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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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, 1997
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 NO. 001-11899
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THE HOUSTON EXPLORATION COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 22-2674487
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
1100 LOUISIANA, SUITE 2000
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(713) 830-6800
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH
TITLE OF EACH CLASS EXCHANGE ON WHICH REGISTERED
------------------- ----------------------------
Common Stock, $.01 par value New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulations S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $141,908,000 as of February 5, 1998, based on
the closing sales price of the registrant's common stock on the New York Stock
Exchange on such date of $18.00 per share. For purposes of the preceding
sentence only, all directors, executive officers and beneficial owners of ten
percent or more of the common stock are assumed to be affiliates. As of
February 5, 1998, 23,360,903 shares of common stock were outstanding.
Certain sections of the registrant's definitive proxy statement relating to
the registrant's 1998 annual meeting of stockholders, which proxy statement
will be filed under the Securities Exchange Act of 1934 within 120 days of the
end of the registrant's fiscal year ended December 31, 1997, are incorporated
by reference into Part III of this Form 10-K.
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This Annual Report on Form 10-K contains certain "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1993, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
The words "anticipate," "believe," "expect," "estimate," "project" and similar
expressions are intended to identify forward-looking statements. Without
limiting the foregoing, all statements under the caption "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations"
relating to the Company's anticipated capital expenditures, future cash flows
and borrowings, pursuit of potential future acquisition opportunities and
sources of funding for exploration and development are forward-looking
statements. Such statements are subject to certain risks and uncertainties,
such as the volatility of natural gas and oil prices, uncertainty of reserve
information and future net revenue estimates, reserve replacement risks,
drilling risks, operating risks of natural gas and oil operations, acquisition
risks, substantial capital requirements, government regulation, environmental
matters and competition. Should one or more of these risks or uncertainties
materialize, or should underlying assumptions prove incorrect, actual results
may vary materially from those anticipated, believed, expected, estimated or
projected. For additional discussion of such risks, uncertainties and
assumptions, see "Items 1 and 2. Business and Properties" and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" contained in this Annual Report on Form 10-K.
Unless otherwise indicated, references to "Houston Exploration" or the
"Company" refer to The Houston Exploration Company and its subsidiaries on a
combined basis. Certain terms used herein relating to the oil and gas industry
are defined in "Glossary of Oil and Gas Terms" included on pages G-1 through
G-3 of this Annual Report on Form 10-K.
PART I.
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
OVERVIEW
The Houston Exploration Company ("Houston Exploration" or the
"Company") is an independent natural gas and oil company engaged in the
exploration, development, exploitation and acquisition of domestic natural gas
and oil properties. The Company's offshore properties are located primarily in
the shallow waters (up to 600 feet) of the Gulf of Mexico, and its onshore
properties are located in South Texas, the Arkoma Basin, East Texas and West
Virginia. The Company has utilized its geological and geophysical expertise to
grow its reserve base through a combination of high potential exploratory
drilling in the Gulf of Mexico and lower risk, high impact exploitation and
development drilling onshore. The Company believes that the lower risk
projects and more stable production associated with its onshore properties
complement its high potential exploratory prospects in the Gulf of Mexico by
balancing risk and reducing volatility.
The Company has achieved significant growth in net proved reserves,
production and revenues over the past five years. The Company has increased
net proved reserves at a compound annual rate of 30% from 92 Bcfe at December
31, 1992 to 337 Bcfe at December 31, 1997. During this period, annual
production increased at a compound annual rate of 30% from 14 Bcfe in 1992 to
51 Bcfe in 1997. Average daily production during the month of December 1997
was 179 MMcfe per day. The Company's oil and gas revenues have increased from
$22 million in 1992 to $116 million in 1997. At December 31, 1997, Houston
Exploration reported net proved reserves of 337 Bcfe with a discounted present
value of cash flows before income taxes ("PV-10%") of $377 million.
The Company believes that its primary strengths are its high quality
reserves, its substantial inventory of high potential exploration, exploitation
and development opportunities, its expertise in generating new prospects, its
geographic focus and its low-cost operating structure. Approximately 98% of
the Company's net proved reserves at December 31, 1997 were natural gas and
approximately 78% were classified as proved developed. The Company operates
over 90% of its production.
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The geographic focus of the Company's operations in the Gulf of Mexico
and core onshore areas enable it to manage a large asset base with a relatively
small number of employees and to add and operate production at relatively low
incremental costs. The Company achieved lease operating expenses (excluding
severance taxes) of $0.28 per Mcfe of production and net general and
administrative expenses of $0.11 per Mcfe of production for the year ended
December 31, 1997. The Company believes that these expense levels are among
the lowest within its peer group.
The Company was incorporated in Delaware in December 1985 to conduct
certain of the natural gas and oil exploration and development activities of
The Brooklyn Union Gas Company ("Brooklyn Union"). Effective February 29,
1996, Brooklyn Union implemented a reorganization of its exploration and
production assets by transferring to Houston Exploration certain onshore
producing properties and developed and undeveloped acreage. On July 2, 1996,
the Company acquired certain natural gas and oil properties and associated
pipelines located in Zapata County, Texas from TransTexas Gas Corporation and
TransTexas Transmission Corporation (together, "TransTexas") for a net purchase
price of approximately $56 million. In September 1996, the Company completed
an initial public offering (the "IPO") of 7,130,000 shares of Common Stock.
Concurrently with the completion of its IPO, the Company completed the
acquisition of substantially all of the natural gas and oil properties and
related assets of Smith Offshore Exploration Company ("Soxco") for a net
purchase price consisting of approximately $20.3 million in cash and 762,387
shares of Common Stock with an aggregate value (determined by reference to the
IPO price) of $11.8 million. In addition, the Company has agreed to pay to
Soxco effective January 31, 1998 a deferred purchase price, payable in shares
of the Company's Common Stock, of not more than $17.6 million and not less than
$8.8 million as determined by Soxco's probable reserves as of December 31, 1995
that are produced or classified as proved prior to December 31, 1997. As of
December 31, 1997, THEC Holdings Corp., a wholly owned subsidiary of Brooklyn
Union, owned approximately 65% of the outstanding shares of Common Stock.
Brooklyn Union, which in September 1997 became a wholly owned subsidiary of
KeySpan Energy Corporation ("KeySpan"), distributes natural gas in an area of
New York City with a population of four million.
The Company's principal executive offices are located at 1100
Louisiana, Suite 2000, Houston, Texas 77002 and its telephone number is (713)
830-6800.
BUSINESS STRATEGY
The Company's strategy is to continue to increase its reserves,
production and cash flow by pursuing internally generated exploration
prospects, primarily in the Gulf of Mexico, by conducting development and
exploitation drilling on its onshore and offshore properties and by making
selective opportunistic acquisitions. Over the past five years, the Company
has added 400 Bcfe of net proved reserves through exploration, acquisitions,
and exploitation and development. During this period, the Company has produced
a total of 151 Bcfe, and total net proved reserves added due to extensions,
discoveries and revisions were approximately 168% of cumulative production.
Total net proved reserves added during this period including acquisitions were
approximately 265% of cumulative production. During 1997, the Company
increased production by more than 60%, from 32 Bcfe in 1996 to 51 Bcfe in 1997.
The Company focuses on the following elements in implementing this strategy:
High Potential Exploratory and Development Drilling in the Gulf of Mexico
The Company plans to drill approximately 15 exploratory wells in the
Gulf of Mexico in 1998, the successful completion of any one of which could
substantially increase the Company's reserves. Over the past five years, the
Company has drilled 20 successful exploratory wells and 19 successful
development wells in the Gulf of Mexico, representing a historical success rate
of 74%. The Company believes it has assembled a four year inventory of
exploration and development drilling opportunities in the Gulf of Mexico,
principally in shallow waters. The Company holds interests in 79 lease blocks,
representing 394,093 gross (292,837 net) acres, in federal and state waters in
the Gulf of Mexico, of which 26 have current operations. The Company has a
100% working interest in 38 of these lease blocks and a 50% or greater working
interest in 22 other lease blocks. The Company anticipates that approximately
$68 million of its $100 million 1998 capital expenditure budget (excluding
acquisitions) will be spent on offshore projects. In addition, the Company
intends to continue its participation in federal lease sales and to actively
pursue attractive farm-in opportunities as they become available. The
Company's management believes that the Gulf of Mexico area remains
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attractive for future exploration and development activities due to the
availability of geologic data, remaining reserve potential and the
infrastructure of gathering systems, pipelines, platforms and providers of
drilling services and equipment. Based on 1997 annual production, the Company's
offshore reserves have a reserve to production ratio of 5.4 years. During
December 1997, average net production from the Company's Gulf of Mexico
properties was approximately 62 MMcfe per day.
Lower Risk, High Impact Exploitation and Development Drilling Onshore
The Company owns significant onshore natural gas and oil properties in
South Texas, the Arkoma Basin of Oklahoma and Arkansas, East Texas and West
Virginia, accounting for approximately 65% of its net proved reserves at
December 31, 1997. Complementing the Company's offshore properties, the
Company's onshore properties are characterized by relatively longer reserve
lives and more predictable production. Over the past five years, the Company
has drilled or participated in the drilling of 63 successful development wells
and six successful exploratory wells onshore representing a historical drilling
success rate of 76%. One example of the successful implementation of the
Company's onshore strategy is in the Charco Field in South Texas, where the
Company has increased net production from an average of 38 MMcfe per day in
July 1996, immediately following its acquisition of such properties, to an
average of 92 MMcfe per day in December 1997. During 1997, the Company
produced 20 Bcfe, net to the Company's interest, from the Charco Field and
added 40 Bcfe in net proved reserves. The Company has identified an extensive
inventory of more than 100 potential onshore drilling locations, of which
approximately 70 are located in the Charco Field. The Company anticipates that
approximately $32 million of its $100 million 1998 capital expenditure budget
(excluding acquisitions) will be spent on onshore projects, including the
drilling of approximately 25 wells. Based on 1997 annual production, the
Company's onshore reserves have a reserve to production ratio of 7.4 years.
During December 1997, average net production from the Company's onshore
properties was approximately 117 MMcfe per day.
