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1999
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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, 1999
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OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________
Commission File Number: 1-10662
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Cross Timbers Oil Company
(Exact name of registrant as specified in its charter)
Delaware 75-2347769 810 Houston Street, Suite 2000, Fort Worth, Texas 76102
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(State or other jurisdiction of (I.R.S. Employer (Address of principal executive offices) (Zip Code)
incorporation or organization) Identification No.)
Registrant's telephone number, including area code (817) 870-2800
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Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
- --------------------------------- -----------------------------------------
Common stock, $.01 par value, New York Stock Exchange
including preferred stock
purchase rights
Series A convertible preferred New York Stock Exchange
stock, $.01 par value
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to be the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. _____
Aggregate market value of the voting stock held by nonaffiliates of the
Registrant as of March 1, 2000 was approximately $381 million
Number of Shares of Common Stock outstanding as of March 1, 2000 - 48,139,999
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 29, 2000.
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CROSS TIMBERS OIL COMPANY
1999 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..................... 16
Part II
5. Market for Registrant's Common Equity and Related Stockholder Matters... 17
6. Selected Financial Data................................................. 18
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................. 20
7A. Quantitative and Qualitative Disclosures about Market Risk.............. 28
8. Financial Statements and Supplementary Data............................. 30
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.............................................. 30
Part III
10. Directors and Executive Officers of the Registrant...................... 30
11. Executive Compensation.................................................. 30
12. Security Ownership of Certain Beneficial Owners and Management.......... 30
13. Certain Relationships and Related Transactions.......................... 30
Part IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......... 31
PART I
Items 1. and 2. Business and Properties
General
Cross Timbers Oil Company and its subsidiaries ("the Company") are engaged
in the acquisition, development, exploitation and exploration of producing oil
and gas properties, and in the production, processing, marketing and
transportation of oil and natural gas. The Company has grown primarily through
acquisitions of proved oil and gas reserves, followed by development and
exploitation activities and strategic acquisitions of additional interests in or
near such acquired properties. The Company's proved reserves are principally
located in relatively long-lived fields with well-established production
histories concentrated in western Oklahoma, the East Texas Basin, the Permian
Basin of West Texas and New Mexico, the Arkoma Basin of Arkansas and Oklahoma,
the Hugoton Field of Oklahoma and Kansas, the San Juan Basin of northwestern New
Mexico, the Green River Basin of Wyoming and the Middle Ground Shoal Field of
Alaska's Cook Inlet.
The Company's estimated proved reserves at December 31, 1999 were 61.6
million barrels ("Bbls") of oil, 1.5 trillion cubic feet ("Tcf") of natural gas
and 17.9 million Bbls of natural gas liquids, based on December 31, 1999 prices
of $24.17 per Bbl for oil, $2.20 per thousand cubic feet ("Mcf") for gas and
$13.83 per Bbl for natural gas liquids. Approximately 79% of December 31, 1999
proved reserves, computed on a gas energy equivalent ("Mcfe") basis, were proved
developed reserves. Increased proved reserves during 1999 were primarily the
result of predominantly gas-producing property acquisitions and development and
exploitation activities, partially offset by production and property sales,
including the sale of Hugoton Royalty Trust units. During 1999, the Company's
daily average production was 14,006 Bbls of oil, 288,000 Mcf of gas and 3,631
Bbls of natural gas liquids. Fourth quarter 1999 daily average production was
13,238 Bbls of oil, 332,722 Mcf of gas and 4,382 Bbls of natural gas liquids.
The Company's properties have relatively long reserve lives and highly
predictable well production profiles. Based on December 31, 1999 proved reserves
and projected 2000 production, the average reserve-to-production index of the
Company's proved reserves is 13.6 years. In general, the Company's properties
have extensive production histories and production enhancement opportunities.
While the properties are geographically diversified, the major producing fields
are concentrated within core areas, allowing for substantial economies of scale
in production and cost-effective application of reservoir management techniques
gained from prior operations. As of December 31, 1999, the Company owned
interests in 7,209 gross (3,668.3 net) wells and operated wells representing 89%
of the present value of cash flows before income taxes (discounted at 10%) from
estimated proved reserves. The high proportion of operated properties allows
the Company to control expenses, capital allocation and the timing of
development and exploitation activities in its fields. This also allows the
Company to reduce production costs on acquired properties.
The Company has generated a substantial inventory of approximately 1,300
potential development drilling locations within its existing properties (of
which 692 have been attributed proved undeveloped reserves), to support future
net reserve additions. The Company's drilling plans are dependent upon product
prices.
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 Major County, Oklahoma, East
Texas, the Arkoma Basin of Arkansas and Oklahoma and the Hugoton Field of Kansas
and Oklahoma. The Company also operates a gas processing plant in the Hugoton
Field. The Company's gas gathering and processing operations are only in areas
where the Company has production and are considered activities which add value
to the Company's natural gas production and sales operation.
Most of the Company's production is sold at current market prices. The
Company also markets its oil and gas, including sales of gas under forward sales
contracts and use of futures contracts and other price risk management
instruments to hedge pricing risks. See Part II, Item 7A. The Company markets
its gas production and the gas output
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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.
History of the Company
The Company was incorporated in Delaware in 1990 to ultimately acquire the
business and properties of predecessor entities that were created from 1986
through 1989. Cross Timbers Oil Company completed its initial public offering
of common stock in May 1993.
During 1991, predecessors of the Company formed Cross Timbers Royalty Trust
by conveying a 90% net profits interest in substantially all of the royalty and
overriding royalty interests that the Company's predecessors 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 ("Commission") to register the Company's 1,360,000 units
for sale in a public offering. The filing of the registration statement was
made in anticipation of improving commodity prices and related market conditions
for oil and gas equities.
In December 1998, the Company formed the Hugoton Royalty Trust by conveying
an 80% net profits interest in principally gas-producing operated working
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 40,000,000 units of beneficial
interest. The Company sold 17,004,000 units in 1999. Hugoton Royalty Trust
units are listed on the New York Stock Exchange under the symbol "HGT."
The Company planned to form the Texas Permian Trust by conveying an 80% net
profits interest in properties that are principally located in the Permian Basin
of West Texas and southeast New Mexico and filed a registration statement with
the Commission in August 1999 to sell 40% of the trust units. In January 2000,
the Company announced that due to the depressed market for oil and gas equities
it no longer planned to pursue the trust offering and would instead sell related
properties representing approximately 40% of the total value of the planned
trust. As of March 31, 2000, the Company will have sold properties in Texas and
New Mexico for a total sales price of $68.3 million. The Company may proceed
with the trust offering containing the remaining properties at a later date,
depending on market conditions.
Current Operating Environment
The oil and gas industry is affected by many factors that the Company
generally cannot control. Crude oil prices are generally determined by global
supply and demand. After sinking to a five-year low at the end of 1993, oil
prices began a recovery and climbed to prices above $22 during fourth quarter
1996 and January 1997. Posted crude oil prices ranged from $17 to $20 during
most of 1997, then declined to a $16 average in December 1997. Crude oil prices
continued to decline throughout 1998, dropping to a West Texas Intermediate
price of $8.00 per barrel in December 1998, the lowest level since 1978. After
a weak first quarter, oil prices increased in 1999 because of production cuts by
OPEC and other leading oil exporters, reduced inventories and anticipated
increased demand. By November 1999, crude oil prices reached their highest
levels since the 1990 Persian Gulf War and have remained at levels above $24 in
first quarter 2000. Members of OPEC met on March 27, 2000 and agreed to increase
production by 6.3%. Because of increased summer demand, increased production is
not expected to substantially increase domestic inventories until fourth quarter
2000.
Natural gas prices are influenced by North American supply and demand,
which is often dependent upon weather conditions. Natural gas competes with
alternative energy sources as a fuel for heating and the generation of
electricity. Generally because of colder weather, storage concerns and U.S.
economic growth, prices remained relatively high during most of 1996 and 1997,
reaching their highest levels since 1985. Gas prices declined, however, in
December 1997 and remained lower throughout 1998 and first quarter 1999,
primarily because the winters of 1997-1998 and 1998-1999 were abnormally mild in
the central and eastern U.S. Cooler spring weather and lower industry
production levels strengthened gas prices in second quarter 1999. This trend
continued into third quarter 1999 when
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the NYMEX gas price rose above $3.00 per Mmbtu. Natural gas prices have remained
volatile during the winter of 1999-2000 as a third consecutive warm winter
reduced seasonal heating demand. In spite of a warm winter, natural gas
inventories are expected to be substantially lower at the end of the 2000
withdrawal season than in 1999. Lower inventories of approximately 1 Tcf,
compared with 1.3 Tcf in March 1999, are attributable to lower domestic
productive capacity. Lower production, reduced inventories and increasing summer
demand are expected to result in volatile natural gas prices averaging higher
than 1999 levels. At March 15, 2000, the average NYMEX price for the following
12 months was $2.97 per Mmbtu.
Business Strategy
The primary components of the Company's business strategy are:
- acquiring long-lived, operated oil and gas properties,
- increasing production and reserves through aggressive management of
operations and through development, exploitation and exploration
activities, and
- retaining management and technical staff that have substantial
experience in the Company's core areas.
Acquiring Long-Lived, Operated Properties. The Company seeks to acquire
long-lived, operated producing properties that:
- contain complex multiple-producing horizons with the potential for
increases in reserves and production,
- are in the Company's core operating areas or in areas with similar
geologic and reservoir characteristics, and
- present opportunities to reduce expenses, per Mcfe produced, through
more efficient operations.
The Company believes that the properties it acquires provide opportunities
to increase production and reserves through the implementation of mechanical and
operational improvements, workovers, behind-pipe completions, secondary recovery
operations, new development wells and other development activities. The Company
also seeks to acquire facilities related to gathering, processing, marketing and
transporting oil and gas in areas where it owns reserves. Such facilities can
enhance profitability, reduce gathering, processing, marketing and
transportation costs, and provide marketing flexibility and access to additional
markets. The Company's ability to successfully purchase properties is dependent
upon, among other things, competition for such purchases and the availability of
financing to supplement internally generated cash flow.
Increasing Production and Reserves. A principal component of the Company's
strategy is to increase production and reserves through aggressive management of
operations and low-risk development. The Company believes that its principal
properties possess geologic and reservoir characteristics that make them well
suited for production increases through development and drilling programs. The
Company has generated an inventory of approximately 1,300 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 2000, the Company plans to focus on
exploration projects that are near currently owned productive fields and have
the potential to add substantially to proved reserves and cash flow. The
Company believes that it can prudently and successfully add growth potential
through exploratory activities given improved technology, its experienced
technical staff and its expanded base of operations. The Company has allocated
approximately 5% of its $120 million 2000 development budget for exploration
activities.
3
Experienced Management and Technical Staff. Most senior management and
technical staff have worked together for over 20 years and have substantial
experience in the Company's core operating areas. Bob R. Simpson and Steffen E.
Palko, who were co-founders of the Company and its predecessors, were previously
executive officers of Southland Royalty Company, one of the largest U.S.
independent oil and gas producers prior to its acquisition by Burlington
Northern, Inc. in 1985.
Other Strategies. The Company may also acquire working interests in
producing properties that it will not operate ("nonoperated interests") if such
interests otherwise meet its acquisition criteria. The Company attempts to
acquire nonoperated interests in fields operated by established oil companies if
these fields represent a significant investment to the operator and are
therefore more likely to be carefully managed by it. The Company may also
acquire nonoperated interests with the intent of ultimately accumulating,
through future acquisitions, sufficient interests to obtain the right to operate
the properties. The Company attempts to acquire nonoperated interests where
geologic conditions indicate the potential for undeveloped reserves that the
operator will exploit.
The Company also attempts to acquire a portion of its oil and gas reserves
in the form of royalty interests. Royalty interests offer less exposure to
operational liabilities because they do not participate in operating activities
and do not bear production or development costs. However, royalty interests
typically allow only limited influence on the operation or development of
properties.
Royalty 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. Sales of
royalty trust units allow the Company to more efficiently capitalize its mature,
lower growth properties. The Company's previously announced plans to create
additional royalty trusts have been indefinitely postponed until the market for
oil and gas equities improves.
Business Goals. In August 1999, the Company announced strategic goals for
2000, including cash flow from operations of $4.00 per share, year-end proved
reserves of 40 Mcfe per share and debt of 40 cents per Mcfe. These goals were
based on NYMEX prices of $21 per Bbl of oil and $2.70 per Mcf of gas. For 1999,
operating cash flow from operations before changes in operating assets and
liabilities and exploration expense was $2.83 per share, while year-end proved
reserves per share were 41 Mcfe and debt per Mcfe was $0.49. The Company plans
to reduce debt with operating cash flow and proceeds from the sale of producing
properties.
The Company has budgeted $120 million for its 2000 development program,
which is expected to be funded primarily by cash flow from operations.
Exploration expenditures are expected to be approximately 5% of the 2000 budget.
The total capital budget, including acquisitions, will be adjusted throughout
2000 depending on oil and gas prices to capitalize on opportunities offering the
highest rates of return.
In February 2000, the Board of Directors authorized the repurchase of 2.5
million shares of common stock, or approximately 5% of the Company's outstanding
shares. These shares will be purchased from time to time in open market or
negotiated transactions. As of March 27, 2000, 1.2 million shares remain to be
purchased under this authorization.
Acquisitions
During 1995, the Company acquired predominantly gas-producing properties
for a total cost of $131 million, and a gas processing plant and gathering
facility for $29 million. The Santa Fe Acquisition, the largest of these
acquisitions, closed in August 1995 and consisted of mostly operated producing
properties, a gas processing plant and gathering system in the Hugoton Field of
Kansas and Oklahoma. The 1995 acquisitions increased proved reserves by
approximately 3 million Bbls of oil and 171 billion cubic feet ("Bcf") of
natural gas. The gas gathering plant and gathering system was sold in March 1996
and is being leased by the Company.
During 1996, the Company acquired predominantly gas-producing properties
for a total cost of $106 million. The Enserch Acquisition, the largest of these
acquisitions, closed in July 1996 at a cost of $39.4 million and primarily
consisted of operated interests in the Green River Basin of southwestern
Wyoming. In November 1996, the Company acquired additional interests in the
Fontenelle Unit, the most significant property included in the Enserch
Acquisition, at a cost of $12.5 million. In December 1996, the Company acquired
primarily operated interests in gas-producing properties in the Ozona area of
the Permian Basin of West Texas for $28.1 million. The Company sold these
properties
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for $43 million in March 2000. From July through December 1996, the Company
acquired 955,800 units, or 16% of the publicly traded outstanding units, of
Cross Timbers Royalty Trust, at a total cost of $12.8 million. The 1996
acquisitions increased proved reserves by approximately 1.6 million Bbls of oil
and 153.4 Bcf of natural gas.
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 944,284 shares of the
Company's common stock at a price of $15.20 per share. This acquisition
consisted primarily of operated properties in the San Juan Basin of New Mexico.
In May 1997, the Company acquired primarily gas-producing properties in
Oklahoma, Kansas and Texas for an adjusted purchase price of $39 million. The
Company also acquired an additional 370,500 units, or 6%, of the Cross Timbers
Royalty Trust units at a cost of $5.4 million. The 1997 acquisitions increased
proved reserves by approximately 3.2 million Bbls of oil, 248 Bcf of natural gas
and 13.9 million Bbls of natural gas liquids.
During 1998, the Company acquired oil and gas-producing properties for a
total cost of $340 million. The East Texas Basin Acquisition was the largest of
these acquisitions. The purchase closed in April 1998 at a price of $245
million which was reduced to $215 million by a $30 million production payment
sold to EEX Corporation. In September 1998, the Company acquired oil-producing
properties in the Middle Ground Shoal Field of Alaska's Cook Inlet in exchange
for 1,921,850 shares of the Company's common stock along with certain price
guarantees and a non-interest bearing note payable of $6 million, resulting in a
total purchase price of $45 million. The Company also acquired primarily gas-
producing properties in northwest Oklahoma and the San Juan Basin of New Mexico
for an estimated purchase price of $31 million. The 1998 acquisitions increased
reserves by approximately 16.3 million Bbls of oil and 311.3 Bcf of natural gas.
In 1999, the Company and Lehman Brothers Holdings, Inc. ("Lehman") acquired
the common stock of Spring Holding Company ("Spring"), a private oil and gas
company, for a combination of cash and Cross Timbers' common stock totaling $85
million. The Company and Lehman each owned 50% of a limited liability company
that acquired the common stock of Spring. In September 1999 the Company
exercised its option to acquire Lehman's 50% interest in Spring for $44.3
million. This acquisition includes oil and gas properties located in the Arkoma
Basin of Arkansas and Oklahoma with a purchase price of $235 million. After
purchase accounting adjustments and other costs, the cost of the properties was
$253 million. The Company also acquired, with Lehman as 50% owner, Arkoma Basin
properties from affiliates of Ocean Energy, Inc. for $231 million. The Company
plans to exercise its option to acquire Lehman's interest in the Ocean Energy
Acquisition on March 31, 2000 for $111 million. The 1999 acquisitions,
including Lehman's 50% interest in the Spring and Ocean Energy acquisitions,
increased reserves by approximately 2.8 million Bbls of oil and 494.7 Bcf of
natural gas.
Many of the properties acquired from 1995 through 1998 in Kansas, Oklahoma
and Wyoming are subject to the 80% net profits interest conveyed to Hugoton
Royalty Trust. The Company sold 42.5% of its Hugoton Royalty Trust units in
April and May 1999.
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Significant Properties
The following table summarizes proved reserves and discounted present
value, before income tax, of proved reserves by the Company's major operating
areas at December 31, 1999 (in thousands):
Proved Reserves
----------------------------------- Discounted
Natural Gas Present Value
Oil Gas Liquids before Income Tax of
(Bbls) (Mcf) (Bbls) Proved Reserves
---------- --------- ----------- ----------------------
Permian Basin.................... 38,738 99,681 - $ 393,602 22.3%
Arkoma Basin (a)................. 4 433,083 - 346,064 19.6%
East Texas....................... 2,575 401,617 - 337,434 19.1%
Hugoton Royalty Trust (b)........ 2,819 333,503 - 269,754 15.3%
San Juan Basin................... 1,315 259,031 17,902 257,426 14.6%
Alaska Cook Inlet................ 14,001 - - 126,309 7.1%
Cross Timbers Royalty Trust (c).. 1,788 12,751 - 24,936 1.4%
Other............................ 363 5,957 - 10,411 0.6%
---------- --------- ----------- ----------------------
Total............................ 61,603 1,545,623 17,902 $ 1,765,936 100.0%
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(a) Includes 1,700 Bbls of oil and 111,814,000 Mcf of gas and discounted
present value before income tax of $91,127,000 related to a 50%
minority interest in the Ocean Energy Acquisition at December 31,
1999. The Company plans to purchase the 50% minority interest on March
31, 2000.
(b) Includes 1,964,000 Bbls of oil and 232,429,000 Mcf of gas and
discounted present value before income tax of $188,001,000 related to
the Company's ownership of approximately 57% of Hugoton Royalty Trust
units at December 31, 1999.
(c) Includes 783,000 Bbls of oil and 8,162,000 Mcf of gas and discounted
present value before income tax of $13,742,000 related to the
Company's ownership of approximately 22% of Cross Timbers Royalty
Trust units at December 31, 1999.
Permian Basin Area
Prentice Field. The Prentice Field is located in Terry and Yoakum
Counties, Texas. In 1993 and 1994, the Company acquired its 91.5% working
interest in the 178-well Prentice Northeast Unit in four separate transactions,
resulting in the Company's assumption of operations of the unit effective March
1, 1994. The Company also owns an interest in 81 gross (2.0 net) nonoperated
wells.
Discovered in 1950, the Prentice Field produces from carbonate reservoirs
in the Clear Fork and Glorieta formations at depths ranging from 6,000 to 7,000
feet. The Prentice Field has been separated into several waterflood units for
secondary recovery operations. The Prentice Northeast Unit was formed in 1964
with waterflood operations commencing a year later. Development potential
exists through infill drilling and improvement of waterflood efficiency.
Tertiary recovery potential also exists through carbon dioxide flooding.
During 1999, the Company drilled 8 gross (7.3 net) vertical wells and 1
gross (0.91 net) horizontal sidetrack in the Prentice Northeast Unit. At the
end of 1999, four vertical wells were still being completed. During 2000, the
Company may drill as many as 10 wells in this field.
Ozona Area. The Company acquired interests in 1996 in the Henderson,
Ozona, and Davidson Ranch fields located in Crockett County, Texas. The Company
has interests in 125 gross (72.7 net) wells that it operates and 140 gross (28.5
net) wells operated by others. Most of these interests were sold in March 2000.
University Block 9. The University Block 9 Field is located in Andrews
County, Texas and was discovered in 1953. The Company owns interests in 60
gross (58.0 net) wells that it operates. Productive zones are of Wolfcamp,
Pennsylvanian and Devonian age at 8,400, 8,700 and 10,400 feet, respectively.
Development potential includes proper wellbore utilization, recompletions,
infill drilling and improvement of waterflood efficiency.
6
This field was the Company's most active oil development area during 1999,
where the Company drilled six wells, including three horizontal sidetrack wells.
The Company also recompleted seven Devonian wells into the Pennsylvanian
horizon. During 2000, the Company plans to drill up to 17 wells and to perform
six recompletions.
Arkoma Basin Area
During 1999, the Company acquired interests in approximately 2,500 wells
and a gas gathering system in the Arkoma Basin of Arkansas and Oklahoma. The
Arkoma Basin, discovered in the 1920's, stretches from central Arkansas into
eastern Oklahoma and is known for shallow production decline rates, multiple
formations and complex geology. With these acquisitions, the Company controls
40% of Arkansas production from the Arkoma Basin.
The acquired properties can be separated into three distinct areas, which
are the Oklahoma Cromwell/Atoka trend, the Arkansas Fairway trend and the
Arkansas Overthrust trend. The Oklahoma Cromwell/Atoka trend of eastern
Oklahoma was originally developed in the 1970's targeting the Cromwell Sands and
Atoka formations. The Arkansas Fairway trend is comprised of multiple
sandstones at depths ranging from 2,500 to 7,500 feet in the Atoka and Morrow
intervals. The Arkansas Overthrust trend is characterized by extremely complex
geology and will require an ongoing process to develop the best exploitation
opportunities.
In the latter half of 1999, the Company drilled 14 wells (10 operated),
completed 10 workovers and drilled a successful exploration well on the Fort
Chaffe Prospect. The Company has identified 150 well locations and over 200
workover opportunities. The Company plans to drill 45 wells and perform 75
workovers in the Arkoma Basin during 2000.
East Texas Area
The Company acquired most of its producing properties in the East Texas
area in April 1998. These properties are located in East Texas and northwestern
Louisiana and produce primarily from the Travis Peak, Cotton Valley and Rodessa
formations between 7,000 feet and 12,000 feet in eight major fields. Oil and
gas were first discovered in the East Texas area in the 1930's. The Company
owns an interest in 618 gross (594 net) wells which it operates and 39 gross
(4.4 net) wells operated by others. The Company also owns the related gathering
facilities.
During 1999, the East Texas area was the Company's most active gas
development area, where 31 gross (30.1 net) gas wells were drilled and 100
workovers were performed. The formations targeted were the Travis Peak, Cotton
Valley and Bossier. The Company plans to continue to extensively develop this
area, including drilling approximately 40 wells in 2000.
Hugoton Royalty Trust
A substantial portion of properties in the Mid-Continent area, the Hugoton
area and the Green River Basin of the Rocky Mountain area are subject to an 80%
net profits interest conveyed to the Hugoton Royalty Trust as of December 1998.
The Company sold 42.5% of its Hugoton Royalty Trust units in April and May 1999.
Mid-Continent Area
The Company is one of the largest producers in the Ringwood, Northwest
Okeene and Cheyenne Valley fields in Major County, Oklahoma. The Company
operates 458 gross (400.9 net) wells and has an interest in 112 gross (31.3 net)
wells operated by others.
Oil and gas were first discovered in the Major County area in 1945. The
fields in the Major County area are located in the Anadarko Basin and are
characterized by oil and gas production from a variety of structural and
stratigraphic traps. Productive zones range from 6,500 to 9,400 feet and
include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and
Arbuckle formations.
The Company develops the Major County area primarily through mechanical
improvements, restimulations, recompletions to shallower zones and development
drilling. During 1999, the Company participated in the drilling of
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8 gross (6.1 net) wells in the northwestern portion of the County, targeting the
Chester, Inola, Oswego and Red Fork formations. The Company has budgeted 13
drill wells in Major County for 2000.
