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1996
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 1996
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________
Commission File Number: 1-10662
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CROSS TIMBERS OIL COMPANY
(Exact name of registrant as specified in its charter)
810 Houston Street,
Suite 2000,
Delaware 75-2347769 Fort Worth, Texas 76102
- ---------------- ------------------- --------------------- ----------
(State or other (I.R.S. Employer (Address of principal (Zip Code)
jurisdiction of Identification No.) executive offices)
incorporation or
organization)
Registrant's telephone number, including area code (817) 870-2800
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Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
- ------------------------------------ -----------------------------------------
Common stock, $.01 par value New York Stock Exchange
Series A convertible preferred stock, New York Stock Exchange
$.01 par value
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to be 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
nonaffiliates of the Registrant as of March 11, 1997
was approximately $493 million
Number of Shares of Common Stock outstanding as of March 11, 1997 - 17,877,929
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(As restated for the three-for-two stock split effective March 19,
1997 - 26,816,893)
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DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Part III of this Report is incorporated by reference from the Registrant's
definitive Proxy Statement for its Annual Meeting of Stockholders, which will be
filed with the Commission no later than April 30, 1997.
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CROSS TIMBERS OIL COMPANY
1996 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
ITEM PAGE
---- ----
PART I
1. and 2. Business and Properties........................................ 1
3. Legal Proceedings.............................................. 12
4. Submission of Matters to a Vote of Security Holders............ 12
PART II
5. Market for Registrant's Common Equity and Related
Stockholder Matters.......................................... 13
6. Selected Financial Data........................................ 14
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 16
8. Financial Statements and Supplementary Data.................... 24
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 24
PART III
10. Directors and Executive Officers of the Registrant............. 24
11. Executive Compensation......................................... 24
12. Security Ownership of Certain Beneficial Owners and Management. 24
13. Certain Relationships and Related Transactions................. 24
PART IV
14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K..................................................... 25
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
Cross Timbers Oil Company and its wholly owned subsidiaries ("the Company")
are engaged in the acquisition, development, exploitation and exploration of
producing oil and gas properties, and in the production, processing, marketing
and transportation of oil and natural gas. The Company has grown primarily
through acquisitions of proved oil and gas reserves, followed by development and
exploitation activities and strategic acquisitions of additional interests in or
near such acquired properties. The Company's proved reserves are principally
located in relatively long-lived fields with well-established production
histories concentrated in western Oklahoma, the Permian Basin of West Texas and
New Mexico, the Hugoton Field of Oklahoma and Kansas, and the Green River Basin
of Wyoming.
The Company's estimated proved reserves at December 31, 1996 were 42.4 million
barrels ("Bbls") of oil and 540.5 billion cubic feet ("Bcf") of natural gas, as
compared to December 31, 1995 proved reserves of 40 million Bbls and 358.1 Bcf.
Increased proved reserves during 1996 are primarily the result of predominantly
gas-producing property acquisitions and development and exploitation
activities, partially offset by production. During 1996, the Company's daily
oil and gas production averaged 9,584 Bbls and 101,845 Mcf. Fourth quarter 1996
daily oil and gas production averaged 9,611 Bbls and 114,769 Mcf.
The Company's properties are characterized by relatively long reserve life and
highly predictable well production profiles. Based on December 31, 1996 proved
reserves and projected 1997 production, the average reserve-to-production index
of the Company's proved reserves is 12.4 years. In general, the Company's
properties have extensive production histories and production enhancement
opportunities. While the Company's properties are geographically diversified,
the producing fields are concentrated within core areas, allowing for
substantial economies of scale in production and cost-effective application of
reservoir management techniques gained from prior operations. By operating the
majority of its properties, the Company can control expenses, capital allocation
and the timing of development and exploitation activities in its fields, thus
allowing the Company to reduce production costs of acquired properties.
The Company has generated a substantial inventory of approximately 630
potential development drilling locations within its existing properties (of
which 156 have been attributed proved undeveloped reserves), to support future
net reserve additions. Approximately 200 of these locations will require
certain regulatory approvals and legislation in Oklahoma prior to drilling.
The Company employs a disciplined acquisition program refined by senior
management to augment its core properties and expand its reserve base. The
Company's engineers and geologists use their expertise and experience gained
through the management of existing core properties to target properties to be
acquired with similar geological and reservoir characteristics.
A subsidiary of the Company operates a gas gathering system in Major County,
Oklahoma, where a significant portion of the Company's gas is produced. Since
August 1, 1995, another subsidiary of the Company also operates a gas gathering
system and a gas processing plant in the Hugoton Field of Kansas and Oklahoma.
Most of the Company's production is sold at market-responsive prices. The
Company also markets its oil and gas, including sales of gas under forward sales
contracts. The Company occasionally uses futures contracts to hedge pricing
risks.
History of the Company
Cross Timbers Oil Company was incorporated in Delaware in 1990 to act as the
managing general partner of Cross Timbers Oil Company, L.P. ("Partnership"), and
ultimately to acquire the business and properties of the Partnership. The
Partnership was formed to combine in February 1991 the business and operations
of six limited partnerships and two corporations that were founded between 1986
and 1989. On May 18, 1993, the Partnership
1
exchanged its common units of ownership for an equal number of shares of common
stock in Cross Timbers Oil Company and the Company sold 3.7 million shares of
common stock in its initial public offering.
During 1991, predecessors of the Company formed Cross Timbers Royalty Trust
("Royalty Trust") by carving net profits interests out of substantially all the
royalty and overriding royalty interests that the Company's predecessors then
owned in Texas, New Mexico and Oklahoma, and certain nonoperated working
interest properties in Texas and Oklahoma. The Company makes monthly net profits
payments to the Royalty Trust based on revenues received and costs disbursed for
the properties from which the net profits interests were carved. Royalty Trust
units of beneficial interest ("Units") are listed on the New York Stock Exchange
under the symbol "CRT." From July through December 1996, the Company acquired
16% of the outstanding Royalty Trust Units. In January 1997, after acquiring a
total of one million Units, the Board of Directors authorized the purchase of up
to one million additional Units.
Current Operating Environment
The oil and gas industry is affected by many factors that the Company
generally cannot control. Crude oil prices are generally determined by global
supply and demand. After hitting a five-year low at the end of 1993, oil prices
have since continued to improve, primarily as a result of an improved global
economy, continued sanctions against Iraq and OPEC's decision to maintain
production quotas. Despite partial resumption of Iraqi exports, 1996 oil prices
reached their highest levels since the Persian Gulf War in 1990.
Natural gas prices are influenced by national and regional supply and demand.
Natural gas competes with alternative energy sources as a fuel for heating and
the generation of electricity. Gas prices were adversely impacted in 1995 as a
result of the winter of 1994/1995 being one of the warmest of the century.
Prices began to increase in fourth quarter 1995 when low storage levels were
strained by unexpected cold weather. During 1996, U. S. gas consumption reached
record highs, and prices were at their highest level since 1985.
Business Strategy
The primary components of the Company's business strategy are (i) acquiring
long-lived, operated oil and gas properties, (ii) increasing production and
reserves through aggressive management of operations and through development,
exploitation and exploration activities, and (iii) retaining management and
technical staff that have substantial experience in the Company's core areas.
Acquiring Long-Lived, Operated Properties. The Company seeks to acquire long-
lived, onshore operated producing properties that (i) contain complex multiple-
producing horizons with the potential for increases in reserves and production,
(ii) are in the Company's core operating areas or in areas with similar geologic
and reservoir characteristics and (iii) present opportunities to reduce expenses
through more efficient operations. The Company believes that the properties it
acquires provide opportunities to increase production and reserves through the
implementation of mechanical and operational improvements, workovers, behind-
pipe completions, secondary recovery operations, new development wells and other
exploitation activities. The Company also seeks to acquire facilities related to
gathering, processing, marketing and transporting oil and gas in areas where it
owns reserves. Such facilities can enhance profitability, reduce gathering,
processing, marketing and transportation costs, provide marketing flexibility
and give the Company access to additional markets. The Company's ability to
successfully purchase properties is dependent upon, among other things,
competition for such purchases and the availability of cash resources.
Increasing Production and Reserves. A principal component of the Company's
strategy is to increase production and reserves through aggressive management of
operations and through development, exploitation and exploration. The Company
believes that its principal properties possess geologic and reservoir
characteristics that make them well suited for production increases through
low-risk exploitation and drilling programs. The Company has generated an
inventory of approximately 630 potential drilling locations for this program.
Additionally, the Company reviews operations and mechanical data on operated
properties to determine if actions can be taken to reduce operating costs or
increase production. Such actions include installing, repairing and upgrading
lifting equipment, redesigning downhole equipment to improve production from
different zones, modifying surface facilities
2
and conducting restimulations and recompletions. The Company may also initiate,
upgrade or revise existing secondary recovery operations and drill development
wells.
The Company's strategy has evolved to include allocation of 10% to 20% of its
annual capital budget (excluding acquisitions) to higher-risk projects,
including step-out development drilling, trend extensions and exploration. The
Company attempts to select projects that it believes will have the potential to
add substantially to proved reserves and cash flow. Although it has not
historically engaged in significant exploratory activities, the Company believes
that it can prudently and successfully add growth potential through exploratory
activities given improved technology, its experienced technical staff and its
expanded base of operations.
Experienced Management and Technical Staff. Most of the Company's senior
management and technical staff have worked together for over 20 years and have
substantial experience in the Company's core operating areas. Bob R. Simpson
and Steffen E. Palko, who were co-founders of the Company and its predecessors,
were previously executive officers of Southland Royalty Company, one of the
largest U.S. independent oil and gas producers prior to its acquisition by
Burlington Northern, Inc. in 1985.
Other Strategies. The Company may also acquire working interests in
producing properties that do not include the right to operate such properties
("nonoperated interests") if such interests otherwise meet its acquisition
criteria. The Company attempts to acquire nonoperated interests in fields that
are operated by major or established independent oil companies, where such
fields represent a significant investment to the operator and are therefore more
likely to be carefully managed by it. The Company may also acquire nonoperated
interests with the intent of ultimately aggregating, through future
acquisitions, sufficient interests to obtain the right to operate the
properties. The Company attempts to acquire nonoperated interests where geologic
conditions indicate the potential for undeveloped reserves that the operator
will exploit.
The Company also attempts to acquire a portion of its oil and gas reserves in
the form of royalty interests. Royalty interests offer less exposure to
operational liabilities because they do not participate in operating activities
and do not bear production or development costs. However, royalty interests
typically allow only limited influence on the operation or development of
properties.
Business Goals. In May 1996, the Company announced the increase in its
1996 development budget to $40 million, and in February 1997, announced its
1997 capital budget of $120 million. The 1997 budget includes $70 million for
the Company's ongoing development program and $50 million for the Company's base
acquisition budget. If attractive acquisition opportunities arise during 1997,
the Company could significantly exceed its base acquisition budget. The Company
plans to allocate up to 20% of the development expenditures to higher-risk
projects, including step-out development wells and exploratory drilling.
Selected projects must have the ability to add three to ten million barrels of
oil equivalent ("BOE") to the Company's proved reserves and to substantially
increase its cash flow.
The Company's goal in accelerating capital expenditures and strategic
acquisitions is to increase 1997 cash flow to $5.50 per common share ($3.67 on a
post three-for-two split basis). Proved reserves at year-end 1997 are targeted
at 5.4 BOE per share, up 50% from 3.6 BOE at the beginning of 1996. Development
expenditures will be funded from internally generated sources, while strategic
acquisitions will be funded by a combination of cash flow from operations and
bank borrowings. Proceeds from public equity and debt transactions may also be
utilized to finance acquisitions. The Company expects to complete this plan with
the same relative level of debt that it currently employs, about $2.20 per BOE
proved reserves, which the Company believes provides the optimal capital
structure.
ACQUISITIONS
During 1995, the Company acquired predominantly gas-producing properties for a
total cost of $131 million, and a gas processing plant and gathering facility
for $29 million. The Santa Fe Acquisition, the largest of these acquisitions,
closed on August 1, 1995 and consisted of mostly operated properties, a gas
processing plant and gathering system in the Hugoton Field of Kansas and
Oklahoma. The 1995 acquisitions increased proved reserves by approximately 3
million Bbls and 171 Bcf.
3
During 1996, the Company acquired predominantly gas-producing properties for a
total cost of $110 million. The Enserch Acquisition, the largest of these
acquisitions, closed in July 1996 at a cost of $39.4 million and primarily
consisted of operated interests in the Green River Basin of southwestern
Wyoming. In November 1996, the Company acquired additional interests in the
Fontenelle Unit, the most significant property included in the Enserch
Acquisition, at a cost of $12.5 million. In December 1996, the Company acquired
primarily operated interests in gas-producing properties in the Ozona area of
the Permian Basin of West Texas for $28 million. From July through December
1996, the Company acquired 16% of the publicly traded outstanding units of
beneficial interest in Cross Timbers Royalty Trust at a total cost of $12.8
million. The 1996 acquisitions increased proved reserves by approximately 1.6
million Bbls and 153.4 Bcf.
SIGNIFICANT PROPERTIES
The following table summarizes proved reserves and discounted present value,
before income tax, of proved reserves by the Company's major operating areas at
December 31, 1996 (in thousands):
Discounted
Proved Reserves Present Value
-------------------------------- before Income Tax of
Oil (Bbl) Gas (Mcf) Proved Reserves
---------------- -------------- ---------------------
Permian Basin... 31,274 77,655 $346,520 36.6%
Mid-Continent... 8,512 165,334 306,730 32.4%
Hugoton......... 362 161,318 167,160 17.7%
Rocky Mountain.. 1,673 127,554 107,269 11.3%
Other (a)....... 619 8,677 18,471 2.0%
------ ------- -------- ----
Total........... 42,440 540,538 $946,150 100.0%
====== ======= ======== =====
(a) Includes 396,000 Bbls and 6,431,000 Mcf and discounted present value
before income tax of $12,242,000 related to the Company's 16% ownership
of Royalty Trust Units at December 31, 1996.
PERMIAN BASIN AREA
Prentice Field. The Prentice Field is located in Terry and Yoakum Counties,
Texas. In 1993, the Company acquired its initial interest in the Prentice
Northeast Unit in three separate transactions, accumulating a 62.1% interest.
In January 1994, the Company purchased an additional 29.4% interest in the
Prentice Northeast Unit, increasing the Company's total ownership to 91.5%. The
Company assumed operations of the Unit effective March 1, 1994. Current net
production from the 153-well Unit is approximately 2,650 Bbls of oil and 580 Mcf
of gas per day. The Company also owns an interest in 80 gross (1.7 net)
nonoperated wells.
Discovered in 1950, the Prentice Field produces from carbonate reservoirs in
the Clear Fork and Glorieta formations at depths ranging from 6,000 to 7,000
feet. The Prentice Field has been separated into several waterflood units for
secondary recovery operations. The Prentice Northeast Unit was formed in 1964
with waterflood operations commencing a year later. Development potential
exists through infill drilling and improvement of waterflood efficiency.
Tertiary recovery potential also exists through carbon dioxide flooding.
During 1996, the Company drilled 28 development wells in the Prentice
Northeast Unit. The Company plans to drill a total of 31 wells during 1997.
Twenty-six of these wells are 10-acre infill wells based on the success of the
1996 program. The remaining five wells are 20-acre wells strategically located
to test the deeper reservoirs discovered in 1995.
Russell Field. The Russell Field is located in Gaines County, Texas. The
Company owns an interest in 25 gross (23.4 net) wells that it operates and 139
gross (43.6 net) wells operated by others. Current net daily oil and gas
production is approximately 990 Bbls and 530 Mcf.
4
The Russell Field, discovered in 1943, produces from the San Andres,
Glorieta, Middle Clear Fork and Devonian formations at depths ranging from 4,800
to 10,800 feet. Exploitation potential exists through restimulations,
recompletions, infill drilling, and the implementation of secondary recovery
operations in the Middle Clear Fork and San Andres formations.
During 1996, the Company performed four recompletions to the Glorieta and
San Andres formations. The Company and its working interest partners plan to
drill five Middle Clear Fork and Glorieta wells during 1997.
Ozona Area. The Company acquired interests in 1996 in the Henderson, Ozona,
and Davidson Ranch fields located in Crockett County, Texas. The Company
acquired interests in 88 gross (49.1 net) wells that it operates and 124 gross
(26.3 net) wells operated by others. Current net daily production is
approximately 8.1 MMcf and 43 Bbls.
Oil and gas were first discovered in the Ozona area in 1962. Production is
from the Pennsylvanian Canyon sandstones and Strawn carbonates at depths ranging
from 6,500 to 9,000 feet. Development potential for this area includes infill
drilling, field extension and delineation drilling, and the possibility of
horizontal drilling in the Strawn Formation.
