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1998
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K/A
Amendment No. 2
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
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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)
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Delaware 75-2347769 810 Houston Street, Suite 2000, Fort Worth, Texas 76102
- ----------------------------- ---------------- ------------------------------------------------- ---------
(State or other jurisdiction of (I.R.S. Employer (Address of principal executive offices) (Zip Code)
incorporation or organization) Identification No.)
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Registrant's telephone number, including area code (817) 870-2800
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Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class Name of Each Exchange on Which Registered
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Common stock, $.01 par value New York Stock Exchange
Series A convertible preferred stock, $.01 par value New York Stock Exchange
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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
----- -----
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. X
-----
Aggregate market value of the voting stock held by nonaffiliates of the
Registrant as of March 1, 1999 was approximately $222 million
Number of Shares of Common Stock outstanding as of
March 1, 1999 - 44,727,256
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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, 1999.
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CROSS TIMBERS OIL COMPANY
1998 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
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Item Page
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Part I
1. and 2. Business and Properties 1
3. Legal Proceedings.................................. 15
4. Submission of Matters to a Vote of Security Holders 15
Part II
5. Market for Registrant's Common Equity and Related Stockholder Matters 16
6. Selected Financial Data.............................................. 17
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................ 19
7A. Quantitative and Qualitative Disclosures about Market Risk........... 27
8. Financial Statements and Supplementary Data.......................... 29
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................................. 29
Part III
10. Directors and Executive Officers of the Registrant................... 29
11. Executive Compensation............................................... 29
12. Security Ownership of Certain Beneficial Owners and Management....... 29
13. Certain Relationships and Related Transactions....................... 29
Part IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...... 30
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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 East Texas Basin, the Permian
Basin of West Texas and New Mexico, the Hugoton Field of Oklahoma and Kansas,
the San Juan Basin of northwestern New Mexico, the Green River Basin of Wyoming
and the Middle Ground Shoal Field of Alaska's Cook Inlet.
The Company's estimated proved reserves at December 31, 1998 were 54.5
million barrels ("Bbls") of oil, 1.2 trillion cubic feet ("Tcf") of natural gas
and 17.2 million Bbls of natural gas liquids, based on December 31, 1998 prices
of $9.50 per Bbl for oil, $2.01 per thousand cubic feet ("Mcf") for gas and
$3.99 per Bbl for natural gas liquids. Based on December 31, 1997 prices of
$15.50 per Bbl for oil, and $2.20 per Mcf and $11.07 per Bbl for natural gas
liquids, estimated proved reserves at December 31, 1998 would be 65.9 million
Bbls of oil, 1.2 Tcf of natural gas and 17.7 million Bbls of natural gas
liquids. This compares with December 31, 1997 proved reserves of 47.9 million
Bbls of oil, 815.8 Bcf of natural gas and 13.8 million Bbls of natural gas
liquids. Approximately 80% of December 31, 1998 proved reserves, computed on a
gas energy equivalent ("Mcfe") basis, were proved developed reserves. Increased
proved reserves during 1998 were primarily the result of predominantly gas-
producing property acquisitions and development and exploitation activities,
partially offset by production. During 1998, the Company's daily oil and gas
production averaged 12,598 Bbls and 229,717 Mcf. Fourth quarter 1998 daily oil
and gas production averaged 14,991 Bbls and 265,702 Mcf. Following its December
1997 acquisition of gas-producing properties in the San Juan Basin, the Company
began separate reporting of natural gas liquids production. During 1998, daily
natural gas liquids production averaged 3,347 Bbls per day.
The Company's properties have relatively long reserve lives and highly
predictable well production profiles. Based on December 31, 1998 proved reserves
and projected 1999 production, the average reserve-to-production index of the
Company's proved reserves is 12.6 years. In general, the Company's properties
have extensive production histories and production enhancement opportunities.
While the properties are geographically diversified, the major 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. As of December 31, 1998, the Company owned
interests in 8,901 gross (3,281 net) wells and operated wells representing
approximately 87% of the present value of cash flows before income taxes
(discounted at 10%) from estimated proved reserves. The Company operates the
majority of its properties, allowing it to control expenses, capital allocation
and the timing of development and exploitation activities in its fields. This
also allows the Company to reduce production costs on acquired properties.
The Company has generated a substantial inventory of approximately 1,075
potential development drilling locations within its existing properties (of
which 585 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's drilling plans are dependent upon product prices.
In 1998, the Company began to emphasize exploration of unproved reserves as
part of its business strategy. During the year, the Company expensed $8 million
in connection with its exploration program, primarily including seismic and
other geological and geophysical analysis costs. The Company has allocated less
than 5% of its $60 million 1999 development budget for exploration activities.
The Company employs a disciplined acquisition program refined by senior
management to augment its core properties and expand its reserve base. Its
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.
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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, the Company has also operated 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 current market prices. The
Company also markets its oil and gas, including sales of gas under forward sales
contracts and uses futures contracts and other price risk management instruments
to hedge pricing risks. See Part II, Item 7A. The Company markets its gas
production and the gas output of its gathering and processing systems. The
Company arranges for some of its natural gas to be processed by unaffiliated
third parties and markets the natural gas liquids from that processing.
History of the Company
The Company was incorporated in Delaware in 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.
During 1991, predecessors of the Company formed Cross Timbers Royalty Trust
by carving net profits interests out of substantially all of the royalty and
overriding royalty interests that the Company's predecessors then owned in
Texas, New Mexico and Oklahoma, and seven nonoperated working interest
properties in Texas and Oklahoma. The Company makes monthly net profits
payments to Cross Timbers Royalty Trust based on revenues received and costs
disbursed for the properties from which the net profits interests were carved.
Cross Timbers Royalty Trust units are listed on the New York Stock Exchange
under the symbol "CRT." From 1996 to 1998, the Company purchased 1,360,000, or
22.7%, of the outstanding units. The Board of Directors has authorized the
purchase of up to two million, or 33%, of the outstanding units. In June 1998,
the Company and Cross Timbers Royalty Trust filed a registration statement with
the Securities and Exchange Commission ("Commission") to register the Company's
1,360,000 units for sale in a public offering. The filing of the registration
statement has been made in anticipation of improving commodity prices and
related market conditions for oil and gas equities.
In December 1998, the Company formed the Hugoton Royalty Trust by conveying
an 80% net profits interest in properties located in the Hugoton area of Kansas
and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of
Wyoming. These properties represent approximately 30% of the Company's existing
reserve base. Hugoton Royalty Trust units will be listed on the New York Stock
Exchange under the symbol "HGT." The Company filed a registration statement with
the Commission in December 1998 and plans to offer approximately 40% of the
Hugoton Royalty Trust units to the public in March or April 1999.
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 sinking to a five-year low at the end of 1993, oil
prices reached their highest levels since the 1990 Persian Gulf War during
fourth quarter 1996 and January 1997. Posted crude oil prices ranged from $17 to
$20 during most of 1997, then declined to a $16 average in December 1997. Crude
oil prices continued to decline throughout 1998, dropping to a West Texas
Intermediate price of $8.00 per barrel in December 1998, the lowest level since
1978. This decline has been caused by low demand, as well as the failure of
OPEC, at its November 1998 meeting, to further reduce production quotas. Low
demand has been caused by warmer than normal winter temperatures and a slow
recovery in Asian economies.
Natural gas prices are influenced by national and regional supply and
demand, which is often dependent upon weather conditions. Natural gas competes
with alternative energy sources as a fuel for heating and the generation of
electricity. Generally because of colder weather, storage concerns and U.S.
economic growth, prices remained relatively high during most of 1996 and 1997,
reaching their highest levels since 1985. Gas prices declined, however, in
December 1997 and have remained lower throughout 1998, primarily because the
winters of 1997-1998 and 1998-1999 were abnormally mild in the central and
eastern U.S.
2
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Business Strategy
The primary components of the Company's business strategy are:
- acquiring long-lived, operated oil and gas properties,
- increasing production and reserves through aggressive management of
operations and through development, exploitation and exploration
activities, and
- 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, operated producing properties that:
- contain complex multiple-producing horizons with the potential for
increases in reserves and production,
- are in the Company's core operating areas or in areas with similar
geologic and reservoir characteristics, and
- present opportunities to reduce expenses, per Mcfe produced, 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 development 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 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 low-risk development. The Company believes that its principal
properties possess geologic and reservoir characteristics that make them well
suited for production increases through development and drilling programs. The
Company has generated an inventory of approximately 1,075 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 gathering and other surface
facilities and conducting restimulations and recompletions. The Company may
also initiate, upgrade or revise existing secondary recovery operations and
drill development wells.
Exploration Activities. During 1999, the Company will focus on exploration
projects that are near currently owned productive fields and have the potential
to add substantially to proved reserves and cash flow. 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. The Company has allocated less than 5% of its $60
million 1999 development budget for exploration activities.
Experienced Management and Technical Staff. Most 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 it will not operate ("nonoperated interests") if such
interests otherwise meet its acquisition criteria. The Company attempts to
3
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acquire nonoperated interests in fields operated by established oil companies if
these 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 accumulating,
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.
Royalty Trust Plan. In December 1998, the Company created the Hugoton
Royalty Trust and plans to sell approximately 40% of the trust to the public in
March or April 1999. The Company has announced its plans to create two
additional royalty trusts, one for the San Juan Basin area and one for the
Permian Basin area. Sales of royalty trust units will allow the Company to more
efficiently capitalize its mature, lower growth properties. The remaining
Company will continue its growth strategy by acquiring and developing properties
that meet its acquisition criteria in order to grow its reserve base.
Business Goals. In May 1998, the Company announced strategic goals for
1999, including increasing cash flow to $4.00 per share and proved reserves to
36 Mcfe per share, and reducing debt to 40 cents per Mcfe. These goals were
based on commodity prices of $18 per Bbl of oil and $2.20 per Mcf of gas, net to
the Company. For 1998, operating cash flow per share was $1.81, while year-end
proved reserves per share were 36.7 Mcfe and debt per Mcfe was $0.56. While the
Company believes it was on course with production and costs to achieve its cash
flow goal, current lower commodity prices make its achievement unlikely in 1999.
The Company's 1999 goal of reducing debt by as much as $300 million is expected
to reduce debt per Mcfe to 40 to 45 cents. The Company plans to reduce debt
with operating cash flow and proceeds from the sale of royalty trust units,
producing properties and equity securities.
The Company also announced its plans to make strategic acquisitions
totaling $150 million from May 1998 through the end of 1999. After closing the
Cook Inlet Acquisition in September 1998, the Seagull Acquisition in November
1998, and other smaller acquisitions in the last half of 1998, the Company has
achieved approximately two-thirds of this goal. No further significant
acquisitions are expected until the Company has substantially met its debt
reduction goal.
The Company has budgeted $60 million for its 1999 development program which
is expected to be funded primarily by cash flow from operations. Exploration
expenditures are expected to be less than 5% of the 1999 budget. The total
capital budget, including acquisitions, will be adjusted throughout 1999
depending on oil and gas prices to capitalize on opportunities offering the
highest rates of return.
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 of oil and 171 Bcf of natural gas.
During 1996, the Company acquired predominantly gas-producing properties
for a total cost of $106 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 $28.1 million. From July through December
1996, the Company acquired 955,800 units, or 16% of the publicly traded
outstanding units, of Cross Timbers Royalty Trust, at a total cost of $12.8
million. The 1996 acquisitions increased proved reserves by approximately 1.6
million Bbls of oil and 153.4 Bcf of natural gas.
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During 1997, the Company acquired predominantly gas-producing properties
for a total cost of $256 million. The Amoco Acquisition, the largest of these
acquisitions, closed December 1, 1997 at an estimated adjusted purchase price of
$195 million, including five-year warrants to purchase 937,500 shares of the
Company's common stock at a price of $15.31 per share. This acquisition
consists primarily of operated properties in the San Juan Basin of New Mexico.
In May 1997, the Company acquired primarily gas-producing properties in
Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39
million. The Company also acquired an additional 370,500 units, or 6%, of the
Cross Timbers Royalty Trust units at a cost of $5.4 million. The 1997
acquisitions increased proved reserves by approximately 3.2 million Bbls of oil,
248 Bcf of natural gas and 13.9 million Bbls of natural gas liquids.
During 1998, the Company acquired oil- and gas-producing properties for a
total cost of $340 million. The East Texas Basin Acquisition was the largest of
these acquisitions. The purchase closed on April 24, 1998 at an estimated price
of $245 million which was reduced to $215 million by a $30 million production
payment sold to EEX Corporation. In September 1998, the Company acquired oil-
producing properties in the Middle Ground Shoal Field of Alaska's Cook Inlet in
exchange for 1,921,850 shares of the Company's common stock along with certain
price guarantees and a non-interest bearing note payable of $6 million,
resulting in an estimated purchase price of $44.4 million. The Company also
acquired primarily gas-producing properties in northwest Oklahoma and the San
Juan Basin of New Mexico for an estimated purchase price of $29.2 million. The
1998 acquisitions increased reserves by approximately 16.3 million Bbls of oil
and 311.3 Bcf of natural gas.
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, 1998 (in thousands):
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Proved Reserves
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Natural Gas Present Value
Liquids before Income Tax of
Oil (Bbls) Gas (Mcf) (Bbls) Proved Reserves
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East Texas......... 2,127 317,947 - $234,825 25.8%
San Juan Basin..... 1,199 253,568 17,174 170,868 18.8%
Mid-Continent...... 4,495 189,374 - 163,282 18.0%
Permian Basin...... 32,295 95,356 - 116,816 12.9%
Rocky Mountain..... 2,481 183,830 - 110,390 12.1%
Hugoton............ 232 159,128 - 89,745 9.9%
Alaska Cook Inlet.. 11,437 - - 12,719 1.4%
Other (a).......... 244 10,021 - 9,961 1.1%
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Total.............. 54,510 1,209,224 17,174 $908,606 100%
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(a) Includes 209,000 Bbls and 8,278,000 Mcf and discounted present value
before income tax of $8,109,000 related to the Company's ownership of
approximately 22% of Cross Timbers Royalty Trust units at December 31,
1998.
Permian Basin Area
Prentice Field. The Prentice Field is located in Terry and Yoakum
Counties, Texas. In 1993 and 1994, the Company acquired its 91.5% working
interest in the 178-well Prentice Northeast Unit in four separate transactions,
resulting in the Company's assumption of operations of the unit effective March
1, 1994. 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.
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During 1998, the Company drilled 1 gross (0.91 net) horizontal sidetrack in
the Prentice Northeast Unit. The Company is currently studying additional areas
in the unit for future development using horizontal technology.
Ozona Area. The Company acquired interests in 1996 in the Henderson,
Ozona, and Davidson Ranch fields located in Crockett County, Texas. The Company
has interests in 125 gross (73.3 net) wells that it operates and 144 gross (30.2
net) wells operated by others.
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 possible horizontal
drilling in the Strawn Formation.
During 1998, the Company drilled a total of 18 gross (11.2 net) operated
wells and participated in 3 gross (1.1 net) wells operated by others, making it
one of the Company's most active gas development areas. The Company is
currently evaluating 50 locations for possible future development.
University Block 9. The University Block 9 Field is located in Andrews
County, Texas. The Company owns a 100% working interest in 64 wells that it
operates. 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 operates the Wolfcamp Unit, Penn Unit and 33 of the
34 active Devonian wells. Development potential includes proper wellbore
utilization, recompletions, infill drilling and improvement of waterflood
efficiency.
This field was the Company's most active oil development area during 1998,
where the Company drilled 8 horizontal and vertical wells, 3 of which were being
completed at year-end. The Company also recompleted four Devonian wells into
the Pennsylvanian horizon. During 1999, the Company plans to drill up to 6
wells, depending on oil prices. An additional 30 to 40 locations have been
identified for future development by either drilling or horizontal sidetrack.
Mid-Continent Area
A substantial portion of properties in the Mid-Continent area are subject
to an 80% net profits interest conveyed to the Hugoton Royalty Trust as of
December 1998. The Company plans to sell approximately 40% of its Hugoton
Royalty Trust units in March or April 1999.
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 496 gross (427.4 net) wells and has an interest in 251
gross (52.5 net) wells operated by others.
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 1998, the Company participated in the drilling of 18 gross
(14.0 net) wells in the western portion of the County, targeted at the
Mississippian and Chester formations. The Company has budgeted 9 wells in Major
County for 1999.
The Company operates a gathering system and pipeline in the Major County
area. The gathering system collects gas from over 400 wells through 300 miles
of pipeline in the Major County area. The gathering system has current
throughput of approximately 25,500 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 plant owned and operated by a third
party, and then transmitted by a 26-mile Company-operated pipeline to
connections with other pipelines.
6
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East Texas Area
The Company acquired most of its producing properties in the East Texas
area in April 1998. These properties are located in East Texas and northwestern
Louisiana and produce primarily from the Travis Peak, Cotton Valley and Rodessa
formations between 7,000 feet and 12,000 feet in eight major fields. Oil and
gas were first discovered in the East Texas area in the 1930's.
The Company owns an interest in 620 gross (590 net) wells which it operates
and 123 gross (14.9 net) wells operated by others. The Company also owns the
related gathering facilities. The East Texas properties also include more than
12,800 net undeveloped acres located primarily in Anderson County, Texas.
During 1998, the Company drilled 10 net wells to the Travis peak formation,
most of which were at various stages of completion at year end. The Company has
identified over 170 drill well locations and over 300 workover and recompletion
projects in this area. Approximately one-half of the Company's 1999 budget is
directed to development in the East Texas area, including 75 workovers and 20
drill wells.
Hugoton Area
Most of the Company's properties in the Hugoton area are subject to an 80%
net profits interest conveyed to the Hugoton Royalty Trust as of December 1998.
The Company plans to sell approximately 40% of its Hugoton Royalty Trust units
in March or April 1999.
