conduct activities impose
restrictions on the drilling, production, transportation and sale of oil and
natural gas.
S-30
<PAGE>
Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission
(the "FERC") regulates the interstate transportation and the sale in interstate
commerce for resale of natural gas. The FERC's jurisdiction over interstate
natural gas sales was substantially modified by the Natural Gas Policy Act,
under which the FERC continued to regulate the maximum selling prices of
certain categories of gas sold in "first sales" in interstate and intrastate
commerce. Effective January 1, 1993, however, the Natural Gas Wellhead
Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all
"first sales" of natural gas. Because "first sales" include typical wellhead
sales by producers, all natural gas produced from our natural gas properties is
being sold at market prices, subject to the terms of any private contracts
which may be in effect. The FERC's jurisdiction over natural gas transportation
was not affected by the Decontrol Act.
Our sales of natural gas are affected by intrastate and interstate gas
transportation regulation. Beginning in 1985, the FERC adopted regulatory
changes that have significantly altered the transportation and marketing of
natural gas. These changes were intended by the FERC to foster competition by,
among other things, transforming the role of interstate pipeline companies from
wholesale marketers of gas to the primary role of gas transporters. All gas
marketing by the pipelines was required to be divested to a marketing
affiliate, which operates separately from the transporter and in direct
competition with all other merchants. As a result of the various omnibus
rulemaking proceedings in the late 1980s and the individual pipeline
restructuring proceedings of the early to mid-1990s, the interstate pipelines
are now required to provide open and nondiscriminatory transportation and
transportation-related services to all producers, gas marketing companies,
local distribution companies, industrial end users and other customers seeking
service. Through similar orders affecting intrastate pipelines that provide
similar interstate services, the FERC expanded the impact of open access
regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (1) the large-scale
divestiture of interstate pipeline-owned gas gathering facilities to affiliated
or non-affiliated companies, (2) further development of rules governing the
relationship of the pipelines with their marketing affiliates, (3) the
publication of standards relating to the use of electronic bulletin boards and
electronic data exchange by the pipelines to make available transportation
information on a timely basis and to enable transactions to occur on a purely
electronic basis, (4) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the
primary market and (5) development of policy and promulgation of orders
pertaining to its authorization of market-based rates (rather than traditional
cost-of-service based rates) for transportation or transportation-related
services upon the pipeline's demonstration of lack of market control in the
relevant service market. It remains to be seen what effect the FERC's other
activities will have on the access to markets, the fostering of competition and
the cost of doing business.
As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counter parties. We believe these
changes generally have improved the access to markets for natural gas while, at
the same time, substantially increasing competition in the natural gas
marketplace. We cannot predict what new or different regulations the FERC and
other regulatory agencies may adopt, or what effect subsequent regulations may
have on production and marketing of gas from our properties.
In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation and the promotion of competition in the gas industry. Thus, in
addition to "first sale" deregulation, Congress also repealed incremental
pricing requirements and gas use restraints previously applicable. There are
other legislative proposals pending in the Federal and state legislatures
which, if enacted, would significantly affect the petroleum industry. At the
present time, it is impossible to predict what proposals, if any, might
actually be enacted by Congress or the various state legislatures and what
effect, if any, these proposals might have on the production and marketing of
gas by us. Similarly, and despite the trend toward federal deregulation of the
natural gas industry, whether or to what extent that trend will continue, or
what the ultimate effect will be on the production and marketing of gas by us,
cannot be predicted.
S-31
<PAGE>
Our sales of oil and natural gas liquids are not regulated and are at market
prices. The price received from the sale of these products is affected by the
cost of transporting the products to market. Much of that transportation is
through interstate common carrier pipelines. Effective as of January 1, 1995,
the FERC implemented regulations generally grandfathering all previously
approved interstate transportation rates and establishing an indexing system
for those rates by which adjustments are made annually based on the rate of
inflation, subject to certain conditions and limitations. These regulations may
tend to increase the cost of transporting oil and natural gas liquids by
interstate pipeline, although the annual adjustments may result in decreased
rates in a given year. These regulations have generally been approved on
judicial review. Every five years, the FERC will examine the relationship
between the annual change in the applicable index and the actual cost changes
experienced by the oil pipeline industry. The first such review is scheduled
for the year 2000. We are not able to predict with certainty what effect, if
any these relatively new federal regulations or the periodic review of the
index by FERC will have on us.
Federal, state, and local agencies have promulgated extensive rules and
regulations applicable to our oil and natural gas exploration, production and
related operations. Oklahoma, Texas and other states require permits for
drilling operations, drilling bonds and the filing of reports concerning
operations and impose other requirements relating to the exploration of oil and
gas. Many states also have statutes or regulations addressing conservation
matters including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
gas wells and the regulation of spacing, plugging and abandonment of such
wells. The statutes and regulations of some states limit the rate at which oil
and gas can be produced from our properties. The federal and state regulatory
burden on the oil and gas industry increases our cost of doing business and
affects its profitability. Because these rules and regulations are frequently
amended or reinterpreted, we are unable to predict the future cost or impact of
complying with those laws.
Federal and State Environmental Regulation
Our operations are subject to numerous federal and state laws and
regulations regarding the control of contamination of the environment. These
laws and regulations may require the acquisition of a permit before or after
drilling commences, prohibit drilling activities on certain lands lying within
wilderness areas or where pollution arises and impose substantial liabilities
for pollution resulting from drilling operations, particularly operations in
offshore waters or on submerged lands. These laws and regulations may
substantially increase the costs of doing business and may prevent or delay the
commencement or continuation of given operations. Compliance with these
legislation and regulations, together with any penalties resulting from
noncompliance therewith, will increase the cost of oil and natural gas
drilling, development, production and processing.
A past, present, or future release or threatened release of a hazardous
substance into the air, water, or ground by us or as a result of disposal
practices may subject us to liability under the Comprehensive Environmental
Response, Compensation and Liability Act, as amended ("CERCLA"), the Resource
Conservation Recovery Act ("RCRA"), the Clean Water Act, and/or similar state
laws, and any regulations promulgated under these laws. Under CERCLA and
similar laws, we may be fully liable for the cleanup costs of a release of
hazardous substances even though we contributed to only part of the release.
While liability under CERCLA and similar laws may be limited under certain
circumstances, the limits are so high that the maximum liability would likely
have a significant adverse effect on us. In certain circumstances, we may have
liability for releases of hazardous substances by previous owners of our
properties. CERCLA currently excludes petroleum from its definition of
"hazardous substances." However, Congress may delete this exclusion for
petroleum, in which case we would be required to manage the petroleum
production and wastes from our exploration and production activities as CERCLA
hazardous substances. In addition, RCRA classifies certain oil field wastes as
"non-hazardous." Congress may delete this exemption for oilfield waste, in
which case we would have to manage much of our oilfield waste as hazardous.
Additionally, the discharge or substantial threat of a discharge of oil by us
into United States waters or onto an adjoining shoreline may subject us to
liability under the Oil Pollution Act of 1990 and similar state laws. While
liability under the Oil
S-32
<PAGE>
Pollution Act of 1990 is limited under certain circumstances, the maximum
liability under those limits would still likely have a significant adverse
effect on us.
Violation of environmental legislation and regulations may result in the
imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the abatement of the conditions, or
suspension of the activities, giving rise to the violation. We believe that we
have complied with all orders and regulations applicable to our operations.
However, in view of the many uncertainties with respect to the current
controls, including their duration and possible modification, we cannot predict
the overall effect of such controls on our operations. Similarly, we cannot
predict what future environmental laws may be enacted or regulations may be
promulgated and what, if any, impact they would have on our operations.
Employees
As of August 31, 1999, we had approximately 439 employees in our land
contract drilling operations, 46 employees in our natural gas and oil
operations and 43 in our general corporate area. Our employees are not
represented by a union or labor organization, nor have our operations ever been
interrupted by a strike or work stoppage. We consider relations with our
employees to be satisfactory.
Legal Proceedings
We are a party to various legal proceedings arising in the normal course of
our business, none of which, in our opinion, should result in judgments which
would have a material adverse effect on us.
S-33
<PAGE>
MANAGEMENT
The following table sets forth certain information concerning each director
and executive officer of Unit:
<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<C> <C> <S>
King P. Kirchner 71 Chairman of the Board, Chief Executive Officer and
Director
John G. Nikkel 64 President, Chief Operating Officer and Director
Earle Lamborn 65 Senior Vice President, Drilling and Director
Philip M. Keeley 58 Senior Vice President, Exploration and Production
Larry D. Pinkston 45 Vice President, Treasurer and Chief Financial Officer
Mark E. Schell 42 General Counsel and Secretary
J. Michael Adcock 50 Director
William B. Morgan 55 Director
Don Cook 74 Director
John H. Williams 81 Director
John S. Zink 70 Director
</TABLE>
King P. Kirchner, a co-founder of Unit, has been the Chairman of the Board
and a director since 1963 and was President until November 1983. Mr. Kirchner
is a Registered Professional Engineer within the State of Oklahoma, having
received degrees in Mechanical Engineering from Oklahoma State University and
in Petroleum Engineering from the University of Oklahoma.
John G. Nikkel joined Unit in 1983 as its President and a director. From
1976 until January 1982 Mr. Nikkel was an officer and director of Cotton
Petroleum Corporation, serving as the President of that company from 1979
until his departure. Prior to joining Cotton, Mr. Nikkel was employed by Amoco
Production Company for 18 years, last serving as Division Geologist for
Amoco's Denver Division. Mr. Nikkel received a Bachelor of Science degree in
Geology and Mathematics from Texas Christian University.
Earle Lamborn has been actively involved in the oil field for over 45
years, joining Unit's predecessor in 1952 prior to it becoming a publicly-held
corporation. He was elected Vice President, Drilling in 1973 and to his
current position as Senior Vice President and Director in 1979.
Philip M. Keeley joined Unit in November 1983 as a Senior Vice President,
Exploration and Production. From 1977 until 1982, Mr. Keeley was employed by
Cotton Petroleum Corporation, serving first as Manager of Land and from 1979
as Vice President and a director. Before joining Cotton, Mr. Keeley was
employed for four years by Apexco, Inc. as Manager of Land and prior thereto
he was employed by Texaco, Inc. for nine years. He received a Bachelor of Arts
degree in Petroleum Land Management from the University of Oklahoma.
Larry D. Pinkston joined Unit in December 1981. He had served as Corporate
Budget Director and Assistant Controller prior to being appointed as
Controller in February 1985. He has been Treasurer since December 1986 and was
elected to the position of Vice President and Chief Financial Officer in May
1989. He holds a Bachelor of Science Degree in Accounting from East Central
University of Oklahoma and is a Certified Public Accountant.
Mark E. Schell joined Unit in January of 1987, as its Secretary and General
Counsel. From 1979 until joining the Company, Mr. Schell was Counsel, Vice
President and a member of the Board of Directors of C & S Exploration, Inc. He
received a Bachelor of Science degree in Political Science from Arizona State
University and his Juris Doctorate degree from the University of Tulsa Law
School. He is a member of the Oklahoma and American Bar Association as well as
being a member of the American Corporate Counsel Association and the American
Society of Corporate Secretaries.
S-34
<PAGE>
J. Michael Adcock was elected a director of Unit in December 1997. He is an
attorney and currently manages a private trust which deals in real estate, oil
and gas properties and commercial banking as well as other equity investments.
He is Chairman of the Board of Arvest American National Bank & Trust Co. of
Shawnee and a member of the Board of Directors of Medicine Lodge Bankshares.
Between 1997 through September, 1998 he was the Chairman of the Board of
Ameribank and President and Chief Executive Officer of American National Bank
and Trust Company of Shawnee, Oklahoma, and Chairman of AmeriTrust Corporation,
Tulsa, Oklahoma. Prior to holding these positions, he was engaged in the
private practice of law from January 1, 1994 through March 1, 1996 and from
March 1, 1996 until November 1, 1997 he served as General Counsel for Ameribank
Corporation. Mr. Adcock was also a director of Grant Geophysical, Inc. from
June 1994 until September 1997 when he resigned. Grant Geophysical, Inc., filed
a petition under Chapter 11 of the Federal Bankruptcy Code in October, 1996.
William B. Morgan was elected a director of Unit in February 1988. Mr.
Morgan has been Executive Vice President and General Counsel of St. John Health
System, Inc., Tulsa, Oklahoma, since March 1, 1995 and, since October 1, 1996,
the President of its principal for profit subsidiary Utica Services, Inc.
Before that, he was a partner in the law firm of Doerner, Saunders, Daniel &
Anderson, Tulsa, Oklahoma, for over 20 years.
Don Cook has served as a director of Unit since the Company's inception. He
is a Certified Public Accountant and was a partner in the accounting firm of
Finley & Cook, Shawnee, Oklahoma, from 1950 until 1987, when he retired.
John H. Williams was elected a director of Unit in December 1988. Prior to
retiring on December 31, 1978, he was Chairman of the Board and Chief Executive
Officer of The Williams Companies, Inc. where he continues to serve as an
honorary director. Mr. Williams also serves as a director of Apco Argentina,
Inc., Westwood Corporation, and Willbros Group, Inc.
John S. Zink was elected a director of Unit in May 1982. For over five
years, he has been a principle in several privately held companies engaged in
the businesses of designing and manufacturing equipment used in the petroleum
industry, construction and heating and air conditioning services and
installation. He holds a Bachelor of Science degree in Mechanical Engineering
from Oklahoma State University. He is also a director of Matrix Service
Company, Tulsa, Oklahoma.
S-35
<PAGE>
SHARES ELIGIBLE FOR FUTURE SALE
Sales of substantial amounts of our common stock, or a perception that such
sales could occur, and the existence of options to purchase shares of common
stock at prices that may be below the then current market price of the common
stock could adversely affect the market price of the common stock and could
impair our ability to raise capital through the sale of equity securities.
After this offering and the consummation of the Parker Acquisition, 33,810,675
shares of common stock will be outstanding (34,860,675 shares if the
underwriters exercise their over-allotment option in full). The 7,000,000
shares sold in this offering (8,050,000 shares if the underwriters exercise
their over-allotment option) will be freely tradable without restriction under
the Securities Act; except for any shares purchased by "affiliates" of Unit as
defined in Rule 144 under the Securities Act. Of the remaining shares to be
outstanding after this offering, approximately 3,261,149 shares are
"restricted securities" within the meaning of Rule 144, or are held by
affiliates of Unit, and in each case generally may not be sold except in
transactions registered under the Securities Act or pursuant to an exemption
from registration, such as the exemption provided by Rule 144.
Unit's officers and directors and holders of 2,300,000 shares have agreed
to enter into lock-up agreements pursuant to which they will not offer or sell
any shares of common stock for a period of 90 days after the date of this
prospectus supplement without the prior written consent of Prudential
Securities, on behalf of the underwriters. See "Underwriting." Prudential
Securities may, at any time and without notice, waive any of the terms of
these lock-up agreements specified in the underwriting agreement. Following
the lock-up period, these shares will not be eligible for sale in the public
market without registration under the Securities Act unless such sales meet
the conditions and restrictions of Rule 144 as described below.
In general, under Rule 144 as currently in effect, any person (or persons
whose shares are aggregated) who has beneficially owned restricted shares for
a period of at least one year is entitled to sell, within any three-month
period, a number of shares that does not exceed the greater of (i) 1% of the
then-outstanding shares of common stock and (ii) the average weekly trading
volume in the common stock during the four calendar weeks immediately
preceding the date on which the notice of such sale on Form 144 is filed with
the Securities and Exchange Commission. Sales under Rule 144 are also subject
to certain provisions relating to notice and manner of sale and the
availability of current public information about Unit. In addition, a person
(or persons whose shares are aggregated) who has not been an affiliate of Unit
at any time during the 90 days immediately preceding a sale, and who has
beneficially owned the shares for at least two years, would be entitled to
sell such shares under Rule 144(k) without regard to the volume limitation and
other conditions described above. Affiliates are subject to the volume
limitations and other conditions described above regardless of the length of
time those shares have been held and whether the shares are restricted. The
foregoing summary of Rule 144 is not intended to be a complete description.
Options
As of the date of this prospectus supplement, we had outstanding options to
purchase a total of 735,100 shares of common stock. Our outstanding options
include options covering 447,500 shares granted to our executive officers and
directors, of which 290,500 are exercisable. These vested and unvested options
are exercisable at prices ranging from $1.75 to $9.00 per share and expire
between July 30, 2001 and May 6, 2009. Options covering 287,600 shares have
been issued to our employees pursuant to our Stock Option Plan. These options
are exercisable at prices ranging from $2.37 to $11.31 per share and expire
between July 30, 2001 and December 22, 2008.
Registration Rights Agreements
Certain of our shareholders have registration rights with respect to shares
of common stock that they hold.
We granted registration rights in connection with the issuance of 1,300,000
shares of common stock in November 1997. We issued these shares in connection
with our acquisition, by merger, of Hickman Drilling Company. A registration
statement relating to the resale of these shares has been filed with the SEC
and is effective.
S-36
<PAGE>
We have also granted registration rights in connection with the proposed
issuance of 1,000,000 shares as partial consideration in the acquisition of the
land drilling equipment from Parker Drilling Company. In the event the
acquisition is consummated, we have agreed to use our best efforts to effect
the registration of these shares for resale on behalf of Parker and to maintain
effectiveness of the registration statement for a period of two years subject
to certain conditions.
Both Parker Drilling and the former shareholders of Hickman Drilling have
agreed to enter into lock-up agreements pursuant to which they will not offer
or sell any shares of common stock for a period of 90 days after the date of
this prospectus supplement without the prior written consent of Prudential
Securities, on behalf of the underwriters. See "Underwriting."
S-37
<PAGE>
UNDERWRITING
We have entered into an underwriting agreement with the underwriters named
below, for whom Prudential Securities Incorporated, CIBC World Markets Corp.
and Raymond James & Associates, Inc. are acting as representatives. We are
obligated to sell, and the underwriters are obligated to purchase, all of the
shares offered on the cover page of this prospectus supplement, if any are
purchased. Subject to certain conditions of the underwriting agreement, each
underwriter has severally agreed to purchase the shares indicated opposite its
name:
<TABLE>
<CAPTION>
Number
Underwriters of Shares
------------ ---------
<S> <C>
Prudential Securities Incorporated.................................... 2,394,000
CIBC World Markets Corp. ............................................. 1,512,000
Raymond James & Associates, Inc. ..................................... 1,134,000
Bear, Stearns & Co. Inc............................................... 140,000
Donaldson, Lufkin & Jenrette Securities Corporation................... 140,000
A.G. Edwards & Sons, Inc.............................................. 140,000
Lehman Brothers Inc................................................... 140,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated.................... 140,000
Morgan Stanley & Co. Incorporated..................................... 140,000
PaineWebber Incorporated.............................................. 140,000
Salomon Smith Barney Inc.............................................. 140,000
Robert W. Baird & Co. Incorporated.................................... 70,000
Dain Rauscher Wessels................................................. 70,000
Everen Securities, Inc................................................ 70,000
First Albany Corporation.............................................. 70,000
First Union Capital Markets Corp...................................... 70,000
Hanifen, Imhoff Inc................................................... 70,000
Harris Webb & Garrison Inc............................................ 70,000
Jefferies & Company, Inc.............................................. 70,000
Petrie Parkman & Co................................................... 70,000
Southcoast Capital Corporation........................................ 70,000
Sutro & Co. Incorporated.............................................. 70,000
Tucker Anthony Cleary Gull............................................ 70,000
---------
Total............................................................... 7,000,000
=========
</TABLE>
The underwriters may sell more shares than the total number of shares
offered on the cover page of this prospectus supplement and they have, for a
period of 30 days from the date of this prospectus supplement, an over-
allotment option to purchase up to 1,050,000 additional shares from us. If any
additional shares are purchased, the underwriters will severally purchase the
shares in the same proportion as per the table above.
The representatives of the underwriters have advised us that the shares will
be offered to the public at the offering price indicated on the cover page of
this prospectus supplement. The underwriters may allow to selected dealers a
concession not in excess of $0.24 per share and such dealers may reallow a
concession not in excess of $0.10 per share to certain other dealers. After the
shares are released for sale to the public, the representatives may change the
offering price and the concession.
