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F O R M 1 0 - K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ________ to _________
[Commission File Number 1-9260]
U N I T C O R P O R A T I O N
(Exact Name of Registrant as Specified in its Charter)
Delaware 73-1283193
(State of Incorporation) (I.R.S. Employer Identification No.)
1000 Kensington Tower
7130 South Lewis
Tulsa, Oklahoma 74136
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code (918) 493-7700
++++++++++++++++++++++++++++++++
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange
Common Stock, par value on which registered
$.20 per share New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in PART III of this
Form 10-K or any amendment to this Form 10-K.
Aggregate Market Value of the Voting Stock Held By
Non-affiliates on March 17, 1999 - $143,274,719
Number of Shares of Common Stock
Outstanding on March 17, 1999 - 26,653,341
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual Meeting
of Stockholders to be held May 5, 1999 are incorporated by reference in Part
III.
Exhibit Index - See Page 77
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . 18
Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . . 18
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . 19
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . 20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations . . . . . . . . . . . . . . . . . . . 21
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . 29
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . . 67
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . . 67
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . 68
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . . . . 68
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . 69
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . . 69
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 1998
PART I
Item 1. Business and Item 2. Properties
- -----------------------------------------
GENERAL
The Company, through its wholly owned subsidiaries, is engaged in the
land contract drilling of oil and natural gas wells and the development,
acquisition and production of oil and natural gas properties. The
Company's primary exploration and production operations are conducted in
the Anadarko and Arkoma Basins, which cover portions of Oklahoma, Texas,
Kansas and Arkansas, with additional operations located in the South Texas
Basin. Additional producing properties are located in other states,
including, but not limited to, New Mexico, Louisiana, North Dakota,
Colorado, Wyoming, Montana, Alabama, Mississippi, Arkansas, Illinois and
Nebraska as well as in Canada. The Company's contract drilling operations
are primarily located in the Oklahoma and Texas areas of the Anadarko and
Arkoma Basins with additional operations in the Permian and South Texas
Basins.
The Company was originally incorporated in Oklahoma in 1963 as Unit
Drilling Company. In 1979 it became a publicly held Delaware corporation
and changed its name to Unit Drilling and Exploration Company ("UDE") to
more accurately reflect the importance of its oil and natural gas business.
In September 1986, pursuant to a merger and exchange offer, the Company
acquired all of the assets and assumed all of the liabilities of UDE and
six oil and gas limited partnerships for which UDE was the general partner,
in exchange for shares of the Company's common stock (the "Exchange
Offer").
The Company's principal executive offices are maintained at 1000
Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; telephone number
(918) 493-7700. The Company also has regional offices in Moore and
Woodward, Oklahoma and Booker and Houston, Texas. When used in this
report, the term "Company" refers to Unit Corporation and at times Unit
Corporation and/or one or more of its subsidiaries with respect to periods
from and after the Exchange Offer and to UDE with respect to periods prior
thereto.
OIL AND NATURAL GAS OPERATIONS
In 1979, the Company began to develop its exploration and production
operations to diversify its source of revenues which, up to that time, were
derived from its contract drilling. Today, the Company conducts the
development, production and sale of oil and natural gas together with the
acquisition of producing properties through its wholly owned subsidiary,
Unit Petroleum Company.
As of December 31, 1998, the Company had 3,245 Mbbls and 161,318 MMcf
of estimated proved oil and natural gas reserves, respectively. The
Company's producing oil and natural gas interests, undeveloped leaseholds
1
and related assets are located primarily in Oklahoma, Texas, Louisiana and
New Mexico and to a lesser extent in Arkansas, North Dakota, Colorado, Wyo-
ming, Montana, Alabama, Mississippi, Arkansas, Illinois, Nebraska and
Canada. As of December 31, 1998, the Company had an interest in a total of
2,499 wells in the United States and served as the operator of 524 wells.
The Company also had an interest in 64 wells located in Canada. The
majority of the Company's development and exploration prospects are
generated by its technical staff. When the Company is the operator of a
property, it generally employs its own drilling rigs and the Company's own
engineering staff supervises the drilling operation.
The Company intends to continue the growth in its oil and natural gas
operations utilizing funds generated from operations and its bank revolving
line of credit.
Well and Leasehold Data. The Company's oil and natural gas explora-
tion and development drilling activities and the number of wells in which
the Company had an interest, which were producing or capable of producing,
were as follows for the periods indicated:
Year Ended December 31,
-------------------------------------------------
1998 1997 1996
Wells drilled: Gross Net Gross Net Gross Net
- -------------- ------ ------ ------ ------ ------ ------
Exploratory:
Oil.............. - - - - - -
Natural gas...... - - - - - -
Dry.............. 1 .26 - - - -
------ ------ ------ ------ ------ ------
Total 1 .26 - - - -
====== ====== ====== ====== ====== ======
Development:
Oil.............. 4 .44 10 4.84 10 8.35
Natural gas...... 52 19.26 57 23.85 55 19.46
Dry.............. 21 10.62 15 9.27 7 4.26
------ ------ ------ ------ ------ ------
Total 77 30.32 82 37.96 72 32.07
====== ====== ====== ====== ====== ======
Oil and natural gas wells producing or capable of producing:
- ------------------------------------------------------------
Oil - USA........ 726 196.64 684 197.67 717 197.71
Oil - Canada..... - - - - - -
Gas - USA........ 1,773 286.73 1,545 260.40 1,530 242.09
Gas - Canada..... 64 1.60 64 1.60 64 1.60
------ ------ ------ ------ ------ ------
Total 2,563 484.97 2,293 459.67 2,311 441.40
====== ====== ====== ====== ====== ======
2
The following table summarizes the Company's acreage as of the end of each
of the years indicated:
Developed Acreage Undeveloped Acreage
------------------- ---------------------
Gross Net Gross Net
------- ------- ------- -------
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
======= ======= ======= =======
3
Price and Production Data. The Company's average sales price, oil and
natural gas production volumes and average production cost per equivalent
Mcf (1 barrel (Bbl) of oil = 6 thousand cubic feet (Mcf) of natural gas) of
production for the periods indicated were as follows:
Year Ended December 31,
----------------------------------
1998 1997 1996
-------- -------- --------
Average sales price per barrel
of oil produced:
USA $ 12.81 $ 19.19 $ 20.40
Canada $ - $ - $ -
Average sales price per Mcf of
natural gas produced:
USA $ 1.90 $ 2.43 $ 2.21
Canada $ 1.46 $ .93 $ 1.18
Oil production (Mbbls):
USA 443 493 579
Canada - - -
-------- -------- --------
Total 443 493 579
======== ======== ========
Natural gas production (MMcf):
USA 16,427 13,742 12,974
Canada 38 74 51
-------- -------- --------
Total 16,465 13,816 13,025
======== ======== ========
Average production expense per
equivalent Mcf:
USA $ .61 $ .64 $ 0.68
Canada $ .54 $ .33 $ 0.27
Reserves. The following table sets forth the estimated proved
developed and undeveloped oil and natural gas reserves of the Company at
the end of each of the years indicated:
Year Ended December 31,
---------------------------------
1998 1997 1996
------- ------- -------
Oil (Mbbls):
USA 3,245 4,131 5,204
Canada - - -
------- ------- -------
Total 3,245 4,131 5,204
======= ======= =======
Natural gas (MMcf):
USA 160,795 144,661 128,408
Canada 523 723 753
------- ------- -------
Total 161,318 145,384 129,161
======= ======= =======
4
Further information relating to oil and natural gas operations is
presented in Notes 1,5,12 and 14 of Notes to Consolidated Financial
Statements set forth in Item 8 hereof.