The Hugoton Field, discovered in 1922, covers parts of Texas, Oklahoma and
Kansas and is the largest gas field in North America. It is estimated that five
million productive acres exist in the entire field. The Company owns an
interest in 399 gross (373.9 net) wells that it operates and 86 gross (20.4 net)
wells operated by others.
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 south end of
the Tyrone gathering system. 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. During 1998, the Company completed the
acquisition of approximately 70 miles of low pressure gathering lines, adding
3,500 Mcf per day to the existing system.
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 35
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 1998, the Company drilled 15 gross (12.0 net) wells to the Chester,
Council Grove and Chase formations. The Company plans to drill 13 wells during
1999.
Rocky Mountain Area
San Juan Basin. The San Juan Basin of northwestern New Mexico and
southwestern Colorado contains the largest reserves of natural gas in the Rocky
Mountains and, within North America, is second in size only to the Hugoton
Field. The Company acquired most of its interests in the San Juan Basin in
December 1997 from Amoco Corporation. The Company owns an interest in 644 gross
(514.4 net) wells that it operates and 1,384 gross (186.1 net) wells operated by
others. Of these wells, 66 gross (56.2 net) operated wells and 15 gross (2.8
net) non-operated wells are dual completions.
During 1998, the Company participated in the drilling of 48 wells,
completed 15 workovers and installed 78 wellhead compressors. The Company has
identified over 300 drill well locations and over 100 workover and recompletion
projects. During 1999, the Company plans to drill 41 wells (23 operated),
recomplete 30 wells and install 40 wellhead compressors.
7
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Green River Basin. The Green River Basin is located in southwestern
Wyoming. The Company has interests in 174 gross (166.9 net) wells that it
operates and 70 gross (9.4 net) wells operated by others in the Fontenelle,
Nitchie Gulch and Pine Canyon fields.
Substantially all properties in the Green River Basin are subject to an 80%
net profits interest conveyed to the Hugoton Royalty Trust as of December 1998.
The Company plans to sell approximately 40% of its Hugoton Royalty Trust units
in March or April 1999.
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. Development potential for the fields
in this area include deepening and opening new producing zones in existing
wells, drilling new wells and adding compression to lower line pressures.
During 1998, the Company drilled 20 net wells in the Fontenelle Unit and
plans to drill approximately 5 wells during 1999. In 1997, the Company
installed additional field compression to lower overall field operating
pressures and to improve overall field performance. The Company also completed
an interconnect to another pipeline in the southeastern part of the Fontenelle
Field that added an additional market for the gas.
Alaska Cook Inlet Area
In September 1998, the Company acquired a 100% working interest in two
State of Alaska leases and the offshore installations located in the Middle
Ground Shoal Field of the Cook Inlet. The properties include two operated
production platforms set in 70 feet of water about seven miles offshore and a
50% interest in certain operated production pipelines and onshore processing
facilities.
Oil was first discovered in the Cook Inlet in 1966. Production from the
29 operated wells is primarily from multiple zones within the Miocene-Oligocene-
aged Tyonek formation between 7,300 feet and 10,000 feet subsea.
No significant development operations are anticipated in 1999. The Company
is conducting engineering and geologic studies, the results of which should be
implemented in 2000, depending on oil prices.
8
<PAGE>
Reserves
The following are estimated quantities of proved reserves and cash flows
therefrom as of December 31, 1998, 1997 and 1996:
<TABLE>
<CAPTION>
December 31
----------------------------------
1998 1997 1996
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Proved developed:
Oil (Bbls)......................... 42,876 33,835 31,883
Gas (Mcf).......................... 968,495 677,710 466,412
Natural gas liquids (Bbls)......... 14,000 11,494 -
Proved undeveloped:
Oil (Bbls)......................... 11,634 14,019 10,557
Gas (Mcf).......................... 240,729 138,065 74,126
Natural gas liquids (Bbls)......... 3,174 2,316 -
Total proved:
Oil (Bbls)......................... 54,510 47,854 42,440
Gas (Mcf).......................... 1,209,224 815,775 540,538
Natural gas liquids (Bbls)......... 17,174 13,810 -
Estimated future net cash flows:
Before income tax.................. $1,677,426 $1,484,542 $1,737,024
After income tax................... $1,446,177 $1,193,167 $1,286,037
Present value of estimated future
net cash flows, discounted at 10%:
Before income tax.................. $ 908,606 $ 782,322 $ 946,150
After income tax................... $ 808,403 $ 642,109 $ 706,481
</TABLE>
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, 1998, 1997 and 1996. As prescribed by the 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. Based
on December 31, 1997 prices of $15.50 per Bbl for oil, $2.20 per Mcf and $11.07
per Bbl for natural gas liquids, estimated proved reserves at December 31, 1998
would be 65.9 million Bbls of oil, 1.2 Tcf of natural gas and 17.7 million Bbls
of natural gas liquids. See Note 14 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 1998, the Company filed estimates of oil and gas reserves as of
December 31, 1997 with the U.S. Department of Energy on Form EIA-23. These
estimates are consistent with the reserve data reported in Note 14 to
Consolidated Financial Statements for the year ended December 31, 1997, with the
exception that Form EIA-23 includes only reserves from properties operated by
the Company.
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.
9
<PAGE>
Producing Wells
The following table summarizes the Company's producing wells as of December
31, 1998, all of which are located in the United States:
<TABLE>
<CAPTION>
Operated Wells Non-Operated Wells Total (a)
----------------- ------------------ -----------------
Gross Net Gross Net Gross Net
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Oil........... 642 589.7 3,595 203.2 4,237 792.9
Gas........... 2,480 2,155.4 2,184 333.1 4,664 2,488.5
----- ------- ----- ----- ----- -------
Total......... 3,122 2,745.1 5,779 536.3 8,901 3,281.4
===== ======= ===== ===== ===== =======
</TABLE>
(a) Two gross (1.5 net) oil wells and 86 gross (60 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. As of December 31, 1998, the Company
was in the process of drilling 52 gross (33.8 net) wells.
<TABLE>
<CAPTION>
Year Ended December 31
--------------------------------------
1998 1997 1996
----------- ------------ -----------
Gross Net Gross Net Gross Net
----- ---- ----- ----- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Development wells:
Completed as-
Oil wells........ 53 14.1 82 53.4 92 45.5
Gas wells........ 139 63.4 119 85.9 70 38.1
Non-productive..... 1 - 5 3.2 4 2.7
--- ---- ---- ----- --- ----
Total.............. 193 77.5 206 142.5 166 86.3
--- ---- ---- ----- --- ----
Exploratory wells:
Completed as-
Gas wells........ 3 3.0 2 0.6 - -
Non-productive..... 2 1.0 1 0.1 - -
--- ---- ---- ----- --- ----
Total.............. 5 4.0 3 0.7 - -
--- ---- ---- ----- --- ----
Total (a)........... 198 81.5 209 143.2 166 86.3
=== ==== ==== ===== === ====
</TABLE>
(a) Included in totals are 118 gross (14.6 net) wells in 1998, 57 gross
(6.9 net) wells in 1997 and 85 gross (10.4 net) wells in 1996 drilled
on nonoperated interests. Excluded from above totals are 21 gross (0.4
net) carbon dioxide wells drilled on non-operated interests in 1996.
10
<PAGE>
Acreage
The following table summarizes developed and undeveloped leasehold acreage
in which the Company owns a working interest as of December 31, 1998. Excluded
from this summary is acreage in which the Company's interest is limited to
royalty, overriding royalty and other similar interests.
<TABLE>
<CAPTION>
Developed (a)(b) Undeveloped
------------------ -------------------
Gross Net Gross Net
--------- ------- ------ -----------
<S> <C> <C> <C> <C>
Oklahoma.... 355,303 289,225 15,821 7,143
Texas....... 268,264 172,859 36,489 25,041
New Mexico.. 232,205 172,049 5,094 4,030
Kansas...... 80,225 67,951 -0- -0-
Wyoming..... 56,583 34,933 2,811 1,906
Other....... 41,699 28,737 31,053 23,876
--------- ------- ------ ------
Total....... 1,034,279 765,754 91,268 61,996
========= ======= ====== ======
</TABLE>
(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 Cross Timbers Royalty Trust, and in
Oklahoma, Kansas and Wyoming is subject to an 80% net profits interest
conveyed to the Hugoton Royalty Trust.
Oil and Gas Sales Prices and Production Costs
The following table shows the average sales prices per Bbl of oil
(including condensate), Mcf of gas and per Bbl of natural gas liquids produced
and the production costs and taxes, transportation and other per thousand cubic
feet of gas equivalent ("Mcfe," computed on an energy equivalent basis of 6 Mcf
to 1 Bbl):
<TABLE>
<CAPTION>
Year Ended December 31
----------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Sales prices:
Oil (per Bbl)........................... $12.21 $18.90 $21.38
Gas (per Mcf)........................... $ 2.07 $ 2.20 $ 1.97
Natural gas liquids (per Bbl)........... $ 7.62 $ 9.66 $ -
Production costs per Mcfe................. $ 0.53 $ 0.59 $ 0.67
Taxes, transportation and other per Mcfe.. $ 0.25 $ 0.22 $ 0.20
</TABLE>
Delivery Commitments
The Company contracted to sell to a single purchaser approximately 11,650
Mcf of gas per day through May 2000 and 21,650 Mcf of gas per day from June 2000
through July 2005. Deliveries under this contract are generally in Oklahoma.
The Company has committed to sell all gas production from certain
properties in the East Texas Basin Acquisition to EEX Corporation at market
prices through the earlier of December 31, 2001, or until a total of
approximately 34.3 billion cubic feet (27.8 billion cubic feet net to the
Company's interest) of gas has been delivered. Based on current production, this
sales commitment is approximately 24,700 Mcf (20,000 Mcf net to the Company's
interest) per day.
Under the terms of its amended purchase and sale agreement with Shell for
the Cook Inlet Acquisition, the Company has committed to sell to Shell,
beginning March 1, 1999, the following minimum daily natural gas volumes: 42,000
Mcf in 1999, 40,000 Mcf in 2000, 37,500 Mcf in 2001, 36,500 Mcf in 2002 and
35,000 Mcf in 2003. Delivery
11
<PAGE>
of 20,000 Mcf per day of committed sales volumes is in the San Juan Basin, and
delivery of the remaining volumes is in the East Texas Basin.
The Company's production and reserves are adequate to meet the above sales
commitments.
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. Factors that affect the Company's ability to acquire producing
properties include 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 is effective
in competing 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 systems and 26-mile pipeline have been declared exempt from FERC
jurisdiction, and therefore, the Company's gathering service is not regulated by
FERC. 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.
Petitions for rehearing on Order No. 636-C were denied on May 28, 1998. FERC's
order remains 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,
12
<PAGE>
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 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. These rules have had little, if any, effect on the Company with
respect to the cost of moving oil to market.
State Regulation
Oil and gas operations 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 production
by well and the number of wells or locations that can be drilled.
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 that can
be charged 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 have recently adopted regulations with respect to
gathering systems, and other states are considering regulations with respect to
gathering systems. New regulations passed have not had a material effect on the
operations of the Company's gathering systems, but the Company cannot predict
whether any further rules will be adopted or, if adopted, the effect these rules
may have on its gathering systems.
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 521 employees as of December 31, 1998. None of the
Company's employees are represented by a union. The Company considers its
relations with its employees to be good.
13
<PAGE>
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, 50, 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.
Steffen E. Palko, 48, 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.
J. Richard Seeds, 53, has been a director of the Company since July 1996
and has served as Executive Vice President since May 1997. Mr. Seeds previously
was Career Guidance Counselor with the Springtown Independent School District
(1993-1997), an independent personal investment manager and consultant to the
San Juan Basin Royalty Trust, the Permian Basin Royalty Trust and the Cross
Timbers Royalty Trust (1986-1993). Mr. Seeds was Vice President of Finance and
Controller (1979-1986) and Controller (1977-1979) of Southland Royalty Company.
Louis G. Baldwin, 49, 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, 40, 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, 48, 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, 52, 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).
Timothy L. Petrus, 44, has been Senior Vice President - Acquisitions or
held similar positions with the Company since 1988. Prior to that time, Mr.
Petrus was a Vice President with Texas American Bank (1980-1988) and was a
Senior Project Engineer with Exxon (1976-1980).
Kenneth F. Staab, 42, 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, 52, 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, 44, 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).
14
<PAGE>
Item 3. Legal Proceedings
On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross
Timbers Oil Company, was filed against the Company in the District Court of
Dewey County, Oklahoma. The action was filed on behalf of all persons who, at
any time since June 1991, have been paid royalties on gas produced from any gas
well within the State of Oklahoma under which the Company has assumed the
obligation to pay royalties. The plaintiffs allege that the Company has reduced
royalty payments by post-production deductions and has entered into contracts
with subsidiaries that were not arms-length transactions, which actions reduced
the royalties paid to the plaintiffs and those similarly situated, and that such
actions are a breach of the leases under which the royalties are paid. The
plaintiffs are seeking an accounting and payment of the monies allegedly owed to
them. The Company filed motions to dismiss the action due to lack of proper
venue, which motions were denied. This decision denying the motions is being
appealed. A hearing on the class certification issue has not been scheduled.
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.
On October 17, 1997, an action, styled United States of America ex rel.
Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District
Court for the Western District of Oklahoma against the Company and certain of
its subsidiaries by Jack J. Grynberg on behalf of the United States under the
qui tam provisions of the False Claims Act. The Company was not made aware of
the claim until the U.S. Justice Department contacted the Company in August
1998. The plaintiff alleges that the Company underpaid royalties on gas produced
from federal leases and lands owned by Native Americans by at least 20% during
the past 10 years as a result of mismeasuring the volume of gas and incorrectly
analyzing its heating content. According to the U.S. Justice Department, the
plaintiff has made similar allegations in actions filed against over 300
companies. The plaintiff seeks to recover the amount of royalties not paid,
together with treble damages, a civil penalty of $5,000 to $10,000 for each
violation and attorney fees and expenses. The Company has not been served with
this complaint which is under review by the U.S. Justice Department. The Company
has filed a response with the U.S. Justice Department and is awaiting its
decision whether to intervene in the case. The Company believes that the
allegations of this lawsuit are without merit and intends to vigorously defend
the action.
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 lawsuits 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 1998.
15
<PAGE>
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 1998 and 1997
(as adjusted for the three-for-two stock splits effected on March 19, 1997 and
February 25, 1998):
<TABLE>
<CAPTION>
High Low Dividends
--------- --------- ---------
<S> <C> <C> <C>
1998
First Quarter... $ 21.125 $ 14.672 $.040
Second Quarter.. 20.875 16.375 .040
Third Quarter... 19.313 11.375 .040
Fourth Quarter.. 16.813 5.063 .040
1997
First Quarter... $ 13.719 $ 10.422 $.037
Second Quarter.. 13.750 9.828 .037
Third Quarter... 16.375 12.328 .037
Fourth Quarter.. 19.125 13.297 .037
</TABLE>
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 Revolving Credit Agreement
with banks restricts the amount of dividends to 25% of cash flow from operations
for the latest four consecutive quarterly periods. The Company's 9 1/4% and 8
3/4% senior subordinated notes also place certain restrictions on distributions
to common shareholders, including dividend payments.
On February 16, 1999, the Board of Directors reduced the Company's
quarterly dividend to $.01 per share from $.04 payable on April 15, 1999 to
shareholders of record on March 31, 1999. The reduction was made in response to
the low commodity price environment and the Company's 1999 goal to reduce debt
by $300 million.
On March 1, 1999, the Company had 547 shareholders of record.
16
<PAGE>
Item 6. Selected Financial Data
The following table shows selected financial information for the five years
ended December 31, 1998. Significant producing property acquisitions in each of
the years presented affect the comparability of year-to-year financial and
operating data. All weighted average shares and per share data have been
adjusted for the three-for-two stock splits effected in March 1997 and February
1998. This information should be read in conjunction with Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements at Item 14(a).
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
-------------- ----------- ----------- ------------- ---------
(in thousands except production, per share and per unit data)
<S> <C> <C> <C> <C> <C>
Consolidated Statement of Operations Data
Revenues:....................................