We have agreed to pay to the underwriters the following fees, assuming both
no exercise and full exercise of the underwriters' over-allotment option to
purchase additional shares:
<TABLE>
<CAPTION>
Total Fees
-------------------------------------------
Fee Without Exercise of Full Exercise of
Per Share Over-Allotment Option Over-Allotment Option
--------- --------------------- ---------------------
<S> <C> <C> <C>
Fees paid by us........... $0.42 $2,940,000 $3,381,000
</TABLE>
In addition, we estimate that we will spend approximately $175,000 in
expenses for this offering. We have agreed to indemnify the underwriters
against certain liabilities, including liabilities under the Securities Act, or
contribute to payments that the underwriters may be required to make in respect
of these liabilities.
S-38
<PAGE>
We, our officers and directors, and both Parker Drilling and the former
shareholders of Hickman Drilling have agreed to enter into lock-up agreements
pursuant to which we and they will not offer or sell any shares of common stock
or securities convertible into or exchangeable or exercisable for shares of
common stock for a period of 90 days from the date of this prospectus
supplement without the prior written consent of Prudential Securities, on
behalf of the underwriters. Prudential Securities may, at any time and without
notice, waive the terms of these lock-up agreements specified in the
underwriting agreement.
Prudential Securities, on behalf of the underwriters, may engage in the
following activities in accordance with applicable securities rules:
. Over-allotments involving sales in excess of the offering size, creating
a short position. Prudential Securities may elect to reduce this short
position by exercising some or all of the over-allotment option.
. Stabilizing and short covering; stabilizing bids to purchase the shares
are permitted if they do not exceed a specified maximum price. After the
distribution of shares has been completed, short covering purchases in
the open market may also reduce the short position. These activities may
cause the price of the shares to be higher than would otherwise exist in
the open market.
. Penalty bids permitting the representatives to reclaim concessions from a
syndicate member for the shares purchased in the stabilizing or short
covering transactions.
Such activities, which may be commenced and discontinued at any time, may be
effected on the New York Stock Exchange, in the over-the-counter market or
otherwise.
Each underwriter has represented that it has complied and will comply with
all applicable laws and regulations in connection with the offer, sale or
delivery of the shares and related offering materials in the United Kingdom,
including:
. the Public Offers of Securities Regulations 1995;
. the Financial Services Act 1986; and
. the Financial Services Act 1986, (Investment Advertisement) (Exemptions)
Order 1996 (as amended).
S-39
<PAGE>
LEGAL OPINIONS
Conner & Winters, A Professional Corporation, Tulsa, Oklahoma, as our
counsel, will issue an opinion for us regarding the validity of the shares of
common stock offered by this prospectus supplement and the accompanying
prospectus. Certain legal matters related to this offering will be passed upon
for the underwriters by Baker & Botts, L.L.P.
EXPERTS
The review of estimated reserve evaluations and related calculations by
Ryder Scott Company, L.P., petroleum consultants, included in this prospectus
supplement and incorporated by reference in the accompanying prospectus have
been included and incorporated in reliance upon the authority of said firm as
experts in petroleum engineering.
INDEPENDENT ACCOUNTANTS
The financial statements of Unit Corporation as of December 31, 1997 and
1998 and for each of the three years in the period ended December 31, 1998
included in this prospectus supplement have been so included in reliance on the
report of PricewaterhouseCoopers LLP, independent accountants, given on the
authority of said firm as experts in auditing and accounting. With respect to
the unaudited consolidated financial information of Unit Corporation for the
six month periods ended June 30, 1998 and 1999, included in this prospectus
supplement, PricewaterhouseCoopers LLP reported that they have applied limited
procedures in accordance with professional standards for a review of such
information. However, their separate report dated August 9, 1999, appearing
herein, states that they did not audit and they do not express an opinion on
that unaudited consolidated financial information. Accordingly, the degree of
reliance on their reports on such information should be restricted in light of
the limited nature of the review procedures applied. PricewaterhouseCoopers LLP
is not subject to the liability provisions of Section 11 of the Securities Act
of 1933 for their report on the unaudited consolidated financial information
because that report is not a "report" or a "part" of the registration statement
prepared or certified by PricewaterhouseCoopers LLP within the meaning of
Sections 7 and 11 of the Securities Act.
S-40
<PAGE>
GLOSSARY OF CERTAIN OIL AND GAS TERMS
As used in this prospectus supplement, "Mcf" means thousand cubic feet,
"MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Bbl" means
barrel, "MBbls" means thousand barrels, "Btu" means British Thermal Unit, or
the quantity of heat required to raise the temperature of one pound of water by
one Degree Fahrenheit, "MMBtu" means one million Btus. "MMBbls" means million
barrels, "BOE" means equivalent barrels of oil, "MBOE" means thousand
equivalent barrels of oil, "MMBOE" means million equivalent barrels of oil,
"cfe" means equivalent cubic feet of gas and "Mcfe", "MMcfe" and "Bcfe" means
thousand, million and billion equivalent cubic feet of gas.
Unless otherwise indicated in this prospectus supplement, gas volumes are
stated at the legal pressure base of the state or area in which the reserves
are located and at 60 Fahrenheit. Equivalent barrels of oil or gas are
determined using the ratio of six Mcf of gas to one Bbl of oil.
"Finding and development cost" or "finding cost" means an amount per BOE or
Mcfe equal to the sum of all costs incurred relating to oil and gas property
acquisition, exploration and development activities divided by the sum of all
additions and revisions to estimated proved reserves, including reserve
purchases.
"Gross" refers to the total acres or wells in which we have a working
interest, and "net" refers to gross acres or wells multiplied by the percentage
working interest owned by us. "Net production" means production that is owned
by us less royalties and production due others.
"Oil" includes crude oil, condensate and natural gas liquids.
"PV-10" means the present value of estimated future net revenues to be
generated from the production of proved reserves, net of estimated production
and ad valorem taxes, future capital costs and operating expenses, using prices
and costs in effect as of the date indicated, without giving effect to federal
income taxes. The future net revenues have been discounted at an annual rate of
10% to determine their "present value." The present value is shown to indicate
the effect of time on the value of the revenue stream and should not be
construed as being the fair market value of the properties.
"Reserve replacement ratio" is calculated on a Mcfe basis by dividing the
estimated reserves added during a year from exploitation, development and
exploration activities, acquisitions of proved reserves and revisions of
previous estimates, excluding property sales, by the natural gas and oil
volumes produced during that year.
"SCR rig" means a diesel electric silicon controlled rectifier rig as
opposed to a mechanical rig powered by diesel engines. An SCR rig generally
allows for greater horsepower and more efficient distribution of power.
"Standardized measure of discounted future net cash flows" means the present
value of estimated future net cash flows to be generated from the production of
proved natural gas and oil reserves, computed using prices and costs as of the
dates indicated, after giving effect to federal income taxes and discounted at
an annual rate of 10%.
S-41
<PAGE>
INDEX TO FINANCIAL STATEMENTS
Financial Statements of Unit Corporation and Subsidiaries
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Accountants........................................ F-2
Consolidated Balance Sheets, December 31, 1997 and 1998.................. F-3
Consolidated Statements of Operations for the Years Ended December 31,
1996, 1997 and 1998..................................................... F-4
Consolidated Statements of Changes in Shareholders' Equity for the Years
Ended December 31, 1996, 1997 and 1998.................................. F-5
Consolidated Statements of Cash Flows for the Years Ended December 31,
1996, 1997 and 1998..................................................... F-6
Notes to Consolidated Financial Statements............................... F-7
Report of Review by Independent Accountants.............................. F-27
Consolidated Condensed Balance Sheets, December 31, 1998 and June 30,
1999 (Unaudited)........................................................ F-28
Consolidated Condensed Statements of Operations for the Six Months Ended
June 30, 1998 and 1999 (Unaudited)...................................... F-29
Consolidated Condensed Statements of Cash Flows for the Six Months Ended
June 30, 1998 and 1999 (Unaudited)...................................... F-30
Notes to Unaudited Consolidated Condensed Financial Statements........... F-31
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, changes in shareholder's equity and cash
flows present fairly in all material respects, the financial position of Unit
Corporation and its subsidiaries at December 31, 1997 and 1998, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted
accounting principles. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
financial statements in accordance with generally accepted auditing standards
which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 23, 1999
F-2
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
As of December 31,
--------------------
1997 1998
--------- ---------
(In thousands)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents............................... $ 458 $ 446
Accounts receivable (less allowance for doubtful
accounts of $354 and $274)............................. 19,813 13,149
Materials and supplies.................................. 3,535 3,298
Prepaid expenses and other.............................. 2,206 2,650
--------- ---------
Total current assets................................. 26,012 19,543
--------- ---------
Property and Equipment:
Drilling equipment...................................... 119,155 123,258
Oil and natural gas properties, on the full cost
method................................................. 233,659 271,960
Transportation equipment................................ 2,825 2,955
Other................................................... 6,948 6,870
--------- ---------
362,587 405,043
Less accumulated depreciation, depletion, amortization
and impairment......................................... 192,613 207,883
--------- ---------
Net property and equipment............................ 169,974 197,160
--------- ---------
Other Assets............................................. 6,511 6,361
--------- ---------
Total Assets............................................. $ 202,497 $ 223,064
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current portion of long-term liabilities and debt....... $ 727 $ 1,801
Accounts payable........................................ 11,112 8,517
Accrued liabilities..................................... 7,762 7,362
Contract advances....................................... 92 310
--------- ---------
Total current liabilities............................ 19,693 17,990
--------- ---------
Other Long-Term Liabilities (Note 5)..................... 2,279 2,301
--------- ---------
Long-Term Debt........................................... 54,100 72,900
--------- ---------
Deferred Income Taxes.................................... 17,560 18,583
--------- ---------
Commitments and Contingencies (Note 11)
Shareholders' Equity:
Preferred stock, $1.00 par value, 5,000,000 shares
authorized, none issued................................ -- --
Common stock, $.20 par value, 40,000,000 shares
authorized, 25,514,836 and 25,563,165 shares issued,
respectively........................................... 5,103 5,113
Capital in excess of par value.......................... 82,043 82,187
Retained earnings....................................... 21,875 24,121
Treasury stock, at cost (19,863 and 25,000 shares,
respectively).......................................... (156) (131)
--------- ---------
Total shareholders' equity........................... 108,865 111,290
--------- ---------
Total Liabilities and Shareholders' Equity............... $ 202,497 $ 223,064
========= =========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
F-3
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------
1996 1997 1998
------------- ------------- -------------
(In thousands except per share amounts)
<S> <C> <C> <C>
Revenues:
Contract drilling................... $ 28,819 $ 46,199 $ 53,528
Oil and natural gas................. 43,013 45,581 39,703
Other............................... 238 84 106
------------- ------------- -------------
Total revenues................... 72,070 91,864 93,337
------------- ------------- -------------
Expenses:
Contract drilling:
Operating costs.................... 24,259 36,419 43,729
Depreciation....................... 2,944 4,216 5,766
Oil and natural gas:
Operating costs.................... 13,409 13,201 14,328
Depreciation, depletion and
amortization...................... 10,807 12,625 16,069
General and administrative.......... 4,122 4,621 4,891
Interest............................ 3,162 2,921 4,815
------------- ------------- -------------
Total expenses................... 58,703 74,003 89,598
------------- ------------- -------------
Income Before Income Taxes........... 13,367 17,861 3,739
------------- ------------- -------------
Income Tax Expense:
Current............................. 4 118 139
Deferred............................ 5,030 6,619 1,354
------------- ------------- -------------
Total income taxes............... 5,034 6,737 1,493
------------- ------------- -------------
Net Income........................... $ 8,333 $ 11,124 $ 2,246
============= ============= =============
Net Income Per Common Share:
Basic............................... $ .37 $ .46 $ .09
============= ============= =============
Diluted............................. $ .37 $ .45 $ .09
============= ============= =============
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
F-4
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
YEAR ENDED DECEMBER 31, 1996, 1997 AND 1998
<TABLE>
<CAPTION>
Capital
In Excess
Common Of Par Retained Treasury
Stock Value Earnings Stock Total
------ --------- -------- -------- --------
(In thousands)
<S> <C> <C> <C> <C> <C>
Balances, January 1, 1996......... $4,195 $50,181 $ 2,418 $(188) $ 56,606
Net income....................... -- -- 8,333 -- 8,333
Activity in employee compensation
plans (321,667 shares).......... 64 615 -- 123 802
Issuance of stock on exercise of
warrants (2,859,555 shares)..... 572 11,939 -- -- 12,511
Purchase of treasury stock (5,000
shares) -- -- -- (42) (42)
------ ------- ------- ----- --------
Balances, December 31, 1996....... 4,831 62,735 10,751 (107) 78,210
Net income....................... -- -- 11,124 -- 11,124
Activity in employee compensation
plans (57,524 shares)........... 12 718 -- 89 819
Issuance of stock for acquisition
(1,300,000 shares).............. 260 18,590 -- -- 18,850
Purchase of treasury stock
(15,000 shares)................. -- -- -- (138) (138)
------ ------- ------- ----- --------
Balances, December 31, 1997....... 5,103 82,043 21,875 (156) 108,865
Net income....................... -- -- 2,246 -- 2,246
Activity in employee compensation
plans (48,329 shares)........... 10 144 -- 156 310
Purchase of treasury stock
(25,000 shares)................. -- -- -- (131) (131)
------ ------- ------- ----- --------
Balances, December 31, 1998....... $5,113 $82,187 $24,121 $(131) $111,290
====== ======= ======= ===== ========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
F-5
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------
1996 1997 1998
------- ------- -------
(In thousands)
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net Income......................................... $ 8,333 $11,124 $ 2,246
Adjustments to reconcile net income to net cash
provided (used) by operating activities:
Depreciation, depletion, and amortization......... 14,079 17,199 22,186
Loss (gain) on disposition of assets.............. (185) (94) 17
Employee stock compensation plans................. 214 244 561
Bad debt expense.................................. -- 250 --
Deferred tax expense.............................. 5,030 6,619 1,354
Changes in operating assets and liabilities
increasing (decreasing) cash:
Accounts receivable............................... (5,444) (1,762) 6,664
Materials and supplies............................ (254) (1,233) 237
Prepaid expenses and other........................ (418) (211) (444)
Accounts payable.................................. (2,288) 2,062 948
Accrued liabilities............................... 540 1,430 (27)
Contract advances................................. 890 (1,208) 218
Other liabilities................................. 167 (70) (447)
------- ------- -------
Net cash provided by operating activities....... 20,664 34,350 33,513
------- ------- -------
Cash Flows From Investing Activities:
Capital expenditures (including producing property
acquisitions)..................................... (34,111) (45,115) (53,654)
Cash received on acquisition of drilling company
(Note 2).......................................... -- 1,611 --
Proceeds from disposition of property and
equipment......................................... 1,009 792 964
(Acquisition) disposition of other assets.......... 215 (314) (93)
------- ------- -------
Net cash used in investing activities........... (32,887) (43,026) (52,783)
------- ------- -------
Cash Flows From Financing Activities:
Borrowings under line of credit.................... 31,500 34,400 52,700
Payments under line of credit...................... (32,000) (25,900) (32,900)
Net payments on notes payable and other long-term
debt.............................................. (20) -- (470)
Proceeds from sale of common stock................. 12,798 225 59
Acquisition of treasury stock...................... (42) (138) (131)
------- ------- -------
Net cash provided by financing activities....... 12,236 8,587 19,258
------- ------- -------
Net Increase (Decrease) in Cash and Cash
Equivalents........................................ 13 (89) (12)
Cash and Cash Equivalents, Beginning of Year........ 534 547 458
------- ------- -------
Cash and Cash Equivalents, End of Year.............. $ 547 $ 458 $ 446
======= ======= =======
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest.......................................... $ 3,189 $ 2,910 $ 4,064
Income taxes...................................... $ 63 $ 102 $ 507
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
F-6
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of Unit
Corporation and its directly and indirectly wholly owned subsidiaries (the
"Company"). The Company's investment in limited partnerships is accounted for
on the proportionate consolidation method, whereby its share of the
partnerships' assets, liabilities, revenues and expenses is included in the
appropriate classification in the accompanying consolidated financial
statements.
Nature of Business
The Company is engaged in the development, acquisition and production of oil
and natural gas properties and the land contract drilling of oil and natural
gas wells primarily in the Anadarko, Arkoma and South Texas Basins. These
basins are located in Oklahoma, Texas, Kansas and Arkansas. Additional
producing properties are located in Canada and other states, including New
Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana, Alabama,
Mississippi, Arkansas, Illinois and Nebraska. At December 31, 1998, the Company
has an interest in 2,563 wells and served as operator of 524 of those wells.
Land contract drilling of oil and natural gas wells is performed for a wide
range of customers using the drilling rigs owned and operated by the Company.
In 1998, 31 of the Company's 34 rigs were in operation.
Drilling Contracts
The Company recognizes revenues generated from "daywork" drilling contracts
as the services are performed, which is similar to the percentage of completion
method. For all contracts under which the Company bears the risk of completion
of the wells ("footage" and "turnkey" drilling contracts), revenues and
expenses are recognized using the completed contract method. The duration of
all three types of contracts range typically from 20 to 90 days. The entire
amount of the loss, if any, is recorded when the loss is determinable.
The costs of uncompleted drilling contracts include expenses incurred to
date on "footage" or "turnkey" drilling contracts which are still in process
and are included in other current assets.
Cash Equivalents and Short-Term Investments
The Company includes as cash equivalents, certificates of deposits and all
investments with maturities at date of purchase of three months or less which
are readily convertible into known amounts of cash.
Property and Equipment
Drilling equipment, transportation equipment and other property and
equipment are carried at cost. The Company provides for depreciation of
drilling equipment on the units-of-production method based on estimated useful
lives, including a minimum provision of 20 percent of the active rate when the
equipment is idle. The Company uses the composite method of depreciation for
drill pipe and collars and calculates the depreciation by footage actually
drilled compared to total estimated remaining footage. Depreciation of other
property and equipment is computed using the straight-line method over the
estimated useful lives of the assets ranging from 3 to 15 years.
Realization of the carrying value of the Company's property and equipment is
reviewed for possible impairment whenever events or changes in circumstances
indicate that the carrying amount may not be recoverable. Assets are determined
to be impaired if a forecast of undiscounted estimated future net operating
cash flows directly related to the asset including disposal value if any, is
less than the carrying amount of the
F-7
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
asset. If any asset is determined to be impaired, the loss is measured as the
amount by which the carrying amount of the asset exceeds its fair value. An
estimate of fair value is based on the best information available, including
prices for similar assets. Changes in such estimates could cause the Company to
reduce the carrying value of its property and equipment.
When property and equipment components are disposed of, the cost and the
related accumulated depreciation are removed from the accounts and any
resulting gain or loss is generally reflected in operations. For dispositions
of drill pipe and drill collars, an average cost for the appropriate feet of
drill pipe and drill collars is removed from the asset account and charged to
accumulated depreciation and proceeds, if any, are credited to accumulated
depreciation.
Goodwill
Goodwill represents the excess of the cost of the acquisition of Hickman
Drilling Company over the fair value of the net assets acquired and is being
amortized on the straight-line method over 25 years. Goodwill is evaluated
periodically for impairment, when it appears an impairment may have occurred,
based on the estimated undiscounted future cash flow of the acquired entity.
Net goodwill reported in other assets at December 31, 1997 and 1998 was
$6,061,000 and $5,818,000, respectively with accumulated amortization at
December 31, 1997 and 1998 of $20,000 and $264,000, respectively.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and development
activities on the full cost method of accounting prescribed by the Securities
and Exchange Commission ("SEC"). Accordingly, all productive and non-productive
costs incurred in connection with the acquisition, exploration and development
of oil and natural gas reserves are capitalized and amortized on a composite
units-of-production method based on proved oil and natural gas reserves. The
Company's determination of its oil and natural gas reserves are reviewed
annually by independent petroleum engineers. The average composite rates used
for depreciation, depletion and amortization ("DD&A") were $3.90, $4.49 and
$4.99 per equivalent barrel in 1996, 1997 and 1998, respectively. The Company's
calculation of DD&A includes estimated future expenditures to be incurred in
developing proved reserves and estimated dismantlement and abandonment costs,
net of estimated salvage values. In the event the unamortized cost of oil and
natural gas properties being amortized exceeds the full cost ceiling, as
defined by the SEC, the excess is charged to expense in the period during which
such excess occurs. The full cost ceiling is based principally on the estimated
future discounted net cash flows from the Company's oil and natural gas
properties. As discussed in Note 14, such estimates are imprecise. Changes in
these estimates or declines in oil and natural gas prices could cause the
Company in the near-term to reduce the carrying value of its oil and natural
gas properties.
