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2000
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
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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)
Delaware 75-2347769 810 Houston Street, Suite 2000, Fort Worth, Texas 76102
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(State or other jurisdiction of (I.R.S. Employer (Address of principal executive offices) (Zip Code)
incorporation or organization) Identification No.)
Registrant's telephone number, including area code (817) 870-2800
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Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
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Common Stock, $.01 par value, including preferred New York Stock Exchange
stock purchase rights
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to be the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. _____
Aggregate market value of the Common Stock held by
nonaffiliates of the Registrant
as of March 16, 2001 was approximately $2,045,000,000
Number of Shares of Common Stock outstanding as of March 1, 2001 - 81,230,051
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, 2001.
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CROSS TIMBERS OIL COMPANY
2000 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
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....................... 16
Part II
5. Market for Registrant's Common Equity and Related Stockholder Matters..... 17
6. Selected Financial Data................................................... 18
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................................. 20
7A. Quantitative and Qualitative Disclosures about Market Risk................ 28
8. Financial Statements and Supplementary Data............................... 31
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................................. 31
PART III
10. Directors and Executive Officers of the Registrant........................ 31
11. Executive Compensation.................................................... 31
12. Security Ownership of Certain Beneficial Owners and Management............ 31
13. Certain Relationships and Related Transactions............................ 31
Part IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K........... 32
PART I
Items 1. and 2. Business and Properties
General
Cross Timbers Oil Company and its 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. Growth for the next year or more is expected to
be primarily internally generated and will be supplemented by incremental
acquisitions.
The Company's proved reserves are principally located in relatively long-
lived fields with well-established production histories concentrated in the East
Texas Basin, the Arkoma Basin of Arkansas and Oklahoma, the San Juan Basin of
northwestern New Mexico, the Hugoton Field of Oklahoma and Kansas, the Anadarko
Basin of Oklahoma, the Green River Basin of Wyoming, the Permian Basin of West
Texas and New Mexico, the Middle Ground Shoal Field of Alaska's Cook Inlet and
the Colquitt and Oaks Fields of Louisiana.
The Company's estimated proved reserves at December 31, 2000 were 58.4
million barrels ("Bbls") of oil, 1.8 trillion cubic feet ("Tcf") of natural gas
and 22 million Bbls of natural gas liquids, based on December 31, 2000 prices of
$25.49 per Bbl for oil, $9.55 per thousand cubic feet ("Mcf") for gas and $26.33
per Bbl for natural gas liquids. Approximately 76% of December 31, 2000 proved
reserves, computed on a gas energy equivalent ("Mcfe") basis, were proved
developed reserves. Increased proved reserves during 2000 were primarily the
result of development and exploitation activities, partially offset by
production and property sales. During 2000, the Company's daily average
production was 12,941 Bbls of oil, 343,871 Mcf of gas and 4,430 Bbls of natural
gas liquids. Fourth quarter 2000 daily average production was 12,852 Bbls of
oil, 366,007 Mcf of gas and 4,523 Bbls of natural gas liquids.
The Company's properties have relatively long reserve lives and highly
predictable production profiles. Based on December 31, 2000 proved reserves and
projected 2001 production, the average reserve-to-production index of the
Company's proved reserves is 14.4 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, 2000, the Company owned
interests in 6,885 gross (3,609 net) wells and operated wells representing 92%
of the present value of cash flows before income taxes (discounted at 10%) from
estimated proved reserves. The high proportion of operated properties allows
the Company to control expenses, capital allocation and the timing of
development and exploitation activities in its fields.
The Company has generated a substantial inventory of approximately 1,500
potential development drilling locations within its existing properties (of
which 684 have been attributed proved undeveloped reserves), to support future
net reserve additions. The Company estimates net potential reserves related to
unbooked development drilling locations to exceed 1.7 Tcf equivalent. The
Company's drilling plans are dependent upon product prices and the availability
of drilling equipment.
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.
The Company operates gas gathering systems in East Texas, the Arkoma Basin
of Arkansas and Oklahoma, the Hugoton Field of Kansas and Oklahoma and Major
County, Oklahoma. The Company also operates a gas processing plant in the
Hugoton Field. The Company's gas gathering and processing operations are only
in areas where the Company has production and are considered activities which
add value to the Company's natural gas production and sales operation.
1
Most of the Company's production is sold at current market prices. The
Company markets its gas production and the gas output of its gathering and
processing systems. A large portion of natural gas is processed and the
resultant natural gas liquids are marketed by unaffiliated third parties. The
Company uses fixed price physical sales contracts and futures, forward sales
contracts and other price risk management instruments to hedge pricing risks.
See "Delivery Contracts" and Part II, Item 7A.
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. The Company completed its initial public offering of common stock
in May 1993.
During 1991, the Company formed Cross Timbers Royalty Trust by conveying a
90% net profits interest in substantially all of the royalty and overriding
royalty interests then owned in Texas, New Mexico and Oklahoma, and a 75% net
profits interests in seven nonoperated working interest properties in Texas and
Oklahoma. 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 to register the Company's
1,360,000 units for sale in a public offering. The registration statement was
filed in anticipation of improving commodity prices and related market
conditions for oil and gas equities. The registration statement was amended in
October 2000.
In December 1998, the Company formed the Hugoton Royalty Trust by conveying
an 80% net profits interest in principally gas-producing operated interests in
the Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the
Green River Basin of Wyoming. These net profits interests were conveyed to the
trust in exchange for 40 million units of beneficial interest. The Company sold
17 million units in the trust's initial public offering in 1999 and 1.3 million
units pursuant to an employee incentive plan in 1999 and 2000. Hugoton Royalty
Trust units are listed on the New York Stock Exchange under the symbol "HGT."
Industry Operating Environment
The oil and gas industry is affected by many factors that the Company
generally cannot control. Governmental regulations, particularly in the areas
of taxation, energy and the environment, can have a significant impact on
operations and profitability. Crude oil prices are determined by global supply
and demand. Oil supply is significantly influenced by production levels of OPEC
member countries, while demand is largely driven by the condition of worldwide
economies, as well as weather. The Company's natural gas prices are generally
determined by North American supply and demand. Weather has a significant
impact on demand for natural gas since it is a primary heating resource. Its
increased use for electrical generation has kept natural gas demand elevated
throughout the year, removing some of the seasonal swing in prices. See
"General - Product Prices" in Part II, Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations", regarding recent
price fluctuations and their effect on the Company's results.
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.
2
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, and 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
financing to supplement internally generated cash flow.
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 drilling and other development programs.
The Company has generated an inventory of approximately 1,500 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.
Exploration Activities. During 2001, the Company plans to 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
approximately $10 million of its $250 million 2001 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, co-founders of the Company, 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 if such interests otherwise meet
its acquisition criteria. The Company attempts to acquire nonoperated interests
in fields where the operators have a significant interest to protect. The
Company may also acquire nonoperated interests in order to ultimately accumulate
sufficient ownership interests to operate the properties. The Company attempts
to acquire nonoperated interests with potential undeveloped reserves that will
be exploited by the operator.
The Company also attempts to acquire a portion of its reserves as royalty
interests. Royalty interests have few operational liabilities because they do
not participate in operating activities and do not bear production or
development costs.
Royalty Trusts. In December 1998, the Company created the Hugoton Royalty
Trust and sold 42.5% of the trust to the public in April and May 1999. An
additional 3.2% of the units were sold in 1999 and 2000, pursuant to an employee
incentive plan. Sales of royalty trust units allow the Company to more
efficiently capitalize its mature, lower growth properties. The Company may
create and sell interests in additional royalty trusts in the future.
3
Business Goals. In November 2000, the Company announced its strategic goal
for 2001of increasing gas production by 15%. This goal was updated in December
to 20% gas production growth for 2001 and 2002. In March 2001, the Company
announced goals for increasing proved reserves to 2.6 Tcfe at year-end 2001 and
3 Tcf equivalent at year-end 2002. To achieve these growth targets, the Company
plans to drill about 245 (178 net) wells and perform approximately 380 (271 net)
workovers and recompletions. The Company plans to reduce debt with operating
cash flow.
The Company has budgeted $250 million for its 2001 development program,
which is expected to be funded primarily by cash flow from operations. About
50% of the development budget will be spent in East Texas with the balance
evenly allocated to Arkoma Basin, San Juan Basin, Alaska, Permian Basin and
Hugoton Royalty Trust properties. Exploration expenditures are expected to be
approximately 4% of the 2001 budget. The total capital budget, including
acquisitions, will be adjusted throughout 2001 depending on oil and gas prices
to capitalize on opportunities offering the highest rates of return.
Acquisitions
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. The Company sold these
properties for $43 million in March 2000. From July through December 1996, the
Company acquired 955,800 units or 16% of the 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.
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 in December 1997 at an adjusted purchase price of $195
million, including five-year warrants to purchase 1.4 million shares of the
Company's common stock at a price of $10.05 per share. This acquisition
consisted primarily of operated properties in the San Juan Basin of New Mexico.
In May 1997, the Company acquired properties in Oklahoma, Kansas and Texas for
an 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 in April 1998 at a 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 2.9 million shares of the Company's common stock along with certain price
guarantees and a non-interest bearing note payable of $6 million, resulting in a
total purchase price of $45 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 $31 million. The 1998 acquisitions increased
reserves by approximately 16.3 million Bbls of oil and 311.3 Bcf of natural gas.
In 1999, the Company and Lehman Brothers Holdings, Inc. acquired the common
stock of Spring Holding Company, a private oil and gas company, for a
combination of cash and Cross Timbers' common stock totaling $85 million. The
Company and Lehman each owned 50% of a limited liability company that acquired
the common stock of Spring. In September 1999 the Company exercised its option
to acquire Lehman's 50% interest in Spring for $44.3 million. This acquisition
includes oil and gas properties located in the Arkoma Basin of Arkansas and
Oklahoma with a purchase price of $235 million. After purchase accounting
adjustments and other costs, the cost of the properties was $253 million. The
Company also acquired, with Lehman as 50% owner, Arkoma Basin properties from
affiliates of Ocean Energy, Inc. for $231 million. The Company exercised its
option to acquire Lehman's interest in the Ocean Energy Acquisition on March 31,
2000 for $111 million. The 1999 acquisitions, including Lehman's 50% interest
in the Spring and Ocean Energy acquisitions, increased reserves by approximately
2.8 million Bbls of oil and 494.7 Bcf of natural gas.
4
During 2000, the Company acquired oil- and gas-producing properties for a
total cost of $32 million, including $11 million paid to Lehman in March 2000 in
excess of its investment in the Ocean Energy Acquisition. There were no
individually significant acquisitions in 2000. In December 2000, the Company
entered into a definitive agreement with Herd Producing Company, Inc. to acquire
primarily gas-producing properties in East Texas and Louisiana for $115 million.
The purchase was completed on January 3, 2001, and increased reserves by
approximately 175 Bcf of natural gas.
Many of the properties acquired from 1996 through 1998 in Kansas, Oklahoma
and Wyoming are subject to the 80% net profits interest conveyed to Hugoton
Royalty Trust. The Company sold 45.7% of its Hugoton Royalty Trust units in
1999 and 2000.
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, 2000:
Proved Reserves
--------------------------------------------------- Discounted
(in thousands) Natural Gas Natural Gas Present Value
Oil Gas Liquids Equivalents before Income Tax
(Bbls) (Mcf) (Bbls) (Mcfe) of Proved Reserves
------- ---------- ----------- ----------- ---------------------
East Texas....................... 2,870 621,645 - 638,865 $2,575,779 33.2%
Arkoma Basin..................... 38 478,776 - 479,004 2,028,993 26.2%
San Juan Basin................... 1,447 291,829 22,012 432,583 1,249,886 16.1%
Hugoton Royalty Trust (a)........ 2,877 326,582 - 343,844 1,230,419 15.9%
Permian Basin.................... 35,285 34,909 - 246,619 451,071 5.8%
Alaska Cook Inlet................ 13,873 - - 83,238 128,412 1.7%
Cross Timbers Royalty Trust (b).. 1,710 12,410 - 22,670 63,185 0.8%
Other............................ 345 3,532 - 5,602 20,887 0.3%
------- ---------- ----------- ----------- ---------- ------
Total............................ 58,445 1,769,683 22,012 2,252,425 $7,748,632 100.0%
======= ========== =========== =========== ========== ======
(a) Includes 1,970,000 Bbls of oil and 223,578,000 Mcf of gas and discounted
present value before income tax of $842,346,000 related to the Company's
ownership of approximately 54% of Hugoton Royalty Trust units at December
31, 2000.
(b) Includes 747,000 Bbls of oil and 7,986,000 Mcf of gas and discounted
present value before income tax of $38,403,000 related to the Company's
ownership of approximately 23% of Cross Timbers Royalty Trust units at
December 31, 2000.
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 652 gross (635 net) wells which it operates and 46 gross
(5.8 net) wells operated by others. The Company also owns the related gathering
facilities.
During 2000, the East Texas area was the Company's most active gas
development area, where 44 gross (42.3 net) gas wells were drilled and 97
workovers were performed. The formations targeted were the Travis Peak, Cotton
Valley and Bossier. The Company plans to continue to extensively develop this
area, including drilling approximately 97 wells in 2001.
Arkoma Basin Area
During 1999, the Company acquired interests in approximately 2,500 wells
and a gas gathering system in the Arkoma Basin of Arkansas and Oklahoma. The
Arkoma Basin, discovered in the 1920's, stretches from central Arkansas into
eastern Oklahoma and is known for shallow production decline rates, multiple
formations and complex geology. With these acquisitions, the Company controls
40% of Arkansas production from the Arkoma Basin. The Company owns an interest
in 839 gross (589.8 net) wells which it operates and 626 gross (112.8 net) wells
operated by
5
others. Of these wells, 136 gross (87.7 net) operated wells and 72
gross (13.7 net) nonoperated wells are dual completions.
The acquired properties can be separated into three distinct areas, which
are the Oklahoma Cromwell/Atoka trend, the Arkansas Fairway trend and the
Arkansas Overthrust trend. The Oklahoma Cromwell/Atoka trend of eastern
Oklahoma was originally developed in the 1970's targeting the Cromwell Sands and
Atoka formations. The Arkansas Fairway trend is comprised of multiple
sandstones at depths ranging from 2,500 to 7,500 feet in the Atoka and Morrow
intervals. The Arkansas Overthrust trend is characterized by extremely complex
geology and will require an ongoing process to develop the best exploitation
opportunities.
In 2000, the Company drilled 47 gross (27.5 net) wells, completed 90
workovers, including 20 wellhead compressors, and drilled two successful
exploration wells in the Pine Hollow Field. The Company plans to drill 70
wells, perform 115 workovers and install 80 wellhead compressors in the Arkoma
Basin during 2001.
San Juan Basin Area
The San Juan Basin of northwestern New Mexico and southwestern Colorado
contains the second largest natural gas reserves in North America. The Company
acquired most of its interests in the San Juan Basin in December 1997 from a
subsidiary of Amoco Corporation. The Company owns an interest in 684 gross
(550.2 net) wells that it operates and 372 gross (90.7 net) wells operated by
others. Of these wells, 82 gross (71.2 net) operated wells and six gross (0.6
net) nonoperated wells are dual completions.
During 2000, the Company participated in the drilling of 34 gross (27.1
net) wells, completed 19 workovers and installed over 93 wellhead compressors.
During 2001, the Company plans to drill 43 wells and perform 15 workovers. The
Company also plans to continue to install wellhead compressors at approximately
the same level as 2000.
Hugoton Royalty Trust Areas
A substantial portion of properties in the Mid-Continent area, the Hugoton
area and the Green River Basin of the Rocky Mountains are subject to an 80% net
profits interest conveyed to the Hugoton Royalty Trust as of December 1998. The
Company sold 45.7% of its Hugoton Royalty Trust units in 1999 and 2000.
Mid-Continent Area
The Company is one of the largest producers in the Major County, Oklahoma
area of the Anadarko Basin. The Company operates 459 gross (402.5 net) wells
and has an interest in 113 gross (30.3 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, Inola, 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 2000, the Company participated in the drilling of 18 gross
(12.9 net) wells in the northwestern portion of the County, targeting the
Chester, Inola, Oswego and Red Fork formations. The Company has budgeted 10
drill wells in Major County for 2001.
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 18,000 Mcf per day, 70% of which is produced from
Company-operated wells. Estimated capacity of the gathering system is 40,000 Mcf
per day. Gas is delivered to a processing plant owned and operated by a third
party, and then transmitted by a 26-mile Company-operated pipeline to
connections with other pipelines.
6
The Company was also very active in Woodward County, Oklahoma, where 15
gross (13.7 net) wells were drilled. In 2001, the Company plans to drill up to
15 wells.
Hugoton Area
The Hugoton Field, discovered in 1922, covers parts of Texas, Oklahoma and
Kansas and is the largest gas field in North America with an estimated five
million productive acres. The Company owns an interest in 380 gross (356.5 net)
wells that it operates and 77 gross (18.2 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. During 1998,
the Company completed the acquisition of approximately 70 miles of low pressure
gathering lines, increasing production by 3,500 Mcf per day. During 1999 and
2000, the Company installed additional lateral compressors that lowered the line
pressure and increased production in various areas of the Hugoton Field.
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. In June 1999, Oklahoma
regulations were amended to allow increased drilling density in the Oklahoma
portion which was previously drilled on 640-acre spacing. The Company believes
it has approximately 200 potential infill drilling locations in Oklahoma.
During 2000, the Company drilled one well to the Chester, Council Grove and
Oswego formations.
Green River Basin
The Green River Basin is located in southwestern Wyoming. The Company has
interests in 179 gross (177.5 net) wells that it operates and 31 gross (4.1 net)
wells operated by others in the Fontenelle Field.