LAND CONTRACT DRILLING OPERATIONS
Unit Drilling Company, a wholly owned subsidiary of the Company, is
engaged in the land drilling of oil and natural gas wells for a wide range
of customers. 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. An active maintenance and
replacement program during the life of a drilling rig permits upgrading of
components 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. The Company also owns additional
equipment used in the operation of its rigs, including large air compres-
sors, trucks and other support equipment.
On November 20, 1997, the Company acquired Hickman Drilling Company,
an Oklahoma corporation pursuant to an Agreement and Plan of Merger ("the
Merger Agreement"), dated November 20, 1997 entered into by and between the
Company, the Company's wholly owned subsidiary Unit Drilling Company,
Hickman Drilling Company and all of the holders of the outstanding capital
stock of Hickman Drilling Company (the "Selling Stockholders"). Under the
terms of this acquisition, the Selling Stockholders received, in aggregate,
1,300,000 shares of 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 the Company retained Hickman Drilling Company's
Woodward, Oklahoma corporate office as a regional office for its contract
drilling operations. In December 1997, the Company also purchased a Mid-
Continent U-36A, 650 horsepower rig with a 13,000 feet depth capacity and
spare components from two additional rigs for a total consideration of
$1 million, of which $200,000 was paid at closing and the balance is to be
paid over a period ending no later than three years. The balance is to be
paid out monthly with the monthly amount to be calculated on the basis of a
predetermined daily rate multiplied by the number of days in such month
that the acquired rig is employed for the account of the seller, all as
more fully specified in the acquisition agreement. If the balance of the
purchase price has not been fully paid at the end of three years the
remaining amount is to be paid in cash to the seller.
5
With the acquisitions noted above, the Company's drilling rig fleet
expanded to 34 rigs with depth capacities ranging from 7,000 to 25,000
feet. At December 31, 1998, 29 of the Company's rigs were located in the
Anadarko and Arkoma Basins of Oklahoma and Texas while five of its larger
horsepower rigs were located in South Texas. In the Anadarko and Arkoma
Basins the Company's primary focus is on the utilization of its 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, the Company does not have a shortage of drilling rig
related equipment. During 1996 and through 1997, the Company increased
its drill pipe acquisitions since certain grades of drill pipe were in high
demand, due to increased rig utilization. However, at any given time, the
Company's ability to utilize its full complement of drilling rigs is
dependent upon the availability of qualified labor, drilling supplies and
equipment as well as demand. Should industry 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 the Company, but in the industry as a whole.
The following table sets forth, for each of the periods indicated,
certain data concerning the Company's contract drilling operations:
Year Ended December 31,
---------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Number of operational rigs owned
at end of period 34 34(1) 24 22 25
Average number of rigs utilized (2) 22.9 19.2 14.7 10.9 9.5
Number of wells drilled 198 167 130 111 95
Total footage drilled (feet in 1000's) 2,203 1,736 1,468 1,196 1,027
- -------------------
(1) Includes 10 rigs acquired in the fourth quarter of 1997.
(2) Utilization rates are based on a 365-day year. A rig is
considered utilized when it is operating or being moved,
assembled or dismantled under contract.
As of February 23, 1999, 22 of the Company's 34 drilling rigs were
operating under contract.
6
The following table sets forth, as of February 23, 1999, the type and
approximate depth capability of each of the Company's drilling rigs:
Approximate
Depth
Capability
Rig# Type (feet)
---- ---- ----------
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 16,000
10 BDW 450T 9,500
11 Gardner Denver 700 15,000
12 BDW 800-M1 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 700M 15,000
24 Gardner Denver 700M 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
During the previous decade, the Company's contract drilling services
encountered significant competition due to depressed levels of activity in
contract drilling. In the last 6 months of 1996 and throughout 1997 and
the first three quarters of 1998, the Company's drilling operation showed
significant improvements in rig utilization. However, in late 1998, the
Company and the industry as a whole experienced a significant reduction in
demand. The Company anticipates that competition within the industry will,
for the foreseeable future, continue to adversely affect the Company.
Drilling Contracts. Most of the Company's 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
7
matters. The contracts obligate the Company to pay certain operating
expenses, including wages of drilling personnel, maintenance expenses and
incidental rig supplies and equipment. Usually, the contracts are subject
to termination by the customer on short notice upon payment of a fee. The
Company generally indemnifies its customers against certain types of claims
by the Company's employees and claims arising from surface pollution caused
by spills of fuel, lubricants and other solvents within the control of the
Company. Such customers generally indemnify the Company against claims
arising from other surface and subsurface pollution other than claims
resulting from the Company's gross negligence.
The contracts may provide for compensation to the Company on a day
rate, footage or turnkey basis with additional compensation for special
risks and unusual conditions. Under daywork contracts, the Company
provides the drilling rig with the required personnel to the operator who
supervises the drilling of the contracted well. Compensation to the
Company is based on a negotiated rate per day as the rig is utilized.
Footage contracts usually require the Company to bear some of the drilling
costs in addition to providing the rig. The Company is compensated on a
rate per foot drilled basis upon completion of the well. Under turnkey
contracts, the Company contracts to drill a well to a specified depth and
provides most of the equipment and services required. The Company bears
the risk of drilling the well to the contract depth and is compensated when
the contract provisions have been satisfied.
Turnkey drilling operations, in particular, might result in losses if
the Company underestimates the costs of drilling a well or if unforeseen
events occur. To date, the Company has not experienced significant losses
in performing turnkey contracts. For 1998, turnkey revenue represented
approximately 15 percent of the Company's contract drilling revenues.
Because the proportion of turnkey drilling is currently dictated by market
conditions and the desires of customers using the Company's services, the
Company is 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, 10
contract drilling customers accounted for approximately 24 percent of the
Company's total revenues and approximately 5 percent of the Company's total
revenues were generated by drilling on oil and natural gas properties of
which the Company was the operator (including properties owned by limited
partnerships for which the Company acted as general partner). Such drill-
ing was pursuant to contracts containing terms and conditions comparable to
those contained in the Company's customary drilling contracts with non-
affiliated operators.
Further information relating to contract drilling operations is
presented in Notes 1, 2 and 12 of Notes to Consolidated Financial State-
ments set forth in Item 8 hereof.
8
VOLATILE NATURE OF THE COMPANY'S OIL AND NATURAL GAS MARKETS;
FLUCTUATIONS IN PRICES
The Company's revenue and profitability are substantially dependent
upon prevailing prices for natural gas and crude oil. Oil and natural gas
prices have historically been volatile and are expected by the Company to
continue to be volatile in the future. These prices vary based on factors
beyond the control of the Company, including the extent of domestic produc-
tion and importation of crude oil and natural gas, the proximity and
capacity of oil and natural gas pipelines, costs of gathering natural gas,
the marketing of competitive fuels, general fluctuations in the supply and
demand for oil and natural gas, the effect of federal and state regulation
of production, refining, transportation and sales, the use and allocation
of oil and natural gas and their substitute fuels and general national and
worldwide economic conditions. In addition, natural gas spot prices
received by the Company are influenced by weather conditions impacting the
continental United States.
The Company's oil and condensate production is sold at or near the
Company's wells under purchase contracts at prevailing prices in accordance
with arrangements which are customary in the oil industry. The Company's
natural gas production is sold to intrastate and interstate pipelines as
well as to independent marketing firms under contracts with original terms
ranging from one month to several years. Most of these contracts contain
provisions for readjustment of price, termination and other terms which are
customary in the industry.