Opportunistic Acquisitions
The Company's primary strategy to grow its reserves through the
drillbit is supplemented by the Company's continuing pursuit of opportunistic
acquisitions of properties with unexploited reserve potential. The Company
targets properties (i) that it can operate, (ii) that are either in the Gulf of
Mexico or onshore in existing core operating areas or in new geographic areas
in which the Company believes it can establish a substantial concentration of
properties and operations, and (iii) that provide a base for further
exploration and development. The Company has a successful track record of
building its reserves through opportunistic acquisitions onshore and in the
Gulf of Mexico and successfully exploiting those reserves. In particular, the
Company has drilled 25 successful wells (74% success rate) in the Charco Field
since acquiring its properties in the field in July 1996. See "-- Pending
Acquisition."
High Percentage of Operated Properties
The Company seeks to operate properties in which it has a significant
ownership interest. By operating these properties the Company can manage
production performance while controlling operating expenses and the timing and
amount of capital expenditures. Properties operated by the Company account for
approximately 90% of its Gulf of Mexico production and approximately 95% of its
onshore production. The Company currently has two offshore jackup rigs and two
land rigs under long-term contracts, which allow the Company to manage the
timing of the drilling of its wells. The Company also pursues cost savings
through the use of outside contractors for much of its offshore field
operations activities. As a result of these and other factors, the Company
achieved lease operating expense (excluding severance taxes) of $0.28 per Mcfe
of production and net general and administrative expense of $0.11 per Mcfe of
production for the year ended December 31, 1997.
Use of Advanced Technology for In-House Prospect Generation
The Company generates virtually all of its exploration prospects
utilizing in-house geological and geophysical expertise. The Company uses
advanced technology, including 3-D seismic and in-house computer-aided
exploration technology, to reduce risks, lower costs and prioritize drilling
prospects. The Company has acquired approximately 2,400 square miles of 3-D
seismic data, including 3-D seismic surveys on 65 of its offshore lease blocks
and on possible
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lease and acquisition prospects, and 73,500 linear miles of offshore 2-D
seismic data. Since the acquisition of its Charco Field properties in 1996,
the Company has purchased and commenced interpretation of 3-D seismic data
covering 148 square miles of the field. In 1998, the Company anticipates the
acquisition of 30 square miles of 3-D seismic data on recently acquired East
Texas acreage. The Company has 13 geologists/geophysicists with average
industry experience of approximately 28 years and 10 geophysical workstations
for use in interpreting 3-D seismic data. The availability of 3-D seismic data
for Gulf of Mexico properties at reasonable costs has enabled the Company to
identify exploration and development prospects in the Company's existing
inventory of properties and to define possible lease and acquisition prospects.
Geographically Focused Operations
Focusing drilling activities on properties in relatively concentrated
offshore and onshore areas permits the Company to utilize its base of
geological, engineering, exploration and production experience in the regions.
The Company currently operates in five areas of geographic concentration -- the
Gulf of Mexico, South Texas, the Arkoma Basin, East Texas, and West Virginia --
and continues to evaluate and may add additional core areas in the future. The
Company is currently evaluating an acquisition that would add a new core area
of operations onshore in South Louisiana. See " -- Pending Acquisition." The
geographic focus of the Company's operations allows it to manage a large asset
base with a relatively small number of employees and enables the Company to add
production at relatively low incremental costs. For example, in the Charco
Field, the Company has reduced lease operating expense (excluding severance
taxes) by 50%, from $0.38 per Mcfe for the six month period beginning on July
1, 1996, when the Company acquired its Charco Field properties, and ending
December 31, 1996 to $0.19 per Mcfe for the six month period ended December 31,
1997.
The following table sets forth information regarding the Company's
reserves associated with its properties in the Gulf of Mexico, the Charco Field
in South Texas and the Company's other onshore properties:
<TABLE>
<CAPTION>
Net Proved Reserves
at December 31, 1997
Percent of --------------------
Total Gas Oil Total
Reserves (MMcf) (MBbls) (MMcfe)
-------- ------- ---------------- --------
<S> <C> <C> <C> <C>
Gulf of Mexico . . . . . . . . 35% 112,739 869 117,953
Charco Field . . . . . . . . . 38% 126,575 50 126,875
Other Onshore . . . . . . . . . 27% 91,287 158 92,235
------- ---------- -------
330,601 1,077 337,063
======= ========== =======
</TABLE>
PENDING ACQUISITION
On January 12, 1998, the Company entered into a non-binding letter of
intent with respect to the acquisition of natural gas and oil properties
located onshore in South Louisiana representing 45 Bcfe of net proved reserves
as of November 1, 1997 (the "Pending Acquisition"). The average net production
in December 1997 attributable to such properties was approximately 14 MMcfe per
day. The non-binding letter of intent provides for the Company to pay $60
million for the properties to be acquired. The completion of the Pending
Acquisition is subject to numerous conditions, including the completion of due
diligence and the negotiation and execution of binding agreements, among
others; accordingly, no assurances can be made that the Pending Acquisition
will be consummated.
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GULF OF MEXICO PROPERTIES
The Company holds interests in 79 offshore blocks, of which 26 have
current operations, and operates 18 of these blocks, accounting for
approximately 90% of the Company's offshore production. The following table
lists the Company's average working interest, net proved reserves and the
operator for the Company's eight largest offshore properties as of December 31,
1997, representing 77% of the Company's Gulf of Mexico proved reserves and 65%
of its offshore production:
<TABLE>
<CAPTION>
NET PROVED RESERVES AT DECEMBER 31, 1997
-----------------------------------------
AVERAGE
GAS OIL TOTAL WORKING
FIELD (MMCF) (MBBLS) (MMCFE) INTEREST OPERATOR
----- ------ ------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
East Cameron Blocks 82/83 . . . . . . . . . 18,526 140 19,366 97.8% Company
Mustang Island Blocks 858/868 . . . . . . . 18,343 329 20,317 79.0% Company
West Cameron Blocks 76/77/60/61 Unit . . . 10,826 73 11,264 10.9% Third Party
Matagorda Island Block 651 . . . . . . . . 10,586 6 10,622 79.6% Company
High Island Block 38 . . . . . . . . . . . 7,655 79 8,129 40.0% Third Party
Mustang Island Block 807 . . . . . . . . . 7,892 23 8,030 100.0% Company
Mustang Island Block 759 . . . . . . . . . 6,591 15 6,681 25.0% Third Party
Mustang Island Block 785 . . . . . . . . . 5,914 -- 5,914 71.3% Company
All Other Gulf of Mexico (10 fields) 26,406 204 27,630
--------- ------ --------
Total Gulf of Mexico 112,739 869 117,953
========= ====== ========
</TABLE>
During 1997, the Company drilled six successful exploratory wells and
one successful development well on its Gulf of Mexico properties. During this
same period, the Company drilled three exploratory wells and one development
well that were not successful. Capital spending associated with the Company's
Gulf of Mexico properties during 1997 was $92.7 million, including $42.2
million for exploratory drilling, $19.8 million for development drilling and
$30.7 million for leasehold and lease acquisitions. During 1997, the Company
acquired one producing property, Mustang Island 868, for $2.6 million.
During 1998, the Company intends to focus on exploratory drilling in
the Gulf of Mexico and plans to drill approximately 15 exploratory wells, along
with limited development drilling. The Company's planned exploratory projects
are located in East Cameron Blocks 82/83, West Cameron Block 174, Mustang
Island Blocks A-113/114 and 138/139, High Island Block 115, South Timbalier
Block 318 and Brazos Block A-40. As of February 5, 1998, the Company was
drilling or participating in the drilling of exploratory wells on Mustang
Island Block A-31/32 and Galveston Island Block 144. The following is a
summary description of the Company's exploration and development activity
during 1997. The Company is the operator of each of these properties except for
High Island Block 38 and Eugene Island Block 64.
Mustang Island Block 858/868. The Company holds an 82.5% working
interest in Mustang Island Block 858 and a 65% working interest in Mustang
Island Block 868. The property has three producing wells, the first of which
commenced production in July 1996. During November 1997, the Company
completed the workover of one well and commenced drilling on a development well
and an exploratory well on the property. At December 31, 1997, the Company was
continuing to drill both wells toward targeted objectives at depths between
14,000 and 15,000 feet; the exploratory well was logged and determined to be
unproductive in January 1998, and the development well had not reached its
targeted objective as of February 5, 1998. During December 1997, the block
produced at an average rate of 6,100 Mcfe/d, net to the Company, which reflects
production downtime due to drilling rigs on location. In December 1997, the
Company completed the purchase of a 65% working interest in Mustang Island
Block 868, a neighboring block which includes the platform and facilities used
for production from Mustang Island Block 858. The Company believes the
acquisition will enable it to control and improve the efficiency of operations
for the two properties. The Company owns substantial leasehold interests in
adjacent blocks and is planning additional exploratory and development drilling
during 1998.
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East Cameron Blocks 82/83. The Company holds an average working
interest of 97.8% in East Cameron Blocks 82 and 83. The property currently has
one producing platform on Block 82 and two satellite platforms. In February
1997, the Company began drilling an exploratory well on Block 83, which was
successfully completed in June 1997 after experiencing a period of uncontrolled
gas flow. During December 1997, the production from the combined platforms
averaged 12,200 Mcfe/d, net to the Company.
Mustang Island Block 807. The Company holds a 100% working interest
in Mustang Island Block 807. The block has one well, the initial discovery
well, which during December 1997 produced at an average of 4,500 Mcfe/d, net to
the Company. Platform construction was completed during the first months of
1997 and initial production began in June 1997.
Galveston Island Blocks 252/272. The Company holds an average working
interest of 43.9% in Galveston Island Block 252/272. The property has two
platforms and one satellite platform at Galveston Island Block 272. In late
February 1997, the Company began drilling an exploratory well which was
successfully completed and brought on-line in May 1997. During December 1997,
the platforms were producing at a combined rate averaging 4,100 Mcfe/d, net to
the Company.
East Cameron Block 185. The Company acquired a 100% working interest
in East Cameron Block 185 in March 1996. The Company successfully drilled and
completed an exploratory well during the third quarter of 1997, and completed
the workover of another well on the property. During December 1997, production
averaged 5,300 Mcfe/d, net to the Company.
Mustang Island Block 738. The Company holds a 49.9% working interest
in Mustang Island Block 738. The property has two producing wells which came
on-line in March 1996. During the fourth quarter of 1997, the Company drilled
an additional development well which was unsuccessful. During December 1997,
production averaged 1,100 Mcfe/d, net to the Company.
High Island Block 38. The Company holds a 40% working interest in
High Island Block 38. The Company participated in the successful drilling of
an exploratory well that was completed in the third quarter of 1997.