Oil and condensate.......................... $ 56,164 $ 75,223 $ 75,013 $ 60,349 $ 53,324
Gas and natural gas liquids................. 182,587 110,104 73,402 40,543 38,389
Gas gathering, processing and marketing..... 9,438 9,851 12,032 7,091 4,274
Other....................................... 1,297 3,094 888 3,362 288
--------- ---------- --------- --------- --------
Total Revenues.............................. $ 249,486 $ 198,272 $ 161,335 $ 111,345 $ 96,275
========== ========== ========= ========= ========
Earnings (loss) available to common stock.... $ (71,498) (a) $ 23,905 $ 19,790 (10,538) (b) $ 3,048
========== ========== ========= ========= ========
Per common share
Basic....................................... $ (1.65) (a) $ 0.60 $ 0.50 $ (0.28) (b) $ 0.09
========== ========== ========= ========= ========
Diluted..................................... $ (1.65) (a) $ 0.59 $ 0.48 $ (0.28) (b) $ 0.08
========== ========== ========= ========= ========
Weighted average common shares outstanding... 43,396 39,773 39,913 38,072 35,829
========== ========== ========= ========= ========
Dividends declared per common share.......... $ 0.16 $ 0.15 $ 0.13 $ 0.13 $ 0.13
========== ========== ========= ========= ========
Consolidated Statement of Cash Flows Data
Cash provided (used) by:
Operating activities........................ $ (45,842) $ 98,006 $ 59,694 $ 32,938 $ 42,293
Investing activities........................ $ (384,598) $ (311,322) $(124,871) $(160,416) $(62,745)
Financing activities........................ $ 438,957 $ 213,195 $ 66,902 $ 121,852 $ 26,232
Consolidated Balance Sheet Data:
Property and equipment, net.................. $1,051,011 $ 723,836 $ 450,561 $ 364,474 $244,555
Total assets................................. $1,207,594 $ 788,455 $ 523,070 $ 402,675 $292,451
Long-term debt............................... $ 921,000 $ 539,000 $ 314,757 $ 238,475 $142,750
Stockholders' equity......................... $ 177,451 $ 170,243 $ 142,668 $ 130,700 $113,333
Operating Data:
Average daily production:
Oil (Bbls).................................. 12,598 10,905 9,584 9,677 9,497
Gas (Mcf)................................... 229,717 135,855 101,845 78,408 58,182
Natural gas liquids (Bbls).................. 3,347 220 - - -
Mcfe........................................ 325,390 202,609 159,349 136,470 115,164
Average sales price:
Oil (per Bbl)............................... $ 12.21 $ 18.90 $ 21.38 $ 17.09 $ 15.38
Gas (per Mcf)............................... $ 2.07 $ 2.20 $ 1.97 $ 1.42 $ 1.81
Natural gas liquids (per Bbl)............... $ 7.62 $ 9.66 - - -
Production expense (per Mcfe)................ $ 0.53 $ 0.59 $ 0.67 $ 0.71 $ 0.77
Taxes, transportation and other (per Mcfe)... $ 0.25 $ 0.22 $ 0.20 $ 0.17 $ 0.21
Proved reserves:
Oil (Bbls).................................. 54,510 47,854 42,440 39,988 33,581
Gas (Mcf)................................... 1,209,224 815,775 540,538 358,070 177,061
Natural gas liquids (Bbls).................. 17,174 13,810 - - -
Mcfe........................................ 1,639,331 1,185,759 795,178 597,998 378,547
Other Data
Operating cash flow (c)...................... $ 78,480 $ 89,979 $ 68,263 $ 40,439 $ 37,816
Ratio of earnings to fixed charges (d)....... (0.7) (e) 2.2 2.6 (0.2) (f) 1.5
</TABLE>
17
<PAGE>
(a) Includes effect of a $93.7 million pre-tax net loss on investment in
equity securities and a $2 million pre-tax, non-cash impairment charge.
(b) 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.
(c) Defined as cash provided by operating activities before changes in
current assets and liabilities. Because of exclusion of changes in
current assets and liabilities, this cash flow statistic is different
from cash provided (used) by operating activities, as is disclosed
under generally accepted accounting principles.
(d) 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.
(e) Includes effect of the items in (a) above. Excluding the effect of
these items, the ratio of earnings to fixed charges is 0.8.
(f) Includes effect of the charge in (b) above. Excluding the effect of
this charge, the ratio of earnings to fixed charges is 1.3.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion and analysis should be read in conjunction with
Item 6, Selected Financial Data and the Company's consolidated financial
statements.
General
The following events affect the comparability of results of operations and
financial condition for the years ended December 31, 1998, 1997 and 1996, and
may impact future operations and financial condition. Throughout this
discussion, the term "Mcfe" refers to thousands of cubic feet of gas equivalent
quantities produced for the indicated period, with oil quantities converted to
Mcf on an energy equivalent ratio of one barrel to six Mcf.
Three-for-Two Stock Splits. The Company effected a three-for-two stock split on
March 19, 1997 and on February 25, 1998. All common stock shares, treasury
stock shares and per share amounts have been retroactively restated to reflect
both stock splits.
1998 Acquisitions. During 1998, the Company acquired oil- and gas-producing
properties for a total cost of $340 million, including:
- The East Texas Basin Acquisition. The Company acquired these primarily
gas-producing properties for an estimated purchase price of $245
million, later reduced to $215 million by a $30 million production
payment sold to EEX Corporation. This acquisition closed on April 24,
1998 and was funded by bank debt, partially repaid from proceeds of the
1998 Common Stock Offering.
- The Alaska Cook Inlet Acquisition. In September 1998, the Company
acquired these oil-producing properties in exchange for 1,921,850 shares
of the Company's common stock along with certain price guarantees and a
non-interest bearing note payable of $6 million, resulting in an
estimated purchase price of $44.4 million.
- The Seagull Acquisition. This acquisition includes primarily gas-
producing properties in northwest Oklahoma and the San Juan Basin of New
Mexico. The Company acquired these properties in November 1998 for an
estimated purchase price of $29.2 million, funded by bank borrowings.
1997 Acquisitions. During 1997, the Company acquired predominantly gas-
producing properties for a total cost of $256 million, funded primarily by bank
borrowings and cash flow from operations. The acquisitions include:
- The Amoco Acquisition. The Company purchased these properties in the San
Juan Basin of New Mexico in December 1997 for an estimated adjusted
purchase price of $195 million. This purchase price includes $5.7
million for five-year warrants to purchase 937,500 shares of the
Company's common stock at $15.31 per share.
- The Burlington Resources Acquisition. The Company purchased these
properties in Oklahoma, Kansas and Texas for an estimated adjusted
purchase price of $39 million in May 1997.
- 6% of the publicly traded outstanding units in Cross Timbers Royalty
Trust, at a cost of $5.4 million.
1996 Acquisitions. During 1996, the Company acquired primarily gas-producing
properties for a total cost of $106 million funded primarily by bank debt.
These acquisitions include:
- The Enserch Acquisition. This acquisition closed in July 1996 at a cost
of $39.4 million and primarily consisted of operated gas-producing
properties 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.
- Gas-producing properties in the Ozona area of the Permian Basin of West
Texas. The Company acquired these mostly operated interests for $28.1
million.
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- 16% of the publicly traded outstanding units in Cross Timbers Royalty
Trust. The Company purchased these units at a total cost of $12.8
million from July through December 1996.
1998, 1997 and 1996 Development and Exploration Programs. Oil development was
concentrated in the University Block 9 Field during 1998 and 1997, as well as
the Prentice Northeast Unit of West Texas during 1997 and 1996. Gas development
focused on the Hugoton Area during 1998, the Ozona Area in 1998 and 1997, the
Fontenelle Unit during all three years and Major County, Oklahoma during 1996.
Exploration activity during 1998 was primarily geological and geophysical
analysis, including seismic studies, of undeveloped properties at a total cost
of $8 million. This work was concentrated in the Silurian Reef of Illinois, and
Texas County and the Nemeha Ridge Area of Oklahoma. Exploratory expenditures
were $2.1 million in 1997 and insignificant in 1996.
1999 Development and Exploration Program. The Company has budgeted $60 million
for its 1999 development and exploration program, which is expected to be funded
primarily by cash flow from operations. The Company anticipates exploration
expenditures will be less than 5% of the 1999 budget. The total capital budget,
including acquisitions, will be adjusted throughout 1999 to capitalize on
opportunities offering the highest rates of return.
1998 Common Stock Offering. In April 1998, the Company sold 7,203,450 shares of
common stock. Net proceeds of $133.1 million were used to partially repay bank
debt used to fund the East Texas Basin Acquisition.
1998 Issuance of Common Shares. In September 1998, the Company issued from
treasury stock 1,921,850 common shares to subsidiaries of Shell Oil Company for
the Alaska Cook Inlet Acquisition.
1997 Senior Subordinated Note Sales. The Company sold $125 million of 9 1/4%
senior subordinated notes in April 1997 and $175 million of 8 3/4% senior
subordinated notes in October 1997. Net proceeds of $121.1 million and $169.9
million were used to reduce bank debt.
1997 and 1996 Conversion of Subordinated Notes. During November and December
1996, noteholders converted $27.7 million principal of the 5 1/4% convertible
subordinated notes into 2,696,521 shares of common stock. In January 1997,
noteholders converted the remaining principal of $29.7 million into 2,892,363
shares of common stock.
1996 Preferred Stock Exchange. In September 1996, stockholders exchanged
2,979,249 shares of common stock for 1,138,729 shares of Series A convertible
preferred stock pursuant to the Company's exchange offer.
Treasury Stock Purchases. Since May 1996, the Board of Directors has authorized
the purchase of a total of 10.5 million shares of the Company's common stock as
part of its strategic acquisition plans. The Company purchased on the open
market 4.3 million shares at a cost of $65.6 million in 1998, 2.4 million shares
at a cost of $28 million in 1997 and 2.9 million shares at a cost of $30.7
million in 1996.
Investment in Equity Securities. The Company acquired common stock of publicly
traded independent oil and gas producers at a total cost of $167.7 million in
1998, $6.5 million in 1997 and $16.1 million in 1996. For accounting purposes,
the Company considered equity securities purchased in 1998 to be trading
securities, whereas it considered equity securities purchased prior to 1998 to
be available-for-sale securities. Accordingly, the Company recognized
unrealized investment gains and losses in its 1998 statement of operations, as
opposed to recording as a component of stockholders' equity in prior years.
During 1998, the Company recognized a $93.7 million loss on investment in equity
securities, including a loss on sale of securities of $14.8 million, an
unrealized loss of $72.6 million and interest expense of $6.3 million related to
the investment. During 1997, the Company recognized a gain of $1.7 million on
its investment in equity securities including a gain on sale of securities of
$2.4 million and interest expense of $700,000 related to the investment.
Property Sales. The Company sold producing properties resulting in net gains of
$800,000 in 1998, $1.8 million in 1997 and $500,000 in 1996.
Stock Incentive Compensation. Stock incentive compensation results from stock
appreciation right ("SAR") and performance share awards, and subsequent changes
in the Company's stock price. During 1998, stock incentive compensation totaled
$1.3 million, which included non-cash performance share compensation of $1.6
million, partially offset by a reduction in SAR compensation of $300,000. In
1997, stock incentive compensation totaled $3.7 million,
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which included non-cash performance share compensation of $3.3 million and SAR
compensation of $400,000. 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. Exercises and forfeitures under the 1991 Stock
Incentive Plan reduced outstanding stock incentive units (including SARs) from
836,000 at the beginning of 1996 to 18,000 at year-end 1998.
Product Prices. In addition to supply and demand, oil and gas prices are
affected by substantial seasonal, political and other fluctuations the Company
generally cannot control or predict.
Crude oil prices are generally determined by global supply and demand.
After sinking to a five-year low at the end of 1993, oil prices reached their
highest levels since the 1990 Persian Gulf War during fourth quarter 1996 and
January 1997. Crude oil prices ranged from $17 to $20 during most of 1997, then
declined to a $16 average in December. Crude oil prices continued to decline
throughout 1998, dropping to a West Texas Intermediate price of $8.00 per barrel
in December 1998, the lowest level since 1978. This decline is the result of low
demand, as well as the failure of OPEC, at its November 1998 meeting, to further
reduce production quotas. Low demand has been caused by warmer than normal
winter temperatures and a slower than expected recovery in Asian economies.
Based on 1998 production, the Company estimates that a $1.00 per barrel increase
or decrease in the average oil sales price would result in approximately a $4.4
million change in 1999 annual operating cash flow.
Natural gas prices are influenced by national and regional supply and
demand, which is often dependent upon weather conditions. Specific gas prices
are also based on the location of production, pipeline capacity, gathering
charges and the energy content of the gas. Generally because of colder weather,
storage concerns and U.S. economic growth, prices remained relatively high
during most of 1996 and 1997, reaching their highest levels since 1985. Gas
prices declined, however, in December 1997 and, except for a rebound during the
summer, have remained lower throughout 1998. Lower gas prices have been
primarily because the winters of 1997-1998 and 1998-1999 in the central and
eastern U.S. were abnormally mild. The Company has entered into commodity price
hedging instruments to reduce its exposure to gas price fluctuations. As a
result of these commodity hedging instruments, the Company's average gas price
increased from $1.97 to $2.07 in 1998 and decreased from $2.24 to $2.20 in 1997.
Based on 1998 production, the Company estimates that a $0.10 per Mcf increase or
decrease in the average gas sales price would result in approximately a $7.7
million change in 1999 annual operating cash flow.
Impairment Provision. During 1998, the Company recorded an impairment provision
on producing properties of $2 million before income tax. This impairment
provision was determined based on an assessment of recoverability of net
property costs from estimated future net cash flows from those properties.
Estimated future net cash flows are based on management's best estimate of
projected oil and gas reserves and prices. If oil and gas prices remain at
lower levels or decline further, the Company may be required to record
impairment provisions in the future, which may be material.
Results of Operations
1998 Compared to 1997
For the year 1998, loss available to common stock was $71.5 million
compared with earnings of $23.9 million for 1997. The 1998 loss includes a $93.7
million loss ($61.8 million after tax) on investment in equity securities and a
$2 million ($1.3 million after tax) impairment write-down of producing
properties. The remaining decline in earnings is primarily the result of lower
product prices and increased interest related to the 1998 acquisitions and
treasury stock purchases.
Revenues for 1998 were $249.5 million, or 26% above 1997 revenues of $198.3
million. Even though oil production increased by 16%, oil revenue decreased
$19.1 million or 25% because of a 35% decrease in oil prices from an average of
$18.90 in 1997 to $12.21 in 1998 (see "General-Product Prices" above). Increased
production was primarily because of the 1998 acquisitions.
Gas revenue increased $72.5 million or 66% because of a 69% increase in
production partially offset by a 6% price decrease (see "General-Product Prices"
above). Increased gas production was attributable to the 1997 and 1998
acquisitions and development programs. Gas revenues for 1998 also included $9.3
million from San Juan Basin natural gas liquids production attributable to the
December 1997 Amoco Acquisition.
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Gas gathering, processing and marketing revenues decreased $400,000
primarily because of decreased wellhead volumes and lower gas and natural gas
liquids prices, partially offset by increased margin. Other revenues were $1.8
million lower primarily because of decreased net gains on sale of properties and
decreased lawsuit settlement receipts.
Expenses for 1998 totaled $209.2 million as compared with total 1997
expenses of $134.8 million. Most expenses increased in 1998 primarily because of
the 1997 and 1998 acquisitions and exploration and development programs.
Production expense increased $19.6 million or 45%. Per Mcfe, production
expense decreased from $0.59 to $0.53. This decrease is primarily because of the
lower operating costs of gas-producing properties acquired in 1997 and 1998, the
timing of workovers and operating efficiencies initiated after acquiring
operated properties. Exploration expenses for 1998 totaled $8 million and were
predominantly geological and geophysical costs, including seismic analysis,
related to the 1998 exploration program. Exploration costs in 1997 totaled $2.1
million.
Taxes on production and property, transportation and other deductions
increased 77% or $12.7 million because of increased oil and gas revenues, as
well as increased property taxes related to the 1997 and 1998 acquisitions.
Taxes, transportation and other per Mcfe increased 14% from $0.22 to $0.25
because of increased transportation, compression and other charges related to
acquisitions.
Depreciation, depletion and amortization ("DD&A") increased $35.8 million,
or 75%, primarily because of the 1997 and 1998 acquisitions and development
programs. On an Mcfe basis, DD&A increased from $0.65 in 1997 to $0.70 in 1998
primarily because of the higher cost per Mcfe of the 1998 acquisitions.
General and administrative expense decreased $2.3 million, or 15%, because
of a $2.4 million decrease in stock incentive compensation, partially offset by
increased expenses from Company growth. Excluding stock incentive compensation,
general and administrative expense per Mcfe decreased to $0.10 in 1998 from
$0.16 in 1997. This reduction resulted from production growth outpacing Company
personnel requirements and other administrative expenses.
Interest expense increased $26.1 million or 100% primarily because of a
comparable increase in weighted average borrowings to partially fund the 1997
and 1998 acquisitions and treasury stock purchases, combined with a 1% increase
in the weighted average interest rate and amortization of loan fees. Interest
related to investment in equity securities has been classified as part of the
loss on investment in equity securities. Interest expense per Mcfe increased
from $0.35 in 1997 to $0.44 in 1998 primarily as the result of an increase in
the weighted average borrowings to fund treasury stock purchases.
1997 Compared to 1996
Earnings available to common stock for 1997 were $23.9 million as compared
with $19.8 million for 1996. Improved earnings were primarily the result of
higher gas prices and increased gas production from the 1996 and 1997
acquisitions and development programs. Results included the effects of stock
incentive compensation of $3.7 million in 1997 and $6.2 million in 1996. Also
included in 1997 results were a $1.7 million gain on investment in equity
securities, a gain of $1.8 million on sale of properties and lawsuit settlement
proceeds of $1.3 million. A $500,000 gain on sale of properties was included in
1996 results. Dividends on preferred stock issued in September 1996 reduced
1997 earnings by $1.8 million and 1996 earnings by $500,000.
Revenues for 1997 were $198.3 million, or 23% above 1996 revenues of $161.4
million. Oil revenue remained constant as a 13% increase in oil production was
offset by a 12% decrease in oil prices from an average of $21.38 in 1996 to
$18.90 in 1997 (see "General-Product Prices" above). Increased production was
primarily because of the 1997 acquisitions and development programs.
Gas revenue increased $36.7 million or 50% because of a 33% increase in
production combined with a 12% price increase (see "General-Product Prices"
above). Increased gas production was attributable to the 1996 and 1997
acquisitions and development programs. Gas revenues for 1997 also included
$800,000 from San Juan Basin natural gas liquids production attributable to the
December 1997 Amoco Acquisition.
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Gas gathering, processing and marketing revenues decreased $2.2 million
primarily because of a decrease in margin and gas volumes. Other revenues
increased $2.2 million primarily because of increased net gains on sale of
properties and lawsuit settlement proceeds received in 1997.
Expenses for 1997 totaled $134.8 million as compared with total 1996
expenses of $113.3 million. All expenses other than general and administrative
expense increased in 1997 primarily because of the 1996 and 1997 acquisitions
and exploration and development programs.