Gas production began 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 2000, the Company drilled five gross (4.9 net) wells in the
Fontenelle Unit and plans to drill 10 wells during 2001.
Permian Basin Area
Prentice Field. The Prentice Field is located in Terry and Yoakum
Counties, Texas. 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.
The Company has a 91.5% working interest in 178 wells in the Prentice
Northeast Unit. The Company also owns an interest in 81 gross (2 net)
nonoperated wells. During 2000, the Company drilled 11 gross (10.1 net)
vertical wells. At the end of 2000, one well was still being completed. During
2001, the Company may drill as many as 15 wells in this field.
University Block 9. The University Block 9 Field is located in Andrews
County, Texas and was discovered in 1953. The Company owns interests in 70
gross (68.5 net) wells that it operates. Productive zones are of Wolfcamp,
Pennsylvanian and Devonian age and range from 8,400 to 10,400 feet. Development
potential includes proper wellbore utilization, recompletions, infill drilling
and improvement of waterflood efficiency.
7
This field was the Company's most active oil development area during 2000,
where the Company drilled 26 wells, including seven horizontal sidetrack wells.
The Company also recompleted five Devonian wells into the Pennsylvanian horizon.
During 2001, the Company plans to drill up to 19 wells.
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 27 wells, 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 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.
Three workovers were performed and two wells were drilled in 2000. The
Company plans to drill two wells in 2001.
Reserves
The following are definitions adopted by the Commission and the Financial
Accounting Standards Board which are applicable to terms used in the following
discussion of oil and natural gas reserves:
Proved reserves- Estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geologic and engineering data,
appear with reasonable certainty to be recoverable in the future from known oil
and gas reservoirs under existing economic and operating conditions.
Proved developed reserves- Proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves- Proved reserves which are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required.
Estimated future net revenues- Also referred to herein as "estimated
future net cash flows." Computational result of applying current prices of oil
and gas (with consideration of price changes only to the extent provided by
existing contractual arrangements) to estimated future production from proved
oil and gas reserves as of the date of the latest balance sheet presented, less
estimated future expenditures (based on current costs) to be incurred in
developing and producing the proved reserves.
Present value of estimated future net cash flows- Also referred to herein
as "standardized measure of discounted future net cash flows" or "standardized
measure." Computational result of discounting estimated future net revenues at
a rate of 10% annually.
8
The following are estimated quantities of proved reserves and cash flows
therefrom as of December 31, 2000, 1999 and 1998:
December 31
-----------------------------------
(in thousands) 2000 1999 1998
----------- ---------- ----------
Proved developed:
Oil (Bbls)......................... 46,334 48,010 42,876
Gas (Mcf).......................... 1,328,953 1,225,014 968,495
Natural gas liquids (Bbls)......... 16,448 13,781 14,000
Mcfe............................... 1,705,645 1,595,760 1,309,751
Proved undeveloped:
Oil (Bbls)......................... 12,111 13,593 11,634
Gas (Mcf).......................... 440,730 320,609 240,729
Natural gas liquids (Bbls)......... 5,564 4,121 3,174
Mcfe............................... 546,780 426,893 329,577
Total proved:
Oil (Bbls)......................... 58,445 61,603 54,510
Gas (Mcf).......................... 1,769,683 1,545,623 1,209,224
Natural gas liquids (Bbls)......... 22,012 17,902 17,174
Mcfe............................... 2,252,425 2,022,653 1,639,328
Estimated future net cash flows:
Before income tax.................. $15,239,560 $3,269,443 $1,677,426
After income tax................... $10,291,946 $2,550,551 $1,446,177
Present value of estimated future
net cash flows, discounted at 10%:
Before income tax.................. $ 7,748,632 $1,765,936 $ 908,606
After income tax................... $ 5,262,030 $1,396,940 $ 808,403
Miller and Lents, Ltd., 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, 2000,
1999 and 1998. 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. Year-end 2000 realized
prices used in the estimation of proved reserves were $25.49 per Bbl for oil,
$9.55 per Mcf for gas and $26.33 per Bbl for natural gas liquids. Based on
NYMEX prices of $25.00 per Bbl for oil and $5.00 per Mcf for gas (which are
comparable to realized prices of $23.69 per Bbl for oil and $4.79 per Mcf for
gas), and an $18.86 per Bbl realized price for natural gas liquids, estimated
proved reserves at December 31, 2000 would be 57.7 million Bbls of oil, 1.75 Tcf
of natural gas and 21.6 million Bbls of natural gas liquids. Using these
prices, the present value of estimated future cash flows, discounted at 10% and
before income tax, would be $3,834,024,000. See Note 16 to Consolidated
Financial Statements for additional information regarding estimated proved
reserves.
Uncertainties are inherent in estimating quantities of proved reserves,
including many factors beyond the Company's control. 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 2000, the Company filed estimates of oil and gas reserves as of
December 31, 1999 with the U.S. Department of Energy on Form EIA-23. These
estimates are consistent with the reserve data reported for the year ended
December 31, 1999 in Note 16 to Consolidated Financial Statements, with the
exception that Form EIA-23 includes only reserves from properties operated by
the Company.
9
Exploration and Production Data
For the following data, "gross" refers to the total wells or acres in which
the Company owns a working interest and "net" refers to gross wells or acres
multiplied by the percentage working interest owned by the Company. Although
many of the Company's wells produce both oil and gas, a well is categorized as
an oil well or a gas well based upon the ratio of oil to gas production.
Producing Wells
The following table summarizes the Company's producing wells as of
December 31, 2000, all of which are located in the United States:
Operated Wells Nonoperated Wells Total (a)
------------------ ----------------- ------------------
Gross Net Gross Net Gross Net
----- ----------- ----- ----- ----- -----------
Oil............ 542 484.7 1,806 126.4 2,348 611.1
Gas............ 3,227 2,728.7 1,310 269.2 4,537 2,997.9
----- ----------- ----- ----- ----- -----------
Total.......... 3,769 3,213.4 3,116 395.6 6,885 3,609.0
===== =========== ===== ===== ===== ===========
(a) One gross (0.5 net) oil wells and 317 gross (194.7 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, 2000, the Company
was in the process of drilling 59 gross (41.9 net) wells.
Year Ended December 31
---------------------------------------------------
2000 1999 1998
---------------- ---------------- ---------------
Gross Net Gross Net Gross Net
------- ------- ------- ------- ------- -------
Development wells:
Completed as-
Oil wells.............. 48 29.9 18 6.7 53 14.1
Gas wells.............. 172 114.6 128 91.2 139 63.4
Non-productive........... 9 1.3 7 3.5 1 -
------- ------- ------- ------- ------- -------
Total.................... 229 145.8 153 101.4 193 77.5
------- ------- ------- ------- ------- -------
Exploratory wells:
Completed as-
Oil wells.............. 4 2.8 - - - -
Gas wells.............. 1 0.5 1 1.0 3 3.0
Non-productive........... 1 0.5 - - 2 1.0
------- ------- ------- ------- ------- -------
Total.................... 6 3.8 1 1.0 5 4.0
------- ------- ------- ------- ------- -------
Total (a)................. 235 149.6 154 102.4 198 81.5
======= ======= ======= ======= ======= =======
(a) Included in totals are 66 gross (8.5 net) wells in 2000, 44 gross (4.1
net) wells in 1999 and 118 gross (14.6 net) in 1998 drilled on nonoperated
interests.
10
Acreage
The following table summarizes developed and undeveloped leasehold acreage
in which the Company owns a working interest as of December 31, 2000. Excluded
from this summary is acreage in which the Company's interest is limited to
royalty, overriding royalty and other similar interests.
Developed Acres (a)(b) Undeveloped Acres
---------------------- -----------------
Gross Net Gross Net
--------- ------- ------ ------
Arkansas.... 519,646 226,345 20,495 15,678
Oklahoma.... 464,737 324,766 14,783 6,783
Texas....... 223,398 140,500 27,190 20,492
New Mexico.. 196,078 145,963 160 160
Kansas...... 66,670 58,169 - -
Wyoming..... 45,007 30,241 1,891 1,211
Other....... 35,157 19,602 4,603 4,002
--------- ------- ------ ------
Total....... 1,550,693 945,586 69,122 48,326
========= ======= ====== ======
(a) Developed acres are acres spaced or assignable to productive wells.
(b) Certain 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 six
Mcf to one Bbl):
Year Ended December 31
----------------------
2000 1999 1998
------ ------ ------
Sales prices:
Oil (per Bbl)............................ $27.07 $16.94 $12.21
Gas (per Mcf)............................ $ 3.38 $ 2.13 $ 2.07
Natural gas liquids (per Bbl)............ $19.61 $11.80 $ 7.62
Production costs per Mcfe................. $ 0.53 $ 0.53 $ 0.53
Taxes, transportation and other per Mcfe.. $ 0.35 $ 0.23 $ 0.25
Delivery Commitments
The Company contracted to sell to a single purchaser approximately 21,650
Mcf of gas per day at the index price through December 2000, 34,344 Mcf per day
at the index price in 2001 and 35,500 Mcf per day from 2002 through July 2005 at
a price of approximately 10% of the average NYMEX futures price for intermediate
crude oil. Deliveries under this contract are in Oklahoma and Arkansas.
The Company has committed to sell all gas production from certain East
Texas properties to EEX Corporation at market prices through the earlier of
December 31, 2001, or until a total of approximately 34.3 Bcf (27.8 Bcf 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.
As partial consideration for an acquisition, the Company agreed to sell gas
volumes ranging from 40,000 Mcf in 2000 to 35,000 Mcf in 2003 at specified
discounts from index prices. Delivery 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.
11
As a part of the Ocean Energy Acquisition, the Company assumed a commitment
to sell 6,800 Mcf of gas per day through April 2003 at a prices which are
adjusted by the monthly index price. In 2000, the prices ranged from $0.50 to
$0.95 per Mcf. Delivery of the committed sales volumes is in Arkansas.
The Company has also entered fixed price contracts to sell physical daily
gas volumes of 210,000 Mcf from April through September 2001 and 140,000 Mcf
from October through March 2002. See Note 8 to Consolidated Financial
Statements.
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.
Gathering systems are the only practical method for the intermediate
transportation of natural gas. Therefore, 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, high margin nature of the Company's oil and
gas reserves and management's experience and 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 Part II, 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"). Federal wellhead
price controls on all domestic gas were terminated on January 1, 1993 and none
of the Company's gathering systems are currently subject to FERC regulation.
The Company cannot predict the impact of future government regulation on any
natural gas facilities.
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 future impact of these regulations on marketing the Company's
production or on its gas transportation business cannot be predicted. The
Company, however, does not believe that it will be affected differently than
competing producers and marketers.
12
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. Under rules adopted
by FERC effective January 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 effect on the Company's oil transportation cost.
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 that can be drilled.
The Company may become a 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 similar regulations. New
regulations 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 Native American Leases
The Company's operations on federal, state or Native American 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.
13
Employees
The Company had 651 employees as of December 31, 2000. None of the
employees are represented by a union. The Company considers its relations with
its employees to be good.
Executive Officers of the Company
The executive officers of the Company are elected by and serve until their
successors are elected by the Board of Directors.
Bob R. Simpson, 52, 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, 50, was a co-founder of the Company with Mr. Simpson and
has been Vice Chairman and President or held similar positions with the Company
since 1986. Mr. Palko was Vice President - Reservoir Engineering (1984-1986)
and Manager of Reservoir Engineering (1982-1984) of Southland Royalty Company.
Louis G. Baldwin, 51, has been Executive 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, 42, has been Executive Vice President - Operations or held
similar positions with the Company since 1987. From 1982 to 1987, Mr. Hutton
was a Reservoir Engineer with Sun Exploration & Production Company.
Vaughn O. Vennerberg, II, 46, has been Executive Vice President -
Administration 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).
Bennie G. Kniffen, 50, 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.
14
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 arm's-length transactions. The plaintiffs
further allege that these 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. These deductions allegedly include
production and post-production costs, marketing costs, administration costs and
costs incurred by the Company in gathering, compressing, dehydrating,
processing, treating, blending and/or transporting the gas produced. The
Company contends that, to the extent any fees are proportionately borne by the
plaintiffs, these fees are established by arm's-length negotiations with third
parties or, if charged by affiliates, are comparable to fees charged by third
party gatherers or processors. The Company further contends that any such fees
enhance the value of the gas or the products derived from the gas. The
plaintiffs are seeking an accounting and payment of the monies allegedly owed to
them. 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 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 has made similar allegations in over 70 actions filed against more
than 300 other 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 plaintiff also
seeks an order for the Company to cease the allegedly improper measuring
practices. After its review, the Department of Justice decided in April 1999
not to intervene and asked the court to unseal the case. The court unsealed the
case in May 1999. A multi-district litigation panel ordered that the lawsuits
against the Company and other companies filed by Grynberg be transferred and
consolidated to the federal district court in Wyoming. The Company and other
defendants filed a motion to dismiss which has been heard by the Court and a
decision is pending. The Company believes that the allegations of this lawsuit
are without merit and intends to vigorously defend the action. Any potential
liability from this claim is not currently determinable and no provision has
been accrued in the Company's financial statements.
A third lawsuit, Bishop, et al. v. Amoco Production Co., et al., was filed
in May 2000 in the Third Judicial District Court in Lincoln County, Wyoming by
owners of royalty and overriding royalty interests in wells located in Wyoming.
The plaintiffs alleged that the Company and the other producer defendants
deducted impermissible costs of production from royalty payments that were made
to the plaintiffs and other similarly situated persons and failed to properly
inform the plaintiffs and others of the deductions taken as allegedly required
by Wyoming statutes. The action was brought as a class action on behalf of all
persons who own an interest in wells located in Wyoming as to which the
defendants pay royalties and overriding royalties. The plaintiffs sought a
declaratory judgment that the deductions made were impermissible and sought
damages in the amount of the deductions made, together with interest and
attorneys' fees. The Company has reached a settlement of this action, which is
subject to court approval. The Company has agreed to pay a total settlement
amount of $572,000 for a release of claims relating to deductions taken by the
Company, the statutory reporting of claims, and other miscellaneous matters.
The Company further agreed that it would not take similar deductions from
royalty owners in the future and to itemize other deductions from future royalty
disbursements. The Company expects that the court will approve the settlement in
April 2001. The settlement was accrued in the Company's financial statements.
In February 2000, the Department of Interior notified the Company and
several other producers that certain Native American leases located in the San
Juan Basin have expired due to the failure of the leases to produce in paying
quantities. The Department of Interior has demanded abandonment of the property
as well as payment of the gross proceeds from the wells minus royalties paid
from the date of the alleged cessation of production to present. The Company
has filed a Notice of Appeal with the Interior Board of Indian Appeals. The
potential loss from these claims is currently not determinable, but could be
material to the Company's annual earnings. The Company believes that the
15
claim is without merit and that there is currently not a probable loss. No
related provision is accrued in the Company's financial statements.
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 or liquidity, although an unfavorable outcome could
have a material adverse effect on the operations of a given interim period or
year.
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 2000.
16
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 2000 and 1999
(as adjusted for the three-for-two stock split effected on September 18, 2000):
High Low Dividend
------ ------- ----------
2000
First Quarter.......... $ 8.917 $ 5.042 $ 0.0067
Second Quarter......... 14.833 8.167 0.0067
Third Quarter.......... 21.625 10.667 0.0100
Fourth Quarter......... 29.000 16.750 0.0100
1999
First Quarter.......... $ 6.042 $ 3.042 $ 0.0067
Second Quarter......... 9.917 4.500 0.0067
Third Quarter.......... 10.083 7.333 0.0067
Fourth Quarter......... 8.875 5.458 0.0067
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, as defined, 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 20, 2001, the Board of Directors declared a quarterly dividend
of $.01 per share payable on April 17, 2001 to shareholders of record on March
30, 2001. On March 1, 2001, the Company had approximately 593 shareholders of
record.
17
Item 6. Selected Financial Data
The following table shows selected financial information for the five years
ended December 31, 2000. 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, February
1998 and September 2000. 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).