Production facilities were completed in January 1998 and initial production
commenced in late January 1998 at an initial flow rate between 4,400 and 7,300
Mcfe/d, net to the Company.
Eugene Island Block 64. The Company acquired a 25% working interest
in Eugene Island Block 64 and participated in the drilling of an exploratory
well which was successfully completed in November 1997. Production facilities
are currently being completed and initial production is expected for the first
half of 1998.
ONSHORE PROPERTIES
The Company also owns significant onshore natural gas and oil
properties in South Texas, the Arkoma Basin of Oklahoma and Arkansas, East
Texas and West Virginia. These properties represent interests in 1,176 gross
(770 net) wells, approximately 95% of which the Company is the operator of
record, and 166,463 gross (126,611 net) acres.
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The following table lists the Company's average working interest and
net proved reserves for the Company's core onshore areas of operation as of
December 31, 1997, representing 99% of the Company's onshore reserves:
<TABLE>
<CAPTION>
NET PROVED RESERVES AT
DECEMBER 31, 1997
AVERAGE ----------------------------------------
WORKING GAS OIL TOTAL
FIELD INTEREST (MMCF) (MBBLS) (MMCFE)
----- ---------------- ----------- ------------ -----------
<S> <C> <C> <C> <C>
Charco Field (South Texas) . . . . . . . . . . 95% 126,575 50 126,875
Chismville/Massard Field (Arkansas) . . . . . . 73% 48,079 -- 48,079
Wilburton, Panola and Surrounding Fields
(Oklahoma) . . . . . . . . . . . . . . . . . 23% 7,666 -- 7,666
Willow Springs and Surrounding Fields
(East Texas) . . . . . . . . . . . . . . . . 53% 9,731 91 10,277
Appalachian Area (West Virginia) . . . . . . . 60% 25,811 67 26,213
</TABLE>
During 1997, the Company participated in the drilling of 33 successful
development wells and two successful exploratory wells on its onshore
properties. During this same period, the Company participated in the drilling
of eight development wells and two exploratory wells that were not successful.
Capital spending associated with the Company's onshore drilling program during
1997 was approximately $51.2 million, including $39.4 million for development,
$1.9 million for exploration and $9.9 million for leasehold and lease
acquisitions. During 1997 the Company did not make any acquisitions of onshore
producing properties.
For 1998 the Company has budgeted funds to drill approximately 15
wells in the Charco Area of South Texas, five wells in the Arkoma Basin, two
wells in East Texas and two wells in West Virginia. The Company has identified
enough additional development and exploratory projects on its existing acreage
to maintain an active drilling program for the next four to six years.
The following is a description of several of the Company's most
significant onshore properties:
Charco Field. The Charco Field is located in Zapata County, Texas.
The Company acquired its properties in the Charco Field in July 1996 in the
TransTexas Acquisition. The Company owns a 95% working interest in the
approximately 165 active wells on such properties, all of which are operated by
the Company. During December 1997, the Company's Charco Field properties had
average production of 92,000 Mcfe/d, net to the Company. The Company has
purchased and commenced interpretation of 3-D seismic data covering 148 square
miles of its Charco Field properties. The Company commenced an active drilling
and workover program beginning in the fourth quarter of 1996 to fully exploit
this property and currently has two drilling rigs under long-term contract.
During 1997, the Company successfully drilled and completed 22 development
wells and drilled five unsuccessful development wells. Subsequent to year end,
the Company has drilled two successful and one unsuccessful development wells
and is currently drilling two new development wells.
Chismville/Massard Field. The Chismville/Massard Field is located in
Logan and Sebastian Counties, Arkansas. The Company owns working interests in
approximately 149 active wells, of which it operates 80 wells. Working
interests range from 11% to 100% and average approximately 73%. During 1997,
the Company successfully completed eight gross (5.8 net) development wells and
three gross (2.9 net) unsuccessful development wells. During December 1997,
production averaged 11,700 Mcfe/d, net to the Company.
Willow Springs and Surrounding Fields. The Willow Springs Field is
located in Gregg County, Texas, with surrounding fields located in Panola and
Harrison Counties, Texas. The Company owns working interests in 63 active
wells, of which it operates 20 wells. Working interests range from 3% to 100%
and average approximately 53%. During 1997, the Company participated in the
drilling of one gross (0.4 net) successful development well in this area.
During December 1997, production averaged 3,100 Mcfe/d, net to the Company.
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Wilburton, Panola and Surrounding Fields. The Wilburton and Panola
Fields are located in Latimer County, Oklahoma. The Company owns working
interest in 51 active wells, of which it operates 18 wells. Working interests
range from 1% to 63% and average approximately 23%. During 1997, the Company
participated in the successful drilling of two exploratory wells in which it
had a small combined working interest of 8%. In 1998, the Company participated
in one successful development well, currently being completed, in which it has
a working interest of 11%. During December 1997, production averaged 5,000
Mcfe/d, net to the Company.
Appalachian Area. The Belington, Clarksburg and Seneca Upshur Fields
are located in Barbour, Randolph, Upshur and Mingo Counties, West Virginia.
The Company owns working interests in 670 wells, substantially all of which are
operated by the Company. Working interests range from 6% to 100% and average
approximately 60%. During 1997, the Company drilled and successfully completed
two development wells in this area. During December 1997, production averaged
5,200 Mcfe/d, net to the Company.
ADDITIONAL FUTURE PROJECTS
In addition to the properties described above, the Company has
accumulated a large inventory of offshore leases comprised of 251,307
undeveloped gross (215,514 net) acres. These leases are under review by the
Company's geologists and geophysicists based upon 3-D seismic data acquired in
recent years. The Company has established a team of geologists and
geophysicists to continually evaluate unleased acreage offshore which will be
available at upcoming lease sales. The Company is also actively pursuing
farm-ins from other companies, interests in other companies' joint ventures and
potential acquisitions. Finally, the Company is also evaluating its producing
properties for workovers and recompletions which it will undertake in the next
several years.
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<PAGE> 10
NATURAL GAS AND OIL RESERVES
The following table summarizes the estimates of the Company's
historical net proved reserves as of December 31, 1995, 1996 and 1997, and the
present values attributable to these reserves at such dates. The reserve data
and present values as of December 31, 1997 were prepared by Netherland, Sewell
& Associates, Inc. ("NSA") and Miller and Lents, Ltd. ("Miller and Lents"),
independent petroleum engineering consultants. The reserve data and present
values as of December 31, 1996 and 1995 were prepared by NSA, Miller and Lents,
Ryder Scott Company ("Ryder Scott") and Huddleston & Co., Inc. ("Huddleston").
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------------------
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
Net Proved Reserves (1):
Natural gas (MMcf) . . . . . . . . . . . 195,946 320,474 330,601
Oil (MBbls) . . . . . . . . . . . . . . . 889 1,131 1,077
Total (MMcfe) . . . . . . . . . . . . . . 201,280 327,260 337,063
Present value of future net revenues
before income taxes(2) . . . . . . . . $ 206,574 $ 577,000 $ 377,065
Standardized measure of discounted
future net cash flows(3) . . . . . . . $ 171,459 $ 452,582 $ 315,380
</TABLE>
- -------------
(1) NSA and Miller and Lents prepared reserve data and present values with
respect to properties comprising approximately 73% and 27%,
respectively, of the present values attributable to the Company's
proved reserves as of December 31, 1997. NSA, Miller and Lents, Ryder
Scott and Huddleston prepared reserve data and present values with
respect to properties comprising approximately 47%, 30%, 23%, and 0%,
respectively, of the present values attributable to the Company's
proved reserves as of December 31, 1996, and 14%, 52%, 32%, and 2%,
respectively, of the present values attributable to the Company's
proved reserves as of December 31, 1995.
(2) The present value of future net revenues attributable to the Company's
reserves was prepared using prices in effect at the end of the
respective periods presented, discounted at 10% per annum on a pre-tax
basis. Average prices per Mcf of natural gas, used in making such
present value determinations as of December 31, 1995, 1996 and 1997
were $2.06, $3.41 and $2.31, respectively. Average prices per Bbl of
oil used in making such present value determinations as of December
31, 1995, 1996 and 1997 were $17.29, $22.94 and $17.23, respectively.
Such amounts reflect the effects of the Company's hedging contracts.
(3) The standardized measure of discounted future net cash flows
represents the present value of future net revenues after income tax
discounted at 10% per annum. Such amounts reflect the effects of the
Company's hedging contracts.
In accordance with applicable requirements of the Securities and
Exchange Commission, estimates of the Company's proved reserves and future net
revenues are made using sales prices estimated to be in effect as of the date
of such reserve estimates and are held constant throughout the life of the
properties (except to the extent a contract specifically provides for
escalation). Estimated quantities of proved reserves and future net revenues
therefrom are affected by gas prices, which have fluctuated widely in recent
years. There are numerous uncertainties inherent in estimating natural gas and
oil reserves and their estimated values, including many factors beyond the
control of the producer. The reserve data set forth in this Annual Report on
Form 10-K represent only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact manner. The accuracy of any reserve estimate is
a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates of different engineers,
including those used by the Company, may vary. In addition, estimates of
reserves are subject to revision based upon actual production, results of
future development and exploration activities, prevailing natural gas and oil
prices, operating costs and other factors, which revision may be material.
Accordingly, reserve estimates are often different from the quantities of
natural gas and oil that are ultimately recovered and are highly dependent upon
the accuracy of the assumptions upon which they are based. The Company's
estimated proved reserves have not been filed with or included in reports to
any federal agency.
-10-
<PAGE> 11
The present value of future net revenues before income taxes and the
standardized measure of discounted future net cash flows set forth in this
Annual Report on Form 10-K do not reflect any adjustment for after
program-payout working interests held by the Company's President and Chief
Executive Officer in certain properties of the Company. The amounts expected
to be payable in respect of such after program-payout working interests would
not have a material effect on the information presented. See "Item 13. Certain
Relationships and Related Transactions."