Production expense increased $4.2 million or 11%. Production expense per
Mcfe decreased from $0.67 to $0.59. This decrease is primarily because of the
lower operating costs of gas-producing properties acquired in 1996 and 1997, the
timing of workovers and operating efficiencies initiated after acquiring
operated properties. Exploration expenses for 1997 totaled $2.1 million, and
were predominantly geological and geophysical costs related to the 1997
exploration program. Exploration costs in 1996 and prior were included in
production expense since not significant.
Taxes on production and property, transportation and other deductions
increased 37% or $4.5 million because of increased oil and gas revenues, as well
as increased property taxes related to the 1996 and 1997 acquisitions. Taxes,
transportation and other per Mcfe increased 10% from $0.20 to $0.22 because of
increased gas prices and higher property tax rates.
DD&A increased $9.9 million, or 26%, primarily because of the 1996 and 1997
acquisitions and development programs. On an Mcfe basis, DD&A remained
relatively flat at $0.65 for 1996 and 1997.
General and administrative expense decreased $600,000, or 4%, because of a
$2.5 million decrease in stock incentive compensation, partially offset by
increased expenses from Company growth. Excluding stock incentive compensation,
general and administrative expense per Mcfe was $0.16 for 1997 as compared with
$0.17 for 1996.
Gas gathering and processing expense increased $1.6 million or 23%. This
increase was primarily because of rental expense related to the Tyrone plant and
gathering system lease that began in March 1996 and the Major County, Oklahoma
gathering system lease that began in November 1996. This increase offsets
related decreases in DD&A and interest.
Interest expense increased $9.9 million or 61% because of a 36% increase in
weighted average borrowings to partially fund the 1996 and 1997 acquisitions and
purchases of treasury stock, combined with a 20% increase in the weighted
average interest rate primarily attributable to the senior subordinated notes
sold in April and October 1997. Interest expense per Mcfe increased from $0.28
in 1996 to $0.35 in 1997, primarily because of an increase in the weighted
average interest rate, as well as the result of increased bank debt to finance
treasury stock purchases.
Liquidity and Capital Resources
The Company's primary sources of liquidity are cash flow from operating
activities, producing property sales, including sales of royalty trust units,
public offerings of equity and debt, and bank debt. Other than for operations,
the Company's cash requirements are generally for the acquisition, exploration
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 1999
cash requirements.
Cash used by operating activities was $45.8 million in 1998, compared with
$98 million cash provided by operations in 1997 and $59.7 million in 1996. The
fluctuation from 1997 to 1998 was primarily because of decreased product prices
and purchases of equity securities, net of sales. Before changes in working
capital, cash flow from operations was $78.5 million in 1998, $90 million in
1997 and $68.3 million in 1996.
The 1997 and 1996 acquisitions were primarily financed by long-term debt.
The 1998 acquisitions were funded by a combination of bank borrowings, proceeds
from a public offering of common stock and the issuance of common stock.
Exploration and development expenditures and dividend payments have generally
been funded by cash flow from operations.
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Financial Condition
Total assets increased 53% from $788 million at December 31, 1997 to $1.2
billion at December 31, 1998, primarily because of the 1998 acquisitions. As of
December 31, 1998, total capitalization of the Company was $1.1 billion, of
which 84% was long-term debt. This compares with capitalization of $709 million
at December 31, 1997, of which 76% was long-term debt. The increase in the
debt-to-capitalization ratio from year-end 1997 to 1998 is because of increased
borrowings under the Company's loan agreement to fund the 1998 acquisitions,
purchases of equity securities and other capital expenditures (see "Financing"
below).
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. Working capital of $38 million at December 31, 1998 is
primarily attributable to the investment in equity securities and the related
deferred tax benefit.
Financing
On November 16, 1998, the Company entered into a new Revolving Credit
Agreement with commercial banks. As of December 31, 1998, the Company had a
borrowing base and commitment of $615 million with no unused borrowing capacity
under the loan agreement. The interest rate on borrowings at December 31, 1998
was 6.9%. The Company periodically renegotiates the loan agreement to increase
the borrowing commitment and extend the revolving facility; however, the Company
cannot assure that it can continue to do so in the future. The Company's goal
in 1999 is to reduce debt by as much as $300 million, resulting in debt of 40 to
45 cents per Mcfe of proved reserves.
The borrowing base is redetermined annually based on the value and expected
cash flow of the Company's proved oil and gas reserves. If borrowings exceed
the redetermined borrowing base, the banks may require that the excess be repaid
within a year. Otherwise, borrowings under the loan agreement do not mature
until June 30, 2003, but may be prepaid at any time without penalty. The
borrowing base is scheduled to be redetermined in June 1999. Based on year-end
proved reserves, the Company does not expect a reduction in the borrowing base
upon its redetermination.
Other financing activities in 1998, 1997 and 1996 included the 1998 common
stock offering, 1998 issuance of common shares, 1997 senior subordinated note
sales, 1997 and 1996 conversion of subordinated notes and 1996 preferred stock
exchange. These transactions are described under "General" above.
Capital Expenditures
In May 1998, the Company announced plans to make strategic acquisitions
totaling $150 million from May 1998 through the end of 1999. After closing the
Alaska Cook Inlet Acquisition in September, the Seagull Acquisition in November
and other smaller acquisitions in the last half of 1998, the Company achieved
approximately two-thirds of this goal. The Company does not expect to make
further significant acquisitions until substantially meeting its debt reduction
goal. The Company plans to fund any future acquisitions through a combination
of cash flow from operations and proceeds from bank debt, public equity or debt
transactions.
In 1998, exploration and development cash expenditures totaled $77.4
million compared with the budget of $90 million. In 1997, exploration and
development cash expenditures totaled $90.5 million, compared with the budget of
$70 million. The Company has budgeted $60 million for the 1999 development
program. As it has done historically, the Company expects to fund the 1999
development program with 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 minor 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 cannot
assure the timing or amount of these expenditures.
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To date, the Company has not spent significant amounts to comply with
environmental or safety regulations, and it currently does not expect to do so
during 1999. However, developments such as new regulations, enforcement
policies or claims for damages could result in significant future costs.
Dividends
The Board of Directors declared quarterly dividends of $0.033 per common
share since the Company's inception through 1996, $0.037 per common share in
1997 and $0.04 per common share in 1998. In February 1999, the Board reduced the
quarterly dividend to $0.01 per common share because of the Company's current
focus on debt reduction. The Company's ability to pay dividends is dependent
upon available cash flow, as well as other factors. In addition, the 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.
Year 2000
"Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant by January 1, 2000 may cause material adverse
effects to companies and organizations that rely upon those systems. Continuity
of the Company's operations in January 2000 will not only depend upon Year 2000
compliance of the Company's computer systems and computer-controlled equipment,
but also compliance of computer systems and computer-controlled equipment of
third parties. These third parties include oil and natural gas purchasers and
significant service providers such as electric utility companies and natural gas
plant, pipeline and gathering system operators.
The Company is in the process of reviewing its computer systems and
computer-controlled field equipment and making the necessary modifications for
Year 2000 compliance. The Company has completed modifications and testing of its
primary accounting and land computer programs. The remaining computer systems
have been inventoried and assessed. Remediation and testing of significant
remaining systems are expected to be complete by August 1999.
Some of the Company's critical field equipment, such as natural gas
compressors, are partially controlled or regulated by embedded computer chips.
Based on a preliminary review of all operating areas, no significant compliance
exceptions have been identified. Approximately 30% of field equipment in
operated areas has been inventoried. The Company expects to complete its review
of the remaining 70% of field equipment inventories by April 1999. The Company
plans to complete remediation and testing of identified exceptions for
significant computer-controlled field equipment by August 1999.
Based on its review, remediation efforts and the results of testing to
date, the Company does not believe that timely modification of its computer
systems and computer-controlled equipment for Year 2000 compliance represents a
material risk to the Company. The Company estimates that total costs related to
Year 2000 compliance efforts will be less than $500,000 of which approximately
$50,000 has been incurred and expensed through December 1998.
The Company has identified significant third parties whose Year 2000
compliance could affect the Company and is in the process of formally inquiring
about their Year 2000 status. The Company has received responses to
approximately 30% of its inquiries. Approximately 90% of respondents have
indicated that they will be Year 2000 compliant by January 1, 2000. Despite its
efforts to assure that such third parties are Year 2000 compliant, the Company
cannot provide assurance that all significant third parties will achieve
compliance in a timely manner. A third party's failure to achieve Year 2000
compliance could have a material adverse effect on the Company's operations and
cash flow. The potential effect of Year 2000 non-compliance by third parties is
currently unknown.
The Company is currently identifying appropriate contingency plans in the
event of potential problems resulting from failure of the Company's or
significant third party computer systems on January 1, 2000. The Company has
not completed any contingency plans to date. Specific contingency plans will be
developed in response to the results of testing scheduled to be complete by
August 1999, as well as the assessed probability and risk of system or equipment
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failure. These contingency plans may include installing backup computer systems
or equipment, temporarily replacing systems or equipment with manual processes,
and identifying alternative suppliers, service companies and purchasers. The
Company expects these plans to be complete by October 1999.
New Accounting Standards
The Company adopted the following pronouncements in 1998:
- SFAS No. 130, "Reporting Comprehensive Income," requires that all items
that are to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements,
and
- SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information," requires reporting of financial and descriptive
information about a company's reportable operating segments. The Company
has identified only one operating segment, which is the exploration and
production of oil and gas.
The Company will be required to comply with the provisions of SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities" which must
be adopted for fiscal years beginning after June 15, 1999. SFAS No. 133
requires that derivatives be reported on the balance sheet at fair value and, if
the derivative is not designated as a hedging instrument, changes in fair value
must be recognized in earnings in the period of change. If the derivative is
designated as a hedge and to the extent such hedge is determined to be
effective, changes in fair value are either offset by the change in fair value
of the hedged asset or liability (if applicable) or reported as a component of
other comprehensive income in the period of change, and subsequently recognized
in earnings when the offsetting hedged transaction occurs. The definition of
derivatives has also been expanded to include contracts that require physical
delivery of oil and gas if the contract allows for net cash settlement. The
Company primarily uses derivatives to hedge product price and interest rate
risks. These derivatives are recorded at cost, and gains and losses on such
derivatives are reported when the hedged transaction occurs. Accordingly,
adoption of SFAS No. 133 will have an impact on the reported financial position
of the Company, and although such impact has not been determined, it is
currently not believed to be material. Adoption of SFAS No. 133 should have no
significant impact on reported earnings, but could materially affect
comprehensive income.
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,
1998, the Company's consolidated balance sheet includes a net receivable of $4.9
million for a net underproduced balancing position of 885,000 Mcf of natural gas
and 7,909,000 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.
Forward-Looking Statements
Certain information included in this year-end report on Form 10-K and other
materials filed by the Company with the Commission contain forward-looking
statements relating to the Company's operations and the oil and gas industry.
Such forward-looking statements are based on management's current projections
and estimates and are identified by words such as "expects," "intends," "plans,"
"projects," "anticipates," "believes," "estimates" and similar words. These
statements are not guarantees of future performance and involve certain risks,
uncertainties and assumptions that are difficult to predict. Therefore, actual
results may differ materially from what is expressed or forecasted in such
forward-looking statements.
Among the factors that could cause actual results to differ materially are:
- crude oil and natural gas price fluctuations
26
<PAGE>
- the Company's ability to acquire oil and gas properties that meet its
objectives and to identify prospects for drilling
- potential delays or failure to achieve expected production from
existing and future exploration and development projects
- potential disruption of operations because of failure to achieve
timely Year 2000 compliance by the Company or other entities with
which it has material relationships, and
- potential liability resulting from pending or future litigation.
In addition, these forward-looking statements may be affected by general
domestic and international economic and political conditions.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The Company only uses derivative financial instruments for hedging
purposes. These instruments principally include interest rate swap agreements
and commodity futures, swaps, and option agreements. These financial and
commodity-based derivative contracts are used to limit the risks of interest
rate fluctuations and natural gas and crude oil price changes. Gains and losses
on these derivatives are entirely offset by losses and gains on the respective
hedged exposures.
The Board of Directors has adopted a policy governing the use of derivative
instruments, which requires that all derivatives used by the Company relate to
an underlying, offsetting position, anticipated transaction or firm commitment,
and prohibits the use of speculative, highly complex or leveraged derivatives.
The policy also requires review and approval by the Executive Vice President of
all risk management programs using derivatives and all derivative transactions.
These programs are also periodically reviewed by the Board of Directors.
Hypothetical changes in interest rates and prices chosen for the estimated
sensitivity effects are considered to be reasonably possible near-term changes
generally based on consideration of past fluctuations for each risk category. It
is not possible to accurately predict future changes in interest rates, product
prices and investment market values. Accordingly, these hypothetical changes may
not necessarily be an indicator of probable future fluctuations.
Interest Rate Risk
The Company is exposed to interest rate risk on short-term and long-term
debt carrying variable interest rates. The Company's variable rate debt was
approximately $620 million at December 31, 1998. The Company attempts to
balance the benefit of lower cost variable rate debt that has inherent increased
risk with more expensive fixed rate debt that has less market risk. This is
accomplished through a mix of bank debt with short-term variable rates and fixed
rate subordinated debt, as well as the use of interest rate swaps. During 1998,
the Company entered into interest rate swap agreements that effectively convert
interest rates from variable to fixed on $150 million principal through
September 2005. The Company had no outstanding interest swap agreements during
1997.
27
<PAGE>
The following table shows the carrying amount and fair value of long-term
debt and interest rate swaps, and the hypothetical change in fair value that
would result from a 100-basis point change in interest rates:
<TABLE>
<CAPTION>
Hypothetical
Change
Carrying Fair in
(in thousands) Amount Value Fair Value
---------- ------------- -----------
<S> <C> <C> <C>
December 31, 1998
Long-term debt....... $(921,000) $(894,750) $(17,000)
Interest rate swaps.. - (2,722) (8,655)
December 31, 1997
Long-term debt....... (539,000) (538,288) (20,656)
</TABLE>
In February and March 1999, the Company terminated its interest rate swaps
on notional balances totaling $100 million, resulting in proceeds received and a
gain of $1.1 million. This gain will be amortized against interest expense
through September 2005. In February 1999, the Company sold a call option that
allows the counterparty to terminate the interest rate swap in September 2001 on
the remaining $50 million notional balance, resulting in proceeds received of
$800,000. This amount will be deferred until the option is exercised or
expires.
Commodity Price Risk
The Company hedges a portion of the market risks associated with its crude
oil and natural gas sales. During 1998, the Company primarily entered into gas
futures contracts and gas basis swap agreements to reduce exposure to price
volatility in the physical markets. As of December 31, 1998, outstanding
futures contracts had a fair value of a gain of $3.5 million and outstanding
basis swap agreements had a fair value of a loss of $0.7 million. These futures
contracts and basis swap agreements are not recorded on the Company's balance
sheet. The Company did not have any significant commodity hedging activity in
1997.
For these commodity derivatives that are permitted to be settled in cash or
another financial instrument, sensitivity effects are as follows. At year-end
1998, the aggregate effect of a hypothetical 10% change in natural gas prices
and basis would result in a $3 million change in the fair value of these
financial instruments. This sensitivity does not include the effects of gas
contracts that cannot be settled in cash or another financial instrument. See
Note 6 to Consolidated Financial Statements.
Investment in Equity Securities
The Company is subject to price risk on its unhedged portfolio of publicly
traded investments in equity securities of energy companies. These securities
were classified as trading securities as of year-end 1998. The fair value of
these securities at December 31, 1998 was $44.4 million. At year-end 1998, a
25% appreciation or depreciation in equity price would increase or decrease
portfolio fair value and pre-tax earnings by approximately $11 million. As of
March 1, 1999, the Company had incurred a 1999 pre-tax loss on its investment in
equity securities of $8 million, of which $17.5 million was a realized loss,
partially offset by a $9.5 million decrease in unrealized loss.
28
<PAGE>
Item 8. Financial Statements and Supplementary Data
The following financial statements and supplementary information are
included under Item 14(a):
<TABLE>
<CAPTION>
Page
----
<S> <C>
Consolidated Balance Sheets......................... 31
Consolidated Statements of Operations............... 32
Consolidated Statements of Comprehensive Income..... 33
Consolidated Statements of Cash Flows............... 34
Consolidated Statements of Stockholders' Equity..... 35
Notes to Consolidated Financial Statements.......... 36
Selected Quarterly Financial Data
(Note 13 to Consolidated Financial Statements)..... 55
Information about Oil and Gas Producing Activities
(Note 14 to Consolidated Financial Statements)..... 55
Report of Independent Public Accountants............ 59
</TABLE>
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 Commission no
later than April 30, 1999.
29
<PAGE>
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:
<TABLE>
<CAPTION>
Page
----
<S> <C>
1. Financial Statements:
Consolidated Balance Sheets at December 31, 1998 and 1997............ 31
Consolidated Statements of Operations for the years ended
December 31, 1998, 1997 and 1996................................... 32
Consolidated Statements of Comprehensive Income for the years ended
December 31, 1998, 1997 and 1996................................... 33
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996................................... 34
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1998, 1997 and 1996................................... 35
Report of Independent Public Accountants............................. 59
</TABLE>
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 61 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, 1998 and through March 15, 1999:
On December 21, 1998, the Company filed a report on Form 8-K
regarding an increase in the size of its Hugoton Royalty Trust
offering and termination of plans to begin royalty trust unit
distribution to stockholders in 2000.
On February 16, 1999, the Company filed a report on Form 8-K/A
(Amendment No. 2 to Form 8-K dated April 24, 1998) to file
amended financial statements for the acquisition of certain
producing oil and gas properties and undeveloped acreage in the
East Texas Basin from EEX Corporation.
