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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, 1996
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:
Name of each exchange
Title of each class on which registered
Common Stock, par value New York Stock Exchange
$.20 per share
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Warrants to Purchase Shares of Common Stock
(Title of Class)
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 10, 1997 - $171,630,448
Number of Shares of Common Stock
Outstanding on March 10, 1997 - 24,176,734
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of Registrant's Proxy Statement with respect to the Annual
Meeting of Stockholders to be held May 7, 1997 are incorporated by
reference in Part III.
Exhibit Index - See Page 76
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. . . . . . . . . . . . . . . . . . . 65
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . 65
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . 67
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . . . 67
Item 13. Certain Relationships and Related Transactions . . . . . . . . . 67
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . 68
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 1996
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
operates primarily in the Anadarko and Arkoma Basins, which cover portions
of Oklahoma, Texas, Kansas and Arkansas and has additional producing
properties located in Canada and other states, including but not limited
to, New Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana,
Alabama and Mississippi.
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, Oklahoma,
Booker, Texas and Houston, Texas. As used herein, 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 acquire oil and natural gas properties
to diversify its source of revenues which had previously been derived from
contract drilling. The development, production and sale of oil and natural
gas together with the acquisition of producing properties now constitutes
the largest part of the Company's operations as conducted through its
wholly owned subsidiary, Unit Petroleum Company.
1
As of December 31, 1996, the Company had 5,204 Mbbls and 129,161 MMcf
of estimated proved oil and natural gas reserves, respectively. The
Company's producing oil and natural gas interests, undeveloped leaseholds
and related assets are located primarily in Oklahoma, Texas, Louisiana and
New Mexico and to a lesser extent in Arkansas, North Dakota, Colorado, Wyo-
ming, Montana, Alabama, Mississippi and Canada. As of December 31, 1996,
the Company had an interest in a total of 2,247 wells in the United States
and served as the operator of 502 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,
1996 1995 1994
Wells drilled: Gross Net Gross Net Gross Net
- -------------- ------ ------ ------ ------ ------ ------
Exploratory:
Oil.............. - - - - - -
Natural gas...... - - - - 1 .98
Dry.............. - - - - 2 .80
------ ------ ------ ------ ------ ------
Total - - - - 3 1.78
====== ====== ====== ====== ====== ======
Development:
Oil.............. 10 8.35 15 4.70 5 5.00
Natural gas...... 55 19.46 26 7.02 40 13.46
Dry.............. 7 4.26 6 2.27 12 7.26
------ ------ ------ ------ ------ ------
Total 72 32.07 47 13.99 57 25.72
====== ====== ====== ====== ====== ======
Oil and natural gas wells producing or capable of producing:
- ------------------------------------------------------------
Oil - USA........ 717 197.71 750 207.80 675 177.68
Oil - Canada..... - - - - - -
Gas - USA........ 1,530 242.09 1,820 232.03 1,089 179.99
Gas - Canada..... 64 1.60 65 1.63 61 1.53
------ ------ ------ ------ ------ ------
Total 2,311 441.40 2,635 441.46 1,825 359.20
====== ====== ====== ====== ====== ======
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
------- ------- ------- -------
1996
----
USA 455,713 115,326 29,245 19,124
Canada 39,040 976 - -
------- ------- ------- -------
Total 494,753 116,302 29,245 19,124
======= ======= ======= =======
1995
----
USA 548,674 117,403 24,810 12,866
Canada 31,360 784 - -
------- ------- ------- -------
Total 580,304 118,187 24,810 12,866
======= ======= ======= =======
1994
----
USA 340,241 100,732 21,514 11,540
Canada 31,360 784 - -
------- ------- ------- -------
Total 371,601 101,516 21,514 11,540
======= ======= ======= =======
3
Price and Production Data. The 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, experienced by the Company, for the periods indicated were as
follows:
Year Ended December 31,
1996 1995 1994
-------- -------- --------
Average sales price per barrel
of oil produced:
USA $ 20.40 $ 16.65 $ 15.13
Canada $ - $ - $ -
Average sales price per Mcf of
natural gas produced:
USA $ 2.21 $ 1.61 $ 1.86
Canada $ 1.18 $ 0.98 $ 1.27
Oil production (Mbbls):
USA 579 577 406
Canada - - -
-------- -------- --------
Total 579 577 406
======== ======== ========
Natural gas production (MMcf):
USA 12,974 12,005 9,606
Canada 51 54 53
-------- -------- --------
Total 13,025 12,059 9,659
======== ======== ========
Average production expense per
equivalent Mcf:
USA $ .68 $ 0.64 $ 0.58
Canada $ .27 $ 0.30 $ 0.37
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,
1996 1995 1994
------- ------- -------
Oil (Mbbls):
USA 5,204 5,428 4,308
Canada - - -
------- ------- -------
Total 5,204 5,428 4,308
======= ======= =======
Natural gas (MMcf):
USA 128,408 107,950 92,566
Canada 753 778 794
------- ------- -------
Total 129,161 108,728 93,360
======= ======= =======
4
Further information relating to oil and natural gas operations is
presented in Notes 1,4,11 and 13 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,
engages 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, 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 up to 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.
In September 1996, the Company purchased one 1,500 horsepower rig and
one 2,500 horsepower rig and 36,000 feet of drill pipe for $1.7 million
bringing the Companies operational rig fleet at December 31, 1996 to 24
with rated depth capacities ranging from 5,000 to 25,000 feet. A majority
of the Company's rigs are located in the Anadarko and Arkoma Basins of
Oklahoma and Texas. In July 1994, the Company began moving rigs to the
South Texas basin region thereby expanding the Company's market area for
its contract drilling services and in December 1995, the contract drilling
operations opened a regional office in Houston, Texas. At December 31,
1996, the Company had 3 of its larger horsepower rigs 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 rig equipment.
However, certain grades of drill pipe are in high demand due to increases
in the Company's rig utilization so the Company has increased its drill
pipe acquisitions to maintain current utilization levels. There is no
assurance that sufficient supplies of such equipment will be readily
available in the future and, given the general decline experienced in the
land contract drilling industry over the past decade, the Company's ability
to utilize its full complement of drilling rigs, should economic conditions
improve rapidly, will be restricted due to a lack of availability of
additional equipment, drill pipe and qualified labor not only within the
Company but in the industry as a whole.
5
The following table sets forth, for each of the periods indicated,
certain data concerning the Company's contract drilling operations:
Year Ended December 31,
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Number of operational rigs owned
at end of period 24 22 25 25 26
Average number of rigs utilized(1) 14.7 10.9 9.5 8.0 5.5
Number of wells drilled 130 111 95 84 56
Total footage drilled (feet in 1000's) 1,468 1,196 1,027 788 527
- -------------------
(1) 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 March 10, 1997, 20 of the Company's 24 drilling rigs were oper-
ating under contract.
The following table sets forth, as of March 10, 1997, the type and
approximate depth capability of each of the Company's drilling rigs:
Approximate
Depth
Capability
Type (feet)
---- ----------
U-15 Unit Rig 11,000
U-15 Unit Rig 11,000
U-15 Unit Rig 11,000
U-15 Unit Rig 11,000
Gardner Denver 800 15,000
Gardner Denver 700 15,000
BDW 800-M1 15,000
Gardner Denver 700 15,000
Mid-Continent 914-C 20,000
U-15 Unit Rig 11,000
Brewster N-75 15,000
Gardner Denver 500 12,000
Gardner Denver 700 15,000
Gardner Denver 700 15,000
Gardner Denver 700 15,000
Brewster N-75A 15,000
BDW 1350-M 20,000
SU-15 North Texas Machine 12,000
SU-15 North Texas Machine 12,000
National 110-UE 20,000
Continental Emsco C-1-E 20,000
Gardner Denver 1500-E 25,000
Mid-Continent 914-EC 20,000
Mid-Continent 1220-EB 25,000
6
For the past several years, the Company's contract drilling services
have encountered significant competition due to depressed levels of
activity in contract drilling. In the last 6 months of 1996, the Company's
drilling operations showed significant improvements in rig utilization, but
it is anticipated 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
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. 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. For 1996, turnkey revenue represented approximately 8 percent of
the Company's contract drilling revenues. To date, the Company has not
experienced significant losses in performing turnkey contracts.
7
Customers. During the fiscal year ended December 31, 1996, 10
contract drilling customers accounted for approximately 22 percent of the
Company's total revenues and approximately 3 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 and 11 of Notes to Consolidated Financial Statements
set forth in Item 8 hereof.
NATURAL GAS MARKETING
Prior to April 1995, the Company marketed natural gas from wells
located primarily in Oklahoma and Texas and to a lesser extent in Arkansas,
Kansas, Louisiana, Mississippi and New Mexico. Effective April 1, 1995 the
Company completed a business combination between the Company's natural gas
marketing operations and a third party also involved in natural gas
marketing activities forming a new company called GED Gas Services, L.L.C.
("GED"). The Company owns a 34 percent interest in GED. Effective
November 1, 1995, GED sold its natural gas marketing operations to a third
party. This sale removed the Company from the third party natural gas
marketing business. The creation of GED and the subsequent sale of the
marketing operations did not adversely affect the Company's drilling and
oil and natural gas exploration operations or the profitability of the
Company as a whole. The disposition of the Company's natural gas marketing
segment was accounted for as a discontinued operation and accordingly, the
1995 and prior year financial information were restated to reflect this
treatment.
MARKETING OF OIL AND NATURAL GAS PRODUCTION
The Company's revenue and profitability are substantially dependent
upon prevailing prices for natural gas and crude oil. These prices vary
based on factors beyond the control of the Company, including the extent of
domestic production and importation of crude oil and natural gas, the
proximity and capacity of oil and natural gas pipelines, 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.
8
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 at the wellhead to intrastate and interstate
pipelines as well as to independent marketing firms under contracts with
original terms ranging from one month to 20 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
slightly 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 while inventories of certain components
such as 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.
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 8 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 activi-
ties 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 subsidiaries.
9
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.
Depending upon a number of factors, including the performance of the
drilling programs and general economic and capital market conditions, the
Company may form additional drilling and/or producing property acquisition
programs in the future.
EMPLOYEES
As of March 10, 1997, the Company had approximately 402 employees in
its land contract drilling operations, 59 employees in its oil and natural
gas operations and 25 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 worker's compensation insurance for losses
exceeding $50,000. In Oklahoma, starting in August 1991, the Company
elected to become self insured. In consideration therewith, the Company
purchased an excess liability reinsurance policy. The Company believes
that to the extent reasonably practicable such insurance coverages are ade-
quate. The Company's insurance policies do not, however, provide protec-
tion against revenue losses incurred by reason of business interruptions
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
10
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
is 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 marketed. 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 over the long-term.
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
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.
11
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
available not only simultaneously but also without prior nomination, with
the only limitation being the customer's daily contract demand) if the
12
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 judicial review of Order 636 and 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.
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 limiting 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
14
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.
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 and well performance, and the Company's
anticipated bank debt.
Statement 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.
In order to provide a more thorough understanding of the possible
effects of some of these influences on any projections made by the Company,
the following discussion outlines certain factors that in the future could
cause the Company's consolidated results for 1997 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, 1996, 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 $1,180,000 and $540,000, respectively. During
1996, 97% of the natural gas volume of the Company and substantially all
the 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 by 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 more 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 made 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.
Bank Borrowing
The amount of the Company's bank debt as well as its projected
borrowing 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 for its oil and natural gas production. 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 bank 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 bank
borrowing.
17
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, 1996.