During 1997, the Company plans to drill a total of 32 wells which are equally
divided between the Henderson and Ozona Fields. This will be one of the most
active gas development areas in the Company.
University Block 9. The University Block 9 Field is located in Andrews
County, Texas. The Company owns an interest in 36 gross (30.1 net) wells that
it operates. Current net daily production is approximately 700 Bbls of oil and
750 Mcf of gas.
The University Block 9 Field was discovered in 1953. Productive zones are of
Wolfcamp, Pennsylvanian, and Devonian age at 8,400, 8,700 and 10,400 feet,
respectively. The Company recently completed an acquisition which gave it 100%
working interest and operation of the Wolfcamp Unit, Penn Unit, and 13 of the 14
active Devonian wells. Development potential includes proper wellbore
utilization, recompletions, infill drilling and improvement of waterflood
efficiency.
During 1996, the Company drilled 2 gross (2 net) Devonian wells. During 1997,
the Company plans to drill 15 wells, making this field one of the most active
oil development areas in the Company.
MID-CONTINENT AREA
Major County Area. The Company is one of the largest producers in the
Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County, Oklahoma.
The Company operates 426 gross (364.2 net) wells and has an interest in 199
gross (45.4 net) wells operated by others. Current net daily oil and gas
production is approximately 930 Bbls and 32,700 Mcf.
Oil and gas were first discovered in the Major County area in 1945. The fields
in the Major County area are located in the Anadarko Basin and are characterized
by oil and gas production from a variety of structural and stratigraphic traps.
Productive zones range from 6,500 to 9,400 feet and include the Oswego, Red
Fork, Chester, Manning, Mississippian, Hunton and Arbuckle formations.
The Company develops the Major County area primarily through mechanical
improvements, restimulations, recompletions to shallower zones and development
drilling. During 1996, the Company participated in the drilling of 33 gross
wells and has budgeted 21 gross (11.1 net) wells in Major County for 1997. The
primary area for drilling during 1997 is located in the western portion of the
County and will target the Mississippian and Chester formations.
A subsidiary of the Company operates a gathering system and pipeline in the
Major County area. The gathering system collects gas from 425 wells through 300
miles of pipeline in the Major County area. The gathering system has current
throughput of approximately 30,000 Mcf per day, 70% of which is produced from
Company operated wells. Estimated capacity of the gathering system is 40,000
Mcf per day. Gas is delivered to a processing
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plant owned and operated by a third party, and then transmitted by a 26-mile
Company-operated pipeline to connections with other pipelines.
Since 1994, the Company has operated its Major County gathering system.
Through its direct maintenance and management, the Company has achieved
operating cost reductions and improved reliability. During 1994 and 1995, the
gathering system was converted from centralized to field compression through the
installation of four field compression stations. Field compression has allowed
the system to operate more efficiently and to expand into previously
inaccessible areas.
Elk City Field. The Elk City Field is located in Beckham and Washita Counties
of western Oklahoma. The Company operates the Elk City Unit with 35 gross (31.6
net) wells and owns an interest in 9 gross (1.5 net) wells operated by others.
Current net production of the Elk City Field is approximately 180 Bbls of oil
and 5,200 Mcf of gas per day.
The Elk City Field was discovered in 1947 and has been extensively developed.
Production is from the Hoxbar (9,500 feet), Atoka (13,100 feet) and Morrow
(15,500 feet) zones. The Company's primary development activities in this field
have been to initiate mechanical efficiencies and to recomplete additional
productive intervals. Recompletions and zone isolations have been successful
and additional opportunities for these types of workovers remain in the field.
Recent recompletions to the Atoka Formation have resulted in significant reserve
additions. There are several other deep wellbores with similar recompletion
potential.
HUGOTON AREA
The Hugoton Field, discovered in 1922, covers parts of Texas, Oklahoma and
Kansas and is the largest gas field in the United States. It is estimated that
5 million productive acres exist in the entire field. The Company owns an
interest in 349 gross (327.9 net) wells that it operates and 116 gross (25.8
net) wells operated by others. Current net production averages approximately
34,400 Mcf of gas per day and 110 Bbls of oil per day.
Approximately 70% of the Company's Hugoton gas production is delivered to the
Tyrone Plant, a gas processing plant operated by the Company. In May 1996, the
Company completed the installation of a field compressor on the southern end of
the Tyrone gathering system. This unit compresses gas from forty-four wells,
thirty-one of which are owned by the Company, and has resulted in a significant
production increase. The Company also completed the installation and start-up
of a residue compressor and 11.5 miles of high pressure residue pipeline during
August 1996. The installation of these facilities allows the Company to operate
the Tyrone Plant more efficiently and allows access to three additional
interstate pipelines.
While much of the Kansas portion of the Hugoton Field has been infill drilled
on 320-acre spacing, the Company believes that there are up to 50 additional
potential infill drilling locations. The Oklahoma portion is drilled on 640-
acre spacing. The Company believes that there are approximately 200 potential
infill drilling locations, subject to regulatory approval and possibly new
legislation being enacted in Oklahoma.
During 1996, the Company installed artificial lift on 53 wells along with
drilling five gross (4.8 net) wells in the Kansas portion of the Hugoton Field.
The Company plans to drill 10 wells to the Council Grove and Chase formations
during 1997.
ROCKY MOUNTAIN AREA
Green River Basin. The Green River Basin is located in southwestern Wyoming.
The Company acquired interests in 110 gross (100.2 net) wells that it operates
and 37 gross (8.3 net) wells operated by others in the Fontenelle, Nitchie Gulch
and Pine Canyon fields during 1996. Current net daily production is
approximately 18.5 MMcf of gas and 70 Bbls of oil.
Gas production was discovered in the Fontenelle area in the early 1970's. The
producing reservoirs are the Cretaceous Frontier and Dakota sandstones at depths
ranging from 7,500 to 10,000 feet. Exploitation potential for the fields in
this area include restimulations, recompletions and development drilling.
6
During 1996, the Company drilled 10 gross (9.8 net) wells of which eight were
completed in 1996 with the remaining two wells being completed in early 1997.
The Company plans to drill approximately 30 wells during 1997, targeting the
Frontier Formation, making this one of the Company's most active development
areas.
RESERVES
The following are estimated quantities of proved reserves and cash flows
therefrom as of December 31, 1996, 1995 and 1994:
December 31
------------------------------
1996 1995 1994
---------- -------- --------
(in thousands)
Proved developed:
Oil (Bbls).......................... 31,883 28,946 26,948
Gas (Mcf)........................... 466,412 320,230 164,169
Proved undeveloped:
Oil (Bbls).......................... 10,557 11,042 6,633
Gas (Mcf)........................... 74,126 37,840 12,892
Total proved:
Oil (Bbls).......................... 42,440 39,988 33,581
Gas (Mcf)........................... 540,538 358,070 177,061
Estimated future net cash flows:
Before income tax.................. $1,737,024 $712,907 $406,128
After income tax................... $1,286,037 $581,888 $344,591
Present value of estimated future
net cash flows, discounted at 10%:
Before income tax.................. $ 946,150 $405,706 $247,946
After income tax................... $ 706,481 $335,156 $213,146
Miller and Lents, Ltd. ("Miller and Lents"), an independent petroleum
engineering firm, prepared the estimates of the Company's proved reserves and
the future net cash flow (and present value thereof) attributable to proved
reserves at December 31, 1996, 1995 and 1994. As prescribed by the Securities
and Exchange Commission, such proved reserves were estimated using oil and gas
prices and production and development costs as of December 31 of each such year,
without escalation. See Note 11 to Consolidated Financial Statements for
additional information regarding estimated proved reserves.
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company.
Reserve engineering is a subjective process of estimating subsurface
accumulations of oil and gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of available data
and the interpretation thereof. As a result, estimates by different engineers
often vary, sometimes significantly. In addition, physical factors such as the
results of drilling, testing and production subsequent to the date of an
estimate, as well as economic factors such as change in product prices, may
justify revision of such estimates. Accordingly, oil and gas quantities
ultimately recovered will vary from reserve estimates.
During 1996, the Company filed estimates of oil and gas reserves as of
December 31, 1995 with the U.S. Department of Energy on Form EIA-23. These
estimates were consistent with the reserve data reported in Note 11 to
Consolidated Financial Statements for the year ended December 31, 1995, with the
exception that Form EIA-23 includes only reserves from properties operated by
the Company.
7
EXPLORATION AND PRODUCTION DATA
For the following data, "gross" refers to the total wells or acres in which
the Company owns a working interest and "net" refers to gross wells or acres
multiplied by the percentage working interest owned by the Company. Although
many of the Company's wells produce both oil and gas, a well is categorized as
an oil well or a gas well based upon the ratio of oil to gas production.
Producing Wells
The following table summarizes the Company's producing wells as of December
31, 1996, all of which are located in the United States:
Operated Wells Non-Operated Wells Total (a)
-------------- ------------------ -------------
Gross Net Gross Net Gross Net
----- ------- ------ ------- ----- ------
Oil.... 595 530.3 3,050 192.2 3,645 722.5
Gas.... 970 841.8 694 130.8 1,664 972.6
----- ------- ----- ----- ----- -------
Total.. 1,565 1,372.1 3,744 323.0 5,309 1,695.1
===== ======= ===== ===== ===== =======
(a) One gross (0.2 net) oil well and 4 gross (2.1 net) gas wells are
dual completions.
Drilling Activity
The following table summarizes the number of development wells drilled by
the Company during the years indicated. There were no exploratory wells drilled
during this three-year period. As of December 31, 1996, the Company was in the
process of drilling 20 gross (15.8 net) wells.
Year Ended December 31
-------------------------------------
1996 1995 1994
----------- ----------- -----------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Completed as-
Oil wells..... 92 45.5 71 17.3 51 4.5
Gas wells..... 70 38.1 24 16.8 30 24.4
Non-productive.. 4 2.7 2 1.1 1 1.0
---- ---- ---- ---- -- ----
Total (a)....... 166 86.3 97 35.2 82 29.9
==== ==== ==== ==== == ====
(a) Included in totals are 85 gross (10.4 net), 61 gross (3.2 net) and 50
gross (2.1 net) wells drilled on nonoperated interests in 1996, 1995
and 1994, respectively. Excluded from above totals are 21 gross (0.4
net) and 31 gross (0.6 net) carbon dioxide wells drilled on non-
operated interests in 1996 and 1995, respectively.
8
Acreage
The following table summarizes developed and undeveloped leasehold acreage
in which the Company owns a working interest as of December 31, 1996. Excluded
from this summary is acreage in which the Company's interest is limited to
royalty, overriding royalty and other similar interests.
Developed (a)(b) Undeveloped
--------------------- -----------------
Gross Net Gross Net
------- ------- ------ ------
Oklahoma.... 320,254 255,096 761 687
Texas....... 91,505 66,762 656 199
Kansas...... 75,018 64,805 2,960 817
New Mexico.. 59,495 24,970 6,118 3,192
Wyoming..... 40,685 21,712 - -
Other....... 9,455 6,855 - -
------- ------- ------ -----
Total....... 596,412 440,200 10,495 4,895
======= ======= ====== =====
(a) "Developed acres" are acres spaced or assignable to productive wells.
(b) Certain leasehold acreage in Oklahoma and Texas is subject to a 75% net
profits interest conveyed to the Royalty Trust.
Oil and Gas Sales Prices and Production Costs
The following table shows the average sales prices per Bbl of oil
(including condensate) and Mcf of gas (including natural gas liquids) produced
and the production costs and production and property taxes per barrel of oil
equivalent ("BOE," computed on an energy equivalent basis of 6 Mcf to 1 Bbl):
Year Ended December 31
----------------------------
1996 1995 1994
------ ------ ------
Sales prices:
Oil (per Bbl)........................ $21.38 $17.09 $15.38
Gas (per Mcf)........................ $ 1.97 $ 1.42 $ 1.81
Production costs per BOE............... $ 4.05 $ 4.26 $ 4.62
Production and property taxes per BOE.. $ 1.23 $ 1.04 $ 1.23
DELIVERY COMMITMENTS
The Company sells to a single purchaser approximately 10,000 Mcf of gas per
day through July 1998 and 11,650 Mcf of gas per day from August 1998 through
July 2005. The Company has also entered contracts to sell a total of 25,000 Mcf
of gas per day from January through March 1997. Deliveries under these
contracts are generally in Oklahoma, where the Company's production and reserves
are adequate to meet these sales commitments.
The Company has committed to sell between 1,460,000 and 1,825,000 Mcf of
gas annually to a cogeneration facility under a take-or-pay contract that
expires in September 2004. The Company generally purchases gas to fill this
commitment.
9
COMPETITION AND MARKETS
The Company faces competition from other oil and gas companies in all
aspects of its business, including acquisition of producing properties and oil
and gas leases, marketing of oil and gas, and obtaining goods, services and
labor. Many of its competitors have substantially larger financial and other
resources. Competition for property purchases is affected by available funds,
available information about the property and the Company's standards established
for minimum projected return on investment. Because gathering systems are the
only practical method for the intermediate transportation of natural gas,
competition for natural gas delivery is presented by other pipelines and gas
gathering systems. Competition is also presented by alternative fuel sources,
including heating oil and other fossil fuels. Because of the long-lived nature
of the Company's oil and gas reserves and management's expertise in exploiting
these reserves, management believes that it effectively competes in the market.
The Company's ability to market oil and gas depends on many factors beyond
its control, including the extent of domestic production and imports of oil and
gas, the proximity of the Company's gas production to pipelines, the available
capacity in such pipelines, the demand for oil and gas, the effects of weather,
and the effects of state and federal regulation. The Company cannot assure that
it will always be able to market all of its production or obtain favorable
prices. The Company, however, does not currently believe that the loss of any
of its oil or gas purchasers would have a material adverse effect on its
operations.
Decreases in oil and gas prices have had, and could have in the future, an
adverse effect on the Company's acquisition and development programs, proved
reserves, revenues, profitability, cash flow and dividends. See Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, "General - Product Prices."
FEDERAL AND STATE REGULATIONS
There have been, and continue to be, numerous federal and state laws and
regulations governing the oil and gas industry that are often changed in
response to the current political or economic environment. Compliance with this
regulatory burden is often difficult and costly and may carry substantial
penalties for noncompliance. The following are some specific regulations that
may affect the Company. The Company cannot predict the impact of these or
future legislative or regulatory initiatives.
Federal Regulation of Natural Gas
The interstate transportation and sale for resale of natural gas is subject
to federal regulation, including transportation rates charged and various other
matters, by the Federal Energy Regulatory Commission ("FERC"). The Company's
gathering system and 26-mile pipeline have been declared exempt from FERC
jurisdiction, and FERC has allowed the Company to provide gathering service on a
non-regulated basis. Federal wellhead price controls on all domestic gas were
terminated on January 1, 1993. The Company cannot predict the impact of
government regulation on any natural gas facilities.
In 1992, FERC issued Orders Nos. 636 and 636-A, requiring operators of
pipelines to unbundle transportation services from sales services and allow
customers to pay for only the services they require, regardless of whether the
customer purchases gas from such pipelines or from other suppliers. The United
States Court of Appeals upheld the unbundling provisions and other components of
FERC's orders but remanded several issues to FERC for further explanation. On
February 27, 1997, FERC issued Order No. 636-C, addressing the Court's concern.
FERC's orders remain subject to judicial review and may be changed as a result
of that review. Although FERC's regulations should generally facilitate the
transportation of gas produced from the Company's properties and the direct
access to end-user markets, the impact of these regulations on marketing the
Company's production or on its gas transportation business cannot be predicted.
The Company, however, does not believe that it will be affected any differently
than other natural gas producers and marketers with which it competes.
Federal Regulation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The net price received from the sale
of these products is affected by market transportation costs. A
10
significant part of the Company's oil production is transported by pipeline.
The Energy Policy Act of 1992 required the FERC to adopt a simplified ratemaking
methodology for interstate oil pipelines. In 1993 and 1994, the FERC issued
Order Nos. 561 and 561-A, adopting rules that establish new rate methods for
such pipelines. Under the new rules, effective January 1, 1995, interstate oil
pipelines can change rates based on an inflation index, though other rate
mechanisms may be used in specific circumstances. The United States Court of
Appeals upheld FERC's orders in 1996. The Company cannot predict the effect
these rules may have on the cost of moving oil to market.
State Regulation
The oil and gas operations of the Company are subject to various types of
regulation at the state and local levels. Such regulation includes requirements
for drilling permits, the method of developing new fields, the spacing and
operations of wells and waste prevention. The production rate may be regulated
and the maximum daily production allowable from oil and gas wells may be
established on a market demand or conservation basis. These regulations may
limit the Company's production from its wells and the number of wells or
locations the Company can drill.
