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2001
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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, 2001
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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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XTO Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware 75-2347769
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
810 Houston Street, Suite 2000, Fort Worth, Texas 76102
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(Address of principal executive offices) (Zip Code)
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
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Common Stock, $.01 par value, including preferred
stock purchase rights
Name of Each Exchange on Which Registered
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New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to be the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the Common Stock held by nonaffiliates of the
Registrant as of March 15, 2002 was approximately $2,249,000,000
Number of Shares of Common Stock outstanding as of March 1, 2002 - 123,896,389
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, 2002.
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XTO ENERGY INC.
2001 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Item Page
---- ----
Part I
1. and 2. Business and Properties ........................................ 1
3. Legal Proceedings ................................................ 16
4. Submission of Matters to a Vote of Security Holders .............. 17
Part II
5. Market for Registrant's Common Equity and Related Stockholder
Matters ........................................................ 18
6. Selected Financial Data .......................................... 19
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations ...................................... 21
7A. Quantitative and Qualitative Disclosures about Market Risk ....... 33
8. Financial Statements and Supplementary Data ...................... 35
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure ....................................... 35
Part III
10. Directors and Executive Officers of the Registrant ............... 35
11. Executive Compensation ........................................... 35
12. Security Ownership of Certain Beneficial Owners and Management ... 35
13. Certain Relationships and Related Transactions ................... 35
Part IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ... 36
PART I
Items 1. and 2. BUSINESS AND PROPERTIES
General
XTO Energy Inc. 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 was formerly known as Cross Timbers Oil Company
and changed its name to XTO Energy Inc. in June 2001. 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, Logansport and Oaks Fields of Louisiana.
The Company's estimated proved reserves at December 31, 2001 were 54
million barrels ("Bbls") of oil, 2.2 trillion cubic feet ("Tcf") of natural gas
and 20.3 million Bbls of natural gas liquids, based on December 31, 2001 prices
of $17.39 per Bbl for oil, $2.36 per thousand cubic feet ("Mcf") for gas and
$8.70 per Bbl for natural gas liquids. Approximately 67% of December 31, 2001
proved reserves, computed on a gas energy equivalent ("Mcfe") basis, were proved
developed reserves. Increased proved reserves during 2001 were primarily the
result of acquisitions and development and exploitation activities, partially
offset by production. During 2001, the Company's daily average production was
13,637 Bbls of oil, 416,927 Mcf of gas and 4,385 Bbls of natural gas liquids.
Fourth quarter 2001 daily average production was 13,761 Bbls of oil, 455,070 Mcf
of gas and 4,567 Bbls of natural gas liquids.
The Company's properties have relatively long reserve lives and highly
predictable production profiles. Based on December 31, 2001 proved reserves and
projected 2002 production, the average reserve-to-production index of the
Company's proved reserves is 14.8 years. In general, these 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, 2001, the Company owned
interests in 7,301 gross (3,911 net) wells, and it operated wells representing
94% 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 exercise more control over expenses, capital allocation
and the timing of development and exploitation activities in its fields.
The Company has generated a substantial inventory of approximately 1,250
potential development drilling locations within its existing properties (of
which 821 have been attributed proved undeveloped reserves) to support future
net reserve additions. Estimated net potential reserves related to unbooked
development drilling locations exceed 1.5 Tcf equivalent. 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. It also operates a gas processing plant in the Hugoton Field.
Gas gathering and processing operations are only in areas where the Company has
production and are considered activities which add value to its natural gas
production and sales operation.
1
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 Commitments" 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. Its initial public offering of common stock was completed 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
June 2001.
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 core operating areas or in areas with similar geologic
and reservoir characteristics, and
. present opportunities to reduce expenses per Mcfe 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 costs, and provide marketing flexibility and
access to additional markets. The 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 1,250 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 2002, the Company plans to focus on
exploration projects that are near currently owned productive fields. 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 $15 million of its $400 million 2002 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, including
potential undeveloped reserves that will be exploited by the operator. The
Company may also acquire nonoperated interests in order to ultimately accumulate
sufficient ownership interests to operate the properties.
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 December 2001, the Company announced its strategic goal
for 2002 of increasing gas production by 20% over 2001 levels and increasing all
production, including oil and natural gas liquids, by approximately 15% on an
Mcfe basis. The Company reiterated its goal to increase proved reserves to 3
Tcf equivalent at year-end 2002. To achieve these growth targets, the Company
plans to drill about 295 (240 net) development wells and perform approximately
515 (408 net) workovers and recompletions in 2002. Approximately 90% of these
planned wells are classified as proved undeveloped reserves on the Company's
current reserve report.
The Company has budgeted $400 million for its 2002 development drilling
programs, which is expected to be funded primarily by cash flow from operations.
The Company plans to spend about 65% of the development budget in East Texas and
about 20% in aggregate in the Arkoma and San Juan Basins, and the balance evenly
allocated to Alaska, Permian Basin and Hugoton Royalty Trust properties.
Exploration expenditures are expected to be approximately 4% of the 2002 budget.
Costs of any property acquisitions during 2002 may reduce the amount currently
budgeted for development and exploration. The Company may reevaluate its budget
and drilling programs in the event of significant changes in oil and gas prices
to focus on opportunities offering the highest rates of return. The Company's
ability to achieve these production and proved reserves goals will depend on the
success of these planned drilling programs or, if property acquisitions are made
in place of a portion of the drilling program, the success of those
acquisitions.
Acquisitions
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 2.1 million shares of the
Company's common stock at a price of $6.70 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 purchased 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 4.3 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.
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.
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 XTO Energy's 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 acquired Lehman's 50%
interest in Spring for $44.3 million. This acquisition included 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 $257 million. The Company also acquired, with
Lehman as 50% owner, Arkoma Basin properties from affiliates of Ocean Energy,
Inc. for $231 million. The Company acquired Lehman's interest in the Ocean
Energy Acquisition in March 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.
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.
4
During 2001, the Company acquired predominantly gas-producing properties
for a total cost of $242 million. In January 2001, the Company acquired gas
properties in East Texas and Louisiana for $115 million from Herd Producing
Company, Inc., and in February 2001, it acquired gas properties in East Texas
for $45 million from Miller Energy, Inc. and other owners. In August 2001, the
Company acquired primarily underdeveloped acreage in the Freestone area of East
Texas for approximately $22 million. The 2001 acquisitions increased reserves by
approximately 248.3 Bcf of natural gas, approximately 50% of which were proved
undeveloped.
Significant Properties
The following table summarizes proved reserves and discounted present
value, before income tax, of proved reserves by major operating areas at
December 31, 2001:
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................................. 4,136 1,175,871 -- 1,200,687 $ 871,085 44.7%
Arkoma Basin............................... 35 457,333 -- 457,543 407,635 20.9%
Hugoton Royalty Trust (a).................. 2,421 298,164 -- 312,690 232,655 11.9%
San Juan Basin............................. 1,413 253,784 20,299 384,056 182,211 9.4%
Permian Basin.............................. 30,233 31,985 -- 213,383 173,382 8.9%
Alaska Cook Inlet.......................... 14,284 -- -- 85,704 55,537 2.9%
Cross Timbers Royalty Trust (b)............ 1,374 11,414 -- 19,658 16,882 0.9%
Other...................................... 153 6,927 -- 7,845 8,054 0.4%
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Total...................................... 54,049 2,235,478 20,299 2,681,566 $ 1,947,441 100.0%
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(a) Includes 1,658,000 Bbls of oil and 204,123,000 Mcf of gas and discounted
present value before income tax of $159,275,000 related to the Company's
ownership of approximately 54% of Hugoton Royalty Trust units at December
31, 2001.
(b) Includes 605,000 Bbls of oil and 7,305,000 Mcf of gas and discounted
present value before income tax of $9,974,000 related to the Company's
ownership of approximately 23% of Cross Timbers Royalty Trust units at
December 31, 2001.
East Texas Area
The Company acquired most of its producing properties in the East Texas
area in 1998 with the purchase of 251 Bcfe of reserves in eight major fields.
These properties are located in East Texas and northwestern Louisiana and
produce primarily from the Rodessa, Travis Peak, Cotton Valley sandstone,
Bossier sandstone and Cotton Valley limestone formations between 7,000 feet and
13,000 feet. Development in the East Texas area has more than doubled reserves
since acquisition and the Company now has an interest in more than 132,000 gross
acres. The Company owns an interest in 872 gross (831.5 net) wells which it
operates and 61 gross (9.1 net) wells operated by others. The Company also owns
the related gathering facilities.
Freestone Trend
The Freestone Trend area is located in the western shelf of the East Texas
Basin in Freestone, Robertson, Limestone and Leon counties. This area includes
the Freestone, Bald Prairie, Farrar, Dew and Luna fields and was the Company's
most active gas development area in 2001, where 84 gross (74.4 net) gas wells
were drilled and 25 workovers were performed. Initial development was
concentrated in the Travis Peak formation, but is now focused on multi-pay
development of the deeper horizons including the Cotton Valley and Bossier
sandstones, and Cotton Valley limestone. A 27-mile pipeline system was completed
in January 2002 which connected the major fields and will allow multiple exit
points for marketing. Currently testing at about 140 MMcf per day, the Company's
gathering capacity will be increased to more than 400 MMcf per day. The Company
plans to continue its expansion efforts in this area by drilling approximately
134 wells in 2002.
5
Willow Springs Field
This Gregg County field has been another target area in the East Texas
development program. Willow Springs wells produce from both the Travis Peak and
Cotton Valley sandstones at depths ranging from 8,500 feet to 10,500 feet.
Development has included deeper drilling to the less exploited Cotton Valley
sandstones and commingling the shallower Travis Peak zone. The Company drilled
16 wells and performed 5 workovers in 2001 and plans to drill an additional 10
wells in 2002.
Other East Texas Fields
Other fields in East Texas include Opelika, Tri-Cities, Whelan, North
Lansing and Logansport which provide opportunities for field extensions and
infill drilling. In 2001, the Company drilled four wells in the Logansport field
and performed 35 workovers in these fields. In 2002, the Company plans to
perform 26 workovers.
Arkoma Basin Area
During 1999, the Company acquired 480 Bcfe of reserves and a gas gathering
system in the Arkoma Basin of Arkansas and Oklahoma. The Arkoma Basin,
discovered in the 1920s, extends from central Arkansas into southeastern
Oklahoma and is known for shallow production decline rates, multiple formations
and complex geology. The Company controls 40% of Arkansas production from the
Arkoma Basin and is the largest natural gas producer in Arkansas with over
500,000 gross acres of leasehold. The Company owns an interest in 885 gross
(624.3 net) wells which it operates and 657 gross (120.4 net) wells operated by
others. Of these wells, 136 gross (90.8 net) operated wells and 77 gross (15.1
net) nonoperated wells are dual completions. During 2001, the Company drilled 70
wells and completed 132 workovers, 36 of which were stimulation/recompletions
and 75 of which were wellhead compressor installations. The Company's properties
can be separated into three distinct areas which are the Arkansas Fairway trend,
the Arkansas Overthrust trend and the Oklahoma Cromwell/Atoka trend.
Arkansas Fairway Trend
The Arkansas Fairway trend comprises multiple sandstones at depths ranging
from 2,500 to 7,500 feet in the Atoka and Morrow intervals. In 2001, the Orr and
Hale sandstones were targets for the Company's drilling in the Aetna, Silex and
Cecil fields where 33 wells were drilled and 40 workovers were performed.
Drilling was concentrated in the Aetna field and compression and gathering were
upgraded. The Company also continued development of the Silex field into the
deeper Boone and Penters intervals and began redevelopment of the Cecil field
using methods similar to those used in the Aetna field. In 2002, the Company
plans to drill 32 wells.
Arkansas Overthrust Trend
The Arkansas Overthrust trend area, located south of the Arkansas Fairway
Trend , typically has multiple thrust faults that created isolated reservoirs.
Production is found at varying depths, ranging from 3,500 to 7,500 feet. This
extremely complex geology requires an ongoing process to develop the best
exploitation opportunities. The use of electric imaging logs has enhanced the
process of identifying new well locations. The Company drilled 21 wells in this
area in 2001 and completed 88 workovers. In 2002, it plans to drill 13 wells.
Oklahoma Cromwell/Atoka Trend
The Oklahoma Cromwell/Atoka trend of southeastern Oklahoma was originally
developed in the 1970s targeting the Cromwell sandstones, with the Atoka and
Wapanuka limestones as secondary objectives. Development activities were
concentrated in the Ashland and South Pine Hollow Fields where 16 wells were
drilled and 4 workovers were performed in 2001. The Company also completed a 3-D
seismic survey of the South Pine Hollow Field. In 2002, there will be
approximately 10 wells drilled in this area.
6
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 and Woodward
counties, Oklahoma area of the Anadarko Basin. It operates 562 gross (487.1 net)
wells and has an interest in 141 gross (37.1 net) wells operated by others. Oil
and gas were first discovered in the Major County area in 1945. The fields in
the Major and Woodward counties area 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.
Development in the Major County area focuses on mechanical improvements,
restimulations and recompletions to shallower zones and development drilling.
During 2001, the Company participated in the drilling of 16 gross (10.5 net)
wells in the northwestern portion of the county, targeting the Mississippian
formation. The Company has budgeted six drill wells in Major County for 2002.
The Company was also very active in Woodward County, Oklahoma, where 17 gross
(14.3 net) wells were drilled which targeted the Chester formation. In 2002, the
Company plans to drill up to 12 wells.
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 21,000 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.
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 376 gross (352.5 net)
wells that it operates and 79 gross (18.3 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 July 1998, Oklahoma
regulations were amended to increase allowable production in the Oklahoma
panhandle from 150 MMcf per day to 450 MMcf per day which lifted curtailment in
this area. During 2001, development of the Hugoton area included successful
recompletions to the Towanda formation. The Company also embarked on a pilot
project to test new restimulation techniques in the Chase intervals.
Twenty-seven of these restimulations were completed in 2001. The Company plans
to perform seven Towanda completions and 46 Chase restimulations during 2002.
Green River Basin
The Green River Basin is located in southwestern Wyoming. The Company has
interests in 185 gross (183.5 net) wells that it operates and 31 gross (4.1 net)
wells operated by others in the Fontenelle Field area. Gas production began in
the Fontenelle area in the early 1970s and the producing reservoirs are the
Cretaceous Frontier, Baxter and Dakota sandstones at depths ranging from 7,500
to 10,000 feet. Development potential for the fields in this area include
7
deepening and opening new producing zones in existing wells, drilling new wells
and adding compression to lower line pressures. During 2001, the Company drilled
6 gross (6.0 net) wells in the Fontenelle Unit.
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 with the
purchase of approximately 290 Bcfe from Amoco Corporation. The Company owns an
interest in 719 gross (578.7 net) wells that it operates and 358 gross (85.9
net) wells operated by others. Of these wells, 86 gross (74.6 net) operated
wells and 6 gross (0.5 net) nonoperated wells are dual completions. In 2001, the
Company participated in the drilling of 45 wells and completed 190 workovers.
Drilling focused on the Fruitland Coal and Pictured Cliffs formations at shallow
intervals of 3,000 feet or less and the Mesaverde and Dakota formations at
depths of 3,000 to 7,500 feet. During 2002, the Company plans to drill 48 wells
and perform 190 workovers and recompletions including installation of as many as
100 wellhead compressors and 45 pumping units.
Fruitland Coal and Pictured Cliffs Formations
The Company has centered its Fruitland Coal development efforts on trend
extensions. Its coalbed methane play, first pursued in the San Juan Basin in the
1980s, is focused on the northwestern portion of the Basin surrounding the city
of Farmington. The Company drilled nine Fruitland Coal and six Pictured Cliffs
wells in 2001 and plans to drill an additional 12 wells and perform 20 workovers
in 2002. Operators are seeking approval to reduce current spacing of coalbed
methane wells from 320 acres to 160 acres. The Company anticipates that hearings
on the request will be held in June 2002. If approved, the Company will add more
than 60 potential well locations.
Mesaverde and Dakota Formations
Eighty-acre spacing was approved in January 2002 which will allow wells to
be drilled with multiple zone targets. The Company has identified more than 200
potential well locations which will allow deeper drilling through the Dakota to
the Burro Canyon and Morrison sandstones. The reduced spacing will generate
significant future development opportunities and additional test wells are
planned for 2002. In 2001, the Company drilled 19 Dakota and 11 Mesaverde wells.
Thirty-six wells and 25 workovers are planned for 2002.
Permian Basin Area
University Block 9. The University Block 9 Field is located in Andrews
County, Texas and was discovered in 1953. The Company owns interests in 79 gross
(73.3 net) wells that it operates. Productive zones are of Wolfcamp,
Pennsylvanian and Devonian age and range from 8,400 to 10,000 feet. Development
potential includes proper wellbore utilization, recompletions, infill drilling
and improvement of waterflood efficiency.
Initial development focused on the deeper Devonian formation leaving the
shallower zones for the future. This field was the Company's most active oil
development area during 2001, where the Company drilled 12 wells, including nine
horizontal sidetrack wells. The Company also discovered a new Grayburg producing
interval. During 2002, the Company plans to drill up to nine wells.
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
6,800 to 7,700 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 198 wells in the Prentice
Northeast Unit. The Company also owns an interest in 81 gross (2.0 net)
nonoperated wells. During 2001, the Company continued its 10-acre development
drilling program by drilling 10 gross (9.1 net) vertical wells. During 2002, the
Company plans to continue its expansion of the potential infill area by drilling
as many as ten wells.
8
Wasson Field. The Wasson Field, discovered in 1936, is located in Gaines
and Yoakum counties, Texas and produces from the San Andres formation at depths
ranging from 4,500 to 6,300 feet. The Cornell Unit was formed in 1965 and has
development potential which exists through infill drilling and improvement of
waterflood efficiency. The Company has a 68.3% working interest in the unit. In
2001, the Company drilled five 10-acre infill wells and began testing gas cap
productivity on three wells. The Company plans to drill six wells in this area
in 2002.