(in thousands except production, per share and per unit data)
2000 1999 1998 1997 1996
---------- ---------- ----------- ---------- ---------
Consolidated Income Statement Data
Revenues:
Oil and condensate.......................... $ 128,194 $ 86,604 $ 56,164 $ 75,223 $ 75,013
Gas and natural gas liquids................. 456,814 239,056 182,587 110,104 73,402
Gas gathering, processing and marketing..... 16,123 10,644 9,438 9,851 12,032
Other....................................... (280) 4,991 1,297 3,094 888
---------- ---------- ----------- ---------- ---------
Total Revenues.............................. $ 600,851 $ 341,295 $ 249,486 $ 198,272 $ 161,335
========== ========== =========== ========== =========
Earnings (loss) available to common stock.... $ 115,235(a) $44,964(b)$ (71,498)(c) $ 23,905 $ 19,790
========== ========== =========== ========== =========
Per common share
Basic....................................... $ 1.62 $ 0.64 $ (1.10) $ 0.40 $ 0.33
========== ========== =========== ========== =========
Diluted..................................... $ 1.55 $ 0.63 $ (1.10) $ 0.39 $ 0.32
========== ========== =========== ========== =========
Weighted average common shares outstanding.. 71,154 70,228 65,094 59,660 59,870
========== ========== =========== ========== =========
Dividends declared per common share.......... $ 0.0333 $ 0.0267 $ 0.1067 $ 0.1000 $ 0.0867
========== ========== =========== ========== =========
Consolidated Statement of Cash Flows Data
Cash provided (used) by:
Operating activities........................ $ 377,421 $ 133,301 $ (53,876) $ 95,918 $ 59,694
Investing activities........................ $ (133,884) $ (156,370) $ (376,564) $ (309,234) $(124,871)
Financing activities........................ $ (241,833) $ 16,470 $ 438,957 $ 213,195 $ 66,902
Consolidated Balance Sheet Data
Property and equipment, net.................. $1,357,374 $1,339,080 $ 1,050,422 $ 723,836 $ 450,561
Total assets................................. $1,591,904 $1,477,081 $ 1,207,005 $ 788,455 $ 523,070
Long-term debt............................... $ 769,000 $ 991,100 $ 920,411 $ 539,000 $ 314,757
Stockholders' equity......................... $ 497,367 $ 277,817 $ 201,474 $ 170,243 $ 142,668
Operating Data
Average daily production:
Oil (Bbls).................................. 12,941 14,006 12,598 10,905 9,584
Gas (Mcf)................................... 343,871 288,000 229,717 135,855 101,845
Natural gas liquids (Bbls).................. 4,430 3,631 3,347 220 -
Mcfe........................................ 448,098 393,826 325,390 202,609 159,349
Average sales price:
Oil (per Bbl)............................... $ 27.07 $ 16.94 $ 12.21 $ 18.90 $ 21.38
Gas (per Mcf)............................... $ 3.38 $ 2.13 $ 2.07 $ 2.20 $ 1.97
Natural gas liquids (per Bbl)............... $ 19.61 $ 11.80 $ 7.62 $ 9.66 -
Production expense (per Mcfe)................ $ 0.53 $ 0.53 $ 0.53 $ 0.59 $ 0.67
Taxes, transportation and other (per Mcfe)... $ 0.35 $ 0.23 $ 0.25 $ 0.22 $ 0.20
Proved reserves:
Oil (Bbls).................................. 58,445 61,603 54,510 47,854 42,440
Gas (Mcf)................................... 1,769,683 1,545,623 1,209,224 815,775 540,538
Natural gas liquids (Bbls).................. 22,012 17,902 17,174 13,810 -
Mcfe........................................ 2,252,425 2,022,653 1,639,328 1,185,759 795,178
Other Data
Operating cash flow (d)...................... $ 344,638 $ 132,683 $ 78,480 $ 89,979 $ 68,263
Ratio of earnings to fixed charges (e)....... 2.8 1.9 - (f) 2.1 2.6
18
(a) Includes effect of pre-tax gain of $43.2 million on significant asset
sales, pre-tax derivative fair value loss of $55.8 million and non-cash
incentive compensation expense of $26.1 million.
(b) Includes effect of a $40.6 million pre-tax gain on sale of Hugoton Royalty
Trust units.
(c) 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.
(d) Defined as cash provided by operating activities before changes in
operating assets and liabilities and exploration expense. Because of
exclusion of changes in operating assets and liabilities and exploration
expense, this cash flow statistic is different from cash provided (used) by
operating activities, as is disclosed under generally accepted accounting
principles.
(e) For purposes of calculating this ratio, earnings include earnings (loss)
available to common stock before income tax and fixed charges. Fixed
charges include interest costs, the portion of rentals (calculated as one-
third) considered to be representative of the interest factor and preferred
stock dividends.
(f) Fixed charges exceeded earnings by $108.4 million. Excluding the effect of
items in (c) above, fixed charges exceeded earnings by $19 million.
19
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 at Item 14(a).
General
The following events affect the comparability of results of operations and
financial condition for the years ended December 31, 2000, 1999 and 1998, 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 and natural gas liquid
quantities converted to Mcf on an energy equivalent ratio of one barrel to six
Mcf.
Three-for-Two Stock Splits. The Company effected three-for-two stock splits on
February 25, 1998 and September 18, 2000. All common stock shares, treasury
stock shares and per share amounts have been retroactively restated to reflect
all stock splits.
1999 Acquisitions. During 1999, the Company acquired predominantly gas-producing
properties at a total cost of $510 million primarily funded by a combination of
bank borrowings, proceeds from a public offering of common stock and the
issuance of common stock. The acquisitions include:
- Spring Holding Company Acquisition. In July 1999, the Company and Lehman
each acquired 50% of the common stock of Spring Holding Company for a
combination of cash and the Company's common stock totaling $85 million. In
September 1999, the Company exercised its option to acquire Lehman's 50%
interest in Spring for $44.3 million. The acquisition includes gas
properties located in the Arkoma Basin of Arkansas and Oklahoma with a
purchase price of $235 million. After purchase accounting adjustments and
other costs, the cost of the properties was $257 million.
- Ocean Energy Acquisition. In September 1999, the Company and Lehman
acquired Arkoma Basin gas properties for $231 million. Lehman contributed
$100 million in cash and the Company contributed $100 million in
securities, including its common stock, to a jointly owned company. The
acquisition was funded with cash of $100 million and bank borrowings of
$131 million. The Company acquired Lehman's interest in this acquisition on
March 31, 2000 for $111 million, which was funded by proceeds from the
sales of producing properties and equity securities, as well as bank debt.
The $11 million in excess of Lehman's investment was recorded as additional
property cost in 2000.
1998 Acquisitions. During 1998, the Company acquired oil- and gas-producing
properties at a total cost of $340 million, including:
- East Texas Basin Acquisition. The Company acquired these primarily gas-
producing properties at a purchase price of $245 million, later reduced to
$215 million by a $30 million production payment sold to EEX Corporation.
This acquisition closed in April 1998 and was funded by bank debt,
partially repaid from proceeds of the 1998 Common Stock Offering.
- Cook Inlet Acquisition. In September 1998, the Company acquired these oil-
producing properties in Alaska from affiliates of Shell Oil Company in
exchange for 2.9 million shares of the Company's common stock along with
certain price guarantees and a non-interest bearing note payable of $6
million, resulting in a purchase price of $45 million.
- Seagull Acquisition. This acquisition included 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 $31 million, funded by bank borrowings.
Hugoton Royalty Trust Sales. The Company created Hugoton Royalty Trust in
December 1998 by conveying 80% net profits interests in producing properties in
Kansas, Oklahoma and Wyoming. In April and May 1999, the Company sold 17 million
units, or 42.5%, of Hugoton Royalty Trust in its initial public offering. Total
proceeds from this sale were $148.6 million, which were used to reduce bank
debt. Total gain on sale, including the sale of units pursuant to an
20
employee incentive plan, was $40.6 million before income tax. In October and
November 2000, the Company sold 1.2 million units, or approximately 3%, of
Hugoton Royalty Trust pursuant to the employee incentive plan. Total gain on
these sales during 2000 was $11 million before income tax.
2000 Property Sales. In March 2000, the Company sold oil- and gas-producing
properties in Crockett County, Texas and Lea County, New Mexico for total gross
proceeds of $68.3 million.
1999 Property Sales. In May and June 1999, the Company sold primarily
nonoperated gas-producing properties in New Mexico for $44.9 million. In
September 1999, the Company sold primarily nonoperated oil- and gas-producing
properties in Oklahoma, Texas, New Mexico and Wyoming for $63.5 million,
including sales of $22.5 million of properties acquired in the Spring Holding
Company Acquisition.
2000, 1999 and 1998 Development and Exploration Programs. Oil development was
concentrated in the University Block 9 Field during all three years. Gas
development focused on the East Texas area in 2000 and 1999, the Hugoton Area
during 1998, and the Fontenelle Unit during all three years. Exploration
activity has been primarily geological and geophysical analysis, including
seismic studies, of undeveloped properties. Exploratory expenditures were $1
million in 2000, $900,000 in 1999 and $8 million in 1998.
2001 Development and Exploration Program. The Company has budgeted $250 million
for its 2001 development and exploration program, which is expected to be funded
primarily by cash flow from operations. The Company anticipates exploration
expenditures will be approximately 4% of the 2001 budget. The total capital
budget, including acquisitions, will be adjusted throughout 2001 to focus on
opportunities offering the highest rates of return.
Common Stock Transactions. The following significant sales and issuances of
common stock occurred during the three-year period ended December 31, 2000:
- In November 2000, the Company sold 6.6 million shares of common stock from
treasury with net proceeds of approximately $126.1 million. The proceeds
were used to reduce outstanding indebtedness.
- In July 1999, the Company sold 3 million shares of common stock from
treasury with net proceeds of approximately $26.5 million. The proceeds
were used to repurchase 2.9 million shares of common stock issued to
affiliates of Shell for the Cook Inlet Acquisition.
- In July 1999, the Company issued 6 million shares of common stock for its
50% interest in Spring Holding Company and for cash proceeds of $3.2
million which was used to reduce bank debt.
- In September 1998, the Company issued 2.9 million common shares from
treasury to affiliates of Shell for the Cook Inlet Acquisition. In July
1999, the Company repurchased these shares from Shell.
- In April 1998, the Company sold 10.8 million 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.
Treasury Stock Purchases. The Company often repurchases shares of its common
stock as part of its strategic acquisition plans. The Company purchased on the
open market 5.3 million shares at a cost of $41.4 million in 2000, 7,500 shares
at a cost of $53,000 in 1999 and 6.5 million shares at a cost of $65.6 million
in 1998. Through March 26, 2001, 4.3 million shares remain under the May 2000
Board of Directors' authorization to purchase an additional 4.5 million shares.
Conversion of Preferred Stock. In January 2001, the Company sent notice to
preferred stockholders that it would redeem all outstanding shares on February
16, 2001 at a price of $25.94 per share plus accrued and unpaid dividends. Prior
to the redemption date, 1.1 million outstanding shares of preferred stock were
converted into 3.5 million common shares.
Investment in Equity Securities. In 1998, the Company purchased what it believed
to be undervalued oil and gas reserves by acquiring common stock of publicly
traded independent oil and gas producers at a total cost of $167.7 million. For
accounting purposes, the Company considered equity securities purchased in 1998
to be trading securities since they
21
were purchased with the intent to resell in the near future, and therefore
recognized unrealized investment gains and losses in the income statements.
After selling a portion of these securities in 1998 and 1999, the Company sold
its remaining investment in equity securities in 2000 for $43.7 million. The
Company recognized a $13.3 million gain in 2000, and losses of $1.1 million in
1999 and $93.7 million in 1998 related to this investment.
Derivative fair value loss. During 2000, the Company recorded a $55.8 million
loss on call options which the Company sold in 1999 related to its hedging
activities. Because written call options do not provide protection against
declining prices, they do not qualify for hedge or loss deferral accounting. A
current liability of $53.8 million related to this loss is recorded in the
consolidated balance sheet at December 31, 2000. See "Accounting Changes" below.
Incentive Compensation. Incentive compensation results from stock appreciation
right, performance share and royalty trust option awards, and subsequent changes
in the Company's stock price. In 2000, incentive compensation totaled $26.1
million, which was primarily related to performance share grants and royalty
trust option exercises. Incentive compensation was not significant in 1999. In
1998, incentive compensation totaled $1.3 million, which included non-cash
performance share compensation of $1.6 million, partially offset by a reduction
in stock appreciation right compensation of $300,000. As of December 31, 2000,
there were 85,000 performance shares outstanding that vested when the common
stock price closed above $30.00 on March 9, 2001, and 13,500 performance shares
that vest in increments of 4,500 in each of 2001, 2002 and 2003. On March 9,
2001, an additional 77,000 performance shares were issued that vest when the
stock price closes above $32.50.
Product Prices. In addition to supply and demand, oil and gas prices are
affected by seasonal, political and other fluctuations the Company generally
cannot control or predict.
Crude oil prices are generally determined by global supply and demand.
Starting at about $15 per barrel, crude oil prices declined throughout 1998,
dropping to a posted West Texas Intermediate ("WTI") price of $8.00 per barrel
in December 1998, the lowest level since 1978. Oil prices increased in 1999
because of production cuts by OPEC and other leading oil exporters, reduced
inventories and anticipated increased demand. Despite OPEC production increases
in 2000, increased demand has sustained higher prices. In September 2000, posted
WTI prices reached $34.25, their highest levels since the 1990 Persian Gulf War.
In response to lower prices in 2001 caused by lagging demand, OPEC members
announced their resolve to maintain higher oil prices through production cuts
when needed. The Company uses commodity price hedging instruments to reduce its
exposure to oil price fluctuations. Including the effect of these hedging
instruments, the Company's average oil price decreased from $28.72 to $27.07 in
2000 and from $17.37 to $16.94 in 1999. Based on 2000 production, the Company
estimates that a $1.00 per barrel increase or decrease in the average oil sales
price would result in approximately a $4.5 million change in 2001 annual
operating cash flow.
Natural gas prices are influenced by North American 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. Gas prices were approximately $2.00 per MMBtu in January 1998 and
remained lower throughout the year because of mild winters in the central and
eastern U.S. Cooler spring weather and lower industry production levels
strengthened gas prices in 1999 and, after declining briefly at the end of 1999,
continued to strengthen in 2000. The combination of lower domestic productive
capacity, reduced storage and increased summer and winter demand have resulted
in higher natural gas prices with increased volatility. NYMEX gas prices reached
a record high of $10.10 in December 2000. At March 15, 2001, the average NYMEX
price for the following 12 months was $5.08 per MMBtu. The Company uses
commodity price hedging instruments to reduce its exposure to gas price
fluctuations. Including the effect of these hedging instruments, the Company's
average gas price decreased from $3.70 to $3.38 in 2000 and from $2.18 to $2.13
in 1999. Based on 2000 production, the Company estimates that a $0.10 per Mcf
increase or decrease in the average gas sales price would result in
approximately an $11 million change in 2001 annual operating cash flow. However,
a significant portion of the Company's gas production through March 2002 is
hedged by contracts that effectively fix prices. See Note 8 to the Consolidated
Financial Statements.
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 significantly
decline, the Company may be required to record impairment provisions in the
future, which could be material.
22
Results of Operations
2000 Compared to 1999
For the year 2000, earnings available to common stock were $115.2 million
compared with earnings available to common stock of $45 million for 1999. The
2000 earnings include a $7.3 million after-tax gain from the sale of Hugoton
Royalty Trust units, a $13.1 million after-tax gain on sale of properties, an
$8.8 million after-tax gain on investment in equity securities, a $17.3 million
after-tax charge for incentive compensation and a $36.8 after-tax loss on the
change in derivative fair value. The 1999 earnings include a $26.8 million
after-tax gain from the sale of Hugoton Royalty Trust units, a $4.2 million
after-tax gain on sale of properties, and an $800,000 after-tax loss on
investment in equity securities. Excluding these gains and losses from asset
sales and incentive compensation, earnings for 2000 were $140.1 million,
compared with $14.8 million for 1999.
Revenues for 2000 were $600.9 million, or 76% above 1999 revenues of $341.3
million. Oil revenue increased $41.6 million, or 48%, because of a 60% increase
in oil prices from an average of $16.94 per Bbl in 1999 to $27.07 in 2000 (see
"General - Product Prices" above), partially offset by a 7% decrease in oil
production. Decreased production was primarily because of the 2000 property
sales.
Gas and natural gas liquids revenue increased $217.8 million, or 91%,
because of a 20% increase in gas production, a 22% increase in natural gas
liquids production, a 59% increase in gas prices from an average of $2.13 per
Mcf in 1999 to $3.38 in 2000 and a 66% increase in natural gas liquids prices
from an average price of $11.80 per Bbl in 1999 to $19.61 in 2000 (see "General-
Product Prices" above). Increased gas and natural gas liquids production was
attributable to the 1999 acquisitions and the 1999 and 2000 development
programs.
Gas gathering, processing and marketing revenues increased $5.5 million
primarily because of higher gas and natural gas liquids prices, increased margin
and increased volumes from the 1999 acquisitions. Other revenues were $5.3
million lower primarily because of decreased net gains on sale of properties.
Expenses for 2000 totaled $388.7 million as compared with total 1999
expenses of $245.9 million. Most expenses increased in 2000 primarily because of
the 1999 acquisitions and the 1999 and 2000 development programs.
Production expense increased $10.9 million, or 14%, because of increased
production related to the 1999 acquisitions and 1999 and 2000 development
programs. Production expense per Mcfe remained flat at $0.53. The Company's 2000
exploration expense of $1 million, which was predominantly geological and
geophysical costs, remained about the same as 1999.
Taxes, transportation and other deductions increased 68% or $23 million
because of increased oil and gas revenues, as well as increased transportation,
compression and other charges related to the 1999 acquisitions and the 1999 and
2000 development programs. Taxes, transportation and other per Mcfe increased
52% from $0.23 to $0.35 because of increased prices and other deductions.
Depreciation, depletion and amortization ("DD&A") increased $17.4 million,
or 16%, primarily because of the 1999 acquisitions and the 1999 and 2000
development programs. On an Mcfe basis, DD&A increased slightly from $0.78 in
1999 to $0.79.
General and administrative expense increased $35.4 million, or 251% because
of incentive compensation of $26.1 million and increased expenses from Company
growth related to the 1999 acquisitions. Excluding incentive compensation,
general and administrative expense per Mcfe increased from $0.10 in 1999 to
$0.14 in 2000.
Interest expense increased $14.7 million, or 23%, primarily because of a 7%
increase in weighted average borrowings and an 8% increase in the weighted
average interest rate. Interest classified as part of the gain (loss) on
investment in equity securities decreased $4.6 million from 1999. Interest
expense per Mcfe increased from $0.45 in 1999 to $0.48 in 2000.