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 20,000 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. It is estimated that five
million productive acres exist in the entire field. The Company owns an
interest in 380 gross (356.5 net) wells that it operates and 76 gross (18.1 net)
wells operated by others.
Approximately 70% of the Company's Hugoton gas production is delivered to
the Tyrone Plant, a gas processing plant operated by the Company. In May 1996,
the Company completed the installation of a field compressor on the south end of
the Tyrone gathering system. The Company also completed the installation and
start-up of a residue compressor and 11.5 miles of high pressure residue
pipeline during August 1996. The installation of these facilities allows the
Company to operate the Tyrone Plant more efficiently and allows access to three
additional interstate pipelines. During 1998, the Company completed the
acquisition of approximately 70 miles of low pressure gathering lines,
increasing production by 3,500 Mcf per day. During 1999, the Company installed
three lateral compressors that lowered the wellhead pressure in various areas of
the field.
While much of the Kansas portion of the Hugoton Field has been infill
drilled on 320-acre spacing, the Company believes that there are up to 35
additional potential infill drilling locations. In June 1999, Oklahoma
regulations were amended to allow increased drilling density in the Oklahoma
portion which was previously drilled on 640-acre spacing. The Company believes
it has approximately 200 potential infill drilling locations in Oklahoma.
During 1999, the Company drilled 5 gross (4.0 net) wells to the Chester,
Council Grove and Oswego formations. The Company plans to drill three wells
during 2000.
Green River Basin
The Green River Basin is located in southwestern Wyoming. The Company has
interests in 175 gross (170.5 net) wells that it operates and 47 gross (5.2 net)
wells operated by others in the Fontenelle field.
Gas production began in the Fontenelle area in the early 1970's. The
producing reservoirs are the Cretaceous Frontier and Dakota sandstones at depths
ranging from 7,500 to 10,000 feet. Development potential for the fields in this
area include deepening and opening new producing zones in existing wells,
drilling new wells and adding compression to lower line pressures.
During 1999, the Company drilled seven gross (6.9 net) wells in the
Fontenelle Unit and plans to drill five wells during 2000. In 1997, the Company
installed additional field compression to lower overall field operating
pressures and to improve overall field performance. The Company also completed
an interconnect to another pipeline in the southeastern part of the Fontenelle
Field that added an additional market for the gas.
San Juan Basin Area
The San Juan Basin of northwestern New Mexico and southwestern Colorado
contains the largest reserves of natural gas in the Rocky Mountains and, within
North America, is second in size only to the Hugoton Field. The Company acquired
most of its interests in the San Juan Basin in December 1997 from a subsidiary
of Amoco Corporation. The Company owns an interest in 653 gross (521.8 net)
wells that it operates and 338 gross (89.1 net) wells operated by others. Of
these wells, 77 gross (67.2 net) operated wells and 4 gross (0.2 net)
nonoperated wells are dual completions.
8
During 1999, the Company participated in the drilling of 19 gross (15.8
net) wells, completed 31 workovers and installed over 74 wellhead compressors.
During 2000, the Company plans to drill 42 wells and perform 30 workovers. The
Company also plans to continue to install wellhead compressors at approximately
the same level as 1999.
Alaska Cook Inlet Area
In September 1998, the Company acquired a 100% working interest in two
State of Alaska leases and the offshore installations located in the Middle
Ground Shoal Field of the Cook Inlet. The properties include two operated
production platforms set in 70 feet of water about seven miles offshore and a
50% interest in certain operated production pipelines and onshore processing
facilities.
Oil was discovered in the Cook Inlet in 1966. Production from the 29
operated wells is primarily from multiple zones within the Miocene-Oligocene-
aged Tyonek formation between 7,300 feet and 10,000 feet subsea.
Six workovers were performed in 1999 and drilling rigs on both platforms
were refurbished in preparation for continued development in 2000. The Company
also conducted engineering and geologic studies of the Cook Inlet during 1999
and plans to drill three wells in 2000.
Reserves
The following are definitions adopted by the Commission and the Financial
Accounting Standards Board which are applicable to terms used in the following
discussion of oil and natural gas reserves:
Proved reserves- Estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geologic and engineering data,
appear with reasonable certainty to be recoverable in the future from known oil
and gas reservoirs under existing economic and operating conditions.
Proved developed reserves- Proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves- Proved reserves which are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required.
Estimated future net revenues- Also referred to herein as "estimated
future net cash flows." Computational result of applying current prices of oil
and gas (with consideration of price changes only to the extent provided by
existing contractual arrangements) to estimated future production from proved
oil and gas reserves as of the date of the latest balance sheet presented, less
estimated future expenditures (based on current costs) to be incurred in
developing and producing the proved reserves.
Present value of estimated future net cash flows- Also referred to herein
as "standardized measure of discounted future net cash flows" or "standardized
measure." Computational result of discounting estimated future net revenues at
a rate of 10% annually.
9
The following are estimated quantities of proved reserves and cash flows
therefrom as of December 31, 1999, 1998 and 1997:
December 31
----------------------------------
1999 1998 1997
---------- ---------- ----------
(in thousands)
Proved developed:
Oil (Bbls)......................... 48,010 42,876 33,835
Gas (Mcf).......................... 1,225,014 968,495 677,710
Natural gas liquids (Bbls)......... 13,781 14,000 11,494
Proved undeveloped:
Oil (Bbls)......................... 13,593 11,634 14,019
Gas (Mcf).......................... 320,609 240,729 138,065
Natural gas liquids (Bbls)......... 4,121 3,174 2,316
Total proved:
Oil (Bbls)......................... 61,603 54,510 47,854
Gas (Mcf).......................... 1,545,623 1,209,224 815,775
Natural gas liquids (Bbls)......... 17,902 17,174 13,810
Estimated future net cash flows:
Before income tax.................. $3,269,443 $1,677,426 $1,484,542
After income tax................... $2,550,551 $1,446,177 $1,193,167
Present value of estimated future
net cash flows, discounted at 10%:
Before income tax.................. $1,765,936 $ 908,606 $ 782,322
After income tax................... $1,396,940 $ 808,403 $ 642,109
Miller and Lents, Ltd. ("Miller and Lents"), an independent petroleum
engineering firm, prepared the estimates of the Company's proved reserves and
the future net cash flow (and present value thereof) attributable to proved
reserves at December 31, 1999, 1998 and 1997. As prescribed by the Commission,
such proved reserves were estimated using oil and gas prices and production and
development costs as of December 31 of each such year, without escalation. See
Note 19 to Consolidated Financial Statements for additional information
regarding estimated proved reserves.
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company.
Reserve engineering is a subjective process of estimating subsurface
accumulations of oil and gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of available data
and the interpretation thereof. As a result, estimates by different engineers
often vary, sometimes significantly. In addition, physical factors such as the
results of drilling, testing and production subsequent to the date of an
estimate, as well as economic factors such as change in product prices, may
justify revision of such estimates. Accordingly, oil and gas quantities
ultimately recovered will vary from reserve estimates.
During 1999, the Company filed estimates of oil and gas reserves as of
December 31, 1998 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, 1998 in Note 19 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 of the Company's wells produce both oil and gas, a well is categorized as
an oil well or a gas well based upon the ratio of oil to gas production.
10
Producing Wells
The following table summarizes the Company's producing wells as of December
31, 1999, all of which are located in the United States:
Operated Wells Nonoperated Wells Total (a)
------------------------ ------------------------ ------------------------
Gross Net Gross Net Gross Net
----------- ----------- ----------- ----------- ----------- -----------
Oil.... 550 507.0 1,904 155.2 2,454 662.2
Gas.... 3,254 2,695.6 1,501 310.5 4,755 3,006.1
----------- ----------- ----------- ----------- ----------- -----------
Total.. 3,804 3,202.6 3,405 465.7 7,209 3,668.3
=========== =========== =========== =========== =========== ===========
(a) One gross (0.5 net) oil wells and 334 gross (200.1 net) gas wells are
dual completions.
Drilling Activity
The following table summarizes the number of development wells drilled by
the Company during the years indicated. As of December 31, 1999, the Company
was in the process of drilling 37 gross (22.2 net) wells.
Year Ended December 31
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Development wells:
Completed as-
Oil wells................. 18 6.7 53 14.1 82 53.4
Gas wells................. 128 91.2 139 63.4 119 85.9
Non-productive............. 7 3.5 1 - 5 3.2
--- ----- ---- ---- --- -----
Total...................... 153 101.4 193 77.5 206 142.5
--- ----- ---- ---- --- -----
Exploratory wells:
Completed as-
Gas wells................. 1 1.0 3 3.0 2 0.6
Non-productive............. - - 2 1.0 1 0.1
--- ----- ---- ---- --- -----
Total...................... 1 1.0 5 4.0 3 0.7
--- ----- ---- ---- --- -----
Total (a)................... 154 102.4 198 81.5 209 143.2
=== ===== ==== ==== === =====
(a) Included in totals are 44 gross (4.1 net) wells in 1999, 118 gross (14.6
net) in 1998 and 57 gross (6.9 net) wells in 1997 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, 1999. Excluded
from this summary is acreage in which the Company's interest is limited to
royalty, overriding royalty and other similar interests.
Developed (a)(b) Undeveloped
------------------ -------------------
Gross Net Gross Net
--------- ------- --------- -------
Arkansas.... 517,680 224,338 20,495 15,678
Oklahoma.... 464,817 324,846 12,824 5,529
Texas....... 221,078 137,466 37,427 22,455
New Mexico.. 206,345 149,215 2,447 869
Kansas...... 66,670 58,169 - -
Wyoming..... 54,974 35,090 2,211 1,531
Other....... 41,658 23,203 9,840 6,964
--------- ------- --------- -------
Total (c)... 1,573,222 952,327 85,244 53,026
========= ======= ========= =======
(a) Developed acres are acres spaced or assignable to productive wells.
(b) Certain leasehold acreage in Oklahoma and Texas is subject to a 75% net
profits interest conveyed to the Cross Timbers Royalty Trust, and in
Oklahoma, Kansas and Wyoming is subject to an 80% net profits interest
conveyed to the Hugoton Royalty Trust.
(c) Includes developed and undeveloped acreage in Arkansas and Oklahoma
related to a 50% minority interest in the Ocean Energy Acquisition at
December 31, 1999. The Company plans to acquire the 50% minority
interest on March 31, 2000.
Oil and Gas Sales Prices and Production Costs
The following table shows the average sales prices per Bbl of oil
(including condensate), Mcf of gas and per Bbl of natural gas liquids produced
and the production costs and taxes, transportation and other per thousand cubic
feet of gas equivalent ("Mcfe," computed on an energy equivalent basis of six
Mcf to one Bbl):
Year Ended December 31
----------------------
1999 1998 1997
------ ------ ------
Sales prices:
Oil (per Bbl)........................... $16.94 $12.21 $18.90
Gas (per Mcf)........................... $ 2.13 $ 2.07 $ 2.20
Natural gas liquids (per Bbl)........... $11.80 $ 7.62 $ 9.66
Production costs per Mcfe................. $ 0.53 $ 0.53 $ 0.59
Taxes, transportation and other per Mcfe.. $ 0.23 $ 0.25 $ 0.22
Delivery Commitments
The Company contracted to sell to a single purchaser approximately 11,650
Mcf of gas per day through May 2000 and 21,650 Mcf of gas per day from June 2000
through July 2005. Deliveries under this contract are generally in Oklahoma.
The Company has committed to sell all gas production from certain
properties in the East Texas Basin Acquisition to EEX Corporation at market
prices through the earlier of December 31, 2001, or until a total of
approximately 34.3 Bcf (27.8 Bcf net to the Company's interest) of gas has been
delivered. Based on current production, this sales commitment is approximately
24,700 Mcf (20,000 Mcf net to the Company's interest) per day.
12
Under the terms of its amended purchase and sale agreement with affiliates
of Shell Oil Company ("Shell") for the Cook Inlet Acquisition, the Company has
committed to sell to Shell the following minimum daily natural gas volumes:
40,000 Mcf in 2000, 37,500 Mcf in 2001, 36,500 Mcf in 2002 and 35,000 Mcf in
2003. Delivery of 20,000 Mcf per day of committed sales volumes is in the San
Juan Basin, and delivery of the remaining volumes is in the East Texas Basin.
As a part of the Ocean Energy Acquisition, the Company assumed a commitment
to sell 6,800 Mcf of gas per day through April 2003 at a price of $0.53 per Mcf.
Delivery of the committed sales volumes is in Arkansas.
The Company's production and reserves are adequate to meet the above sales
commitments.
Competition and Markets
The Company faces competition from other oil and gas companies in all
aspects of its business, including acquisition of producing properties and oil
and gas leases, marketing of oil and gas, and obtaining goods, services and
labor. Many of its competitors have substantially larger financial and other
resources. Factors that affect the Company's ability to acquire producing
properties include available funds, available information about the property and
the Company's standards established for minimum projected return on investment.
Gathering systems are the only practical method for the intermediate
transportation of natural gas. Therefore, competition for natural gas delivery
is presented by other pipelines and gas gathering systems. Competition is also
presented by alternative fuel sources, including heating oil and other fossil
fuels. Because of the long-lived, high margin nature of the Company's oil and
gas reserves and management's experience and expertise in exploiting these
reserves, management believes that it is effective in competing in the market.
The Company's ability to market oil and gas depends on many factors beyond
its control, including the extent of domestic production and imports of oil and
gas, the proximity of the Company's gas production to pipelines, the available
capacity in such pipelines, the demand for oil and gas, the effects of weather,
and the effects of state and federal regulation. The Company cannot assure that
it will always be able to market all of its production or obtain favorable
prices. The Company, however, does not currently believe that the loss of any
of its oil or gas purchasers would have a material adverse effect on its
operations.
Decreases in oil and gas prices have had and could have in the future an
adverse effect on the Company's acquisition and development programs, proved
reserves, revenues, profitability, cash flow and dividends. See Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, "General - Product Prices."
Federal and State Regulations
There have been, and continue to be, numerous federal and state laws and
regulations governing the oil and gas industry that are often changed in
response to the current political or economic environment. Compliance with this
regulatory burden is often difficult and costly and may carry substantial
penalties for noncompliance. The following are some specific regulations that
may affect the Company. The Company cannot predict the impact of these or
future legislative or regulatory initiatives.
Federal Regulation of Natural Gas
The interstate transportation and sale for resale of natural gas is subject
to federal regulation, including transportation rates charged and various other
matters, by the Federal Energy Regulatory Commission ("FERC"). The Company's
gathering systems and 26-mile pipeline in Major County, Oklahoma have been
declared exempt from FERC jurisdiction. Other gathering systems of the Company
are not subject to regulation. Federal wellhead price controls on all domestic
gas were terminated on January 1, 1993. The Company cannot predict the impact
of government regulation on any natural gas facilities.
In 1992, FERC issued Orders Nos. 636 and 636-A, requiring operators of
pipelines to unbundle transportation services from sales services and allow
customers to pay for only the services they require, regardless of whether the
customer purchases gas from such pipelines or from other suppliers. The United
States Court of Appeals upheld the unbundling provisions and other components of
FERC's orders but remanded several issues to FERC for further
13
explanation. On February 27, 1997, FERC issued Order No. 636-C, addressing the
court's concern. Petitions for rehearing on Order No. 636-C were denied on May
28, 1998. FERC's order remains subject to judicial review and may be changed as
a result of that review. Although FERC's regulations should generally facilitate
the transportation of gas produced from the Company's properties and the direct
access to end-user markets, the impact of these regulations on marketing the
Company's production or on its gas transportation business cannot be predicted.
The Company, however, does not believe that it will be affected any differently
than other natural gas producers and marketers with which it competes.
Federal Regulation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The net price received from the sale of
these products is affected by market transportation costs. A significant part
of the Company's oil production is transported by pipeline. The Energy Policy
Act of 1992 required FERC to adopt a simplified ratemaking methodology for
interstate oil pipelines. In 1993 and 1994, FERC issued Orders Nos. 561 and 561-
A, adopting rules that establish new rate methods for such pipelines. Under the
new rules, effective January 1, 1995, interstate oil pipelines can change rates
based on an inflation index, though other rate mechanisms may be used in
specific circumstances. The United States Court of Appeals upheld FERC's orders
in 1996. These rules have had little, if any, effect on the Company with respect
to the cost of moving oil to market.
State Regulation
Oil and gas operations are subject to various types of regulation at the
state and local levels. Such regulation includes requirements for drilling
permits, the method of developing new fields, the spacing and operations of
wells and waste prevention. The production rate may be regulated and the
maximum daily production allowable from oil and gas wells may be established on
a market demand or conservation basis. These regulations may limit production
by well and the number of wells or locations that can be drilled.
The Company may become 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 regulations with respect to
gathering systems. New regulations passed have not had a material effect on the
operations of the Company's gathering systems, but the Company cannot predict
whether any further rules will be adopted or, if adopted, the effect these rules
may have on its gathering systems.
Federal, State or Indian Leases
The Company's operations on federal, state or Indian oil and gas leases are
subject to numerous restrictions, including nondiscrimination statutes. Such
operations must be conducted pursuant to certain on-site security regulations
and other permits and authorizations issued by the Bureau of Land Management,
Minerals Management Service and other agencies.
Environmental Regulations
Various federal, state and local laws regulating the discharge of materials
into the environment, or otherwise relating to the protection of the
environment, directly impact oil and gas exploration, development and production
operations, and consequently may impact the Company's operations and costs.
Management believes that the Company is in substantial compliance with
applicable environmental laws and regulations. To date, the Company has not
expended any material amounts to comply with such regulations, and management
does not currently anticipate that future compliance will have a materially
adverse effect on the consolidated financial position or results of operations
of the Company.
14
Employees
The Company had 600 employees as of December 31, 1999. None of the
employees are represented by a union. The Company considers its relations with
its employees to be good.
Executive Officers of the Company
The executive officers of the Company are elected by and serve until their
successors are elected by the Board of Directors.
Bob R. Simpson, 51, 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, 49, 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, 50, 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, 41, 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, 45, has been Executive Vice President -
Administration or held similar positions with the Company since 1987. Prior to
that time, Mr. Vennerberg was Land Manager with Hutton Gas Operating Company
(1986-1987).
Bennie G. Kniffen, 49, has been Senior Vice President and Controller or
held similar positions with the Company since 1986. From 1976 to 1986, Mr.
Kniffen held the position of Director of Auditing or similar positions with
Southland Royalty Company.
Larry B. McDonald, 53, has been Senior Vice President - Operations or held
similar positions with the Company since 1990. Prior to that time, Mr. McDonald
owned and operated McDonald Energy, Inc. (1986-1990).
Timothy L. Petrus, 45, has been Senior Vice President - Acquisitions or
held similar positions with the Company since 1988. Prior to that time, Mr.
Petrus was a Vice President with Texas American Bank (1980-1988) and was a
Senior Project Engineer with Exxon (1976-1980).
Kenneth F. Staab, 43, has been Senior Vice President - Engineering or held
similar positions with the Company since 1986. Prior to that time, Mr. Staab
was a Reservoir Engineer with Southland Royalty Company (1982-1986).
Thomas L. Vaughn, 53, has been Senior Vice President - Operations or held
similar positions with the Company since 1988. From 1986 to 1988, Mr. Vaughn
owned and operated Vista Operating Company.
15
Item 3. Legal Proceedings
On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross
Timbers Oil Company, was filed against the Company in the District Court of
Dewey County, Oklahoma. The action was filed on behalf of all persons who, at
any time since June 1991, have been paid royalties on gas produced from any gas
well within the State of Oklahoma under which the Company has assumed the
obligation to pay royalties. The plaintiffs allege that the Company has reduced
royalty payments by post-production deductions and has entered into contracts
with subsidiaries that were not arms-length transactions, which actions reduced
the royalties paid to the plaintiffs and those similarly situated, and that such
actions are a breach of the leases under which the royalties are paid. 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 other third party gatherers or processors. The
Company further contends that any such fees enhance the value of the gas or the
products derived from the gas. The plaintiffs are seeking an accounting and
payment of the monies allegedly owed to them. A hearing on the class
certification issue has not been scheduled. Management believes it has strong
defenses against this claim and intends to vigorously defend the action.
Management's estimate of the potential liability from this claim has been
accrued in the Company's financial statements.
On October 17, 1997, an action, styled United States of America ex rel.
Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District
Court for the Western District of Oklahoma against the Company and certain of
its subsidiaries by Jack J. Grynberg on behalf of the United States under the
qui tam provisions of the False Claims Act. The plaintiff alleges that the
Company underpaid royalties on gas produced from federal leases and lands owned
by Native Americans by at least 20% during the past 10 years as a result of
mismeasuring the volume of gas and incorrectly analyzing its heating content.
The plaintiff 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 has made similar allegations in over
70 actions filed against over 300 other companies. After its review, the
Department of Justice decided in April 1999 not to intervene, and the court
unsealed the case in May 1999. A federal multi-district litigation panel has
ordered that the lawsuits filed by Grynberg against the Company and other
companies be transferred and consolidated to the federal district court in
Wyoming. The Company and other defendants have filed a motion to dismiss the
lawsuit. The Company believes that the allegations of this lawsuit are without
merit and intends to vigorously defend the action.
The Company is involved in various other lawsuits and certain governmental
proceedings arising in the ordinary course of business. Company management and
legal counsel do not believe that the ultimate resolution of these claims,
including the lawsuits described above, will have a material effect on the
Company's financial position, liquidity or operations.
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 1999.
16
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
The Company's common stock is listed on the New York Stock Exchange and
trades under the symbol "XTO." The following table sets forth quarterly high and
low sales prices and cash dividends declared for each quarter of 1999 and 1998
(as adjusted for the three-for-two stock split effected on February 25, 1998):
High Low Dividend
-------- ------- --------
1999
First Quarter... $ 9.063 $ 4.563 $.01
Second Quarter.. 14.875 6.750 .01
Third Quarter... 15.125 11.000 .01
Fourth Quarter.. 13.313 8.188 .01
1998
First Quarter... $ 21.125 $ 14.672 $.04
Second Quarter.. 20.875 16.375 .04
Third Quarter... 19.313 11.375 .04
Fourth Quarter.. 16.813 5.063 .04
The determination of the amount of future dividends, if any, to be declared
and paid is in the sole discretion of the Company's Board of Directors and will
depend on the Company's financial condition, earnings and funds from operations,
the level of its capital expenditures, dividend restrictions in its financing
agreements, its future business prospects and other matters as the Board of
Directors deems relevant. Furthermore, the Company's revolving credit agreement
with banks restricts the amount of dividends to 25% of cash flow from
operations, as defined, for the latest four consecutive quarterly periods. The
Company's 9 1/4% and 8 3/4% senior subordinated notes also place certain
restrictions on distributions to common shareholders, including dividend
payments.
On February 15, 2000, the Board of Directors declared a quarterly dividend
of $.01 per share payable on April 14, 2000 to shareholders of record on March
31, 2000. On March 1, 2000, the Company had 622 shareholders of record.
On July 1, 1999, the Company issued 4,000,000 shares of common stock at its
fair value of $45,700,000 to the stockholders of Spring Holding Company in
exchange for a 50% interest in Spring Holding Company and for cash proceeds of
$3.2 million. See Note 13 of Consolidated Financial Statements. The sale of the
common stock was deemed to be exempt from the registration requirements of the
Securities Act, pursuant to Section 4(2) of the Securities Act, as a transaction
by an issuer not involving a public offering.
On September 15, 1999, the Company issued from treasury 4,555,756 shares of
its common stock to Whitewine Holding Company ("Whitewine") at its fair value of
$63,211,000 as part of its contribution for its 50% interest in Whitewine. See
Note 14 of Consolidated Financial Statements. The sale of the common stock was
deemed to be exempt from the registration requirements of the Securities Act,
pursuant to Section 4(2) of the Securities Act, as a transaction by an issuer
not involving a public offering.
On July 2, 1999, a senior officer exercised options to purchase 73,684
Hugoton Royalty Trust units from the Company pursuant to the 1998 Royalty Trust
Option Plan. The officer exchanged 48,755 shares of Company common stock with a
fair value of $700,000 for the units. The issuance of the units to the officer
was deemed to be exempt from the registration requirements of the Securities
Act, pursuant to Section 4(2) of the Securities Act, as a transaction by an
issuer not involving a public offering.
17
Item 6. Selected Financial Data
The following table shows selected financial information for the five years
ended December 31, 1999. Significant producing property acquisitions in each of
the years presented affect the comparability of year-to-year financial and
operating data. All weighted average shares and per share data have been
adjusted for the three-for-two stock splits effected in March 1997 and February
1998. This information should be read in conjunction with Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements at Item 14(a).