18
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
- --------------------------------------------------------------------------
Matters
- -------
As of February 18, 1997, the Company had 2,862 holders of record of
its common stock. 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, if any, 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. 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:
1996 1995
QUARTER High Low High Low
------- ------- ------- ------- -------
First $ 6 $ 4 $ 3 1/4 $ 2 1/2
Second $ 7 3/8 $ 5 3/4 $ 3 7/8 $ 2 7/8
Third $ 7 1/8 $ 5 1/2 $ 4 1/4 $ 3 1/4
Fourth $10 1/8 $ 5 7/8 $ 4 3/4 $ 3 1/2
19
Item 6. Selected Financial Data
- --------------------------------
Year Ended December 31,
1996 1995 1994 1993 1992
------- ------- ------- ------- -------
(In thousands except per share amounts)
Revenues $72,070 $53,074 $43,895 $38,682 $33,744
======= ======= ======= ======= =======
Income From Continuing
Operations $ 8,333 $ 3,751(1) $ 4,628(2) $ 3,937 $ 1,631(3)
======= ======= ======= ======= =======
Net Income $ 8,333 $ 3,999(1) $ 4,794(2) $ 3,871 $ 1,087(3)
======= ======= ======= ======= =======
Earnings Per Common Share:
Continuing Operations:
Primary $.37 $.18(1) $.22(2) $.19 $.08(3)
==== ==== ==== ==== ====
Fully Diluted $.36 $.18(1) $.22(2) $.19 $.08(3)
==== ==== ==== ==== ====
Net Income:
Primary $.37 $.19(1) $.23(2) $.19 $.05(3)
==== ==== ==== ==== ====
Fully Diluted $.36 $.19(1) $.23(2) $.19 $.05(3)
==== ==== ==== ==== ====
Total Assets $137,993 $110,922 $103,933 $ 88,816 $ 83,960
======== ======== ======== ======== ========
Long-Term Debt $ 40,600 $ 41,100 $ 37,824 $ 25,919 $ 22,298
======== ======== ======== ======== ========
Long-Term Portion
of Natural Gas
Purchaser Prepayments $ 2,276 $ 2,109 $ 2,149 $ 4,417 $ 5,924
======== ======== ======== ======== ========
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.
(3) Includes a $1.5 million provision for litigation
20
See Management's Discussion of Financial Condition and Results of
Operations for a review of 1996, 1995 and 1994 activity.
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
commitment of $75 million, consisting of a revolving credit facility
through August 1, 1999 and a term loan thereafter, maturing on August 1,
2003. Borrowings under the revolving credit facility are limited to a
borrowing base which is subject to a semi-annual redetermination. The
latest borrowing base determination indicated $52 million of the commitment
is available to the Company. The Loan Agreement contains certain covenants
which require the Company to maintain consolidated net worth of at least
$48 million, a modified 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 to 1 and a ratio of total liabilities, as
defined in the Loan Agreement, to consolidated tangible net worth not
greater than 1.25 to 1. In addition, working capital provided by
operations, as defined in the Loan Agreement, cannot be less than $12
million in any year. At December 31, 1996, borrowings under the Loan
Agreement totaled $40.6 million. At February 21, 1997, borrowings under the
Loan Agreement totaled $36.0 million with $13.1 million available for
future borrowings. The interest rate on the bank debt was 7.2 and 7.0
percent at December 31, 1996 and February 21, 1997, respectively. At the
Company's election, any portion of the debt outstanding may be fixed at the
London Interbank Offered Rate ("Libor Rate") for 30, 60, 90 or 180 days
with the remainder of the outstanding debt subject to the Chase Manhattan
Bank, N. A. 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, 1996
and February 21, 1997, $35.0 million of borrowings were subject to the
Libor Rate. A commitment fee of 1/2 of 1 percent is charged for any unused
portion of the borrowing base.
Shareholders' equity at December 31, 1996 was $78.2 million, making
the Company's ratio of long-term debt-to-equity .52 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 Company's Loan Agreement. Net cash provided by
continuing operating activities in 1996 was $20.7 million as compared to
$11.2 million in 1995.
The Company's capital expenditures during 1996 were $36.5 million. The
majority of the capital expenditures, $25.6 million, were made in the
Company's oil and natural gas operations with $20.2 million and $2.3
million used for exploration and development drilling and producing
21
property acquisitions, respectively. Capital expenditures made by the
Company's contract drilling operations were $9.9 million in 1996. The
drilling expenditures principally consisted of the purchase and
refurbishment of two drilling rigs acquired in September 1996, the
refurbishment of two drilling rigs already owned by the Company and the
acquisition of over 110,000 feet of drill pipe. 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 $6.0
million projected for 1997.
During 1997, the Company's oil and natural gas subsidiary plans to
continue its focus on its developmental drilling as increased spot market
natural gas prices in late 1996 and into early 1997 lessened the
availability of economical producing property acquisitions. The majority
of the Company's capital expenditures are discretionary and primary
directed toward increasing reserves and future growth. Current operations
are not dependent of 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 $31 million on its exploration capital
expenditure program in 1997.
At December 31, 1995, the Company had 2.873 million warrants
outstanding. The warrants entitled the holders to purchase one share of
common stock at a price of $4.375 per share. Prior to the warrants
expiration on August 30, 1996, 2.86 million warrants were exercised
providing $12.5 million in additional capital to the Company.
The Company continued to receive 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"). As a result of the Settlement Agreement, the December 31,
1996 prepayment balance of $2.3 million paid by the purchaser for natural
gas not taken (the "Prepayment Balance") is subject to recoupment in
volumes of natural gas through a period ending on the earlier of recoupment
or December 31, 1997 (the "Recoupment Period"). During 1997, the purchaser
is obligated to make monthly payments on behalf of the Committed Interest
based on their share of the natural gas deliverability of the wells subject
to the Settlement Agreement, up to a maximum of $156,000 or a minimum of
$80,000 per month. The monthly payments will end at the end of 1997.
If natural gas is taken during a month, the value of such natural gas is
credited toward the monthly amount the purchaser is required to pay. In
the event the purchaser takes volumes of natural gas valued in excess of
its monthly payment obligations, the value taken in excess is applied to
reduce any then outstanding Prepayment Balance. The Company currently
believes that sufficient natural gas deliverability is available to enable
the Committed Interest to receive substantially all of the maximum monthly
payments during 1997. At the end of the Recoupment Period, the Settlement
22
Agreement and the natural gas purchase contracts which are subject to the
Settlement Agreement will terminate. If the Prepayment Balance is not
fully recouped in natural gas by December 31, 1997, then the unrecouped
portion is subject to cash repayment, limited to a maximum of $3 million,
payable in equal annual payments over a five year period with the first
payment due June 1, 1998. The Company anticipates the maximum balance of
$3 million will be unrecouped at December 31, 1997. The price per Mcf under
the Settlement Agreement is substantially higher than current spot market
prices. The impact of the higher price received under the Settlement
Agreement increased pre-tax income approximately $0.6, $1.6 and $1.8
million in 1996, 1995 and 1994, respectively.
Average oil prices received by the Company in 1996 ranged from $16.90
in February to $24.00 in December. The Company's average price received
for oil during 1996 was $20.40. Natural gas prices received by the Company
in 1996 ranged from an average of $1.71 in September to an average of $3.60
in December. Average natural gas prices received by the Company were
volatile throughout 1996 and averaged $2.20 for the year as a whole.
Average oil prices received early in the first quarter of 1997 were 5
percent lower than average prices received by the Company at December 31,
1996 while average natural gas spot prices dropped 10 percent from the
December 31, 1996 price. 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.
Any drop in spot market natural gas prices would have a significant adverse
effect on the value of the Company's reserves and further large drops in
prices could cause the Company to reduce the carrying value of its oil and
natural gas properties. Likewise, declines in natural gas or oil prices
could 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 base determination under the Company's
Loan Agreement since this determination is calculated on the value of the
Company's oil and natural gas reserves.
The Company's ability to utilize its full complement of drilling rigs,
is being restricted due to the lack of qualified labor and certain
supporting 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. The Company's
management expects that these factors will continue to influence the
Company's rig utilization during 1997.
23
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, 120,100
shares have been repurchased at prices ranging from $2.5 to $8.275 per
share. During the first quarters of 1996 and 1995, 44,686 and 46,659,
respectively, of the purchased shares were reissued as the Company's
matching contribution to its 401(k) Employee Thrift Plan. At December 31,
1996, 28,755 treasury shares were held by the Company.
On April 1, 1995, the Company completed a business combination between
the Company's natural gas marketing operations and a third party also
involved in natural gas marketing activities forming a new company called
GED Gas Services, L.L.C. ("GED"). The Company owns a 34 percent interest in
GED. Effective November 1, 1995 GED sold its natural gas marketing
operations to a third party. This sale removed the Company from the third
party natural gas marketing business. The creation of GED and its
subsequent sale of its marketing operations did not adversely affect the
Company's drilling and oil and natural gas exploration operations or the
profitability of the Company as a whole. The discontinuation of the
Company's natural gas marketing segment was accounted for as a discontinued
operation and accordingly, the 1995 and prior year financial information
reflect this treatment.
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 the third
and fourth quarters of 1996 as drilling rig day rates and drilling rig
utilization has increased, the impact of inflation has intensified as
shortages in related equipment, third party services and qualified labor
increased. 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 continues to increase 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.
24
Results of Operations
1996 versus 1995
- ----------------
Net income for 1996 was $8,333,000, compared with $3,999,000 in 1995.
Increased natural gas production from new wells drilled along with higher
oil and natural gas prices, contract drilling day rates and rig utilization
all combined to produce the large increase in 1996 net income. Net income
in 1995 included $635,000 gain from the sale of 44 natural gas compressors
and certain related support equipment which were sold for $2.7 million in
the first quarter and by the receipt of $850,000 in the third quarter from
a settlement reached by two of the Company's subsidiaries in certain
litigation brought against the Federal Deposit Insurance Corporation and
other parties. In the fourth quarter of 1995, the Company also recognized a
$360,000 net gain from the Company's interest in the sale of GED's gas
marketing operations and a $530,000 income tax benefit. Net income in the
fourth quarter of 1995 was reduced by a $254,000 write down of certain rig
components as the Company elected to take 3 of its drilling rigs out of
service.
Oil and natural gas revenues increased 38 percent in 1996 due to a 8
percent increase in natural gas production combined with a 23 and 37
percent increase in average oil and natural gas prices received by the
Company, respectively. Oil production remained virtually unchanged from
1995 levels. Average natural gas spot market prices received by the Company
increased by 46 percent while volumes produced from certain wells included
under the Settlement Agreement, which contains provisions for prices which
are higher than current spot market prices, dropped by 46 percent. The
impact of higher prices received under the Settlement Agreement increased pre-
tax income by approximately $0.6 and $1.6 million in 1996 and 1995,
respectively.
In 1996, revenues from contract drilling operations increased by 43
percent as average rig utilization increased from 10.9 rigs operating in
1995 to 14.7 rigs operating in 1996, and daywork revenues per rig per day
increased 12 percent. Total daywork revenues represented 68 percent of
total drilling revenues in 1996 and 57 percent in 1995. 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 69 percent in 1996 compared to 62 percent
in 1995. Increased operating margins resulted primarily from the increase
in natural gas production and the increases in both oil and natural gas
prices received by the Company between the two years. Total operating costs
increased 12 percent primarily due to the additional costs associated with
oil and natural gas production from new wells drilled in 1996.
Operating margins for contract drilling increased from 11 percent in
1995 to 16 percent in 1996. Margins in 1996 improved due to increases in
daily rig rates and utilization. Margins in 1995 were limited by initial
start up costs incurred in the first quarter of 1995 to establish rigs in
25
the South Texas Basin and by unusually wet weather conditions during the
second quarter of 1995 which delayed rig moves and depressed rig
utilization. Total operating costs for contract drilling were up 34
percent in 1996 versus 1995 due to increased drilling rig utilization.