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company on
its properties for the years ended December 31, 1995, 1996 and 1997.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1995 1996 1997
-------------------- ------------------- --------------------
GROSS NET GROSS NET GROSS NET
--------- ---------- ---------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
OFFSHORE DRILLING ACTIVITY:
--------------------------
Exploratory:
Productive . . . . . . . . . . . . . . . . . . 1 1.0 6 4.2 6 3.7
Non-Productive . . . . . . . . . . . . . . . . -- -- 4 2.2 3 2.3
------ ------- ------ ------- ------ -------
Total . . . . . . . . . . . . . . . . 1 1.0 10 6.4 9 6.0
Development:
Productive . . . . . . . . . . . . . . . . . . 7 2.8 1 0.5 1 0.1
Non-Productive . . . . . . . . . . . . . . . . -- -- -- -- 1 0.8
------ ------- ------- ------- ------ -------
Total . . . . . . . . . . . . . . . . 7 2.8 1 0.5 2 0.9
ONSHORE DRILLING ACTIVITY:
-------------------------
Exploratory:
Productive . . . . . . . . . . . . . . . . . . 3 0.5 1 0.1 2 0.1
Non-Productive . . . . . . . . . . . . . . . . -- -- 3 2.2 2 0.6
------ ------- ------ ------- ------ -------
Total . . . . . . . . . . . . . . . . 3 0.5 4 2.3 4 0.7
Development:
Productive . . . . . . . . . . . . . . . . . . 12 7.4 9 6.5 33 29.1
Non-Productive . . . . . . . . . . . . . . . . 5 2.5 1 1.0 8 7.7
------ ------- ------ ------- ------ -------
Total . . . . . . . . . . . . . . . . 17 9.9 10 7.5 41 36.8
PRODUCTIVE WELLS
</TABLE>
The following table sets forth the number of productive wells in which
the Company owned an interest as of December 31, 1997.
<TABLE>
<CAPTION>
COMPANY COMPANY
OPERATED OPERATED TOTAL PRODUCTIVE
PLATFORMS WELLS NON-OPERATED WELLS WELLS
-------------- ------------------------ --------------------- ------------------------
GROSS NET GROSS NET GROSS NET
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
OFFSHORE
--------
Gas . . . . . . . . . . 18 56 35.8 12 2.6 68 38.4
Oil . . . . . . . . . . -- -- -- 4 0.5 4 0.5
----- ----- ------- ----- ------- ----- --------
Total . . . . . . . . . 18 56 35.8 16 3.1 72 38.9
----- ----- ------- ----- ------- ----- --------
ONSHORE
-------
Gas . . . . . . . . . . 949 695.6 151 33.6 1,100 729.2
Oil . . . . . . . . . . 2 1.9 2 0.5 4 2.4
----- ------- ----- ------- ----- --------
Total . . . . . . . . . 951 697.5 153 34.1 1,104 731.6
----- ------- ----- ------- ----- --------
</TABLE>
Productive wells consist of producing wells capable of production,
including gas wells awaiting connections. Wells that are completed in more
than one producing horizon are counted as one well.
-11-
<PAGE> 12
ACREAGE DATA
The following table sets forth the approximate developed and
undeveloped acreage in which the Company held a leasehold mineral or other
interest as of December 31, 1997. Undeveloped acreage includes leased acres on
which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of natural gas and oil, regardless of
whether or not such acreage contains proved reserves:
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
------------------------------------- -------------------------------------
GROSS NET GROSS NET
---------------- --------------- --------------- ----------------
<S> <C> <C> <C> <C>
Offshore (1) . . . . . . . . 142,786 77,323 251,307 215,514
Onshore . . . . . . . . . . . 157,132 120,914 9,331 5,697
---------------- --------------- --------------- ----------------
Total . . . . . . . 299,918 198,237 260,638 221,211
---------------- --------------- --------------- ----------------
</TABLE>
- ------------
(1) Offshore includes acreage in federal and state waters.
MARKETING AND CUSTOMERS
Substantially all of the Company's production is sold at market
prices. The Company sold 38% and 27% of its natural gas production in 1997 and
1996, respectively, to H&N Gas Ltd., an unaffiliated third party. Prior to
October 1996, the Company agreed, subject to certain conditions, to sell
substantially all of its subsequently developed or acquired gas production, to
an affiliate of Brooklyn Union, PennUnion Energy Services, L.L.C.
("PennUnion"). The gas sales agreement with PennUnion was terminated in
September 1996 when Brooklyn Union sold its interest in PennUnion; however,
PennUnion still remains a purchaser of the Company's natural gas production.
The gas production sold to PennUnion is sold at market prices, based upon an
index price adjusted to reflect the point of delivery of such production.
During 1996 and 1995 sales to PennUnion and BRING Gas Services Corp. ("BRING"),
predecessor to PennUnion and then an affiliate of Brooklyn Union, accounted for
40% and 46% of total revenues, respectively. In 1997, sales to PennUnion
accounted for less than 10% of total revenues. The Company believes that the
prices at which it sold gas to PennUnion and BRING were similar to those it
would be able to obtain in the open market. No customer other than H&N Gas
Ltd., PennUnion and BRING purchased more than 10% of the Company's natural gas
production during the past three years. The Company believes that the loss of
any such customer would not have a material adverse effect on the Company's
operations. See Note 9 to the Company's Combined Financial Statements.
The Company enters into commodity swaps with unaffiliated third
parties for portions of its natural gas production to achieve more predictable
cash flows and to reduce its exposure to short-term fluctuations in gas prices.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- General."
Most of the Company's natural gas is transported through gas gathering
systems and gas pipelines which are not owned by the Company. Transportation
space on such gathering systems and pipelines is occasionally limited and at
times unavailable due to repairs or improvements being made to such facilities
or due to such space being utilized by other gas shippers with priority
transportation agreements. While the Company's inability to market its natural
gas has been subject to limitations or delays only on an infrequent basis, if
transportation space is restricted or is unavailable, the Company's cash flow
from the affected properties could be adversely affected. See "-- Regulation"
and "Risk Factors -- Operating Risks of Natural Gas and Oil Operations."
ABANDONMENT COSTS
The Company is responsible for the payment of abandonment costs on the
natural gas and oil properties pro rata to its working interest. The Company
provides for its expected future abandonment liabilities by accruing for such
costs as a component of depletion, depreciation and amortization as the
properties are produced. As of December 31, 1997, total undiscounted
abandonment costs estimated to be incurred through the year 2008 were
approximately $7.0 million for properties in the federal and state waters and
are not considered significant for onshore properties. Estimates
-12-
<PAGE> 13
of abandonment costs and their timing may change due to many factors including
actual drilling and production results, inflation rates, and changes in
environmental laws and regulations.
The Minerals Management Service ("MMS") requires lessees of Outer
Continental Shelf properties to post bonds in connection with the plugging and
abandonment of wells located offshore and the removal of all production
facilities. Operators in the Outer Continental Shelf waters of the Gulf of
Mexico are currently required to post an area wide bond of $3 million or
$500,000 per producing lease. The Company is presently exempt from any
requirement by MMS to provide supplemental bonding on its offshore leases,
although no assurance can be made that it will continue to satisfy the
requirements for such exemption in the future. Whether or not the Company
qualifies for such exemption, the Company does not believe that the cost of any
such bonding requirements will materially affect the Company's financial
condition or results of operations. Under certain circumstances, the MMS has
the authority to suspend or terminate operations on federal leases for failure
to comply with applicable bonding requirements or other regulations applicable
to plugging and abandonment. Any such suspensions or terminations of the
Company's operations could have a material adverse effect on the Company's
financial condition and results of operations.
TITLE TO PROPERTIES
As is customary in the oil and gas industry, the Company makes only a
cursory review of title to farmout acreage and to undeveloped natural gas and
oil leases upon execution of the contracts. Prior to the commencement of
drilling operations, a thorough title examination is conducted and curative
work is performed with respect to significant defects. To the extent title
opinions or other investigations reflect title defects, the Company, rather
than the seller of the undeveloped property, is typically responsible for
curing any such title defects at its expense. If the Company were unable to
remedy or cure any title defect of a nature such that it would not be prudent
to commence drilling operations on the property, the Company could suffer a
loss of its entire investment in the property. The Company has obtained title
opinions on substantially all of its producing properties and believes that it
has satisfactory title to such properties in accordance with standards
generally accepted in the oil and gas industry. Prior to completing an
acquisition of producing natural gas and oil leases, the Company obtains title
opinions on the most significant leases. The Company's natural gas and oil
properties are subject to customary royalty interests, liens for current taxes
and other burdens which the Company believes do not materially interfere with
the use of or affect the value of such properties.
THIRD PARTY CONTRACTORS
In an effort to control costs, the Company entered into a contract
with Operators & Consulting Services, Inc. ("OCS") pursuant to which OCS
provides professional services to the Company in the areas of drilling,
production and construction for offshore properties. OCS provides (i)
engineering and field supervision for well design, drilling, completion and
workover operations; (ii) supervision of the daily production operations and
field personnel to operate and maintain production facilities; and (iii)
coordination and review of third party engineering and fabrication work, and
installation supervision of platforms, production facilities and pipelines.
The Company has maintained this contractual relationship with OCS since 1989.
COMPETITION
The Company encounters competition from other oil and gas companies in
all areas of its operations, including the acquisition of producing properties.
The Company's competitors include major integrated oil and gas companies and
numerous independent oil and gas companies, individuals and drilling and income
programs. Many of its competitors are large, well-established companies with
substantially larger operating staffs and greater capital resources than the
Company's and which, in many instances, have been engaged in the oil and gas
business for a much longer time than the Company. Such companies may be able
to pay more for productive natural gas and oil properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater number of
properties and prospects than the Company's financial or human resources
permit. The Company's ability to acquire additional properties and to discover
reserves in the future will be dependent upon its ability to evaluate and
select suitable properties and to consummate transactions in this highly
competitive environment.
-13-
<PAGE> 14
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in
drilling for and production and transportation of natural gas and oil, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures, and spills, any of which can
result in loss of hydrocarbons, environmental pollution, personal injury
claims, and other damage to properties of the Company and others.
Additionally, certain of the Company's natural gas and oil operations are
located in an area that is subject to tropical weather disturbances, some of
which can be severe enough to cause substantial damage to facilities and
possibly interrupt production. As protection against operating hazards, the
Company maintains insurance coverage against some, but not all, potential
losses. The Company's coverages include, but are not limited to, operator's
extra expense, to include loss of well, blowouts and certain costs of pollution
control, physical damage on certain assets, employer's liability, comprehensive
general liability, automobile and worker's compensation. The Company believes
that its insurance is adequate and customary for companies of a similar size
engaged in operations similar to those of the Company, but losses could occur
for uninsurable or uninsured risks or in amounts in excess of existing
insurance coverage. The occurrence of an event that is not fully covered by
insurance could have an adverse impact on the Company's financial condition and
results of operations.