1999 1998 1997 1996 1995
---------- ---------- ---------- --------- ---------
(in thousands except production, per share and per unit data)
Consolidated Statement of Operations Data
Revenues:
Oil and condensate............................ $ 86,604 $ 56,164 $ 75,223 $ 75,013 $ 60,349
Gas and natural gas liquids................... 239,056 182,587 110,104 73,402 40,543
Gas gathering, processing and marketing....... 10,644 9,438 9,851 12,032 7,091
Other......................................... 4,991 1,297 3,094 888 3,362
---------- ---------- ---------- --------- ---------
Total Revenues................................ $ 341,295 $ 249,486 $ 198,272 $ 161,335 $ 111,345
========== ========== ========== ========= =========
Earnings (loss) available to common stock...... $ 44,964(a) $ (71,498)(b) $ 23,905 $ 19,790 $ (10,538)(c)
========== ========== ========== ========= =========
Per common share
Basic......................................... $ 0.96 $ (1.65) $ 0.60 $ 0.50 $ (0.28)
========== ========== ========== ========= =========
Diluted....................................... $ 0.95 $ (1.65) $ 0.59 $ 0.48 $ (0.28)
========== ========== ========== ========= =========
Weighted average common shares outstanding.. 46,818 43,396 39,773 39,913 38,072
========== ========== ========== ========= =========
Dividends declared per common share............ $ 0.04 $ 0.16 $ 0.15 $ 0.13 $ 0.13
========== ========== ========== ========= =========
Consolidated Statement of Cash Flows Data
Cash provided (used) by:
Operating activities.......................... $ 133,301 $ (53,876) $ 95,918 $ 59,694 $ 32,938
Investing activities.......................... $ (156,370) $ (376,564) $ (309,234) $(124,871) $(160,416)
Financing activities.......................... $ 16,470 $ 438,957 $ 213,195 $ 66,902 $ 121,852
Consolidated Balance Sheet Data (Restated)(d)
Property and equipment, net.................... $1,339,080 $1,050,422 $ 723,836 $ 450,561 $ 364,474
Total assets................................... $1,477,081 $1,207,005 $ 788,455 $ 523,070 $ 402,675
Long-term debt................................. $ 991,100 $ 920,411 $ 539,000 $ 314,757 $ 238,475
Stockholders' equity........................... $ 277,817 $ 201,474 $ 170,243 $ 142,668 $ 130,700
Operating Data
Average daily production:
Oil (Bbls).................................... 14,006 12,598 10,905 9,584 9,677
Gas (Mcf)..................................... 288,000 229,717 135,855 101,845 78,408
Natural gas liquids (Bbls).................... 3,631 3,347 220 - -
Mcfe.......................................... 393,826 325,390 202,609 159,349 136,470
Average sales price:
Oil (per Bbl)................................. $16.94 $12.21 $18.90 $21.38 $17.09
Gas (per Mcf)................................. $2.13 $2.07 $2.20 $1.97 $1.42
Natural gas liquids (per Bbl)................. $11.80 $7.62 $9.66 - -
Production expense (per Mcfe).................. $0.53 $0.53 $0.59 $0.67 $0.71
Taxes, transportation and other (per Mcfe)..... $0.23 $0.25 $0.22 $0.20 $0.17
Proved reserves:
Oil (Bbls).................................... 61,603 54,510 47,854 42,440 39,988
Gas (Mcf)..................................... 1,545,623 1,209,224 815,775 540,538 358,070
Natural gas liquids (Bbls).................... 17,902 17,174 13,810 - -
Mcfe.......................................... 2,022,653 1,639,331 1,185,759 795,178 597,998
Other Data
Operating cash flow (e)........................ $ 132,683 $ 78,480 $ 89,979 $ 68,263 $ 40,439
Ratio of earnings to fixed charges (f)......... 1.9 - (g) 2.1 2.6 - (h)
18
(a) Includes effect of a $40.6 million pre-tax gain on sale of Hugoton
Royalty Trust units.
(b) 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.
(c) Includes effect of a $20.3 million pre-tax, non-cash impairment charge
recorded upon adoption of Statement of Financial Accounting Standards No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed Of.
(d) Reflects restatement for a change in accounting for the acquisition of
oil-producing properties in the Cook Inlet of Alaska from affiliates of
Shell Oil Company. See Note 17 to Consolidated Financial Statements.
(e) 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.
(f) For purposes of calculating this ratio, earnings include income (loss)
from continuing operations before income tax and fixed charges. Fixed
charges include interest costs, the portion of rentals (calculated as
one-third) considered to be representative of the interest factor and
preferred stock dividends.
(g) Fixed charges exceeded earnings by $108.4 million. Excluding the effect
of items in (b) above, fixed charges exceeded earnings by $19 million.
(h) Fixed charges exceeded earnings by $16.4 million. Excluding the effect of
the charge in (c) above, the ratio of earnings to fixed charges is 1.3.
19
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion and analysis should be read in conjunction with Item
6, "Selected Financial Data" and the Company's consolidated financial
statements at Item 14 (a).
General
The following events affect the comparability of results of operations and
financial condition for the years ended December 31, 1999, 1998 and 1997, 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 a three-for-two stock split on
March 19, 1997 and on February 25, 1998. All common stock shares, treasury
stock shares and per share amounts have been retroactively restated to reflect
both stock splits.
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. ("Lehman") each acquired 50% of the common stock of
Spring Holding Company for a combination of cash and the Company's common
stock totaling $85 million. In September 1999, the Company exercised its
option to acquire Lehman's 50% interest in Spring for $44.3 million. The
acquisition includes gas properties located in the Arkoma Basin of Arkansas
and Oklahoma with a purchase price of $237 million. After purchase
accounting adjustments and other costs, the cost of the properties was $253
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 intends to acquire Lehman's interest in this
acquisition on March 31, 2000 for $111 million.
Hugoton Royalty Trust Sale. In April and May 1999, the Company sold 17,004,000
units, or 42.5%, of Hugoton Royalty Trust in its initial public offering. The
Company created Hugoton Royalty Trust in December 1998 by conveying 80% net
profits interests in producing properties in Kansas, Oklahoma and Wyoming.
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 exercise
of royalty trust options, was $40.6 million before income tax.
Other 1999 Dispositions. 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.
1998 Acquisitions. During 1998, the Company acquired oil and gas-producing
properties at a total cost of $340 million, including:
- East Texas Basin Acquisition. The Company acquired these primarily gas-
producing properties at a purchase price of $245 million, later reduced to
$215 million by a $30 million production payment sold to EEX Corporation.
This acquisition closed in April 1998 and was funded by bank debt,
partially repaid from proceeds of the 1998 Common Stock Offering.
- Cook Inlet Acquisition. In September 1998, the Company acquired these oil-
producing properties in exchange for 1,921,850 shares of the Company's
common stock along with certain price guarantees and a non-interest bearing
note payable of $6 million, resulting in a purchase price of $45 million.
20
- Seagull Acquisition. This acquisition includes primarily gas-producing
properties in northwest Oklahoma and the San Juan Basin of New Mexico. The
Company acquired these properties in November 1998 for an estimated
purchase price of $31 million, funded by bank borrowings.
1997 Acquisitions. During 1997, the Company acquired predominantly gas-
producing properties at a total cost of $256 million, funded primarily by bank
borrowings and cash flow from operations. The acquisitions include:
- Amoco Acquisition. The Company purchased these properties in the San Juan
Basin of New Mexico in December 1997 for an adjusted purchase price of $195
million. This purchase price includes $5.7 million for five-year warrants
to purchase 944,284 shares of the Company's common stock at $15.20 per
share.
- Burlington Resources Acquisition. The Company purchased these properties in
Oklahoma, Kansas and Texas for an adjusted purchase price of $39 million in
May 1997.
- 6% of the publicly traded outstanding units in Cross Timbers Royalty Trust,
at a cost of $5.4 million.
1999, 1998 and 1997 Development and Exploration Programs. Oil development was
concentrated in the University Block 9 Field during 1999, 1998 and 1997, as well
as the Prentice Northeast Unit of West Texas during 1997. Gas development
focused on the East Texas area in 1999, the Hugoton Area during 1998, the Ozona
Area in 1998 and 1997 and the Fontenelle Unit during all three years.
Exploration activity has been primarily geological and geophysical analysis,
including seismic studies, of undeveloped properties. Exploratory expenditures
were $900,000 in 1999, $8 million in 1998 and $2.1 million in 1997.
2000 Development and Exploration Program. The Company has budgeted $120 million
for its 2000 development and exploration program, which is expected to be funded
primarily by cash flow from operations. The Company anticipates exploration
expenditures will be approximately 5% of the 2000 budget. The total capital
budget, including acquisitions, will be adjusted throughout 2000 to capitalize
on opportunities offering the highest rates of return.
1999 Sale and Repurchase of Common Stock. In July 1999, the Company sold
2,000,000 shares of common stock from treasury with net proceeds of
approximately $26.5 million. The proceeds were used to repurchase 1,921,850
shares of common stock issued to affiliates of Shell Oil Company for the Cook
Inlet Acquisition.
1999 Issuances of Common Shares. In July 1999, the Company issued 4,000,000
shares of common stock for its 50% interest in Spring Holding Company and for
cash proceeds of $3.2 million which was used to reduce bank debt. In September
1999, the Company issued from treasury 4,555,756 shares of its common stock to
Whitewine Holding Company ("Whitewine") as part of its contribution for its 50%
interest in Whitewine. These common shares are eliminated in the consolidated
financial statements.
1998 Common Stock Offering. In April 1998, the Company sold 7,203,450 shares of
common stock. Net proceeds of $133.1 million were used to partially repay bank
debt used to fund the East Texas Basin Acquisition.
1998 Issuance of Common Shares. In September 1998, the Company issued from
treasury stock 1,921,850 common shares to affiliates of Shell for the Cook Inlet
Acquisition. In July 1999, the Company repurchased these shares from Shell.
1997 Senior Subordinated Note Sales. The Company sold $125 million of 9 1/4%
senior subordinated notes in April 1997 and $175 million of 8 3/4% senior
subordinated notes in October 1997. Net proceeds of $121.1 million and $169.9
million, respectively, were used to reduce bank debt.
1997 Conversion of Subordinated Notes. In January 1997, noteholders converted
the remaining $29.7 million of the Company's 5 1/4% convertible subordinated
notes into 2,892,363 shares of common stock.
Treasury Stock Purchases. From May 1996 to December 1999, the Company
repurchased a total of 9.6 million shares of the Company's common stock as part
of its strategic acquisition plans. The Company purchased on the open market
5,000 shares at a cost of $53,000 in 1999, 4.3 million shares at a cost of $65.6
million in 1998 and 2.4 million shares at a cost of $28 million in 1997. Through
March 27, 2.2 million shares have been repurchased in 2000 at a cost of
21
$22.3 million, and 1.2 million shares remain under the February 2000 Board
of Directors' authorization to repurchase 2.5 million shares. Investment in
Equity Securities. The Company acquired common stock of publicly traded
independent oil and gas producers at a total cost of $167.7 million in 1998 and
$6.5 million in 1997. 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. Equity securities purchased prior
to 1998 were considered to be available-for-sale securities. Accordingly, the
Company recognized unrealized investment gains and losses in its 1998 and 1999
statements of operations, as opposed to recording as a component of
stockholders' equity in prior years. During 1999, the Company recognized a
$1.1 million loss on investment in equity securities, including a loss on sale
of securities of $22.2 million, an unrealized gain of $27.1 million and interest
expense of $6 million related to the investment. During 1998, the Company
recognized a $93.7 million loss on investment in equity securities, including a
loss on sale of securities of $14.8 million, an unrealized loss of $72.6 million
and interest expense of $6.3 million related to the investment. During 1997, the
Company recognized a gain of $1.7 million on its investment in equity securities
including a gain on sale of securities of $2.4 million and interest expense of
$700,000 related to the investment.
Property Sales. Excluding the Hugoton Royalty Trust sale, the Company sold
producing properties resulting in net gains of $6.4 million in 1999, $800,000 in
1998 and $1.8 million in 1997.
Stock Incentive Compensation. Stock incentive compensation results from stock
appreciation right ("SAR") and performance share awards, and subsequent changes
in the Company's stock price. In 1999, stock incentive compensation totaled
$100,000, which was primarily related to performance share grants. During 1998,
stock incentive compensation totaled $1.3 million, which included non-cash
performance share compensation of $1.6 million, partially offset by a reduction
in SAR compensation of $300,000. In 1997, stock incentive compensation totaled
$3.7 million, which included non-cash performance share compensation of $3.3
million and SAR compensation of $400,000. Exercises and forfeitures under the
1991 Stock Incentive Plan reduced outstanding stock incentive units (including
SARs) from 51,000 at the beginning of 1997 to 9,000 at year-end 1999. As of
December 31, 1999, there are 130,000 performance shares that vest when the
common stock price reaches $16.00 and 60,000 performance shares that vest when
the common stock price reaches $22.50. In January 2000, 120,000 performance
shares were granted that vest when the common stock price reaches $20.00.
Product Prices. In addition to supply and demand, oil and gas prices are
affected by substantial seasonal, political and other fluctuations the Company
generally cannot control or predict.
Crude oil prices are generally determined by global supply and demand.
Posted crude oil prices ranged from $17 to $20 during most of 1997, then
declined to a $16 average in December 1997. Crude oil prices continued to
decline throughout 1998, dropping to a West Texas Intermediate price of $8.00
per barrel in December 1998, the lowest level since 1978. After a weak first
quarter, oil prices increased in 1999 because of production cuts by OPEC and
other leading oil exporters, reduced inventories and anticipated increased
demand. By November 1999, crude oil prices reached their highest levels since
the 1990 Persian Gulf War and have remained at levels above $24 in first quarter
2000. Members of OPEC met on March 27, 2000 and agreed to increase production by
6.3%. Because of increased summer demand, increased production is not expected
to substantially increase domestic inventories until fourth quarter 2000. The
Company has entered oil futures contracts to sell 8,000 Bbls per day from April
through June 2000 at prices ranging from $22.04 to $23.28 per Bbl. Based on 1999
production, the Company estimates that a $1.00 per barrel increase or decrease
in the average oil sales price would result in approximately a $4.9 million
change in 2000 annual operating cash flow.
Natural gas prices are influenced by North American supply and demand,
which is often dependent upon weather conditions. Natural gas competes with
alternative energy sources as a fuel for heating and the generation of
electricity. Generally because of colder weather, storage concerns and U.S.
economic growth, prices remained relatively high during most of 1997, reaching
their highest levels since 1985. Gas prices declined, however, in December 1997
and remained lower throughout 1998 and first quarter 1999, primarily because the
winters of 1997-1998 and 1998-1999 were abnormally mild in the central and
eastern U.S. Cooler spring weather and lower industry production levels
strengthened gas prices in second quarter 1999. This trend continued into third
quarter 1999 when the NYMEX gas price rose above $3.00. Natural gas prices have
remained volatile during the winter of 1999-2000 as a third consecutive warm
winter reduced seasonal heating demand. In spite of a warm winter, natural gas
inventories are expected to be
22
substantially lower at the end of withdrawal season than in 1999. Lower
inventories of approximately 1 Tcf, compared with 1.3 Tcf in March 1999, are
attributable to lower domestic productive capacity. Lower production, reduced
inventories and increasing summer demand are expected to result in volatile
natural gas prices averaging higher than 1999 levels. At March 15, the average
NYMEX price for the following 12 months was $2.97 per Mmbtu. The Company has
entered commodity price hedging instruments to reduce its exposure to gas price
fluctuations. As a result of these commodity hedging instruments, the Company's
average gas price decreased from $2.18 to $2.13 in 1999 and increased from $1.97
to $2.07 in 1998. Largely influenced by crude oil prices, natural gas liquids
prices were weak in 1998 and rose significantly in 1999. Based on 1999
production, the Company estimates that a $0.10 per Mcf increase or decrease in
the average gas sales price would result in approximately a $10 million change
in 2000 annual operating cash flow.
Impairment Provision. During 1998, the Company recorded an impairment provision
on producing properties of $2 million before income tax. This impairment
provision was determined based on an assessment of recoverability of net
property costs from estimated future net cash flows from those properties.
Estimated future net cash flows are based on management's best estimate of
projected oil and gas reserves and prices. If oil and gas prices decline, the
Company may be required to record impairment provisions in the future, which may
be material.
Results of Operations
1999 Compared to 1998
For the year 1999, earnings available to common stock were $45 million
compared with a loss available to common stock of $71.5 million for 1998. The
1999 earnings include a $26.8 million after-tax gain from the sale of Hugoton
Royalty Trust units, a $4.2 million after-tax gain on sale of properties, and an
$800,000 after-tax loss on investment in equity securities. The 1998 loss
includes a $61.8 million after-tax loss related to the Company's investment in
equity securities and a $1.3 million after-tax impairment write-off of producing
properties. Excluding gains and losses from investments and from sales of trust
units and other property, earnings for 1999 were $14.8 million. Excluding losses
from investments and impairment write-off, the Company would have reported a
loss of $8.3 million in 1998.
Revenues for 1999 were $341.3 million, or 37% above 1998 revenues of $249.5
million. Oil revenue increased $30.4 million, or 54%, because of an 11%
increase in oil production and a 39% increase in oil prices from an average of
$12.21 per Bbl in 1998 to $16.94 in 1999 (see "General-Product Prices" above).
Increased production was primarily because of the 1998 acquisitions.
Gas revenue increased $56.5 million, or 31%, because of a 25% increase in
production, a 3% increase in gas prices and a 55% increase in natural gas
liquids prices from an average price of $7.62 per Bbl in 1998 to $11.80 in 1999
(see "General-Product Prices" above). Increased gas production was attributable
to the 1998 and 1999 acquisitions and development programs.
Gas gathering, processing and marketing revenues increased $1.2 million
primarily because of higher gas and natural gas liquids prices, increased margin
and increased volumes from the 1999 acquisitions. Other revenues were $3.7
million higher primarily because of increased net gains on sale of properties,
partially offset by decreased lawsuit settlement receipts.
Expenses for 1999 totaled $245.9 million as compared with total 1998
expenses of $209.2 million. Most expenses increased in 1999 primarily because
of the 1998 and 1999 acquisitions and development programs.
Production expense increased $13 million, or 21%, because of increased
production. Production expense per Mcfe remained flat at $0.53. The Company
lowered its exploration budget for 1999, resulting in a $7.1 million reduction
in exploration expense, which is predominantly geological and geophysical costs.
Taxes, transportation and other deductions increased 16% or $4.6 million
because of increased oil and gas revenues, as well as increased transportation,
compression and other charges related to the 1998 and 1999 acquisitions. Taxes,
transportation and other per Mcfe decreased 8% from $0.25 to $0.23 because of
decreased property taxes and a lower production tax rate associated with
production from the 1999 acquisitions.
23
Depreciation, depletion and amortization ("DD&A") increased $28.8 million,
or 34%, primarily because of the 1998 and 1999 acquisitions and development
programs. On an Mcfe basis, DD&A increased from $0.70 in 1998 to $0.78 in 1999
primarily because of the higher cost per Mcfe of the 1998 and 1999 acquisitions.
General and administrative expense increased $600,000, or 5%, because of
increased expenses from Company growth related to the 1998 and 1999
acquisitions. Excluding stock incentive compensation, general and
administrative expense per Mcfe remained at $0.10 in 1999.
Interest expense increased $12.1 million, or 23%, primarily because of a
comparable increase in weighted average borrowings to partially fund the 1998
and 1999 acquisitions. Interest related to investment in equity securities has
been classified as part of the loss on investment in equity securities.
Interest expense per Mcfe increased slightly from $0.44 in 1998 to $0.45 in
1999.
1998 Compared to 1997
For the year 1998, loss available to common stock was $71.5 million
compared with earnings of $23.9 million for 1997. The 1998 loss includes a
$61.8 million after-tax loss on investment in equity securities and a $1.3
million after-tax impairment write-down of producing properties. The remaining
decline in earnings was primarily the result of lower product prices and
increased interest expense related to the 1998 acquisitions and treasury stock
purchases.
Revenues for 1998 were $249.5 million, or 26% above 1997 revenues of $198.3
million. Although oil production increased 16%, oil revenue decreased $19.1
million or 25% because of a 35% decrease in oil prices from an average of $18.90
per Bbl in 1997 to $12.21 in 1998 (see "General-Product Prices" above).
Increased production was primarily because of the 1998 acquisitions.
Gas revenue increased $72.5 million or 66% because of a 69% increase in
production partially offset by a 6% price decrease (see "General-Product Prices"
above). Increased gas production was attributable to the 1997 and 1998
acquisitions and development programs. Gas revenues for 1998 also included $9.3
million from San Juan Basin natural gas liquids production attributable to the
December 1997 Amoco Acquisition.
Gas gathering, processing and marketing revenues decreased $400,000
primarily because of decreased wellhead volumes and lower gas and natural gas
liquids prices, partially offset by increased margin. Other revenues were $1.8
million lower primarily because of decreased net gains on sale of properties and
decreased lawsuit settlement receipts.
Expenses for 1998 totaled $209.2 million as compared with total 1997
expenses of $134.8 million. Most expenses increased in 1998 primarily because
of the 1997 and 1998 acquisitions and exploration and development programs.
Production expense increased $19.6 million or 45%. Per Mcfe, production
expense decreased from $0.59 to $0.53. This decrease is primarily because of
the lower operating costs of gas-producing properties acquired in 1997 and 1998,
the timing of workovers and operating efficiencies initiated after acquiring
operated properties. Exploration expenses for 1998 totaled $8 million and were
predominantly geological and geophysical costs, including seismic analysis,
related to the 1998 exploration program. Exploration costs in 1997 totaled $2.1
million.
Taxes, transportation and other deductions increased 77% or $12.7 million
because of increased oil and gas revenues, as well as increased property taxes
related to the 1997 and 1998 acquisitions. Taxes, transportation and other per
Mcfe increased 14% from $0.22 to $0.25 because of increased transportation,
compression and other charges related to acquisitions.
DD&A increased $35.8 million, or 75%, primarily because of the 1997 and
1998 acquisitions and development programs. On an Mcfe basis, DD&A increased
from $0.65 in 1997 to $0.70 in 1998 primarily because of the higher cost per
Mcfe of the 1998 acquisitions.
24
General and administrative expense decreased $2.3 million, or 15%, because
of a $2.4 million decrease in stock incentive compensation, partially offset by
increased expenses from Company growth. Excluding stock incentive compensation,
general and administrative expense per Mcfe decreased to $0.10 in 1998 from
$0.16 in 1997. This reduction resulted from production growth outpacing Company
personnel requirements and other administrative expenses.
Interest expense increased $26.1 million or 100% primarily because of a
comparable increase in weighted average borrowings to partially fund the 1997
and 1998 acquisitions and treasury stock purchases, combined with a 1% increase
in the weighted average interest rate and amortization of loan fees. Interest
related to investment in equity securities has been classified as part of the
loss on investment in equity securities. Interest expense per Mcfe increased
from $0.35 in 1997 to $0.44 in 1998 primarily as the result of an increase in
the weighted average borrowings to fund treasury stock purchases.
Liquidity and Capital Resources
The Company's primary sources of liquidity are cash flow from operating
activities, producing property sales, including sales of royalty trust units,
public offerings of equity and debt, and bank debt. Other than for operations,
the Company's cash requirements are generally for the acquisition, exploration
and development of oil and gas properties, and debt and dividend payments.
Exploration and development expenditures and dividend payments have generally
been funded by cash flow from operations. The Company believes that its sources
of liquidity are adequate to fund its cash requirements in 2000.
Cash provided by operating activities was $133.3 million in 1999, compared
with cash used by operating activities of $53.9 million in 1998 and $95.9
million cash provided by operations in 1997. Fluctuations during this three-
year period were primarily because of purchases of equity securities and lower
product prices in 1998 and increased production from acquisitions and
development activity in 1999. Before changes in operating assets and
liabilities and exploration expense, cash flow from operations was $132.7
million in 1999, $78.5 million in 1998 and $90 million in 1997.
Financial Condition
Total assets increased 22% from $1.2 billion at December 31, 1998 to $1.5
billion at December 31, 1999, primarily because of the 1999 acquisitions. As of
December 31, 1999, total capitalization of the Company was $1.3 billion, of
which 78% was long-term debt. This compares with capitalization of $1.1 billion
at December 31, 1998, of which 82% was long-term debt. The decrease in the debt-
to-capitalization ratio from year-end 1998 to 1999 is because of funding a
significant portion of the 1999 acquisitions from sources other than debt and
repayment of debt from proceeds from the sale of Hugoton Royalty Trust units.