Contract drilling depreciation increased 13 percent in response to
increased rig utilization. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 6 percent as the
Company increased its equivalent barrels of production by 6 percent. The
Company's average DD&A rate per equivalent barrel declined from $3.93 in
1995 to $3.90 in 1996.
General and administrative expenses increased 6 percent as certain
employee costs increased between the comparative years. Interest expense
decreased 2 percent as the average interest rate on the Company's
outstanding bank debt decreased from 8.52 percent in 1995 to 7.69 percent
in 1996. The decrease in average interest rate was partially offset by an
8 percent increase in bank debt outstanding in 1996 primarily due to the
financing of new wells drilled and the additional rigs and drill pipe
purchased during 1996.
The Company's effective income tax rate in recent years has been
significantly impacted by its net operating loss carryforwards. As of
December 31, 1995, the Company's net operating loss and statutory depletion
carryforwards has been fully recognized for financial reporting purposes;
therefore, the Company's effective income tax rate increased in 1996 to
approximately the statutory rate.
1995 versus 1994
- ----------------
Net income for 1995 was $3,999,000, compared with $4,794,000 in 1994.
While the Company continued to increase natural gas production through
producing property acquisitions and developmental drilling, lower 1995
natural gas prices limited corresponding increases in net income. Net
income in the fourth quarter of 1995 was also further reduced by a $254,000
write down of certain rig components as the Company elected to take 3 of
its drilling rigs out of service since economic conditions did not warrant
the capital investment necessary to keep them in service. The impact of
lower natural gas prices on net income was partially offset by a $635,000
gain from the sale of 44 natural gas compressors and certain related
support equipment which were sold for $2.7 million in the first quarter and
by the receipt of $850,000 in the third quarter from a settlement reached
by two of the Company's subsidiaries in certain litigation brought against
the Federal Deposit Insurance Corporation and other parties. In the fourth
quarter, the Company also recognized a $360,000 net gain from the Company's
interest in the sale of GED's gas marketing operations and a $530,000 net
income tax benefit. Total revenues from continuing operations increased to
$53,074,000 in 1995 as compared to $43,895,000 in 1994. The Company's 1994
net income included a net gain of $742,000 recognized in conjunction with
the sale of one of the Company's natural gas gathering systems.
26
Oil and natural gas revenues increased 20 percent due to a 25 percent
increase in natural gas production and a 42 percent increase in oil
production between 1995 and 1994. Average oil prices received by the
Company increased 10 percent while average natural gas prices received by
the Company decreased 13 percent. The average natural gas price declined
due to a 11 percent reduction in average spot market prices received by the
Company coupled with a 18 percent reduction in volumes produced from
certain wells included under the Settlement Agreement which contains
provisions for prices which were higher than spot market prices. The
impact of higher prices received under the Settlement Agreement increased pre-
tax income by approximately $1.6 and $1.8 million in 1995 and 1994,
respectively.
In 1995, revenues from contract drilling operations increased by 19
percent as average rig utilization increased from 9.5 rigs operating in
1994 to 10.9 rigs operating in 1995. Daywork revenues represented 57
percent of total drilling revenues in 1995 and 58 percent in 1994. 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 62 percent in 1995 compared to 66 percent
in 1994. The reduction was primarily due to the decrease in prices
received for the Company's natural gas production which offset increases in
production between the two years. Margins were also reduced by the
shutting in of production on certain natural gas properties in the months
of February and March due to low spot market natural gas prices. Total
operating costs increased 36 percent due to the additional costs associated
with oil and natural gas production from new wells acquired and drilled in
1995 and 1994.
Operating margins for contract drilling decreased from 12 percent in
1994 to 11 percent in 1995. Margins in 1995 were limited by initial start
up costs incurred in the first quarter of 1995 to establish rigs in the
South Texas Basin and by unusually wet weather conditions during the second
quarter of 1995 which delayed rig moves and depressed rig utilization.
Total operating costs for contract drilling were up 21 percent in 1995
versus 1994 due to increased rig utilization and start up costs.
Contract drilling depreciation increased 28 percent in response to
increased rig utilization. Depreciation, depletion and amortization
("DD&A") of oil and natural gas properties increased 23 percent as the
Company increased its equivalent barrels of production by 28 percent. The
Company's average DD&A rate per equivalent barrel declined from $4.08 in
1994 to $3.93 in 1995.
27
General and administrative expense increased 9 percent as certain
employee costs, contract services and rental costs increased between the
comparative years due to the continued growth of the Company's operations.
Interest expense increased 96 percent as the average interest rate on the
Company's outstanding bank debt increased from 7.15 percent in 1994 to 8.52
percent in 1995. Average bank debt outstanding in 1995 was $20.3 million
higher than average bank debt outstanding in 1994 primarily due to the
financing of producing property acquisition and developmental drilling as
previously discussed.
The Company's effective income tax rate in 1995 and 1994 was
significantly impacted by its net operating loss carryforwards. As of
December 31, 1995, the Company's net operating loss and statutory depletion
carryforwards had been fully recognized for financial reporting purposes,
resulting in a net deferred tax asset of $530,000 at December 31, 1995.
28
Item 8. Financial Statements and Supplementary Data
- -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
ASSETS 1996 1995
---------- ----------
(In thousands)
Current Assets:
Cash and cash equivalents $ 547 $ 534
Accounts receivable (less allowance for
doubtful accounts of $104 and $116) 15,842 10,398
Materials and supplies 2,302 2,048
Prepaid expenses and other 1,464 1,046
--------- ---------
Total current assets 20,155 14,026
--------- ---------
Property and Equipment:
Drilling equipment 84,409 75,751
Oil and natural gas properties, on the full
cost method 200,610 175,225
Transportation equipment 2,413 3,695
Other 6,485 6,100
--------- ---------
293,917 260,771
Less accumulated depreciation, depletion,
amortization and impairment 176,211 164,752
--------- ---------
Net property and equipment 117,706 96,019
--------- ---------
Other Assets 132 877
--------- ---------
Total Assets $137,993 $110,922
========= =========
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 1996 1995
---------- ----------
(In thousands)
Current Liabilities:
Current portion of long-term debt $ - $ 20
Accounts payable 6,893 6,701
Accrued liabilities 4,516 3,976
Contract advances 1,300 410
---------- ----------
Total current liabilities 12,709 11,107
---------- ----------
Natural Gas Purchaser Prepayments (Note 4) 2,276 2,109
---------- ----------
Long-Term Debt 40,600 41,100
---------- ----------
Deferred Income Taxes 4,198 -
---------- ----------
Commitments and Contingencies (Note 10)
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, 24,157,312 and
20,976,090 shares issued, respectively 4,831 4,195
Capital in excess of par value 62,735 50,181
Retained earnings (deficit) 10,751 2,418
Treasury stock, at cost (28,755 and
68,441 shares, respectively) (107) (188)
---------- ----------
Total shareholders' equity 78,210 56,606
---------- ----------
Total Liabilities and Shareholders' Equity $ 137,993 $ 110,922
========== ==========
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,
1996 1995 1994
-------- -------- --------
Revenues: (In thousands except per share amounts)
Contract drilling $28,819 $20,211 $16,952
Oil and natural gas 43,013 31,187 26,001
Other 238 1,676 942
-------- -------- --------
Total revenues 72,070 53,074 43,895
-------- -------- --------
Expenses:
Contract drilling:
Operating costs 24,259 18,041 14,909
Depreciation and impairment 2,944 2,596 2,030
Oil and natural gas:
Operating costs 13,409 12,003 8,799
Depreciation, depletion
and amortization 10,807 10,223 8,281
General and administrative 4,122 3,893 3,574
Interest 3,162 3,235 1,654
-------- -------- --------
Total expenses 58,703 49,991 39,247
-------- -------- --------
Income From Continuing Operations
Before Income Taxes 13,367 3,083 4,648
-------- -------- --------
Income Tax Expense (Benefit):
Current 4 14 20
Deferred 5,030 (682) -
-------- -------- --------
Total income taxes 5,034 (668) 20
-------- -------- --------
Income From Continuing Operations 8,333 3,751 4,628
-------- -------- --------
Discontinued Operations:
Income (loss) from operations of
discontinued operations (net of
income tax benefit of $69 in 1995) - (112) 166
Gain from sale of discontinued
operations (net of income taxes
of $221 in 1995) - 360 -
-------- -------- --------
Income from
discontinued operations - 248 166
-------- -------- --------
Net Income $ 8,333 $ 3,999 $ 4,794
======== ======== ========
31
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS - CONTINUED
Year Ended December 31,
1996 1995 1994
-------- -------- --------
(In thousands except per share amounts)
Earnings Per Common Share:
Continuing operations:
Primary $ .37 $ .18 $ .22
======== ======== ========
Fully diluted $ .36 $ .18 $ .22
======== ======== ========
Net income:
Primary $ .37 $ .19 $ .23
======== ======== ========
Fully diluted $ .36 $ .19 $ .23
======== ======== ========
Weighted Average Shares Outstanding:
Primary 22,708 21,210 20,900
======== ======== ========
Fully diluted 22,867 21,210 20,900
======== ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
32
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Year Ended December 31, 1994, 1995 and 1996
Capital
In Excess Retained
Common Of Par Earnings Treasury
Stock Value (Deficit) Stock Total
-------- -------- --------- -------- --------
(In thousands)
Balances,
January 1, 1994 $ 4,172 $49,977 $ (6,375) $ - $47,774
Net income - - 4,794 - 4,794
Activity in employee
compensation plans
(48,685 shares) 10 109 - - 119
Purchase of treasury
stock (25,100
shares) - - - (80) (80)
-------- -------- --------- -------- --------
Balances,
December 31, 1994 4,182 50,086 (1,581) (80) 52,607
Net income - - 3,999 - 3,999
Activity in employee
compensation plans
(112,559 shares) 13 95 - 122 230
Purchase of treasury
stock (90,000
shares) - - - (230) (230)
-------- -------- --------- -------- --------
Balances,
December 31, 1995 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
======== ======== ========= ======== ========
The accompanying notes are an integral part of the
consolidated financial statements
33
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1996 1995 1994
-------- -------- --------
(In thousands)
Cash Flows From Operating Activities:
Income from continuing operations $ 8,333 $ 3,751 $ 4,628
Adjustments to reconcile income
from continuing operations
to net cash provided (used) by
continuing operating activities:
Depreciation, depletion,
amortization and impairment 14,079 13,120 10,760
Gain on disposition of assets (185) (723) (813)
Employee stock compensation plans 214 231 119
Bad debt expense - 55 -
Deferred tax benefit 5,030 (682) -
Changes in operating assets and
liabilities increasing
(decreasing) cash:
Accounts receivable (5,444) (2,280) 94
Materials and supplies (254) (550) (74)
Prepaid expenses and other (418) (94) (396)
Accounts payable (2,288) (1,151) (871)
Accrued liabilities 540 925 824
Contract advances 890 252 148
Natural gas purchaser prepayments 167 (1,620) (1,858)
-------- -------- --------
Net cash provided
by continuing operating
activities 20,664 11,234 12,561
-------- -------- --------
Net cash flows from
discontinued operations
including changes in
working capital - (259) 532
-------- -------- --------
Net cash provided by
operating activities 20,664 10,975 13,093
-------- -------- --------
The accompanying notes are an integral part of the
consolidated financial statements
34
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31,
1996 1995 1994
--------- --------- ---------
(In thousands)
Cash Flows From Investing Activities:
Capital expenditures (including
producing property acquisitions $(34,111) $(20,634) $(28,227)
Proceeds from disposition of assets 1,009 4,613 2,038
Decrease in short-term investments - - 41
(Acquisition) disposition
of other assets 215 - 141
Proceeds of sale of
discontinued operations - 369 -
--------- --------- ---------
Net cash used in
investing activities (32,887) (15,652) (26,007)
--------- --------- ---------
Cash Flows From Financing Activities:
Borrowings under line of credit 31,500 39,700 63,700
Payments under line of credit (32,000) (35,900) (51,300)
Payments on notes payable and
other long-term debt (20) (1,000) (480)
Proceeds from sale of common stock 12,798 - -
Acquisition of treasury stock (42) (230) (80)
--------- --------- ---------
Net cash provided by
financing activities 12,236 2,570 11,840
--------- --------- ---------
Net Increase (Decrease) in Cash
and Cash Equivalents 13 (2,107) (1,074)
Cash and Cash Equivalents,
Beginning of Year 534 2,641 3,715
--------- --------- ---------
Cash and Cash Equivalents, End of Year $ 547 $ 534 $ 2,641
========= ========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the year for:
Interest $ 3,189 $ 3,214 $ 1,548
Income taxes $ 63 $ - $ 2
The accompanying notes are an integral part of the
consolidated financial statements
35
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 and Mississippi. The Company has an interest in 2,311 wells and
serves as operator of 502 of those wells. Land contract drilling of oil
and natural gas wells is performed for a wide range of customers using the
24 drilling rigs owned and operated by the Company.