No gains or losses are recognized upon the sale, conveyance or other
disposition of oil and natural gas properties unless a significant reserve
amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in
current operations for services performed on oil and natural gas properties in
which the Company has an interest or on properties in which a partnership, of
which the Company is a general partner, has an interest. Accordingly, in 1997
and 1998 the Company recorded $314,000 and $437,000 of contract drilling
profits, respectively, as a reduction of the carrying value of its oil and
natural gas properties rather than including these profits in current
operations. No contract drilling profits were realized on such interests in
1996.
Limited Partnerships
The Company's wholly owned subsidiary, Unit Petroleum Company, is a general
partner in fourteen oil and natural gas limited partnerships sold privately and
publicly. Certain of the Company's officers, directors and employees own
interests in most of these partnerships.
F-8
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company shares in partnership revenues and costs in accordance with
formulas prescribed in each limited partnership agreement. The partnerships
also reimburse the Company for certain administrative costs incurred on behalf
of the partnerships.
Income Taxes
Measurement of current and deferred income tax liabilities and assets is
based on provisions of enacted tax law; the effects of future changes in tax
laws or rates are not included in the measurement. Valuation allowances are
established where necessary to reduce deferred tax assets to the amount
expected to be realized. Income tax expense is the tax payable for the year and
the change during that year in deferred tax assets and liabilities.
Natural Gas Balancing
The Company uses the sales method for recording natural gas sales. This
method allows for recognition of revenue which may be more or less than the
Company's share of pro-rata production from certain wells. Based upon the
Company's 1998 average spot market natural gas price of $1.90 per Mcf, the
Company estimates its balancing position to be approximately $4.6 million on
under-produced properties and approximately $2.8 million on over-produced
properties.
The Company's policy is to expense its pro-rata share of lease operating
costs from all wells as incurred. Such expenses relating to the Company's
balancing position on wells in which the Company has imbalances are not
material.
Stock Based Compensation
The Company applies APB Opinion 25 in accounting for its stock option plans.
Under this standard, no compensation expense is recognized for grants of
options which include an exercise price equal to or greater than the market
price of the stock on the date of grant. Accordingly, based on the Company's
grants in 1996, 1997 and 1998 no compensation expense has been recognized. As
provided by Financial Accounting Standard No. 123 "Accounting for Stock-Based
Compensation," the Company has disclosed the pro forma effects of recording
compensation for such option grants based on fair value in Note 8 to the
financial statements.
Self Insurance
The Company utilizes self insurance programs for employee group health and
worker's compensation. Self insurance costs are accrued based upon the
aggregate of estimated liabilities for reported claims and claims incurred but
not yet reported.
Financial Instruments and Concentrations of Credit Risk
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of trade receivables with a
variety of national and international oil and natural gas companies. The
Company does not generally require collateral related to receivables. Such
credit risk is considered by management to be limited due to the large number
of customers comprising the Company's customer base. In addition, at December
31, 1997 and 1998, the Company had a concentration of cash of $0.3 million and
$1.5 million, respectively, with one bank.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and
F-9
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Earnings Per Share
In the fourth quarter of 1997, the Company adopted Financial Accounting
Standards Board Statement of Financial Accounting Standards No. 128, Earnings
Per Share ("FAS 128"). Earnings per share amounts for all previous periods
presented give effect to the application of FAS 128.
Impact of Financial Accounting Pronouncements
On June 15, 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (FAS 133). FAS 133 is effective for all
fiscal quarters of fiscal years beginning after June 15, 1999 (January 1, 2000
for the Company). FAS 133 requires that all derivative instruments be recorded
on the balance sheet at their fair value. Changes in the fair value of
derivatives are recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as part of a hedge
transaction and, if it is, the type of hedge transaction. Management of the
Company anticipates that, due to its limited use of derivative instruments, the
adoption of FAS 133 will not have a significant effect on the Company's results
of operations or its financial position.
NOTE 2--ACQUISITION OF DRILLING COMPANY
On November 20, 1997, the Company acquired Hickman Drilling Company. The
selling stockholders of Hickman Drilling Company received, in the aggregate,
1,300,000 shares of common stock valued at $18,850,000 and promissory notes of
$5,000,000 to be paid in five equal annual installments commencing January 2,
1999. The acquisition has been accounted for as a purchase and the results of
Hickman Drilling Company have been included in the accompanying consolidated
financial statements since the date of acquisition. The acquisition is
summarized as follows:
<TABLE>
<CAPTION>
(In thousands)
<S> <C>
Current assets net of current liabilities................... $ 2,072
Property and equipment...................................... 23,187
Goodwill.................................................... 6,081
Deferred tax liability--long-term........................... (7,490)
-------
Total acquisition......................................... $23,850
=======
</TABLE>
NOTE 3--EARNINGS PER SHARE
The following data shows the amounts used in computing earnings per share.
<TABLE>
<CAPTION>
For the Year Ended December 31, 1996
-----------------------------------------
Weighted
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------- -------------- ----------
<S> <C> <C> <C>
Basic earnings per common share...... $ 8,333,000 22,463,000 $ 0.37
========
Effect of dilutive stock options..... -- 302,000
------------- -------------
Diluted earnings per common share.... $ 8,333,000 22,765,000 $ 0.37
============= ============= ========
</TABLE>
F-10
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
<TABLE>
<CAPTION>
For the Year Ended December 31, 1997
-----------------------------------------
Weighted
Income Shares Per-Share
(Numerator) (Denominator) Amount
-------------- -------------- ----------
<S> <C> <C> <C>
Basic earnings per common share...... $ 11,124,000 24,327,000 $ 0.46
========
Effect of dilutive stock options..... -- 380,000
-------------- -------------
Diluted earnings per common share.... $ 11,124,000 24,707,000 $ 0.45
============== ============= ========
<CAPTION>
For the Year Ended December 31, 1998
-----------------------------------------
Weighted
Income Shares Per-Share
(Numerator) (Denominator) Amount
-------------- -------------- ----------
<S> <C> <C> <C>
Basic earnings per common share...... $ 2,246,000 25,544,000 $ 0.09
========
Effect of dilutive stock options..... -- 340,000
-------------- -------------
Diluted earnings per common share.... $ 2,246,000 25,884,000 $ 0.09
============== ============= ========
</TABLE>
The following options and their average exercise prices were not included in
the computation of diluted earnings per share because the option exercise
prices were greater than the average market price on common shares for the
years ended December 31,:
<TABLE>
<CAPTION>
1996 1997 1998
-------- ------ --------
<S> <C> <C> <C>
Options............................................... 161,500 2,500 191,000
======== ====== ========
Average exercise price................................ $ 8.60 $11.32 $ 8.60
======== ====== ========
</TABLE>
NOTE 4--WARRANTS
In 1987, the Company issued 2.873 million Units, consisting of three shares
of the Company's common stock and one warrant, at a price of $10.375 per Unit.
Each warrant entitled the holder to purchase one share of the Company's common
stock at a price of $4.375. Prior to the warrants expiration on August 30,
1996, 2.86 million warrants were exercised providing $12.5 million in
additional capital to the Company.
NOTE 5--OTHER LONG-TERM LIABILITIES
Other long-term liabilities consisted of the following as of December 31,
1997 and 1998:
<TABLE>
<CAPTION>
1997 1998
------- -------
(In thousands)
<S> <C> <C>
Natural gas purchaser prepayment............................ $2,206 $ 1,759
Separation benefit plan..................................... -- 1,012
Rig acquisition............................................. 800 331
------- -------
3,006 3,102
Less current portion........................................ 727 801
------- -------
$2,279 $ 2,301
======= =======
</TABLE>
In March 1988, the Company entered into a settlement agreement with a
natural gas purchaser. During early 1991, the Company and the natural gas
purchaser superseded the original agreement with a new settlement agreement
effective retroactively to January 1, 1991. Under these settlement agreements
F-11
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
("Settlement Agreement"), the Company has a prepayment balance of $1.8 million
at December 31, 1998 representing proceeds received from the purchaser as
prepayment for natural gas. This amount is net of natural gas recouped and net
of certain amounts disbursed to other owners (such owners, collectively with
the Company are referred to as the "Committed Interest") for their
proportionate share of the prepayments. At December 31, 1997, the Settlement
Agreement and the natural gas purchase contracts which were subject to the
Settlement Agreement terminated. The December 31, 1997 Prepayment Balance of
$2.2 million became payable in equal annual payments over a five year period.
The first payment of $441,000 was due and paid on June 1, 1998.
The Company has other long-term liabilities of $1,343,000, consisting of
$331,000 from the December 9, 1997 acquisition of a Mid-Continent U-36-A, 650
horsepower rig plus additional spare rig equipment and $1,012,000 from the
liability accrued for the Company's Separation Benefit Plan. The debt for rig
equipment is payable over a maximum of three years from the closing date of the
acquisition.
NOTE 6--LONG-TERM DEBT
Long-term debt consisted of the following as of December 31, 1997 and 1998:
<TABLE>
<CAPTION>
1997 1998
------- -------
(In thousands)
<S> <C> <C>
Revolving credit and term loan, with interest at December
31, 1997 and 1998 of 7.3 percent and 6.3 percent,
respectively............................................... $49,100 $68,900
Notes payable for Hickman Drilling Company acquisition with
interest at December 31, 1997 and 1998 of 8.5 percent and
7.8 percent, respectively.................................. 5,000 5,000
------- -------
54,100 73,900
Less current portion........................................ -- 1,000
------- -------
Total long-term debt...................................... $54,100 $72,900
======= =======
</TABLE>
At December 31, 1998, the Company's loan agreement ("Loan Agreement")
provided for a total loan commitment of $100 million consisting of a revolving
credit facility through May 1, 2002 and a term loan thereafter, maturing on May
1, 2005. Borrowings under the Loan Agreement are limited to a borrowing value
which as of December 31, 1998 was $85 million. The Loan Value under the
revolving credit facility is subject to a semi-annual redetermination
calculated as the sum of a percentage of the discounted future value of the
Company's oil and natural gas reserves, as determined by the banks, plus the
greater of (i) 50 percent of the appraised value of the Company's contract
drilling rigs or (ii) two times the previous 12 months cash flow from the
contract drilling rigs, limited in either case to $20 million. Any declines in
commodity prices would adversely impact the determination of the borrowing
value.
Borrowings under the revolving credit facility bear interest at the Chase
Manhattan Bank, N.A. prime rate ("Prime Rate") or the London Interbank Offered
Rates ("Libor Rate") plus .75 to 1.25 percent depending on the level of debt as
a percentage of the total borrowing base. Subsequent to May 1, 2002, borrowings
under the Loan Agreement bear interest at the Prime Rate plus .25 percent or
the Libor rate plus 1.0 to 1.5 percent depending on the level of debt as a
percentage of the total borrowing base.
At the Company's election, any portion of the debt outstanding may be fixed
at the Libor Rate for 30, 60, 90 or 180 days. During any Libor Rate funding
period the Company may not pay in part or in whole the outstanding principal
balance of the note to which such Libor Rate option applies. Borrowings under
the Prime Rate option may be paid anytime in part or in whole without premium
or penalty.
F-12
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company paid an origination fee of $85,000 at inception of the Loan
Agreement and a facility fee of 3/8 of one percent is charged for any unused
portion of the borrowing value. Virtually all of the Company's drilling rigs
are collateral for such indebtedness and the balance of the Company's assets
are subject to a negative pledge.
The Loan Agreement includes prohibitions against (i) the payment of
dividends (other than stock dividends) during any fiscal year in excess of 25
percent of the consolidated net income of the Company during the preceding
fiscal year, and only if working capital provided from operations during said
year is equal to or greater than 175 percent of current maturities of long-term
debt at the end of such year, (ii) the incurrence by the Company or any of its
subsidiaries of additional debt with certain very limited exceptions and (iii)
the creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any property of the Company or any of its
subsidiaries, except in favor of its banks. The Loan Agreement also requires
that the Company maintain consolidated net worth of at least $75 million, a
current ratio of not less than 1 to 1, a ratio of long-term debt, as defined in
the Loan Agreement, to consolidated tangible net worth not greater than 1.2 to
1 and a ratio of total liabilities, as defined in the Loan Agreement, to
consolidated tangible net worth not greater than 1.65 to 1. In addition,
working capital provided by operations, as defined in the Loan Agreement,
cannot be less than $18 million in any year.
In November 1997, the Company completed its acquisition of Hickman Drilling
Company. In association with this acquisition, the Company issued an aggregate
of $5.0 million in promissory notes payable in five equal annual installments
commencing January 2, 1999, with interest at the Prime Rate.
Estimated annual principal payments under the terms of all long-term
liabilities and debt from 1999 through 2003 are $1,801,000, $1,484,000,
$1,440,000, $14,837,000 and $23,967,000. Based on the borrowing rates currently
available to the Company for debt with similar terms and maturities, long-term
debt at December 31, 1998 approximates its fair value.
NOTE 7--INCOME TAXES
A reconciliation of the income tax expense, computed by applying the federal
statutory rate to pre-tax income to the Company's effective income tax expense
is as follows:
<TABLE>
<CAPTION>
1996 1997 1998
------ ------ ------
(In thousands)
<S> <C> <C> <C>
Income tax expense computed by applying the
statutory rate.................................... $4,545 $6,073 $1,271
State income tax, net of federal................... 499 733 150
Goodwill and other................................. (10) (69) 72
------ ------ ------
Income tax expense................................ $5,034 $6,737 $1,493
====== ====== ======
</TABLE>
F-13
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Deferred tax assets and liabilities are comprised of the following at
December 31, 1997 and 1998:
<TABLE>
<CAPTION>
1997 1998
-------- --------
(In thousands)
<S> <C> <C> <C>
Deferred tax assets:
Allowance for losses................................ $ 1,348 $ 1,680
Net operating loss carryforwards.................... 15,819 12,541
Statutory depletion carryforward.................... 2,260 2,260
Investment tax credit carryforward.................. 1,552 530
Alternative minimum tax credit carryforward......... 167 431
-------- --------
Gross deferred tax assets......................... 21,146 17,442
Valuation allowance................................. (1,552) (530)
Deferred tax liability--
Depreciation, depletion and amortization........... (37,154) (35,495)
-------- --------
Net deferred tax liability........................ $(17,560) $(18,583)
======== ========
</TABLE>
The deferred tax asset valuation allowance reflects that the investment tax
credit carryforwards may not be utilized before the expiration dates due in
part to the effects of anticipated future exploratory and development drilling
costs. The reduction in the valuation allowance was the result of the
expiration of investment tax credit carryforwards in 1998.
Realization of the deferred tax asset is dependent on generating sufficient
taxable income prior to expiration of loss carryforwards. Although realization
is not assured, management believes it is more likely than not that the
deferred tax asset will be realized. The amount of the deferred tax asset
considered realizable, however, could be reduced in the near-term if estimates
of future taxable income during the carryforward period are reduced.
At December 31, 1998, the Company has net operating loss carryforwards for
regular tax purposes of approximately $33,003,000 and net operating loss
carryforwards for alternative minimum tax purposes of approximately $19,953,000
which expire in various amounts from 2000 to 2011. The Company has investment
tax credit carryforwards of approximately $530,000 which expire from 1999 to
2000. In addition, a statutory depletion carryforward of approximately
$5,948,000, which may be carried forward indefinitely, is available to reduce
future taxable income, subject to statutory limitations.
NOTE 8--EMPLOYEE BENEFIT AND COMPENSATION PLANS
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common stock
were authorized for issuance under the Plan. On May 3, 1995, the Company's
shareholders approved and amended the Plan to increase by 250,000 shares the
aggregate number of shares of common stock that could be issued under the Plan.
Under the terms of the Plan, bonuses may be granted to employees in either cash
or stock or a combination thereof, and are payable in a lump sum or in annual
installments subject to certain restrictions. No shares were issued under the
Plan in 1996, 1997 or 1998.
On December 22, 1998, the Board of Directors approved a stock bonus of
87,376 shares of common stock to be issued on January 4, 1999 for payment of
the Company's year end bonuses.
The Company also has a Stock Option Plan which provides for the granting of
options for up to 1,500,000 shares of common stock to officers and employees.
The plan permits the issuance of qualified or nonqualified
F-14
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
stock options. Options granted become exercisable at the rate of 20 percent per
year one year after being granted and expire after ten years from the original
grant date. The exercise price for options granted to date was based on the
fair market value on the date of the grant.
Activity pertaining to the Stock Option Plan is as follows:
<TABLE>
<CAPTION>
Weighted
Number Average
Of Exercise
Shares Price
-------- --------
<S> <C> <C>
Outstanding at January 1, 1996............................ 865,600 $2.23
Granted.................................................. 149,500 8.75
Exercised................................................ (371,200) 1.59
Canceled................................................. (7,100) 2.92
-------- -----
Outstanding at December 31, 1996.......................... 636,800 4.13
Granted.................................................. 24,000 9.00
Exercised................................................ (56,440) 2.71
Canceled................................................. (30,200) 7.89
-------- -----
Outstanding at December 31, 1997.......................... 574,160 4.28
Granted.................................................. 226,000 3.96
Exercised................................................ (21,300) 2.71
Canceled................................................. (10,500) 7.05
-------- -----
Outstanding at December 31, 1998.......................... 768,360 $4.19
======== =====
</TABLE>
<TABLE>
<CAPTION>
Outstanding Options
-----------------------------------------------------------------
Weighted
Number Weighted Average Average
Exercise of Remaining Exercise
Prices Shares Contractual Life Price
-------- ------ ---------------- --------
<S> <C> <C> <C>
$2.37--$ 4.00 614,860 5.7 years $3.07
$7.25--$11.32 153,500 8.1 years $8.67
</TABLE>
<TABLE>
<CAPTION>
Exercisable Options
------------------------------------------------------
Weighted
Number Average
Exercise of Exercise
Prices Shares Price
-------- ------ --------
<S> <C> <C>
$2.37--$ 4.00 374,660 $2.68
$8.00--$11.32 52,000 $8.76
</TABLE>
Options for 375,000, 383,000 and 427,000 shares were exercisable with
weighted average exercise prices of $2.64, $3.01 and $3.42 at December 31,
1996, 1997 and 1998, respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the
Company's common stock may be issued upon exercise of the stock options. On the
first business day following each annual meeting of stockholders of the
Company, each person who is then a member of the Board of Directors of the
Company and who is not then an employee of the Company or any of its
subsidiaries will be granted an option to purchase 2,500 shares of common
stock. The option price for each stock option is the fair market value of the
common stock on the date the stock options are granted. No stock options may be
exercised during the first six months of its term except in case of death and
no stock options are exercisable after ten years from the date of grant.
F-15
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Activity pertaining to the Directors' Plan is as follows:
<TABLE>
<CAPTION>
Weighted
Number Average
Of Exercise
Shares Price
------ --------
<S> <C> <C>
Outstanding at January 1, 1996.............................. 42,500 $2.96
Granted.................................................... 12,500 6.88
------ -----
Outstanding at December 31, 1996............................ 55,000 3.85
Granted.................................................... 12,500 8.94
Exercised................................................... (7,500) 2.67
------ -----
Outstanding at December 31, 1997............................ 60,000 5.06
Granted.................................................... 12,500 9.00
------ -----
Outstanding at December 31, 1998............................ 72,500 $5.74
====== =====
</TABLE>
Outstanding Options And
Exercisable Options
<TABLE>
<CAPTION>
Weighted
Number Weighted Average Average
Exercise of Remaining Exercise
Prices Shares Contractual Life Price
-------- ------ ---------------- --------
<S> <C> <C> <C>
$1.75--$ 3.75 35,000 4.9 years $3.03
$6.87--$ 9.00 37,500 8.3 years $8.28
</TABLE>
The Company applies APB Opinion 25 in accounting for its Stock Option Plan
and Non-Employee Director's Stock Option Plan. Accordingly, based on the nature
of the Company's grants of options, no compensation cost has been recognized in
1996, 1997 and 1998. Had compensation been determined on the basis of fair
value pursuant to FASB Statement No. 123, net income and earnings per share
would have been reduced as follows:
<TABLE>
<CAPTION>
1996 1997 1998
------ ------- ------
<S> <C> <C> <C>
Net Income (In thousands):
As reported............................................. $8,333 $11,124 $2,246
------ ------- ------
Pro forma............................................... $8,244 $10,748 $1,933
====== ======= ======
Basic Earnings per Share:
As reported............................................. $ .37 $ .46 $ .09
------ ------- ------
Pro forma............................................... $ .37 $ .44 $ .08
====== ======= ======
Diluted Earnings per Share:
As reported............................................. $ .37 $ .45 $ .09
------ ------- ------
Pro forma............................................... $ .36 $ .43 $ .07
====== ======= ======
</TABLE>
The fair value of each option granted is estimated using the Black-Scholes
model. The Company's stock volatility was 0.51, 0.52 and 0.53 in 1996, 1997 and
1998, respectively, based on previous stock performance. Dividend yield was
estimated to remain at zero with a risk free interest rate of 6.55, 5.80 and
4.95 percent in 1996, 1997 and 1998, respectively. Expected life ranged from 1
to 10 years based on prior experience
F-16
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
depending on the vesting periods involved and the make up of participating
employees. The aggregate fair value of options granted during 1996, 1997 and
1998 under the Stock Option Plan were $753,000, $136,000 and $527,000,
respectively, and under the Non-Employee Stock Option Plan were $56,000,
$74,000 and $71,000, respectively.