Alaska Cook Inlet Area
In September 1998, the Company acquired a 100% working interest in two
State of Alaska leases and the offshore installations in the Middle Ground Shoal
Field of the Cook Inlet. The properties included 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 and, to date, more than 120
million barrels have been produced. The field is separated into East and West
flanks by a crestal fault. Waterflooding of the East Flank has been successful,
but the West Flank has not been fully developed or efficiently waterflooded.
Production is primarily from multiple zones within Miocene-Oligocene-aged Tyonek
formation between 7,000 feet and 10,000 feet subsea.
In 2001, the Company completed a West Flank simulation study and began an
East Flank study. Three wells were converted to injection and five horizontal
high angle sidetrack wells were drilled in 2001. Three additional West Flank
wells are planned for 2002.
Reserves
The following are definitions of terms used in the following disclosures
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.
9
The following are estimated quantities of proved reserves and cash flows
therefrom as of December 31, 2001, 2000 and 1999:
December 31
------------------------------------------------
(in thousands) 2001 2000 1999
------------ ------------ ------------
Proved developed:
Oil (Bbls) ............................ 41,231 46,334 48,010
Gas (Mcf) ............................. 1,452,222 1,328,953 1,225,014
Natural gas liquids (Bbls) ............ 14,774 16,448 13,781
Mcfe .................................. 1,788,252 1,705,645 1,595,760
Proved undeveloped:
Oil (Bbls) ............................ 12,818 12,111 13,593
Gas (Mcf) ............................. 783,256 440,730 320,609
Natural gas liquids (Bbls) ............ 5,525 5,564 4,121
Mcfe .................................. 893,314 546,780 426,893
Total proved:
Oil (Bbls) ............................ 54,049 58,445 61,603
Gas (Mcf) ............................. 2,235,478 1,769,683 1,545,623
Natural gas liquids (Bbls) ............ 20,299 22,012 17,902
Mcfe .................................. 2,681,566 2,252,425 2,022,653
Estimated future net cash flows:
Before income tax ..................... $ 3,756,602 $ 15,239,560 $ 3,269,443
After income tax ...................... $ 2,876,728 $ 10,291,946 $ 2,550,551
Present value of estimated future
net cash flows, discounted at 10%:
Before income tax ..................... $ 1,947,441 $ 7,748,632 $ 1,765,936
After income tax ...................... $ 1,522,049 $ 5,262,030 $ 1,396,940
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,
2001, 2000 and 1999. As prescribed by the Securities and Exchange Commission,
such proved reserves were estimated using oil and gas prices and production and
development costs as of December 31 of each such year, without escalation.
Year-end 2001 realized prices used in the estimation of proved reserves were
$17.39 per Bbl for oil, $2.36 per Mcf for gas and $8.70 per Bbl for natural gas
liquids. See Note 15 to Consolidated Financial Statements for additional
information regarding estimated proved reserves.
Estimated future net cash flows, and the 10% discounted present value, of
year-end 2001 proved reserves are significantly lower than at year-end 2000
because of significantly higher product prices used in the estimation of year-
end 2000 proved reserves. Year-end 2000 prices were $25.49 per Bbl for oil,
$9.55 per Mcf for gas and $26.33 per Bbl for natural gas liquids. Based on
assumed realized prices of $25.00 per Bbl for oil, $3.50 per Mcf for gas and
$16.00 per Bbl for natural gas liquids, estimated proved reserves at December
31, 2001 would be 59.3 million Bbls of oil, 2.3 Tcf of natural gas and 22.3
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
$3.5 billion.
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.
10
During 2001, the Company filed estimates of oil and gas reserves as of
December 31, 2000 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, 2000 in Note 15 to Consolidated Financial Statements, with the
exception that Form EIA-23 includes only reserves from properties operated by
the Company.
Exploration and Production Data
For the following data, "gross" refers to the total wells or acres in
which the Company owns a working interest and "net" refers to gross wells or
acres multiplied by the percentage working interest owned by the Company.
Although many 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 producing wells as of December 31, 2001,
all of which are located in the United States:
Operated Wells Nonoperated Wells Total (a)
---------------------------- ---------------------------- ----------------------------
Gross Net Gross Net Gross Net
------------- ------------- ------------ ------------- ------------ -------------
Oil.......................... 588 516.1 1,835 127.6 2,423 643.7
Gas ......................... 3,525 2,988.6 1,353 278.7 4,878 3,267.3
------------- ------------- ------------ ------------- ------------- ------------
Total........................ 4,113 3,504.7 3,188 406.3 7,301 3,911.0
============= ============= ============ ============= ============= ============
(a) One gross (0.5 net) oil wells and 325 gross (201.2 net) gas wells
are dual completions.
Drilling Activity
The following table summarizes the number of wells drilled during the
years indicated. As of December 31, 2001, the Company was in the process of
drilling 85 gross (59.3 net) wells.
Year Ended December 31
------------------------------------------------------------
2001 2000 1999
---------------- ---------------- ----------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Development wells:
Completed as-
Oil wells ....... 85 33.0 48 29.9 18 6.7
Gas wells ....... 282 200.3 172 114.6 128 91.2
Non-productive ..... 15 5.9 9 1.3 7 3.5
----- ----- ----- ----- ----- -----
Total .............. 382 239.2 229 145.8 153 101.4
----- ----- ----- ----- ----- -----
Exploratory wells:
Completed as-
Oil wells ....... 1 0.5 4 2.8 -- --
Gas wells ....... 4 2.3 1 0.5 1 1.0
Non-productive ..... 2 1.8 1 0.5 -- --
----- ----- ----- ----- ----- -----
Total .............. 7 4.6 6 3.8 1 1.0
----- ----- ----- ----- ----- -----
Total (a) ............. 389 243.8 235 149.6 154 102.4
===== ===== ===== ===== ===== =====
(a) Included in totals are 125 gross (16.5 net) wells in 2001, 66 gross
(8.5 net) wells in 2000 and 44 gross (4.1 net) wells in 1999 drilled
on nonoperated interests.
11
Acreage
The following table summarizes developed and undeveloped leasehold acreage
in which the Company owns a working interest as of December 31, 2001. Excluded
from this summary is acreage related to royalty, overriding royalty and other
similar interests.
Developed Acres (a)(b) Undeveloped Acres
----------------------- ------------------
Gross Net Gross Net
--------- ------- ------ ------
Arkansas ................ 519,646 226,363 25,537 18,906
Oklahoma ................ 464,737 324,816 15,663 6,881
Texas ................... 270,212 177,531 29,610 25,302
New Mexico .............. 196,078 145,963 1,520 1,520
Kansas .................. 66,670 58,169 -- --
Wyoming ................. 45,007 30,241 1,840 1,097
Other ................... 45,694 26,413 1,801 1,925
--------- ------- ------ ------
Total ................... 1,608,044 989,496 75,971 55,631
========= ======= ====== ======
(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 expense and taxes, transportation and other expense per
thousand cubic feet of gas equivalent ("Mcfe," computed on an energy equivalent
basis of six Mcf to one Bbl):
Year Ended December 31
------------------------------------
2001 2000 1999
-------- -------- --------
Sales prices:
Oil (per Bbl) .................................. $ 23.49 $ 27.07 $ 16.94
Gas (per Mcf) .................................. $ 4.51 $ 3.38 $ 2.13
Natural gas liquids (per Bbl) .................. $ 15.41 $ 19.61 $ 11.80
Production expense per Mcfe ....................... $ 0.57 $ 0.53 $ 0.53
Taxes, transportation and other expense per Mcfe .. $ 0.33 $ 0.35 $ 0.23
Delivery Commitments
The Company contracted to sell to a single purchaser approximately 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. The Company terminated this contract in December 2001 in
connection with the Enron Corporation bankruptcy filing. See Notes 7 and 8 to
Consolidated Financial Statements.
Under a production payment, the Company has committed to deliver 16.0 Bcf
(13.0 Bcf net to the Company's interest) to the purchaser beginning
approximately September 2006. Delivery of the committed volumes is in East
Texas. See Note 8 to Consolidated Financial Statements.
12
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 these volumes is
from the San Juan Basin, with the remainder from the East Texas Basin.
As part of an acquisition, the Company assumed a commitment to sell 6,800
Mcf of gas per day in Arkansas through April 2003 at prices which are adjusted
by the monthly index price. The prices ranged from $0.44 to $1.44 per Mcf in
2001 and from $0.50 to $0.95 per Mcf in 2000.
The Company has also entered fixed price contracts to sell physical daily
gas volumes of 130,000 Mcf in January 2002, 100,000 Mcf from February through
March 2002 and 30,000 Mcf from April through December 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 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 effectively competes in the market.
The Company's ability to market oil and gas depends on many factors beyond
its control, including the extent of domestic production and imports of oil and
gas, the proximity of the Company's gas production to pipelines, the available
capacity in such pipelines, the demand for oil and gas, and the effects of
weather and 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.
13
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.
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. 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.
14
Employees
The Company had 742 employees as of December 31, 2001. None of the
employees are represented by a union. Management 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, 53, 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, 51, 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, 52, 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, 43, 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, 47, has been Executive Vice President -
Administration or held similar positions with the Company since 1987. Prior to
that time, Mr. Vennerberg was employed by Cotton Petroleum Corporation (1984-
1986).
Bennie G. Kniffen, 51, 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.
15
Item 3. LEGAL PROCEEDINGS
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 in
April 1998. 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. The court has ordered that the
parties enter into mediation, which should occur in the first half of 2002.
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.
In October 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 the lawsuit, which was denied. 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 cannot currently be
reasonably estimated, and no provision has been 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 from February through August 1990. 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. 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.
In June 2001, the Company was served with a lawsuit styled Quinque
Operating Co., et al. v. Gas Pipelines, et al. The action was filed in the
District Court of Stevens County, Kansas, against the Company and one of its
subsidiaries, along with over 200 natural gas transmission companies, producers,
gatherers and processors of natural gas. Plaintiffs seek to represent a class of
plaintiffs consisting of all similarly situated gas working interest owners,
overriding royalty owners and royalty owners either from whom the defendants had
purchased natural gas or who received economic benefit from the sale of such gas
since January 1, 1974. No class has been certified. The allegations in the case
are similar to those in the Grynberg case; however, the Quinque case broadens
the claims to cover all oil and gas leases (other than the Federal and Native
American leases that are the subject of the Grynberg case). The complaint
alleges that the defendants have mismeasured both the volume and heating content
of natural gas delivered into their pipelines resulting in underpayments to the
plaintiffs. Plaintiffs assert a breach of contract claim, negligent or
intentional misrepresentation, civil conspiracy, common carrier liability,
conversion, violation of a variety of Kansas statutes and other common law
causes of action. The amount of damages was not specified in the complaint. In
16
September 2001, the Company filed a motion to dismiss the lawsuit, which is
currently pending. In February 2002, the Company and one of its subsidiaries
were dismissed from the suit and another subsidiary of the Company was added.
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
cannot currently be reasonably estimated, and no provision has been 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 operating results 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 2001.
17
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 2001 and 2000
(as adjusted for the three-for-two stock splits effected on September 18, 2000
and June 5, 2001):
High Low Dividend
---------- ---------- ----------
2001
First Quarter .............................. $ 20.633 $ 12.542 $ 0.0067
Second Quarter ............................. 21.733 13.750 0.0100
Third Quarter .............................. 16.500 12.300 0.0100
Fourth Quarter ............................. 19.300 13.250 0.0100
2000
First Quarter .............................. $ 5.944 $ 3.361 $ 0.0045
Second Quarter ............................. 9.889 5.444 0.0045
Third Quarter .............................. 14.417 7.111 0.0067
Fourth Quarter ............................. 19.333 11.167 0.0067
The determination of the amount of future dividends, if any, to be
declared and paid is at 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 stockholders, including dividend
payments.
On February 19, 2002, the Board of Directors declared a quarterly dividend
of $.01 per share payable on April 15, 2002 to stockholders of record on March
28, 2002. On March 1, 2002, the Company had approximately 658 stockholders of
record.
18
Item 6. SELECTED FINANCIAL DATA
The following table shows selected financial information for the five
years ended December 31, 2001. Significant producing property acquisitions in
each of the years presented, other than 2000, affect the comparability of
year-to-year financial and operating data. See Items 1 and 2, Business and
Properties, "Acquisitions." All weighted average shares and per share data have
been adjusted for the three-for-two stock splits effected in March 1997,
February 1998, September 2000 and June 2001. 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)
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
Consolidated Income Statement Data
Revenues:
Oil and condensate ......................... $ 116,939 $ 128,194 $ 86,604 $ 56,164 $ 75,223
Gas and natural gas liquids ................ 710,348 456,814 239,056 182,587 110,104
Gas gathering, processing and marketing .... 12,832 16,123 10,644 9,438 9,851
Other ...................................... (1,371) (280) 4,991 1,297 3,094
----------- ----------- ----------- ----------- -----------
Total Revenues ............................. $ 838,748 $ 600,851 $ 341,295 $ 249,486 $ 198,272
=========== =========== =========== =========== ===========
Earnings (loss) available to common stock .... $ 248,816(a) $ 115,235(b) $ 44,964(c) $(71,498) (d) $ 23,905
=========== =========== =========== =========== ===========
Per common share
Basic ...................................... $ 2.03(e) $ 1.08 $ 0.43 $ (0.73) $ 0.27
=========== =========== =========== =========== ===========
Diluted .................................... $ 2.00(e) $ 1.03 $ 0.42 $ (0.73) $ 0.26
=========== =========== =========== =========== ===========
Weighted average common shares outstanding .. 122,505 106,730 105,341 97,640 89,490
=========== =========== =========== =========== ===========
Dividends declared per common share .......... $ 0.0367 $ 0.0222 $ 0.0178 $ 0.0711 $ 0.0667
=========== =========== =========== =========== ===========
Consolidated Statement of Cash Flows Data
Cash provided (used) by:
Operating activities ....................... $ 542,615 $ 377,421 $ 133,301 $ (53,876) $ 95,918
Investing activities ....................... $ (610,923) $ (133,884) $ (156,370) $ (376,564) $ (309,234)
Financing activities ....................... $ 67,680 $ (241,833) $ 16,470 $ 438,957 $ 213,195
Consolidated Balance Sheet Data
Property and equipment, net .................. $ 1,841,387 $ 1,357,374 $ 1,339,080 $ 1,050,422 $ 723,836
Total assets ................................. $ 2,132,327 $ 1,591,904 $ 1,477,081 $ 1,207,005 $ 788,455
Long-term debt ............................... $ 856,000 $ 769,000 $ 991,100 $ 920,411 $ 539,000
Stockholders' equity ......................... $ 821,050 $ 497,367 $ 277,817 $ 201,474 $ 170,243
Operating Data
Average daily production:
Oil (Bbls) ................................. 13,637 12,941 14,006 12,598 10,905
Gas (Mcf) .................................. 416,927 343,871 288,000 229,717 135,855
Natural gas liquids (Bbls) ................. 4,385 4,430 3,631 3,347 220
Mcfe ....................................... 525,062 448,098 393,826 325,390 202,609
Average sales price:
Oil (per Bbl) .............................. $ 23.49 $ 27.07 $ 16.94 $ 12.21 $ 18.90
Gas (per Mcf) .............................. $ 4.51 $ 3.38 $ 2.13 $ 2.07 $ 2.20
Natural gas liquids (per Bbl) .............. $ 15.41 $ 19.61 $ 11.80 $ 7.62 $ 9.66
Production expense (per Mcfe) ................ $ 0.57 $ 0.53 $ 0.53 $ 0.53 $ 0.59
Taxes, transportation and other (per Mcfe) ... $ 0.33 $ 0.35 $ 0.23 $ 0.25 $ 0.22
Proved reserves:
Oil (Bbls) ................................. 54,049 58,445 61,603 54,510 47,854
Gas (Mcf) .................................. 2,235,478 1,769,683 1,545,623 1,209,224 815,775
Natural gas liquids (Bbls) ................. 20,299 22,012 17,902 17,174 13,810
Mcfe ....................................... 2,681,566 2,252,425 2,022,653 1,639,328 1,185,759
Other Data
Operating cash flow (f) ...................... $ 549,567 $ 344,638 $ 132,683 $ 78,480 $ 89,979
Ratio of earnings to fixed charges (g) ....... 7.7 2.8 1.9 --(h) 2.1
19
(a) Includes effect of pre-tax derivative fair value gain of $54.4 million,
pre-tax non-cash incentive compensation of $9.6 million and an after-tax
charge of $44.6 million for the cumulative effect of accounting change.
(b) 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.
(c) Includes effect of a $40.6 million pre-tax gain on sale of Hugoton Royalty
Trust units.
(d) 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.
(e) Before cumulative effect of accounting change, earnings per share were
$2.39 basic and $2.35 diluted.
(f) 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.
(g) 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 considered to be
representative of the interest factor and preferred stock dividends.
(h) Fixed charges exceeded earnings by $108.4 million. Excluding the effect of
items in (d) above, fixed charges exceeded earnings by $19 million.
20
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, 2001, 2000 and 1999, 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
September 18, 2000 and June 5, 2001. All common stock shares, treasury stock
shares and per share amounts have been retroactively restated to reflect all
stock splits.
2001 Acquisitions. During 2001, the Company acquired predominantly gas-producing
properties at a total cost of $242 million primarily funded by bank borrowings
and operating cash flow. The acquisitions include:
. Herd Acquisition. In January 2001, the Company acquired gas
properties in East Texas and Louisiana for $115 million from Herd
Producing Company, Inc.
. Miller Acquisition. In February 2001, the Company acquired gas
properties in East Texas for $45 million from Miller Energy, Inc.
and other owners.
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 Brothers Holdings, Inc. 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 acquired Lehman's 50% interest in Spring for $44.3 million.
The acquisition included 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 in March 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.
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 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 at a total gain of $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
21
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.
2001, 2000 and 1999 Development and Exploration Programs. Gas development
focused on the East Texas area and the Arkoma and San Juan basins during 2001,
and on the East Texas area and the Fontenelle Unit during 2000 and 1999. Oil
development was concentrated in Alaska during 2001 and in the University Block 9
Field during all three years. Exploration activity has been primarily geological
and geophysical analysis, including seismic studies, of undeveloped properties.