Drilling Contracts
The Company accounts for "footage" and "turnkey" drilling contracts,
in which the Company assumes the risks associated with drilling the well,
under the completed-contract method and for "daywork" drilling contracts
under the percentage-of-completion method. 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.
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.
36
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. At December 31, 1995, the Company elected
to take three rigs out of service, and at that time, the three drilling
rigs and certain other components of the rig fleet were written down by
$254,000 to their estimated market value. 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 comput-
ed 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 determined to be impaired based on estimated future net cash flows
are reduced to estimated fair value. 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 dispo-
sitions 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.
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 produc-
tive and non-productive costs incurred in connection with the acquisition,
exploration and development of oil and natural gas reserves are capitalized
and amortized on a composite units-of-production method based on proved oil
and natural gas reserves. The Company's determination of its oil and
natural gas reserves are reviewed annually by independent petroleum
engineers. The average composite rates used for depreciation, depletion and
amortization ("DD&A") were $3.90, $3.93 and $4.08 per equivalent barrel in
1996, 1995 and 1994, 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 13, 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.
37
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 part-
nership, of which the Company is a general partner, has an interest.
Accordingly, in 1994 the Company recorded $14,000 of contract drilling
profits 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 and 1995.
Limited Partnerships
The Company, through its wholly owned subsidiary, Unit Petroleum
Company, is a general partner in twelve oil and natural gas limited part-
nerships sold privately and publicly. Certain of the Company's officers
and directors own interests in some of these partnerships. Their interests
were acquired generally on the same basis as other outside investors.
The Company shares in partnership revenues and costs in accordance
with formulas prescribed in each limited partnership agreement. The
partnerships also reimburse the Company for certain administrative costs
incurred on behalf of the partnerships.
Income Taxes
Measurement of current and deferred income tax liabilities and assets
is based on provisions of enacted tax law; the effects of future changes in
tax laws or rates are not included in the measurement. Valuation
allowances are established where necessary to reduce deferred tax assets to
the amount expected to be realized. Income tax expense is the tax payable
for the year and the change during that year in deferred tax assets and
liabilities.
Natural Gas Balancing
The Company uses the sales method for recording natural gas sales.
This method allows for recognition of revenue which may be more or less
than the Company's share of pro-rata production from certain wells. Based
upon the Company's 1996 average spot market natural gas price of $2.15 per
Mcf, the Company estimates its balancing position to be approximately
$6.4 million on under-produced properties and approximately $3.2 million on
over-produced properties.
The Company's policy is to expense its pro-rata share of lease oper-
ating costs from all wells as incurred. Such expenses relating to the
Company's balancing position on wells on which the Company has imbalances
are not material.
38
Stock Based Compensation
The Company applies APB Opinion 25 in accounting for its stock option
plans. Under this standard, no compensation expense is recognized for
grants of options which include an exercise price equal to or greater than
the market price of the stock on the date of grant. Accordingly, based on
the Company's grants in 1996, 1995 and 1994 no compensation expense has
been recognized. As allowed by Financial Accounting Standard No. 123
"Accounting for Stock-Based Compensation," the Company has disclosed the
pro forma effects of recording compensation for such option grants based on
fair value in Note 7 to the financial statements.
Self Insurance
The Company utilizes self insurance programs for employee group health
and worker's compensation. Self insurance cost are accrued based upon the
aggregate of estimated liabilities for reported claims and claims incurred
but not yet reported.
Financial Instruments and Concentrations of Credit Risk
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of trade receivables with a
variety of national and international oil and natural gas companies. The
Company does not generally require collateral related to receivables. Such
credit risk is considered by management to be limited due to the large
number of customers comprising the Company's customer base. In addition,
at December 31, 1996 and 1995, the Company had a concentration of cash of
$2.6 million and $1.2 million, respectively, with one bank.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
39
NOTE 2 - DISCONTINUED OPERATIONS
- --------------------------------
On April 1, 1995, the Company's natural gas marketing operations were
combined with a third party also involved in natural gas marketing
activities forming GED Gas Services L.L.C. ("GED"). The combination was
made to attain the increased volumes deemed necessary to profitably market
third party natural gas. The Company owns a 34 percent interest in GED.
On November 1, 1995 GED sold its natural gas marketing operation. This
sale removed the Company from the third party natural gas marketing
business. The gain on the sale was $360,000 net of income tax of $221,000.
The Company's former natural gas marketing activity has been presented
as a discontinued operation. Summary results of operations data of the
discontinued operations were as follows:
For the Year Ended December 31,
1996 1995 1994
-------- -------- --------
(In Thousands)
Results of Operations:
Revenues attributable to
discontinued operations $ - $13,548 $43,725
Expenses attributable to
discontinued operations - 13,729 43,559
-------- -------- --------
Income (loss) attributable
to discontinued operations
before income taxes - (181) 166
Income tax benefit - 69 -
-------- -------- --------
Income (loss) attributable
to discontinued
operations $ - $ (112) $ 166
======== ======== ========
NOTE 3 - WARRANTS
- -----------------
In 1987, the Company issued 2.873 million Units, consisting of three
shares of the Company's common stock and one warrant, at a price of $10.375
per Unit. Each warrant entitled the holder to purchase one share of the
Company's common stock at a price of $4.375. Prior to the warrants
expiration on August 30, 1996, 2.86 million warrants were exercised
providing $12.5 million in additional capital to the Company.
40
NOTE 4 - NATURAL GAS PURCHASER PREPAYMENTS
- -------------------------------------------
In March 1988, the Company entered into a settlement agreement with a
natural gas purchaser. During early 1991, the Company and the natural gas
purchaser superseded the original agreement with a new settlement agreement
effective retroactively to January 1, 1991. Under these settlement
agreements ("Settlement Agreement"), the Company has a prepayment balance
of $2.3 million at December 31, 1996 representing proceeds received from
the purchaser as prepayment for natural gas. This amount is net of natural
gas recouped and net of certain amounts disbursed to other owners (such
owners, collectively with the Company are referred to as the "Committed
Interest") for their proportionate share of the prepayments. The December
31, 1996 prepayment balance is subject to recoupment in volumes of natural
gas for a period ending the earlier of recoupment or December 31, 1997 (the
"Recoupment Period"). During 1997, the purchaser is obligated to make
monthly payments on behalf of the Committed Interest in an amount
calculated as a percentage of the Committed Interest's share of the
deliverability of the wells subject to the Settlement Agreement, up to a
maximum of $156,000 or a minimum of $80,000 per month. At December 31,
1997, the Committed Interest's prepayment balance, if any, that has not
been fully recouped in natural gas is subject to a cash repayment limited
to a maximum of $3 million to be made in equal annual payments over a five
year period with the first payment due June 1, 1998. The prepayment
amounts subject to recoupment from future production by the purchaser are
being recorded as liabilities and are reflected in revenues as recoupment
occurs. The Company anticipates the maximum balance of $3 million will be
unrecouped at December 31, 1997 and accordingly, the prepayment balance at
December 31, 1996 is reported as a long-term liability. At the end of the
Recoupment Period, the terms of the Settlement Agreement and the natural
gas purchase contracts which are subject to the Settlement Agreement will
terminate.
41
NOTE 5 - LONG-TERM DEBT
- ------------------------
Long-term debt consisted of the following as of December 31, 1996 and
1995:
1996 1995
--------- ---------
Revolving credit and term loan, (In thousands)
with interest at December 31,
1996 and 1995 of 7.2 percent
and 8.2 percent, respectively $ 40,600 $ 41,100
Other - 20
--------- ---------
40,600 41,120
Less current portion - 20
--------- ---------
Total long-term debt $ 40,600 $ 41,100
========= =========
At December 31, 1996, the Company's loan agreement ("Loan Agreement")
provided for a total loan commitment of $75 million consisting of a revolv-
ing credit facility through August 1, 1999 and a term loan thereafter,
maturing on August 1, 2003. Borrowings under the Loan Agreement are
limited to a semi-annual borrowing base computation which as of December
31, 1996 is $52 million.
Borrowings under the revolving credit facility bear interest at the
Chase Manhattan Bank, N.A. prime rate ("Prime Rate") or the London
Interbank Offered Rates ("Libor Rate") plus 1.25 to 1.75 percent depending
on the level of debt as a percentage of the total borrowing base.
Subsequent to August 1, 1999, borrowings under the Loan Agreement bear
interest at the Prime Rate plus .25 percent or the Libor rate plus 1.50 to
2.00 percent depending on the level of debt as a percentage of the total
borrowing base.
At the Company's election, any portion of the debt outstanding may be
fixed at the Libor Rate for 30, 60, 90 or 180 days. During any Libor Rate
funding period the Company may not pay in part or in whole the outstanding
principal balance of the note to which such Libor Rate option applies.
Borrowings under the Prime Rate option may be paid anytime in part or in
whole without premium or penalty.
A facility fee of 1/2 of 1 percent is charged for any unused portion
of the borrowing base. Virtually all of the Company's drilling rigs are
collateral for such indebtedness and the balance of the Company's assets
are subject to a negative pledge.
The Loan Agreement includes prohibitions against (i) the payment of
dividends (other than stock dividends) during any fiscal year in excess of
25 percent of the consolidated net income of the Company during the preced-
ing 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
42
long-term debt at the end of such year, (ii) the incurrence by the Company
or any of its subsidiaries of additional debt with certain very limited
exceptions and (iii) the creation or existence of mortgages or liens, other
than those in the ordinary course of business, on any property of the
Company or any of its subsidiaries, except in favor of its banks. The Loan
Agreement also requires that the Company maintain consolidated net worth of
at least $48 million, a modified 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 to 1 and a ratio of total liabil-
ities, as defined in the Loan Agreement, to consolidated tangible net worth
not greater than 1.25 to 1. In addition, working capital provided by
operations, as defined in the Loan Agreement, cannot be less than $12
million in any year.
Estimated annual principal payments under the terms of all long-term
debt from 1997 through 2001 are $0, $0, $3,383,000, $10,150,000 and
$10,150,000. Based on the borrowing rates currently available to the
Company for debt with similar terms and maturities, long-term debt at
December 31, 1996 approximates its fair value.