23
1999 Compared to 1998
For the year 1999, earnings available to common stock were $45 million
compared with a loss available to common stock of $71.5 million for 1998. The
1999 earnings include a $26.8 million after-tax gain from the sale of Hugoton
Royalty Trust units, a $4.2 million after-tax gain on sale of properties and an
$800,000 after-tax loss on investment in equity securities. The 1998 loss
includes a $61.8 million after-tax loss related to the Company's investment in
equity securities, a $500,000 after-tax gain on sale of properties, a $1.3
million after-tax impairment write-off of producing properties and a $900,000
after-tax charge for incentive compensation. Excluding these gains and losses
from investments and asset sales and charges for impairment and incentive
compensation, earnings for 1999 were $14.8 million, compared with an $8 million
loss for 1998.
Revenues for 1999 were $341.3 million, or 37% above 1998 revenues of $249.5
million. Oil revenue increased $30.4 million, or 54%, because of an 11% increase
in oil production and a 39% increase in oil prices from an average of $12.21 per
Bbl in 1998 to $16.94 in 1999 (see "General - Product Prices" above). Increased
production was primarily because of the 1998 acquisitions.
Gas and natural gas liquids revenue increased $56.5 million, or 31%,
because of a 25% increase in gas production, a 3% increase in gas prices and a
55% increase in natural gas liquids prices from an average price of $7.62 per
Bbl in 1998 to $11.80 in 1999 (see "General - Product Prices" above). Increased
gas production was attributable to the 1998 and 1999 acquisitions and
development programs.
Gas gathering, processing and marketing revenues increased $1.2 million
primarily because of higher gas and natural gas liquids prices, increased margin
and increased volumes from the 1999 acquisitions. Other revenues were $3.7
million higher primarily because of increased net gains on sale of properties,
partially offset by decreased lawsuit settlement receipts.
Expenses for 1999 totaled $245.9 million as compared with total 1998
expenses of $209.2 million. Most expenses increased in 1999 primarily because of
the 1998 and 1999 acquisitions and development programs.
Production expense increased $13 million, or 21%, because of increased
production. Production expense per Mcfe remained flat at $0.53. The Company
lowered its exploration budget for 1999, resulting in a $7.1 million reduction
in exploration expense, which is predominantly geological and geophysical costs.
Taxes, transportation and other deductions increased 16% or $4.6 million
because of increased oil and gas revenues, as well as increased transportation,
compression and other charges related to the 1998 and 1999 acquisitions. Taxes,
transportation and other per Mcfe decreased 8% from $0.25 to $0.23 because of
decreased property taxes and a lower production tax rate associated with
production from the 1999 acquisitions.
Depreciation, depletion and amortization increased $28.8 million, or 34%,
primarily because of the 1998 and 1999 acquisitions and development programs. On
an Mcfe basis, DD&A increased from $0.70 in 1998 to $0.78 in 1999 primarily
because of the higher cost per Mcfe of the 1998 and 1999 acquisitions.
General and administrative expense increased $600,000, or 5%, because of
increased expenses from Company growth related to the 1998 and 1999
acquisitions. Excluding incentive compensation, general and administrative
expense per Mcfe remained at $0.10 in 1999.
Interest expense increased $12.1 million, or 23%, primarily because of a
comparable increase in weighted average borrowings to partially fund the 1998
and 1999 acquisitions. 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 slightly from $0.44 in 1998 to $0.45 in 1999.
24
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.
Exploration and development expenditures and dividend payments have generally
been funded by cash flow from operations. The Company believes that its sources
of liquidity are adequate to fund its cash requirements in 2001.
Cash provided by operating activities was $377.4 million in 2000, compared
with cash provided by operating activities of $133.3 million in 1999 and $53.9
million cash used by operations in 1998. Fluctuations during this three-year
period were primarily because of purchases of equity securities and lower
product prices in 1998 and increased prices and production from acquisitions and
development activity in 1999 and 2000. Before changes in operating assets and
liabilities and exploration expense, cash flow from operations was $344.6
million in 2000, $132.7 million in 1999 and $78.5 million in 1998.
Financial Condition
Total assets increased 8% from $1.5 billion at December 31, 1999 to $1.6
billion at December 31, 2000, primarily because of higher product prices and
Company growth related to the 1999 acquisitions. As of December 31, 2000, total
capitalization of the Company was $1.3 billion, of which 61% was long-term debt.
Capitalization at December 31, 1999 was also $1.3 billion, but 78% was long-term
debt. The decrease in the debt-to-capitalization ratio from year-end 1999 to
2000 is because of repayment of debt from cash flow and the sale of common
stock.
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. The decrease in working capital from $39.3 million at
December 31, 1999 to negative working capital of $25.3 million at December 31,
2000 was primarily attributable to the sale of equity security investments and
increased current liabilities, net of the increase in current deferred income
tax benefit, related to the derivative fair value loss.
Included in other current liabilities at December 31, 2000 is a $53.8
million derivative loss accrual for the fair value of call options sold in 1999
related to the Company's hedging activities. Beginning January 1, 2001, the
Company will also accrue fair value losses related to unrealized hedge
derivative losses and a gas delivery contract. See "Accounting Changes" below.
The Company expects that any cash settlement of these derivative losses should
be offset by increased cash flows from the Company's sale of related production.
Therefore, the Company believes that substantially all derivative fair value
gains and losses are offset by changes in value of its natural gas reserves.
This offsetting change in gas reserve value, however, is not reflected in
working capital.
Prior to their sale, equity securities owned by the Company had been held
in a PaineWebber broker account and provided support for officer margin debt. As
of March 2001, officer margin debt balances related to Company common stock were
fully repaid, and the margin support agreements were terminated because they
were no longer needed. See Note 3 to Consolidated Financial Statements.
Financing
In May 2000, the Company entered a new revolving credit agreement with
commercial banks with a commitment of $800 million. Proceeds of this loan
agreement were used to refinance the Company's previous senior credit facility
and to fully repay a $25 million term loan and the separate bank debt of the
Company's subsidiaries, Spring Holding Company and Summer Acquisition Company.
In June 2000, the loan agreement was amended to allow the Company to issue
letters of credit. Any letters of credit outstanding reduce the borrowing
capacity under the revolving credit facility. As of December 31, 2000, letters
of credit outstanding totaled $33 million. Borrowings at
25
December 31, 2000 under the loan agreement were $469 million with unused
borrowing capacity of $298 million. 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. Based on reserve values at
December 31, 2000 and parameters specified by the banks, the borrowing base
supports borrowings in excess of the $800 million commitment. Borrowings under
the loan agreement are due May 12, 2005, 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. In February 2001,
the loan agreement was amended to allow the repurchase of the Company's
subordinated debt and to increase commodity hedging limits.
On January 3, 2001, the Company purchased primarily gas-producing
properties in East Texas and Louisiana for $115 million, of which $11.6 million
had been paid in 2000. This acquisition was funded through borrowings under the
loan agreement which are expected to be repaid from cash flow during the first
six months of 2001.
The 1999 and 1998 acquisitions were partially funded by the sale and
issuance of common stock and cash flow from operations. The 1999 acquisitions
were also partially funded by contributions from Lehman, the Company's equity
partner until the Company later purchased Lehman's interest in these
acquisitions. These transactions are described under "General" above. See also
"Capital Expenditures" below.
Capital Expenditures
Because of their size, the 1999 acquisitions were made jointly with Lehman
as a 50% equity partner. Pursuant to its call option, the Company acquired
Lehman's interest in the Spring Holding Acquisition in September 1999. The
Company exercised its option to purchase Lehman's interest in the Ocean Energy
Acquisition on March 31, 2000 for $111 million, funded primarily by the proceeds
from sales of property and equity security investments. The Company plans to
fund any future property acquisitions through a combination of cash flow from
operations and proceeds from asset sales, bank debt, public equity or debt
transactions. There are no restrictions under the Company's revolving credit
agreement that would affect the Company's ability to use its remaining borrowing
capacity for acquisitions of producing properties.
In February 2000, the Board of Directors authorized the repurchase of 3.8
million shares of the Company's common stock. Upon completion of repurchases
under this authorization, the Board of Directors authorized the repurchase of an
additional 4.5 million shares in May. During 2000, the Company repurchased 5.3
million shares of its common stock at a cost of $41.4 million, including 1.3
million shares repurchased under a prior Board authorization. As of March 26,
2001, 4.3 million shares are available for repurchase under the May 2000 Board
authorization.
In 2000, exploration and development cash expenditures totaled $155.4
million compared with $91.6 million in 1999. The Company has budgeted $250
million for the 2001 development program. As it has done historically, the
Company expects to fund the 2001 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.
To date, the Company has not spent significant amounts to comply with
environmental or safety regulations, and it does not expect to do so during
2001. 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 $0.0267 per common
share in 1998, $0.0067 per common share from 1999 through second quarter 2000
and $0.01 per common share for the third and fourth quarters of 2000. The
Company's ability to pay dividends is dependent upon available cash flow, as
well as other factors. In
26
addition, the Company's bank loan agreement restricts the amount of common stock
dividends to 25% of cash flow from operations, as defined, 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. Pursuant to the Company's notice of preferred stock
redemption, all preferred stock was converted into common shares prior to March
2001.
Accounting Changes
Effective January 1, 2001, the Company has adopted SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137
and 138. SFAS No. 133 requires the Company to record all derivatives on the
balance sheet at fair value. Change in the fair value of derivatives that are
not designated as hedges, as well as the ineffective portion of hedge
derivatives, must be recognized as a derivative fair value gain or loss in the
income statement. Change in fair value of effective cash flow hedges are
recorded as a component of other comprehensive income, which is later
transferred to earnings when the hedged transaction occurs. Physical delivery
contracts which cannot be net cash settled are deemed to be normal sales and
therefore are not accounted for as derivatives. However, physical delivery
contracts that have a price not clearly and closely associated with the asset
sold are not a normal sale and must be accounted for as a non-hedge derivative.
The Company accounted for adoption of SFAS No. 133 on January 1, 2001 by
recording a one-time after-tax charge of $44.6 million in the income statement
for the cumulative effect of a change in accounting principle, and an unrealized
after-tax loss of $67.3 million in other comprehensive income. The charge to the
income statement is primarily related to the Company's physical delivery
contract to sell 35,500 Mcf of natural gas per day from 2002 through July 2005
at crude oil-based prices. The unrealized loss is related to the derivative fair
value of cash flow hedges. See Note 8 to Consolidated Financial Statements.
Amounts recorded on the balance sheet at January 1, 2001 were a $103.6 million
current liability, a $2.2 million long-term asset and a $70.8 million long-term
liability related to the fair value of derivatives, and a current deferred tax
asset of $36.3 million and a reduction to the long-term tax liability of $24
million for the related tax benefits.
As oil and gas prices fluctuate, the Company will recognize a derivative
fair value gain or loss in its consolidated income statement related to the gas
physical delivery contract with crude oil-based pricing, as well as written call
options. The opportunity loss, related to market gas prices exceeding the prices
provided by these contracts, is immediately recognized as a loss in derivative
fair value in the income statement. This contrasts with opportunity losses on
hedge derivative contracts which are recorded as an unrealized loss in other
comprehensive income and later recognized in the income statement when the
related sale occurs. Since there is no net cash settlement expected under the
gas physical delivery contract, any losses recognized under this contract will
be reversed into income when gas is delivered. In all other cases, derivative
losses should be offset by increased cash flows from the Company's later sale of
related production. Accordingly, the Company believes that substantially all
derivative fair value gains and losses will be offset by changes in the value of
its natural gas reserves. This offsetting change in gas reserve value, however,
is not reflected in the Company's financial statements.
See Item 7A, "Commodity Price Risk" for the effect of price changes on
derivative fair value gains and losses.
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, 2000, the Company's
consolidated balance sheet includes a net current asset of $2.5 million for a
net underproduced balancing position of 911,000 Mcf of natural gas, and a net
long-term liability of $3.7 million for an overproduced balancing position of
3,581,000 Mcf of natural gas, net of an underproduced balancing position of
10,062,000 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.
27
Forward-Looking Statements
Certain information included in this annual report and other materials
filed or to be filed by the Company with the Securities and Exchange Commission,
as well as information included in oral statements or other written statements
made or to be made by the Company, contain projections and forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended, and Section 27A of the Securities Act of 1933, as amended,
relating to the Company's operations and the oil and gas industry. Such forward-
looking statements may be or may concern, among other things, capital
expenditures, cash flow, drilling activity, acquisition and development
activities, pricing differentials, operating costs, production activities, oil,
gas and natural gas liquids reserves and prices, hedging activities and the
results thereof, liquidity, debt repayment, regulatory matters and competition.
Such forward-looking statements are based on management's current plans,
expectations, assumptions, projections and estimates and are identified by words
such as "expects," "intends," "plans," "projects," "predicts," "anticipates,"
"believes," "estimates," "goal," "should," "could," "assume," and similar words
that convey the uncertainty of future events. 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 expectations, estimates, or assumptions expressed in, forecasted
in, or implied in such forward-looking statements.
Among the factors that could cause actual results to differ materially are:
- crude oil and natural gas price fluctuations,
- changes in interest rates,
- the Company's ability to acquire oil and gas properties that meet its
objectives and to identify prospects for drilling,
- higher than expected production costs and other expenses,
- potential delays or failure to achieve expected production from existing
and future exploration and development projects,
- volatility of crude oil, natural gas and hydrocarbon-based financial
derivative prices,
- basis risk and counterparty credit risk in executing commodity price risk
management activities,
- potential liability resulting from pending or future litigation,
- competition in the oil and gas industry as well as competition from other
sources of energy.
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 enters derivative financial instruments in conjunction
with its hedging activities. 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 generally 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 Chairman or the Executive
Vice President - Administration of all risk management programs using
derivatives and all derivative transactions. These programs are also reviewed at
least annually by the Board of Directors.
28
Hypothetical changes in interest rates and prices chosen for the following
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 and product prices. 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. At December 31, 2000, the Company's
variable rate debt had a carrying value of $469 million, which approximated its
fair value, and the Company's fixed rate debt had a carrying value of $300
million and an approximate fair value of $305 million. Assuming a one percent,
or 100-basis point, change in interest rates at December 31, 2000, the fair
value of the Company's fixed rate debt would change by approximately $16.4
million. 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.
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. The hypothetical
change in fair value could result in a gain or a loss depending on an increase
or decrease in the interest rate.
Hypothetical
Carrying Fair Change in
(in thousands) Amount Value Fair Value
---------- ---------- ------------
December 31, 2000
Long-term debt....... $(769,000) $(774,000) $16,389
Interest rate swaps.. 473 2,651 1,484
December 31, 1999
Long-term debt....... $(991,100) $(981,540) $16,771
Interest rate swaps.. 218 2,503 2,237
Commodity Price Risk
The Company hedges a portion of its price risks associated with its crude
oil and natural gas sales. As of December 31, 2000, the Company had outstanding
gas futures contracts, swap agreements and gas basis swap agreements. Gas
futures contracts and swap agreements would have had a total fair value loss of
approximately $112.8 million at December 31, 2000 and $2.7 million at December
31, 1999. Basis swap agreements had a fair value gain of $3.9 million at
December 31, 2000 and a fair value loss of $1.1 million at December 31, 1999.
The aggregate effect of a hypothetical 10% change in gas prices and basis would
result in a change of approximately $19.9 million in the fair value of gas
futures contracts and swap agreements and approximately $483,000 in the fair
value of basis swap agreements at December 31, 2000. This sensitivity does not
include the effects of commodity contracts, such as physical product delivery
contracts, that cannot be settled in cash or another financial instrument. See
Note 8 to Consolidated Financial Statements.
In conjunction with its hedging activities, the Company sold call options
to sell future gas production at certain ceiling prices. Call options
outstanding had a fair value loss of $44.5 million at December 31, 2000 and
$300,000 at December 31, 1999. The aggregate effect of a hypothetical 10% change
in gas prices and basis would result in a change of approximately $8.1 million
in the fair value of these options at December 31, 2000. Changes in the fair
value of these options are recognized in the consolidated income statements
since they do not qualify for hedge accounting. See Note 7 to Consolidated
Financial Statements.
The Company has entered a physical delivery contract to sell 35,500 Mcf per
day from 2002 through July 2005 at a price of approximately 10% of the average
NYMEX futures price for intermediate crude oil. Because this gas sales contract
is priced based on crude oil, which is not clearly and closely associated with
natural gas prices, it must be accounted for as a non-hedge derivative financial
instrument under SFAS No. 133 beginning January 1, 2001. See
29
Note 8 to Consolidated Financial Statements and "Accounting Changes" above. The
pre-tax fair value loss of this contract at January 1, 2001 is $70.8 million.
The effect of a hypothetical 10% change in gas prices would result in a change
of approximately $15.8 million in the fair value of this contract, while a 10%
change in crude oil prices would result in a change of approximately $8.7
million.
30
Item 8. Financial Statements and Supplementary Data
The following financial statements and supplementary information are
included under Item 14(a):
Page
----
Consolidated Balance Sheets......................... 33
Consolidated Income Statements...................... 34
Consolidated Statements of Cash Flows............... 35
Consolidated Statements of Stockholders' Equity..... 36
Notes to Consolidated Financial Statements.......... 37
Selected Quarterly Financial Data
(Note 15 to Consolidated Financial Statements).... 57
Information about Oil and Gas Producing Activities
(Note 16 to Consolidated Financial Statements).... 58
Report of Independent Public Accountants............ 61
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, 2001.
31
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents are filed as a part of this report:
Page
----
1. Financial Statements:
Consolidated Balance Sheets at December 31, 2000 and 1999............. 33
Consolidated Income Statements for the years ended
December 31, 2000, 1999 and 1998................................... 34
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999 and 1998................................... 35
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 2000, 1999 and 1998.................................... 36
Notes to Consolidated Financial Statements............................ 37
Report of Independent Public Accountants.............................. 61
2. Financial Statement Schedules:
All financial statement schedules have been omitted because they are
not applicable or the required information is presented in the financial
statements or the notes to consolidated financial statements.