30
<PAGE>
CROSS TIMBERS OIL COMPANY
Consolidated Balance Sheets
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(in thousands) December 31
------------------------
1998 1997
------------ ----------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents........................................... $ 12,333 $ 3,816
Accounts receivable, net (Note 8)................................... 50,607 43,996
Investment in equity securities (Note 2)............................ 44,386 -
Deferred income tax benefit (Note 5)................................ 24,816 445
Other current assets................................................ 5,436 3,905
---------- ---------
Total Current Assets.............................................. 137,578 52,162
---------- ---------
Property and Equipment, at cost --
successful efforts method (Notes 1 and 4):
Producing properties................................................ 1,335,844 931,259
Undeveloped properties.............................................. 6,845 6,406
Gas gathering and other............................................. 27,829 23,703
---------- ---------
Total Property and Equipment....................................... 1,370,518 961,368
Accumulated depreciation, depletion and amortization................ (319,507) (237,532)
---------- ---------
Net Property and Equipment........................................ 1,051,011 723,836
---------- ---------
Other Assets......................................................... 13,210 12,457
---------- ---------
Loans to Officers (Note 3)........................................... 5,795 -
---------- ---------
TOTAL ASSETS......................................................... $1,207,594 $ 788,455
========== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............................ $ 93,583 $ 52,266
Payable to Royalty Trust............................................ 968 2,073
Short-term debt (Note 4)............................................ 4,962 -
Accrued stock incentive compensation (Note 11)...................... 75 554
---------- ---------
Total Current Liabilities......................................... 99,588 54,893
---------- ---------
Long-term Debt (Note 4).............................................. 921,000 539,000
---------- ---------
Deferred Income Taxes Payable (Note 5)............................... 6,892 21,320
---------- ---------
Other Long-term Liabilities (Note 6)................................. 2,663 2,999
---------- ---------
Commitments and Contingencies (Note 6)
Stockholders' Equity (Note 7):
Series A convertible preferred stock ($.01 par value, 25,000,000
shares authorized, 1,138,729 issued, at liquidation value of $25).. 28,468 28,468
Common stock ($.01 par value, 100,000,000 shares authorized,
54,048,227 and 46,310,710 shares issued)........................... 541 463
Additional paid-in capital.......................................... 338,503 210,954
Treasury stock (9,320,971 and 6,860,779 shares)..................... (118,555) (76,656)
Retained earnings (deficit)......................................... (71,506) 7,014
---------- ---------
Total Stockholders' Equity........................................ 177,451 170,243
---------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY........................... $1,207,594 $ 788,455
========== =========
</TABLE>
See accompanying notes to consolidated financial statements.
31
<PAGE>
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Operations
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(in thousands, except per share data)
Year Ended December 31
-------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
REVENUES
Oil and condensate....................................... $ 56,164 $ 75,223 $ 75,013
Gas and natural gas liquids.............................. 182,587 110,104 73,402
Gas gathering, processing and marketing.................. 9,438 9,851 12,032
Other.................................................... 1,297 3,094 888
--------- -------- --------
Total Revenues........................................... 249,486 198,272 161,335
--------- -------- --------
EXPENSES
Production............................................... 63,148 43,580 39,365
Exploration.............................................. 8,034 2,088 -
Taxes, transportation and other.......................... 29,105 16,405 11,944
Depreciation, depletion and amortization................. 83,560 47,721 37,858
Impairment (Note 1)...................................... 2,040 - -
General and administrative (Note 11)..................... 13,479 15,818 16,420
Gas gathering and processing............................. 8,360 8,517 6,905
Trust development costs.................................. 1,498 665 854
--------- -------- --------
Total Expenses........................................... 209,224 134,794 113,346
--------- -------- --------
OPERATING INCOME......................................... 40,262 63,478 47,989
--------- -------- --------
OTHER INCOME (EXPENSE)
Gain (loss) on investment in equity securities (Note 2).. (93,719) 1,735 (893)
Interest expense, net.................................... (52,113) (26,012) (16,123)
--------- -------- --------
Total Other Income (Expense)............................. (145,832) (24,277) (17,016)
--------- -------- --------
INCOME (LOSS) BEFORE INCOME TAX.......................... (105,570) 39,201 30,973
Income Tax Expense (Benefit) (Note 5).................... (35,851) 13,517 10,669
--------- -------- --------
NET INCOME (LOSS)........................................ (69,719) 25,684 20,304
Preferred stock dividends................................ 1,779 1,779 514
--------- -------- --------
EARNINGS (LOSS) AVAILABLE TO COMMON STOCK................ $ (71,498) $ 23,905 $ 19,790
========= ======== ========
EARNINGS (LOSS) PER COMMON SHARE (Notes 1 and 9)
Basic................................................... $(1.65) $0.60 $0.50
========= ======== ========
Diluted................................................. $(1.65) $0.59 $0.48
========= ======== ========
Weighted Average Common Shares Outstanding............... 43,396 39,773 39,913
========= ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
32
<PAGE>
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Comprehensive Income
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(in thousands)
Year Ended December 31
-----------------------------
1998 1997 1996
-------- ------- --------
<S> <C> <C> <C>
NET INCOME (LOSS)............................................ $(69,719) $25,684 $20,304
-------- ------- -------
OTHER COMPREHENSIVE INCOME
Unrealized gains on available-for-sale securities (Note 2):
Unrealized holding gains................................... - 1,434 1,022
Less realized gains included in net income................. - (2,400) (56)
-------- ------- -------
Other Comprehensive Income (Loss) Before Tax................. - (966) 966
Income tax benefit (expense) related to
other comprehensive income.................................. - 328 (328)
-------- ------- -------
Other Comprehensive Income (Loss)............................ - (638) 638
-------- ------- -------
COMPREHENSIVE INCOME (LOSS).................................. $(69,719) $25,046 $20,942
======== ======= =======
</TABLE>
See accompanying notes to consolidated financial statements.
33
<PAGE>
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Cash Flows
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(in thousands)
(Note 10)
Year Ended December 31
---------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income (loss)....................................................... $ (69,719) $ 25,684 $ 20,304
Adjustments to reconcile net income (loss) to net cash..................
provided (used) by operating activities:...............................
Depreciation, depletion and amortization............................. 83,560 47,721 37,858
Impairment........................................................... 2,040 - -
Exploration.......................................................... 8,034 2,088 -
Stock incentive compensation......................................... 1,141 3,386 (853)
Deferred income tax.................................................. (35,744) 13,393 10,213
(Gain) loss from sale of properties and equity securities............. 86,628 (4,157) (576)
Other non-cash items................................................. 2,540 1,864 1,317
Changes in current assets and liabilities (a)........................ (124,322) 8,027 (8,569)
--------- --------- ---------
Cash Provided (Used) by Operating Activities............................ (45,842) 98,006 59,694
--------- --------- ---------
INVESTING ACTIVITIES
Proceeds from sale of long-term investment in equity securities......... - 24,626 402
Long-term investment in equity securities............................... - (6,479) (16,093)
Proceeds from sale of property and equipment............................ 2,494 17,972 37,388
Property acquisitions................................................... (296,390) (238,294) (109,535)
Exploration and development costs....................................... (77,390) (90,470) (32,291)
Gas plant, gathering and other additions................................ (7,517) (18,677) (4,742)
Loans to officers....................................................... (5,795) - -
--------- --------- ---------
Cash Used by Investing Activities....................................... (384,598) (311,322) (124,871)
--------- --------- ---------
FINANCING ACTIVITIES
Proceeds from long-term debt............................................ 877,900 688,400 188,000
Payments on long-term debt.............................................. (496,938) (437,430) (81,200)
Common stock offering................................................... 133,113 - -
Dividends............................................................... (8,460) (7,571) (5,339)
Stock option exercises and other........................................ (269) 750 364
Purchases of treasury stock............................................. (66,389) (30,954) (34,923)
--------- --------- ---------
Cash Provided by Financing Activities................................... 438,957 213,195 66,902
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........................ 8,517 (121) 1,725
Cash and Cash Equivalents, January 1.................................... 3,816 3,937 2,212
--------- --------- ---------
Cash and Cash Equivalents, December 31.................................. $ 12,333 $ 3,816 $ 3,937
========= ========= =========
(a) Changes in Current Assets and Liabilities
Accounts receivable................................................. $ (7,022) $ 246 $ (16,999)
Investment in equity securities (purchases net of sales)............ (131,809) - -
Other current assets................................................ (1,513) (970) (1,683)
Accounts payable, accrued liabilities and payable to Royalty Trust.. 16,022 8,751 10,113
--------- --------- ---------
Decrease (Increase) in Current Assets and Liabilities................ $(124,322) $ 8,027 $ (8,569)
========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
34
<PAGE>
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Stockholders' Equity
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(in thousands)
(Note 7)
Shares Stockholders' Equity
---------------------------- ---------------------------------------------------
Common Stock
------------------ Additional Retained
Preferred In Preferred Common Paid-in Treasury Earnings
Stock Issued Treasury Stock Stock Capital Stock (Deficit)
--------- ------ -------- --------- ------ ---------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balances, December 31, 1995 - 41,434 69 $ - $ 414 $156,440 $ (528) $(25,626)
Issuance/vesting of
performance shares...... - 168 106 - 2 2,673 (1,038) -
Stock option exercises..... - 996 768 - 10 7,189 (7,931) -
Treasury stock purchases... - - 2,925 - - - (30,722) -
Exchange of Series A
convertible preferred
stock for
common stock........... 1,139 (2,979) - 28,468 (30) (28,978) - -
Conversion of subordinated
convertible notes to
common stock........... - 2,696 - - 27 27,112 - -
Common stock dividends
($0.13 per share) - - - - - - - (5,242)
Preferred stock dividends
($0.45 per share)....... - - - - - - - (514)
Net income................. - - - - - - - 20,304
--------- ------ -------- --------- ------ ---------- --------- --------
Balances, December 31, 1996 1,139 42,315 3,868 28,468 423 164,436 (40,219) (11,078)
Issuance/vesting of
performance shares...... - 180 76 - 2 3,431 (1,098) -
Stock option exercises..... - 924 566 - 9 8,183 (7,326) -
Treasury stock purchases... - - 2,351 - - - (28,013) -
Conversion of subordinated
convertible notes to
common stock........... - 2,892 - - 29 29,179 - -
Issuance of warrants....... - - - - - 5,725 - -
Common stock dividends
($0.15 per share)....... - - - - - - - (5,813)
Preferred stock dividends
($1.56 per share)....... - - - - - - - (1,779)
Net income................. - - - - - - - 25,684
--------- ------ -------- --------- ------ ---------- --------- --------
Balances, December 31, 1997 1,139 46,311 6,861 28,468 463 210,954 (76,656) 7,014
Sale of common stock....... - 7,203 - - 72 133,041 - -
Issuance/vesting of
performance shares........ - 82 27 - 1 1,804 (536) -
Stock option exercises..... - 452 25 - 5 2,986 (483) -
Treasury stock purchases... - - 4,330 - - - (65,575) -
Treasury stock issued...... - - (1,922) - - (10,282) 24,695 -
Common stock dividends
($0.16 per share)....... - - - - - - - (7,022)
Preferred stock dividends
($1.56 per share)....... - - - - - - - (1,779)
Net loss................... - - - - - - - (69,719)
--------- ------ -------- --------- ------ ---------- --------- --------
Balances, December 31, 1998 1,139 54,048 9,321 $ 28,468 $ 541 $ 338,503 $(118,555) $(71,506)
========= ====== ======== ========= ====== ========== ========= ========
</TABLE>
See accompanying notes to consolidated financial statements.
35
<PAGE>
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. 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. Certain amounts presented in
prior period financial statements have been reclassified for consistency with
current period presentation.
All common stock shares and per share amounts in the accompanying financial
statements have been adjusted for the three-for-two stock splits effected on
March 19, 1997 and February 25, 1998 (Note 7).
The Company is an independent oil and gas company with production and
exploration concentrated in Texas, Oklahoma, Kansas, New Mexico, Wyoming and
Alaska. 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. Exploratory geological and geophysical costs
are expensed as incurred. All developmental costs are capitalized. The Company
generally pursues acquisition and development of proved reserves, although the
Company increased its exploration activities in 1997 and 1998. Most of the
property costs reflected in the accompanying consolidated balance sheets are
from acquisitions of producing properties from other oil and gas companies.
Producing properties balances include costs of $15,859,000 at December 31, 1998
and $26,570,000 at December 31, 1997, related to wells in progress of drilling.
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 is generally depreciated using the
straight-line method over estimated useful lives which range from 3 to 40 years.
Repairs and maintenance are expensed, while renewals and betterments are
generally capitalized. The estimated undiscounted cost, net of salvage value,
of dismantling and removing major oil and gas production facilities, including
necessary site restoration, are accrued using the unit-of-production method.
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. When impairment
review is necessary, the carrying value of property, plant and equipment
intended to be retained is compared to management's future estimated pretax cash
flow. If impairment is necessary, the asset carrying value is adjusted to fair
value. Cash flow pricing estimates are based on existing reserve and production
information and pricing assumptions that management believes are reasonable.
Generally, for producing properties, the review considers proved reserves,
though probable reserves and other conditions are considered if warranted.
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. The Company recorded an
impairment provision on producing properties of $2,040,000 before income tax in
1998.
36
<PAGE>
Cross Timbers Royalty Trust
The Company makes monthly net profits payments to Cross Timbers Royalty
Trust based on revenues and costs related to properties from which net profits
interests were carved. Net profits payments to the Cross Timbers 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 Cross Timbers
Royalty Trust. The Cross Timbers Royalty Trust's portion of development costs
are expensed as trust development costs in the accompanying consolidated
statements of operations. The Company owned approximately 22% of the Cross
Timbers Royalty Trust publicly traded units at December 31, 1998 and 1997.
Cross Timbers Royalty Trust units are traded on the New York Stock Exchange
under the symbol "CRT."
Hugoton Royalty Trust
In December 1998, the Company formed the Hugoton Royalty Trust by conveying
an 80% net profits interest in properties that are principally located in the
Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the
Green River Basin of Wyoming. These properties represent approximately 30% of
the Company's existing reserve base. The Company filed a registration statement
with the Securities and Exchange Commission ("Commission") in December 1998 and
plans to offer approximately 40% of the trust units to the public in March or
April 1999. The trust units will be listed on the New York Stock Exchange under
the symbol "HGT."
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
In accordance with Statement of Financial Accounting Standards No. 115,
Accounting for Certain Investments in Debt and Equity Securities, equity
securities acquired during 1998 have been recorded as trading securities since
such securities were acquired principally for resale in the near future.
Accordingly, such investment at December 31, 1998 has been recorded as a current
asset at market value, unrealized holding gains and losses have been recognized
in the consolidated statement of operations, and cash flows from purchases and
sales of equity securities have been included in cash provided (used) by
operating activities in the consolidated statement of cash flows. Gains
(losses) on trading securities and interest related to the cost of these
investments have been classified as other income (expense). Such gains (losses)
were previously classified as other revenue and interest related to such
investments was previously classified as interest expense.
Prior to 1998, the Company's investments in equity securities were recorded
as available-for-sale securities. As a result, such investments were recorded as
long-term assets at market value, unrealized holding gains and losses were
recorded as a separate component of stockholders' equity and cash flows from
purchases and sales of equity securities were included in cash provided (used)
by investing activities. See Note 2.
Other Assets
Other assets primarily include deferred debt costs that are amortized over
the term of the related debt (Note 4). Other assets are presented net of
accumulated amortization of $4,697,000 at December 31, 1998 and $2,860,000 at
December 31, 1997.
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. See Note 8.
37
<PAGE>
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, 1998, the Company recorded a net receivable of $4,904,000 for a net
underproduced balancing position of 885,000 Mcf of natural gas and 7,909,000 Mcf
of carbon dioxide. At December 31, 1997, the Company recorded a net receivable
of $5,054,000 for a net underproduced balancing position of 1,114,000 Mcf of
natural gas and 8,049,000 Mcf of carbon dioxide.
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 $56.3 million for 1998, $57.1 million for 1997 and $56.4 million for
1996. These amounts are net of intercompany eliminations.
Other Revenues
Other revenues include gains and losses from sale of property and
equipment. The Company realized gains on sale of property and equipment of
$795,000 in 1998, $1,757,000 in 1997 and $520,000 in 1996.
Exploration Expense
During 1998, the Company incurred $8 million of exploration costs,
primarily composed of geological and geophysical costs related to the 1998
exploration program. Exploration costs were $2.1 million in 1997.
Interest Expense
Interest expense includes amortization of deferred debt costs and is
presented net of interest income of $91,000 in 1998, $71,000 in 1997 and
$152,000 in 1996, and net of capitalized interest of $1,070,000 in 1998 and
$1,185,000 in 1997. No interest was capitalized in 1996.
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 to employees 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 No. 123,
Accounting for Stock-Based Compensation, is disclosed in Note 11.
Earnings per Common Share
Effective December 31, 1997, the Company adopted SFAS No. 128, Earnings Per
Share, which changed the method of computing and disclosing earnings per share
for all periods. Under SFAS No. 128, the Company must report basic earnings per
share, which excludes the effect of potentially dilutive securities, and diluted
earnings per share, which includes the effect of all potentially dilutive
securities unless their impact is antidilutive. The Company previously only
reported earnings per share excluding potentially dilutive securities because
their effect was antidilutive or less than 3% dilutive, as prescribed by the
accounting pronouncement superseded by SFAS No. 128. See Note 9.
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 splits on March 19, 1997 and February 25, 1998 (Note 7).
38
<PAGE>
Segment Reporting
In accordance with SFAS No. 131, Disclosures about Segments of an
Enterprise and Related Information, the Company has identified only one
operating segment, which is the exploration and production of oil and gas. All
the Company's assets are located in the United States and all its revenues are
attributable to United States customers.