NOTE 6 - INCOME TAXES
- ---------------------
A reconciliation of the income tax expense, computed by applying the
federal statutory rate to pre-tax income from continuing operations, to the
Company's effective income tax expense is as follows:
1996 1995 1994
-------- -------- --------
(In thousands)
Income tax expense computed by
applying the statutory rate $ 4,545 $ 1,048 $ 1,580
Tax benefit of net operating
loss carryforward - (1,730) (1,595)
State income tax 499 - 6
Other (10) 14 29
-------- -------- --------
Income tax expense (benefit) $ 5,034 $ (668) $ 20
======== ======== ========
43
Deferred tax assets and liabilities are comprised of the following at
December 31, 1996 and 1995:
1996 1995
--------- ---------
Deferred tax assets: (In thousands)
Allowance for losses $ 443 $ 670
Net operating loss carryforwards 17,586 17,058
Statutory depletion carryforward 2,260 2,260
Investment tax credit carryforward 3,530 3,530
--------- ---------
Gross deferred tax assets 23,819 23,518
Valuation allowance (3,530) (3,530)
Deferred tax liability-
Depreciation, depletion and amortization (24,487) (19,458)
--------- ---------
Net deferred tax asset (liability) $ (4,198) $ 530
========= =========
The deferred tax asset valuation allowance reflects that the
investment tax credit carryforwards above may not be utilized before the
expiration dates as itemized below due in part to the effects of
anticipated future exploratory and development drilling costs.
Realization of the deferred tax asset is dependent on generating
sufficient taxable income prior to expiration of loss carryforwards.
Although realization is not assured, management believes it is more likely
than not that the deferred tax asset will be realized. The amount of the
deferred tax asset considered realizable, however, could be reduced in the near-
term if estimates of future taxable income during the carryforward
period are reduced.
At December 31, 1996, the Company has net operating loss carryforwards
for regular tax purposes of approximately $46,279,000 and net operating
loss carryforwards for alternative minimum tax purposes of approximately
$37,636,000 which expire in various amounts from 1999 to 2011. The Company
has investment tax credit carryforwards of approximately $3,530,000 which
expire from 1997 to 2000. In addition, a statutory depletion carryforward
of approximately $5,948,000, which may be carried forward indefinitely, is
available to reduce future taxable income, subject to statutory
limitations.
44
NOTE 7 - BENEFIT AND COMPENSATION PLANS
- ---------------------------------------
In December 1984, the Board of Directors approved the adoption of an
Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common
stock were authorized for issuance under the Plan. On May 3, 1995, the
Company's shareholders amended the Plan to increase by 250,000 shares the
aggregate number of shares of common stock that could be issued under the
Plan. Under the terms of the Plan, bonuses may be granted to employees in
either cash or stock or a combination thereof, and are payable in a lump
sum or in annual installments subject to certain restrictions. No shares
were issued under the Plan in 1996, 1995 or 1994.
At December 31, 1996, the Company also has a Stock Option Plan which
provides for the granting of options for up to 1,500,000 shares of common
stock to officers and employees. The plan permits the issuance of
qualified or nonqualified stock options. Options granted become
exercisable at the rate of 20 percent per year one year after being granted
and expire after ten years from the original grant. The exercise price for
options granted to date was based on the fair market value on the date of
the grant.
Activity pertaining to the Stock Option Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
--------- --------
Outstanding at
January 1, 1994 829,000 $ 2.04
Granted 102,500 3.00
Exercised (16,000) 1.55
--------- --------
Outstanding at
December 31, 1994 915,500 2.16
Granted 26,000 3.22
Exercised (65,900) 1.65
Canceled (10,000) 1.88
--------- --------
Outstanding at
December 31, 1995 865,600 2.23
Granted 149,500 8.75
Exercised (371,200) 1.59
Canceled (7,100) 2.92
--------- --------
Outstanding at
December 31, 1996 636,800 $ 4.13
========= ========
45
OUTSTANDING OPTIONS
--------------------------------------
WEIGHTED WEIGHTED
NUMBER AVERAGE AVERAGE
EXERCISE OF REMAINING EXERCISE
PRICES SHARES CONTRACTUAL LIFE PRICE
-----------------------------------------------------------
$1.50-$4.00 487,300 5 years $2.72
$8.75 149,500 10 years $8.75
EXERCISABLE OPTIONS
-----------------------
WEIGHTED
NUMBER AVERAGE
EXERCISE OF EXERCISE
PRICES SHARES PRICE
------------------------------------
$1.50-$4.00 375,000 $ 2.64
$8.75 - $ -
Options for 375,000, 675,000 and 676,400 shares were exercisable with
weighted average exercise prices of $2.64, $2.06 and $1.95 at December 31,
1996, 1995 and 1994, respectively.
In February and May 1992, the Board of Directors and shareholders,
respectively, approved the Unit Corporation Non-Employee Directors' Stock
Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the
Company's common stock may be issued upon exercise of the stock options.
On the first business day following each annual meeting of stockholders of
the Company, each person who is then a member of the Board of Directors of
the Company and who is not then an employee of the Company or any of its
subsidiaries will be granted an option to purchase 2,500 shares of common
stock. The option price for each stock option is the fair market value of
the common stock on the date the stock options are granted. No stock
options may be exercised during the first six months of its term except in
case of death and no stock options are exercisable after ten years from the
date of grant.
46
Activity pertaining to the Directors' Plan is as follows:
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
-------- --------
Outstanding at
January 1, 1994 20,000 $ 2.75
Granted 10,000 2.88
-------- --------
Outstanding at
December 31, 1994 30,000 2.79
Granted 12,500 3.38
-------- --------
Outstanding at
December 31, 1995 42,500 2.96
Granted 12,500 6.88
-------- --------
Outstanding at
December 31, 1996 55,000(1) $ 3.85
======== ========
- -------------
(1) All 55,000 options were exercisable at December 31, 1996.
47
The Company applies APB Opinion 25 in accounting for its Stock Option
Plan and Non-Employee Director's Stock Option Plan. Accordingly, based on
the nature of the Company's grants of options, no compensation cost has
been recognized in 1996 and 1995. Had compensation been determined on the
basis of fair value pursuant to FASB Statement No. 123, net income and
earnings per share would have been reduced as follows:
1996 1995
------ ------
Net Income (In thousands):
As reported $8,333 $3,999
====== ======
Pro forma $8,244 $3,971
====== ======
Primary Earnings per Share:
As reported $ .37 $ .19
===== =====
Pro forma $ .36 $ .19
===== =====
Fully Diluted Earnings per Share:
As reported $ .36 $ .19
===== =====
Pro forma $ .36 $ .19
===== =====
The fair value of each option granted is estimated using the Black-
Scholes model. The Company's volatility of stock was 0.51 based on
previous stock performance. Dividend yield was estimated to remain at zero
with a risk free interest rate of 6.55 and 6.45 percent in 1996 and 1995,
respectively. Expected life ranged from 1 to 10 years based on prior
experience depending on the vesting periods involved and the make up of
participating employees within each grant. Fair value of options granted
during 1996 and 1995 under the Stock Option Plan were $753,000 and $14,000,
respectively, and under the Non-Employee Stock Option Plan were $56,000 and
$27,000, respectively.
Under the Company's 401(k) Employee Thrift Plan, employees who meet
specified service requirements may contribute a percentage of their total
compensation, up to a specified maximum, to the plan. Each employee's
contribution, up to a specified maximum, may be matched by the Company in
full or on a partial basis. The Company made discretionary contributions
under the plan of 44,686, 46,659 and 32,685 shares of common stock and
recognized expense of $268,000, $174,000 and $130,000 in 1996, 1995 and
1994, respectively.
48
The Company provides a salary deferral plan ("Deferral Plan") which
allows participants to defer the recognition of salary for income tax
purposes until actual distribution of benefits which occurs at either
termination of employment, death or certain defined unforeseeable emergency
hardships. Funds set aside in a trust to satisfy the Company's obligation
under the Deferral Plan at December 31, 1996 and 1995 totaled $492,000 and
$271,000 respectively. The Company recognizes payroll expense and records
a liability at the time of deferral.
Effective January 1, 1997, the Company adopted a separation benefit
plan ("Separation Plan"). The Separation Plan allows eligible employees
whose employment with the Company is involuntarily terminated or, in the
case of an employee who has completed 20 years of service, voluntarily or
involuntarily terminated, to receive benefits equivalent to 4 week's salary
for every whole year of service completed with the Company up to a maximum
of 104 weeks. Benefits received under the Separation Plan will be reduced
by the amount of any other benefits received from other disability or
severance plans which may be in effect during the payment period. To
receive payments the recipient must waive any claims against the Company
in exchange for receiving the separation benefits. Benefits associated
with this plan will begin to be recognized in 1997 for anticipated payments
under the Separation Plan.
NOTE 8 - TRANSACTIONS WITH RELATED PARTIES
- ------------------------------------------
The Company formed private limited partnerships (the "Partnerships")
with certain qualified employees, officers and directors from 1984 through
1996, with a subsidiary of the Company serving as General Partner. The
Partnerships were formed for the purpose of conducting oil and natural gas
acquisition, drilling and development operations and serving as co-general
partner with the Company in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis
with the Company in most drilling operations and most producing property
acquisitions commenced by the Company for its own account during the period
from the formation of the Partnership through December 31 of each year.
Amounts received in the following years ended December 31 from both
public and private Partnerships for which the Company is a general partner
are as follows for the following years ended December 31:
1996 1995 1994
-------- -------- --------
(In thousands)
Contract drilling $ 37 $ 34 $ 53
Well supervision and other fees $ 349 $ 356 $ 226
General and administrative
expense reimbursement $ 105 $ 235 $ 209
49
A subsidiary of the Company paid the Partnerships, for which the
Company or a subsidiary is the general partner, $31,000, $18,000 and
$38,000 during the years ended December 31, 1996, 1995 and 1994,
respectively, for purchases of natural gas production.
During 1996, 1995 and 1994 a bank owned by one of the Company's
Directors was a participant in the Company's Loan Agreement. The bank's
total pro rata share of the Company's line of credit is currently limited
to an amount not to exceed $1.5 million.
NOTE 9 - SHAREHOLDER RIGHTS PLAN
- --------------------------------
The Company maintains a Shareholder Rights Plan (the "Plan") designed
to deter coercive or unfair takeover tactics, to prevent a person or group
from gaining control of the Company without offering fair value to all
shareholders and to deter other abusive takeover tactics which are not in
the best interest of shareholders.
Under the terms of the Plan, each share of common stock is accompanied
by one right, which given certain acquisition and business combination
criteria, entitles the shareholder to purchase from the Company one one-
hundredth of a newly issued share of Series A Participating Cumulative
Preferred Stock at a price subject to adjustment by the Company or to
purchase from an acquiring Company certain shares of its common stock or
the surviving company's common stock at 50 percent of its value.
The rights become exercisable 10 days after the Company learns that an
acquiring person (as defined in the Plan) has acquired 15 percent or more
of the outstanding common stock of the Company or 10 business days after
the commencement of a tender offer which would result in a person owning 15
percent or more of such shares. The Company can redeem the rights for
$0.01 per right at any date prior to the earlier of (i) the close of
business on the tenth day following the time the Company learns that a
person has become an acquiring person or (ii) May 19, 2005 (the "Expiration
Date"). The rights will expire on the Expiration Date, unless redeemed
earlier by the Company.
50
NOTE 10 - COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
The Company leases office space under the terms of operating leases
expiring through January 31, 2002. Future minimum rental payments under
the terms of the leases are approximately $368,000, $348,000, $341,000,
$93,000 and $70,000 in 1997, 1998, 1999, 2000, and 2001, respectively.