(b) Reports on Form 8-K
The Company filed the following reports on Form 8-K during the quarter
ended December 31, 2000 and through March 30, 2001:
On November 20, 2000, the Company filed a report on Form 8-K to
disclose financial results for the third quarter of 2000 and the
Company's sale of 6 million shares of its common stock.
On December 20, 2000, the Company filed a report on Form 8-K to
announce that it had entered into a definitive agreement to buy
primarily gas-producing properties in East Texas and Louisiana
and had increased its 2001 capital budget by $50 million to $250
million.
On January 12, 2001, the Company filed a report on Form 8-K
regarding its completion of the previously announced acquisition
of primarily gas-producing properties in East Texas and
Louisiana.
(c) Exhibits
See Index to Exhibits at page 63 for a description of the exhibits
filed as a part of this report.
32
CROSS TIMBERS OIL COMPANY
Consolidated Balance Sheets
- --------------------------------------------------------------------------------
(in thousands, except shares) December 31
------------------------
2000 1999
---------- ----------
ASSETS
Current Assets:
Cash and cash equivalents......................................... $ 7,438 $ 5,734
Accounts receivable, net.......................................... 158,826 68,998
Investment in equity securities................................... - 29,052
Deferred income tax benefit....................................... 17,098 4,168
Other current assets.............................................. 10,075 5,540
---------- ----------
Total Current Assets............................................ 193,437 113,492
---------- ----------
Property and Equipment, at cost - successful efforts method:
Producing properties.............................................. 1,732,017 1,635,883
Undeveloped properties............................................ 6,460 10,358
Gas gathering and other........................................... 38,340 32,902
---------- ----------
Total Property and Equipment..................................... 1,776,817 1,679,143
Accumulated depreciation, depletion and amortization.............. (419,443) (340,063)
---------- ----------
Net Property and Equipment...................................... 1,357,374 1,339,080
---------- ----------
Other Assets....................................................... 32,879 16,817
---------- ----------
Loans to Officers.................................................. 8,214 7,692
---------- ----------
TOTAL ASSETS....................................................... $1,591,904 $1,477,081
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities.......................... $ 153,581 $ 68,937
Payable to royalty trusts......................................... 8,577 2,739
Other current liabilities......................................... 56,593 2,542
---------- ----------
Total Current Liabilities....................................... 218,751 74,218
---------- ----------
Long-term Debt..................................................... 769,000 991,100
---------- ----------
Deferred Income Taxes Payable...................................... 82,476 25,975
---------- ----------
Other Long-term Liabilities........................................ 24,310 7,959
---------- ----------
Commitments and Contingencies (Note 6)
Minority Interest in Consolidated Subsidiary....................... - 100,012
---------- ----------
Stockholders' Equity:
Series A convertible preferred stock ($.01 par value, 25,000,000
shares authorized, 1,088,663 and 1,138,729 shares issued,
at liquidation value of $25)..................................... 27,217 28,468
Common stock ($.01 par value, 100,000,000 shares authorized,
82,586,830 and 87,282,751 shares issued)......................... 826 873
Additional paid-in capital........................................ 435,735 396,277
Treasury stock (5,031,040 and 13,949,073 shares).................. (50,829) (119,387)
Retained earnings (deficit)....................................... 84,418 (28,414)
---------- ----------
Total Stockholders' Equity...................................... 497,367 277,817
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY......................... $1,591,904 $1,477,081
========== ==========
See accompanying notes to consolidated financial statements.
33
CROSS TIMBERS OIL COMPANY
Consolidated Income Statements
- --------------------------------------------------------------------------------
(in thousands, except per share data)
Year Ended December 31
-------------------------------
2000 1999 1998
-------- -------- ---------
REVENUES
Oil and condensate................................................... $128,194 $ 86,604 $ 56,164
Gas and natural gas liquids.......................................... 456,814 239,056 182,587
Gas gathering, processing and marketing.............................. 16,123 10,644 9,438
Other................................................................ (280) 4,991 1,297
-------- -------- ---------
Total Revenues....................................................... 600,851 341,295 249,486
-------- -------- ---------
EXPENSES
Production........................................................... 86,988 76,110 63,148
Taxes, transportation and other...................................... 56,696 33,681 29,105
Exploration.......................................................... 1,047 904 8,034
Depreciation, depletion and amortization............................. 129,807 112,364 83,560
Impairment........................................................... - - 2,040
Gas gathering and processing......................................... 8,930 8,743 8,360
General and administrative........................................... 49,460 14,091 13,479
Derivative fair value loss........................................... 55,821 - -
Trust development costs.............................................. - - 1,498
-------- -------- ---------
Total Expenses....................................................... 388,749 245,893 209,224
-------- -------- ---------
OPERATING INCOME..................................................... 212,102 95,402 40,262
-------- -------- ---------
OTHER INCOME (EXPENSE)
Gain on significant property divestitures............................ 29,965 40,566 -
Gain (loss) on investment in equity securities....................... 13,279 (1,149) (93,719)
Interest expense, net................................................ (78,914) (64,214) (52,113)
-------- -------- ---------
Total Other Income (Expense)......................................... (35,670) (24,797) (145,832)
-------- -------- ---------
INCOME (LOSS) BEFORE INCOME TAX
AND MINORITY INTEREST............................................... 176,432 70,605 (105,570)
Income Tax Expense (Benefit)......................................... 59,380 23,965 (35,851)
Minority Interest in Net (Income) Loss of Consolidated Subsidiaries.. (59) 103 -
-------- -------- ---------
NET INCOME (LOSS).................................................... 116,993 46,743 (69,719)
Preferred stock dividends............................................ 1,758 1,779 1,779
-------- -------- ---------
EARNINGS (LOSS) AVAILABLE TO COMMON STOCK............................ $115,235 $ 44,964 $ (71,498)
======== ======== =========
EARNINGS (LOSS) PER COMMON SHARE
Basic............................................................... $1.62 $0.64 $(1.10)
======== ======== =========
Diluted............................................................. $1.55 $0.63 $(1.10)
======== ======== =========
Weighted Average Common Shares Outstanding........................... 71,154 70,228 65,094
======== ======== =========
See accompanying notes to consolidated financial statements.
34
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Cash Flows
- --------------------------------------------------------------------------------
(in thousands)
Year Ended December 31
---------------------------------
2000 1999 1998
--------- --------- ---------
OPERATING ACTIVITIES
Net income (loss)............................................................... $ 116,993 $ 46,743 $ (69,719)
Adjustments to reconcile net income (loss) to net cash
provided (used) by operating activities:
Depreciation, depletion and amortization.................................... 129,807 112,364 83,560
Impairment.................................................................. - - 2,040
Non-cash incentive compensation............................................. 25,790 93 1,141
Deferred income tax......................................................... 58,993 23,657 (35,744)
(Gain) loss on investment in equity securities and from sale of properties.. (45,578) (51,802) 86,628
Non-cash loss in derivative fair value...................................... 54,512 - -
Minority interest in net income (loss) of consolidated subsidiaries......... 59 (103) -
Other non-cash items........................................................ 3,015 827 2,540
Changes in operating assets and liabilities (a)............................. 33,830 1,522 (124,322)
--------- --------- ---------
Cash Provided (Used) by Operating Activities.................................... 377,421 133,301 (53,876)
--------- --------- ---------
INVESTING ACTIVITIES
Proceeds from sale of Hugoton Royalty Trust units............................... - 148,570 -
Proceeds from sale of other property and equipment.............................. 77,119 110,500 2,494
Property acquisitions........................................................... (45,648) (270,226) (296,390)
Purchase of Spring Holding Company.............................................. - (42,540) -
Development costs............................................................... (154,382) (90,725) (69,356)
Gas gathering and other additions............................................... (11,033) (10,479) (7,517)
(Loans to) repayments from officers............................................. 60 (1,470) (5,795)
--------- --------- ---------
Cash Used by Investing Activities............................................... (133,884) (156,370) (376,564)
--------- --------- ---------
FINANCING ACTIVITIES
Proceeds from short- and long-term debt......................................... 523,400 256,400 877,900
Payments on short- and long-term debt........................................... (745,500) (339,262) (496,938)
Purchase of minority interest................................................... (100,071) (42,385) -
Contributions from minority interests........................................... - 142,500 -
Common stock offering........................................................... 126,125 29,668 133,113
Dividends....................................................................... (3,891) (4,950) (8,460)
Purchases of treasury stock and other........................................... (41,896) (25,501) (66,658)
--------- --------- ---------
Cash Provided (Used) by Financing Activities.................................... (241,833) 16,470 438,957
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................................ 1,704 (6,599) 8,517
Cash and Cash Equivalents, January 1............................................ 5,734 12,333 3,816
--------- --------- ---------
Cash and Cash Equivalents, December 31.......................................... $ 7,438 $ 5,734 $ 12,333
========= ========= =========
(a) Changes in Operating Assets and Liabilities
Accounts receivable....................................................... $ (90,921) $ (8,227) $ (7,022)
Investment in equity securities........................................... 43,746 20,180 (131,809)
Other current assets...................................................... (4,535) (32) (1,513)
Other assets.............................................................. (15,535) - -
Current liabilities....................................................... 82,392 (11,628) 16,022
Other long-term liabilities............................................... 18,683 1,229 -
--------- --------- ---------
Decrease (Increase) in Operating Assets and Liabilities..................... $ 33,830 $ 1,522 $(124,322)
========= ========= =========
See accompanying notes to consolidated financial statements.
35
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Stockholders' Equity
- --------------------------------------------------------------------------------
(in thousands, except per share amounts)
Additional Retained
Preferred Common Paid-in Treasury Earnings
Stock Stock Capital Stock (Deficit) Total
----------- --------- --------- ---------- --------- ---------
Balances, December 31, 1997.................. $28,468 $695 $210,722 $ (76,656) $ 7,014 $170,243
Sale of common stock......................... - 108 133,005 - - 133,113
Issuance/vesting of performance shares....... - 1 1,804 (536) - 1,269
Stock option exercises....................... - 7 2,984 (483) - 2,508
Treasury stock purchases..................... - - - (65,575) - (65,575)
Treasury stock issued........................ - - 13,741 24,695 - 38,436
Common stock dividends ($0.11 per share)..... - - - - (7,022) (7,022)
Preferred stock dividends ($1.56 per share).. - - - - (1,779) (1,779)
Net loss..................................... - - - - (69,719) (69,719)
---------- ---- -------- --------- -------- --------
Balances, December 31, 1998.................. 28,468 811 362,256 (118,555) (71,506) 201,474
Issuance/sale of common stock................ - 60 45,640 - - 45,700
Issuance/vesting of performance shares....... - 2 231 - - 233
Stock option exercises....................... - - 95 (755) - (660)
Treasury stock purchases..................... - - - (25,517) - (25,517)
Treasury stock issued........................ - - (11,945) 25,440 - 13,495
Common stock dividends ($0.03 per share)..... - - - - (1,872) (1,872)
Preferred stock dividends ($1.56 per share).. - - - - (1,779) (1,779)
Net income................................... - - - - 46,743 46,743
---------- ---- -------- --------- -------- --------
Balances, December 31, 1999.................. 28,468 873 396,277 (119,387) (28,414) 277,817
Sale of common stock from treasury........... - - 61,427 64,698 - 126,125
Issuance/vesting of performance shares....... - 8 18,244 (6,976) - 11,276
Stock option exercises....................... - 32 29,976 (4,933) - 25,075
Treasury stock purchases..................... - - - (55,758) - (55,758)
Cancellation of shares....................... - (89) (71,438) 71,527 - -
Common stock dividends ($0.03 per share)..... - - - - (2,403) (2,403)
Preferred stock converted to common.......... (1,251) 2 1,249 - - -
Preferred stock dividends ($1.56 per share).. - - - - (1,758) (1,758)
Net income................................... - - - - 116,993 116,993
---------- ---- -------- --------- -------- --------
Balances, December 31, 2000.................. $27,217 $826 $435,735 $ (50,829) $ 84,418 $497,367
========== ==== ======== ========= ======== ========
See accompanying notes to consolidated financial statements.
36
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
February 25, 1998 and September 18, 2000.
The Company is an independent oil and gas company with production and
exploration concentrated in Texas, Oklahoma, Arkansas, Kansas, New Mexico,
Wyoming, Alaska and Louisiana. The Company also gathers, processes and markets
gas, transports and markets oil and conducts other activities directly related
to its oil and gas producing activities.
Comprehensive Income
During the years ended December 31, 2000, 1999 and 1998, there were no
reportable elements of comprehensive income other than net income.
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 as opposed to
exploration activities. 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
$66,823,000 at December 31, 2000 and $27,937,000 at December 31, 1999, related
to wells in process 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.
If conditions indicate that long-term assets may be impaired, the carrying
value of property and equipment 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 proved
reserve and production information and pricing assumptions that management
believes are reasonable. 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.
37
Royalty Trusts
The Company created Cross Timbers Royalty Trust in February 1991 and
Hugoton Royalty Trust in December 1998 by conveying defined net profits
interests in certain of the Company's properties. Units of both trusts are
traded on the New York Stock Exchange. The Company makes monthly net profits
payments to each trust based on revenues and costs from the related underlying
properties. The Company owns 22.7% of Cross Timbers Royalty Trust units that it
purchased on the open market in 1996 and 1997, and owns 54.3% of the Hugoton
Royalty Trust following the sale of units in 1999 and 2000. The cost of the
Company's interest in the trusts is included in producing properties. Amounts
due the trusts, net of amounts retained by the Company's ownership of trust
units, are deducted from the Company's revenues, taxes, production expenses and
development costs. As of January 1, 1999, the Company no longer records the
trusts' portion of development costs as an expense in the consolidated income
statement.
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 ("SFAS") No.
115, Accounting for Certain Investments in Debt and Equity Securities, equity
securities were recorded as trading securities since they were acquired
principally for resale in the near future. Accordingly, this investment at
December 31, 1999 is recorded as a current asset at market value, unrealized
holding gains and losses are recognized in the consolidated income statements,
and cash flows from purchases and sales of equity securities are included in
cash provided (used) by operating activities in the consolidated statements of
cash flows. Gains (losses) on trading securities and interest expense related to
the cost of these investments are classified as other income (expense) in the
consolidated income statements. See Note 2.
Other Assets
Other assets primarily include deferred debt costs that are amortized over
the term of the related debt (Note 4) and the long-term portion of gas balancing
receivable (see "Revenue Recognition" below). Other assets are presented net of
accumulated amortization of $11,574,000 at December 31, 2000 and $7,252,000 at
December 31, 1999.
Derivatives
The Company uses derivatives to hedge product price and interest rate
risks, as opposed to their use for trading purposes. Gains and losses on
commodity futures contracts are recognized in oil and gas revenues when the
hedged transaction occurs. Amounts receivable or payable under interest swap
agreements are recorded as adjustments to interest expense. Cash flows related
to derivative transactions are included in operating activities. See Note 7.
In conjunction with its hedging activities, the Company occasionally enters
natural gas call options. Because options do not provide protection against
declining prices, they do not qualify for hedge or loss deferral accounting. The
opportunity loss, related to gas prices exceeding the fixed gas prices
effectively provided by the call options, is recognized as a derivative fair
value loss, rather than deferring the loss and recognizing it as reduced gas
revenue when the hedged production occurs, as prescribed by hedge accounting.
Effective January 1, 2001, the Company adopted SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and
138 (Note 7). SFAS No. 133 requires the Company to record all derivatives on the
balance sheet at fair value. Change in the fair value of derivatives that are
not designated as hedges, as well as the ineffective portion of hedge
derivatives, must be recognized as a derivative fair value gain or loss in the
income statement. Changes in the fair value of effective cash flow hedges are
recorded as a component of other comprehensive income, which is later
transferred to earnings when the hedged transaction occurs. Physical delivery
contracts which cannot be net cash settled are deemed to be normal sales and
therefore are not accounted for as derivatives. However, physical delivery
contracts that have a price not clearly and closely associated with the asset
sold are not a normal sale and must be accounted for as a non-hedge derivative
(Note 8).
38
Revenue Recognition
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, 2000, the Company's consolidated balance sheet includes a net
current asset of $2.5 million for a net underproduced balancing position of
911,000 Mcf of natural gas, and a net long-term liability of $3.7 million for an
overproduced balancing position of 3,581,000 Mcf of natural gas, net of an
underproduced balancing position of 10,062,000 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
$144.3 million for 2000, $66.2 million for 1999 and $56.3 million for 1998.
These amounts are net of intercompany eliminations.
Other Revenues
Other revenues include gains and losses from sale of property and
equipment. Excluding the gain on sale of significant property divestitures,
including the sale of Hugoton Royalty Trust units (Note 13), the Company
realized gains on sale of property and equipment of $920,000 in 2000, $6,390,000
in 1999 and $795,000 in 1998.
Interest Expense
Interest expense includes amortization of deferred debt costs and is
presented net of interest income of $1,430,000 in 2000, $619,000 in 1999 and
$91,000 in 1998, and net of capitalized interest of $3,488,000 in 2000,
$1,353,000 in 1999 and $1,070,000 in 1998. Interest expense related to
investment in equity securities has been classified as a component of gain
(loss) on investment in equity securities (Note 2).
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 or non-employee directors
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. 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 12.
Earnings per Common Share
In accordance with SFAS No. 128, Earnings Per Share, the Company reports
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. See Note
10.
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 2000, 1999 or 1998.
39
2. Investment in Equity Securities
In 1998, the Company purchased what it believed to be undervalued oil and
gas reserves through investments in publicly traded equity securities of select
energy companies. After selling a portion of these securities in 1998 and 1999,
the Company sold its remaining investment in equity securities in 2000 for $43.7
million, resulting in a gain of $13.3 million.