The Company may become party to agreements relating to the construction or
operations of pipeline systems for the transportation of natural gas. To the
extent that such gas is produced, transported and consumed wholly within one
state, such operations may in certain instances be subject to the state's
administrative authority charged with regulating pipelines. The rates the
Company could charge for gas, the transportation of gas, and the construction
and operation of such pipelines would be subject to the regulations governing
such matters. Certain states are considering regulations with respect to
gathering systems. The Company cannot predict whether any rules will be adopted
or, if adopted, the effect these rules may have on the gathering systems owned
by the Company.
Federal, State or Indian Leases
The Company's operations on federal, state or Indian oil and gas leases are
subject to numerous restrictions, including nondiscrimination statutes. Such
operations must be conducted pursuant to certain on-site security regulations
and other permits and authorizations issued by the Bureau of Land Management,
Minerals Management Service and other agencies.
ENVIRONMENTAL REGULATIONS
Various federal, state and local laws regulating the discharge of materials
into the environment, or otherwise relating to the protection of the
environment, directly impact oil and gas exploration, development and production
operations, and consequently may impact the Company's operations and costs.
Management believes that the Company is in substantial compliance with
applicable environmental laws and regulations. To date, the Company has not
expended any material amounts to comply with such regulations, and management
does not currently anticipate that future compliance will have a materially
adverse effect on the consolidated financial position or results of operations
of the Company.
EMPLOYEES
The Company had 306 and 270 employees as of December 31, 1996 and 1995,
respectively. None of the Company's employees are represented by a union. The
Company considers its relations with its employees to be good.
EXECUTIVE OFFICERS OF THE COMPANY
The officers of the Company are elected by and serve until their successors
are elected by the Board of Directors.
BOB R. SIMPSON, 48, was a co-founder of the Company with Mr. Palko and has
been Chairman and Chief Executive Officer of the Company since July 1, 1996.
Prior thereto, Mr. Simpson served as Vice Chairman and Chief Executive Officer
or held similar positions with the Company since 1986. Mr. Simpson was Vice
President of Finance and Corporate Development (1979-1986) and Tax Manager
(1976-1979) of Southland Royalty Company.
11
STEFFEN E. PALKO, 46, was a co-founder of the Company with Mr. Simpson and
has been Vice Chairman and President or held similar positions with the Company
since 1986. Mr. Palko was Vice President - Reservoir Engineering (1984-1986) and
Manager of Reservoir Engineering (1982-1984) of Southland Royalty Company.
LOUIS G. BALDWIN, 47, has been Senior Vice President and Chief Financial
Officer or held similar positions with the Company since 1986. Mr. Baldwin was
Assistant Treasurer (1979-1986) and Financial Analyst (1976-1979) at Southland
Royalty Company.
KEITH A. HUTTON, 38, has been Senior Vice President - Asset Development or
held similar positions with the Company since 1987. From 1982 to 1987, Mr.
Hutton was a Reservoir Engineer with Sun Exploration & Production Company.
BENNIE G. KNIFFEN, 46, has been Senior Vice President and Controller or
held similar positions with the Company since 1986. From 1976 to 1986, Mr.
Kniffen held the position of Director of Auditing or similar positions with
Southland Royalty Company.
LARRY B. MCDONALD, 50, has been Senior Vice President - Operations or held
similar positions with the Company since 1990. Prior to that time, Mr. McDonald
owned and operated McDonald Energy, Inc. (1986-1990).
KENNETH F. STAAB, 40, has been Senior Vice President of Engineering or held
similar positions with the Company since 1986. Prior to that time, Mr. Staab was
a Reservoir Engineer with Southland Royalty Company (1982-1986).
THOMAS L. VAUGHN, 50, has been Senior Vice President - Operations or held
similar positions with the Company since 1988. From 1986 to 1988, Mr. Vaughn
owned and operated Vista Operating Company.
VAUGHN O. VENNERBERG II, 42, has been Senior Vice President - Land or held
similar positions with the Company since 1987. Prior to that time, Mr.
Vennerberg was Land Manager with Hutton Gas Operating Company (1986-1987).
ITEM 3. LEGAL PROCEEDINGS
In June 1996, Holshouser v. Cross Timbers Oil Company, a class action
lawsuit, was filed in the District Court of Major County, Oklahoma. The action
was filed on behalf of all parties who, at any time since June 1991, have
allegedly had production or other costs deducted by the Company from royalties
paid on gas produced in Oklahoma when the royalty is based upon a specified
percentage of the proceeds received from the gas sold. The plaintiff alleges
that such deductions are a breach of the Company's contractual obligations to
the class and is seeking to recover an unspecified amount of damages as a result
of the alleged breach. The plaintiff is also seeking a determination of the
Company's obligations to the plaintiff and the class regarding production or
other costs. The Company has responded that it has complied with all of its
contractual obligations and denied that the matter is appropriate for
determination as a class action. The parties are currently conducting discovery
on the class issues. Management believes it has strong defenses against this
claim and intends to vigorously defend the action. Management's estimate of the
potential liability from this claim has been accrued in the Company's financial
statements for the year ended December 31, 1996.
The Company and certain of its subsidiaries are involved in various other
lawsuits and certain governmental proceedings arising in the ordinary course of
business. Company management and legal counsel do not believe that the ultimate
resolution of these claims, including the class action lawsuit described above,
will have a material effect on the Company's financial position, liquidity or
operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of security holders during the fourth
quarter of 1996.
12
PART II
-------
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed on the New York Stock Exchange and
trades under the symbol "XTO." The following table sets forth quarterly high
and low sales prices and cash dividends declared for each quarter of 1996 and
1995, adjusted for the effect of the three-for-two stock split effected on March
19, 1997:
High Low Dividends
------- ------- ---------
1996
First Quarter..................... $12.500 $10.375 $.05
Second Quarter.................... 17.125 11.375 .05
Third Quarter..................... 19.125 12.750 .05
Fourth Quarter.................... 17.875 15.000 .05
1995
First Quarter..................... $10.000 $ 8.875 $.05
Second Quarter.................... 11.500 9.125 .05
Third Quarter..................... 10.625 8.875 .05
Fourth Quarter.................... 12.125 9.375 .05
The determination of the amount of future dividends, if any, to be declared
and paid is in the sole discretion of the Company's Board of Directors and will
depend on the Company's financial condition, earnings and funds from operations,
the level of its capital expenditures, dividend restrictions in its financing
agreements, its future business prospects and other matters as the Board of
Directors deems relevant. Furthermore, the Company's Credit Facility with banks
restricts the amount of dividends to 25% of cash flow from operations for the
latest four consecutive quarterly periods.
On February 18, 1997, the Board of Directors declared a dividend of $.055
per share payable on April 15, 1997 to shareholders of record March 31, 1997.
On March 1, 1997, the Company had 141 shareholders of record.
13
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial information for each of the
years, and as of year-end, in the five-year period ended December 31, 1996.
This information should be read in conjunction with Item 7, Management's
Discussion and Analysis, and the Consolidated Financial Statements at Item
14(a).
1996 1995 1994 1993 1992
--------- --------- -------- --------- -------
(in thousands except production, per share and per unit data)
CONSOLIDATED STATEMENT OF OPERATIONS DATA (a)
Revenues:.
Oil........................................... $ 75,013 $ 60,349 $ 53,324 $ 39,747 $ 31,921
Gas........................................... 73,402 40,543 38,389 34,649 31,994
Gas gathering, processing and marketing....... 12,032 7,091 4,274 3,717 3,943
Other......................................... 944 4,922 288 69 (502)(b)
--------- --------- -------- --------- --------
Total Revenues................................ $ 161,391 $ 112,905 $ 96,275 $ 78,182 $ 67,356
========= ========= ======== ========= ========
Earnings (loss) available to common stock..... $ 19,790 (10,538)(c) $ 3,048 (4,012)(d) $ 4,744
========= ========= ======== ========= ========
Per common share.............................. $ 0.74 $ (0.42)(c) $ 0.13 $ (0.18)(d) -(e)
========= ========= ======== ========= ========
Pro forma earnings (loss) (f)................. - - - $ (251) $ 3,233
========= ========= ======== ========= ========
Per common share/unit (f)..................... - - - $ (0.01) $ 0.17
========= ========= ======== ========= ========
Weighted average common shares/
units outstanding (g)......................... 26,609 25,382 23,886 21,788 18,582
========= ========= ======== ========= ========
Dividends/distributions declared
per common share/unit (h)..................... $ 0.20 $ 0.20 $ 0.20 $ 0.20 0.10
========= ========= ======== ========= ========
CONSOLIDATED STATEMENT OF CASH FLOWS DATA (a)
Operating cash flow (i)....................... $ 68,263 $ 40,439 $ 37,816 $ 27,925 $ 27,033
Cash provided (used) by:
Operating activities.......................... $ 59,694 $ 32,938 $ 42,293 $ 32,209 $ 26,240
Investing activities.......................... $(124,871) $(160,416) $(62,745) $(104,786) $ 13,916
Financing activities.......................... $ 66,902 $ 121,852 $ 26,232 $ 70,332 $(41,468)
CONSOLIDATED BALANCE SHEET DATA (a)
Property and equipment, net................... $ 450,561 $ 364,474 $244,555 $ 228,551 $149,484
Total assets.................................. $ 523,070 $ 402,675 $292,451 $ 258,019 $176,831
Long-term debt................................ $ 314,757 $ 238,475 $142,750 $ 111,750 $ 79,000
Owners' equity................................ $ 142,668 $ 130,700 $113,333 $ 115,168 $ 76,056
OPERATING DATA (a)
Average daily production:
Oil (Bbls)................................... 9,584 9,677 9,497 6,968 4,749
Gas (Mcf).................................... 101,845 78,408 58,182 51,260 51,205
Barrels of oil equivalent (BOE)............... 26,558 22,745 19,194 15,511 13,283
Average sales price:
Oil (per Bbl)................................ $ 21.38 $ 17.09 $ 15.38 $ 15.63 $ 18.37
Gas (per Mcf)................................ $ 1.97 $ 1.42 $ 1.81 $ 1.85 $ 1.71
Production costs (per BOE).................... $ 4.05 $ 4.26 $ 4.62 $ 5.16 $ 4.47
Production and property taxes (per BOE)....... $ 1.23 $ 1.04 $ 1.23 $ 1.19 $ 1.19
Proved reserves:
Oil (Bbls)................................... 42,440 39,988 33,581 21,082 16,666
Gas (Mcf).................................... 540,538 358,070 177,061 169,119 172,199
Barrels of oil equivalent (BOE)............... 132,530 99,666 63,091 49,269 45,366
OTHER DATA
Ratio of earnings to fixed charges (j)........ 2.6 (0.2)(k) 1.5 0.9 1.8
14
(a) Significant producing property acquisitions in 1993, 1994, 1995 and
1996 affect the comparability of year-to-year financial and operating
data.
(b) Includes a $2.4 million loss on sale of Royalty Trust Units in the
initial public offering for the Royalty Trust.
(c) Includes effect of a $20.3 million pre-tax, non-cash impairment charge
recorded upon adoption of Statement of Financial Accounting Standards
No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of.
(d) Includes effect of a one-time, non-cash accounting charge of $4 million
for net deferred income tax liabilities recorded upon the merger of the
Company with the former Partnership.
(e) Historical net income (loss) per common share is not provided for 1992
since the results of the former Partnership, as a nontaxable entity,
are not comparable to the Company.
(f) As if all former Partnership income was subject to corporate income
tax, exclusive of the charge in (d) above.
(g) Adjusted for the effect of the three-for-two stock split affected on
March 19, 1997.
(h) Excludes non-recurring distributions of the former Partnership.
(i) Defined as cash provided by operating activities before changes in
working capital.
(j) For purposes of calculating this ratio, earnings include income (loss)
from continuing operations before income tax and fixed charges. Fixed
charges include interest expense, the portion of rentals (calculated as
one-third) considered to be representative of the interest factor and
preferred stock dividends.
(k) Includes effect of the charge in (c) above. Excluding the effect of
this charge, the ratio of earnings to fixed charges is 1.3.
15
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
GENERAL
Cross Timbers Oil Company ("the Company") was organized in October 1990 to
ultimately acquire the business and properties of predecessor entities that were
created from 1986 through 1989. The Company completed its initial public
offering of common stock in May 1993.
The Company follows the successful efforts method of accounting (see Note 1
to Consolidated Financial Statements). As of October 1, 1995, the Company
adopted SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of, recording a pre-tax, non-cash impairment
charge of $20.3 million. The Company has implemented the disclosure provisions
of SFAS No. 123, Accounting for Stock-Based Compensation, but continues to
record compensation of stock-based awards using Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees.
In addition to the adoption of accounting principles described above, the
following events affect the comparative results of operations and/or financial
condition for the years ended December 31, 1996, 1995 and 1994, and/or may
impact future operations and financial condition. Throughout Management's
Discussion and Analysis of Financial Condition and Results of Operations,
references to barrels of oil equivalent ("BOE") refer to quantities of
production for the indicated period (with gas quantities converted to barrels on
an energy equivalent ratio of six Mcf to one barrel).
Three-for-Two Stock Split. On March 19, 1997, the Company effected a three-for-
two stock split for common stockholders of record on March 12, 1997. All per
share amounts have been restated to reflect the stock split on a retroactive
basis.
1996 Acquisitions. During 1996, the Company acquired predominantly gas-producing
properties for a total cost of $110 million. The Enserch Acquisition, the
largest of these acquisitions, closed in July 1996 at a cost of $39.4 million
and primarily consisted of operated interests in the Green River Basin of
southwestern Wyoming. In November 1996, the Company acquired additional
interests in the Fontenelle Unit, the most significant property included in the
Enserch Acquisition, at a cost of $12.5 million. In December 1996, the Company
acquired primarily operated interests in gas-producing properties in the Ozona
area of the Permian Basin of West Texas for $28 million. From July through
December 1996, the Company acquired 16% of the publicly traded outstanding units
of beneficial interest in Cross Timbers Royalty Trust at a total cost of $12.8
million. These 1996 acquisitions were primarily funded by bank borrowings (see
"Liquidity and Capital Resources- Financing" below). See Note 9 to Consolidated
Financial Statements.
1995 Acquisitions. During 1995, the Company acquired predominantly gas-producing
properties for a total cost of $131 million, and a gas processing plant and
gathering facility for $29 million. The Santa Fe Acquisition, the largest of
these acquisitions, closed on August 1, 1995 and consisted of mostly operated
properties and related facilities in the Hugoton Field of Kansas and Oklahoma.
The 1995 acquisitions were primarily funded by bank borrowings and proceeds from
the 1995 common stock offering and asset sales. See Note 9 to Consolidated
Financial Statements.
January 1994 Acquisitions. In January 1994, the Company acquired an additional
interest in the Prentice Northeast Unit and certain other West Texas oil-
producing properties for $22.9 million. These acquisitions were primarily
financed by bank borrowings.
1996, 1995 and 1994 Development Programs. During 1996, the Company drilled 48
oil wells and 52 gas wells and completed 125 recompletions and workovers. In
1995, the Company drilled 40 wells and performed 61 recompletions and workovers.
In 1994, the Company drilled 40 wells and implemented 67 workovers. During 1996
and 1995, oil development was concentrated in the Prentice Northeast Unit of
West Texas. Gas development focused on Major County, Oklahoma throughout this
three-year period. Fourth quarter 1996 development drilling also included the
Fontenelle Unit of southwestern Wyoming. The Company's exploratory expenditures
were not significant during these years.
16
1997 Development Program. The Company has budgeted 173 wells to be drilled in
its 1997 development program including 114 gas and 59 oil, and plans 80
workover/recompletion activities. Natural gas development will be concentrated
in the Fontenelle Unit in southwestern Wyoming, the Ozona area in West Texas and
in Major County, Oklahoma. Oil drilling will continue to be focused in the
Company's largest oil-producing property, the Prentice Northeast Unit of West
Texas, as well as in the University Block 9 Field, where the Company increased
its working interest to 100% in January 1997 at a cost of $12.5 million.
Approximately 10% to 20% of the 1997 budget will be allocated to higher-risk
projects, including step-out development wells and exploratory drilling. Much of
the higher-risk activity will focus on the Tubb Formation in Lea County, New
Mexico, where the Company plans to recomplete up to 22 wells and drill up to 20
wells.
1996 Preferred Stock Exchange. In September 1996, pursuant to the Company's
exchange offer, a total of 1,324,111 shares of common stock were exchanged for
1,138,729 shares of Series A convertible preferred stock. See Note 5 to
Consolidated Financial Statements.
1996 and 1997 Conversion of Subordinated Notes. During November and December
1996, $27.7 million principal of the Company's 5 1/4% convertible subordinated
notes was converted by noteholders into 1,198,454 shares of common stock. In
January 1997, the remaining principal of $29.7 million was converted by
noteholders into 1,285,495 shares of common stock.