The worldwide supply of oil has been largely dependent upon rates of
production of foreign reserves. Although the demand for oil has increased
in the United States, imports of foreign oil continue to increase. Future
domestic oil prices will depend largely upon the actions of foreign
producers with respect to rates of production and it is virtually
impossible to predict what actions those producers will take in the future.
Prices may also be affected by political, social and other factors relating
to the Middle East. In view of the many uncertainties affecting the supply
and demand for oil and natural gas, the Company is unable to predict future
oil and natural gas prices or the overall effect, if any, that a decline in
demand or oversupply of such products would have on the Company.
COMPETITION
All lines of business in which the Company engages are highly com-
petitive. 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 the
Company's competitors in the land contract drilling business are sub-
stantially larger than the Company 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
the Company's drilling operations presently operates is uncertain and
extremely price oriented.
9
The Company's 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 the Company.
OIL AND NATURAL GAS PROGRAMS
The Company currently serves as a general partner to 4 oil and gas
limited partnerships and 10 employee oil and gas limited partnerships. The
employee partnerships acquire an interest fixed annually, ranging from 5%
to 15% of the Company's interest, in most oil and natural gas drilling
activities and purchases of producing oil and natural gas properties
participated in by the Company. The limited partners in the employee
partnerships are either employees or directors of the Company or its sub-
sidiaries.
Under the terms of the partnership agreements of each limited part-
nership, the general partner, which in each case is Unit Petroleum Company,
has broad discretionary authority to manage the business and operations of
the partnership, including the authority to make decisions on such matters
as the partnership's participation in a drilling location or a property
acquisition, the partnership's expenditure of funds and the distribution of
funds to partners. Because the business activities of the limited partners
on the one hand, and the general partner on the other hand, are not the
same, conflicts of interest will exist and it is not possible to eliminate
entirely such conflicts. Additionally, conflicts of interest may arise
where the Company is the operator of an oil and natural gas well and also
provides contract drilling services. Although the Company has no formal
procedures for resolving such conflicts, the Company believes it fulfills
its responsibility to each contracting party and complies fully with the
terms of the agreements which regulate such conflicts.
EMPLOYEES
As of February 23, 1999, the Company had approximately 453 employees
in its land contract drilling operations, 47 employees in its oil and natu-
ral gas operations and 44 in its general corporate area. None of the
Company's employees are represented by a union or labor organization nor
have the Company's operations ever been interrupted by a strike or work
stoppage. The Company considers relations with its employees to be
satisfactory.
OPERATING AND OTHER RISKS
The Company's land contract drilling and oil and natural gas
operations are subject to a variety of oil field hazards such as fire,
explosion, blowouts, cratering and oil spills or certain other types of
possible surface and subsurface pollution, any of which can cause personal
injury and loss of life and severely damage or destroy equipment, suspend
drilling operations and cause substantial damage to surrounding areas or
property of others. As protection against some, but not all, of these
operating hazards, the Company maintains broad insurance coverage,
including all-risk physical damage, employer's liability and comprehensive
general liability. In all states in which the Company operates except
Oklahoma, the Company maintains a large deductible worker's compensation
10
policy that insures for losses exceeding $200,000. In Oklahoma, starting
in August 1991, the Company elected to become self insured. In
consideration therewith, the Company purchased an excess liability
reinsurance policy to insure losses exceeding $250,000. The Company
believes that to the extent reasonably practicable such insurance coverages
are adequate. The Company's insurance policies do not, however, provide
protection against revenue losses incurred by reason of business inter-
ruptions caused by the destruction or damage of major items of equipment
nor certain types of hazards such as specific types of environmental
pollution claims. In view of the difficulties which may be encountered in
renewing such insurance at reasonable rates, no assurance can be given that
the Company will be able to maintain the amount of insurance coverage which
it considers adequate at reasonable rates. Moreover, loss of or serious
damage to any of the Company's equipment, although adequately covered by
insurance, could have an adverse effect upon the Company's earning
capacity.
The Company's oil and natural gas operations are also subject to all
of the risks and hazards typically associated with the search for and
production of oil and natural gas. These include the necessity of ex-
pending large sums of money for the location and acquisition of properties
and for drilling exploratory wells. In such exploratory work, many
failures and losses may occur before any accumulation of oil or natural gas
may be found. If oil or natural gas is encountered, there is no assurance
that it will be capable of being produced or will be in quantities
sufficient to warrant development or that it can be satisfactorily mar-
keted. The Company's future natural gas and crude oil revenues and
production, and therefore cash flow and income, are highly dependent upon
the Company's level of success in acquiring or finding additional reserves.
Without continuing reserve additions through exploration or acquisitions,
the Company's reserves and production will decline.
GOVERNMENTAL REGULATIONS
The production and sale of oil and natural gas is highly affected by
various state and federal regulations. All states in which the Company
conducts activities impose restrictions on the drilling, production and
sale of oil and natural gas, which often include requirements relating to
well spacing, waste prevention, production limitations, pollution preven-
tion and clean-up, obtaining drilling permits and similar matters. The
following discussion summarizes, in part, the regulations of the United
States oil and natural gas industry and is not intended to constitute a
complete discussion of the many statutes, rules, regulations and
governmental orders to which the Company's operations may be subject.
The Company's activities are subject to existing federal and state
laws and regulations governing environmental quality and pollution control.
Various states and governmental agencies are considering, and some have
adopted, laws and regulations regarding environmental control which could
adversely affect the business of the Company. Such 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 such 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. In the
opinion of the Company's management, its operations to date comply in all
11
material respects with applicable environmental legislation and regula-
tions; however, in view of the many uncertainties with respect to the
current controls, including their duration, interpretation and possible
modification, the Company can not predict the overall effect of such
controls on its operations.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the
"Wellhead Decontrol Act") became effective. Under the Wellhead Decontrol
Act, all remaining price and non-price controls of first sales under the
NGA and NGPA were removed effective January 1, 1993. Prices for deregulated
categories of natural gas fluctuate in response to market pressures which
currently favor purchasers and disfavor producers. As a result of the
deregulation of a greater proportion of the domestic United States natural
gas market and an increase in the availability of natural gas
transportation, a competitive trading market for natural gas has developed.
During the past several years, the Federal Energy Regulatory
Commission ("FERC") has adopted several regulations designed to accomplish
a more competitive, less regulated market for natural gas. These
regulations have materially affected the market for natural gas. The major
elements of several of these initiatives remain subject to appellate
review.
One of the initiatives FERC adopted was order 636. In brief, the
primary requirements of Order 636 are as follows: pipelines must separate
their sales and transportation services; pipelines must provide open access
transportation services that are equal in quality for all natural gas
suppliers and must provide access to storage on an open access contract
basis; pipelines that provide firm sales service on May 18, 1992 must offer
a "no-notice" firm transportation service under which firm shippers may
receive delivery of natural gas on demand up to their firm entitlement
without incurring daily balancing and scheduling penalties; pipelines must
provide all shippers with equal and timely access to information relevant
to the availability of their open access transportation services; open
access pipelines must allow firm transportation customers to downstream
pipelines to acquire capacity on upstream pipelines held by downstream
pipelines; pipelines must implement a capacity releasing program so that
firm shippers can release unwanted capacity to those desiring capacity
(which program replaces previous "capacity brokering" and "buy-sell"
programs); existing bundled firm sales entitlement are converted to
unbundled firm sales entitlement and to unbundled firm transportation
rights on the effective date of a particular pipeline's blanket sales
certificate; and pipeline transportation rights must be developed under the
Straight Fixed Variable (SFV) method of cost classification, allocation and
rate design unless the FERC permits the pipeline to use some other method.