Total rent expense incurred by the Company was $323,000, $307,000 and
$210,000 in 1996, 1995 and 1994, respectively.
The Company had letters of credit supported by its Loan Agreement
totaling $1,070,000 at December 31, 1996.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy
Income Limited Partnership agreements along with the employee oil and gas
limited partnerships require, upon the election of a limited partner, that
the Company repurchase the limited partner's interest at amounts to be
determined by appraisal in the future. Such repurchases in any one year
are limited to 20 percent of the units outstanding. The Company made
repurchases of $30,000, $34,000 and $38,000 in 1996, 1995 and 1994,
respectively, for such limited partners' interests.
The Company is a party to various legal proceedings arising in the
ordinary course of its business none of which, in the Company's opinion,
will result in judgements which would have a material adverse effect on the
Company.
51
NOTE 11 - INDUSTRY SEGMENT INFORMATION
- --------------------------------------
The Company operates in the United States in two industry segments
which are contract drilling and oil and natural gas exploration. The
Company also has natural gas production in Canada which is not significant.
Selected financial information by industry segment is as follows:
Depreciation,
Depletion,
Operating Amortization
Operating Profit Total Capital and Impairment
Revenues (Loss)(1) Assets(2) Expenditures Expense
--------- -------- --------- ---------- ----------
Year ended (In thousands)
December 31, 1996:
Drilling $ 28,819 $ 1,616 $ 24,500 $ 9,910 $ 2,944
Oil and
natural gas 43,013 18,797 110,207 25,644 10,807
--------- -------- --------- ---------- ----------
71,832 $20,413 134,707 35,554 13,751
Other 238 ======== 3,286 989 328
--------- --------- ---------- ----------
Total $ 72,070 $137,993 $ 36,543 $ 14,079
========= ========= ========== ==========
Year ended
December 31, 1995:
Drilling $ 20,211 $ (426) $ 15,449 $ 1,556 $ 2,596
Oil and
natural gas 31,187 8,961 92,033 19,308 10,223
--------- -------- --------- ---------- ----------
51,398 $ 8,535 107,482 20,864 12,819
Other 1,676 ======== 3,440 1,089 301
--------- --------- ---------- ----------
Total $ 53,074 $110,922 $ 21,953 $ 13,120
========= ========= ========== ==========
Year ended
December 31, 1994:
Drilling $ 16,952 $ 13 $ 14,771 $ 1,115 $ 2,030
Oil and
natural gas 26,001 8,921 83,082 25,110 8,281
--------- -------- --------- ---------- ----------
42,953 $ 8,934 97,853 26,225 10,311
Other 942 ======== 5,956 764 449
Discontinued
operations - 124 - -
--------- --------- ---------- ----------
Total $ 43,895 $103,933 $ 26,989 $ 10,760
========= ========= ========== ==========
(1) Operating profit is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not include non-
operating revenues, general corporate expenses, interest expense,
income taxes or gain from litigation settlement.
(2) Identifiable assets are those used in the Company's operations in each
industry segment. Corporate assets are principally cash and cash
equivalents, short-term investments, corporate leasehold improvements,
furniture and equipment.
52
NOTE 12 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
- --------------------------------------------------------------
Summarized quarterly financial information for 1996 and 1995 is as
follows:
Three Months Ended
------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- --------- ---------
(In thousands except per share amounts)
Year ended December 31, 1996:
Revenues $ 15,871 $ 17,107 $ 17,286 $ 21,806
========= ========= ========= =========
Gross profit(1) $ 3,851 $ 4,376 $ 4,683 $ 7,503
========= ========= ========= =========
Income before
income taxes $ 1,952 $ 2,529 $ 3,096 $ 5,790
========= ========= ========= =========
Net Income $ 1,219 $ 1,589 $ 1,899 $ 3,626
========= ========= ========= =========
Earnings Per Common Share:
Primary $ .06 $ .07 $ .08 $ .15
========= ========= ========= =========
Fully diluted $ .06 $ .07 $ .08 $ .15
========= ========= ========= =========
53
Three Months Ended
------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- --------- ---------
(In thousands except per share amounts)
Year ended December 31, 1995:
Revenues $ 12,388 $ 11,505 $ 14,117 $ 15,064
========= ========= ========= =========
Gross profit(1) $ 1,875 $ 1,819 $ 1,721 $ 3,120
========= ========= ========= =========
Income from continuing
operations $ 857(2) $ 102 $ 916(3) $ 1,876(4)
Income (loss) from
discontinued
operations 99 (81) (35) (95)
Gain from sale of
discontinued
operations - - - 360
--------- --------- --------- ---------
Net Income $ 956(2) $ 21 $ 881(3) $ 2,141(4)
========= ========= ========= =========
Earnings Per Common Share:
(Both primary and fully diluted)
Continuing
operations $ .05(2) $ - $ .04(3) $ .09(4)
Discontinued
operations - - - (.01)
Gain on sale of
discontinued
operations - - - .02
--------- --------- --------- ---------
Net income $ .05(2) $ - $ .04(3) $ .10(4)
========= ========= ========= =========
(1)Gross Profit excludes other revenues, general and administrative
expense and interest expense.
(2)Includes $635,000 gain on sale of natural gas compressors.
(3)Includes $850,000 gain from the settlement of litigation.
(4)Includes a net income tax benefit of $530,000.
54
NOTE 13 - OIL AND NATURAL GAS INFORMATION (UNAUDITED)
- -----------------------------------------------------
The capitalized costs at year end and costs incurred during the year
were as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1996:
Capitalized costs:
Proved properties $ 195,528 $ 480 $ 196,008
Unproved properties 4,602 - 4,602
--------- -------- ---------
200,130 480 200,610
Less accumulated depreciation,
depletion, amortization
and impairment 102,463 389 102,852
--------- -------- ---------
Net capitalized costs $ 97,667 $ 91 $ 97,758
========= ======== =========
Cost incurred:
Unproved properties $ 1,640 $ - $ 1,640
Producing properties 2,338 - 2,338
Exploration 1,501 - 2,501
Development 20,150 15 20,165
--------- -------- ---------
Total costs incurred $ 25,629 $ 15 $ 25,644
========= ======== =========
1995:
Capitalized costs:
Proved properties $ 171,259 $ 465 $ 171,724
Unproved properties 3,501 - 3,501
--------- -------- ---------
174,760 465 175,225
Less accumulated depreciation,
depletion, amortization
and impairment 91,739 379 92,118
--------- -------- ---------
Net capitalized costs $ 83,021 $ 86 $ 83,107
========= ======== =========
Cost incurred:
Unproved properties $ 1,338 $ - $ 1,338
Producing properties 9,183 - 9,183
Exploration 1,291 - 1,291
Development 7,486 10 7,496
--------- -------- ---------
Total costs incurred $ 19,298 $ 10 $ 19,308
========= ======== =========
55
USA Canada Total
--------- -------- ---------
(In thousands)
1994:
Capitalized costs:
Proved properties $ 154,688 $ 455 $ 155,143
Unproved properties 2,250 - 2,250
--------- -------- ---------
156,938 455 157,393
Less accumulated depreciation,
depletion, amortization
and impairment 81,583 368 81,951
--------- -------- ---------
Net capitalized costs $ 75,355 $ 87 $ 75,442
========= ======== =========
Cost incurred:
Unproved properties $ 460 $ - $ 460
Producing properties 13,108 - 13,108
Exploration 1,825 - 1,825
Development 9,716 1 9,717
--------- -------- ---------
Total costs incurred $ 25,109 $ 1 $ 25,110
========= ======== =========
56
The results of operations for producing activities are provided below.
Due to the Company's utilization of net operating loss carryforwards,
income taxes were not significant and have not been included for the years
1995 and 1994.
USA Canada Total
--------- -------- ---------
(In thousands)
1996:
Revenues $ 40,432 $ 60 $ 40,492
Production costs 11,195 14 11,209
Depreciation, depletion
and amortization 10,723 11 10,734
--------- -------- ---------
18,514 35 18,549
Income tax expense 6,986 15 7,001
--------- -------- ---------
Results of operations for producing
activities (excluding corporate
overhead and financing costs) $ 11,528 $ 20 $ 11,548
========= ======== =========
1995:
Revenues $ 28,928 $ 53 $ 28,981
Production costs 9,914 16 9,930
Depreciation, depletion
and amortization 10,156 11 10,167
--------- -------- ---------
Results of operations for producing
activities before income taxes
(excluding corporate overhead
and financing costs) $ 8,858 $ 26 $ 8,884
========= ======== =========
1994:
Revenues $ 23,964 $ 67 $ 24,031
Production costs 7,011 19 7,030
Depreciation, depletion
and amortization 8,165 53 8,218
--------- -------- ---------
Results of operations for producing
activities before income taxes
(excluding corporate overhead
and financing costs) $ 8,788 $ (5) $ 8,783
========= ======== =========
57
Estimated quantities of proved developed oil and natural gas reserves
and changes in net quantities of proved developed and undeveloped oil and
natural gas reserves were as follows:
USA Canada Total
--------------------------------------------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------- -------- ------- --------
(In thousands)
1996:
Proved developed and
undeveloped reserves:
Beginning of year 5,428 107,950 - 778 5,428 108,728
Revision of previous (387) (3,822) - 26 (387) (3,796)
estimates
Extensions, discoveries
and other additions 718 34,625 - - 718 34,625
Purchases of minerals
in place 67 3,036 - - 67 3,036
Sales of minerals
in place (43) (407) - - (43) (407)
Production (579) (12,974) - (51) (579) (13,025)
------ -------- ------- -------- -------- --------
End of Year 5,204 128,408 - 753 5,204 129,161
====== ======== ======= ======== ======== ========
Proved developed reserves:
Beginning of year 4,697 94,975 - 350 4,697 95,325
End of year 4,509 107,536 - 326 4,509 107,862
1995:
Proved developed and
undeveloped reserves:
Beginning of year 4,308 92,566 - 794 4,308 93,360
Revision of previous
estimates 910 9,525 - (10) 910 9,515
Extensions, discoveries
and other additions 305 7,910 - 48 305 7,958
Purchases of minerals
in place 500 10,892 - - 500 10,892
Sales of minerals
in place (18) (938) - - (18) (938)
Production (577) (12,005) - (54) (577) (12,059)
------ -------- ------- -------- -------- --------
End of Year 5,428 107,950 - 778 5,428 108,728
====== ======== ======= ======== ======== ========
Proved developed reserves:
Beginning of year 3,521 80,110 - 359 3,521 80,469
End of year 4,697 94,975 - 350 4,697 95,325
58
USA Canada Total
--------------------------------------------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
------- -------- ------- -------- ------- --------
(In thousands)
1994:
Proved developed and
undeveloped reserves:
Beginning of year 3,304 71,379 - 861 3,304 72,240
Revision of previous
estimates (97) (571) - (14) (97) (585)
Extensions, discoveries
and other additions 601 17,426 - - 601 17,426
Purchases of minerals
in place 910 14,075 - - 910 14,075
Sales of minerals
in place (4) (137) - - (4) (137)
Production (406) (9,606) - (53) (406) (9,659)
------- -------- ------- -------- ------- --------
End of Year 4,308 92,566 - 794 4,308 93,360
======= ======== ======= ======== ======= ========
Proved developed reserves:
Beginning of year 3,187 65,395 - 426 3,187 65,821
End of year 3,521 80,110 - 359 3,521 80,469
Oil and natural gas reserves cannot be measured exactly. Estimates of
oil and natural gas reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made
in connection with financial disclosures. The Company utilizes Ryder Scott
Company, independent petroleum consultants, to review the Company's
reserves as prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geolog-
ical and engineering data, appear with reasonable certainty to be recov-
erable in the future from known oil and natural gas reservoirs under exist-
ing economic and operating conditions. Proved developed reserves are those
reserves which can be expected to be recovered through existing wells with
existing equipment and operating methods. Proved undeveloped reserves are
those reserves which are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expendi-
ture is required.