Working Capital
The Company generally uses available cash to reduce bank debt and,
therefore, does not maintain large cash and cash equivalent balances. Short-
term liquidity needs are satisfied by bank commitments under the loan agreement
(see "Financing" below). Because of this, and since the Company's principal
source of operating cash flows (i.e., proved reserves to be produced in the
following year) cannot be reported as working capital, the Company often has low
or negative working capital. Working capital of $39 million at December 31,
1999 and $62 million at December 31, 1998 was primarily attributable to the
investment in equity securities and the deferred tax benefit related to the net
unrealized loss on the investment. The decrease in the current deferred income
tax benefit of $20.6 million from December 31, 1998 to December 31, 1999 is
related to the decline in the unrealized loss on investment in equity
securities, resulting from sale of securities and improvement in the market
value of securities held.
In 1998, the Company purchased what it believed to be undervalued oil and
gas reserves through investments in publicly traded equity securities of select
energy companies. After selling a portion of these securities in 1998 and 1999,
the Company's investment in equity securities had a fair market value of $29.1
million at December 31, 1999. During the first quarter of 2000, the Company sold
most of this investment for proceeds of $41.1 million, resulting in a gain of
$14.4 million, of which $17.1 million was a decrease in unrealized loss. Equity
securities held at
25
March 24, 2000 had a value of $1.7 million and are owned by the Company's 50%
owned subsidiary, Whitewine Holding Company, which may sell the securities at
any time.
Prior to their sale, equity securities owned by the Company had been held
in a PaineWebber broker account and provided support for officer margin debt.
Currently, the Company's investment in Cross Timbers Royalty Trust units, with a
March 1, 2000 value of $16 million, provides support for officer margin debt,
which totaled $10.5 million at March 1, 2000. See Note 3 to Consolidated
Financial Statements.
Financing
The Company amended its revolving credit agreement with commercial banks in
August 1999, resulting in a borrowing base and commitment of $468 million and
$29 million unused borrowing capacity under the loan agreement as of December
31, 1999. The interest rate on borrowings in December 1999 averaged 7.5%. The
Company periodically renegotiates the loan agreement to increase the borrowing
commitment and extend the revolving facility; however, the Company cannot assure
that it can continue to do so in the future.
The borrowing base is redetermined annually based on the value and expected
cash flow of the Company's proved oil and gas reserves. If borrowings exceed
the redetermined borrowing base, the banks may require that the excess be repaid
within a year. Otherwise, borrowings under the loan agreement do not mature
until June 30, 2003, but may be prepaid at any time without penalty. The
borrowing base is expected to be redetermined in May 2000 in connection with
consolidation of bank debt of the Company, Spring Holding Company and Summer
Acquisition Company. Based on year-end proved reserves and relatively strong
commodity prices, the Company expects a significant increase in the borrowing
base upon its redetermination.
Spring Holding Company, a wholly owned subsidiary of the Company, has a
$140 million revolving credit facility with commercial banks which had a
borrowing base of $130 million and unused borrowing capacity of $13.9 million at
December 31, 1999. The borrowing base is subject to semiannual
redeterminations. The credit facility is secured by properties owned by Spring
and is nonrecourse to the Company. Borrowings under the credit facility mature
on July 31, 2004.
Summer Acquisition Company, a wholly owned subsidiary of Whitewine Holding
Company, which is 50% owned by each of the Company and Lehman, has a $140
million revolving credit facility with commercial banks which had a borrowing
base of $140 million and unused borrowing capacity of $11 million at December
31, 1999. The borrowing base is subject to semiannual redeterminations.
Borrowings under the credit facility were used to partially fund the Ocean
Energy Acquisition. The credit facility is secured by the properties acquired
and is nonrecourse to the Company and Lehman. Borrowings under the credit
facility mature on September 15, 2001.
The 1999 and 1998 acquisitions were partially funded by the sale and
issuance of common stock. The 1999 acquisitions were also partially funded by
contributions from Lehman, the Company's equity partner. These transactions are
described under "General" above. See also "Capital Expenditures" below.
Capital Expenditures
Because of their size, the 1999 acquisitions were made jointly with Lehman
as a 50% equity partner. Pursuant to its call option, the Company acquired
Lehman's interest in the Spring Holding Acquisition in September 1999. The
Company plans to exercise its option to purchase Lehman's interest in the Ocean
Energy Acquisition on March 31, 2000 for approximately $111 million, funded
primarily by the proceeds from sales of property and equity securities. If the
Company does not exercise its option to purchase Lehman's interest by September
15, 2000, Lehman will have the right to sell its interest to the Company on that
date for $120 million. The Company plans to fund any future acquisitions
through a combination of cash flow from operations and proceeds from asset
sales, bank debt, public equity or debt transactions. There are no restrictions
under the Company's revolving credit agreement that would affect the Company's
ability to use its remaining borrowing capacity for acquisitions of producing
properties.
In February 2000, the Board of Directors authorized the repurchase of 2.5
million shares of Company's common stock, or approximately 5% of the shares
outstanding. These shares will be purchased from time to time in
26
open market or negotiated transactions. Through March 27, 2000, 1.3 million
shares have been purchased at a cost of $15 million.
In 1999, exploration and development cash expenditures totaled $91.6
million compared with the budget of $90 to $100 million. In 1998, exploration
and development cash expenditures totaled $77.4 million, compared with the
budget of $90 million. The Company has budgeted $120 million for the 2000
development program. As it has done historically, the Company expects to fund
the 2000 development program with cash flow from operations. Since there are no
material long-term commitments associated with this budget, the Company has the
flexibility to adjust its actual development expenditures in response to changes
in product prices, industry conditions and the effects of the Company's
acquisition and development programs.
A minor portion of the Company's existing properties are operated by third
parties which control the timing and amount of expenditures required to exploit
the Company's interests in such properties. Therefore, the Company cannot
assure the timing or amount of these expenditures.
To date, the Company has not spent significant amounts to comply with
environmental or safety regulations, and it does not expect to do so during
2000. However, developments such as new regulations, enforcement policies or
claims for damages could result in significant future costs.
Dividends
The Board of Directors declared quarterly dividends of $0.037 per common
share in 1997, $0.04 per common share in 1998 and $0.01 per common share in
1999. 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 to 25% of cash flow from
operations, as defined, for the last four quarters.
Cumulative dividends on Series A convertible preferred stock are paid
quarterly, when declared by the Board of Directors, based on an annual rate of
$1.5625 per share, or $1.8 million annually.
Year 2000
"Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant could have material adverse effects on
companies and organizations that rely upon those systems. The transition to the
year 2000 has had no significant impact on the Company's computer systems and
computer-controlled equipment, and the Company does not foresee any material
system failures in the coming months. The Company will continue to monitor its
Year 2000 status throughout the year.
The Company reviewed its computer systems and computer-controlled field
equipment and made the necessary modifications for Year 2000 compliance by
December 1999. The Company estimates that total costs related to Year 2000
compliance efforts will be less than $500,000 of which approximately $225,000
has been incurred and expensed through December 1999. The Company also
identified significant third parties whose Year 2000 compliance could affect it
and formally inquired about their Year 2000 status. The Company is not aware of
any significant third parties who have experienced a material Year 2000 system
failure. Despite its efforts to assure that significant third parties are Year
2000 compliant, the Company cannot provide assurance that third parties will not
experience material system failures in the coming months. Although the
potential effect of Year 2000 non-compliance by third parties is unknown, the
Company has developed appropriate contingency plans in the event of related
system failures.
Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative
Instruments and Hedging Activities which was required to be adopted for fiscal
years beginning after June 15, 1999. In July 1999, the Financial Accounting
Standards Board issued SFAS No. 137 which delays the effective date of Statement
133 for one year, to fiscal years beginning after June 15, 2000. Adoption of
SFAS No. 133 should have no significant impact on the Company's reported
earnings, but could materially affect comprehensive income.
27
Production Imbalances
The Company has gas production imbalance positions that are the result of
partial interest owners selling more or less than their proportionate share of
gas on jointly owned wells. Imbalances are generally settled by disproportionate
gas sales over the remaining life of the well or by cash payment by the
overproduced party to the underproduced party. The Company uses the entitlement
method of accounting for natural gas sales. At December 31, 1999, the Company's
consolidated balance sheet includes a net payable of $4.1 million for a net
overproduced balancing position of 2,215,000 Mcf of natural gas, and a
receivable of $3.9 million for an underproduced balancing position of 9,076,000
Mcf of carbon dioxide. Production imbalances do not have, and are not expected
to have, a significant impact on the Company's liquidity or operations.
Forward-Looking Statements
Certain information included in this annual report on Form 10-K and other
materials filed by the Company with the Commission contain forward-looking
statements relating to the Company's operations and the oil and gas industry.
Such forward-looking statements are based on management's current projections
and estimates and are identified by words such as "expects," "intends," "plans,"
"projects," "anticipates," "believes," "estimates" and similar words. These
statements are not guarantees of future performance and involve certain risks,
uncertainties and assumptions that are difficult to predict. Therefore, actual
results may differ materially from what is expressed or forecasted in such
forward-looking statements.
Among the factors that could cause actual results to differ materially are:
- crude oil and natural gas price fluctuations,
- the Company's ability to acquire oil and gas properties that meet its
objectives and to identify prospects for drilling,
- potential delays or failure to achieve expected production from
existing and future exploration and development projects, and
- potential liability resulting from pending or future litigation.
In addition, these forward-looking statements may be affected by general
domestic and international economic and political conditions.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The Company only uses derivative financial instruments for hedging
purposes. These instruments principally include interest rate swap agreements
and commodity futures, swaps and option agreements. These financial and
commodity-based derivative contracts are used to limit the risks of interest
rate fluctuations and natural gas and crude oil price changes. Gains and losses
on these derivatives are offset by losses and gains on the respective hedged
exposures.
The Board of Directors has adopted a policy governing the use of derivative
instruments, which requires that all derivatives used by the Company relate to
an underlying, offsetting position, anticipated transaction or firm commitment,
and prohibits the use of speculative, highly complex or leveraged derivatives.
The policy also requires review and approval by the Executive Vice President of
all risk management programs using derivatives and all derivative transactions.
These programs are also periodically reviewed by the Board of Directors.
Hypothetical changes in interest rates and prices chosen for the estimated
sensitivity effects are considered to be reasonably possible near-term changes
generally based on consideration of past fluctuations for each risk category. It
is not possible to accurately predict future changes in interest rates, product
prices and investment market values. Accordingly, these hypothetical changes may
not necessarily be an indicator of probable future fluctuations.
28
Interest Rate Risk
The Company is exposed to interest rate risk on short-term and long-term
debt carrying variable interest rates. The Company's variable rate debt was
approximately $691.1 million at December 31, 1999. The Company attempts to
balance the benefit of lower cost variable rate debt that has inherent increased
risk with more expensive fixed rate debt that has less market risk. This is
accomplished through a mix of bank debt with short-term variable rates and fixed
rate subordinated debt, as well as the use of interest rate swaps.
The following table shows the carrying amount and fair value of long-term
debt and interest rate swaps, and the hypothetical change in fair value that
would result from a 100-basis point change in interest rates. The hypothetical
change in fair value could result in a gain or a loss depending on an increase
or decrease in the interest rate.
Hypothetical
Carrying Fair Change in
(in thousands) Amount Value Fair Value
---------- --------- ------------
December 31, 1999
Long-term debt...................... $(991,100) $(981,540) $16,771
Interest rate swaps................. - 574 483
December 31, 1998
Long-term debt...................... $(920,411) $(894,750) $17,000
Interest rate swaps................. - (2,722) 8,655
Commodity Price Risk
The Company hedges a portion of the market risks associated with its crude
oil and natural gas sales. During 1998 and 1999, the Company primarily entered
oil and gas futures contracts and gas basis swap agreements to reduce exposure
to price volatility in the physical markets. As of December 31, 1999,
outstanding futures contracts had a fair value loss of $2.7 million and
outstanding basis swap agreements had a fair value loss of $1.1 million. These
futures contracts and basis swap agreements are not recorded on the Company's
balance sheet. As of December 31, 1998, outstanding futures contracts had a
fair value gain of $3.5 million and outstanding basis swap agreements had a fair
value loss of $0.7 million.
At year-end 1999, the total effect of a hypothetical 10% change in natural
gas prices, oil prices and gas basis would result in approximately a $16 million
change in the fair value of these financial instruments. This sensitivity does
not include the effects of commodity contracts that cannot be settled in cash or
another financial instrument. See Note 6 to Consolidated Financial Statements.
Investment in Equity Securities
The Company is subject to price risk on its unhedged portfolio of publicly
traded investment in equity securities of energy companies. The fair value of
these securities at December 31, 1999 was $29.1 million. At year-end 1999, a
25% change in equity price would increase or decrease portfolio fair value and
pre-tax earnings by approximately $7 million. During the first quarter of 2000,
the Company sold most of this investment at a gain of $14.4 million. Equity
securities held at March 24, 2000 had a fair value of $1.7 million.
29
Item 8. Financial Statements and Supplementary Data
The following financial statements and supplementary information are
included under Item 14(a):
Page
----
Consolidated Balance Sheets......................... 32
Consolidated Statements of Operations............... 33
Consolidated Statements of Comprehensive Income..... 34
Consolidated Statements of Cash Flows............... 35
Consolidated Statements of Stockholders' Equity..... 36
Notes to Consolidated Financial Statements.......... 37
Selected Quarterly Financial Data
(Note 18 to Consolidated Financial Statements).... 62
Information about Oil and Gas Producing Activities
(Note 19 to Consolidated Financial Statements).... 62
Report of Independent Public Accountants............ 66
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
Except for the portion of Item 10 relating to Executive Officers of the
Registrant which is included in Part I of this Report, the information called
for by Items 10 through 13 is incorporated by reference from the Company's
Notice of Annual Meeting and Proxy Statement to be filed with the Commission no
later than April 29, 2000.
30
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, 1999 and 1998........ 32
Consolidated Statements of Operations for the years ended
December 31, 1999, 1998 and 1997............................... 33
Consolidated Statements of Comprehensive Income for the years
ended December 31, 1999, 1998 and 1997......................... 34
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997............................... 35
Consolidated Statements of Stockholders' Equity for the years
years December 31, 1999, 1998 and 1997......................... 36
Notes to Consolidated Financial Statements....................... 37
Report of Independent Public Accountants......................... 66
2. Financial Statement Schedules:
Schedule I - Condensed Financial Information of Registrant....... 67
Report of Independent Public Accountants......................... 71
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, 1999 and through March 30, 2000:
On November 29, 1999, the Company filed a report on Form 8-K/A
(Amendment No. 1 to Form 8-K dated September 15, 1999) to file
amended financial statements for the acquisition of certain producing
oil and gas properties and undeveloped acreage in the Arkoma Basin
from affiliates of Ocean Energy, Inc. with Lehman Brothers Holding,
Inc.
On March 9, 2000, the Company filed a report on Form 8-K to announce
that it has entered into definitive agreements to sell oil and gas-
producing properties in Crockett County, Texas and Lea County, New
Mexico. The report also disclosed that the Company has received Board
of Directors approval to repurchase up to 2.5 million shares of the
Company's common stock.
(c) Exhibits
See Index to Exhibits at page 72 for a description of the exhibits filed
as a part of this report.
(d) Financial Statement Schedules
Separate financial statements of subsidiary guarantors will be filed by
amendment to this Form 10-K if determination is made by the Commission
that such financial statements are required in lieu of condensed
consolidating financial statements disclosed in Note 16 to Consolidated
Financial Statements.
31
CROSS TIMBERS OIL COMPANY
Consolidated Balance Sheets
===============================================================================
(in thousands, except shares) December 31
------------------------
1999 1998
------------ -----------
ASSETS (Restated)
Current Assets:
Cash and cash equivalents........................................... $ 5,734 $ 12,333
Accounts receivable, net............................................ 68,998 50,607
Investment in equity securities..................................... 29,052 44,386
Deferred income tax benefit......................................... 4,168 24,816
Other current assets................................................ 5,540 5,436
---------- ----------
Total Current Assets.............................................. 113,492 137,578
---------- ----------
Property and Equipment, at cost -- successful efforts method:
Producing properties................................................ 1,635,883 1,335,255
Undeveloped properties.............................................. 10,358 6,845
Gas gathering and other............................................. 32,902 27,829
---------- ----------
Total Property and Equipment....................................... 1,679,143 1,369,929
Accumulated depreciation, depletion and amortization................ (340,063) (319,507)
---------- ----------
Net Property and Equipment........................................ 1,339,080 1,050,422
---------- ----------
Other Assets......................................................... 16,817 13,210
---------- ----------
Loans to Officers.................................................... 7,692 5,795
---------- ----------
TOTAL ASSETS......................................................... $1,477,081 $1,207,005
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities............................ $ 68,937 $ 69,560
Payable to royalty trusts........................................... 2,739 968
Short-term debt..................................................... - 4,962
Other current liabilities........................................... 2,542 75
---------- ----------
Total Current Liabilities......................................... 74,218 75,565
---------- ----------
Long-term Debt....................................................... 991,100 920,411
---------- ----------
Deferred Income Taxes Payable........................................ 25,975 6,892
---------- ----------
Other Long-term Liabilities.......................................... 7,959 2,663
---------- ----------
Commitments and Contingencies (Note 6)
Minority Interest in Consolidated Subsidiary......................... 100,012 -
---------- ----------
Stockholders' Equity:
Series A convertible preferred stock ($.01 par value, 25,000,000
shares authorized, 1,138,729 issued, at liquidation value of $25).. 28,468 28,468
Common stock ($.01 par value, 100,000,000 shares authorized,
58,188,501 and 54,048,227 shares issued)........................... 582 541
Additional paid-in capital.......................................... 396,568 362,526
Treasury stock (9,299,382 and 9,320,971 shares)..................... (119,387) (118,555)
Retained earnings (deficit)......................................... (28,414) (71,506)
---------- ----------
Total Stockholders' Equity........................................ 277,817 201,474
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY........................... $1,477,081 $1,207,005
========== ==========
See accompanying notes to consolidated financial statements.
32
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Operations
================================================================================
(in thousands, except per share data)
Year Ended December 31
-------------------------------
1999 1998 1997
-------------------------------
REVENUES
Oil and condensate.......................................... $ 86,604 $ 56,164 $ 75,223
Gas and natural gas liquids................................. 239,056 182,587 110,104
Gas gathering, processing and marketing..................... 10,644 9,438 9,851
Other....................................................... 4,991 1,297 3,094
-------- --------- --------
Total Revenues.............................................. 341,295 249,486 198,272
-------- --------- --------
EXPENSES....................................................
Production.................................................. 76,110 63,148 43,580
Taxes, transportation and other............................. 33,681 29,105 16,405
Exploration................................................. 904 8,034 2,088
Depreciation, depletion and amortization.................... 112,364 83,560 47,721
Impairment.................................................. - 2,040 -
Gas gathering and processing................................ 8,743 8,360 8,517
General and administrative.................................. 14,091 13,479 15,818
Trust development costs..................................... - 1,498 665
-------- --------- --------
Total Expenses.............................................. 245,893 209,224 134,794
-------- --------- --------
OPERATING INCOME............................................ 95,402 40,262 63,478
-------- --------- --------
OTHER INCOME (EXPENSE)
Gain on sale of Hugoton Royalty Trust units................. 40,566 - -
Gain (loss) on investment in equity securities.............. (1,149) (93,719) 1,735
Interest expense, net....................................... (64,214) (52,113) (26,012)
-------- --------- --------
Total Other Income (Expense)................................ (24,797) (145,832) (24,277)
-------- --------- --------
INCOME (LOSS) BEFORE INCOME TAX
AND MINORITY INTEREST...................................... 70,605 (105,570) 39,201
Income Tax Expense (Benefit)................................ 23,965 (35,851) 13,517
Minority Interest in Net Loss of Consolidated Subsidiaries.. 103 - -
-------- --------- --------
NET INCOME (LOSS)........................................... 46,743 (69,719) 25,684
Preferred stock dividends................................... 1,779 1,779 1,779
-------- --------- --------
EARNINGS (LOSS) AVAILABLE TO COMMON STOCK................... $ 44,964 $ (71,498) $ 23,905
======== ========= ========
EARNINGS (LOSS) PER COMMON SHARE
Basic...................................................... $0.96 $(1.65) $0.60
======== ========= ========
Diluted.................................................... $0.95 $(1.65) $0.59
======== ========= ========
Weighted Average Common Shares Outstanding.................. 46,818 43,396 39,773
======== ========= ========
See accompanying notes to consolidated financial statements.
33
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Comprehensive Income
================================================================================
(in thousands)
Year Ended December 31
---------------------------
1999 1998 1997
------- -------- -------
NET INCOME (LOSS)................................... $46,743 $(69,719) $25,684
------- -------- -------
OTHER COMPREHENSIVE INCOME (LOSS)
Unrealized gains on available-for-sale securities:
Unrealized holding gains.......................... - - 1,434
Less realized gains included in net income........ - - (2,400)
------- -------- -------
Other Comprehensive Income (Loss) Before Tax........ - - (966)
Income tax benefit (expense) related to
other comprehensive income......................... - - 328
------- -------- -------
Other Comprehensive Income (Loss)................... - - (638)
------- -------- -------
COMPREHENSIVE INCOME (LOSS)......................... $46,743 $(69,719) $25,046
======= ======== =======
See accompanying notes to consolidated financial statements.
34
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Cash Flows
================================================================================
(in thousands)
Year Ended December 31
----------------------------------
1999 1998 1997
---------- ---------- ----------
OPERATING ACTIVITIES
Net income (loss)............................................................... $ 46,743 $ (69,719) $ 25,684
Adjustments to reconcile net income (loss) to net cash..........................
provided (used) by operating activities:......................................
Depreciation, depletion and amortization.................................... 112,364 83,560 47,721
Impairment.................................................................. - 2,040 -
Stock incentive compensation................................................ 93 1,141 3,386
Deferred income tax......................................................... 23,657 (35,744) 13,393
(Gain) loss on investment in equity securities and from sale of properties.. (51,802) 86,628 (4,157)
Minority interest in net loss of consolidated subsidiaries.................. (103) - -
Other non-cash items........................................................ 827 2,540 1,864
Changes in operating assets and liabilities (a)............................. 1,522 (124,322) 8,027
--------- --------- ---------
Cash Provided (Used) by Operating Activities.................................... 133,301 (53,876) 95,918
--------- --------- ---------
INVESTING ACTIVITIES
Proceeds from sale of Hugoton Royalty Trust units............................... 148,570 - -
Proceeds from sale of long-term investment in equity securities................. - - 24,626
Long-term investment in equity securities....................................... - - (6,479)
Proceeds from sale of property and equipment.................................... 110,500 2,494 17,972
Property acquisitions........................................................... (270,226) (296,390) (238,294)
Purchase of Spring Holding Company.............................................. (42,540) - -
Development costs............................................................... (90,725) (69,356) (88,382)
Gas plant, gathering and other additions........................................ (10,479) (7,517) (18,677)
Loans to officers............................................................... (1,470) (5,795) -
--------- --------- ---------
Cash Used by Investing Activities............................................... (156,370) (376,564) (309,234)
--------- --------- ---------
FINANCING ACTIVITIES
Proceeds from short- and long-term debt......................................... 256,400 877,900 688,400
Payments on short- and long-term debt........................................... (339,262) (496,938) (437,430)
Purchase of minority interest................................................... (42,385) - -
Contributions from minority interests........................................... 142,500 - -
Common stock offering........................................................... 29,668 133,113 -
Dividends....................................................................... (4,950) (8,460) (7,571)
Purchases of treasury stock and other........................................... (25,501) (66,658) (30,204)
--------- --------- ---------
Cash Provided by Financing Activities........................................... 16,470 438,957 213,195
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................................ (6,599) 8,517 (121)
Cash and Cash Equivalents, January 1............................................ 12,333 3,816 3,937
--------- --------- ---------
Cash and Cash Equivalents, December 31.......................................... $ 5,734 $ 12,333 $ 3,816
========= ========= =========
(a) Changes in Operating Assets and Liabilities
Accounts receivable....................................................... $ (8,227) $ (7,022) $ 246
Investment in equity securities........................................... 20,180 (131,809) -
Other current assets...................................................... (32) (1,513) (970)
Current liabilities....................................................... (11,628) 16,022 8,751
Other long-term liabilities............................................... 1,229 - -
--------- --------- ---------
Decrease (Increase) in Operating Assets and Liabilities..................... $ 1,522 $(124,322) $ 8,027
========= ========= =========
See accompanying notes to consolidated financial statements.