There were no sales to a single purchaser that exceeded 10% of total
revenues in 1998. In 1997, gas sales to one purchaser were approximately 14% of
total revenues. In 1996, gas sales to two purchasers were approximately 15% and
14% of total revenues.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, which is required
to be adopted for fiscal years beginning after June 15, 1999. SFAS No. 133
requires that derivatives be reported on the balance sheet at fair value and, if
the derivative is not designated as a hedging instrument, changes in fair value
must be recognized in earnings in the period of change. If the derivative is
designated as a hedge and to the extent such hedge is determined to be
effective, changes in fair value are either a) offset by the change in fair
value of the hedged asset or liability (if applicable) or b) reported as a
component of other comprehensive income in the period of change, and
subsequently recognized in earnings when the offsetting hedged transaction
occurs. The definition of derivatives has also been expanded to include
contracts that require physical delivery of oil and gas if the contract allows
for net cash settlement. The Company primarily uses derivatives to hedge
product price and interest rate risks. Such derivatives are reported at cost,
if any, and gains and losses on such derivatives are reported when the hedged
transaction occurs. Accordingly, the Company's adoption of SFAS No. 133 will
have an impact of the reported financial position of the Company, and although
such impact has not been determined, it is currently not believed to be
material. Adoption of SFAS No. 133 should have no significant impact on reported
earnings, but could materially affect comprehensive income.
2. Investment in Equity Securities
The Company periodically invests in publicly traded equity securities of
select energy companies which it believes to be undervalued. Since classified
as trading securities, this investment at December 31, 1998 is recorded as a
current asset at market value. Realized gains and losses are computed based on
a first-in, first-out determination of cost of securities sold. After sale of
its current investment, the Company does not plan to make future investments in
equity securities of other energy companies.
The following are components of gain (loss) on investment in equity
securities (in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
--------- ------- ------
<S> <C> <C> <C>
Realized gains (losses) on sale of securities:
Gains............................................ $ 887 $2,400 $ 56
Losses........................................... (15,706) - -
-------- ------ -----
Net gains (losses)............................... (14,819) 2,400 56
Unrealized gains (losses) (a)...................... (72,605) - -
Interest expense related to investment in
equity securities................................ (6,295) (665) (949)
-------- ------ -----
Gains (losses) on investment in equity securities.. $(93,719) $1,735 $(893)
======== ====== =====
</TABLE>
(a) Because investments in equity securities were recorded as available-
for-sale securities prior to 1998, unrealized gains and losses for
1997 and 1996 are reported as a component of stockholders' equity, as
shown in the Consolidated Statements of Comprehensive Income.
As of March 1, 1999 the Company had incurred a 1999 pre-tax loss on its
investment in equity securities of $8 million, of which $17.5 million was a
realized loss, partially offset by a $9.5 million decrease in unrealized loss.
39
<PAGE>
3. Related Party Transactions
Loans to Officers
Pursuant to margin support agreements with each of six officers, the
Company agreed to use the value of its investments in equity securities (Note 2)
to provide margin support for the officers' broker accounts in which they held
Company common stock. In August 1998, the Board of Directors authorized these
agreements so that the officers would not be forced to sell Company common
stock, particularly at depressed prices, potentially creating further downward
pressure on the stock price. These agreements provide that each officer cannot
purchase additional securities in his broker account, or engage in any
transaction that would increase the margin requirements for his account,
including withdrawal of any funds or securities. The Company also has agreed to
pay each officer's margin debt to the extent unpaid by the officer. In
connection with these agreements, in December 1998 the Company loaned four
officers a total of $5,795,000 to reduce their margin debt. In January and
February 1999, an additional $430,000 was loaned. These loans are full recourse
and due in five years, with interest equal to the Company's bank debt rates
(Note 4). Total officer margin debt on their broker accounts at March 1, 1999
was $11.2 million.
Other Transactions
A director-related company performed consulting services in 1998 in
connection with the Cook Inlet Acquisition (Note 12). After the Company
recovers its acquisition costs, including interest and subsequent property
development and operating costs, the director-related company will receive, at
its election, either a 20% working interest or a 1% overriding interest conveyed
from the Company's 100% working interest in these properties. In 1997, the
Company paid fees of $1.6 million to this director-related company in connection
with property sales and the Amoco Acquisition. These consulting fees are
effectively capitalized as a portion of property cost.
4. Debt
The Company's outstanding debt consists of the following (in thousands):
<TABLE>
<CAPTION>
December 31
-------------------
1998 1997
-------- ---------
<S> <C> <C>
Short-term Debt:
Short-term borrowings, 7.4% at December 31, 1998................... $ 4,962 $ 10,000
Reclassified to long-term debt..................................... - (10,000)
-------- --------
Total short-term debt.............................................. $ 4,962 $ -
======== ========
Long-term Debt:
Senior debt-
Bank debt under revolving credit agreements due June 30, 2003,
6.9% at December 31, 1998....................................... $615,000 $229,000
Subordinated debt-
9 1/4% senior subordinated notes due April 1, 2007............... 125,000 125,000
8 3/4% senior subordinated notes due November 1, 2009............ 175,000 175,000
Other long-term debt............................................... 6,000 -
-------- --------
Sub-total long-term debt........................................... 921,000 529,000
Reclassified from short-term debt.................................. - 10,000
-------- --------
Total long-term debt............................................... $921,000 $539,000
======== ========
</TABLE>
40
<PAGE>
Senior Debt
On November 16, 1998, the Company entered into a new Revolving Credit
Agreement with commercial banks ("loan agreement"). As of December 31, 1998,
the loan agreement had a borrowing base and commitment of $615 million with no
unused borrowing capacity. The borrowing base is redetermined annually based on
the value and expected cash flow of the Company's proved oil and gas reserves.
If borrowings exceed the redetermined borrowing base, the banks may require that
the excess be repaid within a year. Otherwise, borrowings under the loan
agreement do not mature until June 30, 2003, 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. The
borrowing base is scheduled to be redetermined in June 1999. Based on year-end
proved reserves, the Company does not expect a reduction in the borrowing base
upon its redetermination.
Reclassification of short-term to long-term debt at December 31, 1997
represents unused capacity under the loan agreement based on outstanding debt
balances at that date.
Restrictions set forth in the loan agreement include limitations on the
incurrence of additional indebtedness, the creation of certain liens, and the
redemption or prepayment of subordinated indebtedness. The loan agreement also
limits dividends to 25% of cash flow from operations for the latest four
consecutive quarterly periods. The Company is also required to maintain a
current ratio of not less than one (where unused borrowing commitments are
included as a current asset).
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, 1998 were based
on LIBOR rates with a maturity of one to six months and accrued at the
applicable LIBOR rate plus 1 3/8%. 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 6.9% during 1998 and 1997 and 6.7% during 1996.
See Note 8 regarding interest rate swap agreements.
Subordinated Debt
The Company sold $125 million of 9 1/4% senior subordinated notes ("9 1/4%
Notes") on April 2, 1997, and $175 million of 8 3/4% senior subordinated notes
("8 3/4% Notes") on October 28, 1997 (the 9 1/4% Notes and the 8 3/4% Notes
collectively referred to as "the Notes"). The Notes are general unsecured
indebtedness that is subordinate to bank borrowings under the loan agreement.
Net proceeds of $121.1 million from the 9 1/4% Notes and $169.9 million from the
8 3/4% Notes were used to reduce bank borrowings under the loan agreement. The
9 1/4% Notes mature on April 1, 2007 and interest is payable each April 1 and
October 1, while the 8 3/4% Notes mature on November 1, 2009 with interest
payable each May 1 and November 1.
The Company has the option to redeem the 9 1/4% Notes on April 1, 2002 and
the 8 3/4% Notes on November 1, 2002 at a price of approximately 105%, and
thereafter at prices declining ratably at each anniversary to 100% in 2005. In
addition, on or prior to April 1, 2000 for the 9 1/4% Notes and November 1, 2000
for the 8 3/4% Notes, the Company may redeem up to one-third of the Notes with
the net proceeds from one or more public equity offerings at a price of
approximately 109% plus accrued interest, subject to certain requirements. Upon
a change in control of the Company, the holders of the Notes have the right to
require the Company to purchase all or a portion of their Notes at 101% plus
accrued interest.
The Notes were issued under indentures that place certain restrictions on
the Company, including limitations on additional indebtedness, liens, dividend
payments, treasury stock purchases, disposition of proceeds from asset sales,
transfers of assets and transactions with subsidiaries and affiliates.
To reduce the interest rate on a portion of its subordinated debt, the
Company has entered an agreement with a bank that has purchased on the market
Notes with a face value of $21.6 million. The Company pays the bank a variable
interest rate based on three-month LIBOR rates, and receives semiannually from
the bank the fixed interest rate on the Notes. The term of the agreement for
approximately half the Notes is through April 2002, and for the remaining half
is through November 2002. Any change in market value of the Notes from the date
purchased by the bank is payable to or receivable from the bank. The Company
funded market value depreciation of $169,000 in January
41
<PAGE>
1999. The Company has the option of repurchasing the Notes from the bank at any
time at market value.
Other Debt
As part of the Cook Inlet Acquisition, the Company executed a $6 million
non-interest bearing promissory note payable to Shell. Payments of $3 million,
$2 million and $1 million are due when the average NYMEX crude oil price for 60
consecutive calendar days equals or exceeds $18.50, $19.50 and $20.50,
respectively.
See also Note 7 "- Registration Statement."
5. Income Tax
The effective income tax rate for the Company was different than the
statutory federal income tax rate for the following reasons (in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Income tax expense (benefit) at the
federal statutory rate of 34%............................................. $(35,893) $13,329 $10,531
State and local taxes and other............................................ 42 188 138
-------- ------- -------
Income tax expense (benefit)............................................... $(35,851) $13,517 $10,669
======== ======= =======
</TABLE>
Components of income tax expense (benefit) are as follows (in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Current income tax......................................................... $ (107) $ 124 $ 456
Deferred income tax expense (benefit)...................................... (2,626) 22,509 13,152
Net operating loss carryforward............................................ (33,118) (9,116) (2,939)
-------- ------- -------
Income tax expense (benefit)............................................... $(35,851) $13,517 $10,669
======== ======= =======
</TABLE>
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 $24,816,000 and a long-term liability of $6,892,000 at December
31, 1998, and a current asset of $445,000 and a long-term liability of
$21,320,000 at December 31, 1997. Significant components of net deferred tax
assets and liabilities are (in thousands):
<TABLE>
<CAPTION>
December 31
------------------
1998 1997
------- ---------
<S> <C> <C>
Deferred tax assets:
Net operating loss carryforwards......................................... $54,044 $ 20,926
Trust development expenses............................................... 4,454 3,959
Accrued stock appreciation right and performance share compensation...... 576 739
Unrealized loss on trading securities.................................... 24,686 -
Other.................................................................... 2,626 1,593
------- --------
Total deferred tax assets......................................... 86,386 27,217
------- --------
Deferred tax liabilities:
Intangible development costs............................................. 48,913 37,856
Tax depletion and depreciation in excess of financial statement amounts.. 16,894 8,008
Other.................................................................... 2,655 2,228
------- --------
Total deferred tax liabilities.................................... 68,462 48,092
------- --------
Net deferred tax assets (liabilities)...................................... $17,924 $(20,875)
======= ========
</TABLE>
As of December 31, 1998, the Company has estimated tax loss carryforwards
of approximately $160 million, of which $10 million are related to capital
losses. The capital loss tax carryforwards expire in 2003 while the remaining
$150 million are scheduled to expire in 2008 through 2013. The Company believes
it will be able to realize its deferred
42
<PAGE>
tax asset, as it plans to utilize its tax loss carryforwards through gains
generated from the sale of Hugoton Royalty Trust units and non-strategic asset
sales which are to begin in 1999.
6. 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,
1998, minimum future lease payments for all non-cancelable lease agreements
(including the sale and operating leaseback agreements described below) were as
follows (in thousands):
<TABLE>
<S> <C>
1999....................................... $ 7,528
2000....................................... 7,177
2001....................................... 6,968
2002....................................... 6,886
2003....................................... 6,858
Remaining.................................. 6,548
-------
Total...................................... $41,965
=======
</TABLE>
Amounts incurred by the Company under operating leases (including renewable
monthly leases) were $11,180,000 in 1998, $9,132,000 in 1997 and $5,489,000 in
1996.
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. 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 bank debt.
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 4) and may be irrevocably fixed by the Company with 20 days advance
notice. As of December 31, 1998, annual rentals were $1.7 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 bank debt.
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.
43
<PAGE>
Gas Sales Contracts
The Company has entered into 1999 futures contracts to sell 175,000 Mcf per
day in April at $1.98 per Mcf, 160,000 Mcf per day in May and June at $1.96 per
Mcf, 40,000 Mcf per day in July at $2.00 per Mcf, 50,000 Mcf per day in August
and September at $2.04 per Mcf and 30,000 Mcf per day in October through
December at an average of $2.13 per Mcf. Prices to be realized for hedged
production may be less than these hedged prices because of location, quality and
other adjustments.
The Company has entered into basis swap agreements that effectively fix the
San Juan Basin basis at $0.25 per Mcf for 30,000 Mcf per day for April and May
1999 and 20,000 Mcf per day from June through December 1999, and $0.28 per Mcf
for 10,000 Mcf per day from January through December 2000. The Company has
basis swap agreements that effectively fix the Wyoming basis at $0.27 per Mcf
for 15,000 Mcf per day for April 1999 and 10,000 Mcf per day from May through
December 1999. The Company also has basis swap agreements that effectively fix
Oklahoma basis at $0.13 per Mcf for 10,000 Mcf per day for April 1999 through
December 1999.
The Company's termination of futures contracts related to first quarter
1999 gas production, net of the effects of basis swap agreements, resulted in a
net gain of $6.4 million. This gain will be recognized as additional gas
revenue of approximately $0.25 per Mcf in the first quarter of 1999.
The Company has committed a minimum gas sales price of $2.00 per Mcf for
gas sales related to April 1999 through March 2000 distributions of the Hugoton
Royalty Trust. The Company plans to sell approximately 40% of Hugoton Royalty
Trust units to the public in March or April 1999. The underlying volumes for
units to be sold to the public are approximately 36,000 Mcf per day.
Under the terms of its amended purchase and sale agreement with Shell for
the Cook Inlet Acquisition (Note 12), the Company has committed to sell to Shell
20,000 Mcf of gas per day from March 1, 1999 through 2003 in the San Juan Basin
with an estimated basis differential of $0.24 per Mcf. The Company has also
agreed to sell Shell in East Texas daily gas volumes of 22,000 Mcf in 1999,
20,000 Mcf in 2000, 17,500 Mcf in 2001, 16,500 Mcf in 2002 and 15,000 Mcf in
2003 at the index price less a weighted average transportation fee of $0.24 per
Mcf.
The Company has committed to sell all gas production from certain
properties in the East Texas Basin Acquisition to EEX Corporation at market
prices through the earlier of December 31, 2001, or until a total of
approximately 34.3 billion cubic feet (27.8 billion cubic feet net to the
Company's interest) of gas has been delivered. Based on current production, this
sales commitment is approximately 24,700 Mcf (20,000 Mcf net to the Company's
interest) per day.
From August 1995 through July 1998 the Company received an additional $0.30
to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, the
Company has agreed to sell 11,650 Mcf per day from August 1998 through May 2000
at the index price and 21,650 Mcf per day from June 2000 through July 2005 at a
contract price of approximately 10% of the month's average NYMEX futures
contract for West Texas Intermediate crude oil, adjusted for point of physical
delivery.
Section 29 Tax Credits
The Company has entered contracts to monetize Section 29 tax credits
generated by production from qualified properties, most of which were acquired
in December 1997. As a result, the Company received approximately $2.9 million
in 1998 and anticipates receiving approximately $2.8 million annually from 1999
through 2002 which will be recorded as gas revenue.
Litigation
On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross
Timbers Oil Company, was filed against the Company in the District Court of
Dewey County, Oklahoma. The action was filed on behalf of all persons who, at
any time since June 1991, have been paid royalties on gas produced from any gas
well within the State of Oklahoma under which the Company has assumed the
obligation to pay royalties. The plaintiffs allege that the Company has reduced
royalty payments by post-production deductions and has entered into contracts
with subsidiaries that were not arms-length transactions, which actions reduced
the royalties paid to the plaintiffs and those similarly situated, and that
44
<PAGE>
such actions are a breach of the leases under which the royalties are paid. The
plaintiffs are seeking an accounting and payment of the monies allegedly owed to
them. The Company filed motions to dismiss the action due to lack of proper
venue, which motions were denied. The decision denying the motions is being
appealed. A hearing on the class certification issue has not been scheduled.
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.
On October 17, 1997, an action, styled United States of America ex rel.
Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District
Court for the Western District of Oklahoma against the Company and certain of
its subsidiaries by Jack J. Grynberg on behalf of the United States under the
qui tam provisions of the False Claims Act. The Company was not made aware of
the claim until the U.S. Justice Department contacted the Company in August
1998. The plaintiff alleges that the Company underpaid royalties on gas produced
from federal leases and lands owned by Native Americans by at least 20% during
the past 10 years as a result of mismeasuring the volume of gas and incorrectly
analyzing its heating content. The plaintiff seeks to recover the amount of
royalties not paid, together with treble damages, a civil penalty of $5,000 to
$10,000 for each violation and attorney fees and expenses. The Company has not
been served with this complaint that is under review by the U.S. Justice
Department. The Company has filed a response with the U.S. Justice Department
and is awaiting its decision whether to intervene in the case. The Company
believes that the allegations of this lawsuit are without merit and intends to
vigorously defend the action.
The Company is 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 lawsuits described above, will have a material effect on the
Company's financial position, liquidity or operations.
Other
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.
See also Notes 3 and 12.