Exploratory expenditures were $5.4 million in 2001, $1 million in 2000 and
$900,000 in 1999. Exploration expense for 2001 includes dry hole expense of $2.2
million.
2002 Development and Exploration Program. The Company has budgeted $400 million
for its 2002 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 2002 budget. The cost of any
property acquisitions during 2002 may reduce the amount currently budgeted for
development and exploration. The total capital budget, including acquisitions,
will be adjusted throughout 2002 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, 2001:
. In November 2000, the Company sold 9.9 million shares of common
stock from treasury with net proceeds of approximately $126.1
million. The proceeds were used to reduce bank debt.
. In July 1999, the Company sold 4.5 million shares of common stock
from treasury with net proceeds of approximately $26.5 million. The
proceeds were used to repurchase 4.3 million shares of common stock
issued for a 1998 acquisition.
. In July 1999, the Company issued 9 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.
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 7.9 million shares at a cost of $41.4 million in 2000 and 11,000
shares at a cost of $53,000 in 1999. As of March 27, 2002, 6.5 million shares
remain under the May 2000 Board of Directors' authorization to purchase an
additional 6.8 million shares.
Conversion of Preferred Stock. In 2000 and 2001, all outstanding preferred stock
was converted into 5.5 million shares of common stock.
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 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 gain of $13.3 million in 2000 and a
loss of $1.1 million in 1999 related to this investment.
Hedging Activities. The Company enters futures contracts, collars and swap
agreements, as well as fixed price physical delivery contracts, to hedge against
unfavorable changes in product prices. During 2001, all hedging activities
increased gas revenue by $97 million. Hedging activities reduced gas revenue by
$40.5 million in 2000 and by $5.7 million in 1999, and reduced oil revenue by
$7.8 million in 2000 and by $2.2 million in 1999.
Cumulative Effect of Accounting Change for Derivatives. On January 1, 2001, the
Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133 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 accumulated other comprehensive income, which is an
element of stockholders' equity. The unrealized loss was related to the
derivative fair value of cash flow hedges. The charge to the income statement
was primarily related to the Company's gas physical delivery contract at crude
oil-based prices.
22
Derivative Fair Value Gain/Loss. The Company has recorded realized derivative
gains and losses in its income statements and unrealized derivative gains and
losses associated with cash flow hedges in accumulated other comprehensive
income. The Company recorded a $54.4 million gain in 2001 and a $55.8 million
loss in 2000 related to changes in fair value of non-hedge derivatives. The 2000
loss and $29.5 million of the 2001 gain are related to the change in fair value
of call options that the Company sold in 1999 as part of its hedging activities.
Because written call options do not provide protection against declining prices,
they do not qualify for hedge or loss deferral accounting. Most of the remaining
gain in 2001 is related to the change in fair value of a gas physical delivery
contract with crude oil-based pricing, the loss on which was initially recorded
in the cumulative effect of accounting change for derivatives.
At December 31, 2001, the Company has recorded a net unrealized gain of
$70.6 million (net of $38.1 million tax) in accumulated other comprehensive
income related to the fair value of derivatives designated as cash flow hedges.
The ultimate settlement value of these hedges will be recognized in the income
statement as gas revenue when the related production occurs through 2002. The
Company also has fixed price gas physical delivery contracts that are not
expected to be net cash settled, and therefore, their fair value of $36.4
million is not recorded in the financial statements. Revenues from these
contracts will be recognized as the commodity is delivered.
Enron Corporation Bankruptcy. As of December 2, 2001, the date of its bankruptcy
filing, Enron Corporation was the counterparty to some of the Company's hedge
derivative contracts, as well as purchaser of natural gas under certain physical
delivery contracts. One of these contracts was a natural gas physical delivery
contract with crude oil-based pricing, also referred to as the Enron Btu swap
contract. The Company terminated its contracts with Enron and has recorded a net
receivable of $21.3 million related to gas physical deliveries and hedge
derivative fair value at the contract termination dates. An additional $14.1
million is due from Enron for net unrealized gains related to undelivered gas
under physical delivery contracts, which has not been recorded in the Company's
financial statements. In accordance with termination provisions of the Enron Btu
swap contract, the Company believes that it no longer has a liability to Enron
under this contract. However, until this debt is legally extinguished, the $43.3
million fair value liability of this contract at the date of termination must
remain recorded in the Company's financial statements. In the event the
termination provisions of the Enron Btu swap contract are ultimately not
enforced, the Company believes that it should have the right to offset all
amounts due from Enron, including amounts related to undelivered gas under
physical delivery contracts, against any Enron Btu swap contract liability.
Because this liability exceeds net receivables from Enron, no reserve for asset
collectibility is anticipated to be necessary. The final resolution of the Enron
bankruptcy and related proceedings may result in a settlement materially
different from amounts recorded at December 31, 2001. See Note 7 to Consolidated
Financial Statements.
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. Incentive compensation totaled $9.6 million in
2001 and $26.1 million in 2000, which was primarily related to performance share
grants, as well as royalty trust option exercises in 2000. Incentive
compensation was not significant in 1999. As of December 31, 2001, there were
159,000 performance shares outstanding that vest when the common stock price
reaches $18.30, 242,000 performance shares outstanding that vest when the common
stock price reaches $21.67 and 13,500 performance shares that vest in increments
of 6,750 in each of 2002 and 2003. In February 2002, upon vesting of the
performance shares with the $18.30 common stock vesting price, an additional
159,000 performance shares were issued that vested when the stock price reached
$20.00 in March 2002.
Product Prices. In addition to supply and demand, oil and gas prices are
affected by seasonal, political and other conditions the Company generally
cannot control or predict.
Oil. Crude oil prices are generally determined by global supply and
demand. After OPEC members and other oil producers agreed to production cuts in
March 1999, oil prices climbed through the remainder of 1999 and first quarter
2000. Despite OPEC production increases in 2000, increased demand sustained
higher prices. The West Texas Intermediate ("WTI") posted price reached $34.25
per Bbl in September 2000, its highest level in ten years. Lagging demand in
2001, attributable to a worldwide economic slowdown, caused oil prices to
decline. OPEC members agreed to cut daily production by one million barrels in
April 2001 and an additional one million barrels in September 2001 to adjust for
weak demand and excess supply. The economic decline was accelerated by the
terrorist attacks in the United States on September 11, 2001, placing further
downward pressure on oil prices. In December, OPEC announced additional
production cuts of 1.5 million barrels per day effective January 1, 2002, for
six months. The Company uses commodity price hedging instruments to reduce its
exposure to oil price fluctuations. Excluding the effect of these
23
hedging instruments, the Company's average oil price was $28.72 in 2000 and
$17.37 in 1999. The Company did not hedge oil prices in 2001 and its average oil
price was $23.49. With economic recoveries in the U.S. and global markets, oil
prices have strengthened during 2002. At March 26, 2002, the average NYMEX oil
price for the following 12 months was $24.91 per Bbl. The Company estimates that
a $1.00 per barrel increase or decrease in the average oil sales price would
result in approximately a $4.6 million change in 2002 annual operating cash
flow.
Gas. Natural gas prices are dependent upon North American supply and
demand, which is affected by weather conditions. Natural gas competes with
alternative energy sources as a fuel for heating and the generation of
electricity. The 1999 average price was lower because of high levels of gas
remaining in storage from the abnormally warm winter of 1998-1999. Gas prices
began to increase in May 1999 and, after declining briefly at year end,
strengthened in 2000, reaching a record high of $10.10 per MMBtu in December
2000 as winter demand strained gas supplies. Gas prices declined during 2001
because of fuel switching due to higher prices, milder weather and a weaker
economy, which has reduced the demand for gas to generate electricity and
resulted in sharply increased gas storage levels. Despite the winter of
2001-2002 being one of the warmest on record and the likely result that storage
levels will be higher than historical averages at the end of the heating season,
gas prices have increased during 2002 and are expected to remain volatile. At
March 26, 2002, the average NYMEX gas price for the following 12 months was
$3.63 per MMBtu. The Company uses commodity price hedging instruments, including
fixed price delivery contracts, to reduce its exposure to gas price
fluctuations. Excluding the effect of these hedging instruments, the Company's
average gas price was $3.87 in 2001, $3.70 in 2000 and $2.18 in 1999. The
Company has hedges in place on approximately 95% of April through December 2002
projected production, including futures and fixed price contracts with an
average weighted NYMEX price of $3.71 for 67% of production, and collars that
provide an average weighted NYMEX floor price of $3.03 and ceiling price of
$3.62 for 28% of production. Including the effects of gains on closed futures
contracts, these collars provide a floor price of $3.31 and a ceiling price of
$3.90. After the effects of hedging, the Company estimates that a $0.10 per Mcf
increase or decrease in the average gas sales price would result in a $5.6
million change in 2002 annual operating cash flow, subject to floor and ceiling
prices provided by the collars.
The following summarizes the Company's April through December 2002 gas
hedging positions at March 27, 2002, as are further detailed in Note 8 to the
Consolidated Financial Statements. Prices to be realized for hedged production
may be less than these NYMEX prices because of location, quality and other
adjustments.
Collars
Futures and ----------------------------------------------------------
Physical Contracts Closed Adjusted Total
-------------------- NYMEX Price(b) Contract NYMEX Price(b)(d) Hedged
Mcf NYMEX Mcf -------------- Gain per ----------------- Mcf
2002 Production Period per Day Price(a) per Day Floor Ceiling Mcf(c) Floor Ceiling per Day
- ---------------------- ------- -------- ------- ----- ------- -------- ----- ------- -------
April 385,050 $3.66 75,000 $2.60 $3.20 $0.48 $3.08 $3.68 460,050
May 385,050 3.66 75,000 2.60 3.20 0.45 3.05 3.65 460,050
June 335,050 3.71 150,000 2.90 3.46 0.32 3.22 3.78 485,050
2nd Quarter Average 368,566 $3.68 99,725 $2.75 $3.33 $0.39 $3.14 $3.72 468,291
July 310,000 3.73 150,000 2.95 3.52 0.31 3.26 3.83 460,000
August 310,000 3.73 150,000 2.95 3.52 0.30 3.25 3.82 460,000
September 310,000 3.73 150,000 2.95 3.52 0.30 3.25 3.82 460,000
3rd Quarter Average 310,000 $3.73 150,000 $2.95 $3.52 $0.30 $3.25 $3.82 460,000
October 310,000 3.73 165,000 3.27 3.89 0.22 3.49 4.11 475,000
November 310,000 3.73 165,000 3.27 3.89 0.18 3.45 4.07 475,000
December 310,000 3.73 165,000 3.27 3.89 0.13 3.40 4.02 475,000
4th Quarter Average 310,000 $3.73 165,000 $3.27 $3.89 $0.18 $3.45 $4.07 475,000
Nine-Month Average 329,380 $3.71 138,382 $3.03 $3.62 $0.28 $3.31 $3.90 467,762
(a) Includes $0.05 per Mcf gain that will be deferred and recognized in 2003
related to contract terminations and hedge redesignations. Physical
contract prices have been converted from index to NYMEX price using
estimated delivery point basis.
(b) Includes $0.10 per Mcf reduction for cost of collars.
(c) Gain on closed futures contracts per Mcf of collars. Includes average
gains of $0.20 per Mcf on terminated Enron contracts.
(d) Includes gain on closed futures contracts per (c) above.
24
Impairment Provision. The Company regularly determines whether an impairment
provision is needed for producing properties 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. The Company has not
recorded impairment of producing properties since a $2 million provision was
recorded in 1998. If oil and gas prices significantly decline, the Company may
be required to record impairment provisions for producing properties in the
future, which could be material.
Results of Operations
2001 Compared to 2000
For the year 2001, earnings available to common stock were $248.8 million
compared with earnings of $115.2 million for 2000. Earnings for 2001 include a
$44.6 million after-tax charge for adoption of the new derivative accounting
principle, SFAS No. 133, an after-tax derivative fair value gain of $35.3
million and a $6.4 million after-tax charge for incentive compensation and loss
on sale of properties. 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 derivative fair value loss. Excluding these gains and losses
from asset sales, changes in derivative fair value and incentive compensation,
earnings for 2001 were $264.5 million, compared with $140.1 million for 2000.
Revenues for 2001 were $838.7 million, or 40% above 2000 revenues of
$600.9 million. Oil revenue decreased $11.3 million, or 9%, because of a 13%
decrease in oil prices from an average of $27.07 per Bbl in 2000 to $23.49 in
2001 (see "General - Product Prices - Oil" above), partially offset by a 5%
increase in oil production. Increased production was primarily because of the
2001 development program.
Gas and natural gas liquids revenue increased $253.5 million, or 56%,
because of a 21% increase in gas production and a 33% increase in gas prices
from an average of $3.38 per Mcf in 2000 to $4.51 in 2001 (see "General -
Product Prices - Gas" above). These increases were partially offset by a 1%
decrease in natural gas liquids production and a 21% decrease in natural gas
liquids prices from an average price of $19.61 per Bbl in 2000 to $15.41 in
2001. Increased gas production was attributable to the 2001 development program.
Decreased gas liquids production was primarily because higher gas prices in
first quarter 2001 made ethane extraction uneconomical at some gas plants.
Gas gathering, processing and marketing revenues decreased $3.3 million
primarily because of decreased processing margins. Other revenues declined $1.1
million primarily because of decreased gains on sale of properties.
Expenses for 2001 totaled $327.8 million as compared with total 2000
expenses of $388.7 million. Excluding derivative fair value (gain) loss,
expenses for 2001 totaled $382.2 million, or 15% above total expenses of $332.9
for 2000. Most expenses increased in 2001 because of acquisitions and
development and related increased production.
Production expense increased $23 million, or 26%, because of increased
production, as well as higher maintenance, overhead, fuel, pumper and workover
expense. Production expense per Mcfe increased $0.04. The Company's 2001
exploration expense was $5.4 million compared with $1 million for 2000 because
of dry hole costs of $2.2 million and increased geological and geophysical
costs.
Taxes, transportation and other deductions increased 12%, or $7 million,
primarily because of increased oil and gas revenues. Taxes, transportation and
other per Mcfe decreased 6% from $0.35 to $0.33 primarily because of lower
severance tax rates on new wells in East Texas.
Depreciation, depletion and amortization ("DD&A") increased $24.5 million,
or 19%, primarily because of increased production and higher acquisition and
drilling costs. On an Mcfe basis, DD&A increased slightly from $0.79 in 2000 to
$0.81 in 2001.
General and administrative expense decreased $10.2 million, or 21%,
because of decreased incentive compensation of $16.5 million which was offset by
increased expenses from Company growth. Excluding incentive compensation,
general and administrative expense per Mcfe increased from $0.14 in 2000 to
$0.15 in 2001.
25
The derivative fair value gain of $54.4 million in 2001 primarily reflects
the effect of decreased natural gas prices during the year on the fair value of
outstanding call options and a gas physical delivery contract with crude
oil-based pricing. The derivative fair value loss of $55.8 million in 2000
reflects the effect of increased prices during the period on the fair value of
call options. These derivatives do not qualify for hedge accounting. See Note 6
to Consolidated Financial Statements.
Interest expense decreased $23.3 million, or 30%, primarily because of a
19% decrease in the weighted average interest rate, an 11% decrease in weighted
average borrowings and increased capitalized interest. Interest expense per Mcfe
decreased 40% from $0.48 in 2000 to $0.29 in 2001.
2000 Compared to 1999
For the year 2000, earnings available to common stock were $115.2 million
compared with earnings 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 million 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, changes in derivative fair value 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 - Oil" 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 - Gas" 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 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 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.
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.
26
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.
Liquidity and Capital Resources
The Company's primary sources of liquidity are cash flow from operating
activities, borrowings against the revolving credit facility, occasional
producing property sales (including sales of royalty trust units) and public
offerings of equity and 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 2002.
Cash provided by operating activities was $542.6 million in 2001, compared
with cash provided by operating activities of $377.4 million in 2000 and $133.3
million in 1999. Increased operating cash flow during this three-year period was
primarily because of increased prices and production from acquisitions and
development activity. Before changes in operating assets and liabilities and
exploration expense, cash flow from operations was $549.6 million in 2001,
$344.6 million in 2000 and $132.7 million in 1999. Operating cash flow is
largely dependent upon the prices received for oil and gas production. The
Company has hedged approximately 95% of its projected April through December
2002 gas production, including futures and fixed price contracts that hedge 67%
of production and collars that hedge 28% of production. See "Product Prices"
under "General" above.
The Company does not have any transactions, arrangements or other
relationships with unconsolidated entities or persons that could materially
affect its liquidity or the availability of capital resources.
Financial Condition
Total assets increased 34% from $1.6 billion at December 31, 2000 to $2.1
billion at December 31, 2001, primarily because of Company growth related to
acquisitions and development. As of December 31, 2001, total capitalization was
$1.7 billion, of which 51% was long-term debt. Capitalization at December 31,
2000 was $1.3 billion of which 61% was long-term debt. The decrease in the
debt-to-capitalization ratio from year-end 2000 to 2001 is primarily because of
increased earnings and accumulated other comprehensive income which is related
to the unrealized fair value gain on hedge derivatives.
Working Capital
The Company generally maintains low cash and cash equivalent balances
because it uses available funds to reduce bank debt. 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 increase from negative working capital of $25.3 million at December
31, 2000 to working capital of $37.5 million at December 31, 2001 was primarily
attributable to the derivative fair value asset, net of deferred income taxes,
recorded during 2001 related to adoption of SFAS No. 133, the new derivative
accounting principle.
Financing
On December 31, 2001, borrowings under the revolving credit agreement with
commercial banks were $556 million with unused borrowing capacity of $244
million. The interest rate of 3.45% at December 31, 2001 is based on the
one-month London Interbank Offered Rate plus 1.375%. Based on the value of the
Company's reserves, the borrowing base increased to $1.2 billion effective June
30, 2001. The bank's total commitment, however, remains at $800 million,
resulting in no increase to the Company's borrowing capacity. The borrowing base
is redetermined annually based on the value and expected cash flow of the
Company's proved oil and gas reserves. If borrowings exceed the redetermined
borrowing base, the banks may require that the excess be repaid within a year.