35
CROSS TIMBERS OIL COMPANY
Consolidated Statements of Stockholders' Equity
================================================================================
(in thousands)
Shares Stockholders' Equity
-------------------------------- ----------------------------------------------------------------
Common Stock
----------------------- Additional Retained
Preferred In Preferred Common Paid-in Treasury Earnings
Stock Issued Treasury Stock Stock Capital Stock (Deficit)
-------- -------- -------- --------- --------- ---------- ----------- ----------
Balances, December 31, 1996... 1,139 42,315 3,868 $ 28,468 $ 423 $ 164,436 $ (40,219) $ (11,078)
Issuance/vesting of
performance shares......... - 180 76 - 2 3,431 (1,098) -
Stock option exercises........ - 924 566 - 9 8,183 (7,326) -
Treasury stock purchases...... - - 2,351 - - - (28,013) -
Conversion of subordinated....
convertible notes to
common stock.............. - 2,892 - - 29 29,179 - -
Issuance of warrants ......... - - - - - 5,725 - -
Common stock dividends
($0.15 per share).......... - - - - - - - (5,813)
Preferred stock dividends
($1.56 per share).......... - - - - - - - (1,779)
Net income.................... - - - - - - - 25,684
------- -------- -------- --------- --------- ---------- ---------- ----------
Balances, December 31, 1997... 1,139 46,311 6,861 28,468 463 210,954 (76,656) 7,014
Sale of common stock.......... - 7,203 - - 72 133,041 - -
Issuance/vesting of
performance shares........... - 82 27 - 1 1,804 (536) -
Stock option exercises........ - 452 25 - 5 2,986 (483) -
Treasury stock purchases...... - - 4,330 - - - (65,575) -
Treasury stock issued
(restated)................... - - (1,922) - - 13,741 24,695 -
Common stock dividends
($0.16 per share).......... - - - - - - - (7,022)
Preferred stock dividends
($1.56 per share).......... - - - - - - - (1,779)
Net loss...................... - - - - - - - (69,719)
------- -------- -------- --------- --------- ---------- ---------- ----------
Balances, December 31,
1998 (restated).............. 1,139 54,048 9,321 28,468 541 362,526 (118,555) (71,506)
Issuance/sale of common
stock........................ - 4,000 - - 40 45,660 - -
Issuance/vesting of
performance shares........... - 130 - - 1 232 - -
Stock option exercises........ - 11 51 - - 95 (755) -
Treasury stock purchases...... - - 1,927 - - - (25,517) -
Treasury stock issued......... - - (2,000) - - (11,945) 25,440 -
Common stock dividends
($0.04 per share) ......... - - - - - - - (1,872)
Preferred stock dividends
($1.56 per share).......... - - - - - - - (1,779)
Net income.................... - - - - - - - 46,743
------- -------- -------- --------- --------- ---------- ---------- ----------
Balances, December 31, 1999 1,139 58,189 9,299 $ 28,468 $ 582 $ 396,568 $ (119,387) $ (28,414)
======= ======== ========= ========= ========== ========== ========== ==========
See accompanying notes to consolidated financial statements.
36
CROSS TIMBERS OIL COMPANY
Notes to Consolidated Financial Statements
================================================================================
1. Organization and Summary of Significant Accounting Policies
Cross Timbers Oil Company, a Delaware corporation, was organized in October
1990 to ultimately acquire the business and properties of predecessor entities
that were created from 1986 through 1989. Cross Timbers Oil Company completed
its initial public offering of common stock in May 1993.
The accompanying consolidated financial statements include the financial
statements of Cross Timbers Oil Company and its wholly owned subsidiaries ("the
Company"), as well as the financial statements of 50% owned subsidiaries (Notes
13 and 14) with recognition of the minority stockholder's share of equity and
income as minority interest in the balance sheet and income statements. 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. See Note 16 regarding restatement of financial statements.
All common stock shares and per share amounts in the accompanying financial
statements have been adjusted for the three-for-two stock splits effected on
March 19, 1997 and February 25, 1998.
The Company is an independent oil and gas company with production and
exploration concentrated in Texas, Oklahoma, Arkansas, Kansas, New Mexico,
Wyoming and Alaska. The Company also gathers, processes and markets gas,
transports and markets oil and conducts other activities directly related to the
oil and gas producing industry.
Property and Equipment
The Company follows the successful efforts method of accounting,
capitalizing costs of successful exploratory wells and expensing costs of
unsuccessful exploratory wells. Exploratory geological and geophysical costs
are expensed as incurred. All developmental costs are capitalized. The Company
generally pursues acquisition and development of proved reserves, although the
Company increased its exploration activities in 1997 and 1998. Most of the
property costs reflected in the accompanying consolidated balance sheets are
from acquisitions of producing properties from other oil and gas companies.
Producing properties balances include costs of $27,937,000 at December 31, 1999
and $15,859,000 at December 31, 1998, related to wells in process of drilling.
Depreciation, depletion and amortization of producing properties is
computed on the unit-of-production method based on estimated proved oil and gas
reserves. Other property and equipment is generally depreciated using the
straight-line method over estimated useful lives which range from 3 to 40 years.
Repairs and maintenance are expensed, while renewals and betterments are
generally capitalized. The estimated undiscounted cost, net of salvage value,
of dismantling and removing major oil and gas production facilities, including
necessary site restoration, are accrued using the unit-of-production method.
If conditions indicate that long-term assets may be impaired, the carrying
value of property, plant and equipment intended to be retained is compared to
management's future estimated pretax cash flow. If impairment is necessary, the
asset carrying value is adjusted to fair value. Cash flow pricing estimates are
based on existing proved reserve and production information and pricing
assumptions that management believes are reasonable. Impairment of individually
significant undeveloped properties is assessed on a property-by-property basis,
and impairment of other undeveloped properties is assessed and amortized on an
aggregate basis. The Company recorded an impairment provision on producing
properties of $2,040,000 before income tax in 1998.
37
Royalty Trusts
The Company created Cross Timbers Royalty Trust in February 1991 and
Hugoton Royalty Trust in December 1998 by conveying defined net profits
interests in certain of the Company's properties. Units of both trusts are
traded on the New York Stock Exchange. The Company makes monthly net profits
payments to each trust based on revenues and costs from the related underlying
properties. The Company owns 22.7% of Cross Timbers Royalty Trust units that it
purchased on the open market in 1996 and 1997, and owns 57.3% of the Hugoton
Royalty Trust following the sale of units in the trust's initial public offering
(Note 12). The cost of the Company's interest in the trust is included in
producing properties. Amounts due the trusts, net of amounts retained by the
Company's ownership of trust units, are deducted from the Company's revenues,
taxes, production expenses and development costs. As of January 1, 1999, the
Company no longer records the trusts' portion of development costs as an expense
in the consolidated statement of operations.
The Company planned to create the Texas Permian Trust in 1999 and sell
approximately 40% of the trust units in a public offering. However, because of
the depressed market for oil and gas equities, the Company decided not to create
the trust and to instead sell a portion of the related properties (Note 20).
The Company may later create a trust with the remaining properties, depending on
market conditions.
Cash and Cash Equivalents
Cash equivalents are considered to be all highly liquid investments having
an original maturity of three months or less.
Investment in Equity Securities
In accordance with Statement of Financial Accounting Standards No. 115,
Accounting for Certain Investments in Debt and Equity Securities, equity
securities acquired since 1997 are recorded as trading securities since such
securities were acquired principally for resale in the near future.
Accordingly, this investment is recorded as a current asset at market value,
unrealized holding gains and losses are recognized in the consolidated
statements of operations, and cash flows from purchases and sales of equity
securities are included in cash provided (used) by operating activities in the
consolidated statements of cash flows. Gains (losses) on trading securities and
interest expense related to the cost of these investments are classified as
other income (expense) in the consolidated statements of operations. See Note
2.
Other Assets
Other assets primarily include deferred debt costs that are amortized over
the term of the related debt (Note 4). Other assets are presented net of
accumulated amortization of $7,224,000 at December 31, 1999 and $4,697,000 at
December 31, 1998.
Derivatives
The Company uses derivatives on a limited basis to hedge interest rate and
product price risks, as opposed to their use for trading purposes. Amounts
receivable or payable under interest swap agreements are recorded as adjustments
to interest expense. Gains and losses on commodity futures contracts and other
price risk management instruments are recognized in oil and gas revenues when
the hedged transaction occurs. Cash flows related to derivative transactions
are included in operating activities. See Note 8.
Revenue Recognition
The Company uses the entitlement method of accounting for gas sales, based
on the Company's net revenue interest in production. Accordingly, revenue is
deferred when gas deliveries exceed the Company's net revenue interest, while
revenue is accrued for under-deliveries. Production imbalances are generally
recorded at the estimated sales price in effect at the time of production. At
December 31, 1999, the Company recorded a payable of $4,109,000 for an
overproduced balancing position of 2,215,000 Mcf of natural gas, and a
receivable of $3,903,000 for an underproduced balancing position of 9,076,000
Mcf of carbon dioxide. At December 31, 1998, the Company recorded a net
receivable
38
of $4,904,000 for a net underproduced balancing position of 885,000 Mcf of
natural gas and 7,909,000 Mcf of carbon dioxide.
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 $66.2 million for 1999, $56.3 million for 1998 and $57.1 million for
1997. 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 Hugoton Royalty Trust units (Note 12),
the Company realized gains on sale of property and equipment of $6,390,000 in
1999, $795,000 in 1998 and $1,757,000 in 1997.
Interest Expense
Interest expense includes amortization of deferred debt costs and is
presented net of interest income of $619,000 in 1999, $91,000 in 1998 and
$71,000 in 1997, and net of capitalized interest of $1,353,000 in 1999,
$1,070,000 in 1998 and $1,185,000 in 1997. 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 with an exercise price
equal to or above the common stock price on the grant date. Compensation
related to performance share grants is recognized from the grant date until the
performance conditions are satisfied, based on the market price of the Company's
common stock. The pro forma effect of recording stock-based compensation at the
estimated fair value of awards on the grant date, as prescribed by SFAS No. 123,
Accounting for Stock-Based Compensation, is disclosed in Note 11.
Earnings per Common Share
Effective December 31, 1997, the Company adopted SFAS No. 128, Earnings Per
Share, which changed the method of computing and disclosing earnings per share
for all periods. Under SFAS No. 128, the Company must report basic earnings per
share, which excludes the effect of potentially dilutive securities, and diluted
earnings per share, which includes the effect of all potentially dilutive
securities unless their impact is antidilutive. The Company previously only
reported earnings per share excluding potentially dilutive securities because
their effect was antidilutive or less than 3% dilutive, as prescribed by the
accounting pronouncement superseded by SFAS No. 128. See Note 9.
Segment Reporting
In accordance with SFAS No. 131, Disclosures about Segments of an
Enterprise and Related Information, the Company has identified only one
operating segment, which is the exploration and production of oil and gas. All
the Company's assets are located in the United States and all its revenues are
attributable to United States customers.
There were no sales to a single purchaser that exceeded 10% of total
revenues in 1999 or 1998. In 1997, gas sales to one purchaser were
approximately 14% of total revenues.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, which was required
to be adopted for fiscal years beginning after June 15, 1999. In July 1999, the
Financial Accounting Standards Board issued SFAS No. 137 which delays the
effective date of
39
Statement 133 for one year, to fiscal years beginning after June 15, 2000.
Adoption of SFAS No. 133 should have no significant impact on the Company's
reported earnings, but could materially affect comprehensive income.
2. Investment in Equity Securities
In 1998, the Company purchased what it believed to be undervalued oil and
gas reserves through investments in publicly traded equity securities of select
energy companies. After selling a portion of these securities in 1998 and 1999,
the Company's investment in equity securities had a fair market value of $29.1
million at December 31, 1999. Because classified as trading securities, this
investment at December 31, 1999 is recorded as a current asset at market value.
Realized gains and losses are computed based on a first-in, first-out
determination of cost of securities sold.
The following are components of gain (loss) on investment in equity
securities (in thousands):
1999 1998 1997
--------- --------- -------
Realized gains (losses) on sale of securities:
Gains............................................ $ 823 $ 887 $2,400
Losses........................................... (23,047) (15,706) -
-------- -------- ------
Net gains (losses)............................... (22,224) (14,819) 2,400
Decrease (increase) in net unrealized losses (a)... 27,070 (72,605) -
Interest expense related to investment in
equity securities................................ (5,995) (6,295) (665)
-------- -------- ------
Gains (losses) on investment in equity securities.. $ (1,149) $(93,719) $1,735
======== ======== ======
(a) Because investments in equity securities were recorded as
available-for-sale securities prior to 1998, unrealized gains and
losses for 1997 are reported as a component of stockholders' equity, as
shown in the Consolidated Statements of Comprehensive Income.
On September 15, 1999, as a portion of its investment in Whitewine Holding
Company ("Whitewine"), a consolidated subsidiary with a 50% minority interest
(Note 14), the Company contributed equity securities with a value of $36.8
million on that date to Whitewine. The Company has a call option to purchase
these securities from Whitewine at this contributed value until September 14,
2000. As of December 31, 1999, the equity securities held by Whitewine had a
fair market value of $27.1 million.
During the first quarter of 2000, the Company sold most of its investment
in equity securities for proceeds of $41.1 million, resulting in a gain of $14.4
million, of which $17.1 million was a decrease in unrealized loss. Remaining
equity securities are held by Whitewine and had a March 24, 2000 value of $1.7
million.
3. Related Party Transactions
Loans to Officers
Pursuant to margin support agreements with each of six officers, the
Company, with Board of Directors authorization, agreed to use up to $15 million
of the value of Cross Timbers Royalty Trust units owned by the Company and
investment in equity securities other than those held by Whitewine (Note 2), to
provide margin support for the officers' broker accounts in which they held
Company common stock. The Company also agreed to pay each officer's margin debt
to the extent unpaid by the officer. In connection with these agreements, in
December 1998 the Company loaned four officers a total of $5,795,000 to reduce
their margin debt. An additional $1,530,000 was loaned during 1999, including a
new loan to a fifth officer. The loans are full recourse and due in December
2003, with an interest rate equal to the Company's bank debt rate. At each
balance sheet date, the loans are reviewed to determine whether a reserve for
collectibility should be booked as compensation expense. To date, no reserve
for collectibility has been recorded. At March 1, 2000, total officer margin
debt on their broker accounts was $10.5 million. At that date, the market value
of the Company's Cross Timbers Royalty Trust units was approximately $16
million; all of the Company's
40
equity securities were sold during the first quarter of 2000 with the exception
of securities with a value of $1.7 million on March 24, 2000 held by Whitewine.
Other Transactions
A company, partially owned by a director of the Company, is currently
performing consulting services in connection with the Company's divestiture of
oil and gas properties in West Texas and eastern New Mexico (Note 20). The
Company expects to pay the director-related company a transaction fee of
approximately $800,000 that will be due upon sale of the properties. The
director-related company also represented the purchaser of properties sold by
the Company during 1999 and invested in the purchase. The same director-related
company performed consulting services in 1998 in connection with the Cook Inlet
Acquisition (Note 15). After the Company recovers its acquisition costs,
including interest and subsequent property development and operating costs, the
director-related company will receive, at its election, either a 20% working
interest or a 1% overriding interest conveyed from the Company's 100% working
interest in these properties. In 1997, the Company paid fees of $1.6 million to
this director-related company in connection with property sales and the Amoco
Acquisition (Note 15). These fees have effectively been recorded as a property
cost.
4. Debt
The Company's outstanding debt consists of the following (in thousands):
December 31
------------------
1999 1998
-------- --------
Short-term Debt:
Short-term borrowings................................................... $ - $ 4,962
======== ========
Long-term Debt:
Senior debt-
Bank debt under revolving credit agreements due June 30, 2003, 7.4%.
(a).................................................................. $439,000 $615,000
Subordinated debt-
9 1/4% senior subordinated notes due April 1, 2007.................... 125,000 125,000
8 3/4% senior subordinated notes due November 1, 2009................. 175,000 175,000
Spring Holding Company-
Senior bank debt, 8.5%.(a)............................................ 116,100 -
Senior subordinated debt, 12.9%.(a)................................... 7,000 -
Summer Acquisition Company-
Senior bank debt, 8.5%.(a)............................................ 129,000 -
Other long-term debt (restated - Note 17)............................... - 5,411
-------- --------
Total long-term debt.................................................... $991,100 $920,411
======== ========
(a) LIBOR-based rate at January 4, 2000.
Senior Debt
On November 16, 1998, the Company entered a new revolving credit agreement
with commercial banks ("loan agreement"). The Company amended the loan agreement
on August 15, 1999, and as of December 31, 1999, the loan agreement had a
borrowing base and commitment of $468 million and $29 million unused borrowing
capacity. Other significant provisions of the revolving credit agreement
remained unchanged. The borrowing base is redetermined annually based on the
value and expected cash flow of the Company's proved oil and gas reserves. If
borrowings exceed the redetermined borrowing base, the banks may require that
the excess be repaid within a year. Otherwise, borrowings under the loan
agreement do not mature until June 30, 2003, but may be prepaid at any time
without penalty. The Company periodically renegotiates the loan agreement to
increase the borrowing commitment and extend the
41
revolving facility. The borrowing base is expected to be redetermined in May
2000 in connection with the consolidation of bank debt of the Company, Spring
Holding Company and Summer Acquisition Company. Based on year-end proved
reserves and relatively strong commodity prices, the Company expects a
significant increase in the borrowing base upon its redetermination.
Restrictions set forth in the loan agreement include limitations on the
incurrence of additional indebtedness, the creation of certain liens, and the
redemption or prepayment of subordinated indebtedness. The loan agreement also
limits dividends to 25% of cash flow from operations, as defined, for the latest
four consecutive quarterly periods. The Company is also required to maintain a
current ratio of not less than one (where unused borrowing commitments are
included as a current asset).
The loan agreement provides the option of borrowing at floating interest
rates based on the prime rate or at fixed rates for periods of up to six months
based on certificate of deposit rates or LIBOR. Borrowings under the loan
agreement at December 31, 1999 were based on the prime rate in anticipation of
potential interest rate increases due to Year 2000 concerns. On January 4, 2000,
the borrowings reverted to LIBOR rates with a maturity of one to six months and
accrued at the applicable LIBOR rate plus 1 3/8%. Interest is paid at maturity,
or quarterly if the term is for a period of 90 days or more. The Company also
incurs a commitment fee of 3/8% on unused borrowing commitments. The weighted
average interest rate on senior debt was 6.7% during 1999, and 6.9% during 1998
and 1997. See Note 8 regarding interest rate swap agreements.
Subordinated Debt
The Company sold $125 million of 9 1/4% senior subordinated notes ("9 1/4%
Notes") on April 2, 1997, and $175 million of 8 3/4% senior subordinated notes
("8 3/4% Notes") on October 28, 1997 (the 9 1/4% Notes and the 8 3/4% Notes are
collectively referred to as "the Notes"). The Notes are general unsecured
indebtedness that is subordinate to bank borrowings under the loan agreement.
Net proceeds of $121.1 million from the 9 1/4% Notes and $169.9 million from the
8 3/4% Notes were used to reduce bank borrowings under the loan agreement. The
9 1/4% Notes mature on April 1, 2007 and interest is payable each April 1 and
October 1, while the 8 3/4% Notes mature on November 1, 2009 with interest
payable each May 1 and November 1.
The Company has the option to redeem the 9 1/4% Notes on April 1, 2002 and
the 8 3/4% Notes on November 1, 2002 at a price of approximately 105%, and
thereafter at prices declining ratably at each anniversary to 100% in 2005. In
addition, on or prior to April 1, 2000 for the 9 1/4% Notes and November 1, 2000
for the 8 3/4% Notes, the Company may redeem up to one-third of the Notes with
the net proceeds from one or more public equity offerings at a price of
approximately 109% plus accrued interest, subject to certain requirements. Upon
a change in control of the Company, the holders of the Notes have the right to
require the Company to purchase all or a portion of their Notes at 101% plus
accrued interest.
The Notes were issued under indentures that place certain restrictions on
the Company, including limitations on additional indebtedness, liens, dividend
payments, treasury stock purchases, disposition of proceeds from asset sales,
transfers of assets and transactions with subsidiaries and affiliates.
To reduce the interest rate on a portion of its subordinated debt, the
Company entered an agreement with a bank that has purchased on the market Notes
with a face value of $21.6 million. The Company pays the bank a variable
interest rate based on three-month LIBOR rates, and receives semiannually from
the bank the fixed interest rate on the Notes. The term of the agreement for
approximately half the Notes is through April 2002, and for the remaining half
is through November 2002. Any change in market value of the Notes from the date
purchased by the bank is payable to or receivable from the bank. The Company
has funded market value depreciation of $169,000 through December 31, 1999. The
Company has the option of repurchasing the Notes from the bank at any time at
market value.
Spring Holding Company
Spring Holding Company ("Spring") (Note 13) has a $140 million revolving
credit facility with commercial banks which had a borrowing base of $130 million
and unused borrowing capacity of $13.9 million at December 31, 1999. The
borrowing base is subject to semiannual redetermination. The credit facility is
secured by properties owned by Spring and is nonrecourse to the Company.
Borrowings under the credit facility mature on July 31, 2004.
42
Restrictions set forth in the credit facility include the maintenance of a
minimum consolidated net worth of $35 million and minimum current and other
ratios.
The credit facility 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 LIBOR. Borrowings under the credit facility at December 31, 1999 were
based on the prime rate plus 1%. On January 4, 2000, the borrowings reverted to
LIBOR rates with a maturity of one month and accrued at the applicable LIBOR
rate plus 2.5%.
Spring also has a senior subordinated term loan outstanding, which had a
principal balance of $7 million at December 31, 1999. This loan has a secondary
lien on Spring's properties and matures on July 31, 2008. On December 31, 1999,
interest accrued at a rate of LIBOR plus 7%. This spread increases 0.5%
quarterly. Other terms of the subordinated loan are substantially the same as
the Spring revolving credit facility.
Summer Acquisition Company
Summer Acquisition Company ("Summer") (Note 14) has a $140 million
revolving credit facility with commercial banks which had a borrowing base of
$140 million and unused borrowing capacity of $11 million at December 31, 1999.
The borrowing base is subject to semiannual redetermination. Borrowings under
the credit facility were used to partially fund properties acquired from
affiliates of Ocean Energy, Inc. The credit facility is secured by the
properties acquired and is nonrecourse to the Company and Lehman Brothers
Holdings, Inc. Borrowings under the credit facility mature on September 15,
2001. Restrictions set forth in the credit facility include limitations on the
payment of dividends and general and administrative expenses, and maintenance of
a minimum consolidated net worth of $85 million and minimum current and other
ratios.
The credit facility 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 LIBOR. Borrowings under the credit facility at December 31, 1999 were
based on the prime rate plus 1.5%. On January 4, 2000, the borrowings reverted
to LIBOR rates with a maturity of one month and accrued at the applicable LIBOR
rate plus 2.5%.
Other Debt
As part of the Cook Inlet Acquisition, the Company executed a $6 million
non-interest bearing promissory note payable to Shell. This note was due when
NYMEX crude oil prices increased to specified levels, and was paid in August and
September 1999.
See also Note 7 "-Registration Statement."
5. Income Tax
The effective income tax rate for the Company was different than the
statutory federal income tax rate for the following reasons (in thousands):
1999 1998 1997
------- -------- -------
Income tax expense (benefit) at the
federal statutory rate of 34%.......................................... $24,006 $(35,893) $13,329
State and local taxes and other......................................... (41) 42 188
------- -------- -------
Income tax expense (benefit)............................................ $23,965 $(35,851) $13,517
======= ======== =======
Components of income tax expense (benefit) are as follows (in thousands):
1999 1998 1997
------- -------- -------
Current income tax...................................................... $ 308 $ (107) $ 124
Deferred income tax expense (benefit)................................... 28,697 (2,626) 22,509
Net operating loss carryforward......................................... (5,040) (33,118) (9,116)
------- -------- -------
Income tax expense (benefit)............................................ $23,965 $(35,851) $13,517
======= ======== =======
43
Deferred tax assets and liabilities are the result of temporary
differences between the financial statement carrying values and tax bases of
assets and liabilities. The Company's net deferred tax liabilities are recorded
as a current asset of $4,168,000 and a long-term liability of $25,975,000 at
December 31, 1999, and a current asset of $24,816,000 and a long-term liability
of $6,892,000 at December 31, 1998. Significant components of net deferred tax
assets and liabilities are (in thousands):
December 31
------------------
1999 1998
-------- -------
Deferred tax assets:
Net operating loss carryforwards......................................... $ 64,118 $54,044
Accrued stock appreciation right and performance share compensation...... 985 576
Unrealized loss on trading securities.................................... 6,103 24,686
Other.................................................................... 2,891 2,626
-------- -------
Total deferred tax assets......................................... 74,097 81,932
-------- -------
Deferred tax liabilities:
Property and equipment................................................... 92,115 61,689
Other.................................................................... 3,789 2,319
-------- -------
Total deferred tax liabilities.................................... 95,904 64,008
-------- -------
Net deferred tax assets (liabilities)...................................... $(21,807) $17,924
======== =======
As of December 31, 1999, the Company has estimated tax loss carryforwards
of approximately $190 million, of which $23 million are related to capital
losses. The capital loss tax carryforwards expire in 2004 while the remaining
$167 million are scheduled to expire in 2008 through 2014. Approximately $15
million of the tax loss carryforwards are the result of the Spring Acquisition.