1995 Common Stock Offering. In August 1995, the Company sold 2,250,000 shares of
common stock. The net proceeds of $29.5 million from this offering were used to
partially fund the Santa Fe Acquisition.
Treasury Stock. As part of its 1996 strategic acquisition plan, the Company
purchased 1.3 million shares of common stock at a total cost of $30.7 million.
An additional 483,000 shares have been purchased through March 10, 1997 at a
cost of $12.9 million. These purchases were primarily funded by bank borrowings.
Investment in Equity Securities. During 1996, the Company acquired less than 5%
of a publicly traded independent oil and gas producer at a total cost of $16.1
million. During 1994, the Company acquired 6.6% of the common stock of Plains
Petroleum Company, a publicly traded independent oil and gas producer, at a
total cost of $15.2 million. The Company sold its investment in Plains Petroleum
in 1995 at a gain of $1.6 million.
Property Sales. During 1996 and 1995, sales of producing properties resulted in
net gains of $500,000 and $3 million, respectively. During 1994, the Company
recorded a net loss on property sales of $100,000.
Stock Incentive Compensation. Stock incentive compensation includes stock
appreciation right ("SAR") compensation and performance share compensation, and
is the result of these stock awards and subsequent increases in the Company's
stock price. See Note 8 to Consolidated Financial Statements. During 1996, stock
incentive compensation totaled $6.2 million, which included SAR compensation of
$3.7 million (cash payments of $7.1 million, partially offset by prior accruals)
and non-cash performance share compensation of $2.5 million. During 1995, stock
incentive compensation totaled $5.1 million, which included SAR compensation of
$2.3 million (cash payments of $800,000) and non-cash performance share
compensation of $2.8 million. In 1994, SAR compensation was $700,000 (cash
payments of $10,000). Exercises and forfeitures under the 1991 Stock Incentive
Plan have reduced outstanding stock incentive units (including SARs) from
447,000 at year-end 1994 to 371,000 at year-end 1995 and 23,000 (34,000 after
the three-for-two stock split) at year-end 1996.
Extraordinary Item. During 1995, the Company recognized an extraordinary gain of
$700,000 (net of income tax of $300,000) as a result of the purchase and early
retirement of $8.3 million principal amount of the Company's 5 1/4% convertible
subordinated notes. During 1996, the Company redeemed, purchased and retired a
total of $9 million principal amount of the notes at a loss before income tax of
$400,000. This loss was not presented as an extraordinary item because it was
not material to 1996 earnings. These purchases were primarily funded by bank
borrowings. See Note 2 to Consolidated Financial Statements.
Product Prices. Oil and gas prices are affected not only by supply and demand
factors, but are also subject to substantial seasonal, political and other
fluctuations that are generally beyond the ability of the Company to control or
predict.
17
Crude oil prices are generally affected by global politics and supply,
particularly among OPEC members. Despite the anticipation of and eventual
resumption of Iraqi exports, 1996 oil prices reached their highest levels since
the Persian Gulf War in 1990. The average posted price per barrel of West Texas
Intermediate ("WTI") oil, a benchmark crude, was $20.45, $16.77 and $15.63 in
1996, 1995 and 1994, respectively. Posted WTI prices fluctuated in 1996 between
a monthly average low of $17.21 and high of $23.39. The average posted WTI price
for January and February 1997 was $21.98. Improvement in oil prices from 1995 to
1996 have generally been attributed to global economic growth and diminished
excess production capacity. Crude oil prices in 1997 will continue to largely
depend on these factors. Based on 1996 production, the Company estimates that a
$1.00 per barrel increase or decrease in the average oil sales price would
result in approximately a $3 million change in 1997 annual income before income
tax.
Natural gas prices are generally influenced by national and regional supply
and demand, which is often dependent upon the weather. Specific gas prices are
also based on the location of production, pipeline capacity, gathering charges
and the energy content of the gas. Throughout most of 1995, gas prices were
relatively weak, primarily because of unseasonably warm weather. Gas prices
began to increase in fourth quarter 1995 when low storage levels and colder than
expected weather began to escalate prices. During 1996, U.S. gas consumption
reached record highs, and prices were at their highest level since 1985. While
domestic demand continues to grow, gas prices in 1997 will largely depend on the
severity of winter weather, gas storage levels and price competition from other
energy sources. Based on 1996 production, the Company estimates that a $0.10 per
Mcf increase or decrease in the average gas sales price would result in
approximately a $3 million change in 1997 annual income before income tax.
RESULTS OF OPERATIONS
1996 COMPARED TO 1995
Earnings available to common stock for 1996 were $19.8 million as compared
to a net loss of $10.5 million for 1995. Significantly improved earnings are the
result of higher oil and gas prices and increased gas production from the 1995
and 1996 acquisitions and development programs. Additionally, 1995 results
included a $20.3 million, pre-tax, non-cash impairment charge recorded upon
adoption of SFAS 121. Results for 1996 and 1995 included the effects of stock
incentive compensation of $6.2 million and $5.1 million, respectively. Also
included in 1995 results were net gains on sale of properties and equity
securities of $3 million and $1.6 million, respectively, and a $700,000
extraordinary gain on the Company's purchase and retirement of a portion of its
convertible subordinated notes. Earnings for 1996 have been reduced by dividends
of $500,000 on preferred stock that was issued in September 1996.
Revenues for 1996 were $161.4 million, or 43% above 1995 revenues of $112.9
million. Oil revenue increased $14.7 million or 24% primarily because of a 25%
increase in oil prices from an average of $17.09 in 1995 to $21.38 in 1996 (see
"General- Product Prices" above). The Company's 1996 average oil price was above
the average WTI price of $20.45 because of improved oil marketing margins. Oil
production declined 1% from 1995 to 1996 primarily because of property sales and
natural decline, largely offset by the effects of the 1995 and 1996 acquisitions
and development programs.
Gas revenue increased $32.9 million or 81% because of a 39% price increase
(see "General- Product Prices" above) combined with a 30% increase in
production. Increased gas production was attributable to the 1995 and 1996
acquisitions and development programs.
Gas gathering, processing and marketing revenues increased $4.9 million
primarily because of revenues from the gas processing plant and gathering
facility acquired as part of the Santa Fe Acquisition on August 1, 1995. Other
revenues decreased $4 million primarily because of net gains on sale of property
and equity securities in 1995.
Expenses for 1996 totaled $130.4 million as compared with total 1995
expenses of $129.9 million. Expenses for 1995 included the $20.3 million
impairment charge recorded upon adoption of SFAS No. 121 in October 1995. All
expenses other than impairment increased in 1996 primarily because of the 1995
and 1996 acquisitions.
18
Production expenses increased $4 million or 11%. Per BOE, production
expense decreased from $4.26 to $4.05. This decrease is primarily because the
1995 and 1996 acquisitions were predominantly gas-producing properties that
generally have lower production costs per BOE.
Taxes on production and property increased 38% or $3.3 million because of
increased oil and gas revenues. Taxes on production and property per BOE only
increased 18% from $1.04 to $1.23 because of property tax reductions on
properties acquired before 1995 that largely offset property taxes related to
the 1995 and 1996 acquisitions.
Depreciation, depletion and amortization ("DD&A") increased $1 million, or
3%, primarily because of the 1995 and 1996 acquisitions and development
programs. On a BOE basis, DD&A decreased from $4.44 in 1995 to $3.89 in 1996.
Decreased DD&A per BOE is the result of increased proved reserve estimates at
January 1, 1996, reduced depletable costs resulting from the SFAS 121 provision
recorded in fourth quarter 1995, and the sale and operating leaseback of the
Tyrone gas processing plant and related gathering system.
General and administrative expense increased $3.3 million, or 25%, because
of Company growth and increased stock incentive compensation. Excluding stock
incentive compensation, general and administrative expense per BOE was $1.04 in
1996 as compared to $0.97 in 1995.
Gas gathering and processing expense increased from $2.5 million in 1995 to
$6.9 million in 1996. This increase was primarily because of rental expense
related to the Tyrone plant and gathering system lease that began in March 1996.
This increase offsets related decreases in DD&A and interest.
Interest expense increased $4.5 million or 36% primarily because of
increased debt to partially fund the 1995 and 1996 acquisitions and purchases of
treasury stock and equity securities. Weighted average principal outstanding
during 1996 was $259 million at an average interest rate of 6.4% compared with
weighted average principal of $195.1 million at 6.2% for 1995. Interest expense
per BOE increased from $1.51 in 1995 to $1.76 in 1996 primarily because of
financing expenditures for other than oil and gas producing properties with bank
and other short-term borrowings.
1995 COMPARED TO 1994
Net loss for 1995 was $10.5 million as compared to net income of $3 million
for 1994. The loss for 1995 included a $20.3 million pre-tax, non-cash
impairment charge recorded upon adoption of SFAS No. 121, and a pre-tax charge
of $5.1 million for predominantly non-cash stock incentive compensation. Also
included in 1995 results were net gains on sale of properties and equity
securities of $3 million and $1.6 million, respectively, and a $700,000
extraordinary gain on the Company's purchase and retirement of a portion of its
convertible subordinated notes.
Revenues for 1995 were $112.9 million, or 17% above 1994 revenues of $96.3
million. Oil revenue increased $7 million or 13% primarily because of an 11%
increase in oil prices from an average of $15.38 in 1994 to $17.09 in 1995. The
Company's 1995 average oil price was above the average WTI price of $16.77
because of improved oil marketing margins. Oil production increased 2% from 1994
as a result of the 1995 acquisitions, partially offset by reduced production
from natural decline and property sales.
Gas revenue increased $2.2 million or 6% because of a 35% increase in
production, attributable to the 1995 acquisitions and the 1994 and 1995
development programs. The effects of increased production were largely offset by
a 22% decline in average gas prices. Part of the decline in the Company's
average gas price is because of a lower energy content and higher transportation
differential for production from the Hugoton Field. Additionally, the 1994
average price was supported by sales of 25,000 Mcf per day under contract at
$2.00 per Mcf during the last six months of the year.
Gas gathering, processing and marketing revenues increased $2.8 million
primarily because of revenues from the gas processing plant and gathering
facility acquired as part of the Santa Fe Acquisition on August 1, 1995. Other
revenues increased $4.6 million because of net gains of $3 million from property
sales and a gain of $1.6 million from sale of equity securities.
19
Expenses for 1995 totaled $129.9 million, a $38.4 million or 42% increase
from total 1994 expenses of $91.5 million. Included in 1995 expenses is the
$20.3 million impairment charge recorded upon adoption of SFAS No. 121 in
October 1995. Other expense increases were generally attributable to the 1995
acquisitions.
Production expenses increased $3 million or 9%. Per BOE, production expense
decreased from $4.62 to $4.26. This decrease is generally because the 1995
acquisitions were predominantly gas-producing properties and therefore have
lower production costs per BOE.
Taxes on production and property increased only 1% or $100,000. Increased
taxes from the 1995 acquisitions were almost completely offset by decreased
property taxes on properties acquired before 1995, resulting in a decrease in
taxes on production and property per BOE from $1.23 to $1.04.
DD&A increased $5.2 million, or 16%, primarily because of the 1995
acquisitions, the largest of which closed on August 1. On a BOE basis, DD&A
decreased from $4.53 in 1994 to $4.44 in 1995.
General and administrative expense increased $4.6 million, or 54%,
primarily because of increased stock incentive compensation of $4.4 million.
Excluding stock incentive compensation, general and administrative expense per
BOE was $0.97 in 1995 or 13% below $1.11 in 1994.
Gas gathering and processing expense increased by $900,000 or 54% from 1994
to 1995. This increase was primarily because of operating expenses related to
the Tyrone gas processing and gathering facility acquired August 1, 1995.
Interest expense increased $4.5 million or 56% because of increased debt to
partially fund the 1995 acquisitions and an increase in interest rates. Weighted
average principal outstanding during 1995 was $195.1 million at an average
interest rate of 6.2% compared with weighted average principal of $135.3 million
at 5.5% for 1994. Interest expense per BOE was $1.51 in 1995 and $1.15 in 1994.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of liquidity are cash flow from operating
activities, public offerings of equity and debt, and bank debt. The Company's
cash requirements, other than for operations, are generally for the acquisition
and development of oil and gas properties, and debt and dividend payments. The
Company believes that its sources of liquidity are adequate to fund its cash
requirements during 1997.
Cash provided by operating activities was $59.7 million in 1996, compared
to $32.9 million in 1995 and $42.3 million in 1994. The fluctuation from 1995 to
1996 was primarily because of increased oil and gas prices and gas production,
partially offset by stock incentive compensation payments that increased $6.3
million, while the fluctuation from 1994 to 1995 was almost entirely due to
timing of realization of accounts receivable, inventory and payables. Before
changes in working capital, cash flow from operations was $68.3 million, $40.4
million and $37.8 million in 1996, 1995 and 1994, respectively.
The January 1994, 1995 and 1996 acquisitions were primarily financed by
proceeds from long-term debt borrowings. The 1995 acquisitions were also
partially funded by proceeds from public offerings of common stock. Development
expenditures and dividend payments have generally been funded by cash flow from
operations.
Financial Condition
Total assets increased from $403 million at December 31, 1995 to $523
million at December 31, 1996, primarily because of the 1996 acquisitions. As of
December 31, 1996, total capitalization of the Company was $457 million, of
which 69% was long-term debt. This compares with capitalization of $369 million
at December 31, 1995, of which 65% was long-term debt. The increase in the debt-
to-capitalization ratio from year-end 1995 to 1996 is because of increased
borrowings under the Company's loan agreement to fund the 1996 acquisitions and
other capital expenditures (see "Financing" below). After considering the effect
of the January 1997 conversion of subordinated notes, the pro forma debt-to-
capitalization ratio at December 31, 1996 was 62%.
20
Working Capital
The Company generally uses available cash to reduce bank debt and,
therefore, does not maintain large cash and cash equivalent balances. Short-term
liquidity needs are satisfied by bank commitments under the loan agreement (see
"Financing" below). Because of this, and since the Company's principal source of
operating cash flows (i.e., proved reserves to be produced in the following
year) cannot be reported as working capital, the Company often has low or
negative working capital.
Financing
Total borrowing commitments from commercial banks under the Revolving
Credit Agreement ("loan agreement") were $300 million at December 31, 1996. The
loan agreement provides for a revolving facility with scheduled reductions of
borrowing commitment that generally occur each June 30 and December 31. As of
December 31, 1996, borrowing commitments were scheduled to be reduced to $285
million on December 31, 1997. In connection with a property acquisition in
January 1997, borrowing commitments were increased to $306 million, which will
be reduced to $291 million on December 31, 1997. Borrowings under the loan
agreement mature on June 30, 2002, but may be prepaid at any time without
penalty. The Company has periodically renegotiated its loan agreement to
increase borrowing commitments and extend the revolving facility; however, there
is no assurance that the Company will continue to do so in the future.
Loan capacity under the loan agreement is redetermined annually using
present value and cash flow parameters based on year-end estimated oil and gas
reserves. If the redetermined loan capacity is less than total borrowings
commitments, then such commitments will be reduced by the difference. If
borrowings exceed the redetermined capacity, the Company must reduce borrowings
to a level equal to the redetermined capacity within a specified period.
During 1995, the Company purchased and retired $8.3 million principal
amount of its 5 1/4% convertible subordinated notes, resulting in an
extraordinary gain of $700,000. During 1996, the Company redeemed, purchased and
retired a total of $9 million principal amount of the notes at a loss of
$430,000. Note purchases were primarily funded by bank borrowings under the loan
agreement. In November and December 1996, principal of $27.7 million was
converted at the option of noteholders into 1,198,454 shares of common stock. In
January 1997, principal of $29.7 million was converted into 1,285,495 shares of
common stock. As of January 21, 1997, no notes remain outstanding.
In August 1995, the Company sold 2.3 million shares of common stock for net
proceeds of $29.5 million that were used to partially fund the Santa Fe
Acquisition.
In September 1996, pursuant to the Company's exchange offer, a total of
1,324,111 shares of common stock were exchanged for 1,138,729 shares of Series A
convertible preferred stock.
On March 12, 1997, the Company announced that it intends to offer $165
million of senior subordinated notes due 2007. The offering will be made by
means of an offering memorandum to qualified institutional buyers pursuant to
Rule 144A of the Securities Act of 1933. Net proceeds from the sale of notes
will be used to reduce bank borrowings under the loan agreement.
Capital Expenditures
In May 1996, the Company announced its plan to make strategic acquisitions
totaling $120 million over the following 18 months, including additional
interests in and around the Company's operations, as well as purchases of up to
two million shares of the Company's common stock. This goal excludes the
previously announced Enserch Acquisition. Since that date and through December
1996, the Company purchased producing properties totaling approximately $66
million (excluding the Enserch Acquisition of $39.4 million) and 1.3 million
treasury shares at a total cost of $30.7 million. These purchases were primarily
funded by bank debt. Producing property acquisitions include the purchase of 16%
of the outstanding beneficial units ("Units") of Cross Timbers Royalty Trust at
a total cost of $12.8 million. After the Company completed its program to
purchase one million Units in January 1997, the Board of Directors authorized
the of purchase up to one million additional Units.