Based on reserve values at December 31, 2001 and using parameters specified by
the banks, the borrowing base remains in excess of the $800 million commitment.
Borrowings under the loan agreement are due May 12, 2005, but may be prepaid at
27
any time without penalty. The Company may renegotiate the loan agreement to
increase borrowing capacity 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. In May 2001, the
loan agreement was amended to allow the Company to issue senior debt.
The 1999 acquisitions were partially funded by the sale and issuance of
common stock, cash flow from operations and contributions from Lehman, the
Company's equity partner until it later purchased Lehman's interest in these
acquisitions. These transactions are described under "General" above. See also
"Capital Expenditures" below.
In October 2001, the Company filed a shelf registration statement with the
Securities and Exchange 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 total price of securities
to be offered is $600 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. As of March 2002,
no securities have been issued under the shelf registration.
Capital Expenditures
In 2001, exploration and development cash expenditures totaled $386.5
million compared with $155.4 million in 2000. The Company has budgeted $400
million for the 2002 development and exploration program. As it has done
historically, the Company expects to fund the 2002 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.
Because of their size, the 1999 acquisitions were made jointly with Lehman
as a 50% equity partner. The Company acquired Lehman's interest in the Spring
Holding Acquisition in September 1999. The Company purchased Lehman's interest
in the Ocean Energy Acquisition in March 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 2000, the Board of Directors authorized the repurchase of a total of
12.4 million shares of the Company's common stock. During 2000, the Company
repurchased 7.9 million shares of its common stock at a cost of $41.4 million,
including 2 million shares repurchased under a 1998 Board authorization. No
shares were repurchased in 2001. As of March 27, 2002, 6.5 million shares are
available for repurchase.
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
2002. However, new regulations, enforcement policies, claims for damages or
other events could result in significant future costs.
Dividends
The Board of Directors declared quarterly dividends of $0.0045 per common
share from 1999 through second quarter 2000, $0.0067 per common share for third
quarter 2000 through first quarter 2001 and $0.01 per common share for the
remainder of 2001. The Company's ability to pay dividends is dependent upon
available cash flow, as well as other factors. In addition, the Company's bank
loan agreement restricts the amount of common stock dividends and treasury stock
repurchases to 25% of cash flow from operations, as defined, for the last four
quarters.
28
Contractual Obligations and Commitments
The following summarizes the Company's significant obligations and
commitments to make future contractual payments as of December 31, 2001. The
Company has not guaranteed the debt of any other party, nor does the Company
have any other arrangements or relationships with other entities that could
potentially result in unconsolidated debt.
Long-Term Debt. Borrowings under the Company's senior bank revolving credit
facility were $556 million at December 31, 2001. Bank debt is not due until May
2005, but may be prepaid at any date. The Company may renegotiate its bank debt
to increase borrowing capacity and extend its maturity. Subordinated debt
totaled $300 million at December 31, 2001. Of that amount, $125 million is due
in April 2007 and $175 million is due in November 2009. Subordinated debt may be
redeemed at a price of approximately 105% in 2002. For further information
regarding long-term debt, see Note 3 to Consolidated Financial Statements.
Operating Leases. The Company's minimum lease payment commitments under
noncancelable lease agreements totaled $90 million at December 31, 2001.
Estimated annual payments under these lease agreements for the next five years
are disclosed in Note 5 to Consolidated Financial Statements. Estimated annual
payments total $15.5 million for 2002 and decline for subsequent years.
Drilling Contracts. The Company has minimum drilling rig use payments of $9.5
million in 2002 and $1 million in 2003. These costs are part of the Company's
budgeted capital expenditures of $400 million for 2002.
Derivative Hedge Contracts. The Company has entered into futures contracts and
swaps to hedge its exposure to natural gas price fluctuations. Because the
contractual fixed price generally exceeds the current market gas price, the
Company expects to receive payments from counterparties under most of these
contracts. If market gas prices increase, the Company could be required to make
payments under these contracts, which would be funded by the higher price
received from the sale of Company gas production. See Note 6 to Consolidated
Financial Statements.
For further information regarding commitments, see Note 5 to Consolidated
Financial Statements.
Related Party Transactions
The Company has limited related party transactions, as further disclosed
in Note 2 to Consolidated Financial Statements. During 1998 and 1999, the
Company loaned five of its officers $7.3 million pursuant to full recourse
promissory notes to pay margin debt in broker accounts in which the officers
held Company common stock. In May 2001, officers sold 302,000 shares of common
stock to the Company for $6.5 million and used the proceeds to partially repay
their loans. These loans were fully repaid in 2001. The interest rate charged on
these loans was equal to the Company's bank debt rate.
A company, partially owned by one of the Company's directors, performs
acquisition and divestiture consulting for the Company. This director-related
company received consulting fees of $994,000 in 2000. It also represented the
purchaser of properties sold by the Company during 1999, and also invested in
the purchase. This director-related company also performed consulting services
in connection with a 1998 producing property acquisition and was entitled to
receive, at its election, either a 20% working interest or a 1% overriding
royalty interest conveyed from the Company's 100% working interest in the
properties after payout of acquisition and operating costs. The Company acquired
this potential interest from the director-related company and other parties in
2001 for a price of $15 million, pursuant to an independent fairness opinion.
The director-related company received $10 million of the purchase price.
Critical Accounting Policies
The Company's financial position and results of operations are
significantly affected by accounting policies and estimates related to its oil
and gas properties, proved reserves, and commodity prices and risk management,
as summarized below.
29
Oil and Gas Property Accounting
Oil and gas exploration and production companies may elect to account for
their property costs using either the "successful efforts" or "full cost"
accounting method. Under the successful efforts method, unsuccessful exploratory
well costs, as well as all exploratory geological and geophysical costs, are
expensed. Under the full cost method, all exploration costs are capitalized,
regardless of success. Selection of the oil and gas accounting method can have a
significant impact on a company's financial results. The Company, which
generally pursues acquisition and development of proved reserves as opposed to
exploration activities, follows the successful efforts method of accounting.
Property costs must be expensed through an impairment provision if in
excess of the estimated future cash flows of proved reserves. The Company
evaluates possible impairment of producing properties when conditions indicate
that they may be impaired. Cash flow pricing estimates are based on existing
proved reserve and production information and pricing assumptions that
management believes are reasonable. Individually significant undeveloped
properties are reviewed for impairment on a property-by-property basis, and
impairment of other undeveloped properties is done on a total basis. The
Company's impairment of producing properties has been limited to a $2 million
provision recorded in 1998. By comparison, full cost companies must generally
record higher impairment provisions under a "ceiling test" which is computed
using discounted estimated future after-tax cash flows based on current market
prices.
Oil and Gas Reserves
The Company's proved oil and gas reserves are estimated by independent
petroleum engineers. Reserve engineering is a subjective process that is
dependent upon the quality of available data and the interpretation thereof.
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 changes in product prices, may justify revision of such estimates.
Because proved reserves are required to be estimated using prices at the date of
the evaluation, estimated reserve quantities can be significantly impacted by
changes in product prices. Accordingly, oil and gas quantities ultimately
recovered and the timing of production may be substantially different from
original estimates.
Depreciation, depletion and amortization of producing properties is
computed on the unit-of-production method based on estimated proved oil and gas
reserves. If estimated proved reserves decline, future DD&A expense will
increase and net income will be reduced. A decline in proved reserves also can
result in a required impairment provision, as discussed under "Oil and Gas
Property Accounting" above.
The standardized measure of discounted future net cash flows and changes
in such cash flows, as reported in Note 15 to Consolidated Financial Statements,
are prepared using assumptions required by the Financial Accounting Standards
Board and the Securities and Exchange Commission. Such assumptions include using
year-end oil and gas prices and year-end costs for estimated future development
and production expenditures. Discounted future net cash flows are calculated
using a 10% rate. Changes in any of these assumptions could have a significant
impact on the standardized measure. Accordingly, the standardized measure does
not represent management's estimated current market value of proved reserves.
Commodity Prices and Risk Management
Commodity prices significantly affect the Company's operating results,
financial condition, cash flows and ability to borrow funds. Current market oil
and gas prices are affected by supply and demand as well as seasonal, political
and other conditions which the Company generally cannot control. Oil and gas
prices and markets are expected to continue their historical volatility. See
"General- Product Prices" above.
The Company attempts to reduce its price risk by entering into financial
instruments such as gas futures contracts, collars and swap agreements, as well
as fixed priced physical delivery contracts. While these instruments guarantee a
certain price and, therefore, a certain cash flow, there is the risk that the
Company will not be able to realize the benefit of rising prices. These
contracts also expose the Company to credit risk of non-performance by the
contract counterparties, which the Company attempts to limit by obtaining
letters of credit or other appropriate security. The Company also has sold call
options as part of its hedging program. Call options, however, do not provide a
hedge
30
against declining prices and there is the risk that the call sales
proceeds will be less than the benefit a higher sales price would have provided.
During 2001, the Company's commodity price hedging activities resulted in
a $0.64 per Mcf increase in the average gas price. During 2000, the Company's
commodity price hedging activities resulted in a $0.32 per Mcf reduction in the
average gas price and a $1.65 per Bbl reduction in the average oil price. Based
on cash flow hedges and physical delivery contracts in place at March 27, 2002,
the Company estimates that it has hedged approximately 95% of its April through
December 2002 projected production, including futures and fixed price contracts
that hedge 67% of production, and collars that hedge 28% of production.
While the Company's price risk management activities decrease the
volatility of cash flows, they may obscure the Company's operating results and
financial condition. As required under generally accepted accounting principles,
the Company adopted SFAS No. 133 on January 1, 2001 with a significant charge to
its income statement and equity related to recording derivative financial
instruments at their market value. Subsequent to that date, the Company recorded
significant derivative fair value gains in the income statement and equity
related to decline in natural gas prices. During 2000, the Company recorded a
significant loss related to the fair value of call options. In each instance,
these are projected gains and losses that will be realized upon settlement of
these contracts in future periods when related production occurs. These gains
and losses are offset by increases and decreases in the market value of the
Company's proved reserves, which are not reflected in the financial statements.
Also, a significant portion of the Company's gas price hedging is provided by
fixed price physical delivery contracts which had a fair value of $36.4 million
at December 31, 2001. This asset is not recorded in the Company's financial
statements since the contracts are deemed to be normal sales that are not
expected to be net cash settled, and therefore are not derivatives. Derivatives
that provide effective cash flow hedges are designated as hedges and the Company
defers related fair value gains and losses in accumulated other comprehensive
income until the hedged transaction occurs. Because hedge accounting is not
required under generally accepted accounting principles, the Company's operating
results as reflected in its financial statements may not be comparable to other
companies.
See Item 7A, "Commodity Price Risk" for the effect of price changes on
derivative fair value gains and losses.
Accounting Pronouncements
During 2001, the Financial Accounting Standards Board issued the following
Statements of Financial Accounting Standards:
. SFAS No. 141, Business Combinations, requires the use of the
purchase method of accounting, as opposed to the
pooling-of-interests method, for all business combinations initiated
or completed after June 30, 2001. It supersedes APB Opinion No. 16,
Business Combinations, and SFAS No. 38, Accounting for
Preacquisition Contingencies of Purchased Enterprises. The adoption
of SFAS No. 141 should have no material affect on the Company's
financial statements since it has historically used the purchase
method of accounting to record business combinations.
. SFAS No. 142, Goodwill and Other Intangible Assets, changes the
method of accounting for acquired goodwill and other tangible
assets, and supersedes APB Opinion No. 17, Intangible Assets.
Goodwill and intangible assets with indefinite lives will no longer
be amortized and will be tested at least annually for impairment.
The provisions of SFAS No. 142 are required to be applied to fiscal
years beginning after December 15, 2001 and should not have a
material effect on the Company's financial statements.
. SFAS No. 143, Accounting for Asset Retirement Obligations, amends
SFAS No. 19, Financial Accounting and Reporting by Oil and Gas
Producing Companies, and addresses financial accounting and
reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. It
requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a
reasonable estimate of fair value can be made. The associated asset
retirement costs are capitalized as part of the cost of the
long-lived asset. The statement is required to be adopted for fiscal
years beginning after June 15, 2002. The effect of the Company's
adoption of SFAS No. 143 has not been determined but is currently
not expected to be material.
31
. SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, supersedes SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed of. With this pronouncement, the FASB establishes a single
accounting model for long-lived assets to be disposed of by sale,
including the reporting of discontinued operations. The statement is
required to be adopted for fiscal years beginning after December 15,
2001. The effect of the Company's adoption of SFAS No. 144 has not
been determined but is currently not expected to be material.
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. Accordingly, revenue is deferred for
gas deliveries in excess of the Company's net revenue interest, while revenue is
accrued for the undelivered volumes. Production imbalances are generally
recorded at the estimated sales price in effect at the time of production. The
consolidated balance sheets include the following amounts related to production
imbalances:
December 31
-----------------------------------------
(in thousands) 2001 2000
------------------- -------------------
Amount Mcf Amount Mcf
-------- -------- -------- --------
Accounts receivable - current underproduction ............... $ 13,497 5,079 $ 11,185 4,854
Accounts payable - current overproduction ................... (13,064) (4,871) (8,720) (3,943)
-------- -------- -------- --------
Net current gas underproduction balancing receivable ... $ 433 208 $ 2,465 911
======== ======== ======== ========
Other assets - noncurrent underproduction ................... $ 15,763 6,018 $ 11,208 5,133
Other long-term liability - noncurrent overproduction ....... (21,871) (8,164) (19,216) (8,714)
-------- -------- -------- --------
Net long-term gas overproduction balancing payable ..... (6,108) (2,146) (8,008) (3,581)
======== ========
Other assets - noncurrent carbon dioxide underproduction .... 4,165 11,256 4,327 10,062
-------- ======== -------- ========
Net long-term overproduction balancing payable ......... $ (1,943) $ (3,681)
======== ========
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,
32
. 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 and natural gas prices and related financial
derivatives,
. basis risk and counterparty credit risk in executing commodity price
risk management activities,
. potential liability resulting from pending or future litigation, and
. 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, collars, swaps and option agreements.
These financial and commodity-based derivative contracts are used to limit the
risks of fluctuations in interest rates and natural gas and crude oil prices.
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.
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, 2001, the Company's
variable rate debt had a carrying value of $556 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 $314.7 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. Unless otherwise
noted, the hypothetical change in fair value could be a gain or a loss depending
on whether interest rates increase or decrease.
33
Hypothetical
Carrying Fair Change in
(in thousands) Amount Value Fair Value
---------- ---------- -----------
December 31, 2001
Long-term debt ..................... $ (856,000) $ (870,720) $ 14,874 (a)
Interest rate swaps ................ 2,791 2,791 (809)(a)
December 31, 2000
Long-term debt ..................... $ (769,000) $ (774,000) $ 16,389
Interest rate swaps ................ 473 2,651 1,484
(a) This is approximate gain in fair value of long-term debt and loss in fair
value of interest rate swaps from a 100-basis point increase in interest
rates. Because of the limitation in value caused by the 2002 call price of
the Company's fixed rate debt, a 100-basis point decrease in interest
rates would not significantly affect fair value at December 31, 2001.
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, 2001, the Company had outstanding
gas futures contracts, swap agreements and gas basis swap agreements. These
contracts and agreements had a net fair value gain of approximately $97.6
million at December 31, 2001 and a net fair value loss of $108.9 million at
December 31, 2000. Of the December 31, 2001 fair value, a $98.4 million gain has
been determined based on the exchange-trade value of NYMEX contracts and an
$800,000 loss has been determined based on the broker bid and ask quotes for
basis contracts. These fair values approximate amounts confirmed by the
counterparties.
The aggregate effect of a hypothetical 10% change in gas prices would
result in a change of approximately $27.8 million in the fair value of gas
futures contracts and swap agreements at December 31, 2001. This sensitivity
does not include physical product delivery contracts, which are not expected to
be settled in cash or another financial instrument; these contracts had a fair
value gain of $36.4 million at December 31, 2001. See Note 8 to Consolidated
Financial Statements.
Because these futures contracts and swap agreements are designated hedge
derivatives, changes in their fair value are reported as a component of
accumulated other comprehensive income until the related sale of production
occurs. At that time, the realized hedge derivative gain or loss is transferred
to product revenues in the consolidated income statement.
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 $44.2 million at December 31, 2000. All
call options were settled in 2001 with payments to the counterparties totaling
$14.7 million, resulting in a 2001 derivative fair value gain of $29.5 million.
The Company had 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 was priced based on crude oil, which is not clearly and closely
associated with natural gas prices, it was accounted for as a non-hedge
derivative financial instrument under SFAS No. 133 beginning January 1, 2001.
This contract (referred to as the Enron Btu swap contract) was terminated in
December 2001 in conjunction with the bankruptcy filing of Enron Corporation,
and as a result, the Company believes that its liability under this contract was
reduced to zero. A $43.3 million current liability will remain on the Company's
consolidated balance sheet until this contractual liability is legally
extinguished. See Note 7 to Consolidated Financial Statements and "General -
Enron Corporation Bankruptcy" above.
In November 2001, the Company entered derivative contracts to effectively
defer until 2005 and 2006 any cash flow impact related to 25,000 Mcf of daily
gas deliveries in 2002 that were to be made under the Enron Btu swap contract.