The FERC will not permit a pipeline to change the new resulting rates until
the FERC accepts the pipeline's formal restructuring plans.
In essence, the goal of Order 636 is to make a pipeline's position as
natural gas merchant indistinguishable from that of a non-pipeline
supplier. It, therefore, pushes the point of sale of natural gas by
pipelines upstream, perhaps all the way to the wellhead. Order 636 also
requires pipelines to give firm transportation customers flexibility with
respect to receipt and delivery points (except that a firm shipper's choice
of delivery point cannot be downstream of the existing primary delivery
point) and to allow "no-notice" service (which means that natural gas is
12
available not only simultaneously but also without prior nomination, with
the only limitation being the customer's daily contract demand) if the
pipeline offered no-notice city-gate sales service on May 18, 1992. Thus,
this separation of pipelines' sales and transportation allows non-pipeline
sellers to acquire firm downstream transportation rights and thus to offer
buyers what is effectively a bundled city-gate sales service and it permits
each customer to assemble a package of services that serves its individual
requirements. But it also makes more difficult the coordination of natural
gas supply and transportation. A corollary to these changes is that all
pipelines will be permitted to sell natural gas at market-based rates.
The results of these changes may be the increased availability of firm
transportation and the reduction of interruptible transportation, with a
corresponding reduction in the rates for off-peak and interruptible
transportation. Due to the continuing evolutionary nature of Order 636 and
its implementation, it is not possible to project the overall potential
impact on transportation rates for natural gas or market prices of natural
gas.
The future interpretation and application by FERC of these rules and
its broad authority, or of the state and local regulations by the relevant
agencies, could affect the terms and availability of transportation
services for transportation of natural gas to customers and the prices at
which natural gas can be sold by the Company. For instance, as a result of
Order 636, more interstate pipeline companies have begun divesting their
gathering systems, either to unregulated affiliates or to third persons, a
practice which could result in separate, and higher, rates for gathering a
producer's natural gas. In proceedings during mid and late 1994 allowing
various interstate natural gas companies' spindowns or spinoffs of
gathering facilities, the FERC held that, except in limited circumstances
of abuse, it generally lacks jurisdiction over a pipeline's gathering
affiliates, which neither transport natural gas in interstate commerce nor
sell gas in interstate commerce for resale. However, pipelines spinning
down gathering systems have to include two Order No. 497 standards of
conduct in their tariffs: nondiscriminatory access to transportation for
all sources of supply and no tying of pipeline transportation service to
any service by the pipeline's gathering affiliate. In addition, if unable
to reach a mutually acceptable gathering contract with a present user of
the gathering facilities, the FERC required that the pipeline must offer a
two-year "default contract" to existing users of the gathering facilities.
However, on appeal, while the United States Court of Appeals for the
District of Columbia upheld the FERC's allowing the spinning down of
gathering facilities to a non-regulated affiliate, in Conoco Inc. v. FERC,
90 F.3d 536, 552-53 (D.C. Cir. 1996)the D.C. Circuit remanded the FERC's
default contract mechanism. On February 18, 1997, the United States
Supreme Court denied review of the D.C. Circuit's decision.
Additional proceedings that might affect the natural gas industry are
pending before the FERC and the courts. The natural gas industry
historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by
the FERC and Congress will continue. Sales of petroleum liquids by the
Company are not currently regulated and are made at market prices; however,
the FERC is considering a proposal that could increase transportation rates
for petroleum liquids. A number of legislative proposals have also been
introduced in Congress and the state legislatures of various states, that,
13
if enacted, would significantly affect the petroleum industry. Such
proposals involve, among other things, the imposition of land and use
controls and certain measures designed to prevent petroleum companies from
acquiring assets in other energy areas. In addition, there is always the
possibility that if market conditions change dramatically in favor of oil
and natural gas producers that some new form of "windfall profits" or
severance tax may be proposed and imposed upon oil or natural gas. At the
present time it is impossible to predict which proposals, if any, will
actually be enacted by Congress or the various state legislatures. The
Company believes that it is complying with all orders and regulations
applicable to its operations. However, in view of the many uncertainties
with respect to the current controls, including their duration and possible
modification together with any new proposals that may be enacted, the
Company cannot predict the overall effect, if any, of such controls on
Company operations.
Certain states in which the Company operates control production from
wells through regulations establishing the spacing of wells, limiting the
number of days in a given month during which a well can produce and
otherwise controlling the rate of allowable production.
As noted above, the Company's 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.
A past, present, or future release or threatened release of a
hazardous substance into the air, water, or ground by the Company or as a
result of disposal practices may subject the Company 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
pursuant thereto. Under CERCLA and similar laws, the Company may be fully
liable for the cleanup costs of a release of hazardous substances even
though it 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 the Company. In certain circumstances, the
Company may have liability for releases of hazardous substances by previous
owners of Company properties. CERCLA currently excludes petroleum from its
definition of "hazardous substances." However, Congress may delete this
exclusion for petroleum, in which case the Company would be required to
manage its petroleum production and wastes from its 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 the Company would
have to manage much of its oilfield waste as hazardous. Additionally, the
discharge or substantial threat of a discharge of oil by the Company into
United States waters or onto an adjoining shoreline may subject the Company
to liability under the Oil Pollution Act of 1990 and similar state laws.
While liability under the Oil Pollution Act of 1990 is limited under
certain circumstances, the maximum liability under those limits would still
likely have a significant adverse effect on the Company.
14
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. The Company
believes that the Company has complied with all orders and regulations
applicable to its operations. However, in view of many uncertainties with
respect to the current controls, including their duration and possible
modification, the Company cannot predict the overall effect of such
controls on such operations. Similarly, the Company cannot predict what
future environmental laws may be enacted or regulations may be promulgated
and what, if any, impact they would have on operations.
SAFE HARBOR STATEMENT OF FURTHER ACTIVITY
In the normal course of its business, the Company, in an effort to
help keep its shareholders and the public informed about the Company's
operations, may, from time to time, issue certain statements, either in
writing or orally, that contain or may contain forward looking information.
Generally, these statements relate to projections involving the anticipated
revenues to be received from the Company's oil and natural gas production
or drilling operations, the utilization rate of its drilling rigs, growth
of its oil and natural gas reserves, well performance, and the Company's
anticipated debt.
Statements in this Annual Report on Form 10-K under the captions
"Business" and "Management's Discussion and Analysis of Financial Condition
and Results of Operations", as well as oral statements that may be made by
the Company or by officers, directors or employees of the Company acting on
the Company's behalf, that are not historical facts constitute "forward-
looking statements" within the meaning of the Private Securities Litigation
Reform Act of 1995. Words such as "believes", "anticipates" and similar
expressions, although not inclusive, identify forward-looking statements.
Such forward-looking statements are subject to a number of factors that may
tend to influence the accuracy of the statements and the projections upon
which the statements are based. As noted elsewhere in this report, all
phases of the Company's operations are subject to a number of influences
outside the control of the Company, any one of which, or a combination of
which, could materially affect the results of the Company's operations.
All future written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
In order to provide a more thorough understanding of the possible
effects of some of these influences on any forward looking statements made
by the Company, the following discussion outlines certain factors that in
the future could cause the Company's consolidated results for 1999 and
beyond to differ materially from those that may be set forth in any such
forward-looking statement made by or on behalf of the Company.