21
The Company continues to pursue acquisitions that meet its criteria,
although there are no assurances that such properties will be available. The
Company plans to fund future acquisitions through a combination of cash flow
from operations and bank borrowings; proceeds from public equity and debt
transactions may also be utilized. The Company's base acquisition budget for
1997 is $50 million. If attractive acquisition opportunities arise during 1997,
the Company could significantly exceed its base acquisition budget.
In 1996, capitalized expenditures for exploitation and development totaled
$32.3 million, compared to the budget of $40 million. Exploitation and
development costs incurred for 1996 totaled $44.8 million. Exploration expenses
in 1996 totaled $280,000. The Company has budgeted $70 million for the 1997
development program. As it has done historically, the Company expects to fund
the 1997 development program from cash flow from operations. Since there are no
material long-term commitments associated with this budget, the Company has the
flexibility to adjust its actual development expenditures in response to changes
in product prices, industry conditions, and the effects of the Company's
acquisition and development programs.
A portion of the Company's existing properties are operated by third
parties which control the timing and amount of expenditures required to exploit
the Company's interests in such properties. Therefore, the Company can give no
assurances regarding the timing or amount of such expenditures.
To date, the Company's expenditures to comply with environmental or safety
regulations have not been significant, and the Company currently does not expect
such expenditures to be significant during 1997. However, developments such as
new regulations, enforcement policies or claims for damages could result in
significant future costs.
In March 1996, the Company sold its Tyrone gas processing plant and related
gathering system for $28 million and entered an agreement to lease the facility
from the buyers for an initial term of eight years at annual rentals of $4
million, and with fixed renewal options for an additional 13 years. In November
1996, the Company sold its gathering system in Major County, Oklahoma for $8
million and entered an agreement to lease the facility from the buyers for an
initial term of eight years at annual rental of $1.6 million and with renewal
options for an additional 10 years. Proceeds of these sales were used to reduce
borrowings under the loan agreement. See Note 4 to Consolidated Financial
Statements.
Dividends
Since the Company's inception, the Board of Directors has declared
quarterly dividends of $0.075 per common share ($0.05 per share on a post-split
basis). In February 1997, the Board of Directors increased the quarterly
dividend 10% to $0.055 per share on a post-split basis, or $6.1 million
annually. Continuance of dividends is dependent upon available cash flow, as
well as other factors. In addition, the Company's loan agreement restricts the
amount of common stock dividends to 25% of operating cash flow for the last four
quarters.
Cumulative dividends on Series A convertible preferred stock are paid
quarterly, when declared by the Board of Directors, based on an annual rate of
$1.5625 per share, or $1.8 million annually.
PRODUCTION IMBALANCES
The Company has gas production imbalance positions that are the result of
partial interest owners selling more or less than their proportionate share of
gas on jointly owned wells. Imbalances are generally settled by disproportionate
gas sales over the remaining life of the well or by cash payment by the
overproduced party to the underproduced party. The Company uses the entitlement
method of accounting for natural gas sales. At December 31, 1996, the Company's
consolidated balance sheet includes a net receivable of $4 million for a net
underproduced balancing position of 821,000 Mcf of natural gas and 6,824,000 Mcf
of carbon dioxide. Production imbalances do not have, and are not expected to
have, a significant impact on the Company's liquidity or operations.
22
DERIVATIVES
The Company uses derivatives on a limited basis to hedge interest rate and
product price risks, as opposed to their use for trading purposes. To reduce
variable interest rate exposure on debt, the Company had entered into a series
of interest rate swap agreements, the last of which expired September 1996. The
Company had no other significant derivative transactions or balances from 1994
to 1996.
FORWARD-LOOKING STATEMENTS
Certain statements included in this Item 7, as well as statements included
in Items 1 and 2 of this report, relating to future development expenditures,
strategic acquisitions, proved reserves and other matters of anticipated
financial and operating performance constitute forward-looking statements. These
statements are based on assumptions concerning oil and gas prices, drilling
results and production, and administrative and other costs that management
believes are reasonable based on currently available information. However,
management's assumptions and the Company's future performance are both subject
to a wide range of risks, uncertainties and other factors that could cause the
Company's actual results and experience to differ materially from the
anticipated results or other expectations expressed in the Company's forward-
looking statements. Risks and uncertainties that may affect the operations and
results of the Company's performance include, but are not limited to, commodity
price fluctuations, competitive energy supplies, market demand, drilling risks,
governmental regulations and uncertainties of proved reserve estimates. In
addition, potential producing property acquisitions that meet the Company's
profitability, size, and geographic and other criteria may not be available on
acceptable economic terms.
23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following financial statements and supplementary information are
included under Item 14(a):
Page
----
Consolidated Balance Sheets......................... 26
Consolidated Statements of Operations............... 27
Consolidated Statements of Cash Flows............... 28
Consolidated Statements of Stockholders' Equity..... 29
Notes to Consolidated Financial Statements.......... 30
Report of Independent Public Accountants............ 46
Selected Quarterly Financial Data
(Note 10 to Consolidated Financial Statements)..... 42
Information about Oil and Gas Producing Activities
(Note 11 to Consolidated Financial Statements)..... 43
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
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Except for the portion of Item 10 relating to Executive Officers of
the Registrant which is included in Part I of this Report, the information
called for by Items 10 through 13 is incorporated by reference from the
Company's Notice of Annual Meeting and Proxy Statement to be filed with the
Securities and Exchange Commission no later than April 30, 1997.
24
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report:
Page
----
1. Financial Statements:
Consolidated Balance Sheets at December 31, 1996 and 1995.. 26
Consolidated Statements of Operations for the years ended
December 31, 1996, 1995 and 1994......................... 27
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994......................... 28
Consolidated Statements of Stockholders' Equity for the
years ended December 31, 1996, 1995 and 1994............. 29
Report of Independent Public Accountants................... 46
2. Financial Statement Schedules:
All financial schedules have been omitted because they are not
applicable or the required information is presented in the
financial statements or the notes to financial statements.
3. Exhibits:
See Index to Exhibits at page 48 for a description of the
exhibits filed as a part of this report.
(b) Reports on Form 8-K
The Company filed the following reports on Form 8-K during the
quarter ended December 31, 1995 and through March 19, 1997:
On December 13, 1996, the Company filed a report on Form 8-K
dated December 2, 1996 regarding the results of its redemption
notice for one-half of its 5 1/4% convertible subordinated notes,
and the closing of two previously announced acquisitions of
natural gas-producing properties in the Permian Basin of West
Texas and Green River Basin of Wyoming at a total cost of $40.5
million.
On January 3, 1997, the Company filed a report on Form 8-K dated
December 20, 1996 regarding issuance of its redemption notice for
its remaining 5 1/4% convertible subordinated notes.
On February 4, 1997, the Company filed a report on Form 8-K dated
January 15, 1997 regarding completion of its previously announced
program to purchase one million units of beneficial interest
("Units") in Cross Timber Royalty Trust and its plans to purchase
up to one million additional Units, results of its redemption
notice for its remaining 5 1/4% convertible subordinated notes,
and preliminary estimates of fourth quarter 1996 earnings and
cash flow.
25
CROSS TIMBERS OIL COMPANY
CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------
(in thousands) DECEMBER 31
-----------------------
1996 1995
---------- ---------
ASSETS
Current Assets:
Cash and cash equivalents........................... $ 3,937 $ 2,212
Accounts receivable, net (Note 6)................... 44,320 27,582
Deferred income tax benefit (Note 3)................ 558 1,661
Other current assets................................ 2,965 1,282
--------- ---------
Total Current Assets............................... 51,780 32,737
--------- ---------
Property and Equipment, at cost --
successful efforts method (Notes 1 and 2):
Producing properties................................ 639,990 493,800
Undeveloped properties.............................. 2,493 1,939
Other property and equipment........................ 16,470 48,064
--------- ---------
Total Property and Equipment...................... 658,953 543,803
Accumulated depreciation, depletion and
amortization..................................... (208,392) (179,329)
--------- ---------
Net Property and Equipment........................ 450,561 364,474
--------- ---------
Investment in Equity Securities, at market value...... 16,714 -
--------- ---------
Other Assets.......................................... 4,015 5,464
--------- ---------
TOTAL ASSETS.......................................... $ 523,070 $ 402,675
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............ $ 45,729 $ 25,314
Payable to Royalty Trust............................ 2,770 1,890
Accrued stock incentive compensation (Note 8)....... 483 3,881
Short-term debt (Note 2)............................ 3,000 -
--------- ---------
Total Current Liabilities.......................... 51,982 31,085
--------- ---------
Long-term Debt (Note 2)............................... 314,757 238,475
--------- ---------
Deferred Income Taxes Payable (Note 3)................ 10,323 2,382
--------- ---------
Other Long-term Liabilities (Note 4).................. 3,340 33
--------- ---------
Commitments and Contingencies (Note 4)
Stockholders' Equity (Note 5):
Series A convertible preferred stock
($.01 par value, 25,000,000 shares authorized,
1,138,729 issued, at liquidation value of $25)... 28,468 -
Common stock ($.01 par value, 100,000,000 shares
authorized, 28,209,976 and 18,415,257 shares
issued).......................................... 282 184
Additional paid-in capital.......................... 164,577 156,670
Treasury stock (2,578,781 and 30,516 shares)........ (40,219) (528)
Unrealized gain on investment in equity securities.. 638 -
Retained earnings (deficit)......................... (11,078) (25,626)
--------- ---------
Total Stockholders' Equity......................... 142,668 130,700
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY............ $ 523,070 $ 402,675
========= =========
See accompanying notes to consolidated financial statements.
26
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
- --------------------------------------------------------------------------------
(in thousands, except per share data)
YEAR ENDED DECEMBER 31
----------------------------
1996 1995 1994
-------- -------- -------
REVENUES
Oil............................................. $ 75,013 $ 60,349 $53,324
Gas............................................. 73,402 40,543 38,389
Gas gathering, processing and marketing......... 12,032 7,091 4,274
Other........................................... 944 4,922 288
-------- -------- -------
Total Revenues.................................. 161,391 112,905 96,275
-------- -------- -------
EXPENSES
Production...................................... 39,365 35,338 32,368
Taxes on production and property................ 11,944 8,646 8,586
Depreciation, depletion and amortization........ 37,858 36,892 31,709
Impairment (Note 1)............................. - 20,280 -
General and administrative (Note 8)............. 16,420 13,156 8,532
Gas gathering and processing.................... 6,905 2,528 1,646
Interest, net................................... 17,072 12,523 8,034
Trust development costs......................... 854 561 622
-------- -------- -------
Total Expenses.................................. 130,418 129,924 91,497
-------- -------- -------
INCOME (LOSS) BEFORE INCOME TAX
AND EXTRAORDINARY ITEM......................... 30,973 (17,019) 4,778
Income Tax Expense (Benefit) (Note 3)........... 10,669 (5,825) 1,730
-------- -------- -------
NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM..... 20,304 (11,194) 3,048
EXTRAORDINARY ITEM (Note 1)..................... - 656 -
-------- -------- -------
NET INCOME (LOSS)............................... 20,304 (10,538) 3,048
Preferred stock dividends....................... 514 - -
-------- -------- -------
EARNINGS (LOSS) AVAILABLE TO COMMON STOCK....... $ 19,790 $(10,538) $ 3,048
======== ======== =======
EARNINGS (LOSS) PER COMMON SHARE (Note 1)
Before extraordinary item...................... $ 0.74 $ (0.44) $ 0.13
======== ======== =======
After extraordinary item....................... $ 0.74 $ (0.42) $ 0.13
======== ======== =======
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
(Note 5)..................................... 26,609 25,382 23,886
======== ======== =======
See accompanying notes to consolidated financial statements.
27
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------
(in thousands)
(Note 7)
YEAR ENDED DECEMBER 31
-------------------------------
1996 1995 1994
--------- ---------- --------
OPERATING ACTIVITIES
Net income (loss).............................. $ 20,304 $ (10,538) $ 3,048
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion and amortization..... 37,858 36,892 31,709
Impairment................................... - 20,280 -
Performance share and restricted stock
compensation................................ 2,545 2,945 -
Accrued stock appreciation right
compensation................................ (3,398) 1,447 706
Deferred income tax.......................... 10,213 (6,023) 1,662
Loss (gain) from sale of properties
and equity securities....................... (576) (4,520) 122
Extraordinary item........................... - (656) -
Other non-cash items......................... 1,317 612 569
Changes in working capital (a)............... (8,569) (7,501) 4,477
--------- --------- --------
CASH PROVIDED BY OPERATING ACTIVITIES.......... 59,694 32,938 42,293
--------- --------- --------
INVESTING ACTIVITIES
Sale of equity securities...................... 402 16,923 -
Investment in equity securities................ (16,093) (123) (15,239)
Sale of property and equipment................. 37,388 13,095 2,102
Property acquisitions.......................... (109,535) (131,342) (28,100)
Development costs.............................. (32,291) (19,296) (19,550)
Gas plant, gathering and other additions....... (4,742) (39,673) (1,958)
--------- --------- --------
CASH USED BY INVESTING ACTIVITIES.............. (124,871) (160,416) (62,745)
--------- --------- --------
FINANCING ACTIVITIES
Proceeds from long-term debt................... 188,000 193,000 57,000
Payments on long-term debt..................... (81,200) (96,040) (26,000)
Proceeds from sale of common stock, net........ - 29,450 -
Dividends...................................... (5,339) (4,951) (4,777)
Proceeds on exercise of stock options.......... 904 744 20
Preferred stock exchange offer costs........... (540) - -
Purchase of treasury stock..................... (34,923) (351) (11)
--------- --------- --------
CASH PROVIDED BY FINANCING ACTIVITIES.......... 66,902 121,852 26,232
--------- --------- --------
INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS.............................. 1,725 (5,626) 5,780
CASH AND CASH EQUIVALENTS, JANUARY 1........... 2,212 7,838 2,058
--------- --------- --------
CASH AND CASH EQUIVALENTS, DECEMBER 31......... $ 3,937 $ 2,212 $ 7,838
========= ========= ========
(a) CHANGES IN WORKING CAPITAL
Accounts receivable......................... $ (16,999) $ (9,365) $ 2,186
Other current assets........................ (1,683) 963 (432)
Accounts payable, accrued liabilities
and payable to Royalty Trust............... 10,113 901 2,723
--------- --------- --------
DECREASE (INCREASE) IN WORKING CAPITAL....... $ (8,569) $ (7,501) $ 4,477
========= ========= ========
See accompanying notes to consolidated financial statements.
28
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- --------------------------------------------------------------------------------
(in thousands)
(Note 5)
SHARES STOCKHOLDERS' EQUITY
------------------------------ ---------------------------------------------------------------
COMMON STOCK
------------------ ADDITIONAL RETAINED
PREFERRED IN PREFERRED COMMON PAID-IN TREASURY EARNINGS
STOCK ISSUED TREASURY STOCK STOCK CAPITAL STOCK (DEFICIT)
------ ------ -------- --------- ------ ---------- -------- ---------
BALANCES, DECEMBER 31, 1993..... - 15,924 - $ - $159 $123,233 $ - $ (8,224)
Stock option exercises.......... - 2 1 - 20 (11) -
Common stock dividends..........
($0.30 per share)............ - - - - - - - (4,777)
Net income...................... - - - - - - - 3,048
------ ------ ------ ------- ---- -------- -------- --------
BALANCES, DECEMBER 31, 1994..... - 15,926 1 - 159 123,253 (11) (9,953)
Sale of common stock............ - 2,250 - - 22 29,428 - -
Issuance of performance shares.. - 164 - - 1 2,944 - -
Stock option exercises.......... - 75 30 - 2 1,045 (517) -
Common stock dividends..........
($0.30 per share)............ - - - - - - - (5,135)
Net income (loss)............... - - - - - - - (10,538)
------ ------ ------ ------- ---- -------- -------- --------
BALANCES, DECEMBER 31, 1995..... - 18,415 31 - 184 156,670 (528) (25,626)
Issuance/vesting of.............
performance shares........... - 75 47 - 1 2,674 (1,038) -
Stock option exercises.......... - 443 341 - 4 7,195 (7,931) -
Treasury stock purchases........ - - 1,300 - - - (30,722) -
Exchange of Series A............
convertible preferred stock..
for common stock............. 1,139 (1,324) - 28,468 (13) (28,995) - -
Conversions of subordinated.....
convertible notes to.........
common stock................. - 1,198 - - 12 27,127 - -
Common stock dividends..........