Under the Company's 401(k) Employee Thrift Plan, employees who meet
specified service requirements may contribute a percentage of their total
compensation, up to a specified maximum, to the plan. Each employee's
contribution, up to a specified maximum, may be matched by the Company in full
or on a partial basis. The Company made discretionary contributions under the
plan of 44,686, 23,892 and 46,892 shares of common stock and recognized expense
of $268,000, $329,000 and $536,000 in 1996, 1997 and 1998, respectively.
The Company provides a salary deferral plan ("Deferral Plan") which allows
participants to defer the recognition of salary for income tax purposes until
actual distribution of benefits which occurs at either termination of
employment, death or certain defined unforeseeable emergency hardships. Funds
set aside in a trust to satisfy the Company's obligation under the Deferral
Plan at December 31, 1997 and 1998 totaled $752,000 and $1,035,000,
respectively. The Company recognizes payroll expense and records a liability at
the time of deferral.
Effective January 1, 1997, the Company adopted a separation benefit plan
("Separation Plan"). The Separation Plan allows eligible employees whose
employment with the Company is involuntarily terminated or, in the case of an
employee who has completed 20 years of service, voluntarily or involuntarily
terminated, to receive benefits equivalent to 4 week's salary for every whole
year of service completed with the Company up to a maximum of 104 weeks.
Benefits received under the Separation Plan will be reduced by the amount of
any other benefits received from other disability or severance plans which may
be in effect during the payment period. To receive payments the recipient must
waive any claims against the Company in exchange for receiving the separation
benefits. On October 28, 1997, the Company adopted a Separation Benefit Plan
for Senior Management ("Senior Plan"). The Senior Plan provides certain
officers and key executives of the Company with benefits generally equivalent
to the Separation Plan. The Compensation Committee of the Board of Directors
has absolute discretion in the selection of the individuals covered in this
plan. The Company recognized expense of $466,000 and $577,000 in 1997 and 1998,
respectively, for benefits associated with anticipated payments from both
separation plans.
NOTE 9--TRANSACTIONS WITH RELATED PARTIES
The Company formed private limited partnerships (the "Partnerships") with
certain qualified employees, officers and directors from 1984 through 1998,
with a subsidiary of the Company serving as General Partner. The Partnerships
were formed for the purpose of conducting oil and natural gas acquisition,
drilling and development operations and serving as co-general partner with the
Company in any additional limited partnerships formed during that year. The
Partnerships participated on a proportionate basis with the Company in most
drilling operations and most producing property acquisitions commenced by the
Company for its own account during the period from the formation of the
Partnership through December 31 of each year.
Amounts received in the years ended December 31 from both public and private
Partnerships for which the Company is a general partner are as follows:
<TABLE>
<CAPTION>
1996 1997 1998
---- ---- ----
(In thousands)
<S> <C> <C> <C>
Contract drilling............................................ $ 37 $135 $180
Well supervision and other fees.............................. $349 $384 $415
General and administrative expense reimbursement............. $105 $119 $133
</TABLE>
F-17
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Related party transactions for contract drilling and well supervision fees
are the related party's share of such costs. These costs are billed to related
parties on the same basis as billings to unrelated parties for such services.
General and administrative reimbursements are both direct general and
administrative expense incurred on the related party's behalf and indirect
expenses allocated to the related parties. Such allocations are based on the
related party's level of activity and are considered by management to be
reasonable.
A subsidiary of the Company paid the Partnerships, for which the Company or
a subsidiary is the general partner, $31,000, $32,000 and $21,000 during the
years ended December 31, 1996, 1997 and 1998, respectively, for purchases of
natural gas production.
During 1996 and 1997 a bank owned by one of the Company's former Directors
was a participant in the Company's Loan Agreement. The bank's pro rata share
of the Company's line of credit was limited to an amount not to exceed $1.5
million.
NOTE 10--SHAREHOLDER RIGHTS PLAN
The Company maintains a Shareholder Rights Plan (the "Plan") designed to
deter coercive or unfair takeover tactics, to prevent a person or group from
gaining control of the Company without offering fair value to all shareholders
and to deter other abusive takeover tactics which are not in the best interest
of shareholders.
Under the terms of the Plan, each share of common stock is accompanied by
one right, which given certain acquisition and business combination criteria,
entitles the shareholder to purchase from the Company one one-hundredth of a
newly issued share of Series A Participating Cumulative Preferred Stock at a
price subject to adjustment by the Company or to purchase from an acquiring
Company certain shares of its common stock or the surviving company's common
stock at 50 percent of its value.
The rights become exercisable 10 days after the Company learns that an
acquiring person (as defined in the Plan) has acquired 15 percent or more of
the outstanding common stock of the Company or 10 business days after the
commencement of a tender offer which would result in a person owning 15
percent or more of such shares. The Company can redeem the rights for $0.01
per right at any date prior to the earlier of (i) the close of business on the
tenth day following the time the Company learns that a person has become an
acquiring person or (ii) May 19, 2005 (the "Expiration Date"). The rights will
expire on the Expiration Date, unless redeemed earlier by the Company.
NOTE 11--COMMITMENTS AND CONTINGENCIES
The Company leases office space under the terms of operating leases
expiring through January 31, 2002. Future minimum rental payments under the
terms of the leases are approximately $372,000, $104,000, $73,000 and $7,000
in 1999, 2000, 2001 and 2002, respectively. No minimum rental payments are due
in 2003. Total rent expense incurred by the Company was $323,000, $373,000 and
$412,000 in 1996, 1997 and 1998, respectively.
The Company had letters of credit supported by its Loan Agreement totaling
$210,000 at December 31, 1998.
The Company as a 40 percent owner in a corporation which provides gas
gathering services, guarantees certain indebtedness of that corporation up to
a maximum of $2 million (approximately $950,000 at December 31, 1998). The
guarantee extends for a period ending on June 21, 2001.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income
Limited Partnership agreements along with the employee oil and gas limited
partnerships require, upon the election of a limited partner, that the Company
repurchase the limited partner's interest at amounts to be determined by
appraisal in the future. Such repurchases in any one year are limited to 20
percent of the units outstanding. The Company
F-18
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
made repurchases of $30,000 and $15,000 in 1996 and 1998, respectively, for
such limited partners' interests and did not make any such repurchases in 1997.
The Company is a party to various legal proceedings arising in the ordinary
course of its business none of which, in the Company's opinion, will result in
judgements which would have a material adverse effect on the Company.
NOTE 12--INDUSTRY SEGMENT INFORMATION
In 1998, the Company adopted Statement of Financial Accounting Standard No.
131 "Disclosures about Segments of an Enterprise and Related Information." The
Company has two business segments: Contract Drilling and Oil and Natural Gas,
representing its two strategic business units offering different products and
services. The Contract Drilling segment provides land contract drilling of oil
and natural gas wells and the Oil and Natural Gas segment is engaged in the
development, acquisition and production of oil and natural gas properties.
The accounting policies of the segments are the same as those described in
the Summary of Significant Accounting Policies (Note 1). The Company evaluates
the performance of its operating segments based on operating income, which is
defined as operating revenues less operating expenses and depreciation,
depletion and amortization. The Company has natural gas production in Canada
which is not significant.
<TABLE>
<CAPTION>
1996 1997 1998
-------- -------- --------
(In thousands)
<S> <C> <C> <C>
Revenues:
Contract drilling................................ $ 28,819 $ 46,199 $ 53,528
Oil and natural gas.............................. 43,013 45,581 39,703
Other............................................ 238 84 106
-------- -------- --------
Total revenues.................................. $ 72,070 $ 91,864 $ 93,337
======== ======== ========
Operating Income (1):
Contract drilling................................ $ 1,616 $ 5,564 $ 4,033
Oil and natural gas.............................. 18,797 19,755 9,306
-------- -------- --------
Total operating income.......................... 20,413 25,319 13,339
General and administrative expenses.............. (4,122) (4,621) (4,891)
Interest expense................................. (3,162) (2,921) (4,815)
Other income (expense)-- net..................... 238 84 106
-------- -------- --------
Income before income taxes...................... $ 13,367 $ 17,861 $ 3,739
======== ======== ========
Identifiable Assets (2):
Contract drilling................................ $ 24,500 $ 66,188 $ 69,147
Oil and natural gas.............................. 110,207 132,332 150,718
-------- -------- --------
Total identifiable assets....................... 134,707 198,520 219,865
Corporate assets................................. 3,286 3,977 3,199
-------- -------- --------
Total assets.................................... $137,993 $202,497 $223,064
======== ======== ========
Capital Expenditures:
Contract drilling................................ $ 9,910 $ 35,193 $ 11,485
Oil and natural gas.............................. 25,644 33,525 38,409
Other............................................ 989 1,464 216
-------- -------- --------
Total capital expenditures...................... $ 36,543 $ 70,182 $ 50,110
======== ======== ========
</TABLE>
F-19
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
<TABLE>
<CAPTION>
1996 1997 1998
------- ------- -------
(In thousands)
<S> <C> <C> <C>
Depreciation, Depletion and Amortization:
Contract drilling....................................... $ 2,944 $ 4,216 $ 5,766
Oil and natural gas..................................... 10,807 12,625 16,069
Other................................................... 328 358 351
------- ------- -------
Total depreciation, depletion and amortization......... $14,079 $17,199 $22,186
======= ======= =======
</TABLE>
- --------
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion and amortization and does not include non-operating
revenues, general corporate expenses, interest expense or income taxes.
(2) Identifiable assets are those used in the Company's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements,
furniture and equipment.
NOTE 13--SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 1997 and 1998 is as follows:
<TABLE>
<CAPTION>
Three Months Ended
-----------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(In thousands except per share amounts)
<S> <C> <C> <C> <C>
Year ended December 31, 1997:
Revenues............................. $24,322 $19,806 $21,585 $26,151
======= ======= ======= =======
Gross profit(1)...................... $ 7,970 $ 4,161 $ 5,227 $ 7,961
======= ======= ======= =======
Income before income taxes........... $ 6,219 $ 2,299 $ 3,409 $ 5,934
======= ======= ======= =======
Net Income........................... $ 3,874 $ 1,432 $ 2,121 $ 3,697
======= ======= ======= =======
Earnings per common share:
Basic............................... $ .16 $ .06 $ .09 $ .15
======= ======= ======= =======
Diluted (2)......................... $ .16 $ .06 $ .09 $ 15
======= ======= ======= =======
Year ended December 31, 1998:
Revenues............................. $24,249 $26,054 $23,627 $19,407
======= ======= ======= =======
Gross profit(1)...................... $ 3,471 $ 4,450 $ 3,537 $ 1,881
======= ======= ======= =======
Income before income taxes........... $ 1,163 $ 2,053 $ 1,136 $ (613)
======= ======= ======= =======
Net Income........................... $ 725 $ 1,235 $ 654 $ (368)
======= ======= ======= =======
Earnings per common share:
Basic (2)........................... $ .03 $ .05 $ .03 $ (.01)
======= ======= ======= =======
Diluted (2)......................... $ .03 $ .05 $ .03 $ (.01)
======= ======= ======= =======
</TABLE>
- --------
(1) Gross profit excludes other revenues, general and administrative expense
and interest expense.
(2) Due to the effect of price changes of the Company's stock, diluted earnings
per share for the year's four quarters, which includes the effect of
potential dilutive common shares calculated during each quarter, does not
equal the annual diluted earnings per share, which includes the effect of
such potential dilutive common shares calculated for the entire year.
F-20
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
NOTE 14--OIL AND NATURAL GAS INFORMATION (UNAUDITED)
The capitalized costs at year end and costs incurred during the year were as
follows:
<TABLE>
<CAPTION>
USA CANADA TOTAL
--------- ------ ---------
(In thousands)
<S> <C> <C> <C>
1996:
Capitalized costs:
Proved properties................................ $ 195,528 $ 480 $ 196,008
Unproved properties.............................. 4,602 -- 4,602
--------- ----- ---------
200,130 480 200,610
Less accumulated depreciation, depletion,
amortization and impairment..................... (102,463) (389) (102,852)
--------- ----- ---------
Net capitalized costs........................... $ 97,667 $ 91 $ 97,758
========= ===== =========
Cost incurred:
Unproved properties.............................. $ 1,640 $ -- $ 1,640
Producing properties............................. 2,338 -- 2,338
Exploration...................................... 1,501 -- 1,501
Development...................................... 20,150 15 20,165
--------- ----- ---------
Total costs incurred............................ $ 25,629 $ 15 $ 25,644
========= ===== =========
1997:
Capitalized costs:
Proved properties................................ $ 225,166 $ 480 $ 225,646
Unproved properties.............................. 7,935 78 8,013
--------- ----- ---------
233,101 558 233,659
Accumulated depreciation, depletion, amortization
and impairment.................................. (115,000) (405) (115,405)
--------- ----- ---------
Net capitalized costs........................... $ 118,101 $ 153 $ 118,254
========= ===== =========
Cost incurred:
Unproved properties.............................. $ 3,540 $ 78 $ 3,618
Producing properties............................. 1,518 -- 1,518
Exploration...................................... 1,785 -- 1,785
Development...................................... 26,604 -- 26,604
--------- ----- ---------
Total costs incurred............................ $ 33,447 $ 78 $ 33,525
========= ===== =========
1998:
Capitalized costs:
Proved properties................................ $ 261,299 $ 480 $ 261,779
Unproved properties.............................. 9,900 281 10,181
--------- ----- ---------
271,199 761 271,960
Less accumulated depreciation, depletion,
amortization and impairment..................... (130,894) (412) (131,306)
--------- ----- ---------
Net capitalized costs........................... $ 140,305 $ 349 $ 140,654
========= ===== =========
Cost incurred:
Unproved properties.............................. $ 4,297 $ 203 $ 4,500
Producing properties............................. 9,026 -- 9,026
Exploration...................................... 2,270 -- 2,270
Development...................................... 22,613 -- 22,613
--------- ----- ---------
Total costs incurred............................ $ 38,206 $ 203 $ 38,409
========= ===== =========
</TABLE>
F-21
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The results of operations for producing activities are provided below.
<TABLE>
<CAPTION>
USA CANADA TOTAL
-------- ------ --------
(In thousands)
<S> <C> <C> <C>
1996:
Revenues........................................... $ 40,432 $ 60 $ 40,492
Production costs................................... (11,195) (14) (11,209)
Depreciation, depletion and amortization........... (10,723) (11) (10,734)
-------- ---- --------
18,514 35 18,549
Income tax expense................................. (6,986) (15) (7,001)
-------- ---- --------
Results of operations for producing activities
(excluding corporate overhead and financing
costs)............................................ $ 11,528 $ 20 $ 11,548
======== ==== ========
1997:
Revenues........................................... $ 42,830 $ 69 $ 42,899
Production costs................................... (10,678) (24) (10,702)
Depreciation, depletion and amortization........... (12,537) (16) (12,553)
-------- ---- --------
19,615 29 19,644
Income tax expense................................. (7,394) (17) (7,411)
-------- ---- --------
Results of operations for producing activities
(excluding corporate overhead and financing
costs)............................................ $ 12,221 $ 12 $ 12,233
======== ==== ========
1998:
Revenues........................................... $ 36,861 $ 55 $ 36,916
Production costs................................... (11,572) (20) (11,592)
Depreciation, depletion and amortization........... (15,893) (8) (15,901)
-------- ---- --------
9,396 27 9,423
Income tax expense................................. (3,752) (9) (3,761)
-------- ---- --------
Results of operations for producing activities
(excluding corporate overhead and financing
costs)............................................ $ 5,644 $ 18 $ 5,662
======== ==== ========
</TABLE>
F-22
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Estimated quantities of proved developed oil and natural gas reserves and
changes in net quantities of proved developed and undeveloped oil and natural
gas reserves were as follows:
<TABLE>
<CAPTION>
USA CANADA TOTAL
--------------- ------------ ----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------ ------- ---- ------- ------ --------
(In thousands)
<S> <C> <C> <C> <C> <C> <C>
1996:
Proved developed and
undeveloped reserves:
Beginning of year............ 5,428 107,950 -- 778 5,428 108,728
Revision of previous
estimates................... (387) (3,822) -- 26 (387) (3,796)
Extensions, discoveries and
other additions............. 718 34,625 -- -- 718 34,625
Purchases of minerals in
place....................... 67 3,036 -- -- 67 3,036
Sales of minerals in place... (43) (407) -- -- (43) (407)
Production................... (579) (12,974) -- (51) (579) (13,025)
------ ------- ---- ---- ------ --------
End of Year.................. 5,204 128,408 -- 753 5,204 129,161
====== ======= ==== ==== ====== ========
Proved developed reserves:
Beginning of year............ 4,697 94,975 -- 350 4,697 95,325
End of year.................. 4,509 107,536 -- 326 4,509 107,862
1997:
Proved developed and
undeveloped reserves:
Beginning of year............ 5,204 128,408 -- 753 5,204 129,161
Revision of previous
estimates................... (927) (12,780) -- 44 (927) (12,736)
Extensions, discoveries and
other additions............. 399 41,108 -- -- 399 41,108
Purchases of minerals in
place....................... 6 2,618 -- -- 6 2,618
Sales of minerals in place... (58) (951) -- -- (58) (951)
Production................... (493) (13,742) -- (74) (493) (13,816)
------ ------- ---- ---- ------ --------
End of Year.................. 4,131 144,661 -- 723 4,131 145,384
====== ======= ==== ==== ====== ========
Proved developed reserves:
Beginning of year............ 4,509 107,536 -- 326 4,509 107,862
End of year.................. 3,406 115,071 -- 295 3,406 115,366
1998:
Proved developed and
undeveloped reserves:
Beginning of year............ 4,131 144,661 -- 723 4,131 145,384
Revision of previous
estimates................... (1,142) (5,207) -- (162) (1,142) (5,369)
Extensions, discoveries and
other additions............. 445 31,460 -- -- 445 31,460
Purchases of minerals in
place....................... 257 6,840 -- -- 257 6,840
Sales of minerals in place... (3) (532) -- -- (3) (532)
Production................... (443) (16,427) -- (38) (443) ( 16,465)
------ ------- ---- ---- ------ --------
End of Year.................. 3,245 160,795 -- 523 3,245 161,318
====== ======= ==== ==== ====== ========
Proved developed reserves:
Beginning of year............ 3,406 115,071 -- 295 3,406 115,366
End of year.................. 2,365 119,415 -- 421 2,365 119,836
</TABLE>
Oil and natural gas reserves cannot be measured exactly. Estimates of oil
and natural gas reserves require extensive judgments of reservoir engineering
data and are generally less precise than other estimates made in connection
with financial disclosures. The Company utilizes Ryder Scott Company,
independent petroleum consultants, to review the Company's reserves as prepared
by the Company's reservoir engineers.
F-23
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Proved reserves are those quantities which, upon analysis of geological and
engineering data, appear with reasonable certainty to be recoverable in the
future from known oil and natural gas reservoirs under existing economic and
operating conditions. Proved developed reserves are those reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are those reserves which are
expected to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required.
Estimates of oil and natural gas reserves require extensive judgments of
reservoir engineering data as previously explained. Assigning monetary values
to such estimates does not reduce the subjectivity and changing nature of such
reserve estimates. Indeed the uncertainties inherent in the disclosure are
compounded by applying additional estimates of the rates and timing of
production and the costs that will be incurred in developing and producing the
reserves. The information set forth herein is therefore subjective and, since
judgments are involved, may not be comparable to estimates submitted by other
oil and natural gas producers. In addition, since prices and costs do not
remain static and no price or cost escalations or de-escalations have been
considered, the results are not necessarily indicative of the estimated fair
market value of estimated proved reserves nor of estimated future cash flows.