Estimates of oil and natural gas reserves require extensive judgments
of reservoir engineering data as previously explained. Assigning monetary
values to such estimates does not reduce the subjectivity and changing
nature of such reserve estimates. Indeed the uncertainties inherent in the
disclosure are compounded by applying additional estimates of the rates and
timing of production and the costs that will be incurred in developing and
producing the reserves. The information set forth herein is therefore
subjective and, since judgments are involved, may not be comparable to
estimates submitted by other oil and natural gas producers. In addition,
since prices and costs do not remain static and no price or cost escala-
tions or de-escalations have been considered, the results are not neces-
sarily indicative of the estimated fair market value of estimated proved
reserves nor of estimated future cash flows.
59
The standardized measure of discounted future net cash flows ("SMOG")
was calculated using year-end prices and costs, and year-end statutory tax
rates, adjusted for permanent differences, that relate to existing proved
oil and natural gas reserves. SMOG as of December 31 is as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1996:
Future cash flows $626,945 $ 2,735 $629,680
Future production and
development costs 171,749 339 172,088
Future income tax expenses 125,540 1,422 126,962
--------- -------- ---------
Future net cash flows 329,656 974 330,630
10% annual discount for
estimated timing of cash flows 129,610 368 129,978
--------- -------- ---------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $200,046 $ 606 $200,652
========= ======== =========
1995:
Future cash flows $320,916 $ 1,462 $322,378
Future production and
development costs 107,830 304 108,134
Future income tax expenses 49,437 660 50,097
--------- -------- ---------
Future net cash flows 163,649 498 164,147
10% annual discount for
estimated timing of cash flows 60,826 183 61,009
--------- -------- ---------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $102,823 $ 315 $103,138
========= ======== =========
1994:
Future cash flows $234,171 $ 1,255 $235,426
Future production and
development costs 105,876 311 106,187
Future income tax expenses 20,161 524 20,685
--------- -------- ---------
Future net cash flows 108,134 420 108,554
10% annual discount for
estimated timing of cash flows 30,116 170 30,286
--------- -------- ---------
Standardized measure of
discounted future net cash
flows relating to proved oil
and natural gas reserves $ 78,018 $ 250 $ 78,268
========= ======== =========
60
The principal sources of changes in the standardized measure of
discounted future net cash flows were as follows:
USA Canada Total
--------- -------- ---------
(In thousands)
1996:
Sales and transfers of oil and
natural gas produced,
net of production costs $(29,237) $ (46) $(29,283)
Net changes in prices and
production costs 92,541 738 93,279
Revisions in quantity estimates
and changes in production timing (13,390) 58 (13,332)
Extensions, discoveries and improved
recovery, less related costs 69,942 - 69,942
Purchases of minerals in place 5,821 - 5,821
Sales of minerals in place (514) - (514)
Accretion of discount 12,101 71 12,172
Net change in income taxes (44,039) (470) (44,509)
Other - net 3,998 (60) 3,938
--------- -------- ---------
Net change 97,223 291 97,514
Beginning of year 102,823 315 103,138
--------- -------- ---------
End of year $200,046 $ 606 $200,652
========= ======== =========
1995:
Sales and transfers of oil and
natural gas produced,
net of production costs $(19,015) $ (36) $(19,051)
Net changes in prices and
production costs 28,857 112 28,969
Revisions in quantity estimates
and changes in production timing (6,620) (10) (6,630)
Extensions, discoveries and improved
recovery, less related costs 11,320 49 11,369
Purchases of minerals in place 11,897 - 11,897
Sales of minerals in place (968) - (968)
Accretion of discount 8,447 54 8,501
Net change in income taxes (11,727) (105) (11,832)
Other - net 2,614 1 2,615
--------- -------- ---------
Net change 24,805 65 24,870
Beginning of year 78,018 250 78,268
--------- -------- ---------
End of year $102,823 $ 315 $103,138
========= ======== =========
61
USA Canada Total
--------- -------- ---------
1994:
Sales and transfers of oil and
natural gas produced,
net of production costs $(16,953) $ (48) $(17,001)
Net changes in prices and
production costs (14,941) 206 (14,735)
Revisions in quantity estimates
and changes in production timing (482) (5) (487)
Extensions, discoveries and improved
recovery, less related costs 17,050 - 17,050
Purchases of minerals in place 13,426 - 13,426
Sales of minerals in place (138) - (138)
Accretion of discount 7,915 35 7,950
Net change in income taxes (457) (177) (634)
Other - net (554) 8 (546)
--------- -------- ---------
Net change 4,866 19 4,885
Beginning of year 73,152 231 73,383
--------- -------- ---------
End of year $ 78,018 $ 250 $ 78,268
========= ======== =========
The Company's SMOG and changes therein were determined in accordance
with Statement of Financial Accounting Standards No. 69. Certain infor-
mation concerning the assumptions used in computing SMOG and their inherent
limitations are discussed below. Management believes such information is
essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect
management's expectations of actual revenues to be derived from those
reserves nor their present worth. Assigning monetary values to the reserve
quantity estimation process does not reduce the subjective and ever-
changing nature of such reserve estimates. Additional subjectivity occurs
when determining present values because the rate of producing the reserves
must be estimated. In addition to errors inherent in predicting the
future, variations from the expected production rate could result from
factors outside of management's control, such as unintentional delays in
development, environmental concerns or changes in prices or regulatory
controls. Also, the reserve valuation assumes that all reserves will be
disposed of by production. However, other factors such as the sale of
reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end prices of oil and
natural gas relating to proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided
by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
natural gas reserves at the end of the year, based on continuation of
existing economic conditions.
62
Future income tax expenses are computed by applying the appropriate year-
end statutory tax rates to the future pretax net cash flows relating
to proved oil and natural gas reserves less the tax basis of the Company's
properties. The future income tax expenses also give effect to permanent
differences and tax credits and allowances relating to the Company's proved
oil and natural gas reserves.
Care should be exercised in the use and interpretation of the above
data. As production occurs over the next several years, the results shown
may be significantly different as changes in production performance,
petroleum prices and costs are likely to occur.
As disclosed in Note 4, the Company is receiving payments from a
natural gas purchaser which are subject to recoupment from future natural
gas production. The amounts received will be reflected in revenues and the
reserves and future net cash flows will be reduced as recoupment occurs.
In early 1997, the natural gas industry has experienced a downturn in
natural gas prices. The Company's reserves were determined at December
31,1996 using a natural gas price of approximately $3.63 per Mcf for
natural gas not subject to long-term contracts. During February 1997, the
natural gas prices received by the Company fell to approximately $2.75 per
Mcf for natural gas not subject to long-term contracts. This decrease in
natural gas prices would have a significant effect on the SMOG value of the
Company's reserves at December 31, 1996.
63
REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors
Unit Corporation
We have audited the accompanying consolidated balance sheets of Unit
Corporation and subsidiaries as of December 31, 1996 and 1995 and the
related consolidated statements of operations, changes in shareholders'
equity and cash flows and the related financial statement schedule for each
of the three years in the period ended December 31, 1996. These financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Unit
Corporation and subsidiaries as of December 31, 1996 and 1995, and the con-
solidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule referred to above, when considered in relation
to the basic financial statements taken as a whole, presents fairly, in all
material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
February 18, 1997
64
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------------------------------------------------------------------------
Financial Disclosure.
- --------------------
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
- ------------------------------------------------------------
The table below and accompanying footnotes set forth certain infor-
mation concerning each executive officer of the Company. Unless otherwise
indicated, each has served in the positions set forth for more than five
years. Executive officers are elected for a term of one year. There are
no family relationships between any of the persons named.
NAME AGE POSITION
-----------------------------------------------------------
King P. Kirchner 69 Chairman of the Board, Chief Executive
Officer and Director
John G. Nikkel 62 President, Chief Operating Officer and
Director
Earle Lamborn 62 Senior Vice President, Drilling and
Director
Philip M. Keeley 55 Senior Vice President, Exploration and
Production
Larry D. Pinkston 42 Vice President, Treasurer and Chief
Financial Officer
Mark E. Schell 39 General Counsel and Secretary
________
Mr. Kirchner, a co-founder of the Company, has been the Chairman of
the Board and a director since 1963 and was President until November 1983.
Mr. Kirchner is a Registered Professional Engineer within the State of
Oklahoma, having received degrees in Mechanical Engineering from Oklahoma
State University and in Petroleum Engineering from the University of
Oklahoma.
65
Mr. Nikkel joined the Company in 1983 as its President and a director.
From 1976 until January 1982 when he co-founded Nike Exploration Company,
Mr. Nikkel was an officer and director of Cotton Petroleum Corporation,
serving as the President of that Company from 1979 until his departure.
Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production
Company for 18 years, last serving as Division Geologist for Amoco's Denver
Division. Mr. Nikkel presently serves as President and a director of Nike
Exploration Company. Mr. Nikkel received a Bachelor of Science degree in
Geology and Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 40
years, joining the Company's predecessor in 1952 prior to it becoming a
publicly-held corporation. He was elected Vice President, Drilling in 1973
and to his current position as Senior Vice President and Director in 1979.
Mr. Keeley joined the Company in November 1983 as a Senior Vice
President, Exploration and Production. Prior to that time, Mr. Keeley co-
founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and
serves as Executive Vice President and a director of that company. From
1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation,
serving first as Manager of Land and from 1979 as Vice President and a
director. Before joining Cotton, Mr. Keeley was employed for four years by
Apexco, Inc. as Manager of Land and prior thereto he was employed by
Texaco, Inc. for nine years. He received a Bachelor of Arts degree in
Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined the Company in December 1981. He had served as
Corporate Budget Director and Assistant Controller prior to being appointed
as Controller in February 1985. He has been Treasurer since December 1986
and was elected to the position of Vice President and Chief Financial
Officer in May 1989. He holds a Bachelor of Science Degree in Accounting
from East Central University of Oklahoma and is a Certified Public
Accountant.
Mr. Schell joined the Company in January of 1987, as its Secretary and
General Counsel. From 1979 until joining the Company, Mr. Schell was
Counsel, Vice President and a member of the Board of Directors of C & S
Exploration, Inc. He received a Bachelor of Science degree in Political
Science from Arizona State University and his Juris Doctorate degree from
the University of Tulsa Law School. He is a member of the Oklahoma and
American Bar Association as well as being a member of the American
Corporate Counsel Association and the American Society of Corporate
Secretaries.
The balance of the information required in this Item 10 is incorpo-
rated by reference from the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1997
annual meeting of stockholders.
66
Item 11.Executive Compensation
- ---------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1997 annual meeting of
stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management
- ------------------------------------------------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1997 annual meeting of
stockholders.
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Information required by this item is incorporated by reference from
the Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1997 annual meeting of
stockholders.
67
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- -------------------------------------------------------------------------
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements:
---------------------
Included in Part II of this report:
Consolidated Balance Sheets as of December 31, 1996 and 1995
Consolidated Statements of Operations for the years ended December
31, 1996, 1995 and 1994
Consolidated Statements of Changes in Shareholders' Equity for the
years ended December 31, 1996, 1995 and 1994
Consolidated Statements of Cash Flows for the years ended December
31, 1996, 1995 and 1994
Notes to Consolidated Financial Statements
Report of Independent Accountants
2. Financial Statement Schedules:
------------------------------
Included in Part IV of this report for the years ended December 31,
1996, 1995 and 1994:
Schedule II - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under
which they are required or because the required information is included
in the consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers
assigned such exhibits in the Exhibit Table of Item 601 of Regulation
S-K.