($0.30 per share)............ - - - - - - - (5,242)
Preferred stock dividends.......
($0.45 per share)............ - - - - - - - (514)
Net income...................... - - - - - - - 20,304
Three-for-two stock split....... - 9,403 860 - 94 (94) - -
------ ------ ------ ------- ---- -------- -------- --------
BALANCES, DECEMBER 31, 1996..... 1,139 28,210 2,579 $28,468 $282 $164,577 $(40,219) $(11,078)
====== ====== ====== ======= ==== ======== ======== ========
See accompanying notes to consolidated financial statements.
29
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cross Timbers Oil Company, a Delaware corporation, was organized in October
1990 to ultimately acquire the business and properties of predecessor entities
that were created from 1986 through 1989. Cross Timbers Oil Company completed
its initial public offering of common stock in May 1993.
The accompanying consolidated financial statements include the financial
statements of Cross Timbers Oil Company and its wholly owned subsidiaries ("the
Company"). All significant intercompany balances and transactions have been
eliminated in the consolidation. Certain amounts presented in prior period
financial statements have been reclassified for consistency with current period
presentation. In preparing the accompanying financial statements, management has
made certain estimates and assumptions that affect reported amounts in the
financial statements and disclosures of contingencies. Actual results may differ
from those estimates.
The Company is an independent oil and gas company with production
concentrated in Texas, Oklahoma, Kansas, New Mexico and Wyoming. The Company
also gathers, processes and markets gas, transports and markets oil and conducts
other activities directly related to the oil and gas producing industry.
Property and Equipment
The Company follows the successful efforts method of accounting,
capitalizing costs of successful exploratory wells and expensing costs of
unsuccessful exploratory wells. All developmental costs are capitalized. The
Company generally pursues acquisition and development of proved reserves as
opposed to exploration activities. Most of the property costs reflected on the
accompanying consolidated balance sheets are from acquisitions of producing
properties from other oil and gas companies since 1986.
Depreciation, depletion and amortization of producing properties is
computed on the unit-of-production method based on estimated proved oil and gas
reserves. Other property and equipment are generally depreciated using the
straight-line method over their estimated useful lives which range from 3 to 40
years. Repairs and maintenance are expensed, while renewals and betterments are
generally capitalized.
Effective October 1, 1995, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of. Based generally on a
field-level assessment, producing properties were written down to estimated fair
value when their net basis exceeded estimated direct future net cash flows from
such properties. The Company's resulting impairment provision was $20,280,000
before income tax. After initial adoption of SFAS No. 121, the Company must
assess impairment of long-lived assets whenever events or changes in
circumstances indicate that the net basis of the asset may not be recoverable.
No impairment was recorded in 1996 and, prior to adoption of SFAS No. 121 in
1995, no impairment of producing properties was required, based on a total
Company assessment using undiscounted estimated future net cash flows.
Impairment of individually significant undeveloped properties is assessed on a
property-by-property basis and impairment of other undeveloped properties is
assessed and amortized on an aggregate basis.
Cross Timbers Royalty Trust
The Company makes monthly net profits payments to Cross Timbers Royalty
Trust ("Royalty Trust") based on revenues and costs related to properties from
which net profits interests were carved. Net profits payments to the Royalty
Trust are generally based on revenues received and costs disbursed by the
Company in the prior month. For financial reporting purposes, the Company
reduces oil and gas revenues and taxes on production for amounts allocated to
the Royalty Trust. The Royalty Trust's portion of development costs are expensed
as trust development costs in the accompanying consolidated statements of
operations. As of December 31, 1996, the Company owns 16% of the Royalty Trust's
publicly traded units of beneficial interest (Note 9).
30
Cash and Cash Equivalents
Cash equivalents are considered to be all highly liquid investments having
an original maturity of three months or less.
Investment in Equity Securities
Investment in equity securities is reported at market value and classified
as available-for-sale securities, rather than trading securities, in accordance
with SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities. Accordingly, the related unrealized gain on investment at December
31, 1996, net of deferred income taxes, is excluded from earnings and is
reported as a separate component of stockholders' equity.
Other Assets
Other assets include goodwill recorded upon purchase of subsidiaries,
deferred debt costs and organization costs that are amortized over periods of
15, 10 and 5 years, respectively. Other assets are presented net of accumulated
amortization of $2,628,000 and $3,431,000 at December 31, 1996 and 1995,
respectively.
Derivatives
The Company uses derivatives on a limited basis to hedge interest rate and
product price risks, as opposed to their use for trading purposes. Amounts
receivable or payable under interest swap agreements are recorded as adjustments
to interest expense. Gains and losses on commodity futures contracts and other
price risk management instruments are recognized in oil and gas revenues when
the hedged transaction occurs. Cash flows related to derivative transactions are
included in operating activities.
Production Imbalances
The Company uses the entitlement method of accounting for gas sales, based
on the Company's net revenue interest in production. Accordingly, revenue is
deferred when gas deliveries exceed the Company's net revenue interest, while
revenue is accrued for under-deliveries. Production imbalances are generally
recorded at the estimated sales price in effect at the time of production. At
December 31, 1996, the Company recorded a net receivable of $3,964,000 for a net
underproduced balancing position of 821,000 Mcf of natural gas and 6,824,000 Mcf
of carbon dioxide. At December 31, 1995, the Company recorded a net receivable
of $2,018,000 for a net underproduced balancing position of 662,000 Mcf of
natural gas and 5,600,000 Mcf of carbon dioxide.
Oil and Gas and Other Revenues
Oil revenue includes sales of oil and condensate. Gas revenue includes
sales of natural gas and natural gas liquids. Other revenues include gain/loss
from sale of equity securities and from sale of property and equipment. During
1996 and 1995, the Company realized gains on sale of property and equipment of
$520,000 and $2,960,000, respectively, and on sale of equity securities of
$56,000 and $1,560,000, respectively. During 1994, the Company realized a loss
on sales of properties of $122,000. In 1996, gas sales to two purchasers were
approximately 15% and 14% of total 1996 revenues. In 1994, gas sales to two
purchasers were approximately 16% and 13% of total 1994 revenues. There were no
sales to a single purchaser that exceeded 10% of total revenues in 1995.
Gas Gathering, Processing and Marketing Revenues
Gas produced by the Company and third parties is marketed by the Company to
brokers, local distribution companies and end-users. Gas gathering and marketing
revenues are recognized in the month of delivery based on customer nominations.
Gas processing and marketing revenues are recorded net of cost of gas sold of
$56.4 million, $30 million and $23.9 million for 1996, 1995 and 1994,
respectively. These amounts are net of intercompany eliminations.
Interest Expense
Interest expense includes amortization of deferred debt costs and is
presented net of interest income of $152,000, $399,000 and $255,000 for the
years ended December 31, 1996, 1995 and 1994, respectively.
31
Stock-Based Compensation
In accordance with Accounting Principles Board Opinion No. 25, Accounting
for Stock Issued to Employees, no compensation is recorded for stock options or
other stock-based awards that are granted with an exercise price equal to or
above the common stock price on the grant date. Compensation related to
performance share grants is recognized from the grant date until the performance
conditions are satisfied, based on the market price of the Company's common
stock. The pro forma effect of recording stock-based compensation at the
estimated fair value of awards on the grant date, as prescribed by SFAS 123,
Accounting for Stock-Based Compensation, is disclosed in Note 8.
Extraordinary Item
During 1995, the Company recognized an extraordinary gain of $656,000 (net
of income tax of $338,000), or $0.02 per common share, upon the purchase and
early retirement of a portion of the Company's 5 1/4% convertible subordinated
notes. A loss of $430,000, before income tax, on purchases and redemption of the
notes was not presented as an extraordinary item because it was not material to
1996 earnings (Note 2).
Earnings per Common Share
Earnings (loss) per common share for all periods presented is based on
weighted average common shares outstanding as adjusted for the three-for-two
stock split on March 19, 1997 (see Note 5). Potential conversion of the
Company's 5 1/4% convertible subordinated notes and Series A convertible
preferred stock (Note 5) and exercise of stock options has not been recognized
in the weighted average common share calculation for any of the periods
presented because their effect is either antidilutive or less than 3% dilutive.
2. DEBT
The Company's outstanding debt consists of the following (in thousands):
December 31
-------------------
1996 1995
-------- --------
SHORT-TERM DEBT:
Short-term borrowings, 7.6% at December 31, 1996.... $ 13,000 $ -
Reclassified to long-term debt...................... (10,000) -
-------- --------
Total short-term debt............................... $ 3,000 $ -
======== ========
LONG-TERM DEBT:
Senior debt-
Bank debt under revolving credit agreements,
7.0% at December 31, 1996....................... $275,000 $172,000
Subordinated debt-
5 1/4% convertible subordinated notes due
November 1, 2003................................ 29,757 66,475
-------- --------
Sub-total long-term debt............................ 304,757 238,475
Reclassified from short-term debt................... 10,000 -
-------- --------
Total long-term debt................................ $314,757 $238,475
======== ========
Debt maturing in each of the five years following December 31, 1996 is as
follows: $3 million in 1997, $37 million in 1998, $48 million in 1999, $49
million in 2000 and $46 million in 2001.
32
Senior Debt
At December 31, 1996, total borrowing commitments from commercial banks
under the Revolving Credit Agreement ("loan agreement") were $300 million, with
resulting unused borrowing capacity of $25 million. The loan agreement provides
for a revolving facility with reductions of borrowing commitment generally
scheduled on each June 30 and December 31. As of December 31, 1997, borrowing
commitments were scheduled to be reduced to $285 million. In connection with a
property acquisition in January 1997, borrowing commitments were increased to
$306 million, which will be reduced to $291 million on December 31, 1997.
Borrowings under the loan agreement mature on June 30, 2002, but may be prepaid
at any time without penalty. The Company periodically renegotiates the loan
agreement to increase the borrowing commitment and extend the revolving
facility.
Reclassification of short-term to long-term debt represents unused capacity
under the loan agreement based on outstanding debt balances at December 31, 1996
and borrowing commitments at December 31, 1997. The Company has both the intent
and ability to refinance this debt on a long-term basis.
The Company is required to maintain a specified current ratio as well as
certain cash flow-to-debt and production ratios based on a reserve report
prepared by independent engineers. The loan agreement also places restrictions
on additional indebtedness, liens, sale of properties and certain other assets.
The banks may require payments based on a specified percentage of net revenue
(as defined in the loan agreement) if material changes occur in the production
profile or nature of oil and gas reserves, or if the cash flow and production
ratios are not met. The loan agreement also limits dividends and treasury stock
purchases to 25% of cash flow from operations for the latest four consecutive
quarterly periods. In May 1996, this limitation on treasury stock purchases was
waived to allow for the purchase of up to two million treasury shares.
The loan agreement provides the option of borrowing at floating
interest rates based on the prime rate or at fixed rates for periods of up to
six months based on certificate of deposit rates or London Interbank Offered
Rates ("LIBOR"). Borrowings under the loan agreement at December 31, 1996 were
based on LIBOR rates with a maturity of 30 days and accrued at the applicable
LIBOR rate plus 1 1/4%. Interest is paid at maturity, or quarterly if the term
is for a period of 90 days or more. The Company also incurs a commitment fee of
3/8% on unused borrowing commitments. The weighted average interest rate on
senior debt was 6.7%, 7.1% and 5.4% during 1996, 1995 and 1994, respectively.
Subordinated Debt
During 1995, the Company purchased and retired $8.3 million principal
amount of its 5 1/4% convertible subordinated notes, resulting in an
extraordinary gain of $656,000 (Note 1). During 1996, the Company redeemed,
purchased and retired a total of $9 million principal amount of the notes at a
loss before income tax of $430,000. Note purchases were primarily funded by bank
borrowings under the loan agreement. In November and December 1996, principal of
$27.7 million was converted at the option of noteholders into common stock at a
conversion price of $23.125 per share (Note 5).
In January 1997, $29.7 million principal amount of the notes was converted
by noteholders into common stock and $29,000 principal was redeemed. As of
January 21, 1997, no notes remain outstanding.
3. INCOME TAX
The effective income tax rate for the Company (before extraordinary item)
was different than the statutory federal income tax rate for the following
reasons (in thousands):
1996 1995 1994
------- ------- ------
Income tax expense (benefit) at the
federal statutory rate of 34%............ $10,531 $(5,786) $1,625
State and local taxes and other............ 138 (39) 105
------- ------- ------
Income tax expense (benefit)............... $10,669 $(5,825) $1,730
======= ======= ======
33
Components of income tax expense (benefit) before extraordinary item are as
follows (in thousands):
1996 1995 1994
------- ------- -------
Current income tax..................... $ 456 $ 198 $ 68
Deferred income tax expense (benefit).. 13,152 (3,221) 5,209
Net operating loss carryforward........ (2,939) (2,802) (3,547)
------- ------- -------
Income tax expense (benefit)........... $10,669 $(5,825) $ 1,730
======= ======= =======
Deferred tax assets and liabilities are the result of temporary differences
between the financial statement carrying values and tax bases of assets and
liabilities. The Company's net deferred tax liabilities are recorded as a
current asset of $558,000 and a long-term liability of $10,323,000 at December
31, 1996, and a current asset of $1,661,000 and a long-term liability of
$2,382,000 at December 31, 1995. Significant components of net deferred tax
liabilities are (in thousands):
December 31
----------------
1996 1995
------- -------
Deferred tax liabilities:
Intangible development costs................. $21,764 $14,253
Tax depletion and depreciation in excess
of financial statement amounts............. 3,298 885
Other........................................ 1,905 824
------- -------
Total deferred tax liabilities.......... 26,967 15,962
------- -------
Deferred tax assets:
Net operating loss carryforwards............. 11,810 8,871
Trust development expenses................... 3,733 3,442
Accrued stock appreciation right and
performance share compensation............. 787 2,288
Other........................................ 872 640
------- -------
Total deferred tax assets............... 17,202 15,241
------- -------
Net deferred tax liabilities.................. $ 9,765 $ 721
======= =======
As of December 31, 1996, the Company has estimated tax loss carryforwards
of approximately $34 million that are scheduled to expire in 2008 through 2011.
4. COMMITMENTS AND CONTINGENCIES
Leases
The Company leases offices, vehicles and certain other equipment in its
primary locations under non-cancelable operating leases. As of December 31,
1996, minimum future lease payments for all non-cancelable lease agreements
(including the sale and operating leaseback agreements described below) were as
follows (in thousands):
1997........................... $ 6,258
1998........................... 6,148
1999........................... 6,040
2000........................... 5,960
2001........................... 5,960
Remaining...................... 14,943
-------
$45,309
=======
Amounts incurred by the Company under operating leases (including renewable
monthly leases) were $5,489,000, $1,912,000 and $1,558,000 in 1996, 1995 and
1994, respectively.
In March 1996, the Company sold its Tyrone gas processing plant and related
gathering system (acquired as part of the Santa Fe Acquisition in August 1995 -
Note 9) for $28 million and entered an agreement to lease the facility from the
buyers for an initial term of eight years at annual rentals of $4 million, and
with fixed renewal
34
options for an additional 13 years. The Company does not have the right or
option to purchase, nor does the lessor have the obligation to sell the facility
at any time. However, if the lessor decides to sell the facility at the end of
the initial term or any renewal period, the lessor must first offer to sell it
to the Company at its fair market value. Additionally, the Company has a right
of first refusal of any third party offers to buy the facility after the initial
term. This transaction has been recorded as a sale and operating leaseback, with
no gain or loss on the sale. Proceeds of the sale were used to reduce borrowings
under the loan agreement (Note 2).
In November 1996, the Company sold its gathering system in Major County,
Oklahoma for $8 million and entered an agreement to lease the facility from the
buyers for an initial term of eight years, with fixed renewal options for an
additional 10 years. Rentals are adjusted monthly based on the 30-day LIBOR rate
(Note 2) and may be irrevocably fixed by the Company with 20 days advance
notice. As of December 31, 1996, annual rentals were $1.6 million. The Company
does not have the right or option to purchase, nor does the lessor have the
obligation to sell the facility at any time. However, if the lessor decides to
sell the facility at the end of the initial term or any renewal period, the
lessor must first offer to sell it to the Company at its fair market value.
Additionally, the Company has a right of first refusal of any third party offers
to buy the facility after the initial term. This transaction has been recorded
as a sale and operating leaseback, with a deferred gain of $3.4 million on the
sale. The deferred gain is amortized over the lease term based on pro rata
rentals and is recorded in other long-term liabilities in the accompanying
balance sheet. Proceeds of the sale were used to reduce borrowings under the
loan agreement.
Employment Agreements
Two executive officers have entered into year-to-year employment agreements
with the Company. The agreements are automatically renewed each year-end unless
terminated by either party upon thirty days notice prior to each December 31.