The following are components of gain (loss) on investment in equity
securities:
(in thousands) 2000 1999 1998
-------- -------- --------
Realized gains (losses) on sale of securities:
Gains............................................ $ 4,683 $ 823 $ 887
Losses........................................... (35,523) (23,047) (15,706)
-------- -------- --------
Net gains (losses)............................... (30,840) (22,224) (14,819)
Changes in unrealized gains (losses)............... 45,535 27,070 (72,605)
Interest expense related to investment in
equity securities................................ (1,416) (5,995) (6,295)
-------- -------- --------
Gains (losses) on investment in equity securities.. $ 13,279 $ (1,149) $(93,719)
======== ======== ========
3. Related Party Transactions
Loans to Officers
Pursuant to margin support agreements with each of six officers, the
Company, with Board of Director authorization, agreed to use up to $15 million
of the value of Cross Timbers Royalty Trust units owned by the Company and
investment in equity securities, to provide margin support for the officers'
broker accounts in which they held Company common stock. The Company also 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. An additional
$1,530,000 was loaned during 1999, including a new loan to a fifth officer. The
loans are full recourse and due in December 2003, with an interest rate equal to
the Company's bank debt rate. At each balance sheet date, the loans are reviewed
to determine whether a reserve for collectibility should be booked as
compensation expense. To date, no reserve for collectibility has been recorded.
As of March 2001, officer margin debt balances related to Company common stock
were fully repaid, and the margin support agreements were terminated because
they were no longer needed.
Other Transactions
A company, partially owned by a director of the Company, performs
consulting services in connection with the Company's acquisition and divestiture
programs, for which it received fees totaling $994,000 in 2000. The director-
related company also represented the purchaser of properties sold by the Company
during 1999 and invested in the purchase.
The same director-related company performed consulting services in 1998 in
connection with the Cook Inlet Acquisition. 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 royalty interest conveyed from
the Company's 100% working interest in these properties.
40
4. Debt
The Company's outstanding debt consists of the following:
(in thousands) December 31
------------------
2000 1999
-------- -------
Long-term Debt:
Senior debt-
Bank debt under revolving credit agreements due May 12, 2005,
8.3% at December 31, 2000..................................... $469,000 $439,000
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
Spring Holding Company-
Senior bank debt, 8.5%.......................................... - 116,100
Senior subordinated debt, 12.9%................................. - 7,000
Summer Acquisition Company-
Senior bank debt, 8.5%.......................................... - 129,000
----------- --------
Total long-term debt.............................................. $769,000 $991,100
=========== ========
Senior Debt
In May 2000, the Company entered a new revolving credit agreement with
commercial banks with a commitment of $800 million. Proceeds of this loan
agreement were used to refinance the Company's previous senior credit facility
and to fully repay a $25 million term loan and the separate bank debt of the
Company's subsidiaries, Spring Holding Company and Summer Acquisition Company.
In June 2000, the loan agreement was amended to allow the Company to issue
letters of credit. Any letters of credit outstanding reduce the borrowing
capacity under the revolving credit facility. As of December 31, 2000, letters
of credit outstanding totaled $33 million. Borrowings at December 31, 2000 under
the loan agreement were $469 million with unused borrowing capacity of $298
million. 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. Based on reserve values at December 31, 2000 and
parameters specified by the banks, the borrowing base supports borrowings in
excess of the $800 million commitment. Borrowings under the loan agreement are
due May 12, 2005, 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. In February 2001, the loan
agreement was amended to allow the repurchase of the Company's subordinated debt
and to increase commodity hedging limits.
On January 3, 2001, the Company purchased primarily gas-producing
properties in East Texas and Louisiana for $115 million, of which $11.6 million
had been paid in 2000. This acquisition was funded through borrowings under the
loan agreement.
The credit facility is secured by the Company's producing properties.
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, as defined, 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, 2000 were based
on LIBOR rates with maturity of one to six months and accrued at the applicable
LIBOR rate plus 1 1/2%. 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 on
unused borrowing
41
commitments which was 0.35% at December 31, 2000. The weighted average interest
rate on senior debt was 8.2% during 2000, 6.7% during 1999 and 6.9% during 1998.
Subordinated Debt
The Company sold $125 million of 9 1/4% senior subordinated notes on April
2, 1997, and $175 million of 8 3/4% senior subordinated notes on October 28,
1997. 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. Upon
a change in control of the Company, the noteholders 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.
See Note 7 regarding interest rate swap agreements.
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) 2000 1999 1998
------- ------- --------
Income tax expense (benefit) at the
federal statutory rate of 34%............................. $59,987 $24,006 $(35,893)
State and local taxes and other............................. (607) (41) 42
------- ------- --------
Income tax expense (benefit)................................ $59,380 $23,965 $(35,851)
======= ======= ========
Components of income tax expense (benefit) are as follows:
(in thousands) 2000 1999 1998
------- ------- --------
Current income tax.......................................... $ 387 $ 308 $ (107)
Deferred income tax expense (benefit)....................... 63,792 28,697 (2,626)
Net operating loss carryforward............................. (4,799) (5,040) (33,118)
------- ------- --------
Income tax expense (benefit)................................ $59,380 $23,965 $(35,851)
======= ======= ========
42
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 $17,098,000 and a long-term liability of $82,476,000 at
December 31, 2000, and a current asset of $4,168,000 and a long-term liability
of $25,975,000 at December 31, 1999. Significant components of net deferred tax
assets and liabilities are:
(in thousands) December 31
---------------------
2000 1999
-------- --------
Deferred tax assets:
Net operating loss carryforwards..................................... $ 69,370 $ 64,118
Accrued stock appreciation right and performance share compensation.. 916 985
Unrealized loss on trading securities................................ - 6,103
Derivative fair value loss........................................... 15,024 -
Other................................................................ 5,038 2,891
-------- --------
Total deferred tax assets..................................... 90,348 74,097
-------- --------
Deferred tax liabilities:
Property and equipment............................................... 148,363 92,115
Other................................................................ 7,363 3,789
-------- --------
Total deferred tax liabilities................................ 155,726 95,904
-------- --------
Net deferred tax assets (liabilities).................................. $(65,378) $(21,807)
======== ========
As of December 31, 2000, the Company has estimated tax loss carryforwards
of approximately $210 million, of which $11 million are related to capital
losses. The capital loss tax carryforwards expire in 2005 while the remaining
$199 million are scheduled to expire in 2008 through 2020. Approximately $21.7
million of the tax loss carryforwards are the result of the Spring Acquisition.
The Company has not booked any valuation allowance because it believes it has
tax planning strategies available to realize its tax loss carryforwards.
6. Commitments and Contingencies
Leases
The Company leases offices, vehicles and certain other equipment in its
primary locations under noncancelable operating leases. As of December 31, 2000,
minimum future lease payments for all noncancelable lease agreements (including
the sale and operating leaseback agreements described below) were as follows:
(in thousands)
2001................................. $12,147
2002................................. 11,937
2003................................. 11,604
2004................................. 7,005
2005................................. 5,051
Remaining............................ 21,357
-------
Total................................ $69,101
=======
Amounts incurred by the Company under operating leases (including renewable
monthly leases) were $17,329,000 in 2000, $14,093,000 in 1999 and $11,180,000 in
1998.
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. This
transaction was recorded as a sale and operating leaseback, with no gain or loss
on the sale.
43
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
and may be irrevocably fixed by the Company with 20 days advance notice. As of
December 31, 2000, annual rentals were $1.7 million. This transaction was
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
consolidated balance sheets. The deferred gain balance at December 31, 2000 was
$2 million.
Under each of the above sale and leaseback transactions, 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.
Letters of Credit
The Company issued letters of credit totaling $33 million to counterparties
and purchasers under certain hedge derivatives and physical delivery contracts.
(Note 8).
Employment Agreements
Two executive officers have 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, the officers receive a minimum annual salary of $625,000
and $450,000, respectively, and are 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 Company terminates the employee without
cause or a change in control of the Company occurs, the officer is entitled to a
lump-sum payment of three times the officer's most recent annual compensation.
Commodity Commitments
The Company has entered into natural gas physical delivery contracts,
futures contracts and swap agreements that effectively fix prices, and natural
gas call options that provide ceiling prices. See Note 8.
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 arm's-length transactions. The plaintiffs
further allege that these 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. These deductions allegedly include
production and post-production costs, marketing costs, administration costs and
costs incurred by the Company in gathering, compressing, dehydrating,
processing, treating, blending and/or transporting the gas produced. The Company
contends that, to the extent any fees are proportionately borne by the
plaintiffs, these fees are established by arm's-length negotiations with third
parties or, if charged by affiliates, are comparable to fees charged by third
party gatherers or processors. The Company further contends that any such fees
enhance the value of the gas or the products derived from the gas. The
plaintiffs are seeking an accounting and payment of the monies allegedly owed to
them. 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
44
Claims Act. 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 has made similar
allegations in over 70 actions filed against more than 300 other 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 plaintiff also seeks an order for the Company to
cease the allegedly improper measuring practices. After its review, the
Department of Justice decided in April 1999 not to intervene and asked the court
to unseal the case. The court unsealed the case in May 1999. A multi-district
litigation panel ordered that the lawsuits against the Company and other
companies filed by Grynberg be transferred and consolidated to the federal
district court in Wyoming. The Company and other defendants filed a motion to
dismiss which has been heard by the Court and a decision is pending. The Company
believes that the allegations of this lawsuit are without merit and intends to
vigorously defend the action. Any potential liability from this claim is not
currently determinable and no provision has been accrued in the Company's
financial statements.
A third lawsuit, Bishop, et al. v. Amoco Production Co., et al., was filed
in May 2000 in the Third Judicial District Court in Lincoln County, Wyoming by
owners of royalty and overriding royalty interests in wells located in Wyoming.
The plaintiffs alleged that the Company and the other producer defendants
deducted impermissible costs of production from royalty payments that were made
to the plaintiffs and other similarly situated persons and failed to properly
inform the plaintiffs and others of the deductions taken as allegedly required
by Wyoming statutes. The action was brought as a class action on behalf of all
persons who own an interest in wells located in Wyoming as to which the
defendants pay royalties and overriding royalties. The plaintiffs sought a
declaratory judgment that the deductions made were impermissible and sought
damages in the amount of the deductions made, together with interest and
attorneys' fees. The Company has reached a settlement of this action, which is
subject to court approval. The Company has agreed to pay a total settlement
amount of $572,000 for a release of claims relating to deductions taken by the
Company, the statutory reporting of claims, and other miscellaneous matters. The
Company further agreed that it would not take similar deductions from royalty
owners in the future and to itemize other deductions from future royalty
disbursements. The Company expects that the court will approve the settlement in
April 2001. This settlement was accrued in the Company's financial statements.
In February 2000, the Department of Interior notified the Company and
several other producers that certain Native American leases located in the San
Juan Basin have expired due to the failure of the leases to produce in paying
quantities. The Department of Interior has demanded abandonment of the property
as well as payment of the gross proceeds from the wells minus royalties paid
from the date of the alleged cessation of production to present. The Company has
filed a Notice of Appeal with the Interior Board of Indian Appeals. The
potential loss from these claims is currently not determinable, but could be
material to the Company's annual earnings. The Company believes that the claim
is without merit and that there is currently not a probable loss. No related
provision is accrued in the Company's financial statements.
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 or liquidity, although an unfavorable outcome could
have a material adverse effect on the operations of a given interim period or
year.
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 Note 3.
45
7. Financial Instruments
The Company uses financial and commodity-based derivative contracts to
manage exposures to commodity price and interest rate 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 and basis swaps to hedge its exposure to price fluctuations on crude oil
and natural gas sales. When actual commodity prices exceed the fixed price
provided by these contracts, the Company pays this excess to the counterparty
and records an opportunity loss in the period related production occurs. When
actual commodity prices are below the contractually provided fixed price, the
Company receives this difference and records a gain in the production period.
These gains and losses are recorded as a component of oil and gas revenues. See
Note 8.
In 2000, the Company recognized net losses on futures contracts and basis
swap transactions of $40.5 million related to gas hedging and $7.8 million
related to oil hedging. During 1999, the Company recognized net losses on
futures contracts and basis swap transactions of $5.7 million related to gas
hedging and $2.2 million related to oil hedging. During 1998, the Company
recognized net gains of $7.7 million related to gas hedging.
The Company occasionally sells gas call options. Because these options are
covered by Company production and the strike prices are below current market gas
prices, they have the same effect on the Company as product hedges. However,
because written options do not provide protection against declining prices, they
do not qualify for hedge or loss deferral accounting. The opportunity loss,
related to gas prices exceeding the fixed gas prices effectively provided by the
call options, has been recognized as a loss in derivative fair value, rather
than deferring the loss and recognizing it as reduced gas revenue when the
hedged production occurs. For the year ended December 31, 2000, a derivative
fair value loss of $55.8 million was recorded in the consolidated income
statements, of which $1.3 million was cash settled.
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. In 1999 and 2000, the Company terminated
these interest rate swaps, resulting in total proceeds received and a gain of $2
million. This gain has been deferred and is being amortized against interest
expense through September 2005.
To reduce the interest rate on a portion of its subordinated debt, the
Company entered an agreement with a bank that has purchased on the market the
Company's subordinated 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 depreciation in market
value of the notes from the date purchased by the bank is immediately payable to
the bank. Any appreciation in the market value, including any depreciation
payments, is receivable from the bank to the extent of the market value of the
notes at the end of the agreement. The Company has the option of terminating
this agreement and repurchasing the notes from the bank at any time at market
value.
46
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, 2000 and 1999. The following are estimated fair
values and carrying values of the Company's other financial instruments at each
of these dates:
Asset (Liability)
--------------------------------------------------
December 31, 2000 December 31, 1999
--------------------- -----------------------
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
---------- --------- --------- ----------
Investment in equity securities.. $ - $ - $ 29,052 $ 29,052
Long-term debt................... (769,000) (774,000) (991,100) (981,540)
Futures contracts................ - (112,807) - (2,676)
Basis swap agreements............ - 3,868 - (1,113)
Call options..................... (53,769) (53,769) (347) (347)
Interest rate swap agreements.... 473 2,651 218 2,503
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 long-term debt is based on current market quotes. The fair
value of futures contracts, swap agreements and call options is estimated based
on current commodity prices and interest rates.
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 $3,121,000 at December 31, 2000 and
$2,150,000 at December 31, 1999. The Company's bad debt provision was $1,093,000
in 2000, $1,347,000 in 1999 and $411,000 in 1998. 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 the exposure is diversified among major banks and financial
institutions with high credit ratings.
New Derivative Accounting Principle
Effective January 1, 2001, the Company has adopted SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137
and 138. SFAS No. 133 requires the Company to record all derivatives on the
balance sheet at fair value. Change in the fair value of derivatives that are
not designated as hedges, as well as the ineffective portion of hedge
derivatives, must be recognized as a derivative fair value gain or loss in the
income statement. Change in fair value of effective cash flow hedges are
recorded as a component of other comprehensive income, which is later
transferred to earnings when the hedged transaction occurs. Physical delivery
contracts which cannot be net cash settled are deemed to be normal sales and
therefore are not accounted for as derivatives. However, physical delivery
contracts that have a price not clearly and closely associated with the asset
sold are not a normal sale and must be accounted for as a non-hedge derivative
(Note 8).
The Company accounted for adoption of SFAS No. 133 on January 1, 2001 by
recording a one-time after-tax charge of $44.6 million in the income statement
for the cumulative effect of a change in accounting principle and an unrealized
loss of $67.3 million in other comprehensive income. The charge to the income
statement is primarily related to the Company's physical delivery contract to
sell 35,500 Mcf of natural gas per day from 2002 through July 2005 at crude oil-
based prices. The unrealized loss is related to the derivative fair value of
cash flow hedges. Amounts recorded on the balance sheet at January 1, 2001 were
a $103.6 million current liability, a $2.2 million long-term asset and a $70.8
million long-term liability related to the fair value of derivatives and a
current deferred tax asset of $36.3 million and a reduction to the long-term tax
liability of $24 million for the related tax benefits.
47
8. Natural Gas Sales Commitments
The Company has entered into natural gas futures contracts and swap
agreements that effectively fix prices, and natural gas call options that
provide ceiling prices, for the production and periods shown below. The Company
does not have any outstanding basis swap agreements as of March 2001. Prices to
be realized for hedged production may be less than these fixed prices because of
location, quality and other adjustments.
Futures Contracts
and Swap Agreements Call Options (a)
--------------------------------- ---------------------------------
Production Period Mcf per Day per Mcf Mcf per Day per Mcf
----------------------- ----------------- -------------- ----------------- --------------
2001 April to September 80,000 $ 2.79 53,333 $2.60 - 3.05
October 80,000 2.79 53,333 2.60 - 3.05
November 80,000 2.86 20,000 2.95
December 80,000 2.93 20,000 2.95
2002 January to March 10,000 5.47 - -
-------------------------------------
(a) Includes a natural gas call option to sell 20,000 Mcf per day in the
San Juan Basin at an average ceiling index price of $2.70 per Mcf for
the year 2001 which is exercisable in December 2001. Based on current
San Juan Basin basis of approximately $0.30 per Mcf for April through
October and $0.20 for November and December, and including premium
received of $0.05 per Mcf, this call option is reflected above at a
NYMEX prices of $3.05 and $2.95 per Mcf.
The Company's settlement of futures contracts and swap agreements related
to first quarter 2001 gas production resulted in a net loss of approximately
$26 million. This loss will be recognized as a decrease in gas revenue of
approximately $0.78 per Mcf in the first quarter of 2001.