6. Commitments and Contingencies
Leases
The Company leases offices, vehicles and certain other equipment in its
primary locations under noncancelable operating leases. As of December 31,
1999, minimum future lease payments for all noncancelable lease agreements
(including the sale and operating leaseback agreements described below) were as
follows (in thousands):
2000..................... $ 9,244
2001..................... 9,020
2002..................... 8,867
2003..................... 8,683
2004..................... 4,559
Remaining................ 14,531
-------
Total.................... $54,904
=======
Amounts incurred by the Company under operating leases (including renewable
monthly leases) were $14,093,000 in 1999, $11,180,000 in 1998 and $9,132,000 in
1997.
In March 1996, the Company sold its Tyrone gas processing plant and related
gathering system for $28 million and entered an agreement to lease the facility
from the buyers for an initial term of eight years at annual rentals of $4
million, and with fixed renewal options for an additional 13 years. This
transaction was recorded as a sale and operating leaseback, with no gain or loss
on the sale.
In November 1996, the Company sold its gathering system in Major County,
Oklahoma for $8 million and entered an agreement to lease the facility from the
buyers for an initial term of eight years, with fixed renewal options for an
additional 10 years. Rentals are adjusted monthly based on the 30-day LIBOR rate
and may be irrevocably fixed
44
by the Company with 20 days advance notice. As of December 31, 1999, 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.
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, each officer receives a minimum annual salary of
$300,000 and is entitled to participate in any incentive compensation programs
administered by the Board of Directors. The agreements also provide that, in the
event the officer terminates his employment for good reason, as defined in the
agreement, the officer will receive severance pay equal to the amount that would
have been paid under the agreement had it not been terminated. If such
termination follows a change in control of the Company, the officer is entitled
to a lump-sum payment of three times his most recent annual compensation.
Commodity Commitments
The Company has entered gas futures contracts to sell 50,000 Mcf of gas per
day from April through October 2000 at prices ranging from $2.32 to $2.41 per
Mcf and 70,000 Mcf of gas per day from November 2000 to December 2001 at prices
ranging from $2.41 to $2.57 per Mcf. In conjunction with these futures
contracts, the Company has entered into natural gas call options to sell 10,000
Mcf of gas per day from April through October 2000 at a ceiling price of $2.91
per Mcf, to sell 10,000 Mcf per day from January through December 2001 at a
ceiling price of $2.63 per Mcf and to sell 20,000 Mcf of gas per day in the San
Juan Basin at an average ceiling index price of $2.75 per Mcf for the year 2001.
Prices to be realized for hedged production will be less than these NYMEX prices
because of location, quality and other adjustments.
The Company has entered gas basis swap agreements which effectively fix
Arkoma Basin basis at $0.11 per Mcf for 40,000 to 72,500 Mcf per day from April
2000 to January 2001, East Texas basis at $0.10 for 5,000 Mcf per day through
September 2000, Oklahoma basis at $0.10 per Mcf for 30,000 Mcf per day through
August and 20,000 Mcf per day for September and October 2000, Houston ship
channel basis at $0.02 per Mcf for 40,000 Mcf per day through October 2000, and
San Juan Basin basis at $0.28 per Mcf for 10,000 Mcf per day through December
2000.
The Company's termination of futures contracts related to first quarter
2000 gas production, including the effects of basis swap agreements, resulted in
a net loss of $1.3 million. This loss will be recognized as a decrease in gas
revenue of approximately $0.04 per Mcf in the first quarter of 2000.
The Company has entered oil futures contracts to sell 8,000 Bbls per day
from April through June 2000 at prices ranging from $22.04 to $23.28 per Bbl.
Prices to be realized for hedged production will be less than these NYMEX prices
because of location, quality and other adjustments.
The Company has crude oil differential swaps to sell 8,000 Bbls of oil per
day through June 2000 at the posted price plus an average of $3.38 per Bbl and
2,500 Bbls of oil per day from July through September 2000 at the posted price
plus $3.18. The Company also has a sweet sour differential swap to sell 2,000
Bbls of oil per day through June 2000 at the posted price plus $1.25 per Bbl.
The Company's termination of futures contracts related to first quarter
2000 oil production resulted in a net loss of $3.3 million. This loss will be
recognized as a decrease in oil revenue of approximately $2.68 per Bbl in first
quarter 2000.
45
As partial consideration for the Cook Inlet Acquisition (Note 15), the
Company agreed to sell to Shell 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, 1999, $1.6 million is recorded in other current liabilities
and $4.4 million is recorded in other long-term liabilities related to this
commitment.
The Company has committed to sell all gas production from certain
properties in the East Texas Basin Acquisition (Note 15) to EEX Corporation at
market prices through the earlier of December 31, 2001, or until a total of
approximately 34.3 billion cubic feet (27.8 billion cubic feet net to the
Company's interest) of gas has been delivered. Based on current production, this
sales commitment is approximately 24,700 Mcf (20,000 Mcf net to the Company's
interest) per day.
As a part of the Ocean Energy Acquisition, the Company assumed a commitment
to sell 6,800 Mcf of gas per day through April 2003 at a price of $0.53 per Mcf.
Delivery of the committed volumes is in Arkansas.
From August 1995 through July 1998 the Company received an additional $0.30
to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, the
Company agreed to sell 11,650 Mcf per day from August 1998 through May 2000 at
the index price and 21,650 Mcf per day from June 2000 through July 2005 at a
price of approximately 10% of the average NYMEX futures price for intermediate
crude oil.
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, which actions reduced
the royalties paid to the plaintiffs and those similarly situated, and that such
actions are a breach of the leases under which the royalties are paid. 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 other third party gatherers or processors. The
Company further contends that any such fees enhance the value of the gas or the
products derived from the gas. The plaintiffs are seeking an accounting and
payment of the monies allegedly owed to them. A hearing on the class
certification issue has not been scheduled. Management believes it has strong
defenses against this claim and intends to vigorously defend the action.
Management's estimate of the potential liability from this claim has been
accrued in the Company's financial statements.
On October 17, 1997, an action, styled United States of America ex rel.
Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District
Court for the Western District of Oklahoma against the Company and certain of
its subsidiaries by Jack J. Grynberg on behalf of the United States under the
qui tam provisions of the False Claims Act. The plaintiff alleges that the
Company underpaid royalties on gas produced from federal leases and lands owned
by Native Americans by at least 20% during the past 10 years as a result of
mismeasuring the volume of gas and incorrectly analyzing its heating content.
The plaintiff 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 has made similar allegations in over
70 actions filed against over 300 other companies. After its review, the
Department of Justice decided in April 1999 not to intervene, and the court
unsealed the case in May 1999. A federal multi-district litigation panel has
ordered that the lawsuits filed by Grynberg against the Company and other
companies be transferred and consolidated to the federal district court in
Wyoming. The Company and other defendants have filed a motion to dismiss the
lawsuit. The Company believes that the allegations of this lawsuit are without
merit and intends to vigorously defend the action.
46
The Company is involved in various other lawsuits and certain governmental
proceedings arising in the ordinary course of business. Company management and
legal counsel do not believe that the ultimate resolution of these claims,
including the lawsuits described above, will have a material effect on the
Company's financial position, liquidity or operations.
Other
To date, the Company's expenditures to comply with environmental or safety
regulations have not been significant and are not expected to be significant in
the future. However, developments such as new regulations, enforcement policies
or claims for damages could result in significant future costs.
On September 30, 1999, the Company entered a consulting contract with a
former officer for services to be provided through September 2000 for a monthly
fee of $40,000.
See also Note 3.
7. Equity
Three-for-Two Stock Splits
The Company effected a three-for-two common stock split on February 25,
1998 and March 19, 1997. All common stock shares, treasury stock shares and per
share amounts have been retroactively restated to reflect these stock splits.
Common Stock
On April 27, 1998, the Company completed a public offering of 7,500,000
shares of common stock, of which 7,203,450 shares were sold by the Company and
296,550 shares were sold by a stockholder. The Company's net proceeds from the
offering of $133.1 million were used to partially repay bank debt used to fund
the East Texas Basin Acquisition (Note 15). The offering was made pursuant to
the shelf registration statement filed with the Commission in February 1998.
See "Registration Statement" below.
On September 30, 1998, the Company issued from treasury 1,921,850 shares to
Shell Western E&P, Inc., Shell Deepwater Development Holdings, Inc., and Shell
Offshore Inc. ("Shell") for the Cook Inlet Acquisition (Note 15). The Company
effectively guaranteed Shell a $20 per share value. As of December 31, 1998, as
restated, these shares were valued at $20.00 per share, or a total of $38.4
million (Note 17). The $20 guarantee was effectively settled in July 1999 upon
the Company's repurchase of these shares from Shell at $13.25 per share, or
$25.5 million, and net additional payments to Shell of $13 million which was
charged to equity at that date.
On July 1, 1999, the Company issued 4,000,000 shares of common stock at its
fair value of $11.425 per share in exchange for its 50% interest in Spring
Holding Company and for cash proceeds of $3.2 million which were used to reduce
bank debt (Note 13).
On July 8, 1999, the Company sold from treasury 2,000,000 shares of common
stock in an underwritten public offering for net proceeds of approximately $26.5
million. The proceeds were used to repurchase the 1,921,850 shares of common
stock issued to Shell for the Cook Inlet Acquisition. The offering was made
pursuant to the shelf registration statement filed with the Commission in
February 1998.
On September 15, 1999, the Company issued from treasury 4,555,756 shares of
its common stock to Whitewine Holding Company ("Whitewine") at its fair value of
$13.875 per share as part of its contribution for its 50% interest in Whitewine
(Note 14). These common shares are eliminated in the consolidated financial
statements.
47
Performance Shares
The Company issued performance shares totaling 141,813 shares in 1999,
82,125 shares in 1998 and 180,000 shares in 1997 (Note 11). In October 1999,
12,000 performance shares were forfeited from the shares issued in 1998. In
January 2000, an additional 120,000 performance shares were issued.
Treasury Stock
The Company's open market treasury share acquisitions totaled 5,000 shares
in 1999 at an average price of $10.60, 4.3 million shares in 1998 at an average
price of $15.26 per share and 2.4 million shares in 1997 at an average price of
$11.67 per share. Through March 27, 2.2 million shares have been repurchased in
2000 at a cost of $22.3 million, and 1.2 million shares remain under the
February 2000 Board of Directors' authorization to repurchase 2.5 million
shares of the Company's common stock.
Stockholder Rights Plan
On August 25, 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.
Registration Statement
In February 1998, the Company filed a shelf registration statement with the
Commission to potentially offer securities which may include debt securities,
preferred stock, common stock or warrants to purchase debt securities, preferred
stock or common stock. The shelf registration statement was amended on April 8,
1998 to increase the maximum total price of securities to be offered to $400
million, at prices and on terms to be determined at the time of sale. Net
proceeds from the sale of such securities will be used for general corporate
purposes, including reduction of bank debt. After the April 1998 and July 1999
common stock offerings, $227.3 million remains available under the shelf
registration statement for future sales of securities.
Common Stock Warrants
As partial consideration for producing properties acquired in December
1997, the Company issued warrants to purchase 944,284 shares of common stock at
a price of $15.20 per share for a period of five years. These warrants were
valued at $5,725,000 and recorded as additional paid-in capital.
Common Stock Dividends
The Board of Directors declared quarterly dividends of $0.037 per common
share in 1997, $0.04 per common share in 1998 and $0.01 per common share in
1999. See Note 4 regarding restrictions on dividends.
Series A Convertible Preferred Stock
Series A convertible preferred stock is recorded in the accompanying
consolidated balance sheets at its liquidation preference of $25 per share.
Cumulative dividends on preferred stock are payable quarterly in arrears, when
declared by the Board of Directors, based on an annual rate of $1.5625 per
share. The preferred stock has no stated maturity and no sinking fund, and is
redeemable, in whole or in part, by the Company. Redemption is allowed only
under certain circumstances on or before October 15, 2000 at $26.09 per share,
and thereafter unconditionally at prices
48
declining ratably annually to $25.00 per share after October 15, 2006, plus
dividends accrued and unpaid to the redemption date.
The preferred stock is convertible at the option of the holder at any time,
unless previously redeemed, into shares of common stock at a rate of 2.16 shares
of common stock for each share of preferred stock, subject to adjustment in
certain events. Preferred stock holders are allowed one vote for each common
share into which their preferred stock may be converted.
Convertible Debt
In January 1997, $29.7 million principal of the Company's 5 1/4%
convertible subordinated notes was converted by noteholders into 2,892,363
shares of common stock.
8. Financial Instruments
The Company uses financial and commodity-based derivative contracts to
manage exposures to interest rate and commodity price fluctuations. The Company
does not hold or issue derivative financial instruments for speculative or
trading purposes.
Commodity Price Hedging Instruments
The Company periodically enters into futures contracts, energy swaps,
collars, basis swaps and option agreements to hedge its exposure to price
fluctuations on crude oil and natural gas sales. In 1999, the Company
recognized net losses on futures contracts and basis swap transactions of $5.7
million related to gas hedging and $2.2 million related to oil hedging. During
1998, the Company recognized net gains of $7.7 million related to gas hedging.
These gains and losses are recorded as a component of oil and natural gas sales.
The Company did not have significant commodity hedging activity during 1997.
See Note 6.
Interest Rate Swap Agreements
In September 1998, to reduce variable interest rate exposure on debt, the
Company entered into a series of interest rate swap agreements, effectively
fixing its interest rate at an average of 6.9% on a total notional balance of
$150 million until September 2005. Settlements of net amounts due are made
quarterly, based on LIBOR rates, which is the same interest rate basis as the
Company's senior debt borrowings.
In 1999, the Company terminated its interest rate swaps on notional
balances totaling $100 million, resulting in proceeds received and a gain of
$1.1 million. This gain has been deferred and is being amortized against
interest expense through September 2005. The Company sold a call option for
$880,000 that allows the counterparty to terminate the interest rate swap on the
remaining $50 million notional balance in November 2000. The call option
proceeds have been recorded as deferred revenue until November 2000 when they
will be amortized against interest expense through September 2005.
49
Fair Value
Because of their short-term maturity, the fair value of cash and cash
equivalents, accounts receivable and accounts payable approximates their
carrying values at December 31, 1999 and 1998. The following are estimated fair
values and carrying values of the Company's other financial instruments at each
of these dates (in thousands):
Asset (Liability)
------------------------------------------------------
December 31, 1999 December 31, 1998
---------------------- ------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ---------- ---------- ------------------
(Restated)
Investment in equity securities.. $ 29,052 $ 29,052 $ 44,386 $ 44,386
Short-term debt.................. - - (4,962) (4,962)
Long-term debt................... (991,100) (981,540) (920,411) (894,750)
Futures contracts................ - (2,676) - 3,525
Basis swap agreements............ - (1,113) - (690)
Interest rate swap agreements.... - 574 - (2,722)
The fair value of short-term borrowings and bank borrowings approximates
the carrying value because of short-term interest rate maturities. The fair
value of investment in equity securities and subordinated long-term debt is
based on current market quotes. The fair value of futures contracts and swap
agreements is estimated based on current commodity prices and interest rates.
Concentrations of Credit Risk
Although the Company's cash equivalents and derivative financial
instruments are exposed to the risk of credit loss, the Company does not believe
such risk to be significant. Cash equivalents are high-grade, short-term
securities, placed with highly rated financial institutions. Most of the
Company's receivables are from a broad and diverse group of energy companies
and, accordingly, do not represent a significant credit risk. The Company's gas
marketing activities generate receivables from customers including pipeline
companies, local distribution companies and end-users in various industries.
Letters of credit or other appropriate security are obtained as considered
necessary to limit risk of loss. The Company recorded an allowance for
collectibility of all accounts receivable of $2,150,000 at December 31, 1999 and
$375,000 at December 31, 1998. The Company's bad debt expense was $1,347,000 in
1999, $411,000 in 1998 and $79,000 in 1997. Financial and commodity-based swap
contracts expose the Company to the credit risk of non-performance by the
counterparty to the contracts. The Company does not believe this risk is
significant since these contracts are placed with major banks and financial
institutions.
9. Earnings Per Share
The following reconciles earnings (numerator) and shares (denominator) used
in the computation of basic and diluted earnings per share (in thousands, except
per share data):
Earnings
Earnings Shares per Share
--------- -------- ----------
1999
- ------------------------------------------------
Basic
Net income.................................... $ 46,743
Preferred stock dividends..................... (1,779)
--------
Earnings available to common stock - basic.... 44,964 46,818 $ 0.96
=========
Diluted
Effect of dilutive securities (a):
Stock options................................ - 108
Preferred stock dividends.................... 1,779 2,460
Warrants..................................... - -
-------- ------
Earnings available to common stock - diluted.. $ 46,743 49,386 $ 0.95
======== ====== =========
50
Earnings
Earnings Shares per Share
-------- -------- ---------
1998
- -------------------------------------------------
Basic
Net loss..................................... $(69,719)
Preferred stock dividends.................... (1,779)
--------
Loss available to common stock - basic....... (71,498) 43,396 $ (1.65)
=========
Diluted
Effect of dilutive securities:
Stock options............................... - 338
Warrants.................................... - 23
-------- ------
Loss available to common stock - diluted..... $(71,498) 43,757 $ (1.65)(b)
======== ====== =========
1997
- -------------------------------------------------
Basic
Net income................................... $ 25,684
Preferred stock dividends.................... (1,779)
--------
Earnings available to common stock - basic... 23,905 39,773 $ 0.60
=========
Diluted
Effect of dilutive securities:
Stock options.............................. - 451
Warrants.................................... - 3
5 1/4% convertible subordinated notes...... 46 115
-------- ------
Earnings available to common stock - diluted. $ 23,951 40,342 $ 0.59
======== ====== =========
(a) Based on common shares outstanding at December 31, 1999, potential
conversion of Series A convertible preferred stock becomes dilutive to
earnings per share when annual earnings available to common stock
exceeds approximately $35.4 million and when quarterly earnings
available to common stock exceeds approximately $8.8 million.
(b) Because of the antidilutive effect of dilutive securities on loss per
common share, diluted loss available to common stock is the same as
basic.
10. Supplemental Cash Flow Information
The consolidated statements of cash flows exclude the following non-cash
transactions :
- Issuance of warrants in 1997 to purchase 944,284 shares of common stock
and exchange of properties valued at $14.3 million, as partial
consideration for producing properties acquired
- Conversion of $29.7 million principal amount of 5 1/4% convertible
subordinated notes into 2,892,363 shares of common stock in 1997
- The Cook Inlet Acquisition on September 30, 1998, a purchase of oil-
producing properties for 1,921,850 shares of common stock, a related
effective guarantee of $20 per share value and a $6 million note payable
- Purchase of a 50% interest in Spring Holding Company, Inc. on July 1,
1999 in exchange for 3,720,000 shares of common stock, valued at $42.5
million
- Performance shares activity including:
- Grants of 141,813 shares in 1999, 82,125 shares in 1998 and 180,000
shares in 1997 to key employees and nonemployee directors
- Vesting of 81,000 shares in 1998 and 243,000 shares in 1997
51
- Forfeiture of 12,000 shares in 1999
- Receipt of common stock of 49,122 shares (valued at $721,000) in 1999,
8,904 shares (valued at $181,000) in 1998 and 421,212 shares (valued at
$5,430,000) in 1997 for the option price of exercised stock options and
royalty trust options
Interest payments in 1999 totaled $70,500,000 (including $1,353,000 of
capitalized interest), $57,200,000 in 1998 (including $1,070,000 of capitalized
interest) and $21,276,000 in 1997 (including $1,185,000 of capitalized
interest). Income tax payments were $941,000 in 1997; net income tax refunds
were $322,000 during 1999 and $454,000 during 1998.
11. Employee Benefit Plans
401(k) Plan
The Company sponsors a 401(k) benefit plan that allows employees to
contribute and defer a portion of their wages. The Company matches employee
contributions of up to 10% of wages (8% of wages prior to January 1, 1998).
Employee contributions vest immediately while the Company's matching
contributions vest 100% upon the earlier of three consecutive years of
participation in the plan or five years of service. All employees over 21 years
of age may participate. Company contributions under the plan were $2,514,000 in
1999, $1,766,000 in 1998 and $1,180,000 in 1997.
1991 Stock Incentive Plan
A total of 1,012,500 incentive units ("units") have been granted to
directors, officers and other key employees under the 1991 Stock Incentive Plan
("1991 Plan"). Units consist of a stock option and a stock appreciation right
("SAR"). An option provides the right to purchase one share of common stock at
the exercise price, which generally is the market price at the date the unit is
granted. A SAR entitles the recipient to a payment equal to twice the excess of
the market price of one share of common stock on the date the option is
exercised over the exercise price. As of December 31, 1999, there are 3,341
units available for grant under the 1991 Plan. General and administrative
expense includes a reduction of stock incentive compensation related to SARs of
$9,000 in 1999, $299,000 in 1998, and stock incentive compensation expense of
$359,000 in 1997. SAR cash payments were $180,000 in 1998 and $288,000 in 1997.
1994 and 1997 Stock Incentive Plans
Under the 1994 Stock Incentive Plan ("1994 Plan") and the 1997 Stock
Incentive Plan ("1997 Plan"), a total of 2,250,000 shares of common stock may be
issued under each plan to directors, officers and other key employees pursuant
to grants of stock options or performance shares of common stock ("performance
shares"). At December 31, 1999, there are 27,878 shares available for grant
under the 1994 Plan and 53,124 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 are not exercisable six months before or ten years
after its grant date. Options granted under the 1994 Plan and the 1997 Plan
generally vest in equal amounts over five years, with provisions for earlier
vesting if specified performance requirements are met. In May 1998, all options
under the 1994 Plan vested by resolution of the Board of Directors. As of
December 31, 1999, there are 382,875 outstanding stock options under the 1997
Plan that vest when the common stock price reaches $25.
1998 Stock Incentive Plan
In May 1998, the stockholders approved the 1998 Stock Incentive Plan ("1998
Plan") under which 6,000,000 shares of common stock are available for grant.
Grants under the 1998 Plan are subject to the provision that outstanding stock
options and performance shares under all the Company's stock incentive plans
cannot exceed 6% of the Company's outstanding common stock at the time such
grants are made. During 1999, there were 349,125 stock options granted under
the 1998 Plan. During 1998, 810,375 stock options were designated to be granted
to specific optionees upon each of their exercises of all outstanding vested
options granted under the 1997 Plan. Stock options 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.
52
Performance Shares
Performance shares granted under the 1994, 1997 and 1998 Plans are subject
to restrictions determined by the Committee and are subject to forfeiture if
performance targets are not met. Otherwise, holders of performance shares
generally have all the voting, dividend and other rights of other stockholders.
The Company issued performance shares to key employees totaling 130,000 in 1999,
72,000 in 1998 and 169,875 in 1997, of which 81,000 vested in 1998 and 243,000
vested in 1997 when the common stock price reached specified levels. In 1999,
12,000 performance shares issued in 1998 were forfeited. General and
administrative expense includes compensation related to these performance share
grants of $102,000 in 1999, $1.6 million in 1998 and $3.3 million in 1997. As
of December 31, 1999, there are 130,000 performance shares that vest when the
common stock price reaches $16.00 and 60,000 performance shares that vest when
the common stock price reaches $22.50. In January 2000, 120,000 performance
shares were granted that vest when the common stock price reaches $20.00. The
Company also issued to nonemployee directors a total of 11,813 performance
shares in 1999 and 10,125 performance shares in each of 1998 and 1997, which
vested upon grant.
Royalty Trust Option Plans
In May 1998, the stockholders approved the 1998 Royalty Trust Option Plan
("Option Plan"). Under the terms of the Option Plan, the Company may grant to
key employees options to purchase units of beneficial interest in one or more
royalty trusts that may be established by the Company. Such options will allow
the purchase of royalty trust units at fair market value on the date of grant in
an aggregate amount not to exceed $12 million. In December 1998, the Company
granted options to purchase 1,263,000 Hugoton Royalty Trust units at a price of
$9.50 per unit, or a total of $12 million. During 1999, an option to purchase
73,684 units was exercised, resulting in compensation expense of $60,000 (Note
12). Upon forfeiture of an option to purchase 147,000 units in January 2000,
174,000 options to purchase units were granted at a price of $8.03 per unit. The
Company formed the 1999 Royalty Trust Option Plan in anticipation of creating a
new royalty trust in 1999. To date, the new trust has not been created and there
are no outstanding grants under the 1999 Royalty Trust Option Plan.