3. Exhibits:
--------
2 Certificate of Ownership and Merger of the Company and Unit
Drilling Co., dated February 22, 1979 (filed as an Exhibit to
the Company's Registration Statement No. 2-63702, which is
incorporated herein by reference).
3.1.1 Certificate of Incorporation (filed as Exhibit 3.2 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
3.1.2 Certificate of Amendment of Certificate of Incorporation dated
July 21, 1988 (filed as an Exhibit to the Company's Annual
Report under cover of Form 10-K for the year ended December
31, 1989, which is incorporated herein by reference).
68
3.1.3 Restated Certificate of Incorporation of Unit Corporation
dated February 2, 1994 (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
3.2.1 By-Laws (filed as Exhibit 3.5 to the Company's Registration
Statement of Form S-4 as S.E.C. File No. 33-7848, which is
incorporated herein by reference).
3.2.2 Amended and Restated By-Laws, dated June 29, 1988 (filed as an
Exhibit to the Company's Annual Report under cover of Form 10-
K for the year ended December 31, 1989, which is incorporated
herein by reference).
4.2.1 Form of Warrant Agreement between the Company and the Warrant
Agent (filed as Exhibit 4.1 to the Company's Registration
statement on Form S-2 as S.E.C. File No. 33-16116, which is
incorporated herein by reference).
4.2.2 Form of Warrant (filed as Exhibit 4.3 to the Company's
Registration Statement of Form S-2 as S.E.C. File No. 33-
16116, which is incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.2 on Form
S-2 as S.E.C. File No. 33-16116, which is incorporated herein
by reference).
4.2.4 First Amendment to Warrant Agreement (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended March 31, 1992, which is incorporated herein
by reference).
4.2.5 Second Amendment to Warrant Agreement (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended March 31, 1994, which is incorporated herein
by reference).
4.2.6 Rights Agreement dated as of May 19, 1995 between the Company
and Chemical Bank, as Rights Agent (filed as Exhibit 1 to the
Company's Form 8-A filed May 23, 1995, File No. 1-92601 and
incorporated herein by reference).
10.1.14 Amended and Restated Credit Agreement dated as of January 17,
1992 by and between Unit Corporation and Bank of Oklahoma
N.A., F&M Bank and Trust Company, Fourth National Bank of
Tulsa and Western National Bank of Tulsa (filed as an Exhibit
to the Company's Annual Report under cover of Form 10-K for
the year ended December 31, 1991, which is incorporated herein
by reference).
69
10.1.16 First Amendment to Amended and Restated Credit Agreement dated
as of May 1, 1992, by and between Unit Corporation and Bank of
Oklahoma, N.A., F&M Bank and Trust Company, Fourth National
Bank of Tulsa, and Western National Bank of Tulsa (filed as an
Exhibit to the Company's Quarterly Report under cover of Form
10-Q for the quarter ended June 30, 1992, which is
incorporated herein by reference).
10.1.17 Second Amendment to Amended and Restated Credit Agreement,
dated March 3, 1993 and effective as of March 1, 1993, by and
between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank
and Trust Company, Fourth National Bank of Tulsa, and Western
National Bank of Tulsa (filed as an Exhibit to the Company's
Quarterly Report under cover of Form 10-Q for the quarter
ended March 31, 1993, which is incorporated herein by
reference).
10.1.18 Third Amendment to Amended and Restated Credit Agreement
effective as of March 31, 1994, by and between Unit
Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust
Company, Bank IV, Oklahoma, N.A. and American National Bank
and Trust Company of Shawnee (filed as an Exhibit to the
Company's Quarterly Report under cover of Form 10-Q for the
quarter ended March 31, 1994, which is incorporated herein by
reference).
10.1.19 Fourth Amendment to Amended and Restated Credit Agreement
dated as of December 12, 1994, by and between Unit Corporation
and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank
IV, Oklahoma, N.A. and American National Bank and Trust
Company of Shawnee (filed as an Exhibit in Form 8-K dated
December 15, 1994, which is incorporated herein by reference).
10.1.20 Loan Agreement dated August 3, 1995 (filed as an Exhibit to
the Company's Quarterly Report under cover of Form 10-Q for
the quarter ended June 30, 1995, which is incorporated herein
by reference).
10.1.21 First Amendment to the Loan Agreement effective as of
September 4, 1996, by and between Unit Corporation and Bank of
Oklahoma, N.A., The First National Bank of Boston, Bank IV
Oklahoma, N.A. and American National Bank and Trust Company of
Shawnee (filed as an Exhibit to the Company's Quarterly
Report under cover of Form 10-Q for the quarter ended
September 30, 1996, which is incorporated herein by
reference).
10.1.22 Second Amendment to the Loan Agreement effective as of
December 16, 1996 by and between Unit Corporation and Bank of
Oklahoma,N.A., The First National Bank of Boston, Boatman's
National Bank of Oklahoma and American National Bank and Trust
Company of Shawnee (filed herewith).
70
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership
(filed as Exhibit I to Unit Drilling and Exploration Company's
Registration Statement on Form S-1 as S.E.C. File No. 2-66347,
which is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership
(filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's
Registration Statement Form S-1 as S.E.C. File No. 2-92582,
which is incorporated herein by reference).
10.2.11 Unit 1984 Employee Oil and Gas Program Agreement of Limited
Partnership (filed as an Exhibit 3.1 to Unit 1984 Employee Oil
and Gas Program's Registration Statement of Form S-1 as S.E.C.
File No. 2-89678, which is incorporated herein by reference).
10.2.12 Unit 1985 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit 3.1 to Unit 1985
Employee Oil and Gas Limited Partnership's Registration
Statement on Form S-1 as S.E.C. File No. 2-95068, which is
incorporated herein by reference).
10.2.13 Unit 1986 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit 10.11 to the
Company's Registration Statement on Form S-4 as S.E.C. File
No. 33-7848, which is incorporated herein by reference).
10.2.14 Unit 1987 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.15 Unit 1988 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.16 Unit 1989 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1989, which is incorporated herein by reference).
10.2.17 Unit 1990 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1990, which is incorporated herein by reference).
10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1991, which is incorporated herein by reference).
71
10.2.19 Unit 1992 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.20 Unit 1993 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1992, which is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as
Exhibit 10.16 to the Company's Registration Statement on Form
S-4 as S.E.C. File No. 33-7848, which is incorporated herein
by reference).
10.2.22* The Company's Stock Option Plan (filed as an Exhibit to the
Company's Registration Statement on Form S-8 as S.E.C. File
No's. 33-19652, 33-44103 and 33-64323 which is incorporated
herein by reference)
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan
(filed as an Exhibit to Form S-8 as S.E.C. File No. 33-49724,
which is incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed as an Exhibit
to Form S-8 as S.E.C. File No. 33-53542, which is incorporated
herein by reference).
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership
Agreement. (filed as an Exhibit to the Company's Annual Report
under cover of Form 10-K for the year ended December 31, 1993,
which is incorporated herein by reference).
10.2.26 Unit 1994 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report under cover of Form 10-K for the year ended
December 31, 1993, which is incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to
the Company's Annual Report under cover of Form 10-K for the
year ended December 31, 1993, which is incorporated herein by
reference).
10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the Company's
Annual Report, under cover of Form 10-K for the year ended
December 31, 1994, which is incorporated herein by reference).
10.2.29 Unit 1996 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed as an Exhibit to the
Company's Annual Report under cover of Form 10-K for the year
ended December 31, 1995, which is incorporated herein by
reference).
72
10.2.30* Separation Benefit Plan of Unit Corporation and Participating
Subsidiaries (filed herewith).
10.2.31 Unit 1997 Employee Oil and Gas Limited Partnership Agreement
of Limited Partnership (filed herewith).
10.5 Acquisition and Development Agreement, dated September 26,
1991, between Registrant and Municipal Energy Agency of
Nebraska (filed as an Exhibit to Form 8-K dated September 30,
1991, which is incorporated herein by reference).
10.6 Purchase and Sale Agreement, dated May 22, 1992, between Esco
Exploration, Inc. and Aleco Production Company (as "Seller")
and Unit Petroleum Company (a "Buyer") and Helmerich & Payne,
Inc. (a "Buyer") (filed as an Exhibit to Form 8-K dated May
21, 1992, which is incorporated herein by reference).
10.7 Asset Purchase Agreement, dated as of November 28, 1994,
between the Registrant and Patrick Petroleum Corp of Michigan
and American National Petroleum Company (filed as an Exhibit
to Form 8-K dated December 15, 1994, which is incorporated
herein by reference).
21 Subsidiaries of the Registrant (filed herewith).
23 Consent of Independent Accountants (filed herewith).
27 Financial Data Schedules (filed herewith).
* Indicates a management contract or compensatory plan identified
pursuant to the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter ended
December 31, 1996.
73
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance
Balance at charged to Deductions at
beginning costs & & net end of
Description of period expenses write-offs period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1996 $ 116 $ - $ 12 $ 104
======== ======== ======== ========
Year ended
December 31, 1995 $ 289 $ 55 $ 228 $ 116
======== ======== ======== ========
Year ended
December 31, 1994 $ 411 $ - $ 122 $ 289
======== ======== ======== ========
Deferred Tax Asset Valuation Allowance:
Balance at Balance at
beginning end of
Description of period Additions Deductions period
----------- --------- -------- --------- --------
(In thousands)
Year ended
December 31, 1996 $ 3,530 $ - $ - $ 3,530
======== ======== ======== ========
Year ended
December 31, 1995 $ 6,423 $ - $ 2,893 $ 3,530
======== ======== ======== ========
Year ended
December 31, 1994 $ 8,218 $ - $ 1,795 $ 6,423
======== ======== ======== ========
74
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION
DATE: March 17, 1997 By: /s/ John G. Nikkel
-------------- ----------------------
JOHN G. NIKKEL
President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on the 17th day of March, 1997.
Name Title
/s/ King P. Kirchner
------------------------------- Chairman of the Board and Chief
KING P. KIRCHNER Executive Officer, Director
/s/ John G. Nikkel
------------------------------- President and Chief Operating
JOHN G. NIKKEL Officer, Director
/s/Earle Lamborn
------------------------------- Senior Vice President, Drilling,
EARLE LAMBORNDirector
/s/Larry D. Pinkston
------------------------------- Vice President, Chief Financial
LARRY D. PINKSTON Officer and Treasurer
/s/Stanley W. Belitz
------------------------------- Controller
STANLEY W. BELITZ
/s/Don Bodard
------------------------------- Director
DON BODARD
/s/Don Cook
------------------------------- Director
DON COOK
/s/William B. Morgan
------------------------------- Director
WILLIAM B. MORGAN
/s/John S. Zink
------------------------------- Director
JOHN S. ZINK
------------------------------- Director
JOHN H. WILLIAMS
75
EXHIBIT INDEX
-----------------------
Exhibit
No. Description Page
--------- -------------------------------------------- -----
10.1.22 Second Amendment to the Loan Agreement effective as
of December 16, 1996 by and between Unit Corporation
and Bank of Oklahoma, N.A., The First National Bank
of Boston, Boatman's National Bank of Oklahoma and
American National Bank and Trust Company of Shawnee.
10.2.30 Separation Benefit Plan of Unit Corporation and
Participating Subsidiaries.
10.2.31 Unit 1997 Employee Oil and Gas Limited
Partnership Agreement of Limited Partnership.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
27 Financial Data Schedule.
76