The Company has entered into physical delivery contracts which cannot be
net cash settled and are therefore considered to be normal sales. These
contracts effectively fix prices for the following production and periods:
Location Production Period Mcf per Day Fixed Price per Mcf
-------------------- ----------------------------- ----------- --------------------
East Texas April 2001 to March 2002 40,000 $5.42
Arkoma April to September 2001 90,000 5.55
October 2001 to March 2002 50,000 5.36
San Juan Basin April to September 2001 25,000 5.14
October 2001 to March 2002 10,000 5.05
Rocky Mountains April 2001 to March 2002 10,000 4.97
Mid-Continent April to September 2001 45,000 5.45
October 2001 to March 2002 30,000 5.55
Other Physical Delivery Contracts
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 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
price of approximately 10% of the average NYMEX futures price for intermediate
crude oil. After contract amendments in May and October 2000, the Company has
agreed to sell 21,650 Mcf per day at the index price through December 2000,
34,344 Mcf per day at the index price in 2001 and 35,500 Mcf per day from 2002
through July 2005 at a price of approximately 10% of the average NYMEX futures
price for intermediate crude oil. Because this gas sales contract is priced
based on crude oil, which is not clearly and closely associated with natural gas
prices, it must be accounted for as a derivative financial instrument under SFAS
No. 133 beginning January 1, 2001 (Note 7).
48
As partial consideration for an acquisition, the Company agreed to sell gas
volumes ranging from 40,000 Mcf in 2000 to 35,000 Mcf in 2003 at specified
discounts from index prices. This commitment was recorded at its total value of
$7.5 million in March 1999 in other current and long-term liabilities. The
discounts are charged to the liability as taken. As of December 31, 2000, $1.6
million is recorded in other current liabilities and $2.4 million is recorded in
other long-term liabilities related to this commitment.
The Company has committed to sell all gas production from certain East
Texas properties 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.
As a part of the Ocean Energy Acquisition, the Company assumed a commitment
to sell 6,800 Mcf of gas per day through April 2003 at prices which are adjusted
by the monthly index price. In 2000, the prices ranged from $0.50 to $0.95 per
Mcf. Delivery of the committed sales volumes is in Arkansas.
9. Equity
Three-for-Two Stock Splits
The Company effected three-for-two common stock splits on February 25, 1998
and September 18, 2000. All common stock shares, treasury stock shares and per
share amounts have been retroactively restated to reflect these stock splits.
Common Stock
The following reflects the Company's common stock activity:
Shares Issued Shares in Treasury
----------------------- ------------------------
Year Ended December 31, Year Ended December 31,
----------------------- ------------------------
(in thousands) 2000 1999 1998 2000 1999 1998
------ ------ ------ ------- ------- ------
Balance, beginning of year.............. 87,283 81,072 69,466 13,949 13,981 10,291
Issuance/sale of common stock........... - 6,000 10,805 (6,600) (3,000) (2,883)
Issuance/vesting of performance shares.. 813 195 123 381 - 41
Stock option exercises.................. 3,195 16 678 276 77 37
Treasury stock purchases................ - - - 5,891 2,891 6,495
Cancellation of shares.................. (8,866) - - (8,866) - -
Preferred stock converted to common..... 162 - - - - -
------ ------ ------ ------ ------ ------
Balance, end of year.................... 82,587 87,283 81,072 5,031 13,949 13,981
====== ====== ====== ====== ====== ======
In April 1998, the Company completed a public offering of 11.3 million
shares of common stock, of which 10.8 million shares were sold by the Company
and the remaining 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. The offering was made pursuant to the
shelf registration statement filed with the Securities and Exchange Commission
in February 1998. See "Shelf Registration Statement" below.
In September 1998, the Company issued from treasury 2.9 million shares to
affiliates of Shell Oil Company for the Cook Inlet Acquisition. The Company
effectively guaranteed Shell a $13.33 per share value. As of December 31, 1998,
these shares were valued at $13.33 per share, or a total of $38.4 million. The
$13.33 guarantee was effectively settled in July 1999 upon the Company's
repurchase of these shares from Shell at $8.83 per share, or $25.5 million, and
net additional payments to Shell of $13 million which was charged to equity at
that date.
49
In July 1999, the Company issued 6 million shares of common stock at its
fair value of $7.617 per share in exchange for its 50% interest in Spring
Holding Company and for cash proceeds of $3.2 million which were used to reduce
bank debt (Note 14).
Also in July 1999, the Company sold from treasury 3 million shares of
common stock in an underwritten public offering for net proceeds of
approximately $26.5 million. The proceeds were used to repurchase the 2.9
million shares of common stock issued to Shell for the Cook Inlet Acquisition.
The offering was made pursuant to the shelf registration statement.
In May 2000, in conjunction with the dissolution of Whitewine Holding
Company, the Company's wholly owned subsidiary, 8.9 million shares were canceled
from treasury stock. This transaction caused a $71.5 million reduction in
treasury stock with an offsetting reduction in additional paid-in capital,
resulting in no change to total stockholders' equity.
In November 2000, the Company sold from treasury 6.6 million shares of
common stock in an underwritten public offering for net proceeds of
approximately $126.1 million. The proceeds were used to reduce outstanding
indebtedness. The offering was made pursuant to the shelf registration
statement.
Performance Shares
The Company issued performance shares totaling 820,000 in 2000, 213,000 in
1999 and 123,000 in 1998 (Note 12). In October 1999, 18,000 performance shares
were forfeited from the shares issued in 1998.
Treasury Stock
The Company's open market treasury share acquisitions totaled 5.3 million
shares in 2000 at an average price of $7.88, 7,500 shares in 1999 at an average
price of $7.04 and 6.5 million shares in 1998 at an average price of $10.10 per
share. Through March 26, 2001, 4.3 million shares remain under the May 2000
Board of Directors' authorization to repurchase 4.5 million shares of the
Company's common stock.
Stockholder Rights Plan
In August 1998, the Board of Directors adopted a stockholder rights plan
that is designed to assure that all stockholders 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 was declared for each
outstanding share of common stock, par value $.01 per share, payable on
September 15, 1998 to stockholders of record on that date. Each right entitles
stockholders 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.
Shelf Registration Statement
In February 1998, the Company filed a shelf registration statement with the
Commission to potentially offer securities which could include debt securities,
preferred stock, common stock or warrants to purchase debt securities, preferred
stock or common stock. The shelf registration statement was amended in April
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 are to be used for general corporate
purposes, including reduction of bank debt. After the April 1998, July 1999 and
November 2000 common stock offerings, $99.4 million remains available under the
shelf registration statement for future sales of securities.
50
Common Stock Warrants
As partial consideration for producing properties acquired in December
1997, the Company issued warrants to purchase 1,427,701 shares of common stock
at a price of $10.05 per share for a period of five years. These warrants were
valued at $5.7 million and recorded as additional paid-in capital.
Common Stock Dividends
The Board of Directors declared quarterly dividends of $0.0267 per common
share in 1998, $0.0067 per common share from 1999 through second quarter 2000
and $0.01 per common share for the third and fourth quarters of 2000. See Note
4 regarding restrictions on dividends.
Series A Convertible Preferred Stock
Series A convertible preferred stock is recorded in the accompanying
consolidated balance sheets at its liquidation preference of $25 per share.
Cumulative dividends on preferred stock are payable quarterly in arrears, when
declared by the Board of Directors, based on an annual rate of $1.5625 per
share. The preferred stock has no stated maturity and no sinking fund, and is
redeemable, in whole or in part, by the Company. 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 3.24 shares of common stock for each
share of preferred stock, subject to adjustment in certain events. During 2000,
50,000 shares of convertible preferred stock were converted into 162,000 shares
of common stock. In January 2001, the Company sent notice to preferred
stockholders that it would redeem all outstanding shares on February 16, 2001 at
a price of $25.94 per share plus accrued and unpaid dividends. Prior to the
redemption date, 1.1 million outstanding shares of preferred stock were
converted into 3.5 million common shares in 2001.
10. 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) Earnings
Earnings Shares per Share
--------- --------- -----------
2000
- ------------------------------------------------
Basic
Net income.................................... $116,993
Preferred stock dividends..................... (1,758)
--------
Earnings available to common stock - basic.... 115,235 71,154 $ 1.62
==========
Diluted
Effect of dilutive securities:
Stock options................................ - 518
Preferred stock.............................. 1,758 3,647
Warrants..................................... - 387
-------- ------
Earnings available to common stock - diluted.. $116,993 75,706 $ 1.55
======== ====== ==========
1999
- ------------------------------------------------
Basic
Net income.................................... $ 46,743
Preferred stock dividends..................... (1,779)
--------
Earnings available to common stock - basic.... 44,964 70,228 $ 0.64
==========
Diluted
Effect of dilutive securities:
Stock options................................ - 161
Preferred stock.............................. 1,779 3,690
Warrants..................................... - -
-------- ------
Earnings available to common stock - diluted.. $ 46,743 74,079 $ 0.63
======== ====== ==========
51
(in thousands, except per share data) Earnings
Earnings Shares per Share
---------- -------- ---------
1998
- ------------------------------------------------
Basic
Net loss...................................... $(69,719)
Preferred stock dividends..................... (1,779)
--------
Loss available to common stock - basic........ (71,498) 65,094 $(1.10)
==========
Diluted
Effect of dilutive securities:
Stock options................................ - 507
Warrants..................................... - 35
-------- ------
Loss available to common stock - diluted...... $(71,498) 65,636 $(1.10) (a)
======== ====== ==========
(a) Because of the antidilutive effect of dilutive securities on loss per
common share, diluted loss available to common stock is the same as
basic.
11. Supplemental Cash Flow Information
The consolidated statements of cash flows exclude the following non-cash
transactions (Notes 9, 12 and 13):
- Cancellation of 8.9 million shares of treasury stock in 2000
- Conversion of 50,000 shares of preferred stock to common stock in 2000
- Sale of Hugoton Royalty Trust units in 2000 in exchange for 495,000
shares of common stock valued at $11.3 million, and in 1999 in exchange
for 74,000 shares of common stock valued at $700,000
- Purchase of a 50% interest in Spring Holding Company in 1999 in exchange
for 5.6 million shares of common stock, valued at $42.5 million
- The Cook Inlet Acquisition in 1998, a purchase of oil-producing
properties for 2.9 million shares of common stock, a related effective
guarantee of $13.33 per share value and a $6 million note payable
- Performance shares activity, including:
- Grants of 820,000 shares in 2000, 213,000 shares in 1999 and 123,000
shares in 1998 to key employees and nonemployee directors
- Vesting of 1,007,000 shares in 2000, 18,000 shares in 1999 and
137,000 shares in 1998
- Forfeiture of 18,000 shares in 1999
- Receipt of common stock of 44,000 shares (valued at $967,000) in 2000
and 13,000 shares (valued at $181,000) in 1998 for the option price of
exercised stock options
Interest payments in 2000 totaled $80,067,000 (including $3,488,000 of
capitalized interest), $70,500,000 in 1999 (including $1,353,000 of capitalized
interest) and $57,200,000 in 1998 (including $1,070,000 of capitalized
interest). Income tax payments were $1,085,000 in 2000; net income tax refunds
were $322,000 during 1999 and $454,000 during 1998.
52
12. 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% upon the earlier of three consecutive years of
participation in the plan or five years of service. All employees over 21 years
of age may participate. Company contributions under the plan were $3,226,000 in
2000, $2,514,000 in 1999 and $1,766,000 in 1998.
Post-Retirement Health Plan
Effective January 1, 2001, the Company adopted a retiree medical plan for
employees who retire at age 55 or over with a minimum of five years full-time
service. Benefits under the plan are the same as for active employees, and
continue until the retired employee or the employee's dependents are eligible
for Medicare or another similar federal health insurance program. After
Medicare eligibility, only prescription coverage is provided. Premiums are only
charged to dependents. Post-retirement medical benefits are not pre-funded by
the Company, but are paid when incurred. As of the plan's inception, total
prior service cost is estimated to be $804,000. For the year 2001, total
expense is estimated to be $1.1 million which includes the total prior service
cost, current year service cost and interest. The annual rate of increase in
health care costs were assumed to range from 9% in 2000 to 6% in 2006 and
beyond. An increase of 1% in the assumed health care cost trend rate would
result in an increase in the total estimated service and interest cost of
$158,000 for 2001, and would increase the estimated prior service cost at
January 1, 2001 by $417,000. The weighted average discount rate used to
determine the prior service cost and interest was 7.75% at January 1, 2001.
1994 and 1997 Stock Incentive Plans
Under the 1994 Stock Incentive Plan and the 1997 Stock Incentive Plan, a
total of 3,375,000 shares of common stock may be issued under each plan to
directors, officers and other key employees pursuant to grants of stock options
or performance shares of common stock. At December 31, 2000, there are 49,000
shares available for grant under the 1994 Plan and 649,000 shares 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 have a term of ten
years and are not exercisable until six months after their 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.
1998 Stock Incentive Plan
In May 1998, the stockholders approved the 1998 Stock Incentive Plan under
which 9,000,000 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.
At December 31, 2000, there were 1,759,000 shares available for grant under the
1998 Plan. Stock options generally vest and become exercisable annually in equal
amounts over a five-year period, with provision for accelerated vesting when the
common stock price reaches specified levels. There were 1,135,000 options
outstanding at December 31, 2000 that vested when the common stock price closed
above $30.00 on March 9, 2001 and 104,000 options that vest when the common
stock price closes above $32.50. In 2001, an additional 927,000 options were
granted, of which 647,000 have vested and 280,000 vest when the stock price
closes above $32.50.
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 820,000 in 2000,
195,000 in 1999 and 108,000 in 1998. Performance shares vested, totaling
53
1,007,000 in 2000 and 122,000 in 1998, when the common stock price reached
specified levels. In 1999, 18,000 performance shares issued in 1998 were
forfeited. General and administrative expense includes compensation related to
these performance share grants of $18.4 million in 2000, $102,000 in 1999 and
$1.6 million in 1998. As of December 31, 2000, there were 85,000 performance
shares that vested when the common stock price closed above $30.00 on March 9,
2001 and 13,500 performance shares that vest in increments of 4,500 in each of
2001, 2002 and 2003. In March 2001, an additional 77,000 performance shares
were issued that vest when the stock price closes above $32.50. The Company also
issued to nonemployee directors a total of 18,000 performance shares in 1999 and
15,000 performance shares in 1998, which vested upon grant.
In February 2001, the Board approved an agreement with certain executive
officers under which the officers, immediately prior to a change in control of
the Company, will receive a total grant of 77,000 performance shares for every
$2.50 increment in the closing price of the Company's common stock above $30.00.
The number of performance shares granted under the agreement will be reduced by
the number of performance shares awarded to the officers between the date of the
agreement and the date of the change in control. Certain officers will also
receive a total grant of 155,000 performance shares immediately prior to a
change in control without regard to the price of the Company's common stock.
Royalty Trust Option Plans
Under the 1998 Royalty Trust Option Plan, the Company granted certain
officers options to purchase 1,290,000 Hugoton Royalty Trust units at prices of
$8.03 and $9.50 per unit, or a total of $12 million. These units were exercised
in 1999 and 2000, resulting in non-cash compensation expense of $7.1 million in
2000 and $60,000 in 1999 (Note 13).
Option Activity and Balances
The following summarizes option activity and balances from 1998 through
2000:
Weighted
Average
Exercise Stock
Price Options
--------- ----------
1998
-------------------------------------------------------
Beginning of year..................................... $ 7.41 3,530,170
Grants.............................................. 11.68 2,093,625
Exercises........................................... 7.76 (1,632,691)
Forfeitures......................................... 11.46 (32,625)
----------
End of year........................................... 9.49 3,958,479
==========
Exercisable at end of year............................ 7.35 2,053,854
==========
1999
-------------------------------------------------------
Beginning of year..................................... $ 9.49 3,958,479
Grants.............................................. 7.11 614,812
Exercises........................................... 4.57 (15,693)
Forfeitures......................................... 7.75 (42,862)
----------
End of year........................................... 9.20 4,514,736
==========
Exercisable at end of year............................ 7.39 2,009,361
==========
2000
- ---------------------------------------------------------
Beginning of year..................................... $ 9.20 4,514,736
Grants.............................................. 19.99 4,762,503
Exercises........................................... 9.81 (4,643,414)
Forfeitures......................................... 8.91 (246,336)
----------
End of year........................................... 20.14 4,387,489
==========
Exercisable at end of year............................ 19.24 3,148,509
==========
54
The following summarizes information about outstanding
options at December 31, 2000:
Options Outstanding Options Exercisable
------------------------------ ---------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Prices Number Term Price Number Price
------------------------ --------- --------- -------- ----------- -------------
$2.76 - $8.28 163,872 6.2 years $ 6.42 163,872 $ 6.42
$8.29 - $13.80 370,912 7.5 years 12.31 370,912 12.31
$13.81 - $19.32 332,425 7.6 years 14.29 332,425 14.29
$19.33 - $27.59 3,520,280 9.8 years 22.16 2,281,300 22.00
---------- -----------
4,387,489 3,148,509
========== ===========
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 $10.27 in
2000, $4.27 in 1999 and $4.55 in 1998.