Under these agreements, each of the officers receives a minimum annual salary of
$300,000 and is entitled to participate in any incentive compensation programs
administered by the Board of Directors. The agreements also provide that, in the
event the officer terminates his employment for good reason, as defined in the
agreement, the officer will receive severance pay equal to the amount that would
have been paid under the agreement had it not been terminated. If such
termination follows a change in control of the Company, the officer is entitled
to a lump-sum payment of three times his most recent annual compensation.
Sales Contracts
The Company sells gas to a single purchaser under a ten-year contract that
began August 1, 1995. From August 1995 through July 1998 ("initial period"),
10,000 Mcf of gas per day is sold at a contract price equal to a monthly natural
gas index for deliveries in Oklahoma plus $.35 per Mcf through December 1996,
and plus $.30 per Mcf from January 1997 through July 1998. For December 1996,
the initial period contract price was $3.96 per Mcf. From August 1998 through
July 2005 ("final period"), 11,650 Mcf of gas per day will be sold at a contract
price of approximately 10% of the month's average NYMEX futures contract for
West Texas Intermediate crude oil, adjusted for the point of physical delivery.
For December 1996, the final period contract price would have been $2.54 per
Mcf, assuming delivery in Oklahoma. The Company's spot price for December 1996
deliveries in Oklahoma was $3.58 per Mcf.
The Company has entered a contract with a single purchaser to sell a total
of 25,000 Mcf of gas per day for the first three months of 1997 at a weighted
average wellhead sales price of $2.83 per Mcf.
Since August 1991, the Company has sold gas to a cogeneration facility
under a take-or-pay contract that expires in September 2004. The Company has
committed to sell between 1,460,000 and 1,825,000 Mcf of gas annually under this
contract, subject to certain modifications, at a price based on a composite
energy cost index. Since the Company generally purchases such gas at spot
prices, there is exposure to loss during months of rapidly increasing gas
prices. The Company recognized a net profit (loss) on this contract of
($206,000), $453,000 and $178,000 during 1996, 1995 and 1994, respectively.
Litigation
In June 1996, Holshouser v. Cross Timbers Oil Company, a class action
lawsuit, was filed in the District Court of Major County, Oklahoma. The action
was filed on behalf of all parties who, at any time since June 1991, have
allegedly had production or other costs deducted by the Company from royalties
paid on gas produced in Oklahoma when the royalty is based upon a specified
percentage of the proceeds received from the gas sold. The
35
plaintiff alleges that such deductions are a breach of the Company's contractual
obligations to the class and is seeking to recover an unspecified amount of
damages as a result of the alleged breach. The plaintiff is also seeking a
determination of the Company's obligations to the plaintiff and the class
regarding production or other costs. The Company has responded that it has
complied with all of its contractual obligations and denied that the matter is
appropriate for determination as a class action. The parties are currently
conducting discovery on the class issues. Management believes it has strong
defenses against this claim and intends to vigorously defend the action.
Management's estimate of the potential liability from this claim has been
accrued in the accompanying financial statements as of December 31, 1996.
The Company and certain of its subsidiaries are involved in various other
lawsuits and certain governmental proceedings arising in the ordinary course of
business. Company management and legal counsel do not believe that the ultimate
resolution of these claims, including the class action lawsuit described above,
will have a material effect on the Company's financial position, liquidity or
operations.
Other
In May 1993, the Company entered into a registration rights agreement with
holders of 9.3 million shares of common stock that could not be resold except
pursuant to registration with the Securities and Exchange Commission or an
exemption from such registration. Under certain conditions, holders of at least
5% of the unregistered shares can require that the Company use its best efforts
to register and sell these shares in a public offering. The Company has agreed
to pay all costs of such registration. Following the August 1995 public offering
of common stock (Note 5), 7.1 million shares remain subject to such registration
rights.
To date, the Company's expenditures to comply with environmental or safety
regulations have not been significant and are not expected to be significant in
the future. However, developments such as new regulations, enforcement policies
or claims for damages could result in significant future costs.
5. EQUITY
Public Offering of Common Stock
In August 1995, the Company completed a public offering of 4,362,775 shares
of common stock, of which 2,250,000 shares were sold by the Company and
2,112,775 shares were sold by stockholders. Net proceeds from the offering of
$29.5 million were used to partially fund the Santa Fe Acquisition (Note 9).
Performance Shares
During 1996 and 1995, the Company issued 74,500 and 164,250 performance
shares (Note 8).
Series A Convertible Preferred Stock
In September 1996, pursuant to the Company's exchange offer, a total of
1,324,111 shares of common stock were exchanged for 1,138,729 shares of Series A
convertible preferred stock ("Preferred Stock"). The Company incurred costs of
$540,000 related to this exchange offer. All exchanged shares of common stock
have been canceled and are authorized but unissued. Preferred Stock is recorded
in the accompanying consolidated balance sheet at its liquidation preference of
$25 per share.
Cumulative dividends on Preferred Stock are payable quarterly in arrears,
when declared by the Board of Directors, based on an annual rate of $1.5625 per
share. The Preferred Stock has no stated maturity and no sinking fund, and is
redeemable, in whole or in part, by the Company after October 15, 1999.
Redemption is allowed only under certain circumstances on or before October 15,
2000 at $26.09 per share, and thereafter unconditionally at prices declining
ratably annually to $25.00 per share after October 15, 2006, plus dividends
accrued and unpaid to the redemption date.
The Preferred Stock is convertible at the option of the holder at any time,
unless previously redeemed, into shares of common stock at a rate of 1.44 shares
of common stock for each share of Preferred Stock, subject to
36
adjustment in certain events. Preferred Stock holders are allowed one vote for
each common share into which their Preferred Stock may be converted.
Treasury Stock
During 1996, 1995 and 1994, the Company purchased 1,485,118, 20,218 and 758
shares of its common stock at an average cost per share of $23.51, $17.37 and
$15.00, respectively. Additionally, the Company received 203,553 and 9,540
shares in 1996 and 1995 that are held in treasury, as payment for the option
price upon exercise of stock options.
Convertible Debt
During November and December 1996, $27.7 million principal of the Company's
5 1/4% convertible subordinated notes (Note 2) was converted by noteholders into
1,198,454 shares of common stock. In January 1997, principal of $29.7 million of
the notes was converted by noteholders into 1,285,495 shares of common stock. As
of January 21, 1997, no notes remain outstanding.
Three-for-Two Stock Split
On March 19, 1997, the Company effected a three-for-two stock split for
common stockholders of record on March 12, 1997. Per share amounts for all
periods presented and common stock, additional paid-in capital and treasury
share balances at December 31, 1996 have been restated to reflect the stock
split on a retroactive basis.
Common Stock Dividends
Since the Company's inception, the Board of Directors has declared
quarterly dividends of $0.075 per common share ($0.05 per share on a post-split
basis). In February 1997, the Board of Directors declared a dividend of $0.055
per share on a post-split basis, payable April 15, 1997 to shareholders of
record on March 31, 1997. See Note 2 regarding restrictions on dividends.
6. FINANCIAL INSTRUMENTS
Interest Rate Swap Agreement
The Company entered a series of interest rate swap agreements to hedge
exposure to interest rate fluctuations on variable-rate debt, the last of which
expired in September 1996. Settlements of net amounts due were made
semiannually, based on LIBOR rates (Note 2). The Company's senior debt
borrowings have been based on LIBOR rates throughout the terms of these swap
agreements.
In January 1996, the Company committed with a bank to enter into two
interest rate swap agreements if LIBOR rates declined to specified strike rates
on April 17, 1996. The Company received $500,000 as consideration for this
commitment that expired unexercised on April 17, resulting in recognition of
such proceeds as other income.
Commodity Futures Contracts
The Company periodically enters into futures contracts to hedge its
exposure to price fluctuations on crude oil and natural gas sales. The Company
did not have any significant hedging activity from 1994 through 1996. See Note
4.
37
Fair Value
Because of their short-term maturity, the fair value of cash and cash
equivalents, accounts receivable and accounts payable approximates their
carrying values at December 31, 1996 and 1995. The following are estimated fair
values and carrying values of the Company's other financial instruments (none of
which are held or issued for trading purposes) at these dates (in thousands):
Asset (Liability)
----------------------------------------------
December 31, 1996 December 31, 1995
---------------------- ----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ---------- ---------- ----------
Investment in equity securities.. $ 16,714 $ 16,714 $ - $ -
Short-term debt.................. $ (3,000) $ (3,000) $ - $ -
Long-term debt................... $(314,757) $(317,331) $(238,475) $(234,487)
Interest rate swap agreements.... $ - $ - $ - $ 41
The above fair values were estimated based on: investment in equity
securities- quoted market price; short and long-term debt- short-term borrowings
and bank borrowings approximate the carrying value because of short-term
interest rate maturities, while the fair value of subordinated notes is
estimated to be ($32.2 million) and ($62.5 million) at December 31, 1996 and
1995 based on a current market quote; interest rate swap agreements- the present
value of estimated future cash flows. Such estimated fair values are not
necessarily representative of amounts that could be realized or settled, nor do
they consider the tax consequences of realization or settlement.
Concentrations of Credit Risk
Although the Company's cash equivalents and derivative financial
instruments are exposed to the risk of credit loss, the Company does not believe
such risk to be significant. Cash equivalents are high-grade, short-term
securities, placed with highly rated financial institutions. Most of the
Company's receivables are from a broad and diverse group of energy companies
and, accordingly, do not represent a significant credit risk. The Company's gas
marketing activities generate receivables from customers including pipeline
companies, local distribution companies and end-users in various industries.
Letters of credit or other appropriate security are obtained as considered
necessary to limit risk of loss. The Company recorded an allowance for
collectibility of all accounts receivable of $911,000 and $650,000 at December
31, 1996 and 1995, respectively.
7. SUPPLEMENTAL CASH FLOW INFORMATION
The consolidated statements of cash flows exclude the following non-cash
equity transactions (Notes 5 and 8):
- Exchange of 1,324,111 shares of common stock for 1,138,729 shares of
Series A convertible preferred stock in 1996
- Conversion of $27.7 million principal amount of 5 1/4% convertible
subordinated notes into 1,198,454 shares of common stock in 1996
- Grants of 74,500 and 164,250 performance shares to key employees and
nonemployee directors in 1996 and 1995, respectively
- Receipt of 203,553 and 9,540 shares of common stock for the option price
of exercised stock options in 1996 and 1995
Interest payments during 1996, 1995 and 1994 totaled $16,369,000,
$12,202,000 and $7,910,000 respectively. Income tax payments during 1996, 1995
and 1994 totaled $6,000, $541,000 and $28,000, respectively.
38
8. EMPLOYEE BENEFIT PLANS
401(k) Plan
The Company sponsors a 401(k) benefit plan that allows employees to
contribute and defer a portion of their wages. Employee contributions (up to 8%
of wages) are matched by the Company. Employee contributions vest immediately
while the Company's matching contributions vest 100% after three years of
service. All full-time employees over 21 years of age and with at least three
months service with the Company may participate. Company contributions under the
plan were $979,000, $814,000 and $675,000 in 1996, 1995 and 1994, respectively.
1991 Stock Incentive Plan
A total of 450,000 incentive units ("Units") have been granted to
directors, officers and other key employees under the 1991 Stock Incentive Plan
("1991 Plan"). One-third of the Units become exercisable on each of the first
three anniversaries of the grant date and no Units are exercisable following the
tenth anniversary. Units consist of a stock option ("Option") and a stock
appreciation right ("SAR"). An Option provides the right to purchase one share
of common stock at the exercise price, which generally is the market price at
the date the Unit is granted. A SAR entitles the recipient to a payment equal to
twice the excess of the market price of one share of common stock on the date
the Option is exercised over the exercise price.
General and administrative expense includes stock incentive compensation
related to SARs of $3.7 million, $2.3 million and $700,000 for 1996, 1995 and
1994, respectively. SAR cash payments were $7.1 million, $800,000 and $10,000 in
1996, 1995 and 1994, respectively.
1994 Stock Incentive Plan
Under the 1994 Stock Incentive Plan ("1994 Plan"), an aggregate of one
million shares of common stock may be issued to directors, officers and other
key employees pursuant to grants of Options or performance shares of common
stock ("performance shares"). At December 31, 1996, 6,550 shares remained
available for grant under the 1994 Plan (9,825 on a post-split basis - see Note
5). Options vest and become exercisable at dates specified when granted by the
compensation committee ("the Committee") of the Board of Directors. No option,
however, is exercisable prior to six months or after ten years from its grant
date. With the exception of 543,765 options granted in 1994 that vest and become
exercisable upon the exercise of the recipients' Units under the 1991 Plan, all
options granted under the 1994 Plan vest in equal amounts over a five-year
period.
Performance shares are subject to restrictions determined by the Committee
and may be subject to forfeiture if performance targets established by the
Committee are not met. Otherwise, holders of performance shares generally have
all the voting, dividend and other rights of other stockholders. During 1995,
the Company issued to key employees 158,250 performance shares that vested in
two equal amounts when the common stock price reached $21 in May 1996 and $24 in
June 1996. The Company recognized compensation expense of $2.8 million and
$700,000 in 1995 and 1996, respectively, related to these 1995 performance share
grants. During 1996, the Company issued to key employees 68,500 performance
shares that vested when the common stock price reached $30 in January 1997. The
Company recognized compensation expense of $1.8 million and $200,000 in 1996 and
January 1997, respectively, related to these 1996 performance share grants. The
Company also issued a total of 6,000 performance shares in each of 1996 and
1995, with immediate vesting to nonemployee directors as compensation for their
services.
39
Unit/ Option Activity and Balances
The following summarizes Unit and Option activity and balances from 1994
through 1996:
Weighted Average
------------------------ 1991 Plan 1994 Plan
Exercise Fair Value Incentive Stock
Price of Grants (a) Units Options
-------- ------------- ---------- ----------
1994
- -------------------------------------------
Beginning of year......................... $12.33 - 450,000 -
Grants................................... 14.94 - - 550,765
Exercises................................ 12.01 - (1,666) -
Forfeitures.............................. 14.53 - (1,000) (4,250)
-------- -------
End of year............................... 13.76 - 447,334 546,515
======== =======
Exercisable at end of year................ 12.10 - 392,884 -
======== =======
1995
- -------------------------------------------
Beginning of year......................... $13.76 - 447,334 546,515
Grants................................... 16.58 $5.81 - 78,750
Exercises................................ 12.05 - (75,462) -
Forfeitures.............................. 14.73 - (401) (3,376)
-------- -------
End of year............................... 14.11 - 371,471 621,889
======== =======
Exercisable at end of year................ 12.83 - 348,306 94,336
======== =======
1996
- -------------------------------------------
Beginning of year......................... $14.11 - 371,471 621,889
Grants................................... 21.68 $8.59 - 135,000
Exercises................................ 12.82 - (348,737) (93,813)
Forfeitures.............................. 14.87 - (84) (2,189)
-------- -------
End of year............................... 16.48 - 22,650 660,887
======== =======
Exercisable at end of year................ 14.98 22,650 447,176
======== =======
Adjusted for 3-for-2 stock split (Note 5):
End of year.............................. $10.99 - 33,975 991,331
======== =======
Exercisable at end of year............... 9.99 - 33,975 670,764
======== =======
(a) The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option-pricing model with the following
assumptions for 1996 and 1995, respectively: risk-free interest rates of
6.4% and 5.8%; dividend yield of 1.4%; expected lives of 6 years; and
volatility of 35% and 31%.
The following summarizes information about Units/ Options at December 31,
1996, as restated for the three-for-two stock split (Note 5):
Units/ Options Outstanding Units/ Options Exercisable
------------------------------- --------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Prices Number Term Price Number Price
- ---------------------------- --------- --------- -------- ------- --------
1991 Plan
$7.97 - $11.33..... 33,975 6.0 years $ 9.63 33,975 $ 9.63
1994 Plan
$9.92 - $11.83..... 793,331 7.8 years 10.16 670,764 10.01
$14.50 - $16.37.... 198,000 9.4 years 14.51 - -
--------- -------
1,025,306 8.1 years 10.99 704,739 9.99
========= =======
40
Pro Forma Effect of Recording Stock-Based Compensation at Estimated
Fair Value
The following are pro forma earnings (loss) available to common stock and
earnings (loss) per common share for 1996 and 1995, as if stock-based
compensation had been recorded at the estimated fair value of stock awards at
the grant date, as prescribed by SFAS 123, Accounting for Stock-Based
Compensation (Note 1), including the effect of restatement for the three-for-two
stock split (Note 5):
(in thousands, except per share data) Pro Forma
------------------
1996 1995
-------- -------
Earnings (loss) available to common stock.. $19,767 $(11,200)
======= ========
Earnings (loss) per common share:
Before extraordinary item............... $ 0.74 $ (0.46)
======= ========
After extraordinary item................ $ 0.74 $ (0.44)
======= ========
9. ACQUISITIONS
At the end of March 1995, the Company acquired predominantly gas-producing
properties in Kansas, Oklahoma and Texas from Apache Corporation for $20 million
and in northwestern Oklahoma from Meridian Oil, Inc. and certain of its
affiliates for $4.1 million. During the second quarter of 1995, the Company
completed other acquisitions totaling approximately $7 million. These
acquisitions were primarily financed with bank debt under the Company's
revolving credit agreements (Note 2).