15
Commodity Prices
The prices received by the Company for its oil and natural gas
production have a direct impact on the Company's revenues, profitability
and cash flow as well as its ability to meet its projected financial and
operational goals. The prices for natural gas and crude oil are heavily
dependent on a number of factors beyond the control of the Company,
including, but not limited to, the demand for oil and/or natural gas;
current weather conditions in the continental United States which can
greatly influence the demand for natural gas at any given time as well as
the price to be received for such gas; and the ability of current
distribution systems in the United States to effectively meet the demand
for oil and or natural gas at any given time, particularly in times of peak
demand which may result due to adverse weather conditions. Oil prices are
extremely sensitive to foreign influences that may be based on political,
social or economic underpinnings, any one of which could have an immediate
and significant effect on the price and supply of oil. In addition, prices
of both natural gas and oil are becoming more and more influenced by
trading on the commodities markets which, at times, has tended to increase
the volatility associated with these prices resulting at times in large
difference in such prices even on a month to month basis. All these
factors, especially when coupled with the fact that much of the Company's
product prices are determined on a month to month basis, can, and at times
do, lead to wide fluctuations in the prices received by the Company.
Based upon the results of operations for the year ended December
31, 1998, the Company estimates that a change of $0.10/Mcf in the average
price of natural gas and a change of $1.00/Bbl in the price of crude oil
throughout such period would have resulted in approximate changes in net
income before income taxes of $1,541,000 and $414,000, respectively. During
1998, substantially all of the natural gas and crude oil volume of the
Company were sold at market responsive prices.
Customer Demand
Demand for the Company's drilling services is dependent almost entirely on
the needs of third parties. Based on past history, such parties' requirements
are subject to a number of factors, independent of any subjective factors, that
directly impact the demand for the Company's drilling rigs. These include the
funds available to such companies to carry out their drilling operations during
any given time period which, in turn, are often subject to downward revision
based on decreases in the then current prices of oil and natural gas. Many of
the Company's customers are small to mid-size oil and natural gas companies
whose drilling budgets tend to be susceptible to the influences of current price
fluctuations. Other factors that affect the Company's ability to work its
drilling rigs are the weather, which can, under adverse circumstances, delay or
even cause a project to be abandoned by an operator, the competition faced by
the Company in securing the award of a drilling contract in a given area, the
experience and recognition of the Company in a new market area, and the
availability of labor to run the Company's drilling rigs.
16
Uncertainty Of Oil And Natural Gas Reserves And Well Performance
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company.
Estimating quantities of proved reserves is imprecise. Such estimates are
based upon certain assumptions pertaining to future production levels,
future natural gas and crude oil prices, timing and amount of development
expenditures and future operating costs, using currently available
geologic, engineering and economic data, some or all of which may prove to
be incorrect over time. As a result of changes in these assumptions that
will occur in the future, and based upon further production history,
results of future exploration and development activities, future natural
gas and crude oil prices and other factors, the reported quantity of
reserves may be subject to upward or downward revision.
In addition to the foregoing, projections regarding the potential
production and reserve capabilities of newly drilled and/ or completed
wells are subject to additional uncertainties that may significantly
influence such projections. Such wells have a very limited production
history, if any, on which to base future forecasts of their capabilities.
Since an established rate of production is a primary factor used by
reservoir engineers to forecast oil and natural gas reserves as well as a
well's production rate, the lack of this information decreases the
Company's ability to accurately project such information. In addition,
there are inherent risks in both the drilling and completion phases of a
new well which could cause a well bore to be prematurely abandoned due
either to the loss of the well bore in the physical sense or due to the
costs associated with operational problems which could render further
operations uneconomical.
Debt and Bank Borrowing
The amount of the Company's existing debt as well as its future debt
is, to a large extent, a function of the costs associated with the projects
undertaken by the Company at any given time and the cash flow received by
the Company. Generally, the costs incurred by the Company in its normal
operations are those associated with the drilling of oil and natural gas
wells, the acquisition of producing properties, and the costs associated
with the maintenance of its drilling rig fleet. To some extent, these
costs, particularly the first two items, are discretionary and the Company
maintains a degree of control regarding the timing and/ or the need to
incur the same. However, in some cases, unforseen circumstances may arise,
such as in the case of an unanticipated opportunity to acquire a large
producing property package or the need to replace a costly rig component
due to an unexpected loss, which could force the Company to incur increased
debt above that which it had expected or forecast. Likewise, for many of
the reasons mentioned above, the Company's cash flow may not be sufficient
to cover its current cash requirements which would then require the Company
to increase its debt either through bank borrowings or otherwise.
17
International Operations and Risks
Currently all of the Company's contract land drilling operations are
conducted within the continental United States. Should, however, the
Company at some point in the future undertake international drilling
operations, such operations would be subject to a number of risks including
foreign exchange restrictions, currency fluctuations, foreign taxation,
changing political conditions and foreign and domestic policies,
expropriation, nationalization, nullification, modification or
renegotiation of contracts, war and civil disturbances or other risks that
may limit or disrupt markets. In addition, the Company would incur certain
additional costs in establishing and running such operations.
Item 3. Legal Proceedings
- --------------------------
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,
should result in judgments which would have a material adverse effect on
the Company.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
No matters were submitted to the security holders during the fourth
quarter of the Company's calendar year ended December 31, 1998.
18
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- --------------------------------------------------------------------------
Matters
- -------
As of February 23, 1999, the Company had 2,543 holders of record of
its common stock the only form of stock issued as of that date. The
Company has not paid any cash dividends on shares of its common stock since
its organization and currently intends to continue its policy of retaining
earnings from the Company's operations. The Company is prohibited, by
certain loan agreement provisions, from declaring and paying dividends
(other than stock dividends) during any fiscal year in excess of 25 percent
of its consolidated net income of 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. The table below reflects the high and low sales prices per
share of the Company's common stock as reported by the New York Stock
Exchange, Inc. for the period indicated:
1998 1997
-------------------- --------------------
QUARTER High Low High Low
------- --------- --------- --------- ---------
First $ 9 13/16 $ 6 7/16 $12 1/4 $ 7 1/2
Second $ 9 7/8 $ 5 1/2 $11 7/8 $ 7 7/8
Third $ 6 5/16 $ 3 3/4 $15 3/8 $ 9 5/8
Fourth $ 6 15/16 $ 3 5/8 $15 13/16 $ 8 7/16
19
Item 6. Selected Financial Data
- --------------------------------
Year Ended December 31,
---------------------------------------------------
1998 1997 1996 1995 1994
------- ------- ------- ------- -------
(In thousands except per share amounts)
Revenues $93,337 $91,864 $72,070 $53,074 $43,895
======= ======= ======= ======= =======
Income From Continuing
Operations $ 2,246 $11,124 $ 8,333 $ 3,751 (1) $ 4,628 (2)
======= ======= ======= ======= =======
Net Income $ 2,246 $11,124 $ 8,333 $ 3,999 (1) $ 4,794 (2)
======= ======= ======= ======= =======
Basic Earnings Per
Common Share:
Continuing Operations $.09 $.46 $.37 $.18 (1) $.22 (2)
Discontinued Operation - - - .01 .01
---- ---- ---- ---- ----
Net Income $.09 $.46 $.37 $.19 (1) $.23 (2)
==== ==== ==== ==== ====
Diluted Earnings Per
Common Share:
Continuing Operations $.09 $.45 $.37 $.18 (1) $.22 (2)
Discontinued Operation - - - .01 .01 (2)
---- ---- ---- ---- ----
Net Income $.09 $.45 $.37 $.19 (1) $.23
==== ==== ==== ==== ====
Total Assets $223,064 $202,497 $137,993 $110,922 $103,933
======== ======== ======== ======== ========
Long-Term Debt $ 72,900 $ 54,100 $ 40,600 $ 41,100 $ 37,300
======== ======== ======== ======== ========
Other Long-Term
Liabilities $ 2,301 $ 2,279 $ 2,276 $ 2,109 $ 2,673
======== ======== ======== ======== ========
Cash Dividends
Per Common Share $ - $ - $ - $ - $ -
======== ======== ======== ======== ========
___________
(1) Includes a $635,000 gain on compressor sale, a $850,000 gain from
settlement of litigation and a net $530,000 deferred tax benefit.