REGULATION
The availability of a ready market for natural gas and oil production
depends upon numerous factors beyond the Company's control. These factors
include regulation of natural gas and oil production, federal and state
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit, the supply of
natural gas and oil available for sale, the availability of adequate pipeline
and other transportation and processing facilities and the marketing of
competitive fuels. For example, a productive natural gas well may be "shut-in"
because of an oversupply of natural gas or the lack of an available natural gas
pipeline in the areas in which the Company may conduct operations.
Regulation of Oil and Gas Exploration and Production. Exploration and
production operations of the Company are subject to various types of regulation
at the federal, state and local levels. Such regulation includes requiring
permits for the drilling of wells, maintaining bonding requirements in order to
drill or operate wells, and regulating the location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon
which wells are drilling and the plugging and abandonment of wells. The
Company's operations are also subject to various conservation laws and
regulations. These include the regulation of the size of drilling and spacing
units or proration units and the density of wells which may be drilled and
unitization or pooling of oil and gas properties. In this regard, some states
allow the forced pooling or integration of tracts to facilitate exploration
while other states rely on voluntary pooling of lands and leases. In addition,
state conservation laws establish maximum rates of production from natural gas
and oil wells, generally prohibit the venting or flaring of natural gas and
impose certain requirements regarding the ratability of production. The effect
of these regulations is to limit the amounts of natural gas and oil the
Company's operator or the Company can produce from its wells, and to limit the
number of wells or the locations of which the Company can drill. Legislation
affecting the oil and gas industry also is under constant review for amendment
or expansion. Generally, state-established allowables have been influenced by
overall natural gas market supply and demand in the United States, as well as
the specific "nominations" for natural gas from the parties who produce or
purchase gas from the field and other factors deemed relevant by the agency.
The Company cannot predict whether further changes will be made in how these
states set allowables or what impact, if any, such further changes might have.
In addition, numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations binding on the oil and gas
industry and its individual members, some of which carry substantial penalties
for failure to comply. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently expanded,
amended or reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.
Natural Gas Marketing and Transportation. Federal legislation and
regulatory controls in the United States have historically affected the price
of the natural gas produced by the Company and the manner in which such
production is marketed. The Federal Energy Regulatory Commission (the "FERC")
has jurisdiction over the
-14-
<PAGE> 15
transportation and sale for resale of natural gas in interstate commerce by
natural gas companies under the Natural Gas Act of 1938 (the "NGA"). Although
maximum selling prices of natural gas were formerly regulated under the NGA and
the Natural Gas Policy Act of 1978 (the "NGPA"), on July 26, 1989, the Natural
Gas Wellhead Decontrol Act of 1989 (the "Decontrol Act") amended the NGPA to
remove completely by January 1, 1993 price and non-price controls for all
"first sales" of domestic natural gas, which include all sales by the Company
of its own production. Consequently, sales of the Company's natural gas
production currently may be made at market prices, subject to applicable
contract provisions. The FERC's jurisdiction over natural gas transportation
was unaffected by the Decontrol Act.
In July 1994, the FERC eliminated a regulation that had rendered
virtually all sales of natural gas by pipeline and distribution company
affiliates, such as the Company, to be deregulated first sales. Although
several parties challenged the FERC's action, in 1996 the United States Court
of Appeals for the District of Columbia Circuit (the "D.C. Circuit Court")
upheld the FERC's elimination of the regulation. As a result, all sales by the
Company of gas for resale in interstate commerce, other than sales by the
Company of its own production, are now subject to NGA jurisdiction. This
includes, for example, sales for resale of gas purchased from third parties.
The Company does not anticipate this change will have any significant current
adverse effects in light of the market based sales authority under existing
blanket certificates. Such sales are subject to the future possibility of
greater federal oversight, however, including the possibility the FERC might
prospectively impose more restrictive conditions on such sales.
The FERC also regulates interstate natural gas transportation rates
and service conditions, which affect the marketing of natural gas produced by
the Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has endeavored to make
interstate natural gas transportation more accessible to natural gas buyers and
sellers on an open and nondiscriminatory basis. The FERC's efforts have
significantly altered the marketing and pricing of natural gas. Commencing in
April 1992, the FERC issued Order Nos. 636, 636-A and 636-B (collectively,
"Order No. 636"), which, among other things, required interstate pipelines to
"restructure" to provide transportation separate or "unbundled" from the
pipelines' sales of natural gas. Also, Order No. 636 required pipelines to
provide open-access transportation on a basis that is equal for all natural gas
supplies. In most instances, the result of the Order No. 636 and related
initiatives has been to substantially reduce or bring to an end the interstate
pipelines' traditional role as wholesalers of natural gas in favor of providing
only storage and transportation services. The FERC has issued final orders in
the individual pipeline restructuring proceedings relating to the
implementation of Order No. 636, and has performed a series of one year reviews
to determine whether refinements are required regarding individual pipeline
implementations of Order No. 636. While a number of the individual pipeline
restructuring proceedings were appealed to the federal courts of appeal, only a
few are currently pending on appeal and those cases generally deal with limited
pipeline-specific issues.
Several parties appealed various parts of Order No. 636, and in July
1996 the D.C. Circuit Court issued its decision in those appeals. The D.C.
Circuit Court largely upheld the basic tenets of Order No. 636, including the
requirements that interstate pipelines "unbundle" their sales of gas from
transportation and provide open-access transportation on a basis that is equal
for all gas suppliers. The D.C. Circuit Court remanded several relatively
narrow issues for further explanation by the FERC. On remand, in Order No.
636-C, the FERC reaffirmed the holding of Order No. 636 that pipelines should
be entitled to recover 100 percent of their prudently incurred GSR costs. In
addition, the FERC reduced the contract matching cap for the
right-of-first-refusal mechanism to five years. The FERC also decided not to
limit a pipeline's no-notice service to its bundled sales customers at the time
of restructuring, and reaffirmed that pipelines should focus on individual
customers, rather than customer classes, in mitigating the effects of SFV rate
design. Order No. 636-C is currently pending on rehearing the FERC.
Although Order No. 636 does not regulate natural gas producers such as
the Company, the FERC has stated that Order No. 636 is intended to foster
increased competition within all phases of the natural gas industry. It is
unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. While Order No. 636 could provide the Company with
additional market access and more fairly applied transportation service rates,
terms and conditions, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violation of those
tolerances. The Company does not believe, however, that it will be affected by
Order No. 636, or by any action taken by the FERC on
-15-
<PAGE> 16
rehearing of Order No. 636-C, materially differently than other natural gas
producers and marketers with which it competes.
The FERC issued a statement of policy in January 1996 concerning
alternatives to its traditional cost-of- service ratemaking methodology. This
policy statement articulates the criteria that the FERC will use to evaluate
proposals to charge market-based rates for the transportation of natural gas,
and also provides that the FERC will consider proposals for negotiated rates
for individual shippers of natural gas so long as a cost-of-service-based rate
also is available. In a related policy statement, the FERC also requested
comments on whether it should allow gas pipelines the flexibility to negotiate
the terms and conditions of transportation service with prospective shippers.
The Company cannot predict what further action the FERC will take on these
matters; however, the Company does not believe that it will be affected by any
action taken materially differently than other natural gas producers and
marketers with which it competes.
The FERC has recently commenced a reexamination of certain of its
transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary markets. The Company cannot predict what action
the FERC will take on these matters, nor can it accurately predict whether the
FERC's actions will achieve the goal of increasing competition in markets in
which the Company's natural gas is sold. However, the Company does not believe
that it will be affected by any action taken materially differently than other
natural gas producers and marketers with which it competes.
The FERC has also issued a policy statement on how interstate natural
gas pipelines can recover the costs of new pipeline facilities. While the
FERC's policy statement on new construction cost recovery affects the Company
only indirectly, in its present form, the new policy should enhance competition
in natural gas markets and facilitate construction of gas supply laterals. The
FERC has also issued numerous decisions that address how it intends to regulate
natural gas gathering facilities owned (or previously owned but either "spun
down" to an affiliate or "spun off" to a non-affiliate) by interstate pipeline
companies after Order No. 636. Specifically, the FERC has approved the spin
down or spin off by numerous interstate pipelines of their gathering
facilities. These approvals were given despite the strong protests of a number
of producers concerned that any diminution in FERC's oversight of interstate
pipeline-related gathering services might result in a denial of open access or
otherwise subject producers to a pipeline's monopoly power. The FERC has
stated that in the future it may regulate gathering activities if a gatherer
acts in concert with its pipeline affiliate in a manner that frustrates the
FERC's effective regulation of a pipeline. It is unclear what effect the
FERC's new gathering policy will have on producers such as the Company and the
Company cannot predict what further action the FERC will take in this regard.
On February 28, 1996, the FERC issued a Statement of Policy regarding
the application of its jurisdiction under the NGA and OCSLA over new natural
gas facilities and services on the Outer Continental Shelf. In its Policy
Statement, the FERC concluded that it will retain its existing primary function
test to determine whether particular facilities on the Outer Continental Shelf
constitute gathering facilities exempt from the FERC's NGA jurisdiction.
However, the FERC added a new factor to its primary function test for
facilities that are designed to collect gas produced in water depths of 200
meters or more. Such facilities now will be presumed to qualify as gathering
facilities up to the point or points of potential connection with the
interstate pipeline grid. Downstream of that point, the facilities will be
evaluated under the existing primary function test. Existing interstate
pipelines and gathering facilities would retain their present status barring
some change in circumstances. On June 14, 1996, the Commission dismissed all
requests for rehearing of its February 28, 1996 order. With respect to this
policy statement, the Company does not believe that it will be affected by any
action taken materially differently than other natural gas producers and
marketers with which it competes.
The Fifth Circuit Court of Appeals recently remanded a FERC decision
which declared certain offshore facilities to be subject to its jurisdiction.
The Fifth Circuit decision required the FERC to revisit its methodology for
determining whether it has jurisdiction over offshore natural gas pipeline
facilities. It is not clear whether a revised FERC policy regarding its
jurisdiction over offshore natural gas pipeline facilities will have a material
effect on producers such as the Company and the Company cannot predict what
this new policy would entail.