7. Equity
Three-for-Two Stock Split
The Company effected a three-for-two common stock split on February 25,
1998 and March 19, 1997. All common stock shares, treasury stock shares and per
share amounts have been retroactively restated to reflect these stock splits.
Common Stock
On April 27, 1998, the Company completed a public offering of 7,500,000
shares of common stock, of which 7,203,450 shares were sold by the Company and
296,550 shares were sold by a stockholder. The Company's net proceeds from the
offering of $133.1 million were used to partially repay bank debt used to fund
the East Texas Basin Acquisition that closed on April 24, 1998 (Note 12). The
offering was made pursuant to the shelf registration statement filed with the
Commission in February 1998. See "-Registration Statement" below.
On September 30, 1998, the Company issued from treasury 1,921,850 shares to
Shell Western E&P, Inc., Shell Deepwater Development Holdings, Inc., and Shell
Offshore Inc. ("Shell") for the Cook Inlet Acquisition (Note 12). As of December
31, 1998, these shares are valued at $7.50 per share, or a total of $14.4
million. The Company effectively guaranteed Shell a $20 per share value,
resulting in an accrued liability of $12.50 per share, or a total of $24
million, that is included in accounts payable and accrued liabilities in the
accompanying consolidated balance sheet at December 31, 1998.
45
<PAGE>
Performance Shares
The Company issued performance shares totaling 82,125 shares in 1998,
180,000 shares in 1997 and 167,625 shares in 1996 (Note 11).
Treasury Stock
The Company's treasury share acquisitions totaled 4,373,138 shares in 1998
at an average cost of $15.19 per share, 2,571,396 shares in 1997 at an average
cost of $12.06 per share and 3,341,515 shares in 1996 at an average cost of
$10.45 per share. Additionally, the Company received 8,904 shares in 1998,
421,212 shares in 1997 and 457,994 shares in 1996 that are held in treasury, as
payment for the option price upon exercise of stock options.
Shareholder Rights Plan
On August 25, 1998, the Board of Directors adopted a shareholder rights
plan that is designed to assure that all shareholders receive fair and equal
treatment in the event of any proposed takeover of the Company. Under this
plan, a dividend of one preferred share purchase right ("Right") was declared
for each outstanding share of common stock, par value $.01 per share, payable on
September 15, 1998 to shareholders of record on that date. Each Right entitles
shareholders to buy one one-thousandth of a share of newly created Series A
Junior Participating Preferred Stock at an exercise price of $80, subject to
adjustment in the event a person acquires, or makes a tender or exchange offer
for, 15% or more of the outstanding common stock. In such event, each Right
entitles the holder (other than the person acquiring 15% or more of the
outstanding common stock) to purchase shares of common stock with a market value
of twice the Right's exercise price. At any time prior to such event, the Board
of Directors may redeem the Rights at one cent per Right. The Rights can be
transferred only with common stock and expire in ten years.
Registration Statement
In February 1998, the Company filed a shelf registration statement with the
Commission to potentially offer securities which may include debt securities,
preferred stock, common stock or warrants to purchase debt securities, preferred
stock or common stock. The shelf registration statement was amended on April 8,
1998 to increase the maximum total price of securities to be offered to $400
million at prices and on terms to be determined at the time of sale. Net
proceeds from the sale of such securities will be used for general corporate
purposes, including reduction of bank debt. After the April 1998 common stock
offering, $253.8 million remains available under the shelf registration
statement for future sales of securities.
Common Stock Warrants
As partial consideration for producing properties acquired in December 1997
(Note 12), the Company issued warrants to purchase 937,500 shares of common
stock at a price of $15.31 per share for a period of five years. These warrants
were valued at $5,725,000 and recorded as additional paid-in capital.
Common Stock Dividends
Since the Company's inception, the Board of Directors has declared
quarterly dividends of $0.033 per common share through 1996, $0.037 per common
share in 1997 and $0.04 per common share in 1998. In February 1999, the
quarterly dividend was reduced to $0.01 per common share in response to the low
commodity price environment and the Company's 1999 goal to reduce debt by $300
million. See Note 4 regarding restrictions on dividends.
Series A Convertible Preferred Stock
In September 1996, pursuant to the Company's exchange offer, a total of
2,979,249 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
46
<PAGE>
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 2.16 shares
of common stock for each share of Preferred Stock, subject to adjustment in
certain events. Preferred Stock holders are allowed one vote for each common
share into which their Preferred Stock may be converted.
Convertible Debt
During November and December 1996, $27.7 million principal of the Company's
5 1/4% convertible subordinated notes (Note 4) was converted by noteholders into
2,696,521 shares of common stock. In January 1997, principal of $29.7 million
of the notes was converted by noteholders into 2,892,363 shares of common stock.
8. Financial Instruments
The Company uses financial and commodity-based derivative contracts to
manage exposures to interest rate and commodity price fluctuations. The Company
does not hold or issue derivative financial instruments for speculative or
trading purposes.
Commodity Price Hedging Instruments
The Company periodically enters into futures contracts, energy swaps,
collars, basis swaps and option agreements to hedge its exposure to price
fluctuations on crude oil and natural gas sales. During 1998, the Company
recognized net gains of $7.7 million primarily related to futures contracts and
basis swap transactions. This gain is recorded as a component of natural gas
sales. The Company did not have significant commodity hedging activity during
1997 or 1996. See Note 6.
Interest Rate Swap Agreements
In September 1998, to reduce variable interest rate exposure on debt, the
Company entered into a series of interest rate swap agreements, effectively
fixing its interest rate at an average of 6.9% on a total notional balance of
$150 million until September 2005. Settlements of net amounts due are made
quarterly, based on LIBOR rates (Note 4), which is the same interest rate basis
as the Company's senior debt borrowings.
In February and March 1999, the Company terminated its interest rate swaps
on notional balances totaling $100 million, resulting in proceeds received and a
gain of $1.1 million. This gain will be amortized against interest expense
through September 2005. In February 1999, the Company sold a call option that
allows the counterparty to terminate the interest rate swap in September 2001 on
the remaining $50 million notional balance, resulting in proceeds received of
$800,000. This amount will be deferred until the option is exercised or
expires.
47
<PAGE>
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, 1998 and 1997. The following are estimated fair
values and carrying values of the Company's other financial instruments at each
of these dates (in thousands):
<TABLE>
<CAPTION>
Asset (Liability)
----------------------------------------------
December 31, 1998 December 31, 1997
---------------------- ---------- ----------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Investment in equity securities.. $ 44,386 $ 44,386 $ - $ -
Short-term debt.................. (4,962) (4,962) - -
Long-term debt................... (921,000) (894,750) (539,000) (538,288)
Futures contracts................ - 3,525 - -
Basis swap agreements............ - (690) - -
Interest rate swap agreements.... - (2,722) - -
</TABLE>
The fair value of short-term borrowings and bank borrowings approximates
the carrying value because of short-term interest rate maturities. The fair
value of subordinated notes is based on a current market quote, while other
long-term debt is based on the estimated present value of expected cash flows.
The fair value of all other financial instruments is based on current market
quotes.
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 $375,000 at December 31, 1998 and
$911,000 at December 31, 1997. Financial and commodity-based swap contracts
expose the Company to the credit risk of non-performance by the counterparty to
the contracts. The Company does not believe this risk is significant since
these contracts are placed with major banks and financial institutions.
48
<PAGE>
9. Earnings Per Share
The following reconciles earnings (numerator) and shares (denominator) used
in the computation of basic and diluted earnings per share (in thousands, except
per share data):
<TABLE>
<CAPTION>
Earnings
Earnings Shares per Share
-------- -------- ---------
<S> <C> <C> <C>
1998
- ------------------------------------------------------
Basic
Net loss....................................... $(69,719)
Preferred stock dividends...................... (1,779)
--------
Loss available to common stock - basic......... (71,498) 43,396 $(1.65)
=========
Diluted
Effect of dilutive securities (a):
Stock options................................ - 338
Warrants..................................... - 23
-------- ------
Loss available to common stock-diluted......... $(71,498) 43,757 $ (1.65)(b)
======== ======== =========
1997
- ------------------------------------------------------
Basic
Net income..................................... $ 25,684
Preferred stock dividends...................... (1,779)
--------
Earnings available to common stock - basic..... 23,905 39,773 $ 0.60
=========
Diluted
Effect of dilutive securities:
Stock options.......................... - 451
Warrants............................... - 3
5 1/4% convertible subordinated notes.. 46 115
-------- --------
Earnings available to common stock - diluted... $ 23,951 40,342 $ 0.59
======== ======== =========
1996
- ------------------------------------------------------
Basic
Net income..................................... $ 20,304
Preferred stock dividends...................... (514)
--------
Earnings available to common stock - basic..... 19,790 39,913 $ 0.50
=========
Diluted
Effect of dilutive securities:
Stock options.......................... - 361
5 1/4% convertible subordinated notes.. 2,570 6,039
-------- --------
Earnings available to common stock - diluted... $ 22,360 46,313 $ 0.48
======== ======== =========
</TABLE>
(a) Based on common shares outstanding at December 31, 1998, potential
conversion of Series A convertible preferred stock becomes dilutive to
earnings per share when annual earnings available to common stock
exceeds approximately $32.4 million and when quarterly earnings
available to common stock exceeds approximately $8.1 million.
(b) Because of the antidilutive effect of dilutive securities on loss per
common share, diluted loss available to common stock is the same as
basic.
49
<PAGE>
10. Supplemental Cash Flow Information
The consolidated statements of cash flows exclude the following non-cash
transactions :
- The Cook Inlet Acquisition on September 30, 1998 (Note 12), a purchase
of oil-producing properties for 1,921,850 shares of common stock, a
related effective guarantee of $20 per share value (Note 7) and a $6
million note payable (Note 4)
- Issuance of warrants in 1997 to purchase 937,500 shares of common stock
and exchange of properties valued at $15.7 million, as partial
consideration for producing properties acquired
- Grants of performance shares of 82,125 in 1998, 180,000 in 1997 and
167,625 in 1996 to key employees and nonemployee directors (Note 11)
- Vesting of performance shares of 81,000 in 1998 and 243,000 performance
shares in 1997
- Receipt of common stock of 8,904 shares (valued at $181,000) in 1998,
421,212 shares (valued at $5,430,000) in 1997 and 457,994 shares (valued
at $4,768,000) in 1996 for the option price of exercised stock options
- Conversion of 5 1/4% convertible subordinated notes of $29.7 million
principal amount into 2,892,363 shares of common stock in 1997 and $27.7
million principal amount into 2,696,521 shares of common stock in 1996
- Exchange of 2,979,249 shares of common stock for 1,138,729 shares of
Series A convertible preferred stock in 1996
Interest payments during 1998 totaled $57,200,000, including $1,070,000 of
capitalized interest. Interest payments totaled $21,276,000 in 1997 and
$16,369,000 in 1996. Income tax payments were $941,000 in 1997 and $6,000 in
1996; during 1998, net income tax refunds were $454,000.
11. 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. The Company matches employee
contributions of up to 10% of wages (8% of wages prior to January 1, 1998).
Employee contributions vest immediately while the Company's matching
contributions vest 100% after three years of service. All employees over 21
years of age and with at least three months service with the Company may
participate. Company contributions under the plan were $1,766,000 in 1998,
$1,180,000 in 1997 and $979,000 in 1996.
1991 Stock Incentive Plan
A total of 1,012,500 incentive units ("Units"), have been granted to
directors, officers and other key employees under the 1991 Stock Incentive Plan
("1991 Plan"). 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. As of December 31, 1998, 3,341
Units remain available for grant under the 1991 Plan. General and
administrative expense includes a reduction of stock incentive compensation
related to SARs of $299,000 in 1998, and stock incentive compensation expense of
$359,000 in 1997 and $3.7 million in 1996. SAR cash payments were $180,000 in
1998, $288,000 in 1997 and $7.1 million in 1996.
50
<PAGE>
1994 and 1997 Stock Incentive Plans
Under the 1994 Stock Incentive Plan ("1994 Plan") and the 1997 Stock
Incentive Plan ("1997 Plan"), a total of 2,250,000 shares of common stock may be
issued under each plan to directors, officers and other key employees pursuant
to grants of Options or performance shares of common stock ("performance
shares"). At December 31, 1998, 25,177 shares remained available for grant
under the 1994 Plan and 102,624 shares remained available for grant under the
1997 Plan. Options vest and become exercisable on terms specified when granted
by the compensation committee ("the Committee") of the Board of Directors.
Options granted under the 1994 Plan are not exercisable prior to six months and
no Option is exercisable after ten years from its grant date. Options granted
under the 1994 Plan and the 1997 Plan generally vest in equal amounts over five
years, with provisions for earlier vesting if specified performance requirements
are met. In May 1998, all options under the 1994 Plan vested by resolution of
the Board of Directors. As of December 31, 1998, there are 356,250 outstanding
stock options under the 1997 Plan that vest when the common stock price reaches
$25.
1998 Stock Incentive Plan
In May 1998, the stockholders approved the 1998 Stock Incentive Plan ("1998
Plan") under which 6 million shares of common stock are available for grant.
Grants under the 1998 Plan are subject to the provision that outstanding stock
options and performance shares under all the Company's stock incentive plans
cannot exceed 6% of the Company's outstanding common stock at the time such
grants are made. During 1998, 675,750 stock options were granted under the 1998
Plan. Additionally, 810,375 stock options were designated to be granted to
specific optionees upon each of their exercises of all outstanding vested
options granted under the 1997 Plan. Stock options will vest and become
exercisable annually in equal amounts over a five-year period, with provision
for accelerated vesting of half the options when the common stock price first
closes at or above $25, and of the remainder when the common stock price first
closes at or above $30.
Performance Shares
Performance shares granted under the 1994, 1997 and 1998 Plans are subject
to restrictions determined by the Committee and are subject to forfeiture if
performance targets are not met. Otherwise, holders of performance shares
generally have all the voting, dividend and other rights of other stockholders.
The Company issued performance shares to key employees totaling 72,000 in 1998,
169,875 in 1997 and 154,125 in 1996, of which 81,000 vested in 1998 and 243,000
vested in 1997 when the common stock price reached specified levels. General
and administrative expense includes compensation related to these performance
share grants of $1.6 million in 1998, $3.3 million in 1997 and $2.5 million in
1996. As of December 31, 1998, there are 72,000 performance shares that vest
when the common stock price reaches $22.50. The Company also issued to
nonemployee directors a total of 10,125 performance shares in each of 1998 and
1997 and 13,500 performance shares in 1996, which vested upon grant.
Royalty Trust Option Plan
In May 1998, the stockholders approved the 1998 Royalty Trust Option
Plan ("Option Plan"). Under the terms of the Option Plan, the Company may grant
to key employees options to purchase units of beneficial interest in one or more
royalty trusts that may be established by the Company. Such options will allow
the purchase of royalty trust units at fair market value on the date of grant in
an aggregate amount not to exceed $12 million. In December 1998, the Company
granted options to purchase Hugoton Royalty Trust units at a total price of $12
million, subject to completion of the initial public offering of the Hugoton
Royalty Trust within six months of the date of grant. The options will be
priced at the initial public offering price.
51
<PAGE>
Unit/ Option Activity and Balances
The following summarizes Unit and Option activity and balances from 1996
through 1998:
1994, 1997
Weighted and
Average 1991 Plan 1998 Plans
Exercise Incentive Stock
Price Units Options
------- --------- ----------
1996
- --------------------------------------
Beginning of year........... $ 6.27 835,810 1,399,250
Grants................. 9.64 - 303,750
Exercises.............. 5.70 (784,658) (211,079)
Forfeitures............ 6.61 (189) (4,925)
-------- ----------
End of year................. 7.32 50,963 1,486,996
======== ==========
Exercisable at end of year.. 6.66 50,963 1,006,146
======== ==========
1997
- --------------------------------------
Beginning of year........... $ 7.32 50,963 1,486,996
Grants................. 12.11 - 1,757,250
Exercises.............. 6.75 (26,213) (897,234)
Forfeitures............ 8.79 - (18,315)
-------- ----------
End of year................. 11.11 24,750 2,328,697
======== ==========
Exercisable at end of year.. 10.96 24,750 1,119,044
======== ==========
1998
- --------------------------------------
Beginning of year........... $11.11 24,750 2,328,697
Grants................. 17.52 - 1,395,750
Exercises.............. 11.64 (6,750) (1,081,711)
Forfeitures............ 17.19 - (21,750)
-------- ----------
End of year................. 14.23 18,000 2,620,986
======== ==========
Exercisable at end of year.. 11.03 18,000 1,351,236
======== ==========
The following summarizes information about Units/ Options at December 31,
1998:
<TABLE>
<CAPTION>
Units/ Options Outstanding Units/ Options Exercisable
------------------------------- --------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Prices Number Term Price Number Price
--------------- --------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C>
1991 Plan
$5.32-$7.56 18,000 3.1 years $ 5.43 18,000 $ 5.43
1994, 1997 and 1998 Plans
$6.61-$7.89 235,015 6.5 years 7.23 235,015 7.23
$9.67-$10.92 264,971 7.4 years 9.68 264,971 9.68
$12.04-$13.40 762,500 8.4 years 12.27 747,000 12.21
$15.53-$18.22 1,358,500 9.4 years 17.58 104,250 15.54
--------- ---------
2,638,986 1,369,236
========= =========
</TABLE>
52
<PAGE>
Estimated Fair Value of Grants
Using the Black-Scholes option-pricing model and the following assumptions,
the weighted average fair value of option grants was estimated to be $6.82 in
1998, $5.05 in 1997 and $3.82 in 1996.