(2) Includes a $742,000 gain on sale of a natural gas gathering
system.
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1998, 1997 and 1996 activity.
20
Item 7. Management's Discussion and Analysis of Financial Condition and
- ------------------------------------------------------------------------
Results of Operations
- ---------------------
Financial Condition and Liquidity
- ---------------------------------
The Company's loan agreement ("Loan Agreement"), provides for a total
facility 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 revolving credit facility are limited to a borrowing value which
is subject to a semi-annual redetermination. As of the latest borrowing
value determination, $85 million of the commitment is available to the
Company. The Loan Agreement contains certain covenants which require the
Company to maintain consolidated tangible 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. At
December 31, 1998, borrowings under the Loan Agreement totaled $68.9
million. At February 23, 1999, borrowings under the Loan Agreement totaled
$71.0 million with $11.4 million available for future borrowings. The
interest rate on the bank debt was 6.27 and 6.31 percent at December 31,
1998 and February 23, 1999, respectively. At the Company's election, any
portion of the debt outstanding may be fixed at the London Interbank
Offered Rate ("Libor Rate"), as adjusted per the Loan Agreement depending
on the level of debt as a percentage of the total borrowing base, for 30,
60, 90 or 180 days with the remainder of the outstanding debt subject to
the Chase Manhattan Bank, N. A. prime rate ("Chase Prime Rate"). 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. At both December 31, 1998 and February 23, 1999, $63.0
million of borrowings were subject to the Libor Rate as adjusted. A
commitment fee of 3/8 of 1 percent is charged for any unused portion of the
borrowing base.
Shareholders' equity at December 31, 1998 was $111.3 million, making
the Company's ratio of long-term debt-to-equity .66 to 1. The Company's
primary source of liquidity and capital resources in the near- and long-
term will consist of cash flow from operating activities and available
borrowings under the Loan Agreement. Net cash provided by operating
activities in 1998 was $33.5 million as compared to $34.4 million in 1997.
At December 31, 1998 and January 31, 1999, the Company had working capital
of $1.6 million and $1.0 million, respectively.
The Company's capital expenditures during 1998 were $50.1 million.
The Company's oil and natural gas operations had capital expenditures of
$38.4 million, with $24.9 million and $9.0 million used for exploration and
development drilling and producing property acquisitions, respectively.
Capital expenditures made by the Company's contract drilling operations
were $11.5 million in 1998. Drilling capital expenditures in 1998 were for
drill pipe and collars, the refurbishment of one drilling rig previously
stacked and major overhauls on large rig components of drilling rigs in
21
service. The Company's drilling rigs are composed of large components some
of which, on a rotational basis, are required to be overhauled to assure
continued proper performance. Such capital expenditures will continue in
future years with approximately $2.5 million projected for 1999.
During 1999, the Company's oil and natural gas exploration subsidiary
plans to continue its developmental drilling program. However, lower spot
market natural gas prices in the fourth quarter of 1998 have increased the
potential availability of economical producing property acquisitions and,
as a result, a larger portion of the Company's capital expenditure budget
may be shifted to producing property acquisitions in 1999. The majority of
the Company's capital expenditures are discretionary and primarily directed
toward increasing reserves and future growth. Current operations are not
dependent on the Company's ability to obtain funds outside of the Company's
Loan Agreement. The decision to acquire or drill on oil and natural gas
properties at any given time depends on market conditions, potential return
on investment, future drilling potential and the availability of
opportunities to obtain financing given the circumstances involved, thus
providing the Company with a large degree of flexibility in incurring such
costs. Depending, in part, on commodity pricing, the Company plans to
spend approximately $20 million on its exploration capital expenditure
program in 1999.
On November 20, 1997, the Company acquired Hickman Drilling Company,
pursuant to an Agreement and Plan of Merger ("the Merger Agreement"),
entered into by and between the Company, Hickman Drilling Company and all
of the holders of the outstanding capital stock of Hickman Drilling Company
(the "Selling Stockholders"). Under the terms of this acquisition, the
Selling Stockholders received, in aggregate, 1,300,000 shares of 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. The notes bear interest at
the Chase Prime Rate which at both December 31, 1998 and February 23, 1999
was 7.75 percent. In December 1997, the Company also purchased a Mid-
Continent U-36-A, 650 horsepower rig with a 13,000 feet depth capacity and
spare components from two additional rigs for a total consideration of $1
million, of which $200,000 was paid at closing and the balance is being
paid out over a period ending no later than three years after the
acquisition date. The balance is paid out monthly with the monthly amount
calculated on the basis of a predetermined daily rate multiplied by the
number of days in such month that the acquired rig is employed for the
account of the seller, all as more fully specified in the acquisition
agreement. If the balance of the purchase price has not been fully paid at
the end of three years the remaining amount is to be paid in cash to the
seller. At December 31, 1998, the balance remaining under this purchase
agreement was $331,000.
In March of 1998, a Vice President of South America Drilling
Operations was hired to facilitate the Company's efforts to expand its
contract drilling operations outside the continental United States,
specifically into areas of South America. Drilling markets in South
America have the potential to provide higher profit margins and higher
profit contributions, with longer term multi-year contracts which could
also provide a leveling effect on drilling rig utilization. The Company
22
has not previously conducted international contract drilling operations,
but it anticipates that such operations would involve a number of
additional political, economic, currency, tax and other risks and costs not
generally encountered in its domestic operations. To date, the Company has
not entered into any contracts for international work.
Prior to December 31, 1997, the Company received monthly payments on
behalf of itself and other parties (collectively the "Committed Interest")
from a natural gas purchaser pursuant to a settlement agreement (the
"Settlement Agreement"). The monthly payments paid by the purchaser for
natural gas not taken (the "Prepayment Balance") were subject to recoupment
in volumes of natural gas through a period ending on the earlier of
recoupment or December 31, 1997 (the "Recoupment Period"). At December 31,
1997, the Settlement Agreement and the natural gas purchase contracts which
were subject to the Settlement Agreement terminated. As a result of the
Settlement Agreement, 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 price
per Mcf under the Settlement Agreement was substantially higher than
current spot market prices. The impact of the higher price received under
the Settlement Agreement increased pre-tax income approximately $540,000
and $650,000 in 1997 and 1996, respectively. The natural gas previously
subject to the Settlement Agreement is now being sold at spot market prices
consistent with primarily all of the rest of the natural gas sold by the
Company.