Unit/Option Activity and Balances
The following summarizes unit and option activity and balances from 1997
through 1999:
1994, 1997
Weighted and 1998
Average 1991 Plan Plans
Exercise Incentive Stock
Price Units Options
---------- --------- -----------
1997
------------------------------------------
Beginning of year..................... $ 7.32 50,963 1,486,996
Grants.............................. 12.11 - 1,757,250
Exercises........................... 6.75 (26,213) (897,234)
Forfeitures......................... 8.79 - (18,315)
--------- -----------
End of year........................... 11.11 24,750 2,328,697
========= ===========
Exercisable at end of year............ 10.96 24,750 1,119,044
========= ===========
1998
------------------------------------------
Beginning of year..................... $ 11.11 24,750 2,328,697
Grants.............................. 17.52 - 1,395,750
Exercises........................... 11.64 (6,750) (1,081,711)
Forfeitures......................... 17.19 - (21,750)
--------- -----------
End of year........................... 14.23 18,000 2,620,986
========= ===========
Exercisable at end of year............ 11.03 18,000 1,351,236
========= ===========
1999
------------------------------------------
Beginning of year..................... $ 14.23 18,000 2,620,986
Grants.............................. 10.67 - 409,875
Exercises........................... 6.86 - (10,462)
Forfeitures......................... 11.63 (9,000) (19,575)
--------- -----------
End of year........................... 13.80 9,000 3,000,824
========= ===========
Exercisable at end of year............ 11.09 9,000 1,330,574
========= ===========
53
The following summarizes information about outstanding units and options at
December 31, 1999:
Units/Options Outstanding Units/Options Exercisable
------------------------------- -------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Prices Number Term Price Number Price
--------------- --------- --------- -------- --------- ---------
1991 Plan
$5.32 - $7.58 9,000 2.1 years $ 5.43 9,000 $ 5.43
1994, 1997 and
1998 Plans
$6.61 - $7.89 283,053 6.3 years 7.24 222,303 7.25
$9.67 - $10.92 264,521 6.4 years 9.68 264,521 9.68
$11.15 - $13.40 1,107,875 8.2 years 11.94 743,250 12.21
$15.53 - $18.22 1,345,375 8.4 years 17.59 100,500 15.54
--------- ---------
3,009,824 1,339,574
========= =========
Estimated Fair Value of Grants
Using the Black-Scholes option-pricing model and the following assumptions,
the weighted average fair value of option grants was estimated to be $6.40 in
1999, $6.82 in 1998 and $5.05 in 1997.
1999 1998 1997
-------- -------- --------
Risk-free interest rates......... 5.8% 5.6% 6.4%
Dividend yield................... 3.0% 3.2% 1.6%
Weighted average expected lives.. 5 years 5 years 5 years
Volatility....................... 91% 52% 47%
Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair
Value
The following are pro forma earnings (loss) available to common stock and
earnings (loss) per common share for 1999, 1998 and 1997, as if stock-based
compensation had been recorded at the estimated fair value of stock awards at
the grant date, as prescribed by SFAS 123, Accounting for Stock-Based
Compensation:
(in thousands, except per share data)
1999 1998 1997
-------- --------- --------
Earnings (loss) available to common stock:
As reported............................... $ 44,964 $ (71,498) $ 23,905
Pro forma................................. $ 40,373 $ (75,785) $ 21,646
Earnings (loss) per common share:
Basic As reported...................... $ 0.96 $ (1.65) $ 0.60
Pro forma........................ $ 0.86 $ (1.75) $ 0.54
Diluted As reported...................... $ 0.95 $ (1.65) $ 0.59
Pro forma........................ $ 0.85 $ (1.75) $ 0.54
54
12. Sale of Hugoton Royalty Trust Units
In December 1998, the Company formed the Hugoton Royalty Trust by conveying
80% net profits interests in properties located in the Hugoton area of Kansas
and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of
Wyoming. These net profits interests were conveyed to the trust in exchange for
40,000,000 units of beneficial interest. On April 8, 1999, the Company sold
15,000,000, or 37.5%, of the trust units in an initial public offering at a
price of $9.50 per unit, less underwriters' discount and expenses. Pursuant to
the underwriters' overallotment option, the Company sold an additional 2,004,000
trust units at $9.50 per unit less discount on May 7, 1999. 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 July 1999, an officer exercised options to purchase 73,684 Hugoton
Royalty Trust units from the Company pursuant to the 1998 Royalty Trust Option
Plan in exchange for 48,755 shares of Company common stock. The Company
recognized a gain of $235,000 on this sale of trust units.
13. Spring Holding Company Acquisition
On July 1, 1999, the Company and Lehman Brothers Holdings, Inc. ("Lehman")
acquired predominantly gas-producing properties in the Arkoma Basin through the
purchase of the common stock of Spring Holding Company ("Spring"), a private oil
and gas company located in Tulsa, Oklahoma for $85 million. The Company issued
3,720,000 shares of common stock for its ownership interest in Spring and Lehman
contributed $42.5 million in cash. The Company and Lehman each owned 50% of a
limited liability company that acquired the common stock of Spring. Pursuant to
a put and call agreement, the Company purchased Lehman's interest on September
15, 1999 for $44.3 million, or $1.8 million in excess of the recorded minority
interest, which excess was recorded as producing property cost. Property cost
associated with the Spring acquisition totaled approximately $235 million, a
portion of which was attributed to other than producing properties, including a
gas gathering system, compressors, undeveloped leasehold cost and other tangible
property. Cost of these other assets are depreciated over their useful lives,
primarily using the unit-of-production method based on proved reserves for
properties served by these assets. After purchase accounting adjustments,
including a $14.1 million step-up adjustment for deferred income taxes, the cost
of the properties was $257 million. Although the Company and Lehman had equal
board representation and control of Spring, the Company's management controlled
operations of the properties since July 1, 1999 and had the right to purchase
Lehman's interest pursuant to the call agreement. The Company accordingly has
consolidated its investment in Spring since July 1, 1999 using the purchase
method of accounting, with recognition of Lehman's investment as a minority
interest through September 14, 1999.
14. Ocean Energy Acquisition
On September 15, 1999, the Company and Lehman acquired predominantly gas-
producing properties in the Arkoma Basin from affiliates of Ocean Energy, Inc.
("Ocean Energy Acquisition") for $231 million. The original purchase price of
$235.3 million was reduced by estimated net revenue received between the July 1,
1999 effective date and the closing date. Additional purchase price adjustments
may result from post-closing adjustments. All purchase costs will be allocated
to oil and gas properties.
The Company and Lehman each own 50% of Whitewine Holding Company
("Whitewine"), which was formed to acquire the Arkoma Basin properties. Lehman
contributed $100 million in cash to Whitewine and the Company contributed $100
million in securities, including its common stock (Note 2). The purchase price
was funded with $100 million from the jointly owned company and $131 million
financed through a revolving credit agreement between Whitewine's wholly owned
subsidiary, Summer Acquisition Company, and commercial banks. Although the
Company and Lehman have equal board representation and control of Whitewine, the
Company's management controls operations of the properties and the Company has
the right to purchase Lehman's interest pursuant to the call agreement described
below. Whitewine's financial results are consolidated in the Company's
financial statements, with recognition of Lehman's 50% interest as a minority
interest.
The Company entered a put and call agreement with Lehman whereby the
Company has the right to purchase Lehman's 50% interest in the Ocean Energy
Acquisition from January 1, 2000 through September 15, 2000. If the
55
Company does not exercise its option on or before that date, Lehman has the
right to sell its 50% interest to the Company on September 15, 2000. The option
exercise price is Lehman's cost of $100 million plus an annualized return of
20%. The parties agreed to the put and call agreement in order to provide the
Company a method of purchasing the remainder of the Ocean Energy Acquisition,
and to provide Lehman a method to sell its interest, if either party determined
it to be in its best interest. The Company plans to exercise its option to
purchase Lehman's interest on March 31, 2000 for $111 million.
15. Acquisitions and Dispositions
On April 24, 1998, the Company acquired producing properties in the East
Texas Basin from EEX Corporation ("East Texas Basin Acquisition") for $265
million. After purchase price adjustments primarily resulting from net revenues
from the January 1, 1998 effective date through April 24, 1998, the properties
were purchased for $245 million. In connection with the acquisition, the
Company sold a production payment to EEX Corporation for $30 million. The
production payment is payable from production from certain properties acquired
in the East Texas Basin Acquisition during the 10-year period beginning January
1, 2002. EEX Corporation effectively pays all taxes, royalties and production
expenses related to such production. The Company has the option to repurchase a
portion of this production payment each December, beginning in 1998; this option
was not exercised in December 1998 or 1999. The cost of the East Texas Basin
Acquisition (net of the production payment sold) of $215 million was funded by
bank borrowings which were partially repaid by proceeds from the sale of common
stock.
On September 30, 1998, the Company acquired oil-producing properties in the
Middle Ground Shoal Field of Alaska's Cook Inlet ("Cook Inlet Acquisition") from
various Shell Oil Company affiliates ("Shell"). The acquired interests include
a 100% working interest in two State of Alaska leases, two offshore production
platforms and a 50% interest in certain operated production pipelines and
onshore processing facilities. The Company acquired the properties in exchange
for 1,921,850 shares of the Company's common stock, subject to a $20 per share
price guarantee. The Company also executed a non-interest bearing promissory
note to Shell for $6 million. Payments under this note, which were due when
NYMEX crude oil prices increased to specified levels, were made in August and
September 1999. The total purchase price of the Cook Inlet Acquisition was $45
million.
On March 1, 1999, the Company and Shell entered an amended agreement to
postpone Shell's resale of Company common stock to no later than August 16,
1999. As agreed in this amendment, and in anticipation of repurchasing the
common stock from Shell, the Company paid Shell $15 million and paid $5 million
into escrow. The Company also entered into gas sales and transportation
contracts that provide Shell purchase discounts with an estimated value of $7.5
million. These payments and contracts were recorded as reductions to equity.
Deferred gas contract revenue of $7.5 million was also recorded which is being
amortized to gas revenue as the discounts are taken by Shell. On July 15, 1999,
the Company used the proceeds from a stock offering to repurchase the 1,921,850
shares of the Company's common stock owned by Shell. Proceeds from the sale of
common stock exceeded the remaining amount due Shell under the $20 common stock
price guarantee by approximately $15 million which was refunded to the Company
and used to reduce bank debt.
On November 20, 1998, the Company acquired primarily gas-producing
properties in northwest Oklahoma and the San Juan Basin of New Mexico for $33.4
million from Seagull Energy Corp. After purchase price adjustments primarily
resulting from net revenues from the October 1, 1998 effective date through
November 20, 1998, the properties were purchased for an estimated price of $31
million. Additional purchase price revisions may result from post-closing
adjustments. The Company funded the acquisition with existing lines of credit.
On May 4, 1999, the Company sold nonoperated producing properties in the
San Juan Basin of New Mexico to Vastar Resources, Inc. for $29.9 million. The
sale was effective March 1, 1999 and is subject to typical post-closing
adjustments. The Company sold other nonoperated producing properties in June
1999 for approximately $15 million. Proceeds from the sales were used to reduce
bank debt.
On September 14, 1999, producing properties were sold for approximately
$63.5 million before closing costs in two transactions. Cross Timbers sold
primarily nonoperated properties in Oklahoma, the Permian Basin of West Texas
and New Mexico and the Green River Basin of Wyoming for a total of $41 million,
and Spring sold properties in the Panhandle area of Texas and in Coal County,
Oklahoma for $22.5 million.
56
Acquisitions have been recorded using the purchase method of accounting.
The following presents unaudited pro forma results of operations for the years
ended December 31, 1999 and 1998 as if these acquisitions, the Spring
Acquisition (Note 13), the Ocean Energy Acquisition (Note 14), and the sale of
Hugoton Royalty Trust units (Note 12) and other properties, had been consummated
on January 1, 1999 and immediately prior to January 1, 1998. These pro forma
results are not necessarily indicative of future results.
(in thousands, except per share data)
Pro Forma (Unaudited)
--------------------------------
1999 1998
---------- ----------
Revenues................................... $ 368,313 $ 308,967
========== ==========
Net income (loss).......................... $ 46,823 $ (62,741)
========== ==========
Earnings (loss) available to common stock.. $ 45,195 $ (64,520)
========== ==========
Earnings (loss) per common share:
Basic................................ $ 0.93 $ (1.26)
========== ==========
Diluted.............................. $ 0.91 $ (1.26)
========== ==========
Spring acquired a significant portion of its producing properties in July
1998. Pro forma results for the year ended December 31, 1998, as if this
acquisition closed on January 1, 1998, are estimated to be: revenues of $326.3
million and loss available to common stock of $65.2 million.
See Note 20.
16. Supplemental Guarantor Information
Redwine Holdings, LLC ("Redwine"), a wholly owned subsidiary of the
Company, has signed a supplemental indenture, fully and unconditionally
guaranteeing the Company's subordinated notes (Note 4) including interest.
Redwine is not restricted from making distributions to the Company. Separate
financial statements for Redwine have not been prepared because the Company has
determined that information provided by such financial statements is not
material to investors. In accordance with practices accepted by the Commission,
and in order to provide meaningful financial data relating to Redwine, the
guarantor, the following condensed consolidating financial statements are
presented. The consolidating balance sheet, statement of operations and
statement of cash flows present financial information for:
- Cross Timbers Oil Company as the parent on a stand-alone basis (carrying
any investments in subsidiaries under the equity method),
- Redwine as the guarantor, as consolidated with its wholly owned
subsidiary, Spring Holding Company, on a stand-alone basis,
- Non-guarantor subsidiaries of the Company on a consolidated basis,
- Consolidation and elimination entries necessary to derive the
information for the Company on a consolidated basis, and
- The Company on a consolidated basis.
Redwine was formed in June 1999 by Lehman Brothers Holdings, Inc. to
acquire the common stock of Spring Holding Company (Note 13). Upon Redwine's
acquisition of Spring Holding Company in July 1999, the Company acquired a 50%
interest in Redwine. Redwine's execution of the supplemental indenture related
to the Company's debt securities was a result of the Company's acquisition of
the remaining 50% in September 1999. Therefore, consolidating financial
statements are presented for 1999 only.
57
Supplemental Condensed Consolidating Balance Sheet
(in thousands)
December 31, 1999
---------------------------------------------------------------------
Cross Timbers
Oil Company Guarantor Non-Guarantor
(Parent) Subsidiary Subsidiaries Eliminations Consolidated
------------ ---------- ------------ ------------ ------------
ASSETS
Current Assets:
Cash and cash equivalents.................................... $ 11 $ 1,557 $ 4,166 $ - $ 5,734
Accounts receivable, net..................................... - 759 68,239 - 68,998
Investment in equity securities.............................. 582 - 28,470 - 29,052
Deferred income tax benefit.................................. 1,763 34 2,371 - 4,168
Other current assets......................................... 4,654 239 647 - 5,540
---------- -------- --------- --------- ----------
Total Current Assets........................................ 7,010 2,589 103,893 - 113,492
---------- -------- --------- --------- ----------
Property and Equipment, at cost - successful efforts method:
Producing properties......................................... 1,176,420 229,494 229,969 - 1,635,883
Undeveloped properties....................................... 6,508 3,850 - - 10,358
Gas gathering and other...................................... 17,876 4,140 10,886 - 32,902
Accumulated depreciation, depletion and amortization......... (326,615) (4,823) (8,625) - (340,063)
---------- -------- --------- --------- ----------
Net Property and Equipment.................................. 874,189 232,661 232,230 - 1,339,080
---------- -------- --------- --------- ----------
Other Assets.................................................. 19,683 1,798 3,028 - 24,509
---------- -------- --------- --------- ----------
Intercompany Receivable (Payable)............................. 167,109 (1,238) (165,871) - -
---------- -------- --------- --------- ----------
Investment in Parent.......................................... - - 63,211 (63,211) -
---------- -------- --------- --------- ----------
Investment in Subsidiaries.................................... 48,916 - - (48,916) -
---------- -------- --------- --------- ----------
TOTAL ASSETS.................................................. $1,116,907 $235,810 $ 236,491 $(112,127) $1,477,081
========== ======== ========= ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities..................... $ 1,130 $ 15,225 $ 52,582 $ - $ 68,937
Other current liabilities.................................... 2,542 - 2,739 - 5,281
---------- -------- --------- --------- ----------
Total Current Liabilities................................... 3,672 15,225 55,321 - 74,218
---------- -------- --------- --------- ----------
Long-term Debt................................................ 739,000 123,100 129,000 - 991,100
---------- -------- --------- --------- ----------
Deferred Income Taxes Payable (Receivable).................... 27,573 14,711 (16,309) - 25,975
---------- -------- --------- --------- ----------
Other Long-term Liabilities................................... 5,634 - 2,325 - 7,959
---------- -------- --------- --------- ----------
Minority Interest in Consolidated Subsidiary.................. - - 100,012 - 100,012
---------- -------- --------- --------- ----------
Stockholders' Equity:
Preferred stock.............................................. 28,468 - - - 28,468
Common stock................................................. 628 - - (46) 582
Additional paid-in capital................................... 459,733 85,040 4,460 (152,665) 396,568
Treasury stock............................................... (119,387) - - - (119,387)
Retained earnings (deficit).................................. (28,414) (2,266) (38,318) 40,584 (28,414)
---------- -------- --------- --------- ----------
Total Stockholders' Equity.................................. 341,028 82,774 (33,858) (112,127) 277,817
---------- -------- --------- --------- ----------
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY...................... $1,116,907 $235,810 $ 236,491 $(112,127) $1,477,081
========== ======== ========= ========= ==========
58
Supplemental Consolidating Statement of Income
(in thousands)
Year Ended December 31, 1999
----------------------------------------------------------------------
Cross Timbers
Oil Company Guarantor Non-Guarantor
(Parent) Subsidiary Subsidiaries Eliminations Consolidated
----------- ---------- ------------ ------------ ------------
REVENUES
Oil and condensate.............................. $ 85,839 $ 141 $ 624 $ - $ 86,604
Gas and natural gas liquids..................... 207,364 19,161 12,531 - 239,056
Gas gathering, processing and marketing......... - 569 10,075 - 10,644
Other........................................... 5,283 (80) (212) - 4,991
---------- --------- ---------- --------- ----------
Total Revenues.................................. 298,486 19,791 23,018 - 341,295
---------- --------- ---------- --------- ----------
EXPENSES
Production...................................... 70,637 3,654 1,819 - 76,110
Taxes, transportation and other................. 31,940 675 1,066 - 33,681
Exploration..................................... 887 14 3 - 904
Depreciation, depletion and amortization........ 94,227 11,731 6,406 - 112,364
Gas gathering and processing.................... - 186 8,557 - 8,743
General and administrative...................... 9,490 1,103 3,498 - 14,091
---------- --------- ---------- --------- ----------
Total Expenses.................................. 207,181 17,363 21,349 - 245,893
---------- --------- ---------- --------- ----------
OPERATING INCOME................................ 91,305 2,428 1,669 - 95,402
---------- --------- ---------- --------- ----------
OTHER INCOME (EXPENSE)
Gain on sale of Hugoton Royalty Trust units..... 40,566 - - - 40,566
Gain (loss) on investment in equity securities.. 426 - (1,575) - (1,149)
Interest expense, net........................... (55,679) (6,184) (2,351) - (64,214)
Equity in loss from subsidiaries................ (3,875) - - 3,875 -
---------- --------- ---------- --------- ----------
Total Other Income (Expense).................... (18,562) (6,184) ( 3,926) 3,875 (24,797)
---------- --------- ---------- --------- ----------
INCOME (LOSS) BEFORE INCOME TAX
AND MINORITY INTEREST.......................... 72,743 (3,756) (2,257) 3,875 70,605
Income Tax Expense (Benefit).................... 26,000 (1,375) (660) - 23,965
Minority interest in net loss (income)
of consolidated subsidiaries................... - 115 (12) - 103
---------- --------- ---------- --------- ----------
NET INCOME (LOSS)............................... 46,743 (2,266) (1,609) 3,875 46,743
Preferred stock dividends....................... 1,779 - - - 1,779
---------- --------- ---------- --------- ----------
EARNINGS (LOSS) AVAILABLE
TO COMMON STOCK................................ $ 44,964 $ (2,266) $ (1,609) $ 3,875 $ 44,964
========== ========= ========== ========= ==========
59
Supplemental Condensed Consolidating Statement of Cash Flows
(in thousands)
Year Ended December 31, 1999
-------------------------------------------------------
Cross Timbers
Oil Company Guarantor Non-Guarantor
(Parent) Subsidiary Subsidiaries Total
------------- ---------- ------------- ----------
Cash Provided by Operating Activities..................... $ 97,812 $ 11,859 $ 23,630 $ 133,301
------------ --------- ------------ ---------
Investing Activities
Proceeds from sale of Hugoton Royalty Trust units...... 148,570 - - 148,570
Proceeds from sale of property and equipment........... 87,647 21,769 1,084 110,500
Property acquisitions.................................. (12,503) (261) (257,462) (270,226)
Purchase of Spring Holding Company..................... - (42,540) - (42,540)
Development costs...................................... (85,294) (5,271) (160) (90,725)
Gas plant, gathering and other additions............... (5,300) (1,599) (3,580) (10,479)
Loans to officers...................................... (1,470) - - (1,470)
------------ --------- ------------ ---------
Cash Used by Investing Activities......................... 131,650 (27,902) (260,118) (156,370)
------------ --------- ------------ ---------
Financing Activities
Proceeds from short- and long-term debt................ 103,000 17,400 136,000 256,400
Payments on short- and long-term debt.................. (289,962) (42,300) (7,000) (339,262)
Purchase of minority interest.......................... (42,385) - - (42,385)
Contributions from minority interests.................. - 42,500 100,000 142,500
Common stock offering.................................. 29,668 - - 29,668
Dividends.............................................. (4,950) - - (4,950)
Purchases of treasury stock and other.................. (25,501) - - (25,501)
------------ --------- ------------ ---------
Cash Provided by Financing Activities..................... (230,130) 17,600 229,000 16,470
------------ --------- ------------ ---------
Increase (Decrease) in Cash
and Cash Equivalents..................................... (668) 1,557 (7,488) (6,599)
Cash and Cash Equivalents, January 1...................... 679 - 11,654 12,333
------------ --------- ------------ ---------
Cash and Cash Equivalents, December 31.................... $ 11 $ 1,557 $ 4,166 $ 5,734
============ ========= ============ =========
60
17. Restatement of Financial Statements
Pursuant to completion of a review of the Company's financial statements by
the Securities and Exchange Commission in March 2000, the Company has restated
its consolidated balance sheet as of December 31, 1998, its consolidated
statement of stockholders' equity for the year ended December 31, 1998 and its
interim 1999 income statements. These restatements were made to reflect a change
in accounting for the Cook Inlet Acquisition for technical compliance with
business combination accounting prescribed by Accounting Principles Board
Opinion No. 16. As disclosed in Note 15, the Company issued common stock to
Shell subject to a $20 per share price guarantee, and by July 1999, the Company
had repurchased the common shares and made other payments to Shell to satisfy
its obligation under the guarantee. The Company also issued a $6 million non-
interest bearing note payable to Shell, payments under which were contingent
upon oil prices reaching specified levels. This note was fully paid by September
1999.
The Company originally recorded the common stock issued to Shell as equity
only to the extent of its current value at the balance sheet date. The
difference between the current value of the common stock and the $20 price
guarantee was conservatively recorded as an accrued current liability, which was
$24 million at December 31, 1998. The note payable was recorded at its face
value of $6 million. As restated, the common shares issued to Shell are recorded
in additional paid-in capital at $20 per share until cash and gas contract
settlements were made with Shell. This change in accounting resulted in an
increase to stockholders' equity of $24 million at December 31, 1998 and no
change to equity after the guarantee was settled in July 1999. Also, the note
payable is restated at its fair value, based on oil prices at the balance sheet
date, with the difference recorded as an adjustment to property. The interim
1999 income statements are restated to include changes in the note value in
income and to expense interest paid to Shell upon settlement which originally
had been capitalized. Because these adjustments were previously recorded in
fourth quarter 1999 results, there is no change to 1999 annual results of
operations that the Company announced on February 3, 2000.