The standardized measure of discounted future net cash flows ("SMOG") was
calculated using year-end prices and costs, and year-end statutory tax rates,
adjusted for permanent differences, that relate to existing proved oil and
natural gas reserves. SMOG as of December 31 is as follows:
<TABLE>
<CAPTION>
USA CANADA TOTAL
--------- ------- ---------
(In thousands)
<S> <C> <C> <C>
1996:
Future cash flows.............................. $ 626,945 $ 2,735 $ 629,680
Future production and development costs........ (171,749) (339) (172,088)
Future income tax expenses..................... (125,540) (1,422) (126,962)
--------- ------- ---------
Future net cash flows.......................... 329,656 974 330,630
10% annual discount for estimated timing of
cash flows.................................... (129,610) (368) (129,978)
--------- ------- ---------
Standardized measure of discounted future net
cash flows relating to proved oil and natural
gas reserves.................................. $ 200,046 $ 606 $ 200,652
========= ======= =========
1997:
Future cash flows.............................. $ 427,292 $ 1,684 $ 428,976
Future production and development costs........ (153,220) (312) (153,532)
Future income tax expenses..................... (63,868) (794) (64,662)
--------- ------- ---------
Future net cash flows.......................... 210,204 578 210,782
10% annual discount for estimated timing of
cash flows.................................... (71,768) (187) (71,955)
--------- ------- ---------
Standardized measure of discounted future net
cash flows relating to proved oil and natural
gas reserves.................................. $ 138,436 $ 391 $ 138,827
========= ======= =========
1998:
Future cash flows.............................. 388,887 1,089 389,976
Future production and development costs........ (154,843) (271) (155,114)
Future income tax expenses..................... (47,305) (160) (47,465)
--------- ------- ---------
Future net cash flows.......................... 186,739 658 187,397
10% annual discount for estimated timing of
cash flows.................................... (62,770) (259) (63,029)
--------- ------- ---------
Standardized measure of discounted future net
cash flows relating to proved oil and natural
gas reserves.................................. $ 123,969 $ 399 $ 124,368
========= ======= =========
</TABLE>
F-24
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The principal sources of changes in the standardized measure of discounted
future net cash flows were as follows:
<TABLE>
<CAPTION>
USA CANADA TOTAL
--------- ------ ---------
(In thousands)
<S> <C> <C> <C>
1996:
Sales and transfers of oil and natural gas
produced, net of production costs............... $ (29,237) $ (46) $ (29,283)
Net changes in prices and production costs....... 92,541 738 93,279
Revisions in quantity estimates and changes in
production timing............................... (13,390) 58 (13,332)
Extensions, discoveries and improved recovery,
less related costs.............................. 69,942 -- 69,942
Purchases of minerals in place................... 5,821 -- 5,821
Sales of minerals in place....................... (514) -- (514)
Accretion of discount............................ 12,101 71 12,172
Net change in income taxes....................... (44,039) (470) (44,509)
Other - net...................................... 3,998 (60) 3,938
--------- ----- ---------
Net change....................................... 97,223 291 97,514
Beginning of year................................ 102,823 315 103,138
--------- ----- ---------
End of year...................................... $ 200,046 $ 606 $ 200,652
========= ===== =========
1997:
Sales and transfers of oil and natural gas
produced, net of production costs............... $ (32,152) $ (45) $ (32,197)
Net changes in prices and production costs....... (111,745) (651) (112,396)
Revisions in quantity estimates and changes in
production timing............................... (19,377) 47 (19,330)
Extensions, discoveries and improved recovery,
less related costs.............................. 46,787 -- 46,787
Purchases of minerals in place................... 2,235 -- 2,235
Sales of minerals in place....................... (2,282) -- (2,282)
Accretion of discount............................ 26,227 147 26,374
Net change in income taxes....................... 33,473 345 33,818
Other - net...................................... (4,776) (58) (4,834)
--------- ----- ---------
Net change....................................... (61,610) (215) (61,825)
Beginning of year................................ 200,046 606 200,652
--------- ----- ---------
End of year...................................... $ 138,436 $ 391 $ 138,827
========= ===== =========
1998:
Sales and transfers of oil and natural gas
produced, net of production costs............... $ (25,289) $ (35) $ (25,324)
Net changes in prices and production costs....... (35,654) (186) (35,840)
Revisions in quantity estimates and changes in
production timing............................... (17,020) (335) (17,355)
Extensions, discoveries and improved recovery,
less related costs.............................. 24,256 -- 24,256
Purchases of minerals in place................... 6,062 -- 6,062
Sales of minerals in place....................... (603) -- (603)
Accretion of discount............................ 16,719 91 16,810
Net change in income taxes....................... 16,083 486 16,569
Other - net...................................... 979 (13) 966
--------- ----- ---------
Net change....................................... (14,467) 8 (14,459)
Beginning of year................................ 138,436 391 138,827
--------- ----- ---------
End of year...................................... $ 123,969 $ 399 $ 124,368
========= ===== =========
</TABLE>
F-25
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company's SMOG and changes therein were determined in accordance with
Statement of Financial Accounting Standards No. 69. Certain information
concerning the assumptions used in computing SMOG and their inherent
limitations are discussed below. Management believes such information is
essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect management's
expectations of actual revenues to be derived from those reserves nor their
present worth. Assigning monetary values to the reserve quantity estimation
process does not reduce the subjective and ever-changing nature of such reserve
estimates. Additional subjectivity occurs when determining present values
because the rate of producing the reserves must be estimated. In addition to
errors inherent in predicting the future, variations from the expected
production rate could result from factors outside of management's control, such
as unintentional delays in development, environmental concerns or changes in
prices or regulatory controls. Also, the reserve valuation assumes that all
reserves will be disposed of by production. However, other factors such as the
sale of reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end prices of oil and
natural gas relating to proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided by
contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of existing
economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates to the future pretax net cash flows relating to proved oil
and natural gas reserves less the tax basis of the Company's properties. The
future income tax expenses also give effect to permanent differences and tax
credits and allowances relating to the Company's proved oil and natural gas
reserves.
Care should be exercised in the use and interpretation of the above data. As
production occurs over the next several years, the results shown may be
significantly different as changes in production performance, petroleum prices
and costs are likely to occur.
In early 1999, the oil and natural gas industry has experienced a downturn
in natural gas prices. The Company's reserves were determined at December 31,
1998 using an oil and natural gas price of $11.10 per barrel and $2.08 per Mcf.
During February 1999, the oil and natural gas prices received by the Company
were approximately $11.62 and $1.74, respectively. The decreases in natural gas
prices would have a significant effect on the SMOG value of the Company's
reserves at December 31, 1998 and would result in a provision to reduce the
carrying value of oil and natural gas properties of approximately $22 million
before taxes.
F-26
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
We have reviewed the accompanying consolidated condensed balance sheet of
Unit Corporation and subsidiaries as of June 30, 1999 and the related
consolidated condensed statements of operations and cash flows for the six
month periods ended June 30, 1998 and 1999. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical review
procedures to financial data and making inquiries of persons responsible for
financial and accounting matters. It is substantially less in scope than an
audit conducted in accordance with generally accepted accounting standards, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to the accompanying condensed consolidated financial statements
for them to be in conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted auditing
standards, the consolidated balance sheet of Unit Corporation and subsidiaries
at December 31, 1998, and the related consolidated statements of operations,
changes in shareholders' equity and cash flows for the year then ended (not
presented herein); and our report dated February 23, 1999 expressed an
unqualified opinion on those consolidated financial statements. In our opinion,
the information set forth in the accompanying consolidated condensed balance
sheet at December 31, 1998, is fairly stated in all material respects in
relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
August 9, 1999
F-27
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31, June 30,
1998 1999
------------ ----------
(Unaudited)
(In thousands)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents............................ $ 446 $ 455
Accounts receivable.................................. 13,149 12,526
Other................................................ 5,948 5,208
-------- --------
Total current assets................................ 19,543 18,189
-------- --------
Property and Equipment:
Total cost........................................... 405,043 413,977
Less accumulated depreciation, depletion,
amortization and impairment......................... 207,883 218,046
-------- --------
Net property and equipment.......................... 197,160 195,931
-------- --------
Other Assets.......................................... 6,361 6,305
-------- --------
Total Assets.......................................... $223,064 $220,425
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current portion of long-term debt.................... $ 1,801 $ 1,735
Accounts payable..................................... 8,517 9,044
Accrued liabilities.................................. 7,672 7,274
-------- --------
Total current liabilities........................... 17,990 18,053
-------- --------
Long-Term Debt........................................ 72,900 72,900
-------- --------
Other Long-Term Liabilities........................... 2,301 2,069
-------- --------
Deferred Income Taxes................................. 18,583 17,415
-------- --------
Shareholders' Equity:
Preferred stock, $1.00 par value, 5,000,000 shares
authorized, none issued............................. -- --
Common stock $.20 par value, 40,000,000 shares
authorized, 25,563,165 and 25,740,160 shares issued,
respectively........................................ 5,113 5,148
Capital in excess of par value....................... 82,187 82,867
Retained earnings.................................... 24,121 21,973
Treasury stock, at cost, 25,000 and 0 shares,
respectively........................................ (131) --
-------- --------
Total shareholders' equity.......................... 111,290 109,988
-------- --------
Total Liabilities and Shareholders' Equity............ $223,064 $220,425
======== ========
</TABLE>
The accompanying notes are an integral part of the consolidated condensed
financial statements.
F-28
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
Six Months
Ended June 30,
---------------
1998 1999
------- -------
(In thousands
except per
share amounts)
<S> <C> <C>
Revenues:
Contract drilling............................................ $30,383 $22,370
Oil and natural gas.......................................... 19,759 16,436
Other........................................................ 161 370
------- -------
Total revenues............................................. 50,303 39,176
------- -------
Expenses:
Contract drilling:
Operating costs............................................. 24,540 20,252
Depreciation and amortization............................... 2,874 2,811
Oil and natural gas:
Operating costs............................................. 7,276 6,595
Depreciation, depletion and amortization.................... 7,531 7,943
General and administrative................................... 2,507 2,474
Interest..................................................... 2,359 2,432
------- -------
Total expenses............................................. 47,087 42,507
------- -------
Income (Loss) Before Income Taxes............................. 3,216 (3,331)
------- -------
Income Tax Expense (Benefit):
Current...................................................... 57 (17)
Deferred..................................................... 1,199 (1,166)
------- -------
Total income taxes......................................... 1,256 (1,183)
------- -------
Net Income (Loss)............................................. $ 1,960 $(2,148)
======= =======
Net Income (Loss) Per Common Share:
Basic........................................................ $ .08 $ (.08)
======= =======
Diluted...................................................... $ .08 $ (.08)
======= =======
</TABLE>
The accompanying notes are an integral part of the consolidated condensed
financial statements.
F-29
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
------------------
1998 1999
-------- --------
(In thousands)
<S> <C> <C>
Cash Flows From Operating Activities:
Net Income (Loss)......................................... $ 1,960 $ (2,148)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization................. 10,569 10,909
Deferred income tax expense.............................. 1,199 (1,166)
Other-net................................................ 219 64
Changes in operating assets and liabilities increasing
(decreasing) cash:
Accounts receivable...................................... 5,155 623
Accounts payable......................................... 3,824 2,772
Other-net................................................ (1,314) 517
-------- --------
Net cash provided by operating activities............... 21,612 11,571
-------- --------
Cash Flows From (Used In) Investing Activities:
Capital expenditures...................................... (34,567) (12,144)
Proceeds from disposition of assets....................... 463 711
Other-net................................................. (118) (66)
-------- --------
Net cash used in investing activities................... (34,222) (11,499)
-------- --------
Cash Flows From (Used In) Financing Activities:
Net borrowings (payments) under line of credit............ 13,000 --
Net payments of notes payable and long-term debt.......... (214) (110)
Other-net................................................. (40) 47
-------- --------
Net cash provided by (used in) financing activities..... 12,746 (63)
-------- --------
Net Increase in Cash and Cash Equivalents.................. 136 9
Cash and Cash Equivalents, Beginning of Year............... 458 446
-------- --------
Cash and Cash Equivalents, End of Period................... $ 594 $ 455
======== ========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the six months ended June 30, for:
Interest................................................. $ 2,057 $ 2,663
Income taxes............................................. $ 20 $ --
</TABLE>
The accompanying notes are an integral part of the consolidated condensed
financial statements.
F-30
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
NOTE 1--BASIS OF PREPARATION AND PRESENTATION
In the opinion of the Company, the accompanying unaudited consolidated
condensed financial statements contain all adjustments necessary (all
adjustments are of a normal recurring nature) to present fairly the
consolidated financial position of Unit Corporation and subsidiaries as of June
30, 1999 and the results of their operations and cash flows for the six month
periods ended June 30, 1998 and 1999. Results for the six months ended June 30,
1999 are not necessarily indicative of the results to be realized during the
full year. The year end consolidated condensed balance sheet data was derived
from audited financial statements but does not include all disclosures required
by generally accepted accounting principles. The condensed financial statements
should be read in conjunction with the Company's Annual Report on Form 10-K for
the year ended December 31, 1998. Our independent accountants have performed a
review of these interim financial statements in accordance with standards
established by the American Institute of Certified Public Accountants. Pursuant
to Rule 436(c) under the Securities Act of 1933, their report of that review
should not be considered a part of any registration statements prepared or
certified by them within the meaning of Sections 7 and 11 of that Act.
NOTE 2--EARNINGS PER SHARE
The following data shows the amounts used in computing earnings (loss) per
share for the Company.
<TABLE>
<CAPTION>
For the Six Months Ended June 30,
1998
--------------------------------------
Income Weighted Shares Per-Share
(Numerator) (Denominator) Amount
----------- --------------- ---------
<S> <C> <C> <C>
Basic earnings per common share......... $ 1,960,000 25,546,000 $ 0.08
======
Effect of dilutive stock options........ -- 295,000
----------- ----------
Diluted earnings per common share....... $ 1,960,000 25,841,000 $ 0.08
=========== ========== ======
<CAPTION>
For the Six Months Ended June 30,
1999
--------------------------------------
Income Weighted Shares Per-Share
(Numerator) (Denominator) Amount
----------- --------------- ---------
<S> <C> <C> <C>
Basic loss per common share............. $(2,148,000) 25,701,000 $(0.08)
======
Effect of dilutive stock options........ -- --
----------- ----------
Diluted loss per common share........... $(2,148,000) 25,701,000 $(0.08)
=========== ========== ======
</TABLE>
The following options to purchase shares of common stock have been excluded
from the computation of diluted earnings per share for the six months ended
June 30, 1999 due to the net loss and for the six months ended June 30, 1998
due to the options exercise prices being greater than the average market price
of common shares:
<TABLE>
<CAPTION>
1998 1999
-------- --------
<S> <C> <C>
Options............................................... 171,000 844,000
======== ========
Average exercise price................................ $ 8.80 $ 4.36
======== ========
</TABLE>
NOTE 3--NEW ACCOUNTING PRONOUNCEMENTS
On June 15, 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (FAS 133). In June 1999, FAS 133 was amended
by FAS 137, Accounting for Derivative Instruments and Hedging Activities--
Deferral of the Effective Date of FASB Statement No. 133--an amendment of FASB
Statement No. 133
F-31
<PAGE>
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(FAS 137). FAS 133 is now effective for all fiscal quarters of fiscal years
beginning after June 15, 2000 (January 1, 2001 for the Company). FAS 133
requires that all derivative instruments be recorded on the balance sheet at
their fair value. Changes in the fair value of derivatives are recorded each
period in current earnings or other comprehensive income, depending on whether
a derivative is designated as part of a hedge transaction and, if it is, the
type of hedge transaction. Management of the Company anticipates that, due to
its limited use of derivative instruments, the adoption of FAS 133 will not
have a significant effect on the Company's results of operations or its
financial position.
NOTE 4--INDUSTRY SEGMENT INFORMATION
The Company has two business segments: Contract Drilling and Oil and Natural
Gas, representing its two strategic business units offering different products
and services. The Contract Drilling segment provides land contract drilling of
oil and natural gas wells and the Oil and Natural Gas segment is engaged in the
development, acquisition and production of oil and natural gas properties. The
Company evaluates the performance of its operating segments based on operating
income, which is defined as operating revenues less operating expenses and
depreciation, depletion and amortization. The Company has natural gas
production in Canada which is not significant. Information regarding the
Company's operations by industry segment for the six months ended June 30, 1998
and 1999 is as follows:
<TABLE>
<CAPTION>
Six Months
Ended June 30,
----------------
1998 1999
------- -------
(In thousands)
<S> <C> <C>
Revenues:
Contract drilling........................................ $30,383 $22,370
Oil and natural gas...................................... 19,759 16,436
Other.................................................... 161 370
------- -------
Total revenues............................................ $50,303 $39,176
======= =======
Operating Income (Loss)(1):
Contract drilling........................................ $ 2,969 $ (693)
Oil and natural gas...................................... 4,952 1,898
------- -------
Total operating income.................................. 7,921 1,205
General and administrative expense....................... (2,507) (2,474)
Interest expense......................................... (2,359) (2,432)
Other income - net....................................... 161 370
------- -------
Income (loss) before income taxes....................... $ 3,216 $(3,331)
======= =======
</TABLE>
- --------
(1) Operating income is total operating revenues less operating expenses,
depreciation, depletion and amortization and does not include non-operating
revenues, general corporate expenses, interest expense or income taxes.
F-32
<PAGE>
Prospectus
- --------------------------------------------------------------------------------
$100,000,000
----------------
UNIT CORPORATION
Debt Securities
Preferred Stock
Common Stock
Warrants
- --------------------------------------------------------------------------------
We may offer and sell, together or separately, from time to time in one or
more offerings:
. unsecured debt securities consisting of senior notes and debentures and
subordinated notes and debentures, and/or other unsecured evidences of
indebtedness in one or more series;
. shares of preferred stock, in one or more series, which may be
convertible into or exchangeable for common stock or debt securities;
. shares of common stock; and
. warrants to purchase debt securities, preferred stock or common stock.
We will provide the specific terms of the securities in supplements to this
prospectus. You should read this prospectus and any supplements to this
prospectus carefully before you invest in the securities.
This prospectus may not be used to sell securities unless accompanied by a
supplement to this prospectus.
----------------
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offence.
----------------
This Prospectus is dated August 3, 1999.
<PAGE>
ABOUT THIS PROSPECTUS
This prospectus is part of a registration statement that we filed with the
SEC utilizing a "shelf" registration process. Under this shelf process, we may,
from time to time, sell any combination of the securities described in this
prospectus in one or more offerings up to a total dollar amount of
$100,000,000.
This prospectus provides you with a general description of the securities we
may offer. Each time we sell securities, we will provide a prospectus
supplement that will contain specific information about the terms of that
offering. The prospectus supplement also may add, update or change information
contained in this prospectus. You should read both this prospectus and any
prospectus supplement together with additional information described under the
heading below "Where You Can Find More Information About the Company."
You should rely only on the information or representations incorporated by
reference or provided in this prospectus and in the accompanying prospectus
supplement. We have not authorized anyone to provide you with different
information. You may obtain copies of the registration statement, or of any
document which we have filed as an exhibit to the registration statement or to
any other SEC filing, either from the SEC or from the corporate secretary of
the company as described below. We are not making an offer of these securities
in any state where the offer is not permitted. You should not assume that the
information in this prospectus or in the accompanying prospectus supplement is
accurate as of any date other than the dates printed on the front of each such
document.
WHERE YOU CAN FIND MORE
INFORMATION ABOUT THE COMPANY
We file annual, quarterly and special reports, proxy statements and other
information with the SEC. You may read and copy any document filed by us at the
SEC's public reference rooms located at 450 Fifth Street, N.W., Judiciary
Plaza, Room 1024, Washington, D.C. 20549; at regional offices of the SEC at the
Northwestern Atrium Center, 500 West Madison Street, Suite 1400, Chicago,
Illinois 60661-2511; and at 7 World Trade Center, New York, New York 10048. You
may call the SEC at 1-800-SEC-0330 for further information on the public
reference rooms. Our filings are also available to the public from the SEC's
Internet web site at http://www.sec.gov. Information concerning us also may be
inspected at the New York Stock Exchange offices located at 20 Broad Street,
New York, New York 10005.