-16-
<PAGE> 17
On July 17, 1996, the FERC issued Order No. 587 which revised the
FERC's regulations to require interstate natural gas pipelines to follow
standardized procedures issued by the Gas Industry Standards Board ("GISB") for
certain business practices, i.e., nominations, allocations, balancing,
measurement, invoicing, capacity release and electronic communication between
the pipelines and those with whom they do business. On January 30, 1997, in
Order No. 587-B, the FERC incorporated into its regulations a second set of
GISB standards that would, inter alia, require interstate pipelines to conduct
business transactions and provide other information according to Internet
protocols and to abide by certain business practice standards dealing with
nomination, flowing gas and capacity release. On March 4, 1997, the FERC
issued Order No. 587-C which amended the FERC's regulations to adopt standards
requiring interstate pipelines to publish certain information on Internet web
pages and to implement new business practice standards covering nominations and
flowing gas. The intent of these standards adopted pursuant to Order Nos. 587,
et seq., is to establish a more efficient and integrated pipeline grid which
will reduce the variations in pipeline business practices and allow buyers to
obtain and transport gas from all potential sources of supply more easily and
efficiently. The FERC has denied requests for rehearing of Order Nos. 587, et
seq.. An appeal of Order No. 587 is pending before the D.C. Circuit Court.
With respect to GISB issues, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any
such proposals might become effective, or their effect, if any, on the
Company's operations. The natural gas industry historically has been very
heavily regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by the FERC and Congress will continue
indefinitely into the future.
Offshore Leasing. Certain operations the Company conducts are on
federal oil and gas leases, which the MMS administers. The MMS issues such
leases through competitive bidding. These leases contain relatively
standardized terms and require compliance with detailed MMS regulations and
orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are
subject to change by the MMS). For offshore operations, lessees must obtain
MMS approval for exploration plans and development and production plans prior
to the commencement of such operations. In addition to permits required from
other agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the Outer Continental Shelf
to meet stringent engineering and construction specifications, and has recently
proposed additional safety-related regulations concerning the design and
operating procedures for Outer Continental Shelf production platforms and
pipelines. The MMS also has issued regulations restricting the flaring or
venting of natural gas, and has recently proposed to amend such regulations to
prohibit the flaring of liquid hydrocarbons and oil without prior
authorization. Similarly, the MMS has promulgated other regulations governing
the plugging and abandonment of wells located offshore and the removal of all
production facilities. To cover the various obligations of lessees on the
Outer Continental Shelf, the MMS generally requires that lessees post
substantial bonds or other acceptable assurances that such obligations will be
met. The cost of such bonds or other surety can be substantial and there is no
assurance that the Company can obtain bonds or other surety in all cases. See
"-- Environmental Matters."
In addition, the MMS is conducting an inquiry into certain contract
settlement agreements from which producers on MMS leases have received
settlement proceeds that are royalty bearing and the extent to which producers
have paid the appropriate royalties on those proceeds. The MMS has recently
issued a final rule governing valuation for royalty purposes of gas produced
from federal and Indian leases to primarily address allowances for
transportation of gas. The amendments clarify the methods by which gas
royalties and deductions for gas transportation are calculated. The Company
does not believe that these amended regulations will affect the Company
materially differently than other natural gas producers and marketers with
which it competes.
The MMS has recently issued a notice of proposed rulemaking in which
it proposes to amend its regulations governing the calculation of royalties and
the valuation of natural gas produced from federal leases. The principal
feature in the amendments, as proposed, would establish an alternative
market-index based method to calculate royalties on certain natural gas
production sold to affiliates or pursuant to non-arm's-length contracts. The
MMS has proposed this rulemaking to facilitate royalty valuation in light of
changes in the natural gas marketing environment. The
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<PAGE> 18
Company cannot predict what action the MMS will take on these matters, nor can
it predict at this state of the rulemaking proceeding how the Company might be
affected by amendments to the regulations.
The OCSLA requires that all pipelines operating on or across the Outer
Continental Shelf provide open-access, non-discriminatory service. Although
the FERC has opted not to impose the regulations of Order No. 509, which
implements these requirements to the OCSLA, on gatherers and other
nonjurisdictional entities, the FERC has retained the authority to exercise
jurisdiction over those entities if necessary to permit non-discriminatory
access to services on the Outer Continental Shelf. If the FERC were to apply
Order No. 509 to gatherers in the Outer Continental Shelf, eliminate the
exemption of gathering lines, and redefine its jurisdiction over gathering
lines, then these acts could result in a reduction in available pipeline space
for existing shippers, such as the Company, in the Gulf of Mexico and
elsewhere.
Oil Sales and Transportation Rates. Sales of crude oil, condensate
and gas liquids by the Company are not regulated and are made at market prices.
The price the Company receives from the sale of these products is affected by
the cost of transporting the products to market. Effective as of January 1,
1995, the FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which would generally index such rates
to inflation, subject to certain conditions and limitations. These regulations
were affirmed by the D.C. Circuit Court on May 10, 1996. Because of the
uncertainty surrounding the indexing methodology, as well as the possibility of
the use of cost-of-service ratemaking and market-based rates, the Company is
not able at this time to predict the effects of these regulations, if any, on
the Company's oil producing operations.
Safety Regulation. The Company's gathering operations are subject to
safety and operational regulations relating to the design, installation,
testing, construction, operation, replacement, and management of facilities.
Pipeline safety issues have recently been the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels. In addition, the major federal pipeline safety law is subject to
change this year as it is considered for reauthorization by Congress. For
example, federal legislation addressing pipeline safety issues has been
introduced, which, if enacted, would establish a federal "one call"
notification system. Additional pending legislation would, among other things,
increase the frequency with which certain pipelines must be inspected, as well
as increase potential civil and criminal penalties for violations of pipeline
safety requirements. The Company believes its operations, to the extent they
may be subject to current natural gas pipeline safety requirements, comply in
all material respects with such requirements. The Company cannot predict what
effect, if any, the adoption of this or other additional pipeline safety
legislation might have on its operations, but the industry could be required to
incur additional capital expenditures and increased costs depending upon future
legislative and regulatory changes.
ENVIRONMENTAL MATTERS
The Company's operations are subject to federal, state and local laws
and regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas, require remedial measures to prevent
pollution from former operations, such as pit closure and plugging abandoned
wells, and impose substantial liabilities for pollution resulting from the
Company's operations. In addition, these laws, rules and regulations may
restrict the rate of oil and natural gas production below the rate that would
otherwise exist. The regulatory burden on the oil and gas industry increases
the cost of doing business and consequently affects its profitability. Changes
in environmental laws and regulations occur frequently, and any changes that
result in more stringent and costly waste handling, disposal and clean-up
requirements could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general. Management believes
that the Company is in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on the Company.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the original conduct, on certain classes of persons who
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<PAGE> 19
are considered to be responsible for the release of a "hazardous substance"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed
or arranged for the disposal of the hazardous substances. Under CERCLA, such
persons may be subject to joint and several liability for the costs of cleaning
up the hazardous substances that have been released into the environment, for
damages to natural resources and for the costs of certain health studies, and
it is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the release
of hazardous substances.
The Oil Pollution Act of 1990 (the "OPA"), as amended by the Coast
Guard Authorization Act of 1996, (collectively, "OPA"), and regulations
thereunder impose a variety of requirements on "responsible parties" related to
the prevention of oil spills and liability for damages resulting from such
spills in "waters of the United States." A "responsible party" includes the
owner or operator of a facility or vessel, or the lessee or permittee of the
area in which an offshore facility is located. The term "waters of the United
States" has been broadly defined to include not only the waters of the Gulf of
Mexico but also inland water bodies, including wetlands, playa lakes and
intermittent streams. The OPA also requires owners and operators of offshore
facilities to establish and maintain evidence of oil-spill financial
responsibility ("OSFR") for costs attributable to oil spills. Under the Coast
Guard Authorization Act of 1996, the definition of offshore facility includes
facilities located in coastal inland waters, such as bays or estuaries. OPA
requires a minimum of $35 million in OSFR for offshore facilities located on
the Outer Continental Shelf and a minimum of $10 million for offshore
facilities located landward of the seaward boundary of a State. This amount is
subject to upward regulatory adjustment up to $150 million. Responsible
parties for more than one offshore facility are required to provide OSFR only
for their offshore facility requiring the highest OSFR. On March 25, 1997, the
Minerals Management Service proposed regulations for establishing the amount of
OSFR to be required for particular facilities. Under the proposed rule, the
amount of OSFR will increase as the volume of a facility's worst-case oil spill
increases. Accordingly, for Outer Continental Shelf facilities with worst-case
spills of less than 35,000 barrels, only $35 million in OSFR will be required;
for worst-case spills of over 35,000 barrels, $70 million will be required; for
worst-case spills of over 70,000 barrels, $105 million will be required; and
for worst-case spills of over 105,000 barrels, $150 million will be required.
In addition, all OSFR below $150 million remains subject to upward regulatory
adjustment if warranted by the particular operational, environmental, human
health or other risks involved with a facility. Although the current
environmental regulation has had no material adverse effect of the Company, the
impact of the recently adopted and proposed regulatory changes, and of future
environmental regulatory developments such as stricter environmental regulation
and enforcement policies, cannot presently be quantified.
OPA imposes a variety of additional requirements on responsible
parties for vessels or oil and gas facilities related to the prevention of oil
spills and liability for damages resulting from such spills in waters of the
United States. OPA assigns liability to each responsible party for oil spill
removal costs and a variety of public and private damages from oil spills.
While liability limits apply in some circumstances, a party cannot take
advantage of liability limits if the spill is caused by gross negligence or
willful misconduct or resulted from violation of a federal safety, construction
or operating regulation. If a party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply. OPA establishes
a liability limit for offshore facilities of all removal costs plus $75
million. Few defenses exist to the liability for oil spills imposed by OPA.
OPA also imposes other requirements on facility operators, such as the
preparation of an oil spill contingency plan. Failure to comply with ongoing
requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions. As of this date,
the Company is not the subject of any civil or criminal enforcement actions
under the OPA.
In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating in the
Outer Continental Shelf. Specific design and operational standards may apply
to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures.
Violations of lease conditions or regulations issued pursuant to OCSLA can
result in substantial civil and criminal penalties, as well as potential court
injunctions curtailing operations and the cancellation of leases. Such
enforcement liabilities can result from either governmental or private
prosecution. As of this date, the Company is not the subject of any civil or
criminal enforcement actions under OCSLA.