The following are the effects of the restatement (in thousands):
As Previously
Reported As Restated
-------------- -----------
Balance Sheet at December 31,1998
Producing property........................... $1,335,844 $1,335,255
Accounts payable and accrued liabilities..... 93,583 69,560
Long-term debt............................... 921,000 920,411
Additional paid-in capital................... 338,503 362,526
1999 Interim Income Statements (Unaudited)
------------------------------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
-------------------- -------------------- ---------------------- ----------------------
As As As As
Previously As Previously As Previously As Previously As
Reported Restated Reported Restated Reported Restated Reported Restated
--------- --------- -------- --------- -------- ---------- ---------- --------
Revenues............................ $ 69,507 $ 69,415 $ 65,504 $ 65,550 $ 95,869 $ 95,326 $110,415 $111,004
Operating income.................... 12,330 12,238 10,711 10,757 33,665 33,122 38,696 39,285
Interest expense.................... (15,390) (15,574) (12,817) (13,209) (16,384) (16,440) (19,623) (18,991)
Income before income tax............ (2,254) (2,530) 43,967 43,621 19,907 19,308 8,985 10,206
Income tax expense (benefit)........ (792) (884) 14,953 14,835 6,642 6,438 3,162 3,576
Earnings (loss) available
to common stock................... (1,907) (2,091) 28,569 28,341 13,466 13,071 4,836 5,643
Earnings (loss) per common share:
Basic............................. $ (0.04) $ (0.05) $ 0.64 $ 0.63 $ 0.28 $ 0.27 $ 0.10 $ 0.12
Diluted............................ (0.04) (0.05) 0.61 0.61 0.27 0.26 0.10 0.12
61
18. Quarterly Financial Data (Unaudited)
The following are summarized quarterly financial data for the years ended
December 31, 1999 and 1998 (in thousands, except per share data):
Quarter
---------------------------------------
1st 2nd 3rd 4th
-------- -------- --------- --------
1999 (Restated - Note 17)
- ---------------------------------------
Revenues.......................... $ 69,415 $ 65,550 $ 95,326 $111,004
Gross profit (a).................. $ 15,154 $ 13,601 $ 36,420 $ 44,318
Earnings (loss) available to
common stock.................... $ (2,091) $ 28,341 $ 13,071 $ 5,643
Earnings (loss) per common share
Basic........................... $ (0.05) $ 0.63 $ 0.27 $ 0.12
Diluted......................... $ (0.05) $ 0.61 $ 0.26 $ 0.12
Average shares outstanding........ 44,727 44,733 48,914 48,831
1998
- ---------------------------------------
Revenues.......................... $ 49,968 $ 61,652 $ 67,044 $ 70,822
Gross profit (a).................. $ 13,007 $ 14,510 $ 16,568 $ 9,656
Earnings (loss) available to
common stock.................... $ (184) $ 759 $(31,004) $(41,069)
Earnings (loss) per common share
Basic........................... $ 0.00 $ 0.02 $ (0.69) $ (0.90)
Diluted......................... $ 0.00 $ 0.02 $ (0.69) $ (0.90)
Average shares outstanding........ 39,046 43,940 44,765 45,440
(a) Operating income before general and administrative expense.
19. 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):
1999 1998 1997
-------- -------- --------
Acquisitions:
Producing properties................ $505,912 $339,889 $251,663
Undeveloped properties.............. 4,182 514 3,964
Development (a)........................ 89,306 69,367 86,555
Exploration:
Geological and geophysical studies.. 872 7,943 1,672
Dry hole expense.................... - - 316
Rental expense and other............ 32 91 100
-------- -------- --------
Total.................................. $600,304 $417,804 $344,270
======== ======== ========
(a) Includes capitalized interest of $1,353,000 in 1999, $1,070,000 in
1998 and $800,000 in 1997.
Proved Reserves
Independent petroleum engineers have estimated the Company's proved oil and
gas reserves, all of which are located in the United States. Proved reserves
are the estimated quantities that geologic and engineering data demonstrate
62
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.
Oil Gas Natural Gas
(Bbls) (Mcf) Liquids (Bbls)(a)
----------- --------- -----------------
Proved Reserves (in thousands)
December 31, 1996........................ 42,440 540,538
Revisions.............................. (989) (14,182) -
Extensions, additions and discoveries.. 9,263 112,906 -
Production............................. (3,980) (49,587) (80)
Purchases in place..................... 3,195 248,040 13,890
Sales in place......................... (2,075) (21,940) -
------ --------- ------
December 31, 1997........................ 47,854 815,775 13,810
Revisions.............................. (5,893) (5,429) 2,631
Extensions, additions and discoveries.. 821 172,059 1,875
Production............................. (4,598) (83,847) (1,222)
Purchases in place..................... 16,331 311,260 80
Sales in place......................... (5) (594) -
------ --------- ------
December 31, 1998........................ 54,510 1,209,224 17,174
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
====== ========= ======
Proved Developed Reserves
December 31, 1996........................ 31,883 466,412
====== =========
December 31, 1997........................ 33,835 677,710 11,494
====== ========= ======
December 31, 1998........................ 42,876 968,495 14,000
====== ========= ======
December 31, 1999........................ 48,010 1,225,014 13,781
====== ========= ======
(a) Proved reserves attributable to natural gas liquids were not considered
significant prior to the Amoco Acquisition in December 1997 (Note 15).
Natural gas liquids proved reserves as disclosed include only San Juan
Basin properties purchased in this acquisition.
63
Standardized Measure of Discounted Future December 31
--------------------------------------
Net Cash Flows Relating to Proved Reserves 1999 1998 1997
----------- ----------- ----------
(in thousands)
Future cash inflows...................... $ 5,113,094 $ 3,041,776 $2,604,453
Future costs:............................
Production............................ (1,549,401) (1,135,789) (979,317)
Development........................... (294,250) (228,561) (140,594)
----------- ----------- ----------
Future net cash flows before income tax.. 3,269,443 1,677,426 1,484,542
Future income tax........................ (718,892) (231,249) (291,375)
----------- ----------- ----------
Future net cash flows.................... 2,550,551 1,446,177 1,193,167
10% annual discount...................... (1,153,611) (637,774) (551,058)
----------- ----------- ----------
Standardized measure (a)................. $ 1,396,940 $ 808,403 $ 642,109
=========== =========== ==========
(a) Before income tax, the year-end standardized measure (or discounted
present value of future net cash flows) was $1,765,936,000 in 1999,
$908,606,000 in 1998 and $782,322,000 in 1997.
Changes in Standardized Measure of
Discounted Future Net Cash Flows 1999 1998 1997
---------- --------- ---------
(in thousands)
Standardized measure, January 1........ $ 808,403 $ 642,109 $ 706,481
---------- --------- ---------
Revisions:.............................
Prices and costs..................... 608,123 (184,568) (388,559)
Quantity estimates................... 62,033 65,600 55,497
Accretion of discount................ 79,647 71,942 86,845
Future development costs............. (113,110) (104,636) (120,073)
Income tax........................... (268,794) 40,011 99,455
Production rates and other........... (137) (296) (1,614)
---------- --------- ---------
Net revisions.................... 367,762 (111,947) (268,449)
Extensions, additions and discoveries.. 125,209 96,829 92,582
Production............................. (215,869) (146,498) (125,343)
Development costs...................... 70,275 56,904 73,062
Purchases in place (a)................. 414,759 271,806 207,387
Sales in place (b)..................... (173,599) (800) (43,611)
---------- --------- ---------
Net change....................... 588,537 166,294 (64,372)
---------- --------- ---------
Standardized measure, December 31...... $1,396,940 $ 808,403 $ 642,109
========== ========= =========
(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.
Year-end oil prices used in the estimation of proved reserves and
calculation of the standardized measure were $24.17 for 1999, $9.50 for 1998 and
$15.50 for 1997. Year-end average gas prices were $2.20 for 1999, $2.01 for
1998 and $2.20 for 1997. Year-end average natural gas liquids prices were
$13.83 for 1999, $3.99 for 1998 and $11.07 for 1997. Proved oil and gas
reserves at December 31, 1999 include:
. 1,700 Bbls of oil and 111,814,000 Mcf of gas and discounted
present value before income tax of $91,127,000 related to a 50%
minority interest in the Ocean Energy Acquisition at December 31,
1999. The Company plans to purchase the 50% minority interest on
March 31, 2000.
. 1,964,000 Bbls of oil and 232,429,000 Mcf of gas and discounted
present value before income tax of $188,001,000 related to the
Company's ownership of approximately 57% of Hugoton Royalty Trust
units at December 31, 1999.
64
. 783,000 Bbls of oil and 8,162,000 Mcf of gas and discounted present
value before income tax of $13,742,000 related to the Company's
ownership of approximately 22% of Cross Timbers Royalty Trust units at
December 31, 1999.
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.
See Note 20.
20. Subsequent Events
On March 30, 2000, the Company sold primarily gas producing properties in
Crockett County, Texas for $43 million. The Company has agreed to sell oil and
gas producing properties in Lea County, New Mexico for $25.3 million on March
31, 2000. Sales prices are subject to post-closing adjustments. The Company
plans to use the proceeds from these sales, sales of equity securities (Note 2)
and a $25 million short-term bank loan to purchase Lehman's interest in
Whitewine from Lehman on March 31, 2000.
65
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Cross Timbers Oil Company
We have audited the accompanying consolidated balance sheets of Cross Timbers
Oil Company and its subsidiaries as of December 31, 1999 and 1998 (as restated,
as described in Note 17), and the related consolidated statements of operations,
comprehensive income, cash flows and stockholders' equity for each of the three
years in the period ended December 31, 1999. 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, 1999 and 1998, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1999, in conformity
with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 17, 2000
66
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
CROSS TIMBERS OIL COMPANY (PARENT COMPANY)
BALANCE SHEETS
(in thousands) December 31
------------------------
1999 1998
----------- -----------
ASSETS
Current Assets:
Cash and cash equivalents.................................... $ 11 $ 679
Investment in equity securities.............................. 582 14,434
Deferred income tax benefit.................................. 1,763 7,589
Other current assets......................................... 4,654 5,208
---------- ----------
Total Current Assets....................................... 7,010 27,910
---------- ----------
Property and Equipment, at cost - successful efforts method:
Producing properties......................................... 1,176,420 1,335,255
Undeveloped properties....................................... 6,508 6,845
Gas gathering and other...................................... 17,876 18,333
Accumulated depreciation, depletion and amortization......... (326,615) (317,093)
---------- ----------
Net Property and Equipment................................. 874,189 1,043,340
---------- ----------
Other Assets.................................................. 19,683 17,656
---------- ----------
Intercompany Receivable (Payable)............................. 167,109 80,161
---------- ----------
Investment in Subsidiaries.................................... 48,916 (32,340)
---------- ----------
TOTAL ASSETS.................................................. $1,116,907 $1,136,727
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities..................... $ 1,130 $ 7,120
Other current liabilities.................................... 2,542 75
---------- ----------
Total Current Liabilities.................................. 3,672 7,195
---------- ----------
Long-term Debt................................................ 739,000 920,411
---------- ----------
Deferred Income Taxes Payable (Receivable).................... 27,573 7,647
---------- ----------
Other Long-term Liabilities................................... 5,634 -
---------- ----------
Stockholders' Equity:
Preferred stock.............................................. 28,468 28,468
Common stock................................................. 628 541
Additional paid-in capital................................... 459,733 362,526
Treasury stock............................................... (119,387) (118,555)
Retained earnings (deficit).................................. (28,414) (71,506)
---------- ----------
Total Stockholders' Equity................................. 341,028 201,474
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................... $1,116,907 $1,136,727
========== ==========
The Notes to Consolidated Financial Statements of Cross Timbers Oil Company
are an integral part of these Statements.
See accompanying Note to Condensed Financial Information of the Registrant.
67
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
CROSS TIMBERS OIL COMPANY (PARENT COMPANY)
STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Year Ended December 31
---------------------------------
1999 1998 1997
----------- ---------- ---------
REVENUES
Oil and condensate.............................. $ 85,839 $ 55,610 $ 73,954
Gas and natural gas liquids..................... 207,364 182,587 110,104
Other........................................... 5,283 3 1,410
-------- --------- --------
Total Revenues.................................. 298,486 238,200 185,468
-------- --------- --------
EXPENSES........................................
Production...................................... 70,637 63,148 43,580
Taxes, transportation and other................. 31,940 29,105 16,405
Exploration..................................... 887 8,034 2,088
Depreciation, depletion and amortization........ 94,227 83,040 47,201
Impairment...................................... - 2,040 -
General and administrative...................... 9,490 10,295 12,716
Trust development costs......................... - 1,498 665
-------- --------- --------
Total Expenses.................................. 207,181 197,160 122,655
-------- --------- --------
OPERATING INCOME................................ 91,305 41,040 62,813
-------- --------- --------
OTHER INCOME (EXPENSE)
Gain on sale of Hugoton Royalty Trust units..... 40,566 - -
Gain (loss) on investment in equity securities.. 426 (36,802) 1,735
Interest expense, net........................... (55,679) (53,273) (26,554)
Equity in income (loss) from subsidiaries....... (3,875) (37,423) 608
-------- --------- --------
Total Other Income (Expense).................... (18,562) (127,498) (24,211)
-------- --------- --------
INCOME (LOSS) BEFORE INCOME TAX................. 72,743 (86,458) 38,602
Income Tax Expense (Benefit).................... 26,000 (16,739) 12,918
-------- --------- --------
NET INCOME (LOSS)............................... 46,743 (69,719) 25,684
Preferred stock dividends....................... 1,779 1,779 1,779
-------- --------- --------
EARNINGS (LOSS) AVAILABLE TO COMMON STOCK....... $ 44,964 $ (71,498) $ 23,905
======== ========= ========
The Notes to Consolidated Financial Statements of Cross Timbers Oil Company
are an integral part of these Statements.
See accompanying Note to Condensed Financial Information of the Registrant.
68
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
CROSS TIMBERS OIL COMPANY (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31
----------------------------------
1999 1998 1997
---------- ---------- ----------
Cash Provided (Used) by Operating Activities........ $ 97,812 $ (63,391) $ 93,808
--------- --------- ---------
Investing Activities
Proceeds from sale of Hugoton Royalty Trust units.. 148,570 - -
Proceeds from sale of equity securities............ - - 24,626
Investment in equity securities.................... - - (6,479)
Proceeds from sale of property and equipment....... 87,647 2,494 16,246
Property acquisitions.............................. (12,503) (296,390) (238,294)
Development costs.................................. (85,294) (69,356) (88,382)
Gas plant, gathering and other additions........... (5,300) (5,851) (14,799)
Loans to officers.................................. (1,470) (5,795) -
--------- --------- ---------
Cash Used by Investing Activities................... 131,650 (374,898) (307,082)
--------- --------- ---------
Financing Activities
Proceeds from short- and long-term debt............ 103,000 877,900 688,400
Payments on short- and long-term debt.............. (289,962) (496,938) (437,430)
Purchase of minority interest...................... (42,385) - -
Common stock offering.............................. 29,668 133,113 -
Dividends.......................................... (4,950) (8,460) (7,571)
Purchases of treasury stock and other.............. (25,501) (66,658) (30,204)
--------- --------- ---------
Cash Provided by Financing Activities............... (230,130) 438,957 213,195
--------- --------- ---------
Increase (Decrease) in Cash and Cash Equivalents.... (668) 668 (79)
Cash and Cash Equivalents, January 1................ 679 11 90
--------- --------- ---------
Cash and Cash Equivalents, December 31.............. $ 11 $ 679 $ 11
========= ========= =========
The Notes to Consolidated Financial Statements of Cross Timbers Oil Company
are an integral part of these Statements.
See accompanying Note to Condensed Financial Information of the Registrant.
69
SCHEDULE I
CROSS TIMBERS OIL COMPANY
NOTE TO CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
1. Basis of Presentation
Pursuant to the rules and regulations of the Securities and Exchange
Commission, these Condensed Financial Statements of Cross Timbers Oil Company,
the Registrant, do not include all of the information and notes normally
included with financial statements prepared in accordance with generally
accepted accounting principles. These Condensed Financial Statements should
therefore be read in conjunction with the Consolidated Financial Statements and
Notes thereto included in Part IV of this Form 10-K.
Litigation contingencies disclosed in Note 6 of the Consolidated Financial
Statements are contingencies of the Registrant, and debt of the Registrant is
separately disclosed in Note 4 of the Consolidated Financial Statements. The
Registrant has not received cash dividends from its subsidiaries during the
three-year period ended December 31, 1999.
70
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Cross Timbers Oil Company
Our audit was made for the purpose of forming an opinion on the basic financial
statements taken as a whole. The information contained in Schedule I is not a
required part of the basic financial statements but is supplementary information
required by the Securities and Exchange Commission. The information has been
subjected to the auditing procedures applied in the audit of the basic financial
statements and, in our opinion, is fairly stated in all material respects in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Forth Worth, Texas
March 17, 2000
71
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 30th day of March
2000.
CROSS TIMBERS OIL COMPANY
By /s/ 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 30th day of March 2000.
PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS) DIRECTORS
/s/ Bob R. Simpson /s/ J. Luther King, Jr.
- -------------------------------------- ----------------------------------
Bob R. Simpson, Chairman of the Board J. Luther King, Jr.
and Chief Executive Officer
/s/ Steffen E. Palko /s/ Jack P. Randall
- -------------------------------------- ----------------------------------
Steffen E. Palko, Vice Chairman of Jack P. Randall
the Board and President
/s/ Scott G. Sherman
----------------------------------
Scott G. Sherman
PRINCIPAL FINANCIAL OFFICER PRINCIPAL ACCOUNTING OFFICER
/s/ Louis G. Baldwin /s/ Bennie G. Kniffen
- ------------------------------------------ ------------------------------------
Louis G. Baldwin, Executive Vice President Bennie G. Kniffen,
and Chief Financial Officer Senior Vice President and Controller
72
INDEX TO EXHIBITS
Exhibit
No. Description Page
-------- ------------------------------------------------------------ ------
3.1 Certificate of Incorporation of Cross Timbers Oil Company, as
amended through and restated on May 18, 1994 (incorporated by
reference to Exhibit 4.1 to Registration Statement on Form S-8,
File No. 33-81766)
3.2 Bylaws of Cross Timbers Oil Company (incorporated by reference
to Exhibit 3.4 to Registration Statement on Form S-1, File No.
33-59820)
4.1 Form of Certificate of Designations of Series A Convertible
Preferred Stock, par value $.01 per share (incorporated by
reference to Exhibit 4 to Form 8-A/A, Amendment No. 1, dated
September 3, 1996)
4.2 Indenture dated as of April 1, 1997, between Cross Timbers Oil
Company and The Bank of New York, as Trustee for the 9 1/4%
Senior Subordinated Notes due 2007 (incorporated by reference to
Exhibit 4.1 to Registration Statement of Form S-4, File No. 333-
26603)
4.3 Indenture dated as of October 28, 1997, between Cross Timbers
Oil Company and the Bank of New York, as Trustee for the 8 3/4%
Senior Subordinated Notes due 2009 (incorporated by reference to
Exhibit 4.1 to Registration Statement on Form S-4, File No. 333-
39097)
4.4 Preferred Stock Purchase Rights Agreement between Cross Timbers
Oil Company and ChaseMellon Shareholder Services, LLC
(incorporated by reference to Exhibit 4.1 to Form 8-A dated
September 8, 1998)
10.1* Employment Agreement between the Company and Bob R. Simpson,
dated February 21, 1995 (incorporated by reference to Exhibit
10.6 to Form 10-K for the year ended December 31, 1994)
10.2* Employment Agreement between the Company and Steffen E. Palko,
dated February 21, 1995 (incorporated by reference to Exhibit
10.7 to Form 10-K for the year ended December 31, 1994)
10.3* 1991 Stock Incentive Plan (incorporated by reference to Exhibit
10.7 to Registration Statement on Form S-1, File No. 33-59820)
10.4* Form of grant under 1991 Stock Incentive Plan (incorporated by
reference to Exhibit 10.8 to Registration Statement on Form S-1,
File No. 33-59820)
10.5* Amended and Restated 1994 Stock Incentive Plan
10.6* Form of grant under 1994 Stock Incentive Plan (incorporated by
reference to Exhibit 4.5 to Registration Statement on Form S-8,
File No. 33-81766)
10.7* 1997 Stock Incentive Plan, as amended February 15, 2000
10.8* Form of grant under 1997 Stock Incentive Plan, as amended
February 25, 1998 (incorporated by reference to Exhibit 10.9 to
Form 10-K for the year ended December 31, 1997)
73
Exhibit
No. Description Page
-------- ------------------------------------------------------------ ------
10.9* 1998 Stock Incentive Plan, as amended February 15, 2000
10.10* Form of grant under 1998 Stock Incentive Plan (incorporated by
reference to Exhibit 4.5 to Registration Statement on Form S-8,
File No. 333-69977)
10.11* 1998 Royalty Trust Option Plan (incorporated by reference to
Exhibit B to the 1998 Proxy Statement filed on April 24, 1998)
10.12* Form of grant under 1998 Royalty Trust Option Plan
10.13* Management Group Employee Severance Protection Plan, as amended
February 15, 2000
10.14* Employee Severance Protection Plan, as amended February 15, 2000
10.15 Registration Rights Agreement among Cross Timbers Oil Company
and partners of Cross Timbers Oil Company, L.P. (incorporated by
reference to Exhibit 10.9 to Registration Statement on Form S-1,
File No. 33-59820)
10.16 Warrant Agreement dated December 1, 1997 by and between Cross
Timbers Oil Company and Amoco Corporation (incorporated by
reference to Exhibit 10.11 to Form 10-K for the year ended
December 31, 1997)
10.17 Amended and Restated revolving credit agreement, dated November
16, 1998, between the Company and certain commercial banks named
therein (incorporated by reference to Exhibit 10.4 to
Registration Statement on Form S-1, File No. 333-68441)
10.18 First Amendment, dated May 17, 1999, to Amended and Restated
revolving credit agreement dated November 16, 1998 between the
Company and certain commercial banks names therein (incorporated
by reference to Exhibit 10.1 to the Company's Quarterly Report
on Form 10-Q for the Quarter ended June 30, 1999)
10.19 Second Amendment, dated June 9, 1999, to Amended and Restated
revolving credit agreement dated November 16, 1998 between the
Company and certain commercial banks names therein (incorporated
by reference to Exhibit 10.2 to the Company's Quarterly Report
on Form 10-Q for the Quarter ended June 30, 1999)
10.20 Third Amendment, dated June 17, 1999, to Amended and Restated
revolving credit agreement dated November 16, 1998 between the
Company and certain commercial banks names therein (incorporated
by reference to Exhibit 10.3 to the Company's Quarterly Report
on Form 10-Q for the Quarter ended June 30, 1999)
10.21 Fourth Amendment, dated August 15, 1999, to Amended and Restated
revolving credit agreement dated November 16, 1998 between the
Company and certain commercial banks names therein (incorporated
by reference to Exhibit 10.1 to the Company's Quarterly Report
on Form 10-Q for the Quarter ended September 30, 1999)
10.22 Revolving credit agreement, dated September 15, 1999, between
Summer Acquisition Company and certain commercial banks named
therein (incorporated by reference to Exhibit 99.1 to the
Company's Current Report on Form 8-K/A filed on November 29,
1999)
74
Exhibit
No. Description Page
-------- ------------------------------------------------------------ ------
10.23 Stockholders Agreement, dated September 15, 1999, among
Whitewine Holding Company, LBI Group Inc. and Cross Timbers
Trading Company (incorporated by reference to Exhibit 99.2 to
the Company's Current Report on Form 8-K/A filed on November 29,
1999)
10.24 Put and Call Agreement, dated September 15, 1999, by and between
Cross Timbers Oil Company and LBI Group Inc. (incorporated by
reference to Exhibit 99.3 to the Company's Current Report on
Form 8-K/A filed on November 29, 1999)
10.25 Registration Rights Agreement, dated September 15, 1999, by and
between Cross Timbers Oil Company and Whitewine Holding Company
(incorporated by reference to Exhibit 99.4 to the Company's
Current Report on Form 8-K/A filed on November 29, 1999)
12.1 Computation of Ratio of Earnings to Fixed Charges (incorporated
by reference to Exhibit 12.1 to Form 10-K for the year ended
December 31, 1999)
21.1 Subsidiaries of Cross Timbers Oil Company (incorporated by
reference to Exhibit 21.1 to Form 10-K for the year ended
December 31, 1999)
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Miller and Lents, Ltd.
* Management contract or compensatory plan
- --------------------------------
Copies of the above exhibits not contained herein are available, at the cost
of reproduction, to any security holder upon written request to the Secretary,
Cross Timbers Oil Company, 810 Houston St., Suite 2000, Fort Worth, Texas
76102.
75