Oil and natural gas prices received by the Company were volatile
throughout 1998. Average oil prices received by the Company in December
1998, as compared to January 1998, dropped by 35 percent. Average natural
gas prices in December 1998, as compared to January 1998, were one percent
higher after recovering from a 20 percent decrease in August and September
of 1998. The Company's average price received for oil during 1998 was
$12.81 and the average natural gas price was $1.90. Average oil prices and
natural gas spot prices received in February 1999 were up 5 percent for oil
and down 16 percent for natural gas, when compared with December 31, 1998
average prices. The large drop in natural gas prices in February 1999 had
a significant impact to the value of the Company's natural gas reserves as
reported at December 31, 1998. If this lower natural gas price had
occurred at year-end 1998, it would have caused the Company to reduce the
carrying value of its natural gas properties by approximately $22.0 million
before taxes. If prices do not recover from this February level and
depending on other variables, the Company will record a provision to reduce
the carrying value of oil and natural gas properties in the first quarter
of 1999. Oil prices within the industry remain largely dependent upon
world market developments for crude oil. Prices for natural gas are
influenced by weather conditions and supply imbalances, particularly in the
domestic market, and by world wide oil price levels. Declines in natural
gas or oil prices could also adversely effect the Company operationally by,
for example, adversely impacting future demand for its drilling rigs or
financially by reducing the price received for its oil and natural gas
sales and also by adversely effecting the semi-annual borrowing value
determination under the Company's Loan Agreement since this determination
is calculated on the value of the Company's oil and natural gas reserves.
23
At December 31, 1998, the Company did not have any hedge against the
fluctuation in the price of oil and natural gas nor did the Company
maintain any forward or future contracts relating to the production of its
oil and natural gas. In the first quarter of 1999, the Company initiated
swap transactions to help manage its exposure to commodity price risk in
the month to month sale of natural gas. These transactions cover
approximately 20 percent of the Company's daily production and cover the
period from March 1, 1999 to June 30, 1999. These activities have been
designated as hedging activities by the Company and will be accounted for
as such. Increases (decreases) in the fair value of these instruments will
generally offset increases (decreases) in the spot market prices of natural
gas. Implicit gains or losses, resulting from changes in the fair value of
hedges which have not yet been settled, are not recognized to the extent
that they relate to changes in the spot price of anticipated natural gas
sales. Gains or losses arising from hedge transactions are recorded in
sales in the month of the hedged transaction.
As a result of the depressed condition existing in the contract
drilling industry over much of the past decade, the Company's ability to
fully utilize its complement of drilling rigs during portions of 1997 and
1998 when there was a rapid increase in drilling activity was limited due
to the lack of qualified labor and certain support equipment not only
within the Company, but in the industry as a whole. The Company's ability
to utilize its drilling rigs at any given time is dependent on a number of
factors, including but not limited to, the price of both oil and natural
gas, the availability of labor and the Company's ability to supply the type
of equipment required. Although the Company currently does not have a
shortage of rig labor or support equipment, the Company's management
expects that these factors will continue to influence the Company's rig
utilization especially if demand should rapidly increase.
In the third quarter of 1994, the Company's Board of Directors
authorized the Company to purchase up to 1,000,000 shares of the Company's
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. During the first quarters of 1998, 1997 and 1996, 19,863, 23,892
and 44,686 of the purchased shares, respectively, were reissued as the
Company's matching contribution to its 401(k) Employee Thrift Plan. At
December 31, 1998, 25,000 treasury shares were held by the Company.
Year 2000 Statement
- -------------------
The Company has initiated a comprehensive assessment of its
information technology ("IT") and non-information technology ("non-IT")
systems to try and ensure that such 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 the Company but also for its customers and suppliers, so the
Company has also initiated an assessment of its customers' and suppliers'
efforts to become year 2000 compliant.
24
Evaluation of the Company's IT systems began in house during 1997.
The Company's IT systems consist mainly of office computers, related
computer programs and mangement financial information software. The
Company believes nearly all of the Company's hardware is Year 2000
compliant and approximately 20 percent of its related computer programs and
software are Year 2000 compliant. The Company has expended approximately
$92,000 and estimates it will expend an additional $40,000 to bring the
remaining systems compliant by the end of the second quarter of 1999.
The Company's non-IT systems consist of office equipment and other
systems associated with its oil and natural gas properties and its drilling
rigs. The Company began assessing these non-IT systems and the associated
cost during the fourth quarter of 1998. The assessment and replacement of
equipment, if any, should be completed by the end of the second quarter of
1999. The Company anticipates that the cost associated with non-IT systems
will be minimal.
During the third quarter of 1998, the Company issued questionnaires to
its key suppliers and customers to assess their preparation for Year 2000
compliance. The Company received responses from 41 percent of these
entities. Approximately 90 percent of the responses indicated that these
entities are aware of and are in the process of resolving their Year 2000
issues. During the first quarter of 1999, the Company will issue second
request questionnaires to those key suppliers and customers who did not
respond to the questionnaires issued during the third quarter of 1998.
Upon the return of the second request questionnaires from these non-
affiliated entities, the Company will review their responses and will begin
the process of assessing the preparedness of these entities.
As noted, the Company currently anticipates that all of its internal
systems and equipment will be Year 2000 compliant by the end of the second
quarter of 1999 and that the associated costs will not have a material
adverse effect on the Company's results of operations and financial
condition. However, the failure to properly assess or timely implement a
material Year 2000 problem could result in a disruption in the Company's
normal business activities or operations. Such failures, depending on the
extent and nature, could materially and adversely effect the Company's
operations and financial condition. As a result, the Company will continue
to evaluate its Year 2000 exposure, both internally and externally. Since
a portion of the Company's overall evaluation of its Year 2000 readiness
will, of necessity, be based on the information to be supplied by and the
readiness of the Company's key suppliers and customers, the Company cannot
currently determine the impact, if any, such third parties will have on the
Company's Year 2000 exposure. As noted, the Company intends to evaluate
this information as, if and when it is made available to it. To date, the
Company has not developed a contingency plan.
25
Effects of Inflation
- ---------------------
The effects of inflation on the Company's operations in previous years
have been minimal due to low inflation rates. However, during third and
fourth quarters of 1996 and throughout 1997 as drilling rig day rates and
drilling rig utilization increased, the impact of inflation intensified as
the availability of related equipment, third party services and qualified
labor decreased. In 1998, the impact of inflation was reduced as oil and
natural gas prices became depressed. The impact on the Company in the
future will depend on the relative increase, if any, the Company may
realize in its drilling rig rates and the selling price of its oil and
natural gas. If industry activity suddenly increases substantially,
shortages in support equipment such as drill pipe, third party services and
qualified labor will occur resulting in additional corresponding increases
in material and labor costs. These market conditions may limit the
Company's ability to realize improvements in operating profits.
Results of Operations
- ---------------------
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 day 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 the
Company's 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 the Company decreased 20
percent. The natural gas previously subject to the 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 the Company. 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 19.2 rigs operating in
1997 to 22.9 rigs operating in 1998. Daywork revenues per rig per day
decreased 3 percent between the comparative years. During the first three
quarters of 1998, the Company's monthly rig utilization consistently
remained at or above 23 rigs with daywork revenue per rig per day declining
by 8 percent from the January 1998 rate. In the fourth quarter utilization
dropped 27 percent from the previous quarter and dayrates decreased another
6 percent from the previous quarter. 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.
26
Operating margins (revenues less operating costs) for the Company's
oil and natural gas 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 the Company
between the two years. Total operating costs were 9 percent higher in 1998
compared to 1997 as the Company continues 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 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 oil and natural gas properties increased 27 percent as the
Company increased its equivalent barrels of production by 14 percent and
the Company's average DD&A rate per equivalent barrel increased 11 percent
to $4.99 in 1998.