The net fair value loss on these contracts at December 31, 2001 was $4.1
million. Of this fair value, a $6.1 million gain has been determined based on
the exchange-trade value of NYMEX contracts and a $10.2 million loss has
34
been based on Company estimated oil prices for periods beyond 2004 for which
there are not readily available exchange-trade values. These values approximate
amounts confirmed by the counterparty. The effect of a hypothetical 10% change
in gas prices would result in a change of approximately $350,000 in the fair
value of these contracts, while a 10% change in crude oil prices would result in
a change of approximately $150,000. In March 2002, the Company terminated
contracts with maturities of May through December 2002 and received $6.6 million
from the counterparty. Because these contracts are non-hedge derivatives, most
of the related $6.6 million gain related to their termination was recorded in
2001 derivative fair value gain.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following financial statements and supplementary information are
included under Item 14(a):
Page
----
Consolidated Balance Sheets ............................................... 37
Consolidated Income Statements ............................................ 38
Consolidated Statements of Cash Flows ..................................... 39
Consolidated Statements of Stockholders' Equity ........................... 40
Notes to Consolidated Financial Statements ................................ 41
Selected Quarterly Financial Data
(Note 14 to Consolidated Financial Statements) .......................... 65
Information about Oil and Gas Producing Activities
(Note 15 to Consolidated Financial Statements) .......................... 66
Report of Independent Public Accountants .................................. 69
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Item 11. EXECUTIVE COMPENSATION
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Except for the portion of Item 10 relating to Executive Officers of the
Registrant which is included in Part I of this Report, the information called
for by Items 10 through 13 is incorporated by reference from the Company's
Notice of Annual Meeting and Proxy Statement to be filed with the Securities and
Exchange Commission no later than April 30, 2002.
35
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, 2001 and 2000... 37
Consolidated Income Statements for the years ended
December 31, 2001, 2000 and 1999.......................... 38
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999.......................... 39
Consolidated Statements of Stockholders' Equity for the
years ended December 31, 2001, 2000 and 1999.............. 40
Notes to Consolidated Financial Statements.................. 41
Report of Independent Public Accountants.................... 69
2. Financial Statement Schedules:
Schedule II - Consolidated Valuation and Qualifying Accounts
All other 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, 2001 and through March 30, 2002:
On December 6, 2001, the Company filed a report on Form 8-K to
disclose that its gas production growth projections and
financial performance should not be materially affected by
transactions with Enron Corporation and its affiliates.
On December 19, 2001, the Company filed a report on Form 8-K
to announce that its Board of Directors approved a $400
million exploration and development budget for 2002 that
targets a 20% growth in total gas production over 2001 levels.
(c) Exhibits
See Index to Exhibits at page 72 for a description of the exhibits
filed as a part of this report. Documents filed prior to June 1, 2001, were
filed with the Securities and Exchange Commission under the Company's prior
name, Cross Timbers Oil Company.
36
XTO ENERGY INC.
Consolidated Balance Sheets
- --------------------------------------------------------------------------------
(in thousands, except shares) December 31
-------------------------
2001 2000
----------- -----------
ASSETS
Current Assets:
Cash and cash equivalents ................................................ $ 6,810 $ 7,438
Accounts receivable, net ................................................. 111,101 158,826
Derivative fair value .................................................... 107,526 106
Deferred income tax benefit .............................................. -- 17,098
Other current assets ..................................................... 13,930 9,969
----------- -----------
Total Current Assets ................................................. 239,367 193,437
----------- -----------
Property and Equipment, at cost - successful efforts method:
Producing properties ..................................................... 2,352,473 1,732,017
Undeveloped properties ................................................... 9,545 6,460
Other .................................................................... 50,645 38,340
----------- -----------
Total Property and Equipment ........................................... 2,412,663 1,776,817
Accumulated depreciation, depletion and amortization ..................... (571,276) (419,443)
----------- -----------
Net Property and Equipment ............................................. 1,841,387 1,357,374
----------- -----------
Other Assets:
Derivative fair value .................................................... 18,174 367
Loans to officers ........................................................ -- 8,214
Other .................................................................... 33,399 32,512
----------- -----------
Total Other Assets ..................................................... 51,573 41,093
----------- -----------
TOTAL ASSETS ................................................................ $ 2,132,327 $ 1,591,904
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities ................................. $ 125,486 $ 153,581
Payable to royalty trusts ................................................ 2,233 8,577
Derivative fair value .................................................... 1,024 44,189
Enron Btu swap contract .................................................. 43,272 --
Current income taxes payable ............................................. 600 --
Deferred income taxes payable ............................................ 27,330 --
Other current liabilities ................................................ 1,898 12,404
----------- -----------
Total Current Liabilities ............................................ 201,843 218,751
----------- -----------
Long-term Debt .............................................................. 856,000 769,000
----------- -----------
Other Long-term Liabilities:
Derivative fair value .................................................... 28,331 --
Deferred income taxes payable ............................................ 199,091 82,476
Other long-term liabilities .............................................. 26,012 24,310
----------- -----------
Total Other Long-term Liabilities ...................................... 253,434 106,786
----------- -----------
Commitments and Contingencies (Note 5)
Stockholders' Equity:
Series A convertible preferred stock ($.01 par value, 25,000,000
shares authorized, -0- and 1,088,663 issued at liquidation value of $25) -- 27,217
Common stock ($.01 par value, 250,000,000 shares authorized,
131,988,733 and 123,880,245 shares issued) ............................. 1,320 1,239
Additional paid-in capital ............................................... 485,094 435,322
Treasury stock (8,215,998 and 7,546,560 shares) .......................... (64,714) (50,829)
Retained earnings ........................................................ 328,712 84,418
Accumulated other comprehensive income ................................... 70,638 --
----------- -----------
Total Stockholders' Equity ........................................... 821,050 497,367
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .................................. $ 2,132,327 $ 1,591,904
=========== ===========
See accompanying notes to consolidated financial statements.
37
XTO ENERGY INC.
Consolidated Income Statements
- -------------------------------------------------------------------------------
(in thousands, except per share data) Year Ended December 31
------------------------------------
2001 2000 1999
---------- ---------- ----------
REVENUES
Oil and condensate ............................................. $ 116,939 $ 128,194 $ 86,604
Gas and natural gas liquids .................................... 710,348 456,814 239,056
Gas gathering, processing and marketing ........................ 12,832 16,123 10,644
Other .......................................................... (1,371) (280) 4,991
---------- ---------- ----------
Total Revenues ............................................... 838,748 600,851 341,295
---------- ---------- ----------
EXPENSES
Production ..................................................... 110,005 86,988 76,110
Taxes, transportation and other ................................ 63,656 56,696 33,681
Exploration .................................................... 5,438 1,047 904
Depreciation, depletion and amortization ....................... 154,322 129,807 112,364
Gas gathering and processing ................................... 9,522 8,930 8,743
General and administrative ..................................... 39,217 49,460 14,091
Derivative fair value (gain) loss .............................. (54,370) 55,821 --
---------- ---------- ----------
Total Expenses ............................................... 327,790 388,749 245,893
---------- ---------- ----------
OPERATING INCOME .................................................. 510,958 212,102 95,402
---------- ---------- ----------
OTHER INCOME (EXPENSE)
Gain on significant property divestitures ...................... -- 29,965 40,566
Gain (loss) on investment in equity securities ................. -- 13,279 (1,149)
Interest expense, net .......................................... (55,601) (78,914) (64,214)
---------- ---------- ----------
Total Other Income (Expense) ................................. (55,601) (35,670) (24,797)
---------- ---------- ----------
INCOME BEFORE INCOME TAX, MINORITY INTEREST
AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE ..................... 455,357 176,432 70,605
Income Tax Expense ................................................ 161,952 59,380 23,965
Minority Interest in Net (Income) Loss of Consolidated Subsidiaries -- (59) 103
---------- ---------- ----------
NET INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE .............................................. 293,405 116,993 46,743
Cumulative effect of accounting change, net of tax ............. (44,589) -- --
---------- ---------- ----------
NET INCOME ........................................................ 248,816 116,993 46,743
Preferred stock dividends ......................................... -- 1,758 1,779
---------- ---------- ----------
EARNINGS AVAILABLE TO COMMON STOCK ................................ $ 248,816 $ 115,235 $ 44,964
========== ========== ==========
EARNINGS PER COMMON SHARE
Basic:
Net income before cumulative effect of accounting change ..... $ 2.39 $ 1.08 $ 0.43
Cumulative effect of accounting change ....................... (0.36) -- --
---------- ---------- ----------
Earnings available to common stock ........................... $ 2.03 $ 1.08 $ 0.43
========== ========== ==========
Diluted:
Net income before cumulative effect of accounting change ..... $ 2.35 $ 1.03 $ 0.42
Cumulative effect of accounting change ....................... (0.35) -- --
---------- ---------- ----------
Earnings available to common stock ........................... $ 2.00 $ 1.03 $ 0.42
========== ========== ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING ........................ 122,505 106,730 105,341
========== ========== ==========
See accompanying notes to consolidated financial statements.
38
XTO ENERGY INC.
Consolidated Statements of Cash Flows
- --------------------------------------------------------------------------------
(in thousands) Year Ended December 31
------------------------------------
2001 2000 1999
---------- ---------- ----------
OPERATING ACTIVITIES
Net income ............................................................... $ 248,816 $ 116,993 $ 46,743
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization ................................. 154,322 129,807 112,364
Non-cash incentive compensation .......................................... 9,246 25,790 93
Deferred income tax ...................................................... 161,105 58,993 23,657
(Gain) loss on investment in equity securities and from sale of properties 277 (45,578) (51,802)
Non-cash (gain) loss in derivative fair value ............................ (69,147) 54,512 --
Minority interest in net income (loss) of consolidated subsidiaries ...... -- 59 (103)
Cumulative effect of accounting change, net of tax ....................... 44,589 -- --
Other non-cash items ..................................................... (5,079) 3,015 827
Changes in operating assets and liabilities (a) .......................... (1,514) 33,830 1,522
---------- ---------- ----------
Cash Provided by Operating Activities ................................. 542,615 377,421 133,301
---------- ---------- ----------
INVESTING ACTIVITIES
Proceeds from sale of Hugoton Royalty Trust units ........................ -- -- 148,570
Proceeds from sale of other property and equipment ....................... 319 77,119 110,500
Property acquisitions .................................................... (224,906) (45,648) (270,226)
Purchase of Spring Holding Company ....................................... -- -- (42,540)
Development costs ........................................................ (381,026) (154,382) (90,725)
Other property additions ................................................. (13,438) (11,033) (10,479)
(Loans to) repayments from officers ...................................... 8,128 60 (1,470)
---------- ---------- ----------
Cash Used by Investing Activities ..................................... (610,923) (133,884) (156,370)
---------- ---------- ----------
FINANCING ACTIVITIES
Proceeds from short- and long-term debt .................................. 640,000 523,400 256,400
Payments on short- and long-term debt .................................... (553,000) (745,500) (339,262)
Dividends ................................................................ (4,413) (3,891) (4,950)
Purchase of minority interest ............................................ -- (100,071) (42,385)
Contributions from minority interests .................................... -- -- 142,500
Common stock offering .................................................... -- 126,125 29,668
Purchases of treasury stock and other .................................... (14,907) (41,896) (25,501)
---------- ---------- ----------
Cash Provided (Used) by Financing Activities .......................... 67,680 (241,833) 16,470
---------- ---------- ----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ............................ (628) 1,704 (6,599)
Cash and Cash Equivalents, January 1 ........................................ 7,438 5,734 12,333
---------- ---------- ----------
Cash and Cash Equivalents, December 31 ...................................... $ 6,810 $ 7,438 $ 5,734
========== ========== ==========
(a) Changes in Operating Assets and Liabilities
Accounts receivable ................................................... $ 58,706 $ (90,921) $ (8,227)
Investment in equity securities ....................................... -- 43,746 20,180
Other current assets .................................................. (3,855) (4,535) (32)
Other assets .......................................................... (1,738) (15,535) --
Current liabilities ................................................... (54,627) 82,392 (11,628)
Other long-term liabilities ........................................... -- 18,683 1,229
---------- ---------- ----------
$ (1,514) $ 33,830 $ 1,522
=========== ========== ==========
See accompanying notes to consolidated financial statements.
39
XTO ENERGY INC.
Consolidated Statements of Stockholders' Equity
- --------------------------------------------------------------------------------
(in thousands, except per share amounts)
Accumulated
Additional Retained Other
Preferred Common Paid-in Treasury Earnings Comprehensive
Stock Stock Capital Stock (Deficit) Income Total
--------- ------- --------- --------- --------- -------------- ---------
Balances, December 31, 1998 ...................... $ 28,468 $ 1,216 $ 361,851 $(118,555) $ (71,506) $ -- $ 201,474
Net income ....................................... -- -- -- -- 46,743 -- 46,743
Issuance/sale of common stock .................... -- 90 45,610 -- -- -- 45,700
Issuance/vesting of performance shares ........... -- 3 230 -- -- -- 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 ($0.018 per share) ........ -- -- -- -- (1,872) -- (1,872)
Preferred stock dividends ($1.56 per share) ...... -- -- -- -- (1,779) -- (1,779)
--------- ------- --------- --------- --------- --------- ---------
Balances, December 31, 1999 ...................... 28,468 1,309 395,841 (119,387) (28,414) -- 277,817
Net income ....................................... -- -- -- -- 116,993 -- 116,993
Sale of common stock from treasury ............... -- -- 61,427 64,698 -- -- 126,125
Issuance/vesting of performance shares ........... -- 12 18,240 (6,976) -- -- 11,276
Stock option exercises ........................... -- 48 29,960 (4,933) -- -- 25,075
Treasury stock purchases ......................... -- -- -- (55,758) -- -- (55,758)
Cancellation of shares ........................... -- (133) (71,394) 71,527 -- -- --
Common stock dividends ($0.022 per share) ........ -- -- -- -- (2,403) -- (2,403)
Preferred stock converted to common .............. (1,251) 3 1,248 -- -- -- --
Preferred stock dividends ($1.56 per share) ...... -- -- -- -- (1,758) -- (1,758)
--------- ------- --------- --------- --------- --------- ---------
Balances, December 31, 2000 ...................... 27,217 1,239 435,322 (50,829) 84,418 -- 497,367
---------
Net income ....................................... -- -- -- -- 248,816 -- 248,816
Cumulative effect of change in accounting for
hedge derivatives, net of applicable income
tax benefit of $36,251 ........................ -- -- -- -- -- (67,323) (67,323)
Change in hedge derivative fair value, net of
applicable taxes of $69,153 ................... -- -- -- -- -- 128,428 128,428
Hedge derivative contract settlements reclassified
into earnings from other comprehensive income,
net of applicable taxes of $5,133 ............. -- -- -- -- -- 9,533 9,533
---------
Comprehensive income ............................. 319,454
---------
Issuance/vesting of performance shares ........... -- 7 5,184 (4,226) -- -- 965
Stock option exercises ........................... -- 21 17,424 (410) -- -- 17,035
Treasury stock purchases ......................... -- -- -- (9,249) -- -- (9,249)
Common stock dividends ($0.037 per share) ........ -- -- -- -- (4,522) -- (4,522)
Preferred stock converted to common .............. (27,217) 53 27,164 -- -- -- --
--------- ------- --------- --------- --------- --------- ---------
Balances, December 31, 2001 ...................... $ -- $ 1,320 $ 485,094 $ (64,714) $ 328,712 $ 70,638 $ 821,050
========= ======= ========= ========= ========= ========= =========
See accompanying notes to consolidated financial statements.
40
XTO ENERGY INC.
Notes to Consolidated Financial Statements
- --------------------------------------------------------------------------------
1. Organization and Summary of Significant Accounting Policies
XTO Energy Inc., a Delaware corporation, was organized under the name
Cross Timbers Oil Company 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 and changed its name to XTO Energy Inc. in June 2001.
The accompanying consolidated financial statements include the financial
statements of XTO Energy Inc. 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 September 18, 2000 and June 5, 2001.
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.
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
$136,611,000 at December 31, 2001 and $66,823,000 at December 31, 2000, 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, is 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.
41
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.
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 held during 1999 and 2000 were recorded as trading securities
since they were acquired principally for resale in the near future. Accordingly,
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 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.
Other Assets
Other assets primarily include deferred debt costs that are amortized over
the term of the related debt (Note 3) and the long-term portion of gas balancing
receivable (see "Revenue Recognition" below). Other assets are presented net of
accumulated amortization of $16,194,000 at December 31, 2001 and $11,574,000 at
December 31, 2000.
Derivatives
The Company uses derivatives to hedge product price and interest rate
risks, as opposed to their use for trading purposes. On 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 6). 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 accumulated other
comprehensive income, which is later transferred to earnings when the hedged
transaction occurs. Physical delivery contracts which are not expected to 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).
Gains and losses on commodity hedge derivatives are recognized in oil and
gas revenues when the hedged transaction occurs, and gains and losses on
interest hedge derivatives are recorded as adjustments to interest expense. Cash
flows related to derivative transactions are included in operating activities.
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.
42
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 for gas deliveries in excess of the Company's net revenue interest,
while revenue is accrued for the undelivered volumes. Production imbalances are
generally recorded at the estimated sales price in effect at the time of
production. The consolidated balance sheets include the following amounts
related to production imbalances:
December 31
-----------------------------------------
(in thousands) 2001 2000
------------------- -------------------
Amount Mcf Amount Mcf
-------- -------- -------- --------
Accounts receivable - current underproduction ..................................... $ 13,497 5,079 $ 11,185 4,854
Accounts payable - current overproduction ......................................... (13,064) (4,871) (8,720) (3,943)
-------- -------- -------- --------
Net current gas underproduction balancing receivable ........................... $ 433 208 $ 2,465 911
======== ======== ======== ========
Other assets - noncurrent underproduction ......................................... $ 15,763 6,018 $ 11,208 5,133
Other long-term liability - noncurrent overproduction ............................. (21,871) (8,164) (19,216) (8,714)
-------- -------- -------- --------
Net long-term gas overproduction balancing payable ............................. (6,108) (2,146) (8,008) (3,581)
======== ========
Other assets - noncurrent carbon dioxide underproduction .......................... 4,165 11,256 4,327 10,062
-------- ======== -------- ========
Net long-term overproduction balancing payable ................................. $ (1,943) $ (3,681)
======== ========
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 $108,590,000 for 2001, $144,282,000 for 2000 and $66,175,000 for
1999. 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, the Company realized a net
loss on sale of property and equipment of $277,000 in 2001, and a net gain on
sale of property and equipment of $920,000 in 2000 and $6,390,000 in 1999.