The SEC allows us to "incorporate by reference" the information we file with
them, which means that we can disclose important information to you by
referring you to those documents. The information incorporated by reference is
considered to be part of this prospectus and information we file later with the
SEC will automatically update and supersede the information in this prospectus.
We incorporate by reference the documents issued below and any future filings
we make with the SEC under Section 13(a), 13(c), 14 or 15(d) of the Securities
Exchange Act of 1934 until we sell all of the securities:
. Our Annual Report on Form 10-K for the fiscal year ended December 31,
1998;
. Our Quarterly Report on Form 10-Q for the quarterly period ended March
31, 1999; and
. The description of rights to purchase preferred stock contained in the
Company's registration statement on Form 8-A filed with the SEC on May
23, 1995.
We will provide, without charge, to each person to whom a copy of this
prospectus has been delivered, a copy of any of the documents referred to above
as being incorporated by reference. You may request a copy of these filings by
writing or telephoning Mr. Mark E. Schell, General Counsel and Corporate
Secretary, Unit Corporation, 1000 Kensington Tower I, 7130 South Lewis, Tulsa,
Oklahoma 74136 (telephone 918/493-7700).
2
<PAGE>
THE COMPANY
Unit Corporation is an independent energy company engaged, through its
subsidiaries, in the exploration and production of oil and natural gas, the
acquisition of producing oil and natural gas properties and the contract
drilling of onshore oil and natural gas wells. Our operations are principally
located in the Mid-Continent region, as well as the Permian and Gulf Coast
Basins of the United States.
Our principal executive offices are located at 1000 Kensington Tower I, 7130
South Lewis, Tulsa, Oklahoma 74136, and our telephone number is (918) 493-7700.
FORWARD-LOOKING STATEMENTS
This prospectus, including the information we incorporate by reference,
information included in, or incorporated by reference from, future filings by
us with the SEC, as well as information contained in written material, press
releases and oral statements issued by or on behalf of us, contain, or may
contain, certain statements that may be deemed to be "forward-looking
statements" within the meaning of federal securities laws. All statements,
other than statements of historical facts, included or incorporated by
reference in this prospectus, which address activities, events or developments
which we expect or anticipate will or may occur in the future are forward-
looking statements. The words "believes," "intends," "expects," "anticipates,"
"projects," "estimates," "predicts" and similar expressions are also intended
to identify forward-looking statements.
These forward-looking statements include, among others, such things as:
. our Year 2000 plans;
. the amount and nature of future capital expenditures;
. wells to be drilled or reworked;
. oil and gas prices and demand;
. exploitation and exploration prospects;
. estimates of proved oil and gas reserves;
. reserve potential;
. development and infill drilling potential;
. drilling prospects;
. expansion and other development trends of the oil and gas industry;
. business strategy;
. production of oil and gas reserves;
. expansion and growth of our business and operations; and
. drilling rig utilization and drilling rig rates.
These statements are based on certain assumptions and analyses made by us in
light of our experience and our perception of historical trends, current
conditions and expected future developments as well as other factors we believe
are appropriate in the circumstances. However, whether actual results and
developments will conform to our expectations and predictions is subject to a
number of risks and uncertainties which could cause actual results to differ
materially from our expectations, including:
. the risk factors discussed in this prospectus and in the documents we
incorporate by reference;
. general economic, market or business conditions;
3
<PAGE>
. the nature or lack of business opportunities that may be presented to
and pursued by us;
. demand for land drilling services;
. changes in laws or regulations; and
. other factors, most of which are beyond our control.
RATIO OF EARNINGS TO FIXED CHARGES
The following table sets forth our ratio of earnings to fixed charges for
the periods indicated:
<TABLE>
<CAPTION>
Three Months
Year Ended December 31, Ended March 31,
------------------------ ---------------
1994 1995 1996 1997 1998 1998 1999
---- ---- ---- ---- ---- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
Ratio of Earnings to Fixed Charges.. 3.70 1.92 5.09 6.87 1.75 2.04 N/A
</TABLE>
Earnings were inadequate by $1,976,000 in the three months ended Mach 31,
1999 to cover fixed charges. Earnings available for fixed charges represent
earnings from continuing operations before income taxes and fixed charges.
Fixed charges represent interest incurred and guaranteed plus that portion of
rental expense deemed to be the equivalent of interest. We are a guarantor of
$879,000 and $521,000 at March 31, 1999 and December 31, 1998, respectively, of
debt of a less-than-fifty-percent-owned company accounted for under the equity
method. The amount of fixed charges associated with this guarantee is $15,000
for the three month period ended March 31, 1999 and $20,000 for the year ended
December 31, 1998, which amounts are included in the computation of the ratio.
USE OF PROCEEDS
Except as otherwise described in any prospectus supplement, the net proceeds
from the sale of securities offered from time to time will be used for general
corporate purposes, which may include:
. repayment or refinancing of indebtedness;
. working capital;
. capital expenditures;
. oil and gas property or drilling rig acquisitions; and
. repurchases and redemption's of securities.
DESCRIPTION OF DEBT SECURITIES
The following description of the terms of the debt securities, which may
consist of senior notes and debentures and subordinated notes and debentures
(the "Debt Securities"), sets forth certain general terms and provisions of the
Debt Securities to which any prospectus supplement may relate. The particular
terms of the Debt Securities offered by any prospectus supplement and the
extent, if any, to which such general provisions may apply to the Debt
Securities being offered will be described in the prospectus supplement
relating to such Debt Securities. Accordingly, for a description of the terms
of a particular issue of Debt Securities, reference should be made to both the
prospectus supplement and to the following description.
The Debt Securities will be unsecured general obligations of the Company and
may be subordinated to our "Senior Indebtedness" (as defined below) to the
extent set forth in the applicable prospectus supplement. See "Description of
Debt Securities--Subordination" below. Debt Securities will be issued under an
indenture (the "Indenture") to be entered into between the Company and an
indenture trustee to be selected by the Company and named in a prospectus
supplement (the "Trustee"). A copy of the form of Indenture has been filed as
an
4
<PAGE>
exhibit to the registration statement. The following discussion of certain
provisions of the Indenture is a summary only and does not purport to be a
complete description of the terms and provisions of the Indenture. Accordingly,
the following discussion is qualified in its entirety by reference to the
provisions of the Indenture. Capitalized terms used in the following summary
but not defined have the meanings specified in the Indenture.
General
The Indenture does not limit the aggregate principal amount of Debt
Securities that may be issued. We may issue the Debt Securities from time to
time in one or more series. The Indenture does not limit the amount of other
unsecured indebtedness or securities which may be issued by the Company. Unless
otherwise indicated in the applicable prospectus supplement, the Debt
Securities will not benefit from any covenant or other provision that would
afford holders of Debt Securities special protection in the event of a highly
leveraged transaction involving the Company. Reference is made to the
applicable prospectus supplement for the following terms of the Debt Securities
of the series with respect to which the prospectus supplement is being
delivered:
. the title of Debt Securities of the series;
. any limit on the aggregate principal amount of the Debt Securities of
the series;
. the date or dates on which the principal and premium, if any, with
respect to the Debt Securities of the series are payable;
. the rate or rates (which may be fixed or variable), or the method of
determination of the rate or rates, at which the Debt Securities of the
series will bear interest, the date or dates from which such interest
shall accrue, the interest payment dates on which such interest will be
payable or the method by which such date will be determined, the record
dates for the determination of holders of Debt Securities of the series
to whom such interest is payable, and the basis upon which interest will
be calculated if other than that of a 360-day year of twelve 30-day
months;
. the place or places of payment, if any, in addition to or instead of the
corporate trust office of the Trustee where the principal, premium, if
any, and interest with respect to Debt Securities of the series will be
payable;
. the price or prices at which, the period or periods within which, and
the terms and conditions upon which Debt Securities of the series may be
redeemed, in whole or in part, at the option of the Company or
otherwise;
. the obligation, if any, of the Company to redeem, purchase, or repay
Debt Securities of the series pursuant to any sinking fund or analogous
provisions or at the option of a holder of Debt Securities of the series
and the price or prices at which, the period or periods within which,
and the terms and conditions upon which Debt Securities of the series
will be redeemed, purchased, or repaid, in whole or in part, pursuant to
such obligations;
. the terms, if any, upon which the Debt Securities of the series may be
convertible into or exchanged for securities of the Company or any other
issuer or obligor and the terms and conditions upon which such
conversion or exchange will be effected, including the initial
conversion or exchange price or rate, the conversion or exchange period
and any other provision in addition to or in lieu of those described
herein;
. if other than denominations of $1,000 or any integral multiple of
$1,000, the denominations in which Debt Securities of the series will be
issuable;
. if the amount of principal, premium, if any, or interest with respect to
the Debt Securities of the series may be determined with reference to an
index or pursuant to a formula, the manner in which such amounts will be
determined;
. if the principal amount payable at the stated maturity of Debt
Securities of the series will not be determinable as of any one or more
dates prior to such stated maturity, the amount that will be deemed to
5
<PAGE>
be such principal amount as of any such date for any purpose, including
the principal amount that will be due and payable upon any maturity other
than the stated maturity or that will be deemed to be outstanding as of
any such date (or, in such case, the manner in which such deemed principal
amount is to be determined), and if necessary, the manner of determining
the equivalent principal amount in United States currency;
. any changes or additions to the provisions of the Indenture dealing with
defeasance, including the addition of additional covenants that may be
subject to the Company's covenant defeasance option;
. if other than United States dollars, the coin or currency or currencies
or units of two or more currencies in which payment of the principal,
premium, if any, and interest with respect to Debt Securities of the
series shall be payable;
. if other than the principal amount of Debt Securities of the series, the
portion of the principal amount of Debt Securities of the series which
shall be payable upon declaration of acceleration or provable in
bankruptcy;
. the terms, if any, of the transfer, mortgage, pledge or assignment as
security for the Debt Securities of the series of any properties,
assets, moneys, proceeds, securities or other collateral, including
whether certain provisions of the Trust Indenture Act are applicable and
any corresponding changes to provisions of the Indenture as currently in
effect;
. any addition to or change in the Events of Default with respect to the
Debt Securities of the series and any change in the right of the Trustee
or the holders to declare the principal of and interest on such Debt
Securities due and payable;
. whether the Debt Securities of the series will be issued in whole or in
part in global form, the terms and conditions, if any, upon which any
global security may be exchanged in whole or in part for other
individual Debt Securities in definitive registered form and the
depositary for any such global security;
. any trustees, authenticating or paying agents, transfer agents or
registrars;
. the applicability of, and any addition to or change in the covenants and
definitions currently set forth in the Indenture or in the terms
relating to permitted consolidations, mergers, or sales of assets,
including conditioning any merger, conveyance, transfer or lease
permitted by the Indenture upon the satisfaction of an Indebtedness
coverage standard by the Company and Successor Company;
. the terms, if any, of any guarantee of the payment of principal of, and
premium, if any, and interest on, Debt Securities of the series and any
corresponding changes to the provisions of the Indenture as currently in
effect;
. the subordination, if any, of the Debt Securities of the series and any
changes or additions to the provisions of the Indenture relating to
subordination;
. if Debt Securities of the series do not bear interest, the dates for
certain required reports to the Trustee; and
. any other terms of the Debt Securities of the series (which terms shall
not be prohibited by the Indenture).
The prospectus supplement will also describe any material United States
federal income tax consequences or other special considerations applicable to
the series of Debt Securities offered, including those applicable to:
. Debt Securities with respect to which payments of principal, premium, or
interest are determined with reference to an index or formula (including
changes in prices of particular securities, currencies, or commodities);
. Debt Securities with respect to which principal, premium, or interest is
payable in a foreign or composite currency;
6
<PAGE>
. Debt Securities that are issued at a discount below their stated
principal amount, bearing no interest or interest at a rate that at the
time of issuance is below market rates ("Original Issue Discount Debt
Securities"); and
. variable rate Debt Securities that are exchangeable for fixed rate Debt
Securities.
Payments of interest on Debt Securities shall be made at the corporate trust
office of the Trustee or at the option of the Company by check mailed to the
registered holders of Debt Securities or, if so provided in the applicable
prospectus supplement, at the option of a holder by wire transfer to an account
designated by such holder.
Unless otherwise provided in the applicable prospectus supplement, Debt
Securities may be transferred or exchanged at the office of the Trustee at
which its corporate trust business is principally administered in the United
States or at the office of the Trustee or the Trustee's agent in the Borough of
Manhattan, the City and State of New York, at which its corporate agency
business is conducted, subject to the limitations provided in the Indenture,
without the payment of any service charge, other than any applicable tax or
governmental charge.
Global Securities
The Debt Securities of a series may be issued in whole or in part in the
form of one or more fully registered global securities (a "Global Security")
that will be deposited with a depositary or its nominee identified in the
prospectus supplement relating to such series. In such case, one or more Global
Securities will be issued in a denomination or aggregate denominations equal to
the portion of the aggregate principal amount of outstanding registered Debt
Securities of the series to be represented by such Global Security or
Securities. Unless and until it is exchanged in whole or in part for Debt
Securities in definitive registered form, a Global Security may not be
transferred except as a whole by the depositary for such Global Security to a
nominee of such depositary or by a nominee of such depositary to such
depositary or another nominee of such depositary or by such depositary or any
such nominee to a successor of such depositary or a nominee of such successor.
The specific terms of the depositary arrangement with respect to any portion
of a series of Debt Securities to be represented by a Global Security will be
described in the prospectus supplement relating to such series. The Company
anticipates that the following provisions will apply to all depositary
arrangements.
Upon the issuance of a Global Security, the depositary for such Global
Security will credit, on its book-entry registration and transfer system, the
respective principal amounts of the Debt Securities represented by such Global
Security to the accounts of persons that have accounts with such depositary
("participants"). The amounts to be credited shall be designated by any
underwriters or agents participating in the distribution of such Debt
Securities. Ownership of beneficial interests in a Global Security will be
limited to participants or persons that may hold interests through
participants. Ownership of beneficial interests in such Global Security will be
shown on, and the transfer of that ownership will be effected only through,
records maintained by the depositary for such Global Security (with respect to
interests of participants) or by participants or persons that hold through
participants (with respect to interests of persons other than participants). So
long as the depositary for a Global Security, or its nominee, is the registered
owner of such Global Security, such depositary or such nominee, as the case may
be, will be considered the sole owner or holder of the Debt Securities
represented by such Global Security for all purposes under the Indenture.
Except as set forth below, owners of beneficial interests in a Global Security
will not be entitled to have the Debt Securities represented by such Global
Security registered in their names, will not receive or be entitled to receive
physical delivery of such Debt Securities in definitive form and will not be
considered the owners or holders of such Debt Securities under the Indenture.
Principal, premium, if any, and interest payments on Debt Securities
represented by a Global Security registered in the name of a depositary or its
nominee will be made to such depositary or its nominee, as the
7
<PAGE>
case may be, as the registered owner of such Global Security. None of the
Company, the Trustee or any paying agent for such Debt Securities will have any
responsibility or liability for any aspect of the records relating to or
payments made on account of beneficial ownership interests in such Global
Securities or for maintaining, supervising or reviewing any records relating to
such beneficial ownership interests.
The Company expects that the depositary for any Debt Securities represented
by a Global Security, upon receipt of any payment of principal, premium, or
interest, will immediately credit participants' accounts with payments in
amounts proportionate to their respective beneficial interests in the principal
amount of such Global Security as shown on the records of such depositary. The
Company also expects that payments by participants to owners of beneficial
interests in such Global Security held through such participants will be
governed by standing instructions and customary practices, as is now the case
with the securities held for the accounts of customers registered in "street
name," and will be the responsibility of such participants.
If the depositary for any Debt Securities represented by a Global Security
is at any time unwilling or unable to continue as depositary and a successor
depositary is not appointed by the Company within 90 days, the Company will
issue such Debt Securities in definitive form in exchange for such Global
Security. In addition, the Company may at any time and in its sole discretion
determine not to have any of the Debt Securities of a series represented by one
or more Global Securities and, in such event, will issue Debt Securities of
such series in definitive form in exchange for the Global Security or
Securities representing such Debt Securities.
Subordination
Debt Securities may be subordinated ("Subordinated Debt Securities") in
right of payment, to the extent and in the manner set forth in the Indenture
and the applicable prospectus supplement, to the prior payment of all
Indebtedness of the Company that is designated as "Senior Indebtedness." Senior
Indebtedness, with respect to any series of Subordinated Debt Securities, will
consist of any Indebtedness of the Company that is designated in a resolution
of the Company's Board of Directors or the supplemental Indenture establishing
such series as Senior Indebtedness with respect to such series.
Upon any payment or distribution of assets of the Company to creditors or
upon a total or partial liquidation or dissolution of the Company or in a
bankruptcy, receivership, or similar proceeding relating to the Company or its
property, holders of Senior Indebtedness shall be entitled to receive payment
in full in cash of the Senior Indebtedness before holders of Subordinated Debt
Securities shall be entitled to receive any payment of principal, premium, or
interest with respect to the Subordinated Debt Securities, and until the Senior
Indebtedness is paid in full, any distribution to which holders of Subordinated
Debt Securities would otherwise be entitled shall be made to the holders of
Senior Indebtedness (except that such holders may receive shares of stock and
any debt securities that are subordinated to Senior Indebtedness to at least
the same extent as the Subordinated Debt Securities).
The Company may not make any payments of principal, premium, or interest
with respect to Subordinated Debt Securities, make any deposit for the purpose
of defeasance of such Subordinated Debt Securities, or repurchase, redeem, or
otherwise retire (except, in the case of Subordinated Debt Securities that
provide for a mandatory sinking fund, by the delivery of Subordinated Debt
Securities by the Company to the Trustee in satisfaction of the Company's
sinking fund obligation) any Subordinated Debt Securities if:
(a) any principal, premium, if any, or interest with respect to Senior
Indebtedness is not paid within any applicable grace period (including
at maturity), or
(b) any other default on Senior Indebtedness occurs and the maturity of
such Senior Indebtedness is accelerated in accordance with its terms,
unless, in either case,
(i) the default has been cured or waived and such acceleration has
been rescinded,
8
<PAGE>
(ii) such Senior Indebtedness has been paid in full in cash, or
(iii) the Company and the Trustee receive written notice approving such
payment from the representatives of each issue of "Designated
Senior Indebtedness" (which will include any specified issue of
Senior Indebtedness).
During the continuance of any default (other than a default described in
clause (a) or (b) above) with respect to any Senior Indebtedness pursuant to
which the maturity of such Senior Indebtedness may be accelerated immediately
without further notice (except any notice required to effect the acceleration)
or the expiration of any applicable grace periods, the Company may not pay the
Subordinated Debt Securities for a period (the "Payment Blockage Period")
commencing on the receipt by the Company and the Trustee of written notice of
such default from the representative of any Designated Senior Indebtedness
specifying an election to effect a Payment Blockage Period (a "Blockage
Notice") and expiring 179 days thereafter. The Payment Blockage Period may be
terminated before its expiration by written notice to the Trustee and the
Company from the person who gave the Blockage Notice, by repayment in full in
cash of the Senior Indebtedness with respect to which the Blockage Notice was
given, or because the default giving rise to the Payment Blockage Period is no
longer continuing. Unless the holders of such Senior Indebtedness shall have
accelerated the maturity of such Senior Indebtedness, the Company may resume
payments on the Subordinated Debt Securities after the expiration of the
Payment Blockage Period. Not more than one Blockage Notice may be given in any
period of 360 consecutive days unless the first Blockage Notice within such
360-day period is given by or on behalf of holders of Designated Senior
Indebtedness other than the Bank Indebtedness, in which case the representative
of the Bank Indebtedness may give another Blockage Notice within such period.
In no event, however, may the total number of days during which any Payment
Blockage Period or Periods is in effect exceed 179 days in the aggregate during
any period of 360 consecutive days. After all Senior Indebtedness is paid in
full and until the Subordinated Debt Securities are paid in full, holders of
the Subordinated Debt Securities shall be subrogated to the rights of holders
of Senior Indebtedness to receive distributions applicable to Senior
Indebtedness.
As a result of the subordination provisions, in the event of the Company's
bankruptcy or insolvency, creditors of the Company who are holders of Senior
Indebtedness, as well as certain general creditors of the Company, may recover
ratably more than the holders of the Subordinated Debt Securities.