General and administrative expenses increased 6 percent as certain
employee costs increased. Interest expense increased 65 percent as the
Company's 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 6 percent in 1997 due to a 6
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 6 percent decrease
in average oil prices received by the Company in 1997. Oil production
declined from 1996 levels due to the Company's 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 the Company increased 11 percent while volumes produced from
certain wells included under the Settlement Agreement, which ended at
December 31, 1997 and contained provisions for prices higher than current
spot market prices, dropped 7 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 19.2 rigs operating in 1997, and daywork revenues per rig per day
increased 22 percent. During the first three quarters of 1997, the
Company's monthly rig utilization consistently remained above 18 rigs with
27
daywork revenue per rig per day steadily climbing by 15 percent. In October
utilization dropped slightly below 18 rigs before the Company acquired 9
rigs through the Hickman acquisition in late November 1997 and another rig
in December 1997, raising the Company's rig count to 34 rigs and its
utilization in December to 26.2 rigs. Daywork revenue per rig per day
continued to rise in the fourth quarter, but the Company's average dayrate
declined 9 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 the Company's
oil and natural gas 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 the Company between the two years. Total operating costs were
2 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 the Company increased
its equivalent barrels of production by 2 percent and the Company's average
DD&A rate per equivalent barrel increased 15 percent to $4.49 in 1997.
General and administrative expenses increased 12 percent as certain
employee costs and outside services increased. Interest expense decreased 8
percent as the average interest rate on the Company's outstanding bank debt
decreased from 7.69 percent in 1996 to 7.27 percent in 1997. Average bank
debt also decreased 4 percent during 1997.
Prior to 1996, the Company's effective income tax rate was
significantly impacted by its net operating loss carryforwards. As of
December 31, 1995, the Company's net operating loss and statutory depletion
carryforwards were fully recognized for financial reporting purposes;
therefore, the Company's effective income tax rate in 1996 and 1997
increased to approximately the statutory rate.
28
Item 8. Financial Statements and Supplementary Data
- -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
-------------------------
ASSETS 1998 1997
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 446 $ 458
Accounts receivable (less allowance for
doubtful accounts of $274 and $354) 13,149 19,813
Materials and supplies 3,298 3,535
Prepaid expenses and other 2,650 2,206
---------- ----------
Total current assets 19,543 26,012
---------- ----------
Property and Equipment:
Drilling equipment 123,258 119,155
Oil and natural gas properties, on the full
cost method 271,960 233,659
Transportation equipment 2,955 2,825
Other 6,870 6,948
---------- ----------
405,043 362,587
Less accumulated depreciation, depletion,
amortization and impairment 207,883 192,613
---------- ----------
Net property and equipment 197,160 169,974
---------- ----------
Other Assets 6,361 6,511
---------- ----------
Total Assets $ 223,064 $ 202,497
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
29
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31,
-------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY 1998 1997
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term
liabilities and debt $ 1,801 $ 727
Accounts payable 8,517 11,112
Accrued liabilities 7,362 7,762
Contract advances 310 92
---------- ----------
Total current liabilities 17,990 19,693
---------- ----------
Other Long-Term Liabilities (Note 5) 2,301 2,279
---------- ----------
Long-Term Debt 72,900 54,100
---------- ----------
Deferred Income Taxes 18,583 17,560
---------- ----------
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, 25,563,165 and
25,514,836 shares issued, respectively 5,113 5,103
Capital in excess of par value 82,187 82,043
Retained earnings 24,121 21,875
Treasury stock, at cost (25,000 and
19,863 shares, respectively) (131) (156)
---------- ----------
Total shareholders' equity 111,290 108,865
---------- ----------
Total Liabilities and Shareholders' Equity $ 223,064 $ 202,497
========== ==========
The accompanying notes are an integral part of the
consolidated financial statements
30
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
----------------------------------
1998 1997 1996
-------- -------- --------
(In thousands except per share amounts)
Revenues:
Contract drilling $53,528 $46,199 $28,819
Oil and natural gas 39,703 45,581 43,013
Other 106 84 238
-------- -------- --------
Total revenues 93,337 91,864 72,070
-------- -------- --------
Expenses:
Contract drilling:
Operating costs 43,729 36,419 24,259
Depreciation 5,766 4,216 2,944
Oil and natural gas:
Operating costs 14,328 13,201 13,409
Depreciation, depletion
and amortization 16,069 12,625 10,807
General and administrative 4,891 4,621 4,122
Interest 4,815 2,921 3,162
-------- -------- --------
Total expenses 89,598 74,003 58,703
-------- -------- --------
Income Before Income Taxes 3,739 17,861 13,367
-------- -------- --------
Income Tax Expense:
Current 139 118 4
Deferred 1,354 6,619 5,030
-------- -------- --------
Total income taxes 1,493 6,737 5,034
-------- -------- --------
Net Income $ 2,246 $11,124 $ 8,333
======== ======== ========
Net Income Per Common Share:
Basic $ .09 $ .46 $ .37
======== ======== ========
Diluted $ .09 $ .45 $ .37
======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
31
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1996, 1997 and 1998
Capital
In Excess
Common Of Par Retained Treasury
Stock Value Earnings Stock Total
-------- -------- --------- -------- ---------
(In thousands)
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
======== ======== ========= ======== =========
The accompanying notes are an integral part of the
consolidated financial statements
32
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
Cash Flows From Operating Activities:
Net Income $ 2,246 $ 11,124 $ 8,333
Adjustments to reconcile net
income to net cash provided
(used) by operating activities:
Depreciation, depletion, and
amortization 22,186 17,199 14,079
Loss (gain) on disposition
of assets 17 (94) (185)
Employee stock compensation plans 561 244 214
Bad debt expense - 250 -
Deferred tax expense (benefit) 1,354 6,619 5,030
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable 6,664 (1,762) (5,444)
Materials and supplies 237 (1,233) (254)
Prepaid expenses and other (444) (211) (418)
Accounts payable 948 2,062 (2,288)
Accrued liabilities (27) 1,430 540
Contract advances 218 (1,208) 890
Other liabilities (447) (70) 167
--------- --------- ---------
Net cash provided
by operating activities 33,513 34,350 20,664
--------- --------- ---------
The accompanying notes are an integral part of the
consolidated financial statements
33
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions) $(53,654) $(45,115) $(34,111)
Cash received on acquisition
of drilling company (Note 2) - 1,611 -
Proceeds from disposition of
property and equipment 964 792 1,009
(Acquisition) disposition
of other assets- (93) (314) 215
--------- --------- ---------
Net cash used in
investing activities (52,783) (43,026) (32,887)
--------- --------- ---------
Cash Flows From Financing Activities:
Borrowings under line of credit 52,700 34,400 31,500
Payments under line of credit (32,900) (25,900) (32,000)
Net payments on notes payable
and other long-term debt (470) - (20)
Proceeds from sale of common stock 59 225 12,798
Acquisition of treasury stock (131) (138) (42)
--------- --------- ---------
Net cash provided by
financing activities 19,258 8,587 12,236
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents (12) (89) 13
Cash and Cash Equivalents,
Beginning of Year 458 547 534
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 446 $ 458 $ 547
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 4,064 $ 2,910 $ 3,189
Income taxes $ 507 $ 102 $ 63
The accompanying notes are an integral part of the
consolidated financial statements
34
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.
35
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
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,
1998 and 1997 was $5,818,000 and $6,061,000, respectively with accumulated
amortization at December 31, 1998 and 1997 of $264,000 and $20,000,
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
36
petroleum engineers. The average composite rates used for depreciation,
depletion and amortization ("DD&A") were $4.99, $4.49 and $3.90 per
equivalent barrel in 1998, 1997 and 1996, 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 1998 and 1997 the Company recorded $437,000 and $314,000 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.
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.
37
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 no