Interest
Interest expense includes amortization of deferred debt costs and is
presented net of interest income of $716,000 in 2001, $1,430,000 in 2000 and
$619,000 in 1999, and net of capitalized interest of $6,649,000 in 2001,
$3,488,000 in 2000 and $1,353,000 in 1999. Interest is capitalized as producing
property cost based on the weighted average interest rate and the cost of wells
in process of drilling. Interest expense related to investment in equity
securities has been classified as a component of gain (loss) on investment in
equity securities.
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 with time vesting
conditions is based on the fair value of the award at the grant date and
recognized over the vesting period. Compensation related to performance shares
with price target vesting is recognized when the price target is reached. 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.
43
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.
Production is sold under contracts with various purchasers. For the year
ended December 31, 2001, sales to each of three purchasers were approximately
13%, 12% and 10% of total revenues. For the year ended December 31, 2000, sales
to a single purchaser were approximately 13% of total revenues. There were no
sales to a single purchaser that exceeded 10% of total revenues in 1999. The
Company believes that alternative purchasers are available, if necessary, to
purchase production at prices substantially similar to those received from these
significant purchasers.
2. 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 the
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, if necessary, each officer's margin debt in the event the officer
subsequently failed to satisfy the debt. 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 were full recourse and due in December
2003, with an interest rate equal to the Company's bank debt rate. In May 2001,
officers sold 302,000 shares of common stock to the Company for $6,496,000 and
used the proceeds to partially repay their loans. Loans to officers were fully
repaid in November 2001.
Other Transactions
A company, partially owned by a director of the Company, received fees
totaling $994,000 in 2000 for consulting services performed in connection with
the Company's acquisition and divestiture programs. 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
connection with a 1998 acquisition and was entitled to receive, at its election,
either a 20% working interest or a 1% overriding royalty interest conveyed from
the Company's 100% working interest in the properties after payout of
acquisition and operating costs. The Board of Directors authorized the purchase
of this potential interest from the director-related company and other parties
in November 2001 for $15 million, as supported by a third-party fairness
opinion. The director-related company received $10 million of the total purchase
price.
44
3. Debt
The Company's outstanding debt consists of the following:
(in thousands) December 31
------------------
2001 2000
-------- --------
Long-term Debt:
Senior debt-
Bank debt under revolving credit agreements due May 12, 2005,
3.45% at December 31, 2001 ................................... $556,000 $469,000
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
-------- --------
Total long-term debt ............................................... $856,000 $769,000
======== ========
Senior Debt
In May 2000, the Company entered a revolving credit agreement with
commercial banks with a commitment of $800 million. 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, 2001, there were no letters of credit
outstanding. In February 2001, the loan agreement was amended to allow the
repurchase of the Company's subordinated debt and to increase commodity hedging
limits. In May 2001, the loan agreement was amended to allow the Company to
issue senior debt. Borrowings at December 31, 2001 under the loan agreement were
$556 million with unused borrowing capacity of $244 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, 2001 and using parameters specified by
the banks, the borrowing base remains 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 may renegotiate the loan agreement to
increase the borrowing commitment and extend the revolving facility.
The credit facility is partially secured by the Company's producing
properties. Restrictions set forth in the loan agreement include limitations on
the incurrence of additional indebtedness and the creation of certain liens. 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 and current assets and
liabilities related to derivative fair value are excluded).
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, 2001 were based
on LIBOR rates with maturity of one to six months and accrued at the applicable
LIBOR rate plus 1.375%. 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 commitments which was 0.25% at December 31, 2001. The weighted
average interest rate on senior debt was 5.7% during 2001, 8.2% during 2000 and
6.7% during 1999.
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.
45
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 6 regarding interest rate swap agreements. Under the terms of one
of these agreements, the Company has notified the bank counterparty that it will
purchase subordinated notes with a face value of $9,725,000 on April 1, 2002.
Including the effects of the interest swap agreement and expensing of related
deferred debt cost, the Company will record a loss on extinguishment of debt of
approximately $600,000.
4. 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) 2001 2000 1999
-------- -------- --------
Income tax expense at the federal statutory rate
(35% in 2001, and 34% in 2000 and 1999) ........ $159,375 $ 59,987 $ 24,006
State and local taxes and other ................... 2,577 (607) (41)
-------- -------- --------
Income tax expense ................................ $161,952 $ 59,380 $ 23,965
======== ======== ========
Components of income tax expense are as follows:
(in thousands) .................................... 2001 2000 1999
-------- -------- --------
Current income tax ................................ $ 847 $ 387 $ 308
Deferred income tax expense ....................... 155,021 63,792 28,697
Net operating loss carryforward (added) used ...... 6,084 (4,799) (5,040)
-------- -------- --------
Income tax expense ................................ $161,952 $ 59,380 $ 23,965
======== ======== ========
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 liability of $27,330,000 and a long-term liability of $199,091,000
at December 31, 2001, and a current asset of $17,098,000 and a long- term
liability of $82,476,000 at December 31, 2000. Significant components of net
deferred tax assets and liabilities are:
46
(in thousands) December 31
---------------------
2001 2000
--------- ---------
Deferred tax assets:
Net operating loss carryforwards ..................................... $ 63,286 $ 69,370
Accrued stock appreciation right and performance share compensation .. 17 916
Derivative fair value loss ........................................... 25,940 15,024
Other ................................................................ 5,976 5,038
--------- ---------
Total deferred tax assets .................................... 95,219 90,348
--------- ---------
Deferred tax liabilities:
Property and equipment ............................................... 261,353 148,363
Derivative fair value gain ........................................... 48,646 --
Other ................................................................ 11,641 7,363
--------- ---------
Total deferred tax liabilities ............................... 321,640 155,726
--------- ---------
Net deferred tax liabilities ............................................. $(226,421) $ (65,378)
========= =========
As of December 31, 2001, the Company has estimated tax loss carryforwards
of approximately $195 million, of which $10.6 million are related to capital
losses. The capital loss tax carryforwards expire in 2005 while the remaining
ordinary loss carryforwards are scheduled to expire in 2009 through 2021.
Approximately $22 million of the tax loss carryforwards are the result of an
acquisition. A new tax law, signed in March 2002 and retroactive to September
11, 2001, will increase the Company's tax loss carryforward by approximately $12
million. The Company has not booked any valuation allowance because it believes
it has tax planning strategies available to realize its tax loss carryforwards.
5. Commitments and Contingencies
Leases
The Company leases offices, vehicles, airplanes, compressors and certain
other equipment in its primary locations under noncancelable operating leases.
Commitments related to these lease payments are not recorded in the accompanying
consolidated balance sheets. As of December 31, 2001, minimum future lease
payments for all noncancelable lease agreements (including the sale and
operating leaseback agreements described below) were as follows:
(in thousands)
2002 .................................................. $15,524
2003 .................................................. 14,956
2004 .................................................. 10,411
2005 .................................................. 8,539
2006 .................................................. 8,639
Remaining ............................................. 31,898
-------
Total ................................................. $89,967
=======
Amounts incurred under operating leases (including renewable monthly
leases) were $20,561,000 in 2001, $17,329,000 in 2000 and $14,093,000 in 1999.
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 with fixed renewal options for an additional 13 years at a total cost
of $7.8 million. This transaction was recorded as a sale and operating
leaseback, with no gain or loss on the sale.
47
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 ten 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, 2001, annual rentals were $1.6 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, 2001 was
$1.6 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.
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.
In addition, the officer is entitled to receive a payment sufficient to make the
officer whole for any excise tax on excess parachute payments imposed by the
Internal Revenue Code.
Commodity Commitments
The Company has entered into natural gas physical delivery contracts,
futures contracts, collars and swap agreements that effectively fix gas prices.
See Note 8.
Drilling Contracts
The Company has agreements to use four drilling rigs and one workover rig
through July 2003. Total commitments under these agreements are $9.5 million for
2002 and $1 million for 2003.
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. The
court has ordered that the parties enter into mediation, which should occur in
the first half of 2002. 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.
48
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.
According to the U.S. Department of Justice, 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 the lawsuit, which was denied. 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 cannot currently be reasonably
estimated, and no provision has been 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 from February through August 1990. 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. 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.
In June 2001, the Company was served with a lawsuit styled Quinque
Operating Co., et al. v. Gas Pipelines, et al. The action was filed in the
District Court of Stevens County, Kansas, against the Company and one of its
subsidiaries, along with over 200 natural gas transmission companies, producers,
gatherers and processors of natural gas. Plaintiffs seek to represent a class of
plaintiffs consisting of all similarly situated gas working interest owners,
overriding royalty owners and royalty owners either from whom the defendants had
purchased natural gas or who received economic benefit from the sale of such gas
since January 1, 1974. No class has been certified. The allegations in the case
are similar to those in the Grynberg case; however, the Quinque case broadens
the claims to cover all oil and gas leases (other than the Federal and Native
American leases that are the subject of the Grynberg case). The complaint
alleges that the defendants have mismeasured both the volume and heating content
of natural gas delivered into their pipelines resulting in underpayments to the
plaintiffs. Plaintiffs assert a breach of contract claim, negligent or
intentional misrepresentation, civil conspiracy, common carrier liability,
conversion, violation of a variety of Kansas statutes and other common law
causes of action. The amount of damages was not specified in the complaint. In
September 2001, the Company filed a motion to dismiss the lawsuit, which is
currently pending. In February 2002, the Company and one of its subsidiaries
were dismissed from the suit and another subsidiary of the Company was added.
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
cannot currently be reasonably estimated, and no provision has been 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, new regulations, enforcement policies, claims for damages
or other events could result in significant future costs.
49
6. 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.
Change in Accounting Principle
On January 1, 2001, the Company adopted SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and
138, by recording a one-time after-tax charge of $44,589,000 in the income
statement for the cumulative effect of a change in accounting principle and an
unrealized loss of $67,323,000 in accumulated other comprehensive income. The
unrealized loss is related to the derivative fair value of cash flow hedges. The
charge to the income statement is primarily related to the Company's physical
delivery contract with crude oil-based pricing, also referred to as the Enron
Btu swap contract.
After adoption of SFAS No. 133, all derivative financial instruments are
recorded 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, are recorded in derivative fair value gain (loss)
in the income statement. Changes in the fair value of effective cash flow hedges
are recorded as a component of accumulated other comprehensive income, which is
later transferred to earnings when the hedged transaction occurs.
Enron Btu Swap Contract
In 1995, the Company entered a contract to sell gas based on crude oil
pricing, also referred to as the Enron Btu swap contract (Note 8). This contract
was terminated as a result of the Enron bankruptcy (Note 7). Because the
contract pricing is not clearly and closely associated with natural gas prices,
it must be considered a non-hedge derivative financial instrument under SFAS No.
133 beginning January 1, 2001, with changes in fair value recorded as a
derivative gain (loss) in the income statement.
Prior to termination of the Enron Btu swap contract, the Company entered
derivative contracts with another counterparty to effectively defer until 2005
and 2006 any cash flow impact related to 25,000 Mcf of daily gas deliveries in
2002 that were to be made under the Enron Btu swap contract. Changes in fair
value of these contracts are recorded as a derivative gain (loss) in the income
statement. In March 2002, the Company terminated some of these contracts with
maturities of May through December 2002 and received $6.6 million from the
counterparty. Because these contracts are non-hedge derivatives, most of the
related $6.6 million gain related to their termination was recorded in 2001
derivative fair value gain.
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 when actual commodity prices are below the contractually provided fixed
price, the Company receives this difference from the counterparty. The Company
has hedged its exposure to variability in future cash flows from natural gas
sales for transactions occurring through December 2002. See Note 8.
In 2001, net losses on futures and basis swap hedge contracts reduced gas
revenue by $11.1 million. Including the effect of fixed price physical delivery
contracts, all hedging activities increased gas revenue by $97 million. During
2000, net losses on futures and basis swap hedge contracts reduced gas revenue
by $40.5 million and oil revenue by $7.8 million. During 1999, net losses on
futures and basis swap hedge contracts reduced gas revenue by $5.7 million and
oil revenue by $2.2 million. The effect of fixed price physical delivery
contracts was not significant in 2000 or 1999. As of December 31, 2001, an
unrealized pre-tax derivative fair value gain of $108.7 million, related to cash
flow hedges of gas price risk, was recorded in accumulated other comprehensive
income. The ultimate settlement value of these hedges will be recognized in the
income statement as gas revenue when the hedged gas sales occur over the next
year.
50
The Company occasionally sells gas call options. Because these options are
covered by Company production, they have the same effect on the Company as
product hedges when the strike prices are below current market gas prices.
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.
Interest Rate Swap Agreements
To reduce the interest rate on a portion of its subordinated debt, the
Company entered an agreement with a bank to purchase a portion of 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 purchasing the notes from the bank at any time at market value. The Company
has notified the bank that it will purchase subordinated notes with a face value
of $9,725,000 on April 1, 2002, the termination date of the related interest
swap agreement. See Note 3. This agreement is recorded in the financial
statements as a non-hedge derivative with changes in fair value recorded in the
income statement.
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 a gain of $2 million. This gain has been
deferred and is being amortized against interest expense through September 2005.
Derivative Fair Value (Gain) Loss
The components of derivative fair value (gain) loss, as reflected in the
consolidated income statements are:
(in thousands) Year Ended December 31
-----------------------
2001 2000
-------- --------
Change in fair value of the Enron Btu swap contract .................. $(27,505) $ --
Change in fair value of call options and other derivatives that do not
qualify for hedge accounting ...................................... (27,022) 55,821
Ineffective portion of derivatives qualifying for hedge accounting .. 157 --
-------- --------
Derivative fair value (gain) loss .................................... $(54,370) $ 55,821
======== ========
Fair Value of Financial Instruments
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, 2001 and 2000. The following are estimated fair
values and carrying values of the Company's other financial instruments at each
of these dates:
51
Asset (Liability)
---------------------------------------------------------
December 31, 2001 December 31, 2000
------------------------- --------------------------
Carrying Fair Carrying Fair
(in thousands) ....................... Amount Value Amount Value
--------- --------- --------- ---------
Derivative Assets:
Fixed-price natural gas futures and
swaps ............................ $ 116,829 $ 116,829 $ -- $ 3,868
Interest rate swap ................. 2,791 2,791 473 2,651
Other (a) (b) ...................... 6,080 6,080 -- --
Derivative Liabilities:
Fixed-price natural gas futures and
swaps ............................ (19,198) (19,198) -- (112,807)
Natural gas written call options ... -- -- (44,189) (44,189)
Enron Btu swap contract (c) ........ -- -- -- (70,777)
Other (a) .......................... (10,157) (10,157) -- --
--------- --------- --------- ---------
Net derivative asset (liability) ..... $ 96,345 $ 96,345 $ (43,716) $(221,254)
========= ========= ========= =========
Long-term debt ....................... $(856,000) $(870,720) $(769,000) $(774,000)
========= ========= ========= =========
(a) These contracts were entered prior to termination of the Enron Btu
swap contract and effectively defer until 2005 and 2006 any cash
flow impact related to 25,000 Mcf of daily gas deliveries in 2002
that were to be made under the Enron Btu swap contract.
(b) In March 2002, the Company terminated contracts with maturities of
May through December 2002 and received $6.6 million from the
counterparty. Because these contracts are non-hedge derivatives,
most of the related $6.6 million gain related to their termination
was recorded in 2001 derivative fair value gain.
(c) The Enron Btu swap contract was terminated in December 2001 (Note
7). The value of this contract immediately prior to termination was
a $43.3 million liability, which is recorded as a current liability
until legal extinguishment is finalized.
The fair value of bank borrowings approximates their 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 the exchange-
trade value of NYMEX contracts, market commodity prices and interest rates for
the applicable future periods.
Changes in fair value of derivative assets and liabilities are the result
of changes in oil and gas prices and interest rates. Natural gas futures and
swaps are generally designated as hedges of commodity price risks, and
accordingly, changes in their values are predominantly recorded in accumulated
other comprehensive income until the hedged transaction occurs.
During 2001, the Company entered gas physical delivery contracts to
effectively provide gas price hedges. Because these contracts are not expected
to be net cash settled, they are considered to be normal sales contracts and not
derivatives; therefore, the contracts are not required to be recorded in the
financial statements. The value of outstanding physical delivery contracts at
December 31, 2001 was $36.4 million.
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.
Financial and commodity-based swap contracts expose the Company to the credit
risk of non-performance by the counterparty to the contracts. In general, the
Company does not believe this risk is significant since the exposure is
diversified among major banks and financial institutions with high credit
ratings. See Note 7 regarding credit risk related to the Enron Corporation
bankruptcy. 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
52
$4,098,000 at December 31, 2001 and $3,121,000 at December 31, 2000. The
Company's bad debt provision was $978,000 in 2001, $1,093,000 in 2000 and
$1,347,000 in 1999.
7. Enron Corporation Bankruptcy
As of December 2, 2001, the date of its bankruptcy filing, Enron
Corporation was the counterparty to some of the Company's hedge derivative
contracts, as well as a purchaser of natural gas under certain physical delivery
contracts. One of these contracts was a natural gas physical delivery contract
with crude oil-based pricing ("Enron Btu swap contract").
The Company sent Enron notices of contract terminations in November and
December 2001. Based on the fair value as of the contract termination dates,
Enron owes the Company $7.8 million for physical gas deliveries in November and
December 2001, and $13.5 million for net gains on hedge derivative contracts.
Enron also owes the Company $14.1 million in net unrealized gains related to
undelivered gas under physical delivery contracts. This amount, however, will
not be recorded in the financial statements until collectibility is assured.
Also recorded in the balance sheet at December 31, 2001 is a current
liability of $43.3 million related to the Enron Btu swap contract, based on fair
values at the date of contract termination. As specified under the contract
termination provisions, the Company, as the nondefaulting party, has notified
Enron that its liability under this contract has been reduced to zero. Based
upon discussion with outside legal counsel, the Company believes that these
termination provisions are legally enforceable, and accordingly, it has no
liability under this contract. However, under generally accepted accounting
principles, this liability cannot be credited to income until legal
extinguishment of the debt is finalized.