Events of Default and Remedies
The following events are defined in the Indenture as "Events of Default"
with respect to a series of Debt Securities:
(a) default in the payment of any installment of interest on any Debt
Securities of that series when due and payable (whether or not, in the
case of Subordinated Debt Securities, such payment shall be prohibited
by reason of the subordination provision described above) and
continuance of such default for a period of 30 days;
(b) default in the payment of principal or premium, if any, with respect to
any Debt Securities of that series when due and payable, whether at
maturity, upon redemption, by declaration, upon required repurchase, or
otherwise (whether or not, in the case of Subordinated Debt Securities,
such payment shall be prohibited by reason of the subordination
provision described above);
(c) default in the payment of any sinking fund payment with respect to any
Debt Securities of that series when due and payable;
(d) the Company fails to comply with the provisions of the Indenture
relating to consolidations, mergers and sales of assets;
(e) the Company fails to observe or perform any other of its covenants or
agreements in the Debt Securities of that series, in any resolution of
the Board of Directors of the Company authorizing the
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issuance of that series of Debt Securities, in the Indenture with
respect to such series, or in any supplemental Indenture with respect to
such series (other than a covenant or agreement a default in the
performance of which is otherwise specifically dealt with) for a period
of 60 days after the date on which written notice specifying such
failure and requiring the Company to remedy the same has been given to
the Company by the Trustee or to the Company and the Trustee by the
holders of at least 25% in aggregate principal amount of the Debt
Securities of that series at the time outstanding;
(f) the Company or any Subsidiary does not pay its Indebtedness within any
applicable grace period after final maturity or such Indebtedness is
accelerated by the holders of such Indebtedness because of a default,
the total amount of such Indebtedness unpaid or accelerated exceeds
$40 million or the United States dollar equivalent of $40 million at
the time, and such default remains uncured or such acceleration is not
rescinded for 10 days after the date on which written notice
specifying such failure and requiring the Company to remedy such
failure shall have been given to the Company by the Trustee or to the
Company and the Trustee by the holders of at least 25% in aggregate
principal amount of the Debt Securities of that series at the time
outstanding;
(g) the Company shall
(1) voluntarily commence any proceeding or file any petition seeking
relief under the United States Bankruptcy Code or other federal or
state bankruptcy, insolvency, or similar law,
(2) consent to the institution of, or fail to controvert within the
time and in the manner prescribed by law, any such proceeding of
the filing of any such petition,
(3) apply for or consent to the appointment of a receiver, trustee,
custodian, sequestrator, or similar official for the Company for a
substantial part of its property,
(4) file an answer admitting the material allegations of a petition
filed against it in any such proceeding,
(5) make a general assignment for the benefit of creditors.
(6) admit in writing its inability or fail generally to pay its debts
as they become due,
(7) take corporate action for the purpose of effecting any of the
foregoing, or
(8) take any comparable action under any foreign laws relating to
insolvency;
(h) the entry of an order or decree by a court having competent
jurisdiction for
(1) relief with respect to the Company or a substantial part of its
property under the United States Bankruptcy Code or any other
federal or state bankruptcy, insolvency, or similar law,
(2) the appointment of a receiver, trustee, custodian, sequestrator, or
similar official for the Company or for a substantial part of its
property, or
(3) the winding-up or liquidation of the Company,
and such order or decree shall continue unstayed and in effect for 60
consecutive days, or any similar relief is granted under any foreign
laws and the order or decree stays in effect for 60 consecutive days; or
(i) any other Event of Default provided under the terms of the Debt
Securities of that series.
An Event of Default with respect to one series of Debt Securities is not
necessarily an Event of Default for another series.
If an Event of Default occurs and is continuing with respect to any series
of Debt Securities, unless the principal and interest with respect to all the
Debt Securities of such series shall have already become due and
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payable, either the Trustee or the holders of not less than 25% in aggregate
principal amount of the Debt Securities of such series then outstanding may
declare the principal of (or, if Original Issue Discount Debt Securities, such
portion of the principal amount as may be specified in such series) and
interest on all the Debt Securities of such series due and payable immediately.
If an Event of Default occurs and is continuing, the Trustee shall be
entitled and empowered to institute any action or proceeding for the collection
of the sums so due and unpaid or to enforce the performance of any provision of
the Debt Securities of the affected series or the Indenture, to prosecute any
such action or proceeding to judgment or final decree, and to enforce any such
judgment or final decree against the Company or any other obligor on the Debt
Securities of such series. In addition, if there shall be pending proceedings
for the bankruptcy or reorganization of the Company or any other obligor on the
Debt Securities, or if a receiver, trustee, or similar official shall have been
appointed for its property, the Trustee shall be entitled and empowered to file
and prove a claim for the whole amount of principal, premium and interest (or,
in the case of Original Issue Discount Debt Securities, such portion of the
principal amount as may be specified in the terms of such series) owing and
unpaid with respect to the Debt Securities. No holder of any Debt Securities of
any series shall have any right to institute any action or proceeding upon or
under or with respect to the Indenture, for the appointment of a receiver or
trustee, or for any other remedy, unless:
(a) such holder previously shall have given to the Trustee written notice
of an Event of Default with respect to Debt Securities of that series
and of the continuance of such Event of Default;
(b) the holders of not less than 25% in aggregate principal amount of the
outstanding Debt Securities of that series shall have made written
request to the Trustee to institute such action or proceeding with
respect to such Event of Default and shall have offered to the Trustee
such reasonable indemnity as it may require against the costs,
expenses, and liabilities to be incurred in connection with such action
or proceeding; and
(c) the Trustee, for 60 days after its receipt of such notice, request, and
offer of indemnity shall have failed to institute such action or
proceeding and no direction inconsistent with such written request
shall have been given to the Trustee pursuant to the provisions of the
Indenture.
Prior to the acceleration of the maturity of the Debt Securities of any
series, the holders of a majority in aggregate principal amount of the Debt
Securities of that series at the time outstanding may, on behalf of the holders
of all Debt Securities of that series, waive any past default or Event of
Default and its consequences for that series, except:
(a) a default in the payment of the principal, premium, if any, or interest
with respect to such Debt Securities; or
(b) a default with respect to a provision of the Indenture that cannot be
amended without the consent of each holder so affected.
In case of any such waiver, such default shall cease to exist, any Event of
Default arising from such default shall be deemed to have been cured for all
purposes, and the Company, the Trustee and the holders of the Debt Securities
of that series shall be restored to their former positions and rights under the
Indenture.
The Trustee shall, within 90 days after the occurrence of a default known to
it with respect to a series of Debt Securities, give to the holders of the Debt
Securities of such series notice of all uncured defaults with respect to such
series known to it, unless such defaults shall have been cured or waived before
the giving of such notice; provided, however, that except in the case of
default in the payment of principal, premium, or interest with respect to the
Debt Securities of such series or in the making of any sinking fund payment
with respect to the Debt Securities of such series, the Trustee shall be
protected in withholding such notice if it in good faith determines that the
withholding of such notice is in the interest of the holders of such Debt
Securities.
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Modification of the Indenture
The Company and the Trustee may enter into supplemental Indentures without
the consent of the holders of Debt Securities issued under the Indenture for
one or more of the following purposes:
(a) to evidence the succession of another person to the Company and the
assumption by such successor of the covenants, agreements, and
obligations of the Company in the Indenture and in the Debt Securities;
(b) to surrender any right or power conferred upon the Company by the
Indenture, to add further covenants, restrictions, conditions, or
provisions for the protection of the holders of all or any series of
Debt Securities, and to make the occurrence, or the occurrence and
continuance of a default in any of such additional covenants,
restrictions, conditions, or provisions, a default or an Event of
Default under the Indenture;
(c) to cure any ambiguity or to correct or supplement any provision
contained in the Indenture, in any supplemental Indenture, or in any
Debt Securities that may be defective or inconsistent with any other
provision contained in the Indenture, in any supplemental Indenture, or
in any Debt Securities, to convey, transfer, assign, mortgage, or
pledge any property to or with the Trustee, or to make such other
provisions in regard to matters or questions arising under the
Indenture as shall not adversely affect the interests of any holders of
Debt Securities of any series;
(d) to modify or amend the Indenture in such a manner as to permit the
qualification of the Indenture or any supplemental Indenture under the
Trust Indenture Act as then in effect;
(e) to add or change any of the provisions of the Indenture to change or
eliminate any restriction on the payment of principal or premium with
respect to Debt Securities so long as any such action does not
adversely affect the interest of the holders of Debt Securities in any
material respect or permit or facilitate the issuance of Debt
Securities of any series in uncertificated form;
(f) to comply with the provisions of the Indenture relating to
consolidations, mergers, and sales of assets;
(g) in the case of Subordinated Debt Securities, to make any change in the
provisions of the Indenture relating to subordination that would limit
or terminate the benefits available to any holder of Senior
Indebtedness under such provisions (but only if such holder of Senior
Indebtedness consents to such change);
(h) to add guarantees with respect to the Debt Securities or to secure the
Debt Securities;
(i) to add to, change, or eliminate any of the provisions of the Indenture
with respect to one or more series of Debt Securities, so long as any
such addition, change, or elimination not otherwise permitted under the
Indenture shall
(1) neither apply to any Debt Securities of any series created prior to
the execution of such supplemental Indenture and entitled to the
benefit of such provision nor modify the rights of the holders of
any such Debt Security with respect to such provision, or
(2) become effective only when there is no such Debt Security
outstanding;
(j) to evidence and provide for the acceptance of appointment by a
successor or separate Trustee with respect to the Debt Securities of
one or more series and to add to or change any of the provisions of the
Indenture as shall be necessary to provide for or facilitate the
administration of the Indenture by more than one Trustee; and
(k) to establish the form or terms of any series of Debt Securities.
With the consent of the holders of a majority in aggregate principal amount
of the outstanding Debt Securities of each series affected, the Company and the
Trustee may from time to time and at any time enter into a supplemental
Indenture for the purpose of adding any provisions to, changing in any manner,
or eliminating any of the provisions of the Indenture or of any supplemental
Indenture or modifying in any manner the rights of the holder of the Debt
Securities of such series. However, without the consent of the holders of each
Debt Security so affected, no such supplemental Indenture may:
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. reduce the percentage in principal amount of Debt Securities of any
series whose holders must consent to an amendment;
. reduce the interest rate or extend the time for payment of interest on
any Debt Security;
. reduce the principal of or extend the stated maturity of any Debt
Security;
. reduce the premium payable upon the redemption of any Debt Security or
change the time at which any Debt Security may or shall be redeemed;
. make any Debt Security payable in a currency other than that stated in
the Debt Security;
. in the case of any Subordinated Debt Security, make any change in the
provisions of the Indenture relating to subordination that adversely
affects the rights of any holder under such provisions;
. release any security that may have been granted with respect to the Debt
Securities; or
. make any change in the provisions of the Indenture relating to waivers of
defaults or amendments that require unanimous consent.
Consolidation, Merger, and Sale of Assets
The Indenture provides that the Company may not consolidate with or merge
with or into any person, or convey, transfer, or lease all or substantially all
of its assets, unless the following conditions have been satisfied:
(a) Either
(i) the Company is the continuing person in the case of a merger, or
(ii) the successor corporation is a corporation organized and existing
under the laws of the United States, any State, or the District of
Columbia and shall expressly assume all of the obligations of the
Company under the Debt Securities and the Indenture;
(b) Immediately after giving effect to the transaction (and treating any
Indebtedness that becomes an obligation of the successor corporation or any
Subsidiary of the Company as a result of the transaction as having been
incurred by the successor corporation or the Subsidiary at the time of the
transaction), no default or Event of Default would occur or be continuing;
and
(c) The Company has delivered to the Trustee an officers' certificate and an
opinion of counsel, each stating that the consolidation, merger, or
transfer complies with the Indenture.
Certain Definitions
The following definitions, among others, are used in the Indenture. Many of
the definitions of terms used in the Indenture have been negotiated
specifically for the purposes of inclusion in the Indenture and may not be
consistent with the manner in which such terms are defined in other contexts.
Prospective purchasers of Debt Securities are encouraged to read each of the
following definitions carefully and to consider such definitions in the context
in which they are used in the Indenture.
"Capitalized Lease Obligation" means an obligation that is required to be
classified and accounted for as a capitalized lease for financial reporting
purposes in accordance with GAAP, and the amount of Indebtedness represented by
such obligation shall be the capitalized amount of such obligation determined
in accordance with GAAP, and the Stated Maturity thereof shall be the date of
the last payment of rent or any other amount due under such lease prior to the
first date upon which such lease may be terminated by the lessee without
payment of a penalty.
"Disqualified Stock" of a Person means Redeemable Stock of such Person as to
which the maturity, mandatory redemption, conversion or exchange or redemption
at the option of the holder thereof occurs, or may occur, on or prior to the
first anniversary of the Stated Maturity of the Debt Securities.
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"GAAP" means generally accepted accounting principles in the United States
as in effect as of the date on which the Debt Securities of the applicable
series are issued, including those set forth in the opinions and
pronouncements of the Accounting Principles Board of the American Institute of
Certified Public Accountants and statements and pronouncements of the
Financial Accounting Standards Board or in such other statements by such other
entity as approved by a significant segment of the accounting profession. All
ratios and computations based on GAAP contained in this Indenture shall be
computed in conformity with GAAP consistently applied.
"Indebtedness" means, with respect to any Person on any date of
determination (without duplication):
(a) the principal of Indebtedness of such Person for borrowed money;
(b) the principal of obligations of such Person evidenced by bonds,
debentures, notes or other similar instruments;
(c) all Capitalized Lease Obligations of such Person;
(d) all obligations of such Person to pay the deferred and unpaid purchase
price of property or services (except Trade Payables);
(e) all obligations of such Person in respect of letters of credit,
banker's acceptances or other similar instruments or credit
transactions (including reimbursement obligations with respect
thereto), other than obligations with respect to letters of credit
securing obligations (other than obligations described in (a) through
(d) above) entered into in the ordinary course of business of such
Person to the extent such letters of credit are not drawn upon or, if
and to the extent drawn upon, such drawing is reimbursed no later than
the third business day following receipt by such Person of a demand for
reimbursement following payment on the letter of credit;
(f) the amount of all obligations of such Person with respect to the
redemption, repayment or other repurchase of any Disqualified Stock
(but excluding, in each case, any accrued dividends);
(g) all Indebtedness of other Persons secured by a Lien on any asset of
such Person, whether or not such Indebtedness is assumed by such
Person; provided, however, that the amount of such Indebtedness shall
be the lesser of (A) the fair market value of such asset at such date
of determination or (B) the amount of such Indebtedness of such other
Persons; and
(h) all Indebtedness of other Persons to the extent Guaranteed by such
Person.
For purposes of this definition, the maximum fixed redemption, repayment or
repurchase price of any Disqualified Stock or Preferred Stock that does not
have a fixed redemption, repayment or repurchase price shall be calculated in
accordance with the terms of such Stock as if such Stock were redeemed, repaid
or repurchased on any date on which Indebtedness shall be required to be
determined pursuant to this Indenture; provided, however, that if such Stock
is not then permitted to be redeemed, repaid or repurchased, the redemption,
repayment or repurchase price shall be the book value of such Stock as
reflected in the most recent financial statements of such Person. The amount
of Indebtedness of any Person at any date shall be the outstanding balance at
such date of all unconditional obligations as described above and the maximum
liability, upon the occurrence of the contingency giving rise to the
obligation, of any contingent obligations at such date.
"Lien" means any mortgage, pledge, security interest, encumbrance, lien or
charge of any kind (including any conditional sale or other title retention
agreement or lease in the nature thereof).
"Person" means any individual, corporation, partnership, joint venture,
association, limited liability company, joint stock company, trust,
unincorporated organization, government or any agency or political subdivision
thereof or any other entity.
"Redeemable Stock" means, with respect to any Person, any Capital Stock
which by its terms (or by the terms of any security into which it is
convertible or for which it is exchangeable) or upon the happening of any
event
(i) matures or is mandatorily redeemable pursuant to a sinking fund
obligation or otherwise,
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(ii) is convertible or exchangeable for Indebtedness (other than Preferred
Stock) or Disqualified Stock, or
(iii) is redeemable at the option of the holder thereof, in whole or in
part.
"Subsidiary" of any Person means any corporation, association, partnership
or other business entity of which more than 50% of the total voting power of
shares of Capital Stock entitled (without regard to the occurrence of any
contingency) to vote in the election of directors, managers or trustees
thereof is at the time owned or controlled, directly or indirectly, by
(i) such Person,
(ii) such Person and one or more Subsidiaries of such Person, or
(iii) one or more Subsidiaries of such Person.
Satisfaction and Discharge of the Indenture; Defeasance
The Indenture shall generally cease to be of any further effect with
respect to a series of Debt Securities if
(a) the Company has delivered to the Trustee for cancellation all Debt
Securities of such series (with certain limited exceptions), or
(b) all Debt Securities of such series not previously delivered to the
Trustee for cancellation shall have become due and payable, or are by
their terms to become due and payable within one year or are to be
called for redemption within one year, and the Company shall have
deposited with the Trustee as trust funds the entire amount in the
currency in which the Debt Securities are denominated sufficient to pay
at maturity or upon redemption all such Debt Securities;
and if, in either case, the Company shall also pay or cause to be paid all
other sums payable under the Indenture by the Company.
In addition, the Company shall have a "legal defeasance option" (pursuant
to which it may terminate, with respect to the Debt Securities of the
particular series, all of its obligations under such Debt Securities and the
Indenture with respect to such Debt Securities) and "covenant defeasance
option" (pursuant to which it may terminate, with respect to the Debt
Securities of a particular series, its obligations with respect to such Debt
Securities under certain specified covenants contained in the Indenture). If
the Company exercises its legal defeasance option with respect to a series of
Debt Securities, payment of such Debt Securities may not be accelerated
because of an Event of Default. If the Company exercises its covenant
defeasance option with respect to a series of Debt Securities, payment of such
Debt Securities may not be accelerated because of an Event of Default related
to the specified covenants.
The Company may exercise its legal defeasance option or its covenant
defeasance option with respect to the Debt Securities of a series only if:
(a) the Company irrevocably deposits in trust with the Trustee cash or U.S.
Government Obligations (as defined in the Indenture) for the payment of
principal, premium, and interest with respect to such Debt Securities
to maturity or redemption, as the case may be;
(b) the Company delivers to the Trustee a certificate from a nationally
recognized firm of independent accountants expressing their opinion
that the payment of principal and interest when due and without
reinvestment on the deposited U.S. Government Obligations plus any
deposited money without investment will provide cash at such times and
in such amounts as will be sufficient to pay the principal, premium, if
any, and interest when due with respect to all the Debt Securities of
such series to maturity or redemption, as the case may be;
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(c) 91 days pass after the deposit is made and during the 91-day period no
default described in clause (g) or (h) under "Description of Debt
Securities -- Events of Default and Remedies" above with respect to the
Company occurs that is continuing at the end of such period;
(d) no default has occurred and is continuing on the date of such deposit
and after giving effect thereto;
(e) the deposit does not constitute a default under any other agreement
binding on the Company, and, in the case of Subordinated Debt
Securities, is not prohibited by the provisions of the Indenture
relating to subordination;
(f) the Company delivers to the Trustee an opinion of counsel to the effect
that the trust resulting from the deposit does not constitute, or is
qualified as, a regulated investment company under the Investment
Company Act of 1940;
(g) the Company shall have delivered to the Trustee an opinion of counsel
addressing certain federal income tax matters relating to the
defeasance; and
(h) the Company delivers to the Trustee an officers' certificate and an
opinion of counsel, each stating that all conditions precedent to the
defeasance and discharge of the Debt Securities of such series as
contemplated by the Indenture have been complied with.
The Trustee shall hold in trust cash or U.S. Government Obligations
deposited with it as described above and shall apply the deposited cash and the
proceeds from deposited U.S. Government Obligations to the payment of
principal, premium, if any, and interest with respect to the Debt Securities of
the defeased series. In the case of Subordinated Debt Securities, the money and
U.S. Government Obligations so held in trust will not be subject to the
subordination provisions of the Indenture.
The Trustee
The Company may maintain banking and other commercial relationships with the
Trustee and its affiliates in the ordinary course of business and the Trustee
may own Debt Securities. The prospectus supplement relating to a particular
issue of Debt Securities will provide additional information with respect to
any relationship the Company may have with the Trustee for such Debt
Securities.
DESCRIPTION OF CAPITAL STOCK
We have 45,000,000 authorized shares of capital stock, consisting of (a)
40,000,000 shares of common stock, having a par value of $.20 per share, and
(b) 5,000,000 shares of preferred stock, having a par value of $1.00 per share.