On August 1, 1995, the Company acquired gas-producing properties and a
related gathering system and gas processing plant from Santa Fe Minerals, Inc.
("Santa Fe Acquisition"). The properties consist primarily of operated interests
in the Hugoton Field of Kansas and Oklahoma. Of the $123 million adjusted
purchase price, $94 million was allocated to producing properties and $29
million was allocated to gas gathering and processing facilities. The Santa Fe
Acquisition was primarily financed by borrowings under the Company's loan
agreement (Note 2) and proceeds from the August 1995 common stock offering (Note
5) and asset sales.
From July through December 1996, the Company purchased 16% of the
outstanding units of beneficial interest in the Royalty Trust ("Units") at a
cost of $12.8 million, funded primarily with bank debt. In January 1997, after
acquiring a total of one million Units, the Board of Directors authorized the
purchase of up to one million additional Units. The Company considers its
investment in Units as an acquisition of oil and gas properties; accordingly,
the cost of these Units has been included in producing properties in the
accompanying consolidated balance sheet.
On July 19, 1996, the Company acquired primarily gas-producing properties
in the Green River Basin of southwestern Wyoming from Enserch Exploration
("Enserch Acquisition") for an adjusted purchase price of $39.4 million. The
properties primarily consist of operated interests in the Fontenelle, Nitchie
Gulch and Pine Canyon fields. On November 21, 1996, the Company acquired
additional interests in the Fontenelle Unit, the most significant property
included in the Enserch Acquisition, for an estimated adjusted purchase price of
$12.5 million. These acquisitions were funded by bank debt and cash flow from
operations.
On December 2, 1996, the Company acquired primarily gas-producing
properties in the Northern Val Verde area of the Permian Basin of West Texas.
The properties are primarily operated interests in the Henderson, Ozona and
Davidson Ranch fields. The estimated adjusted purchase price of $28 million was
funded by bank debt and cash flow from operations.
These acquisitions have been recorded using the purchase method of
accounting. The following presents unaudited pro forma results of operations for
the years ended December 31, 1996 and 1995 as if these acquisitions (net of
related dispositions) and the August 1995 common stock offering had been
consummated as of January 1, 1995. These pro forma results are not necessarily
indicative of future results.
41
(in thousands, except per share data) Pro Forma (Unaudited)
---------------------
1996 1995
-------- ---------
Revenues..................................... $174,722 $140,196
======== ========
Net income (loss) before extraordinary item.. $ 20,199 $(15,416)
======== ========
Earnings (loss) available to common stock.... $ 19,685 $(14,760)
======== ========
Earnings (loss) per common share:
Before extraordinary item.................. $ 0.74 $ (0.56)
======== ========
After extraordinary item................... $ 0.74 $ (0.54)
======== ========
Weighted average common shares outstanding... 26,609 27,318
======== ========
10. QUARTERLY FINANCIAL DATA (Unaudited)
The following are summarized quarterly financial data for the years ended
December 31, 1996 and 1995, with restatement of earnings per common share and
average shares outstanding for the effects of the three-for-two stock split
(Note 5):
(in thousands, except per share data) Quarter
----------------------------------
1st 2nd 3rd 4th (a)
------- ------- ------- -------
1996
-----------------------------------
Revenues....................... $36,081 $36,735 $39,201 $ 49,374
Gross profit (b)............... $13,482 $13,606 $14,240 $ 23,137
Earnings available to
common stock................ $ 4,671 $ 1,807 $ 4,647 $ 8,665
Earnings per common share...... $ 0.17 $ 0.07 $ 0.18 $ 0.35
Average shares outstanding..... 27,602 27,447 26,430 24,977
1995
-----------------------------------
Revenues....................... $24,219 $27,936 $28,066 $ 32,684
Gross profit (b)............... $ 5,627 $ 7,903 $ 5,603 $(10,473)
Earnings (loss) available to
common stock:
Before extraordinary item... $ 1,463 $ 943 $ 1,211 $(14,811)
After extraordinary item.... $ 1,463 $ 943 $ 1,820 $(14,764)
Earnings (loss) per common
share:
Before extraordinary item... $ 0.06 $ 0.04 $ 0.05 $ (0.54)
After extraordinary item.... $ 0.06 $ 0.04 $ 0.07 $ (0.54)
Average shares outstanding..... 23,888 23,897 26,277 27,426
(a) Fourth quarter 1995 results include a pre-tax impairment charge of
$20.3 million upon adoption of SFAS No. 121 (Note 1), and $2.8
million for performance share compensation and $2.6 million for
stock appreciation right compensation (Note 8).
(b) Revenues less expenses, other than general and administrative, net
interest expense and income tax.
42
11. SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING
ACTIVITIES (Unaudited)
All of the Company's operations are directly related to oil and gas
producing activities located in the United States.
Costs Incurred Related to Oil and Gas Producing Activities
The following table summarizes costs incurred whether such costs are
capitalized or expensed for financial reporting purposes (in thousands):
1996 1995 1994
-------- -------- -------
Acquisition (including undeveloped
properties)......................... $105,815 $131,342 $28,100
Exploitation and development.......... 44,758 20,797 21,668
Exploration........................... 280 264 158
-------- -------- -------
Total................................. $150,853 $152,403 $49,926
======== ======== =======
Proved Reserves
Independent petroleum engineers have estimated the Company's proved oil and
gas reserves, all of which are located in the United States. Proved reserves are
the estimated quantities that geologic and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are
the quantities expected to be recovered through existing wells with existing
equipment and operating methods. Due to the inherent uncertainties and the
limited nature of reservoir data, such estimates are subject to change as
additional information becomes available. The reserves actually recovered and
the timing of production of these reserves may be substantially different from
the original estimate. Revisions result primarily from new information obtained
from development drilling and production history and from changes in economic
factors.
Standardized Measure
The standardized measure of discounted future net cash flows ("standardized
measure") and changes in such cash flows are prepared using assumptions required
by the Financial Accounting Standards Board. Such assumptions include the use of
year-end prices for oil and gas and year-end costs for estimated future
development and production expenditures to produce year-end estimated proved
reserves. Discounted future net cash flows are calculated using a 10% rate.
Estimated future income taxes are calculated by applying year-end statutory
rates to future pre-tax net cash flows, less the tax basis of related assets and
applicable tax credits.
The standardized measure does not represent management's estimate of the
Company's future cash flows or the value of proved oil and gas reserves.
Probable and possible reserves, which may become proved in the future, are
excluded from the calculations. Furthermore, year-end prices used to determine
the standardized measure of discounted cash flows, are influenced by seasonal
demand and other factors and may not be the most representative in estimating
future revenues or reserve data.
43
Oil Gas
(Bbls) (Mcf)
------ -------
(in thousands)
PROVED RESERVES
December 31, 1993............................ 21,082 169,119
Revisions.................................. 8,357 1,278
Extensions, additions and discoveries...... 3,981 25,735
Production................................. (3,466) (21,236)
Purchases in place......................... 3,763 4,336
Sales in place............................. (136) (2,171)
------ -------
December 31, 1994............................ 33,581 177,061
Revisions.................................. 1,314 4,507
Extensions, additions and discoveries...... 6,378 41,899
Production................................. (3,532) (28,619)
Purchases in place......................... 3,056 170,711
Sales in place............................. (809) (7,489)
------ -------
December 31, 1995............................ 39,988 358,070
Revisions.................................. 2,361 29,379
Extensions, additions and discoveries...... 2,220 37,480
Production................................. (3,508) (37,275)
Purchases in place......................... 1,552 153,400
Sales in place............................. (173) (516)
------ -------
December 31, 1996............................ 42,440 540,538
====== =======
PROVED DEVELOPED RESERVES
December 31, 1993............................ 17,122 161,240
====== =======
December 31, 1994............................ 26,948 164,169
====== =======
December 31, 1995............................ 28,946 320,230
====== =======
December 31, 1996............................ 31,883 466,412
====== =======
December 31
STANDARDIZED MEASURE OF DISCOUNTED FUTURE ------------------------------------
NET CASH FLOWS RELATING TO PROVED 1996 1995 1994
RESERVES ---------- ---------- ---------
(in thousands)
Future cash inflows...................... $2,634,641 $1,322,345 $ 822,805
Future costs:
Production............................. (819,780) (536,831) (378,431)
Development............................ (77,837) (72,607) (38,246)
---------- ---------- ---------
Future net cash flows before
income tax............................ 1,737,024 712,907 406,128
Future income tax........................ (450,987) (131,019) (61,537)
---------- ---------- ---------
Future net cash flows.................... 1,286,037 581,888 344,591
10% annual discount...................... (579,556) (246,732) (131,445)
---------- ---------- ---------
Standardized measure (a)................. $ 706,481 $ 335,156 $ 213,146
========== ========== =========
(a) Before income tax, the standardized measure (or discounted present value of
future net cash flows) was $946,150,000, $405,706,000 and $247,946,000 at
December 31, 1996, 1995 and 1994, respectively.
44
CHANGES IN STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS
1996 1995 1994
--------- -------- --------
(in thousands)
Standardized measure, January 1........$ 335,156 $213,146 $173,294
--------- -------- --------
Revisions:
Prices and costs..................... 360,053 67,528 8,461
Quantity estimates................... 34,099 8,709 49,337
Accretion of discount................ 37,291 22,242 16,872
Future development costs............. (36,267) (41,416) (31,849)
Income tax........................... (169,118) (36,109) (18,126)
Production rates and other........... (155) (2,682) 683
--------- -------- --------
Net revisions....................... 225,903 18,272 25,378
Extensions, additions and discoveries.. 49,802 44,135 31,268
Production............................. (97,106) (56,909) (50,760)
Development costs...................... 33,484 16,616 16,791
Purchases in place (a)................. 160,670 106,137 18,249
Sales in place......................... (1,428) (6,241) (1,074)
--------- -------- --------
Net change.......................... 371,325 122,010 39,852
--------- -------- --------
Standardized measure, December 31......$ 706,481 $335,156 $213,146
========= ======== ========
(a) Based on the year-end present value (at year-end prices and costs) plus the
cash flow received from such properties during the year, rather than the
estimated present value at the date of acquisition.
Year-end oil prices used in the estimation of proved reserves and
calculation of the standardized measure were $24.25, $18.00, $16.00 and $12.50
per Bbl at December 31, 1996, 1995, 1994 and 1993, respectively. Year-end
average gas prices were $3.02, $1.68, $1.66 and $1.97 per Mcf at December 31,
1996, 1995, 1994 and 1993. Price and cost revisions are primarily the net result
of changes in year-end prices, based on beginning of year reserve estimates.
Quantity estimate revisions during 1994 are primarily the result of the higher
year-end 1994 oil price and the reduction of operating expenses on the Prentice
Northeast Unit, allowing oil reserves to be produced at December 31, 1994 that
were uneconomic to produce at the year-end 1993 oil price of $12.50 per barrel.
Quantity estimate revisions during 1996 are primarily the effect of the extended
economic life of proved reserves that resulted from development workovers and
higher year-end oil and gas prices.
During 1996, the Company acquired 16% of the Royalty Trust's outstanding
Units (Note 9). Proved oil and gas reserves and the standardized measure at
December 31, 1996 include 396,000 Bbls and 6,431,000 Mcf, and $10,784,000,
respectively, attributable to the Company's ownership of the Royalty Trust.
12. SUBSEQUENT EVENT
On March 12, 1997, the Company announced that it intends to offer $165
million of senior subordinated notes due 2007. The offering will be made by
means of an offering memorandum to qualified institutional buyers pursuant to
Rule 144A of the Securities Act of 1933. Net proceeds from the sale of notes
will be used to reduce bank borrowings under the loan agreement.
45
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Cross Timbers Oil Company
We have audited the accompanying consolidated balance sheets of Cross Timbers
Oil Company and its subsidiaries as of December 31, 1996 and 1995, and the
related consolidated statements of operations, cash flows and stockholders'
equity for each of the three years in the period ended December 31, 1996. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Company as of
December 31, 1996 and 1995, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1996, in conformity
with generally accepted accounting principles.
As described in Note 1, effective October 1, 1995, the Company adopted Statement
of Financial Accounting Standards No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 13, 1997
46
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, on the 19th day of March
1997.
CROSS TIMBERS OIL COMPANY
By BOB R. SIMPSON
---------------------------------------
Bob R. Simpson, Chairman of the Board
and Chief Executive 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 19th day of March 1997.
PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS) DIRECTORS
BOB R. SIMPSON CHARLES B. CHITTY
- -------------------------------------------- ----------------------------------
Bob R. Simpson, Chairman of the Board Charles B. Chitty
and Chief Executive Officer
STEFFEN E. PALKO J. LUTHER KING, JR.
- -------------------------------------------- ----------------------------------
Steffen E. Palko, Vice Chairman of the Board J. Luther King, Jr.
and President
J. RICHARD SEEDS
----------------------------------
J. Richard Seeds
SCOTT G. SHERMAN
----------------------------------
Scott G. Sherman
PRINCIPAL FINANCIAL OFFICER PRINCIPAL ACCOUNTING OFFICER
LOUIS G. BALDWIN BENNIE G. KNIFFEN
- -------------------------------------------- ----------------------------------
Louis G. Baldwin, Senior Vice President Bennie G. Kniffen, Senior Vice
and Chief Financial Officer President and Controller
47
INDEX TO EXHIBITS
EXHIBIT
NO. DESCRIPTION PAGE
- ------- ----------------------------------------------------------------- ----
3.1 Certificate of Incorporation of Cross Timbers Oil Company, as
amended through and restated on May 18, 1994 (incorporated by
reference to Exhibit 4.1 to Registration Statement on Form S-8,
File No. 33-81766)
3.2 Bylaws of Cross Timbers Oil Company (incorporated by reference to
Exhibit 3.4 to Registration Statement on Form S-1, File No.
33-59820)
4.1 Form of Indenture dated October 27, 1993, between Cross Timbers
Oil Company and the Bank of New York, as Trustee (incorporated by
reference to Exhibit 4.2 to Registration Statement on Form S-1,
File No. 33-70026)
4.2 Form of Certificate of Designations of Series A Convertible
Preferred Stock, par value $.01 per share (incorporated by
reference to Exhibit 4 to Form 8-A/A, Amendment No. 1, dated
September 3, 1996)
10.1 Revolving Credit Agreement dated June 15, 1995, between Cross
Timbers Oil Company and Morgan Guaranty Trust Company of New
York, NationsBank of Texas, N.A. and the other banks party
thereto (incorporated by reference to Exhibit 10.1 to Form 8-K
dated April 12, 1995)
10.2 Employment Agreement between the Company and Bob R. Simpson,
dated February 21, 1995 (incorporated by reference to
Exhibit 10.6 to Form 10-K for the year ended December 31, 1994)
10.3 Employment Agreement between the Company and Steffen E. Palko,
dated February 21, 1995 (incorporated by reference to Exhibit
10.7 to Form 10-K for the year ended December 31, 1994)
10.4 1991 Stock Incentive Plan (incorporated by reference to Exhibit
10.7 to Registration Statement on Form S-1, File No. 33-59820)
10.5 Form of grant under 1991 Stock Incentive Plan (incorporated by
reference to Exhibit 10.8 to Registration Statement on Form S-1,
File No. 33-59820)
10.6 1994 Stock Incentive Plan (incorporated by reference to Exhibit
4.4 to Registration Statement on Form S-8, File No. 33-81766)
10.7 Form of grant under 1994 Stock Incentive Plan (incorporated by
reference to Exhibit 4.4 to Registration Statement on Form S-8,
File No. 33-81766)
10.8 Registration Rights Agreement among Cross Timbers Oil Company and
partners of Cross Timbers Oil Company, L.P. (incorporated by
reference to Exhibit 10.9 to Registration Statement on Form S-1,
File No. 33-59820)
12.1 Computation of Ratio of Earnings to Fixed Charges
21.1 Subsidiaries of Cross Timbers Oil Company
48
EXHIBIT
NO. DESCRIPTION PAGE
- ------- ----------------------------------------------------------------- ----
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Miller and Lents, Ltd.
- --------------------
Copies of the above exhibits not contained herein are available, at the cost
of reproduction, to any security holder upon written request to the
Secretary, Cross Timbers Oil Company, 810 Houston St., Suite 2000, Fort
Worth, Texas 76102.
49