In the event the termination provisions of the Enron Btu swap contract are
ultimately not enforced, the Company believes that, based on contract provisions
and discussions with outside legal counsel, it should have the right to offset
all amounts due from Enron against any Enron Btu swap contract liability,
including amounts related to undelivered gas under physical delivery contracts.
Because the recorded Enron Btu swap contract liability exceeds total Enron
receivables at December 31, 2001, no reserve for asset collectibility has been
recorded.
Final resolution of the Enron bankruptcy and related proceedings may
result in a settlement materially different from amounts recorded at December
31, 2001. The following is a summary of recorded, unrecorded and total amounts
related to Enron:
Receivable (Payable) at December 31, 2001
-----------------------------------------
(in thousands) Recorded Unrecorded Total
-------- ---------- ---------
Accounts receivable:
Physical delivery contracts ............................ $ 7,817 $ 14,069 $ 21,886
Hedge derivative contract fair value ................... 13,534 -- 13,534
-------- -------- --------
Total accounts receivable .............................. 21,351 14,069 35,420
Current liability - Enron Btu swap contract fair value . (43,272) -- (43,272)
-------- -------- --------
Net asset (liability) .................................. $(21,921) $ 14,069 $ (7,852)
======== ======== ========
53
8. Natural Gas Sales Commitments
The Company has entered into natural gas futures contracts and swap
agreements that effectively fix prices for the production and periods shown
below. Prices to be realized for hedged production may be less than these fixed
prices because of location, quality and other adjustments. See Note 6 regarding
accounting for commodity hedges. All contracts with Enron have been terminated
and excluded (Note 7).
Futures Contracts
and Swap Agreements
--------------------------------------
NYMEX Price
2002 Production Period Mcf per Day per Mcf (a)
------------------------------- -------------------- ---------------
April to May 355,000 $ 3.66
June 305,000 3.71
July to December 280,000 3.73
(a) Includes approximately $0.05 per Mcf gain that will be deferred and
recognized in 2003 related to contract terminations and hedge
redesignations.
The Company has entered into basis swap agreements which effectively fix
basis for the following production and periods:
Location 2002 Production Period Mcf per Day Basis per Mcf (a)
- ---------------------------- ----------------------------------------- -------------------- ---------------------
Arkoma April to October 85,000 $ 0.10
East Texas April to June 170,000 0.00
July to September 170,000 0.01
October 150,000 0.00
November to December 60,000 0.00
Mid-Continent April to October 20,000 0.12
- -------------------
(a) Reductions from NYMEX gas price for location, quality and other
adjustments.
The Company's settlement of futures contracts and basis swap agreements
related to first quarter 2002 gas production resulted in increased gas revenue
of $32.3 million. This gain will be recognized as an increase in gas revenue of
approximately $0.75 per Mcf in the first quarter of 2002. Included in these
settlements is $4.4 million related to terminated Enron futures contracts and
swap agreements which will be recognized as an increase in gas revenue of
approximately $0.10 per Mcf.
In December 2001 and March 2002, the Company closed futures contracts and
swap agreements that were designated as cash flow hedges and, accordingly, has
recorded deferred gains of $10.5 million in accumulated other comprehensive
income. Included in these deferred gains is $7.6 million related to terminated
Enron futures contracts. Deferred gains on these closed contracts will be
recorded as gas revenue based on production in the following periods:
Production Period Mcf per Day Gain per Mcf/d
- ------------------------------- -------------------- -------------------
2002 April 50,000 $ 0.72
May 50,000 0.68
June 75,000 0.65
July 75,000 0.62
August 75,000 0.60
September 75,000 0.61
October 75,000 0.49
November 65,000 0.45
December 65,000 0.34
54
In March 2002, the Company entered into collar agreements which provide a
floor (put) and ceiling (call) price for natural gas. If the market price of
natural gas exceeds the call price or falls below the put price, the Company
receives the fixed price and pays the market price. If the market price of
natural gas is between the floor and ceiling price, no payments are due from
either the Company or the counterparty. Prices to be realized may be less than
these floor and ceiling prices because of location, quality and other
adjustments. The Company has entered into collar agreements for the following
production periods:
Average NYMEX Price (a)
------------------------
2002 Production Period Mcf per Day Floor Ceiling
- ------------------------------- ------------------- ----------- -----------
April to May 75,000 $ 2.60 $ 3.20
June 150,000 2.90 3.46
July to September 150,000 2.95 3.52
October to December 165,000 3.27 3.89
(a) Includes reduction of $0.10 per Mcf for cost of collars.
The Company has entered gas physical delivery contracts that are
considered to be normal sales, and therefore, are not recorded in the financial
statements, because they are not expected to be net cash settled. All Enron
contracts have been terminated and excluded. These contracts effectively fix
prices for the following production and periods:
Location 2002 Production Period Mcf per Day Fixed Price per Mcf
- --------------------------- ------------------------------------ -------------------- ---------------------
Arkoma January to March 60,000 $ 4.75
April to December 20,000 3.61
East Texas January 50,000 5.06
February to March 20,000 4.54
April to December 10,000 3.63
Mid-Continent January to March 20,000 5.58
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 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. See Note 6 regarding
accounting for this contract, also referred to as the Enron Btu swap contract,
which has been terminated as a result of the Enron bankruptcy (Note 7). Also
see Note 6 regarding a related derivative commitment with another counterparty.
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, 2001,
$1,552,000 is recorded in other current liabilities and $455,000 is recorded in
other long-term liabilities related to this commitment.
As part of an acquisition, the Company assumed a commitment to sell 6,800
Mcf of gas per day in Arkansas through April 2003 at prices which are adjusted
by the monthly index price. In 2001, the prices ranged from $0.44 to $1.44 per
Mcf. This contract is considered a normal sale and therefore, is not recorded as
a derivative in the Company's financial statements.
In 1998, the Company sold a production payment, payable from future
production from certain properties acquired in an acquisition, to EEX
Corporation for $30 million. Under the terms of the production payment
conveyance and related delivery agreement, the Company committed to deliver to
EEX a total of approximately 34.3 Bcf (27.8 Bcf net to the Company's interest)
of gas during the 10-year period beginning January 1, 2002, with scheduled
deliveries by year, subject to certain variables. EEX will reimburse the Company
for all royalty and production and property tax payments related to such
deliveries. EEX will also pay the Company an operating fee of $0.257 per Mcf for
deliveries in 2002, which fee will be escalated annually at a rate of 5.5%. Each
December, beginning in 1998, the Company had
55
the option to repurchase a portion of this production payment, based on a total
cost of $30 million plus interest accrued from May 1, 1998 through the
repurchase date. The Company repurchased portions of the production payment in
2001 and 2002 for $20.7 million (Note 13). According to the terms of the
delivery agreement, the Company has the right to receive the repurchased
production payment volumes first out of production commencing January 1, 2002.
Because the Company has repurchased 18.3 Bcf (14.8 Bcf net) of gas, it should be
approximately September 2006 before EEX will begin receiving the remaining 16.0
Bcf (13.0 Bcf net) of gas.
9. Equity
Three-for-Two Stock Splits
The Company effected three-for-two common stock splits on September 18,
2000 and June 5, 2001. 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
------------------------------------- -------------------------------------
(in thousands) 2001 2000 1999 2001 2000 1999
-------- -------- -------- -------- -------- --------
Balance, January 1 ...................... 123,880 130,924 121,608 7,547 20,924 20,972
Issuance/sale of common stock ........... -- -- 9,000 -- (9,900) (4,500)
Issuance/vesting of performance shares .. 666 1,220 292 217 571 --
Stock option exercises .................. 2,154 4,792 24 23 414 115
Treasury stock purchases ................ -- -- -- 429 8,837 4,337
Cancellation of shares .................. -- (13,299) -- -- (13,299) --
Preferred stock converted to common ..... 5,289 243 -- -- -- --
-------- -------- -------- -------- -------- --------
Balance, December 31 .................... 131,989 123,880 130,924 8,216 7,547 20,924
======== ======== ======== ======== ======== ========
In July 1999, the Company issued 9 million shares of common stock at its
fair value of $5.08 per share in exchange for its 50% interest in an
acquisition and for cash proceeds of $3.2 million which were used to reduce bank
debt.
Also in July 1999, the Company sold from treasury 4.5 million shares of
common stock in an underwritten public offering for net proceeds of
approximately $26.5 million. The proceeds were used to repurchase 4.3 million
shares of common stock issued in conjunction with an acquisition.
In May 2000, 13.3 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 9.9 million shares of
common stock in an underwritten public offering for net proceeds of
approximately $126.1 million. The proceeds were used to reduce bank debt.
56
Treasury Stock
The Company's open market treasury share acquisitions totaled 7.9 million
shares in 2000 at an average price of $5.25 and 11,000 shares in 1999 at an
average price of $4.69 per share. As of March 27, 2002, 6.5 million shares
remain under the May 2000 Board of Directors' authorization to repurchase 6.8
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 October 2001, the Company filed a shelf registration statement with the
Securities and Exchange 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 total price of securities
to be offered is $600 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. As of March 2002,
no securities have been issued under the shelf registration statement.
Common Stock Warrants
As partial consideration for producing properties acquired in December
1997, the Company issued warrants to purchase 2.1 million shares of common stock
at a price of $6.70 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 $0.0045 per common
share from 1999 through second quarter 2000, $0.0067 per common share for third
quarter 2000 through first quarter 2001 and $0.01 per common share for the
remainder of 2001. See Note 3 regarding restrictions on dividends.
Series A Convertible Preferred Stock
Series A convertible preferred stock is recorded in the accompanying
December 31, 2000 consolidated balance sheet at its liquidation preference of
$25 per share. During 2000, 50,000 shares of convertible preferred stock were
converted into 243,000 shares of common stock. In January 2001, the Company sent
notice to preferred stockholders that it would redeem all outstanding shares in
February 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 5.3 million common shares.
57
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
-------------- -------------- --------------
2001
- ------------------------------------------------------------
Basic
Net income ................................. $ 248,816
--------------
Earnings available to common stock - basic . 248,816 122,505 $ 2.03
==============
Diluted
Effect of dilutive securities:
Stock options .......................... -- 484
Preferred stock ........................ -- 377
Warrants ............................... -- 1,260
-------------- --------------
Earnings available to common stock - diluted $ 248,816 124,626 $ 2.00
============== ============== ==============
2000
- ------------------------------------------------------------
Basic
Net income ................................. $ 116,993
Preferred stock dividends .................. (1,758)
--------------
Earnings available to common stock - basic . 115,235 106,730 $ 1.08
==============
Diluted
Effect of dilutive securities:
Stock options .......................... -- 777
Preferred stock ........................ 1,758 5,470
Warrants ............................... -- 581
-------------- --------------
Earnings available to common stock - diluted $ 116,993 113,558 $ 1.03
============== ============== ==============
1999
- ------------------------------------------------------------
Basic
Net income ................................. $ 46,743
Preferred stock dividends .................. (1,779)
--------------
Earnings available to common stock - basic . 44,964 105,341 $ 0.43
==============
Diluted
Effect of dilutive securities:
Stock options .......................... -- 243
Preferred stock ........................ 1,779 5,534
Warrants ............................... -- --
-------------- --------------
Earnings available to common stock - diluted $ 46,743 111,118 $ 0.42
============== ============== ==============
58
11. Supplemental Cash Flow Information
The consolidated statements of cash flows exclude the following non-cash
transactions (Notes 9 and 12):
. Conversion of 1.1 million shares of preferred stock to 5.3 million
shares of common stock in 2001 and conversion of 50,000 shares of
preferred stock to 243,000 shares of common stock in 2000
. Cancellation of 13.3 million shares of treasury stock in 2000
. Sale of Hugoton Royalty Trust units in 2000 in exchange for 743,000
shares of common stock valued at $11.3 million, and in 1999 in
exchange for 111,000 shares of common stock valued at $700,000
. Purchase of a 50% interest in an acquisition in 1999 in exchange for
8.4 million shares of common stock, valued at $42.5 million
. Performance shares activity, including:
. Grants of 878,000 shares in 2001, 1,230,000 shares in 2000 and
319,000 shares in 1999 to key employees and nonemployee
directors
. Vesting of 602,000 shares in 2001, 1,510,000 shares in 2000
and 27,000 shares in 1999
. Forfeiture of 9,000 shares in 2001 and 27,000 shares in 1999
. Receipt of common stock of 66,000 shares (valued at $967,000) in
2000 for the option price of exercised stock options
Interest payments in 2001 totaled $59,550,000 (including $6,649,000 of
capitalized interest), $80,067,000 in 2000 (including $3,488,000 of capitalized
interest) and $70,500,000 in 1999 (including $1,353,000 of capitalized
interest). Net income tax refunds were $140,000 during 2001 and $322,000 during
1999; income tax payments were $1,085,000 in 2000.
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. Employee contributions vest immediately
while the Company's matching contributions vest 100% upon completion of three
years of service. All employees over 21 years of age may participate. Company
contributions under the plan were $3,884,000 in 2001, $3,226,000 in 2000 and
$2,514,000 in 1999.
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. All
participants pay premiums as determined by the Company. Post-retirement medical
benefits are not pre-funded by the Company, but are paid when incurred. The
status of the Company's post-retirement health plan for 2001 is as follows:
59
(in thousands) 2001
--------
Change in benefit obligation:
Benefit obligation at January 1 ............................... $ 804
Service cost ............................................... 221
Interest cost .............................................. 62
Actuarial loss ............................................. 1
Benefit payments ........................................... (10)
--------
Benefit obligation at December 31 ............................. $ 1,078
========
Amounts recognized in the consolidated balance sheet:
Funded status ................................................. $ (1,078)
Unrecognized net actuarial gain ............................... (9)
--------
Accrued benefit liability, as recognized in the
consolidated balance sheet at December 31, 2001 ............ $ (1,087)
========
Components of net periodic benefit cost:
Service cost .................................................. $ 221
Interest cost ................................................. 62
Recognized prior service cost ................................. 804
--------
Net periodic benefit cost ....................................... $ 1,087
========
The weighted average discount rate used by the Company in determining the
accumulated post-retirement benefit obligation was 7.5%. For measurement
purposes, the annual rate of increase in the covered health care benefits was
assumed to range from 9% in 2001 to 6% in 2006 and beyond. A 1% change in the
assumed health care cost trend rate would have approximately a $158,000 effect
on total estimated service and interest cost and approximately a $417,000 effect
on the post-retirement benefit obligation.
1994 and 1997 Stock Incentive Plans
Under the 1994 Stock Incentive Plan and the 1997 Stock Incentive Plan, a
total of 5,063,000 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. At December 31, 2001, there are 1,341,000 shares
available for grant under the 1994 Plan and 1,181,000 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 1997 plan have a term of ten years. 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. All
outstanding options under the 1994 Plan were vested by resolution of the Board
of Directors.
1998 Stock Incentive Plan
Under the 1998 Stock Incentive Plan, a total of 13,500,000 shares of
common stock may be issued pursuant to grants of stock options or performance
shares. 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, 2001, there were 1,249,000 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 44,000 options outstanding at December 31, 2001 that vest when the
common stock price reaches $23.33, 174,000 options that vest when the common
stock price reaches $21.50, 5,000 options that vest when the common stock price
reaches $20.00 and 174,000 options that vest when the common stock price reaches
$19.50. The options with the common stock target prices of $19.50 and $20.00
vested in March 2002.
60
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 common
stockholders. The Company issued performance shares to key employees totaling
871,000 in 2001, 1,230,000 in 2000 and 292,000 in 1999. Performance shares
vested, totaling 595,000 in 2001 and 1,510,000 in 2000, when the common stock
price reached specified levels. In 2001, 9,000 of the performance shares issued
in 2001 were forfeited, and in 1999, 27,000 performance shares issued in 1998
were forfeited. General and administrative expense includes compensation related
to performance shares of $8.7 million in 2001, $18.4 million in 2000 and
$102,000 in 1999. As of December 31, 2001, there were 159,000 performance shares
that vest when the common stock price reaches $18.30, 242,000 performance shares
that vest when the common stock price reaches $21.67 and 13,500 performance
shares that vest in increments of 6,750 in each of 2002 and 2003. In February
2002, upon vesting of the performance shares with the $18.30 common stock
vesting price, an additional 159,000 performance shares were issued that vested
when the stock price reached $20.00 in March 2002. The Company also issued to
nonemployee directors a total of 8,000 perfomance shares in February 2002, 7,000
performance shares in 2001 and 27,000 performance shares in 1999, all of which
vested upon grant.
In 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 150,000 performance shares for every
$1.67 increment in the closing price of the Company's common stock above $20.00.
Unless otherwise designated by the Board, 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 232,500
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 options were
exercised in 2000 and 1999, resulting in non-cash compensation expense of $7.1
million in 2000 and $60,000 in 1999.
61
Option Activity and Balances
The following summarizes option activity and balances from 1999 through
2001:
Weighted
Average
Exercise Stock
Price Options
---------- ----------
1999
- -----------------------------------------------
Beginning of year .................... $ 6.33 5,937,719
Grants .......................... 4.74 922,218
Exercises ....................... 3.05 (23,540)
Forfeitures ..................... 5.17 (64,293)
----------
End of year .......................... 6.13 6,772,104
==========
Exercisable at end of year ........... 4.93 3,014,042
==========
2000
- -----------------------------------------------
Beginning of year .................... $ 6.13 6,772,104
Grants .......................... 13.33 7,143,752
Exercises ....................... 6.54 (6,965,106)
Forfeitures ..................... 5.94 (369,528)
----------
End of year .......................... 13.43 6,581,222
==========
Exercisable at end of year ........... 12.83 4,722,764
==========
2001
- -----------------------------------------------
Beginning of year .................... $ 13.43 6,581,222
Grants .......................... 18.74 5,713,621
Exercises ....................... 13.19 (5,325,655)
Forfeitures ..................... 18.81 (81,000)
----------
End of year .......................... 17.93 6,888,188
==========
Exercisable at end of year ........... 18.03 6,492,188
==========
The following summarizes information about outstanding options at December
31, 2001:
Options Outstanding Options Exercisable
------------------------------------------------- -------------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Prices Number Term Price Number Price
- ------------------- --------------- -------------- -------------- ------------- -------------
$1.84 - $5.52 24,049 5.5 years $ 4.29 24,049 $ 4.29
$5.53 - $9.20 37,965 6.9 years 7.49 37,965 7.49
$9.21 - $12.88 46,946 8.6 years 10.35 46,946 10.35
$12.89 - $18.39 2,835,741 9.1 years 15.96 2,483,379 15.98
$18.40 - $20.35 3,943,487 9.3 years 19.62 3,899,849 19.62
--------------- ------------
6,888,188 6,492,188
=============== ============
62
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 $8.68 in 2001, $6.85 in 2000 and $2.85 in 1999.