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<PAGE> 20
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of produced waters and other oil
and gas wastes into navigable waters. Permits must be obtained to discharge
pollutants to state and federal waters. The FWPCA provides for civil, criminal
and administrative penalties for any unauthorized discharges of oil and other
hazardous substances in reportable quantities and, along with the OPA, imposes
substantial potential liability for the costs of removal, remediation and
damages. State laws for the control of water pollution also provide varying
civil, criminal and administrative penalties and liabilities in the case of a
discharge of petroleum or its derivatives into state waters. In January 1995,
the U.S. Environmental Protection Agency ("EPA") issued general permits
prohibiting the discharge of produced water and produced sand derived from oil
and gas point source facilities to coastal waters in Louisiana and Texas,
effective February 8, 1995. However, concurrent with this action, EPA Region
VI issued an administrative order effectively delaying the prohibition on
discharges of produced water and produced sands to January 1, 1997, unless an
earlier compliance date is required by the State. Although the costs to comply
with zero discharge mandates under federal or state law may be significant, the
entire industry will experience similar costs and the Company believes that
these costs will not have a material adverse impact on the Company's financial
conditions and operations. Some oil and gas exploration and production
facilities are required to obtain permits for their storm water discharges.
Costs may be associated with treatment of wastewater or developing storm water
pollution prevention plans. Further, the Coastal Zone Management Act
authorizes state implementation and development of programs of management
measures for nonpoint source pollution to restore and protect coastal waters.
EMPLOYEES
As of December 31, 1997, the Company had 104 full time employees, 60
of whom are located at the Company's headquarters in Houston, Texas and the
remainder of whom are located at field offices. None of the Company's
employees are represented by a labor union. The Company contracts with OCS to
conduct all of the day to day operations of the Company's offshore properties.
See "-- Third Party Contractors.".
OFFICES
The Company currently leases approximately 71,100 square feet of
office space in Houston, Texas, where its principal offices are located. In
addition, the Company maintains field operations offices in the areas where it
operates onshore properties.
ITEM 3. LEGAL PROCEEDINGS
The properties purchased in the TransTexas Acquisition are subject to
a judgment lien imposed on substantially all of TransTexas' properties in the
aggregate amount of $18 million. TransTexas has agreed to indemnify the
Company with respect to any loss arising from such judgment lien. TransTexas
has appealed the judgment to which such liens relate, and has posted a bond to
ensure payment of such judgment pending the completion of such appeal. The
bond, in the approximate amount of $18 million, is secured by an irrevocable
letter of credit. The $18 million judgment against TransTexas has been
reversed, a decision which, if upheld, will result in the release of the
related judgment lien. As a result of such arrangements, the Company believes
that the properties purchased in the TransTexas Acquisition are not subject to
any material risk that any such judgment against TransTexas will not be paid.
The Company is not a party to any other pending legal proceedings,
other than ordinary routine litigation incidental to its business that
management believes will not have a material adverse effect on its financial
condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's security holders
during the last quarter of the fiscal year ended December 31, 1997.
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<PAGE> 21
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's common stock (symbol: THX) is traded on the New York
Stock Exchange. The following table sets forth the range of high and low sales
prices for each calendar quarterly period from September 20, 1996 through
December 31, 1997 as reported on the New York Stock Exchange:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996 High Low
---------------------------- --------- --------
<S> <C> <C>
Third Quarter (commencing September 20, 1996) . . . $ 17.00 $ 16.50
Fourth Quarter . . . . . . . . . . . . . . . . . . 18.25 15.875
YEAR ENDED DECEMBER 31, 1997 High Low
---------------------------- --------- --------
First Quarter . . . . . . . . . . . . . . . . . . . $ 18.875 $ 11.50
Second Quarter . . . . . . . . . . . . . . . . . . 16.00 11.875
Third Quarter . . . . . . . . . . . . . . . . . . . 23.187 15.25
Fourth Quarter . . . . . . . . . . . . . . . . . . 27.25 17.50
</TABLE>
As of February 5, 1997, 23,360,903 shares of Common Stock were
outstanding and the Company had approximately 68 shareholders of record and
approximately 2,800 beneficial owners.
DIVIDENDS
The Company currently intends to retain its cash for the operation and
expansion of its business, including exploration, development and acquisition
activities. The Company's Credit Facility (as defined in "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources") contains restrictions on the payment of
dividends to holders of Common Stock. Accordingly, the Company's ability to
pay dividends will depend upon such restrictions and the Company's results of
operations, financial condition, capital requirements and other factors deemed
relevant by the Board of Directors. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations."
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<PAGE> 22
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below with respect to the
Company's combined statements of operations for each of the five years in the
period ended December 31, 1997 and with respect to the Company's combined
balance sheets as of December 31, 1993, 1994, 1995, 1996 and 1997 are derived
from the financial statements of the Company that have been audited by Arthur
Andersen LLP, independent public accountants. The financial data should be
read in conjunction with the "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's Combined Financial
Statements and Notes thereto included elsewhere and incorporated by reference
in this Annual Report on Form 10-K.
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------------------------------------------------
1993 1994 1995 1996 1997
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Combined Statement of Operations Data:
Revenues:
Natural gas and oil revenues . . . $ 37,462 $ 41,755 $ 39,431 $ 64,864 $ 116,349
Other . . . . . . . . . . . . . . 799 467 1,778 1,040 1,297
-------- ----------- ------------ ----------- ----------
Total revenues . . . . . . 38,261 42,222 41,209 65,904 117,646
Expenses:
Lease operating . . . . . . . . . 4,173 4,858 5,005 10,800 14,146
Severance tax . . . . . . . . . . 304 486 463 1,401 4,233
Depreciation, depletion and
amortization . . . . . . . . . . 23,225 25,365 21,969 33,732 59,081
General and administrative, net 2,454 3,460 3,486 6,249 5,825
Nonrecurring charge(1) . . . . . -- -- 12,000 -- --
--------- ----------- ------------ ---------- ---------
Total operating expenses . . . . . 30,156 34,169 42,923 52,182 83,285
Income (loss) from operations . . . . . . 8,105 8,053 (1,714) 13,722 34,361
Interest expense, net . . . . . . . . . . 1,764 2,102 2,398 2,875 938
--------- ---------- ------------ ----------- ----------
Income (loss) before income taxes . . . . 6,341 5,951 (4,112) 10,847 33,423
Income tax provision (benefit) . . . . . 1,790 597 (3,809) 2,205 10,173
--------- ---------- ------------ ----------- ----------
Net income (loss) . . . . . . . . . . . . $ 4,551 $ 5,354 $ (303) $ 8,642 $ 23,250
========= ========== ============ =========== ==========
Net income (loss) per share . . . . . . . $ 0.30 $ 0.35 $ (0.02) $ 0.49 $ 1.00
========= ========== ============ =========== ==========
Net income (loss) per share assuming
dilution . . . . . . . . . . . . . . . $ 0.30 $ 0.35 $ (0.02) $ 0.49 $ 0.97
========= ========== ============ =========== ==========
Weighted average shares outstanding . . $ 15,295 $ 15,295 $ 15,295 $ 17,532 $ 23,337
As of December 31,
-------------------------------------------------------------------
1993 1994 1995 1996 1997
(in thousands)
Combined Balance Sheet Data:
Property, plant and equipment, net . . . . $ 127,911 $ 169,714 $ 216,678 $ 359,124 $ 443,738
Total assets . . . . . . . . . . . . . . . 165,031 201,678 247,496 401,285 491,391
Long-term debt . . . . . . . . . . . . . . 46,600 65,650 71,862 65,000 113,000
Stockholders' equity . . . . . . . . . . . 65,575 88,866 103,236 233,300 256,187
</TABLE>
- -------------
(1) Represents a nonrecurring non-cash charge incurred in connection with
the reorganization effective in February 1996. See Note 11 to the
Company's Combined Financial Statements.
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<PAGE> 23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of
the Company's historical financial position and results of operations for each
year of the three-year period ended December 31, 1997. The Company's
historical combined financial statements and notes thereto included elsewhere
in this Annual Report on Form 10-K contain detailed information that should be
referred to in conjunction with the following discussion.
GENERAL
Houston Exploration was incorporated in December 1985 to conduct
certain of the natural gas and oil exploration and development activities of
Brooklyn Union. The Company initially focused primarily on the exploration and
development of high potential prospects in the Gulf of Mexico. Effective
February 29, 1996, Brooklyn Union implemented a reorganization of its
exploration and production assets by transferring to Houston Exploration
certain onshore producing properties and developed and undeveloped acreage.
Subsequent to the reorganization, the Company has expanded its focus to include
lower risk exploitation and development drilling on the onshore properties
transferred or acquired, in addition to seeking opportunistic acquisitions both
onshore and offshore. On July 2, 1996, the Company acquired certain natural
gas and oil properties and associated pipelines located in Zapata County, Texas
(the "TransTexas Acquisition") from TransTexas. In September 1996, the Company
completed its IPO of 7,130,000 shares of its Common Stock at $15.50 per share,
resulting in net cash proceeds of approximately $101.0 million. Concurrently
with the completion of the IPO, the Company completed the acquisition of
substantially all of the natural gas and oil properties and related assets of
Soxco (the "Soxco Acquisition"). As of December 31, 1997, THEC Holdings Corp.,
a wholly owned subsidiary of Brooklyn Union, owned approximately 65% of the
outstanding shares of Common Stock. At December 31, 1997, the Company had net
proved reserves of 337 Bcfe, 98% of which were natural gas and 78% of which
were classified as proved developed.
The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for natural gas, oil and
condensate, which are dependent upon numerous factors beyond the Company's
control, such as economic, political and regulatory developments and
competition from other sources of energy. The energy markets have historically
been highly volatile, and future decreases in natural gas and oil prices could
have a material adverse effect on the Company's financial position, results of
operations, quantities of natural gas and oil reserves that may be economically
produced, and access to capital.
The Company uses the full cost method of accounting for its investment
in natural gas and oil properties. Under the full cost method of accounting,
all costs of acquisition, exploration and development of natural gas and oil
reserves are capitalized into a "full cost pool" as incurred, and properties in
the pool are depleted and charged to operations using the unit-of-production
method based on the ratio of current production to total proved natural gas and
oil reserves. To the extent that such capitalized costs (net of accumulated
depreciation, depletion and amortization) less deferred taxes exceed the
present value (using a 10% discount rate) of estimated future net cash flows
from proved natural gas and oil reserves and the lower of cost or fair value of
unproved properties, such excess costs are charged to operations. If a
write-down is required, it would result in a charge to earnings but would not
have an impact on cash flows from operating activities. Once incurred, a
write-down of oil and gas properties is not reversible at a later date even if
oil and gas prices increase.