2000 1999 1998
---- ---- ----
Risk-free interest rates......... 5.8% 5.8% 5.6%
Dividend yield................... 0.2% 3.0% 3.2%
Weighted average expected lives.. 5 years 5 years 5 years
Volatility....................... 53% 91% 52%
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 2000, 1999 and 1998, 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:
(in thousands, except per share data)
2000 1999 1998
--------- -------- ---------
Earnings (loss) available to common stock:
As reported............................... $115,235 $ 44,964 $(71,498)
Pro forma................................. $ 91,194 $ 40,373 $(75,785)
Earnings (loss) per common share:
Basic As reported..................... $ 1.62 $ 0.64 $ (1.10)
Pro forma....................... $ 1.28 $ 0.57 $ (1.16)
Diluted As reported..................... $ 1.55 $ 0.63 $ (1.10)
Pro forma....................... $ 1.23 $ 0.57 $ (1.16)
13. Sale of Hugoton Royalty Trust Units
In December 1998, the Company formed the Hugoton Royalty Trust by conveying
80% net profits interests in properties located in the Hugoton area of Kansas
and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of
Wyoming. These net profits interests were conveyed to the trust in exchange for
40 million units of beneficial interest. In April and May 1999, the Company
sold 17 million, or 42.5%, of the trust units in an initial public offering at a
price of $9.50 per unit, less underwriters' discount and expenses. Total net
proceeds from the sale were $148.6 million, resulting in a gain of $40.3 million
before income tax. Proceeds from the sale were used to reduce bank debt.
55
In 1999 and 2000, officers exercised options to purchase a total of 1.3
million Hugoton Royalty Trust units from the Company pursuant to the 1998
Royalty Trust Option Plan in exchange for shares of Company common stock. The
Company recognized gains of $11 million in 2000 and $235,000 in 1999 on these
sales of trust units.
14. Acquisitions and Dispositions
Acquisitions
On July 1, 1999, the Company and Lehman Brothers Holdings, Inc. acquired
predominantly gas-producing properties in the Arkoma Basin through the purchase
of the common stock of Spring Holding Company, a private oil and gas company
located in Tulsa, Oklahoma for $85 million. The Company issued 5.6 million
shares of common stock for its ownership interest in Spring and Lehman
contributed $42.5 million in cash. The Company and Lehman each owned 50% of a
limited liability company that acquired the common stock of Spring. Pursuant to
a put and call agreement, the Company purchased Lehman's interest in September
1999 for $44.3 million, or $1.8 million in excess of the recorded minority
interest, which excess was recorded as producing property cost. Property cost
associated with the Spring acquisition totaled approximately $235 million, a
portion of which was attributed to other than producing properties, including a
gas gathering system, compressors, undeveloped leasehold cost and other tangible
property. After purchase accounting adjustments, including a $14.1 million step-
up adjustment for deferred income taxes, the cost of the properties was $257
million. Although the Company and Lehman had equal board representation and
control of Spring, the Company's management controlled operations of the
properties from July 1, 1999 and had the right to purchase Lehman's interest
pursuant to the call agreement. The Company accordingly consolidated its
investment in Spring from July 1, 1999, with recognition of Lehman's investment
as a minority interest through September 1999.
On September 15, 1999, the Company and Lehman acquired Arkoma Basin oil and
gas properties from Ocean Energy, Inc. for $231 million. The original purchase
price of $235.3 million was reduced by estimated net revenue received between
the July 1, 1999 effective date and the closing date. The Company and Lehman
each owned 50% of Whitewine Holding Company, which was formed to acquire the
Arkoma Basin properties. Pursuant to a put and call agreement, the Company
purchased Lehman's 50% interest in the Ocean Energy Acquisition on March 31,
2000 for $111 million, or $11 million in excess of the recorded minority
interest, which excess was recorded as producing property cost. Although the
Company and Lehman had equal board representation and control of Whitewine, the
Company's management controlled operations of the properties from September 15,
1999 and had the right to purchase Lehman's interest pursuant to the call
agreement. Whitewine's financial results are consolidated in the Company's
financial statements, with recognition of Lehman's 50% interest as a minority
interest through March 31, 2000.
Dispositions
On May 4, 1999, the Company sold nonoperated producing properties in the
San Juan Basin of New Mexico to Vastar Resources, Inc. for $29.9 million. The
Company sold other nonoperated producing properties in June 1999 for
approximately $15 million. Proceeds from the sales were used to reduce bank
debt.
On September 14, 1999, producing properties were sold for approximately
$63.5 million before closing costs in two transactions. The Company sold
primarily nonoperated properties in Oklahoma, the Permian Basin of West
Texas and New Mexico, the Panhandle area of Texas and the Green River Basin of
Wyoming, including sales of $22.5 million of properties acquired in the Spring
acquisition.
In March 2000, the Company sold primarily gas-producing properties in
Crockett County, Texas for gross proceeds of $43 million and sold oil- and gas-
producing properties in Lea County, New Mexico for gross proceeds of $25.3
million.
Acquisitions have been recorded using the purchase method of accounting.
The following presents unaudited pro forma results of operations for the year
ended December 31, 1999 as if these acquisitions and the sale of Hugoton Royalty
Trust units and other properties had been consummated immediately prior to
January 1, 1999. Pro forma results
56
are not presented for the year ended December 31, 2000 because the effects of
these transactions excluded from 2000 results are not significant. These pro
forma results are not necessarily indicative of future results.
(in thousands, except per share data) Pro Forma
-----------
(Unaudited)
Revenues............................ $353,186
========
Net income.......................... $ 45,552
========
Earnings available to common stock.. $ 43,924
========
Earnings per common share:
Basic......................... $ 0.60
========
Diluted....................... $ 0.59
========
On December 5, 2000, the Company entered into a definitive agreement to
acquire primarily gas-producing properties in East Texas and Louisiana for $115
million from Herd Producing Company, Inc. The purchase was completed on January
3, 2001, and was funded through borrowings under existing bank lines. The
purchase is subject to typical post-closing adjustments.
On January 2, 2001, the Company repurchased 9,598,000 MMBtu of natural gas
for $9.9 million from a production payment sold to EEX Corporation in a 1998
acquisition. In December 2001, the Company can repurchase an additional
9,598,000 MMBtu of gas from the production payment for approximately $11
million.
15. Quarterly Financial Data (Unaudited)
The following are summarized quarterly financial data for the years ended
December 31, 2000 and 1999:
Quarter
------------------------------------------
(in thousands, except per share data) 1st 2nd 3rd 4th
--------- --------- --------- ---------
2000
- ---------------------------------------
Revenues.......................... $113,326 $ 121,650 $160,519 $205,356
Gross profit (a).................. $ 44,997 $ 30,094 $ 80,981 $105,490
Earnings available to
common stock.................... $ 33,267 $ 798 $ 31,366 $ 49,804
Earnings per common share
Basic........................... $ 0.46 $ 0.01 $ 0.45 $ 0.68
Diluted......................... $ 0.44 $ 0.01 $ 0.43 $ 0.64
Average shares outstanding........ 72,441 68,918 69,518 73,728
1999
- ---------------------------------------
Revenues.......................... $ 69,415 $ 65,550 $ 95,326 $111,004
Gross profit (a).................. $ 15,154 $ 13,601 $ 36,420 $ 44,318
Earnings (loss) available to
common stock.................... $ (2,091) $ 28,341 $ 13,071 $ 5,643
Earnings (loss) per common share
Basic........................... $ (0.03) $ 0.42 $ 0.18 $ 0.08
Diluted......................... $ (0.03) $ 0.41 $ 0.17 $ 0.08
Average shares outstanding........ 67,091 67,100 73,371 73,247
(a) Operating income before general and administrative expense.
57
16. 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) 2000 1999 1998
-------- -------- --------
Acquisitions:
Producing properties................ $ 31,983 $505,912 $339,889
Undeveloped properties.............. 3,490 4,182 514
Development (a)........................ 163,224 89,306 69,367
Exploration:
Geological and geophysical studies.. 829 872 7,943
Dry hole expense.................... - - -
Rental expense and other............ 218 32 91
-------- -------- --------
Total.................................. $199,744 $600,304 $417,804
======== ======== ========
(a) Includes capitalized interest of $3,488,000 in 2000, $1,353,000 in
1999 and $1,070,000 in 1998.
Proved Reserves
Independent petroleum engineers have estimated the Company's proved oil and
gas reserves, all of which are located in the United States. Proved reserves
are the estimated quantities that geologic and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are
the quantities expected to be recovered through existing wells with existing
equipment and operating methods. Due to the inherent uncertainties and the
limited nature of reservoir data, such estimates are subject to change as
additional information becomes available. The reserves actually recovered and
the timing of production of these reserves may be substantially different from
the original estimate. Revisions result primarily from new information obtained
from development drilling and production history and from changes in economic
factors.
Standardized Measure
The standardized measure of discounted future net cash flows ("standardized
measure") and changes in such cash flows are prepared using assumptions required
by the Financial Accounting Standards Board. Such assumptions include the use
of year-end prices for oil and gas and year-end costs for estimated future
development and production expenditures to produce year-end estimated proved
reserves. Discounted future net cash flows are calculated using a 10% rate.
Estimated future income taxes are calculated by applying year-end statutory
rates to future pre-tax net cash flows, less the tax basis of related assets and
applicable tax credits.
58
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.
(in thousands) Oil Gas Natural Gas
(Bbls) (Mcf) Liquids (Bbls)
------------ ------------ --------------
Proved Reserves
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
Revisions.................................. 10,792 60,011 1,838
Extensions, additions and discoveries...... 3,003 166,669 3,357
Production................................. (5,112) (105,120) (1,325)
Purchases in place......................... 2,790 494,666 20
Sales in place............................. (4,380) (279,827) (3,162)
----------- ----------- -----------
December 31, 1999............................ 61,603 1,545,623 17,902
Revisions.................................. 2,709 142,974 3,709
Extensions, additions and discoveries...... 1,145 258,843 1,951
Production................................. (4,736) (125,857) (1,622)
Purchases in place......................... 833 26,557 72
Sales in place............................. (3,109) (78,457) -
----------- ----------- -----------
December 31, 2000............................ 58,445 1,769,683 22,012
=========== =========== ===========
Proved Developed Reserves
December 31, 1997............................ 33,835 677,710 11,494
=========== =========== ===========
December 31, 1998............................ 42,876 968,495 14,000
=========== =========== ===========
December 31, 1999............................ 48,010 1,225,014 13,781
=========== =========== ===========
December 31, 2000............................ 46,334 1,328,953 16,448
=========== =========== ===========
Standardized Measure of Discounted Future December 31
Net Cash Flows Relating to Proved Reserves -----------------------------------------
2000 1999 1998
----------- ----------- -----------
(in thousands)
Future cash inflows.......................... $18,866,832 $ 5,113,094 $ 3,041,776
Future costs:
Production................................. (3,237,574) (1,549,401) (1,135,789)
Development................................ (389,698) (294,250) (228,561)
----------- ----------- -----------
Future net cash flows before income tax...... 15,239,560 3,269,443 1,677,426
Future income tax............................ (4,947,614) (718,892) (231,249)
----------- ----------- -----------
Future net cash flows........................ 10,291,946 2,550,551 1,446,177
10% annual discount.......................... (5,029,916) (1,153,611) (637,774)
----------- ----------- -----------
Standardized measure (a)..................... $ 5,262,030 $ 1,396,940 $ 808,403
=========== =========== ===========
(a) Before income tax, the year-end standardized measure (or discounted
present value of future net cash flows) was $7,748,632,000 in 2000,
$1,765,936,000 in 1999 and $908,606,000 in 1998.
59
Changes in Standardized Measure of
Discounted Future Net Cash Flows
(in thousands)
2000 1999 1998
------------ ----------- ----------
Standardized measure, January 1........ $ 1,396,940 $ 808,403 $ 642,109
----------- ---------- ---------
Revisions:
Prices and costs..................... 5,096,973 608,123 (184,568)
Quantity estimates................... 190,457 62,033 65,600
Accretion of discount................ 123,225 70,256 58,195
Future development costs............. (196,048) (113,110) (104,636)
Income tax........................... (2,082,745) (259,403) 53,758
Production rates and other........... 1,378 (137) (296)
----------- ---------- ---------
Net revisions.................... 3,133,240 367,762 (111,947)
Extensions, additions and discoveries.. 1,018,349 125,209 96,829
Production............................. (441,323) (215,869) (146,498)
Development costs...................... 128,757 70,275 56,904
Purchases in place (a)................. 115,866 414,759 271,806
Sales in place (b)..................... (89,799) (173,599) (800)
----------- ---------- ---------
Net change....................... 3,865,090 588,537 166,294
----------- ---------- ---------
Standardized measure, December 31...... $ 5,262,030 $1,396,940 $ 808,403
=========== ========== =========
(a) Generally 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.
(b) Generally based on beginning of the year present value (at beginning of
year prices and costs) less the cash flow received from such properties
during the year, rather than the estimated present value at the date of
sale.
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.
Year-end realized oil prices used in the estimation of proved reserves and
calculation of the standardized measure were $25.49 for 2000, $24.17 for 1999
and $9.50 for 1998. Year-end average realized gas prices were $9.55 for 2000,
$2.20 for 1999 and $2.01 for 1998. Year-end average realized natural gas
liquids prices were $26.33 for 2000, $13.83 for 1999 and $3.99 for 1998. Proved
oil and gas reserves at December 31, 2000 include:
- 1,970,000 Bbls of oil and 223,578,000 Mcf of gas and discounted present
value before income tax of $842,346,000 related to the Company's ownership
of approximately 54% of Hugoton Royalty Trust units at December 31, 2000.
- 747,000 Bbls of oil and 7,986,000 Mcf of gas and discounted present value
before income tax of $38,403,000 related to the Company's ownership of
approximately 23% of Cross Timbers Royalty Trust units at December 31,
2000.
Based on NYMEX prices of $25.00 per Bbl for oil and $5.00 per Mcf for gas
(which are comparable to realized prices of $23.69 per Bbl for oil and $4.79 per
Mcf for gas), and an $18.86 per Bbl realized price for natural gas liquids,
estimated proved reserves at December 31, 2000 would be 57.7 million Bbls of
oil, 1.75 Tcf of natural gas and 21.6 million Bbls of natural gas liquids. Using
these prices, the present value of estimated future cash flows, discounted at
10% and before income tax, would be $3,834,024,000.
60
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, 2000 and 1999, and the
related consolidated income statements, statements of cash flows and
stockholders' equity for each of the three years in the period ended December
31, 2000. 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 auditing standards generally accepted
in the United States. 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, 2000 and 1999, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2000, in conformity
with accounting principles generally accepted in the United States.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 22, 2001
61
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 2nd day of April
2001.
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 2nd day of April 2001.
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 Jack P. Randall
Board and President
Scott G. Sherman
------------------------------------
Scott G. Sherman
Herbert D. Simons
------------------------------------
Herbert D. Simons
PRINCIPAL FINANCIAL OFFICER PRINCIPAL ACCOUNTING OFFICER
Louis G. Baldwin Bennie G. Kniffen
- ------------------------------------------ ------------------------------------
Louis G. Baldwin, Executive Vice President Bennie G. Kniffen, Senior Vice
and Chief Financial Officer President and Controller
62
INDEX TO EXHIBITS
Exhibit
No. Description Page
-------- ----------------------------------------------------------- ------
3.1 Restated Certificate of Incorporation of Cross Timbers Oil
Company, as restated on April 21, 1998 (incorporated by
reference to Exhibit 3.1 to Form 10-Q for the quarter ended
September 30, 2000)
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 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)
4.2 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)
4.3 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/A dated
September 9, 1998)
4.4 Certificate of Designation of Series A Junior Participating
Preferred Stock, par value $.01 per share, dated August 25,
1998 (incorporated by reference to Exhibit 4.1 to Form 10-Q
for the quarter ended September 30, 2000)
10.1 * Amended and Restated Employment Agreement between the Company
and Bob R. Simpson, dated May 17, 2000 (incorporated by
reference to Exhibit 10.2 to Form 10-Q for the quarter ended
June 30, 2000)
10.2 * Amended and Restated Employment Agreement between the Company
and Steffen E. Palko, dated May 17, 2000 (incorporated by
reference to Exhibit 10.3 to Form 10-Q for the quarter ended
June 30, 2000)
10.3 * Amended and Restated 1994 Stock Incentive Plan (incorporated by
reference to Exhibit 10.5 to Form 10-K for the year ended
December 31, 1999)
10.4 * 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)
10.5 * 1997 Stock Incentive Plan, as amended February 15, 2000
(incorporated by reference to Exhibit 10.7 to Form 10-K for the
year ended December 31, 1999)
10.6 * 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)
10.7 * 1998 Stock Incentive Plan, as amended February 20, 2001
10.8 * 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)
63
Exhibit
No. Description Page
------- ---------------------------------------------------------- ------
10.9 * Management Group Employee Severance Protection Plan, as
amended February 15, 2000 (incorporated by reference to
Exhibit 10.13 to Form 10-K for the year ended December 31,
1999)
10.10 * Employee Severance Protection Plan, as amended February 15,
2000 (incorporated by reference to Exhibit 10.14 to Form 10-K
for the year ended December 31, 1999)
10.11 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)
10.12 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)
10.13 Revolving Credit Agreement dated May 12, 2000 between Cross
Timbers Oil Company and certain commercial banks named therein
(incorporated by reference to Exhibit 10.1 to Form 10-Q for
the quarter ended March 31, 2000)
10.14 First Amendment, dated June 20, 2000, to Revolving Credit
Agreement dated May 12, 2000 between Cross Timbers Oil Company
and certain commercial banks named therein (incorporated by
reference to Exhibit 10.1 to Form 10-Q for the quarter ended
June 30, 2000)
10.15 Second Amendment, dated February 16, 2001, to Revolving Credit
Agreement dated May 12, 2000 between Cross Timbers Oil Company
and certain commercial banks named therein
12.1 Computation of Ratio of Earnings to Fixed Charges
21.1 Subsidiaries of Cross Timbers Oil Company
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Miller and Lents, Ltd.
* Management contract or compensatory plan
- --------------------------------
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.
64