2001 2000 1999
-------- -------- --------
Risk-free interest rates ............... 4.9% 5.8% 5.8%
Dividend yield ......................... 0.2% 0.2% 3.0%
Weighted average expected lives ........ 4 years 5 years 5 years
Volatility ............................. 54% 53% 91%
Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair
Value
The following are pro forma earnings available to common stock and
earnings per common share for 2001, 2000 and 1999, as if stock-based
compensation had been recorded at the estimated fair value of stock awards at
the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based
Compensation:
(in thousands, except per share data)
2001 2000 1999
----------- ----------- -----------
Earnings available to common stock:
As reported ....................... $ 248,816 $ 115,235 $ 44,964
Pro forma ......................... $ 204,543 $ 91,194 $ 40,373
Earnings per common share:
Basic As reported .......... $ 2.03 $ 1.08 $ 0.43
Pro forma ............ $ 1.67 $ 0.85 $ 0.38
Diluted As reported .......... $ 2.00 $ 1.03 $ 0.42
Pro forma ............ $ 1.64 $ 0.82 $ 0.38
13. Acquisitions and Dispositions
Acquisitions
In January 2001, the Company acquired gas properties in East Texas and
Louisiana for $115 million from Herd Producing Company, Inc., and in February
2001, it acquired gas properties in East Texas for $45 million from Miller
Energy, Inc. and other owners. In August 2001, the Company acquired primarily
underdeveloped acreage in the Freestone area of East Texas for approximately $22
million. The purchases were funded with bank debt and are subject to typical
post-closing adjustments.
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, 2000 as if these acquisitions had been consummated
immediately prior to January 1, 2000. Pro forma results are not presented for
the year ended December 31, 2001 because the effects of these acquisitions
excluded from 2001 results are not significant. These pro forma results are not
necessarily indicative of future results.
(in thousands, except per share data)
Revenues .................................................... $620,113
========
Net income .................................................. $115,231
========
Earnings available to common stock .......................... $113,473
========
Earnings per common share:
Basic ..................................................... $ 1.06
========
Diluted ................................................... $ 1.01
========
Weighted average shares outstanding ......................... 106,730
========
63
In January 2001, the Company repurchased 9.1 Bcf of natural gas for $9.9
million from a production payment sold to EEX Corporation in a 1998 acquisition.
In January 2002, the Company repurchased an additional 9.2 Bcf of natural gas
for $10.8 million. See Note 8.
In 1999, the Company and Lehman Brothers acquired the common stock of
Spring Holding Company, a private oil and gas company, for a combination of cash
and the Company's 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 acquired Lehman's 50% interest in Spring
for $44.3 million. This acquisition included 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 $257 million.
The Company also acquired in 1999, with Lehman as 50% owner, Arkoma Basin
properties from affiliates of Ocean Energy, Inc. for $231 million. The Company
acquired Lehman's interest in the Ocean Energy Acquisition in March 2000 for
$111 million.
Dispositions
In June 2001, the Company and Cross Timbers Royalty Trust filed an amended
registration statement with the Securities and Exchange Commission to sell
1,360,000 units (22.7% of outstanding units) owned by the Company. The Company's
sale of these units is dependent upon commodity prices and related market
conditions for oil and gas equities. These units are classified as producing
properties in the accompanying balance sheet at a net cost of $12.2 million at
December 31, 2001.
In March 2000, the Company sold producing properties in Crockett County,
Texas, and Lea County, New Mexico for total gross proceeds of $68.3 million. 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.
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. 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.
64
14. Quarterly Financial Data (Unaudited)
The following are summarized quarterly financial data for the years ended
December 31, 2001 and 2000:
(in thousands, except per share data) Quarter
--------------------------------------------
1st 2nd 3rd 4th
-------- -------- -------- --------
2001
- -----------------------------------
Revenues .................... $249,152 $209,021 $197,307 $183,268
Gross profit (a) ............ $164,788 $167,514 $129,604 $ 88,269
Earnings available to
common stock ............ $ 46,748 $ 90,533 $ 70,342 $ 41,193
Earnings per common share:
Basic ................... $ 0.39 $ 0.74 $ 0.57 $ 0.33
Diluted ................. $ 0.38 $ 0.73 $ 0.56 $ 0.33
Average shares outstanding .. 119,640 123,050 123,596 123,669
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 ................... $ 0.31 $ 0.01 $ 0.30 $ 0.45
Diluted ................. $ 0.29 $ 0.01 $ 0.28 $ 0.42
Average shares outstanding .. 108,662 103,376 104,277 110,592
(a) Operating income before general and administrative expense.
65
15. 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) 2001 2000 1999
-------- -------- --------
Acquisitions:
Producing properties ................ $238,041 $ 31,983 $505,912
Undeveloped properties .............. 3,980 3,490 4,182
Development (a) .......................... 385,479 163,224 89,306
Exploration:
Geological and geophysical studies .. 2,123 829 872
Dry hole expense .................... 2,189 -- --
Rental expense and other ............ 1,126 218 32
-------- -------- --------
Total .................................... $632,938 $199,744 $600,304
======== ======== ========
(a) Includes capitalized interest of $6,649,000 in 2001, $3,488,000 in
2000 and $1,353,000 in 1999.
Proved Reserves
The Company's proved oil and gas reserves have been estimated by
independent petroleum engineers. Proved reserves are the estimated quantities
that geologic and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are the quantities expected to
be recovered through existing wells with existing equipment and operating
methods. Due to the inherent uncertainties and the limited nature of reservoir
data, such estimates are subject to change as additional information becomes
available. The reserves actually recovered and the timing of production of these
reserves may be substantially different from the original estimate. Revisions
result primarily from new information obtained from development drilling and
production history and from changes in economic factors.
Standardized Measure
The standardized measure of discounted future net cash flows
("standardized measure") and changes in such cash flows are prepared using
assumptions required by the Financial Accounting Standards Board. Such
assumptions include the use of year-end prices for oil and gas and year-end
costs for estimated future development and production expenditures to produce
year-end estimated proved reserves. Discounted future net cash flows are
calculated using a 10% rate. Estimated future income taxes are calculated by
applying year-end statutory rates to future pre-tax net cash flows, less the tax
basis of related assets and applicable tax credits.
The standardized measure does not represent management's estimate of the
Company's future cash flows or the value of proved oil and gas reserves.
Probable and possible reserves, which may become proved in the future, are
excluded from the calculations. Furthermore, year-end prices used to determine
the standardized measure of discounted cash flows, are influenced by seasonal
demand and other factors and may not be the most representative in estimating
future revenues or reserve data.
66
(in thousands) Oil Gas Natural Gas
(Bbls) (Mcf) Liquids (Bbls)
------------ ------------ -------------
Proved Reserves
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
Revisions ............................... (4,201) (96,990) (2,193)
Extensions, additions and discoveries ... 3,317 469,602 2,081
Production .............................. (4,978) (152,178) (1,601)
Purchases in place ...................... 1,484 248,339 --
Sales in place .......................... (18) (2,978) --
------------ ------------ ------------
December 31, 2001 ........................... 54,049 2,235,478 20,299
============ ============ ============
Proved Developed Reserves
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
============ ============ ============
December 31, 2001 ........................... 41,231 1,452,222 14,774
============ ============ ============
December 31
Standardized Measure of Discounted Future ----------------------------------------------
Net Cash Flows Relating to Proved Reserves 2001 2000 1999
------------ ------------ ------------
(in thousands)
Future cash inflows ......................... $ 6,366,557 $ 18,866,832 $ 5,113,094
Future costs:
Production .............................. (1,989,344) (3,237,574) (1,549,401)
Development ............................. (620,611) (389,698) (294,250)
------------ ------------ ------------
Future net cash flows before income tax ..... 3,756,602 15,239,560 3,269,443
Future income tax ........................... (879,874) (4,947,614) (718,892)
------------ ------------ ------------
Future net cash flows ....................... 2,876,728 10,291,946 2,550,551
10% annual discount ......................... (1,354,679) (5,029,916) (1,153,611)
------------ ------------ ------------
Standardized measure (a) .................... $ 1,522,049 $ 5,262,030 $ 1,396,940
============ ============ ============
(a) Before income tax, the year-end standardized measure (or discounted
present value of future net cash flows) was $1,947,441,000 in 2001,
$7,748,632,000 in 2000 and $1,765,936,000 in 1999.
67
Changes in Standardized Measure of
Discounted Future Net Cash Flows 2001 2000 1999
------------ ------------ ------------
(in thousands)
Standardized measure, January 1 ........ $ 5,262,030 $ 1,396,940 $ 808,403
------------ ------------ ------------
Revisions:
Prices and costs ................... (6,285,062) 5,096,973 608,123
Quantity estimates ................. 173,587 190,457 62,033
Accretion of discount .............. 455,788 123,225 70,256
Future development costs ........... (408,772) (196,048) (113,110)
Income tax ......................... 2,278,522 (2,082,745) (259,403)
Production rates and other ......... 1,090 1,378 (137)
------------ ------------ ------------
Net revisions .................. (3,784,847) 3,133,240 367,762
Extensions, additions and discoveries .. 252,524 1,018,349 125,209
Production ............................. (653,626) (441,323) (215,869)
Development costs ...................... 312,435 128,757 70,275
Purchases in place (a) ................. 148,111 115,866 414,759
Sales in place (b) ..................... (14,578) (89,799) (173,599)
------------ ------------ ------------
Net change ..................... (3,739,981) 3,865,090 588,537
------------ ------------ ------------
Standardized measure, December 31 ...... $ 1,522,049 $ 5,262,030 $ 1,396,940
============ ============ ============
(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 $17.39 for 2001, $25.49 for 2000
and $24.17 for 1999. Year-end average realized gas prices were $2.36 for 2001,
$9.55 for 2000 and $2.20 for 1999. Year-end average realized natural gas liquids
prices were $8.70 for 2001, $26.33 for 2000 and $13.83 for 1999. Proved oil and
gas reserves at December 31, 2001 include:
. 1,658,000 Bbls of oil and 204,123,000 Mcf of gas and discounted
present value before income tax of $159,275,000 related to the
Company's ownership of approximately 54% of Hugoton Royalty Trust
units at December 31, 2001.
. 605,000 Bbls of oil and 7,305,000 Mcf of gas and discounted present
value before income tax of $9,974,000 related to the Company's
ownership of approximately 23% of Cross Timbers Royalty Trust units
at December 31, 2001.
The standardized measure does not include the effect of hedge derivatives
or fixed price physical delivery contracts. Including the effects of these
contracts, the standardized measure before income tax would increase by $151.6
million at December 31, 2001 and $4.3 million at December 31, 1999, and would
decrease by $193.8 million at December 31, 2000.
Based on assumed realized prices of $25.00 per Bbl for oil, $3.50 per Mcf
for gas and $16.00 per Bbl for natural gas liquids, estimated proved reserves at
December 31, 2001 would be 59.3 million Bbls of oil, 2.3 Tcf of natural gas and
22.3 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 $3.5 billion.
68
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
XTO Energy Inc.
We have audited the accompanying consolidated balance sheets of XTO Energy Inc.
and its subsidiaries as of December 31, 2001 and 2000, 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, 2001. 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, 2001 and 2000, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States.
As discussed in Note 6 to Consolidated Financial Statements, the Company changed
its method of accounting for its derivative instruments and hedging activities
effective January 1, 2001, in connection with its adoption of Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 28, 2002
69
SCHEDULE II
XTO ENERGY INC.
Consolidated Valuation and Qualifying Accounts
- --------------------------------------------------------------------------------
Balance at Balance at
(in thousands) Beginning of End of
Period Additions (a) Deductions (b) Other (c) Period
------------ ------------- -------------- -------- -----------
December 31, 2001
Allowance for doubtful accounts - Joint
interest and other receivables ........ $ 3,121 $ 978 $ (1) $ -- $ 4,098
======== ======== ======== ======== ========
December 31, 2000
Allowance for doubtful accounts - Joint
interest and other receivables ........ $ 2,150 $ 1,093 $ (122) $ -- $ 3,121
======== ======== ======== ======== ========
December 31, 1999
Allowance for doubtful accounts - Joint
interest and other receivables ........ $ 375 $ 1,347 $ (72) $ 500 $ 2,150
======== ======== ======== ======== ========
- ----------------
(a) Additions relate to provisions for doubtful accounts
(b) Deductions relate to the write-off of accounts receivable deemed
uncollectible.
(c) Reclassification adjustment.
70
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 28th day of March
2002.
XTO ENERGY INC.
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 28th day of March 2002.
PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS) DIRECTORS
BOB R. SIMPSON WILLIAM H. ADAMS III
- ----------------------------------------------------------------- ------------------------------------------------------------
Bob R. Simpson, Chairman of the Board William H. Adams III
and Chief Executive Officer
STEFFEN E. PALKO J. LUTHER KING, JR
- ----------------------------------------------------------------- ------------------------------------------------------------
Steffen E. Palko, Vice Chairman of the Board J. Luther King, Jr.
and President
JACK P. RANDALL
------------------------------------------------------------
Jack P. Randall
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 President
and Chief Financial Officer and Controller
71
INDEX TO EXHIBITS
Documents filed prior to June 1, 2001 were filed with the Securities and
Exchange Commission under the Company's prior name, Cross Timbers Oil Company.
Exhibit
No. Description Page
-------- ------------------------------------------------------------ ----
3.1 Restated Certificate of Incorporation of the Company, as
restated on August 22, 2001 (incorporated by reference to
Exhibit 4.1 to Registration Statement on Form S-3, File No.
333-71762)
3.2 Bylaws of the 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 the 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 the 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 the 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/*/ 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)
10.5/*/ 1998 Stock Incentive Plan, as amended February 20, 2001
(incorporated by reference to Exhibit 10.7 to Form 10-K for
the year ended December 31, 2000)
10.6/*/ 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)
10.7/*/ 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)
72
Exhibit
No. Description Page
-------- ------------------------------------------------------------ ----
10.8/*/ Form of Agreement for Grant of Performance Shares (relating
to change in control) between the Company and each of Bob R.
Simpson and Steffen E. Palko dated February 20, 2001
(incorporated by reference to Exhibit 10.1 to Form 10-Q for
the quarter ended September 30, 2001)
10.9/*/ Form of Agreement for Grant of Performance Shares (relating
to change in control) between the Company and each of Louis
G. Baldwin, Keith A. Hutton and Vaughn O. Vennerberg II dated
February 20, 2001 (incorporated by reference to Exhibit 10.2
to Form 10-Q for the quarter ended September 30, 2001)
10.10/*/ Amendment to Agreement for Grant of Performance Shares
(relating to change in control) between the Company and Bob
R. Simpson dated May 24, 2001 (incorporated by reference to
Exhibit 10.3 to Form 10-Q for the quarter ended September 30,
2001)
10.11/*/ Amendment to Agreement for Grant of Performance Shares
(relating to change in control) between the Company and
Steffen E. Palko dated May 24, 2001 (incorporated by
reference to Exhibit 10.4 to Form 10-Q for the quarter ended
September 30, 2001)
10.12/*/ Amendment to Agreement for Grant of Performance Shares
(relating to change in control) between the Company and Louis
G. Baldwin dated May 24, 2001 (incorporated by reference to
Exhibit 10.5 to Form 10-Q for the quarter ended September 30,
2001)
10.13/*/ Amendment to Agreement for Grant of Performance Shares
(relating to change in control) between the Company and Keith
A. Hutton dated May 24, 2001 (incorporated by reference to
Exhibit 10.6 to Form 10-Q for the quarter ended September 30,
2001)
10.14/*/ Amendment to Agreement for Grant of Performance Shares
(relating to change in control) between the Company and
Vaughn O. Vennerberg II dated May 24, 2001 (incorporated by
reference to Exhibit 10.7 to Form 10-Q for the quarter ended
September 30, 2001)
10.15 Registration Rights Agreement among the 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)
10.16 Warrant Agreement dated December 1, 1997 by and between the
Company and Amoco Corporation (incorporated by reference to
Exhibit 10.11 to Form 10-K for the year ended
December 31, 1997)
10.17 Revolving Credit Agreement dated May 12, 2000 between the
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)
10.18 First Amendment, dated June 20, 2000, to Revolving Credit
Agreement dated May 12, 2000 between the 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)
10.19 Second Amendment, dated February 16, 2001, to Revolving
Credit Agreement dated May 12, 2000 between the Company and
certain commercial banks named therein (incorporated by
reference to Exhibit 10.15 to Form 10-K for the year ended
December 31, 2000)
73
Exhibit
No. Description Page
-------- ------------------------------------------------------------ ----
10.20 Third Amendment, dated May 1, 2001, to Revolving Credit
Agreement dated May 12, 2000 between the Company and certain
commercial banks named therein (incorporated by reference to
Exhibit 10.1 to Form 10-Q for the quarter ended
March 31, 2001)
12.1 Computation of Ratio of Earnings to Fixed Charges
21.1 Subsidiaries of XTO Energy Inc.
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Miller and Lents, Ltd.
99 Other Exhibits
99.1 Assurance Letter regarding Arthur Andersen LLP
/*/ 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, XTO Energy Inc., 810 Houston St., Suite 2000, Fort Worth, Texas
76102.
74