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Risk-free interest rates......... 5.6% 6.4% 6.4%
Dividend yield................... 3.2% 1.6% 1.4%
Weighted average expected lives.. 5 years 5 years 6 years
Volatility....................... 52% 47% 35%
</TABLE>
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 1998, 1997 and 1996, 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):
<TABLE>
<CAPTION>
(in thousands, except per share data)
1998 1997 1996
-------- ------- -------
<S> <C> <C> <C>
Earnings (loss) available to common stock:
As reported............................... $(71,498) $23,905 $19,790
Pro forma................................. $(75,785) $21,646 $19,767
Earnings (loss) per common share:
Basic As reported...................... $ (1.65) $ 0.60 $ 0.50
Pro forma........................ $ (1.75) $ 0.54 $ 0.50
Diluted As reported...................... $ (1.65) $ 0.59 $ 0.48
Pro forma........................ $ (1.75) $ 0.54 $ 0.48
</TABLE>
12. Acquisitions
On May 14, 1997, the Company acquired primarily gas-producing properties in
Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39
million from a subsidiary of Burlington Resources Inc. The properties are
primarily operated interests. The Company funded the acquisition with bank debt
and cash flow from operations.
On December 1, 1997, the Company acquired interests in certain producing
oil and gas properties in the San Juan Basin of New Mexico ("Amoco Acquisition")
from a subsidiary of Amoco Corporation ("Amoco") for $252 million, including
warrants to purchase 937,500 shares of the Company's common stock at a price of
$15.31 per share for a period of five years. After adjustments for other
acquisition costs, estimated cash flows through date of closing and preferential
purchase rights exercised by third parties, the properties were purchased for
approximately $195 million, including approximately $5.7 million value for the
warrants. Amoco elected to accept certain producing properties owned by the
Company valued at $15.7 million in lieu of cash, reducing cash consideration to
$173.6 million, which was funded with bank debt. Additional purchase price
revisions may result from post-closing adjustments.
On April 24, 1998, the Company acquired producing properties in the East
Texas Basin from EEX Corporation ("East Texas Basin Acquisition") for $265
million. After purchase price adjustments primarily resulting from net revenues
from the January 1, 1998 effective date through April 24, 1998, the properties
were purchased for an estimated price of $245 million. In connection with the
acquisition, the Company sold a production payment to EEX Corporation for $30
million. The production payment is payable from production from certain
properties acquired in the East Texas Basin Acquisition during the 10-year
period beginning January 1, 2002. EEX Corporation effectively pays all taxes,
royalties and production expenses related to such production. The Company has
the option to repurchase a portion of this production payment each December,
beginning in 1998; this option was not exercised in December 1998. The cost of
the East Texas Basin Acquisition (net of the production payment sold) of $215
million was funded by bank borrowings
53
<PAGE>
which were partially repaid by proceeds from the sale of common stock (Note 7).
Purchase price revisions may result from post-closing adjustments.
On September 30, 1998, the Company acquired oil-producing properties in the
Middle Ground Shoal Field of Alaska's Cook Inlet ("Cook Inlet Acquisition") from
various Shell Oil Company affiliates ("Shell"). The acquired interests include
a 100% working interest in two State of Alaska leases, two offshore production
platforms and a 50% interest in certain operated production pipelines and
onshore processing facilities. The acquisition had an effective date of July 1,
1998, and is subject to customary post-closing adjustments. The Company acquired
the properties in exchange for 1,921,850 shares of the Company's common stock.
These shares are subject to a contractual $20 price guarantee, resulting in an
accrued liability of $24 million recorded at December 31, 1998 (Note 7). The
Company also executed a non-interest bearing promissory note to Shell for $6
million. Payments under this note of $3 million, $2 million and $1 million are
due when the average NYMEX crude oil price for 60 consecutive calendar days
equals or exceeds $18.50, $19.50 and $20.50, respectively. The total estimated
purchase price of the Cook Inlet Acquisition is $44.4 million. See Note 3.
On March 1, 1999, the Company and Shell entered into an amended agreement
to postpone Shell's resale of Company common stock to no later than August 16,
1999. Prior to that date, the Company will have the options of purchasing the
common stock from Shell, registering the shares for resale by Shell, or
exchanging the shares with another Company security to be resold by Shell. In
the interim, the Company has agreed to make payments to Shell of up to $20
million, including a payment of $5 million on March 2, 1999, and has entered
into gas sales and transportation contracts that provide Shell with an estimated
value of $7.5 million. If Shell's proceeds from the sale of Company securities
exceeds the remaining amount due Shell, the difference will be refunded to the
Company; otherwise, the difference will be paid to Shell.
On November 20, 1998, the Company acquired primarily gas-producing
properties in northwest Oklahoma and the San Juan Basin of New Mexico for $33.4
million from Seagull Energy Corp. After purchase price adjustments primarily
resulting from net revenues from the October 1, 1998 effective date through
November 20, 1998, the properties were purchased for an estimated price of $29.2
million. Additional purchase price revisions may result from post-closing
adjustments. The Company funded the acquisition with existing lines of credit.
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, 1998 and 1997 as if these acquisitions and the
April 1998 sale of common stock had been consummated as of January 1, 1998 and
1997. These pro forma results are not necessarily indicative of future results.
<TABLE>
<CAPTION>
(in thousands, except per share data) Pro Forma (Unaudited)
---------------------
1998 1997
--------- ---------
<S> <C> <C>
Revenues................................... $ 293,201 $ 366,041
========= =========
Net income (loss).......................... $(64,374) $ 59,924
========= =========
Earnings (loss) available to common stock.. $(66,153) $ 58,145
========= =========
Earnings (loss) per common share:
Basic................................ $ (1.41) $ 1.19
========= =========
Diluted.............................. $ (1.41) $ 1.15
========= =========
</TABLE>
The Company filed a registration statement with the Commission in December
1998 to sell approximately 40% of the Hugoton Royalty Trust units to the public
in March or April 1999 (Note 1). The unit sales price is expected to be in the
range of $9.00 to $10.00. Assuming the underwriters' overallotment option is not
exercised, the Company will sell 15,000,000 units, or 37.5% of the Trust. Based
on a mid-range price of $9.50 per unit, net proceeds to be received by the
Company is estimated to be $131.5 million, net of underwriters' discount and
offering expenses. Proceeds from the sale will be used to reduce bank debt. Pro
forma results of operations for the year ended December 31, 1998, as if the sale
of Trust units and the acquisitions described above were consummated immediately
prior to January 1, 1998, would be: revenues of $269.2 million, net loss of
$63.7 million and loss available to common stock of $65.5 million, or $1.39 per
common share.
54
<PAGE>
13. Quarterly Financial Data (Unaudited)
The following are summarized quarterly financial data for the years ended
December 31, 1998 and 1997 (in thousands, except per share data):
<TABLE>
<CAPTION>
Quarter
--------------------------------------
1st 2nd 3rd 4th
------- ------- -------- --------
<S> <C> <C> <C> <C>
1998
- ---------------------------------
Revenues.................... $49,968 $61,652 $ 67,044 $ 70,822
Gross profit (a)............ $13,007 $14,510 $ 16,568 $ 9,656
Earnings (loss) available to
common stock.............. $ (184) $ 759 $(31,004) $(41,069)
Earnings (loss) per common
share
Basic..................... $ 0.00 $ 0.02 $ (0.69) $ (0.90)
Diluted................... $ 0.00 $ 0.02 $ (0.69) $ (0.90)
Average shares outstanding.. 39,046 43,940 44,765 45,440
1997
- ---------------------------------
Revenues.................... $52,286 $45,520 $ 43,734 $ 56,732
Gross profit (a)............ $24,625 $16,595 $ 14,242 $ 23,834
Earnings available to
common stock.............. $10,650 $ 3,735 $ 2,779 $ 6,741
Earnings per common share
Basic..................... $ 0.26 $ 0.09 $ 0.07 $ 0.17
Diluted................... $ 0.25 $ 0.09 $ 0.07 $ 0.17
Average shares outstanding.. 40,395 39,498 39,581 39,629
</TABLE>
(a) Operating income before general and administrative expense.
14. 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):
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Acquisitions:
Producing properties.... $339,889 $251,663 $105,252
Undeveloped properties.. 514 3,964 563
Development (a)............ 69,367 86,555 44,758
Exploration (b)............ 8,034 2,088 280
-------- -------- --------
Total...................... $417,804 $344,270 $150,853
======== ======== ========
</TABLE>
(a) Includes capitalized interest of $1,070,000 in 1998 and $800,000 in
1997. No interest was capitalized in prior years.
(b) Primarily includes geological and geophysical costs.
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
55
<PAGE>
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.
56
<PAGE>
<TABLE>
<CAPTION>
Oil Gas Natural Gas
(Bbls) (Mcf) Liquids (Bbls) (a)
--------------- --------- ------------------
Proved Reserves (in thousands)
<S> <C> <C> <C>
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 -
Revisions.............................. (989) (14,182) -
Extensions, additions and discoveries.. 9,263 112,906 -
Production............................. (3,980) (49,587) (80)
Purchases in place..................... 3,195 248,040 13,890
Sales in place......................... (2,075) (21,940) -
--------------- --------- -----------------
December 31, 1997........................ 47,854 815,775 13,810
Revisions.............................. (5,893) (5,429) 2,631
Extensions, additions and discoveries.. 821 172,059 1,875
Production............................. (4,598) (83,847) (1,222)
Purchases in place..................... 16,331 311,260 80
Sales in place......................... (5) (594) -
--------------- --------- -----------------
December 31, 1998........................ 54,510 1,209,224 17,174
=============== ========= =================
Proved Developed Reserves
December 31, 1995........................ 28,946 320,230
=============== =========
December 31, 1996........................ 31,883 466,412
=============== =========
December 31, 1997........................ 33,835 677,710 11,494
=============== ========= =================
December 31, 1998........................ 42,876 968,495 14,000
=============== ========= =================
</TABLE>
(a) Proved reserves attributable to natural gas liquids were not
considered significant prior to the Amoco Acquisition in December 1997
(Note 12). Natural gas liquids proved reserves as disclosed include
only San Juan Basin properties purchased in this acquisition.
<TABLE>
<CAPTION>
Standardized Measure of Discounted Future December 31
Net Cash Flows Relating to Proved Reserves --------------------------------------
1998 1997 1996
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Future cash inflows...................... $ 3,041,776 $ 2,604,453 $ 2,634,641
Future costs:............................
Production............................ (1,135,789) (979,317) (819,780)
Development........................... (228,561) (140,594) (77,837)
----------- ----------- -----------
Future net cash flows before income tax.. 1,677,426 1,484,542 1,737,024
Future income tax........................ (231,249) (291,375) (450,987)
----------- ----------- -----------
Future net cash flows.................... 1,446,177 1,193,167 1,286,037
10% annual discount...................... (637,774) (551,058) (579,556)
----------- ----------- -----------
Standardized measure (a)................. $ 808,403 $ 642,109 $ 706,481
=========== =========== ===========
</TABLE>
(a) Before income tax, the year-end standardized measure (or discounted
present value of future net cash flows) was $908,606,000 in 1998,
$782,322,000 in 1997 and $946,150,000 in 1996.
57
<PAGE>
<TABLE>
<CAPTION>
Changes in Standardized Measure of
Discounted Future Net Cash Flows 1998 1997 1996
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Standardized measure, January 1........ $ 642,109 $ 706,481 $ 335,156
----------- ----------- -----------
Revisions:
Prices and costs..................... (184,568) (388,559) 360,053
Quantity estimates................... 65,600 55,497 34,099
Accretion of discount................ 71,942 86,845 37,291
Future development costs............. (104,636) (120,073) (36,267)
Income tax........................... 40,011 99,455 (169,118)
Production rates and other........... (296) (1,614) (155)
----------- ----------- -----------
Net revisions..................... (111,947) (268,449) 225,903
Extensions, additions and discoveries.. 96,829 92,582 49,802
Production............................. (146,498) (125,343) (97,106)
Development costs...................... 56,904 73,062 33,484
Purchases in place (a)................. 271,806 207,387 160,670
Sales in place......................... (800) (43,611) (1,428)
----------- ----------- -----------
Net change........................ 166,294 (64,372) 371,325
----------- ----------- -----------
Standardized measure, December 31...... $ 808,403 $ 642,109 $ 706,481
=========== =========== ===========
</TABLE>
(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 $9.50 for 1998, $15.50 for 1997,
$24.25 for 1996 and $18.00 for 1995. Year-end average gas prices were $2.01 for
1998, $2.20 for 1997, $3.02 for 1996 and $1.68 for 1995. Year-end average
natural gas liquids prices were $3.99 for 1998 and $11.07 for 1997. Proved oil
and gas reserves at December 31, 1998 include 209,000 Bbls and 8,278,000 Mcf,
and the standardized measure, before income tax, includes approximately $8
million attributable to the Company's ownership of approximately 22% of the
Cross Timbers Royalty Trust. Year-end 1998 oil and gas reserves also include
3,224,000 Bbls and 412,058,000 Mcf, and the standardized measure, before income
tax, includes approximately $280 million attributable to the Company's full
ownership of the Hugoton Royalty Trust.
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 are primarily the result of the extended economic life of proved
reserves and proved undeveloped reserve additions attributable to increased
development activity.
58
<PAGE>
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, 1998 and 1997, and the
related consolidated statements of operations, comprehensive income, cash flows
and stockholders' equity for each of the three years in the period ended
December 31, 1998. 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, 1998 and 1997, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 12, 1999
59
<PAGE>
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 16th day of April
1999.
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 16th day of April 1999.
PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS) DIRECTORS
BOB R. SIMPSON J. LUTHER KING, JR.
- -------------------------------------------- ----------------------------------
Bob R. Simpson, Chairman of the Board J. Luther King, Jr.
and Chief Executive Officer
STEFFEN E. PALKO JACK P. RANDALL
- -------------------------------------------- ----------------------------------
Steffen E. Palko, Vice Chairman of the Board Jack P. Randall
and President
J. RICHARD SEEDS SCOTT G. SHERMAN
- -------------------------------------------- ----------------------------------
J. Richard Seeds, Executive Vice President 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
60
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit
No. Description Page
- ------- --------------------------------------------------------------------- ----
<S> <C> <C>
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 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)
4.2 Indenture dated as of April 1, 1997, between Cross Timbers Oil Company
and The Bank of New York, as Trustee for the 9 1/4% Senior
Subordinated Notes due 2007 (incorporated by reference to Exhibit 4.1
to Registration Statement of Form S-4, File No. 333-26603)
4.3 Indenture dated as of October 28, 1997, between Cross Timbers Oil
Company and the Bank of New York, as Trustee for the 8 3/4% Senior
Subordinated Notes due 2009 (incorporated by reference to Exhibit 4.1
to Registration Statement on Form S-4, File No. 333-39097)
4.4 Preferred Stock Purchase Rights Agreement between Cross Timbers Oil
Company and ChaseMellon Shareholder Services, LLC (incorporated by
reference to Exhibit 4.1 to Form 8-A dated September 8, 1998)
10.1 Revolving Credit Agreement dated November 16, 1998, between Cross
Timbers Oil Company and certain commercial banks named therein
(incorporated by reference to Exhibit 10.4 to Registration Statement
on Form S-1, File No. 333-68441)
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 4.5 to Registration Statement on Form S-8, File
No. 33-81766)
</TABLE>
61
<PAGE>
<TABLE>
<CAPTION>
Exhibit
No. Description Page
- ------- --------------------------------------------------------------------- ----
<S> <C> <C>
10.8 * 1997 Stock Incentive Plan, as amended February 25, 1998 (incorporated
by reference to Exhibit 10.8 to Form 10-K for the year ended December
31, 1997)
10.9 * Form of grant under 1997 Stock Incentive Plan, as amended February 25,
1998 (incorporated by reference to Exhibit 10.9 to Form 10-K for the
year ended December 31, 1997)
10.10 * 1998 Stock Incentive Plan (incorporated by reference to Exhibit 4.4 to
Registration Statement on Form S-8, File No. 333-69977)
10.11 * Form of grant under 1998 Stock Incentive Plan (incorporated by
reference to Exhibit 4.5 to Registration Statement on Form S-8, File
No. 333-69977)
10.12 * 1998 Royalty Trust Option Plan (incorporated by reference to Exhibit B
to the 1998 Proxy Statement filed on April 24, 1998)
10.13 * Management Group Employee Severance Protection Plan (incorporated by
reference to Exhibit 10.13 to Form 10-K for the year ended December
31, 1998)
10.14 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)
10.15 Warrant Agreement dated December 1, 1997 by and between Cross Timbers
Oil Company and Amoco Corporation (incorporated by reference to
Exhibit 10.11 to Form 10-K for the year ended December 31, 1997)
12.1 Computation of Ratio of Earnings to Fixed Charges (incorporated by
reference to Exhibit 12.1 to Form 10-K for the year ended December
31, 1998)
21.1 Subsidiaries of Cross Timbers Oil Company (incorporated by reference
to Exhibit 21.1 to Form 10-K for the year ended December 31, 1998)
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Miller and Lents, Ltd. (incorporated by reference to
Exhibit 23.2 to Form 10-K for the year ended December 31, 1998)
* Management contract or compensatory plan
</TABLE>
- --------------------
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.
62
<PAGE>
EXHIBIT 23.1
INDEPENDENT PUBLIC ACCOUNTANTS' CONSENT
Cross Timbers Oil Company
Fort Worth, Texas
As independent public accountants, we hereby consent to the incorporation by
reference in the Registration Statements on Form S-8 (Nos. 33-64274, 33-65238,
33-81766, 333-35229 and 333-36569) and on Form S-3 (No. 333-46909) of Cross
Timbers Oil Company and Form S-3 (No. 333-56983) of Cross Timbers Oil Company
and Cross Timbers Royalty Trust of our report dated March 12, 1999, included in
the Annual Report on Form 10-K of Cross Timbers Oil Company for the year ended
December 31, 1998.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
April 16, 1999