Common Stock
As of the date of this prospectus, there were 25,740,160 shares of common
stock outstanding. All of such outstanding shares of common stock are fully
paid and nonassessable.
Holders of common stock are entitled to receive dividends, when, as and if
declared by our Board of Directors out of assets legally available for their
payment. In certain cases, we may not pay dividends to common stockholders
until our dividend obligations to the holder of any preferred stock then
outstanding have been satisfied. The provisions of our credit arrangements
subject us to certain restrictions on the payment of dividends.
In the event of our voluntary or involuntary liquidation, dissolution or
winding up, the holders of common stock will be entitled to share equally in
our assets remaining after payment of all liabilities and after holders of all
series of outstanding preferred stock have received their liquidation
preferences in full.
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The holders of common stock have no preemptive subscription, conversion or
redemption rights, and are not subject to further calls or assessments by us.
There are no sinking fund provisions applicable to the common stock.
Holders of common stock are entitled to one vote per share for the election
of directors and on all other matters submitted to a vote of stockholders.
Holders of common stock have no right to cumulate their votes in the election
of directors.
Preferred Stock
As of the date of this prospectus, there were no shares of preferred stock
outstanding.
Preferred stock may be issued from time to time in one or more series, and
our Board of Directors, without further approval of the stockholders, is
authorized to fix the dividend rates and terms, conversion rights, voting
rights, redemption rights and terms, liquidation preferences, sinking fund and
any other rights, preferences, privileges and restrictions applicable to each
series of preferred stock. The purpose of authorizing the Board of Directors to
determine such rights, preferences, privileges and restrictions is to eliminate
delays associated with a stockholder vote on specific issuances. The issuance
of preferred stock, while providing flexibility in connection with possible
acquisitions and other corporate purposes, could, among other things, adversely
affect the voting power of the holders of common stock and, under certain
circumstances, make it more difficult for a third party to gain control of us.
Stockholder Rights Agreement
Each share of common stock includes one right ("Right") entitling the
registered holder to purchase from us one one-hundredth of a share (a
"Fractional Share") of Series A Participating Cumulative Preferred Stock (the "
Preferred Shares"), at a purchase price per Fractional Share of $12.75, subject
to adjustment (the "Purchase Price").
With certain exceptions, upon the earlier of (1) 10 days following the date
the Company learns that a person or group of affiliated or associated persons
(an "Acquiring Person") has acquired, or obtained the right to acquire,
beneficial ownership of 15% or more of the outstanding shares of common stock,
or (2) 10 business days following the commencement of a tender offer or
exchange offer that would result in a person becoming an Acquiring Person, a
"Distribution Date" will occur and the Rights will be separated from the common
stock. In certain circumstances, our Board of Directors may defer the
Distribution Date. Certain inadvertent acquisitions will not result in a person
becoming an Acquiring Person if the person promptly divests itself of
sufficient common stock. Until the Distribution Date, (1) the Rights are
evidenced by the certificates representing outstanding shares of common stock
and will be transferred with and only with such certificates, which contain a
notation incorporating the Rights Agreement by reference, and (2) the surrender
for transfer of any certificate for common stock will also constitute the
transfer of the Rights associated with the common stock represented by such
certificate.
The Rights are not exercisable until the Distribution Date and will expire
at the close of business 10 years after the Rights are issued, unless earlier
redeemed or exchanged by us as described below.
As soon as practicable after the Distribution Date, Rights certificates will
be mailed to holders of record of the common stock as of the close of business
on the Distribution Date and, from and after the Distribution Date, the
separate Rights certificates alone will represent the Rights. All shares of
common stock issued prior to the Distribution Date will be issued with Rights.
Shares of common stock issued after the Distribution Date in connection with
certain employee benefit plans or upon conversion of certain securities will be
issued with Rights. Except as otherwise determined by the Board of Directors,
no other shares of the common stock issued after the Distribution Date will be
issued with Rights.
In the event (a "Flip-In Event") that a person becomes an Acquiring Person
(except pursuant to a tender or exchange offer for all outstanding shares of
common stock at a price and on terms that a majority of our
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independent directors determines to be fair to and otherwise in our and our
stockholders best interests (a "Permitted Offer")), each holder of a Right will
thereafter have the right to receive, upon exercise of such Right, the number
of Fractional Shares equivalent to the number of shares of common stock (or, in
certain circumstances, cash, property or other securities) having a market
value equal to two times the Purchase Price. Notwithstanding the foregoing,
following the occurrence of any Triggering Event (as defined below), all Rights
that are, or (under certain circumstances specified in the Rights Agreement)
were, beneficially owned by or transferred to an Acquiring Person (or by
certain related parties) will be null and void in the circumstances set forth
in the Rights Agreement.
In the event (a "Flip-Over Event") that, at any time from and after the time
an Acquiring Person becomes such, (1) we are acquired in a merger or other
business combination transaction (other than certain mergers that follow a
Permitted Offer) or (2) 50% or more of our assets or earning power is sold or
transferred, each holder of a Right (except Rights that are voided as set forth
above) shall thereafter have the right to receive, upon exercise, a number of
shares of common stock of the acquiring company having a market value equal to
two times the exercise price of the Right as set by the Board of Directors.
Flip-In Events and Flip-Over Events are collectively referred to as "Triggering
Events."
The number of outstanding Rights associated with a share of common stock, or
the number of Preferred Shares issuable upon exercise of a Right and the
Purchase Price, are subject to adjustment in the event of a stock dividend on,
or a subdivision, combination or reclassification of, the common stock
occurring prior to the Distribution Date. The Purchase Price payable, and the
number of Fractional Shares of Preferred Shares or other securities or property
issuable, upon exercise of the Rights are subject to adjustment from time to
time to prevent dilution in the event of certain transactions affecting the
Preferred Shares.
At any time until ten days following the first date of public announcement
of the occurrence of a Flip-In Event, we may redeem the Rights in whole, but
not in part, at a price of $0.01 per Right, payable, at our option, in cash,
shares of common stock or such other consideration as the Board of Directors
may determine. Immediately upon the effectiveness of the action of the Board of
Directors ordering redemption of the Rights, the Rights will terminate and the
only right of the holders of Rights will be to receive the $0.01 redemption
price.
Until a Right is exercised, the holder thereof, as such, will have no rights
as a stockholder, including, without limitation, the right to vote or to
receive dividends.
Other than the redemption price, the Board of Directors may amend any of the
provisions of the Rights Agreement as long as the Rights are redeemable.
The Rights have certain antitakeover effects. They will cause substantial
dilution to any person or group that attempts to acquire us without the
approval of our Board of Directors. As a result, the overall effect of the
Rights may be to render more difficult or discourage any attempt to acquire us,
even if such acquisition may be favorable to the interests of our stockholders.
Because the Board of Directors can redeem the Rights or approve a Permitted
Offer, the Rights should not interfere with a merger or other business
combination approved by the Board of Directors. The Rights were issued to
protect our stockholders from coercive or abusive takeover tactics and
inadequate takeover offers and to afford our Board of Directors more
negotiating leverage in dealing with prospective acquirors.
Certain Other Possible Anti-takeover Provisions
Our Charter and Delaware law contain certain provisions that might be
characterized as anti-takeover provisions. These provisions may make it more
difficult to acquire control of us or remove our management.
Classified Board of Directors
Our Charter provides for the Board of Directors to be divided into three
classes of directors serving staggered three-year terms, with the number of
directors in each class to be as nearly equal as possible. As a result, only
one-third of our directors are elected each year.
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Issuance of Preferred Stock
As described above, our Charter authorizes a class of undesignated preferred
stock consisting of 5,000,000 shares. The issuance of preferred stock could,
among other things, make it more difficult for a third party to gain control of
us.
Fair Price Provisions
Our Charter also contains certain "fair price provisions" designated to
provide safeguards for stockholders when an "interested stockholder" (defined
as a stockholder owning 5% or more of our voting stock) attempts to effect a
"business combination" with us. The term "business combination" includes:
. any merger or consolidation of us involving the interested stockholder,
. certain dispositions of our assets,
. any issuance of our securities meeting certain threshold amounts, to the
interested stockholder,
. adoption of any plan of liquidation or dissolution of us proposed by the
interested stockholder, and
. any reclassification of our securities having the effect of increasing
the proportionate share of ownership of the interested stockholder.
In general, a business combination between us and the interested stockholder
must be approved by the affirmative vote of 80% of the outstanding voting stock
unless the transaction is approved by a majority of the members of the Board of
Directors who are not affiliated with the interested stockholder or certain
minimum price and form of consideration requirements are satisfied.
Delaware Business Combination Statute
We are incorporated under the laws of the State of Delaware. Section 203 of
the Delaware General Corporation Law prevents an "interested stockholder"
(defined as a stockholder owning 15% or more of a corporation's voting stock)
from engaging in a business combination with that corporation for a period of
three years from the date the stockholder became an interested stockholder
unless:
. the corporation's board of directors had earlier approved either the
business combination or the transaction by which the stockholder became
an interested stockholder;
. upon attaining that status, the interested stockholder had acquired at
least 85% of the corporation's voting stock (not counting shares owned by
persons who are directors and also officers); or
. the business combination is later approved by the board of directors and
authorized by a vote of two-thirds of the stockholders (not including the
shares held by the interested stockholder).
Since we have not amended our Charter or By-laws to exclude the application
of Section 203, its provisions apply to us. Accordingly, Section 203 may
inhibit an interested stockholder's ability to acquire additional shares of
common stock or otherwise engage in a business combination with us.
Transfer Agent and Registrar
The Transfer Agent and Registrar for the common stock is ChaseMellon
Shareholder Services, L.L.C.
DESCRIPTION OF WARRANTS
General
We may issue warrants (the "Warrants") to purchase Debt Securities ("Debt
Warrants") or, Warrants to purchase common stock or preferred stock ("Stock
Warrants"). Warrants may be issued independently of or together with any other
securities and may be attached to or separate from such securities. Each series
of Warrants will be issued under a separate Warrant Agreement (each a "Warrant
Agreement") to be entered into
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between us and a Warrant Agent ("Warrant Agent"). The Warrant Agent will act
solely as an agent of the Company in connection with any Warrant and will not
assume any obligation or relationship of agency for or with holders or
beneficial owners of Warrants. The following summaries set forth certain
general terms and provisions of the Warrants. Further terms of the Warrants and
the applicable Warrant Agreement will be set forth in the applicable prospectus
supplement.
Debt Warrants
The applicable prospectus supplement will describe the terms of any Debt
Warrants, including the following:
. the title of such Debt Warrants;
. the offering price for such Debt Warrants, if any;
. the aggregate number of such Debt Warrants;
. the designation and terms of such Debt Securities purchasable upon
exercise of such Debt Warrants;
. if applicable, the designation and terms of the securities with which
such Debt Warrants are issued and the number of such Debt Warrants issued
with each such Security;
. if applicable, the date from and after which such Debt Warrants and any
securities issued therewith will be separately transferable;
. the principal amount of Debt Securities purchasable upon exercise of a
Debt Warrant and the price at which such principal amount of Debt
Securities may be purchased upon exercise;
. the date on which the right to exercise such Debt Warrants shall commence
and the date on which such right shall expire;
. if applicable, the minimum or maximum amount of such Debt Warrants which
may be exercised at any one time;
. whether the Debt Warrants represented by the Debt Warrant certificates or
Debt Securities that may be issued upon exercise of the Debt Warrants
will be issued in registered or bearer form;
. information with respect to book-entry procedures, if any;
. the currency, currencies or currency units in which the offering price,
if any, and the exercise price are payable;
. if applicable, a discussion of certain United States federal income tax
considerations;
. the antidilution provisions of such Debt Warrants, if any;
. the redemption or call provisions, if any, applicable to such Debt
Warrants; and
. any additional terms of the Debt Warrants, including terms, procedures
and limitations relating to the exchange and exercise of such Debt
Warrants.
Stock Warrants
The applicable prospectus supplement will describe the terms of any Stock
Warrants, including the following:
. the title of such Stock Warrants;
. the offering price of such Stock Warrants, if any;
. the aggregate number of such Stock Warrants;
. the designation, number of shares and terms (including, without
limitation, liquidation, dividend, conversion and voting rights) of the
series of preferred stock purchasable upon exercise of such Stock
Warrants;
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. if applicable, the date from and after which such Stock Warrants and any
securities issued therewith will be separately transferable;
. the number of shares of common stock, or preferred stock purchasable upon
exercise of a Stock Warrant and the price at which such shares may be
purchased upon exercise;
. the date on which the right to exercise such Stock Warrants shall
commence and the date on which such right shall expire;
. if applicable, the minimum or maximum amount of such Stock Warrants which
may be exercised at any one time;
. the currency, currencies or currency units in which the offering price,
if any, and the exercise price are payable;
. if applicable, a discussion of certain United States federal income tax
considerations;
. the antidilution provisions of such Stock Warrants, if any;
. the redemption or call provisions, if any, applicable to such Stock
Warrants; and
. any additional terms of such Stock Warrants, including terms, procedures
and limitations relating to the exchange and exercise of such Stock
Warrants.
PLAN OF DISTRIBUTION
The distribution of the securities may be effected from time to time in one
or more transactions at a fixed price or prices (which may be changed from time
to time), at market prices prevailing at the time of sale, at prices related to
such prevailing market prices or at negotiated prices. The Company also may
offer and sell the securities in exchange for one or more of its outstanding
issues of debt or convertible debt securities, or in exchange for one or more
classes of securities of other issuers in connection with business combination
transactions. Each prospectus supplement will describe the method of
distribution of the securities offered therein.
We may sell securities in any of three ways: (1) through underwriters or
dealers; (2) through agents; or (3) directly to one or more purchasers. The
accompanying prospectus supplement with respect to a particular offering of
securities will set forth the terms of the offering of such securities,
including the name or names of any underwriters, dealers or agents, the
purchase price of such securities, the proceeds to the Company from such sale,
any delayed delivery arrangements, any underwriting discounts and other items
constituting underwriters' compensation, any initial public offering price, any
discounts or concessions allowed or reallowed or paid to dealers and any
securities exchanges on which such securities may be listed.
If underwriters are used in the sale, the securities will be acquired by the
underwriters for their own account and may be resold from time to time in one
or more transactions, including negotiated transactions, at a fixed public
offering price or at varying prices determined at the time of sale. The
securities may be offered to the public either through underwriting syndicates
represented by one or more managing underwriters or directly by one or more
firms acting as underwriters. The underwriter or underwriters with respect to a
particular underwritten offering of the securities will be named in the
prospectus supplement relating to such offering, and if an underwriting
syndicate is used, the managing underwriter or underwriters will be set forth
on the cover of such prospectus supplement. Unless otherwise set forth in the
prospectus supplement relating thereto, the obligations of the underwriters or
agents to purchase a particular offering of securities will be subject to
conditions precedent, and the underwriters will be obligated to purchase all
the particular securities offered if any are purchased.
If dealers are utilized in the sale of a particular offering of securities
with respect to which this prospectus is delivered, the Company will sell such
securities to the dealers as principals. The dealers may then resell such
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securities to the public at varying prices to be determined by such dealers at
the time of resale. The names of the dealers and the terms of the transaction
will be set forth in the prospectus supplement relating thereto. Any initial
public offering price and any discounts or concessions allowed or reallowed or
paid to dealers may be changed from time to time.
Only underwriters named in a prospectus supplement will be deemed to be
underwriters in connection with the securities described therein. Firms not so
named will have no direct or indirect participation in the underwriting of such
securities, although such a firm may participate in the distribution of such
securities under circumstances entitling it to a dealer's commission. It is
anticipated that any underwriting agreement pertaining to any such securities
will (1) entitle the underwriters to indemnification by the Company against
certain civil liabilities under the securities Act or to contribution with
respect to payments which the underwriters may be required to make in respect
thereof, (2) provide that the obligations of the underwriters will be subject
to certain conditions precedent and (3) provide that the underwriters generally
will be obligated to purchase all such securities if any are purchased.
Securities also may be offered directly by the Company or through agents
designated by the Company from time to time at fixed prices, which may be
changed, or at varying prices determined at the time of sale. Any such agent
will be named, and the terms of any such agency (including any commissions
payable by the Company to such agent) will be set forth, in the prospectus
supplement relating thereto. Unless otherwise indicated in such prospectus
supplement, any such agent will act on a reasonable best efforts basis for the
period of its appointment. Agents named in a prospectus supplement may be
deemed to be underwriters (within the meaning of the Securities Act) of the
securities described therein and, under agreements which may be entered into
with the Company, may be entitled to indemnification by the Company against
certain civil liabilities under the Securities Act or to contribution with
respect to payments which the agents may be required to make in respect
thereof.
If so indicated in a prospectus supplement, the Company will authorize
underwriters or other agents of the Company to solicit offers by certain
specified entities to purchase securities from the Company pursuant to delayed
delivery contracts providing for payment and delivery at a specified future
date. The obligations of any purchaser under any such contract will not be
subject to any conditions except those described in such prospectus supplement.
Such prospectus supplement will set forth the commissions payable for
solicitations of such contracts.
Underwriters and agents may purchase and sell the securities in the
secondary market, but are not obligated to do so. There can be no assurance
that there will be a secondary market for the securities or liquidity in the
secondary market if one develops. From time to time, underwriters and agents
may make a market in the securities. A particular offering of securities may or
may not be listed on a national securities exchange.
Underwriters and agents may engage in transactions with, or perform services
for, the Company and its subsidiaries in the ordinary course of business.
Each class or series of securities will be a new issue of securities with no
established trading market, other than the common stock, which is listed on the
New York Stock Exchange. The Company may elect to list any other class or
series of securities on any exchange, but it is not obligated to do so. Any
underwriters to whom securities are sold by the Company for public offering and
sale may make a market in such securities, but such underwriters will not be
obligated to do so and may discontinue any market making at any time without
notice. No assurance can be given as to the liquidity of the trading market for
any securities.
Certain persons participating in any offering of securities may engage in
transactions that stabilize, maintain or otherwise affect the price of the
securities offered. In connection with any such offering, the underwriters or
agents, as the case may be, may purchase and sell securities in the open
market. These transactions may include overallotment and stabilizing
transactions and purchases to cover syndicate short
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positions created in connection with the offering. Stabilizing transactions
consist of certain bids or purchases for the purpose of preventing or retarding
a decline in the market price of the securities; and syndicate short positions
involve the sale by the underwriters or agents, as the case may be, of a
greater number of securities than they are required to purchase from the
Company in the offering. The underwriters may also impose a penalty bid,
whereby selling concessions allowed to syndicate members or other broker-
dealers for the securities sold for their account may be reclaimed by the
syndicate if such securities are repurchased by the syndicate in stabilizing or
covering transactions. These activities may stabilize, maintain or otherwise
affect the market price of the securities, which may be higher than the price
that might otherwise prevail in the open market, and if commenced, may be
discontinued at any time. These transactions may be effected on the New York
Stock Exchange, in the over-the-counter market or otherwise. For a description
of these activities, see "Plan of Distribution" or "Underwriting" in the
applicable prospectus supplement.
LEGAL MATTERS
The validity of the offered securities will be passed upon for us by Conner
& Winters, A Professional Corporation, Tulsa, Oklahoma, and for any
underwriters, dealers or agents by a firm named in the prospectus supplement
relating to the particular securities.
INDEPENDENT ACCOUNTANTS
The financial statements incorporated in this registration statement by
reference to the Annual Report on Form 10-K for the year ended December 31,
1998, have been so incorporated in reliance on the report of
PricewaterhouseCoopers LLP, independent accountants, given on the authority of
said firm as experts in auditing and accounting. With respect to the unaudited
consolidated financial information of Unit Corporation for the three month
periods ended March 31, 1999 and 1998, incorporated by reference in this
registration statement, PricewaterhouseCoopers LLP reported that they have
applied limited procedures in accordance with professional standards for a
review of such information. However, their separate report dated April 29,
1999, incorporated by reference herein, states that they did not audit and they
do not express an opinion on that unaudited consolidated financial information.
Accordingly, the degree of reliance on their reports on such information should
be restricted in light of the limited nature of the review procedures applied.
PricewaterhouseCoopers LLP is not subject to the liability provisions of
Section 11 of the Securities Act of 1933 for their report on the unaudited
consolidated financial information because that report is not a "report" or a
"part" of the registration statement prepared or certified by
PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the
Securities Act.
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[LOGO OF UNIT CORPORATION APPEARS HERE]
UNIT CORPORATION
Prudential Securities
CIBC World Markets
Raymond James & Associates, Inc.
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