As of December 31, 1997, the Company estimates, using prices in effect
as of such date, that the ceiling limitation imposed under full cost accounting
rules on total capitalized natural gas and oil property costs exceeded actual
capitalized costs. Natural gas prices have fluctuated substantially since
December 31, 1997. The Company may be required to write down the carrying
value of its natural gas and oil properties at the end of the first quarter of
1998, depending upon natural gas prices and the results of the Company's
drilling programs.
In February 1997, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 128, "Earnings Per Share." The statement specifies the
computation, presentation, and disclosure requirements for earnings per share
("EPS") and is designed to improve the EPS information provided in the
financial statements by simplifying the existing computation. Primary EPS has
been replaced with Basic EPS which is calculated by dividing net income by the
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<PAGE> 24
weighted average number of shares of common stock outstanding during the year.
No dilution for any potentially dilutive securities is included. Fully diluted
EPS is now called Diluted EPS and assumes the conversion of all options,
contingent shares and other potentially dilutive securities. The Company
adopted SFAS No. 128 in its December 31, 1997 financial statements and has
presented Diluted EPS for the years 1995 and 1996 which were previously not
required as the dilutive effect of options and contingent shares was less than
3%. See Note 1 to the Company's Combined Financial Statements.
In February 1997, the FASB issued SFAS No. 129, "Disclosure of
Information About Capital Structure," which consolidates the existing
requirements to disclose certain information about an entity's capital
structure, for both public and nonpublic entities. In June 1997, FASB issued
SFAS No. 130, "Reporting Comprehensive Income," which establishes standards for
reporting and display of comprehensive income and its components. Also issued
in June of 1997 was SFAS No. 131, "Disclosures About Segments of an Enterprise
and Related Information," which specifies and revises guidelines for
determining an entity's operating and geographic segments and the type and
level of financial information about those segments to be disclosed. The
Company adopted the provisions of SFAS Nos. 129, 130 and 131 in its 1997
financial statements. The adoption of SFAS Nos. 129, 130 and 131 did not have
a material effect on its results of operations or the calculation of net
income.
The Company incurs certain production gas volume imbalances in the
ordinary course of business and utilizes the entitlements method to account for
its gas imbalances. Under this method, income is recorded based on the
Company's net revenue interest in production or nominated deliveries.
Deliveries in excess of these amounts are recorded as liabilities, while under
deliveries are reflected as assets. Production imbalances are valued using
market value. Management does not believe that the Company has any material
overproduced gas balances.
The Company receives reimbursement for administrative and overhead
expenses incurred on the behalf of other working interest owners of properties
operated by the Company. In addition, the Company capitalizes general and
administrative costs and interest expense directly related to its acquisition,
exploration and development activities.
The Company's combined historical financial statements include the
historical results of operations associated with the onshore producing
properties and developed and undeveloped acreage transferred to the Company by
Fuel Resources Inc. ("FRI"), a subsidiary of Brooklyn Union, in the February
1996 reorganization implemented by Brooklyn Union. Accordingly, the Company's
historical results of operations reflect a nonrecurring charge of $12 million
incurred in the year ended December 31, 1995 with respect to remuneration to
which certain employees of FRI were entitled for the increase in the value of
the transferred properties prior to the reorganization. See Notes 1 and 11 to
the Company's Combined Financial Statements.
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<PAGE> 25
RESULTS OF OPERATIONS
The following table sets forth the Company's historical natural gas
and oil production data during the periods indicated:
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------
1995 1996 1997
<S> <C> <C> <C>
Production:
Natural gas (MMcf) . . . . . . . . . . . 21,077 31,215 50,310
Oil (MBbls) . . . . . . . . . . . . . . . 100 118 171
Total (MMcfe) . . . . . . . . . . . . . . 21,677 31,923 51,336
Average sales prices:
Natural Gas (per Mcf)(1) . . . . . . . . $ 1.79 $ 2.00 $ 2.25
Oil (per Bbl) . . . . . . . . . . . . . . 16.54 21.53 18.33
Expenses (per Mcfe):
Lease operating . . . . . . . . . . . . . $ 0.23 $ 0.34 $ 0.28
Severance tax . . . . . . . . . . . . . . 0.02 0.04 0.08
Depreciation, depletion and amortization 1.01 1.06 1.15
General and administrative, net . . . . . 0.16 0.20 0.11
</TABLE>
- ----------
(1) Reflects the effects of hedging. Absent the effects of hedging,
average realized natural gas prices would have been $1.53, $2.35 and
$2.45 per Mcf for the years ended December 31, 1995, 1996 and 1997,
respectively.
RECENT FINANCIAL AND OPERATING RESULTS
COMPARISON OF YEARS ENDED DECEMBER 31, 1996 AND 1997
Production. Houston Exploration's production increased 61% from
31,923 MMcfe in 1996 to 51,336 MMcfe in 1997. The increase in production was
attributable to added production from both the TransTexas and the Soxco
Acquisitions, which were completed during the second half of 1996, combined
with newly developed offshore production brought on-line during the second and
third quarters of 1997 and the successful development drilling and workover
programs begun in the latter half of 1996 and continuing through the fourth
quarter of 1997 on the Charco Field properties acquired in the TransTexas
Acquisition. Production in the Charco Field increased 179% from approximately
33,000 Mcfe per day in December 1996 to approximately 92,000 Mcfe per day in
December 1997 as 22 development wells were successfully completed and brought
on-line during 1997.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased
79% from $64.9 million in 1996 to $116.3 million in 1997 as a result of the 61%
increase in production combined with a 13% increase in average realized natural
gas prices, from $2.00 per Mcf in 1996 to $2.25 per Mcf for the year ended
1997.
As a result of hedging activities, the Company realized an average gas
price of $2.25 per Mcf for 1997, which was 92% of the $2.45 per Mcf that
otherwise would have been received, resulting in a $9.9 million decrease in
natural gas revenues for the year ended December 31, 1997. During 1996, the
average realized gas price was $2.00 per Mcf which was 85% of the unhedged
average gas price of $2.35, resulting in a decrease in natural gas revenues of
$11.1 million for the year ended 1996.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 31% from $10.8 million in 1996 to $14.1 million in 1997. On an Mcfe
basis, lease operating expenses decreased from $0.34 in 1996 to $0.28 in 1997.
The increase in lease operating expenses during 1997 is primarily attributable
to properties acquired in the
-25-
<PAGE> 26
TransTexas Acquisition and the significant expansion of operations in the
Charco Field combined with the effects of an industry-wide increase in
operating costs. The decrease in the lease operating expenses per Mcfe
resulted from the substantial increase in production during 1997. Severance
tax, which is a function of volume and revenues generated from onshore
production, increased 202% from $1.4 million, or $0.04 per Mcfe, in 1996 to
$4.2 million, or $0.08 per Mcfe, in 1997. The increase in severance tax is due
to the increase in production from the onshore Charco Field properties combined
with higher gas prices in 1997 compared to 1996.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 75% from $33.7 million in 1996 to $59.1 million
in 1997. Depreciation, depletion and amortization expense per Mcfe increased
9% from $1.06 in 1996 to $1.15 in 1997. The increase in depreciation,
depletion and amortization expense was a result of the increased production
from acquired as well as newly developed properties combined with an increased
depletion rate. The increase in the depletion rate is attributable partly to
the industry-wide increase in costs of drilling goods and services, platform
and facilities construction combined with a relatively modest increase in
reserves given the increased capital expenditures from the Company's
exploration and development activities during 1997.
General and Administrative Expenses. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $1.0 million and $0.9 million, in 1996 and 1997, respectively,
decreased 7% from $6.2 million in 1996 to $5.8 million in 1997. After
excluding the one-time charge of $0.8 million taken in September 1996 in
conjunction with the IPO for the buyout and termination of stock options
granted to certain officers and directors of Brooklyn Union, general and
administrative expense increased 7% from $5.4 million in 1996 to $5.8 million
in 1997. The increase in general and administrative expense reflects the
overall growth and expansion of the Company and its operations since the second
half of 1996 and continuing through the end of 1997. The Company capitalized
general and administrative expenses directly related to oil and gas exploration
and development activities of $5.3 million and $7.2 million, respectively, in
1996 and 1997. The increase in capitalized general and administrative expense
directly corresponds with the growth of the Company's technical workforce and
the implementation of an incentive compensation plan. On an Mcfe basis,
general and administrative expenses decreased 45% from $0.20 in 1996 to $0.11
in 1997. The lower rate per Mcfe during 1997 reflects the increase in the
Company's production.
Income Tax Provision. The provision for income taxes increased from
an expense of $2.2 million in 1996 to an expense of $10.2 million in 1997 due
to the increase in pretax income offset by the benefit received from Section 29
tax credits.
Operating Income and Net Income. Operating income increased 151% to
$34.4 million in 1997 from $13.7 million in 1996. Net income increased 171%
from $8.6 million in 1996 to $23.3 million in 1997. The significant increase
in operating income and net income was attributable primarily to higher
production volumes and higher net realized natural gas prices combined with
lower lease operating expenses.
COMPARISON OF YEARS ENDED DECEMBER 31, 1995 AND 1996
Production. Houston Exploration's production increased 47% from
21,677 MMcfe in 1995 to 31,923 MMcfe in 1996. The 1996 production increase is
attributed to commencement of production from newly developed offshore
properties during the first half of the year and the Company's two significant
acquisitions during the second half of the year: (i) the TransTexas
Acquisition, which was completed on July 2, 1996, and (ii) the Soxco
Acquisition, which was completed on September 25, 1996 concurrently with the
closing of the IPO.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased
65% from $39.4 million in 1995 to $64.9 million in 1996 as a result of the 47%
increase in production and an increase in average realized natural gas prices
of 12% from $1.79 per Mcf in 1995 to $2.00 Mcf in 1996.
As a result of hedging activities, the Company realized an average gas
price of $2.00 per Mcf for 1996, compared to an average price of $2.35 per Mcf
that otherwise would have been received, resulting in a $11.1 million decrease
in natural gas revenues for the year ended December 31, 1996. During 1995, the
average realized gas price
-26-
<PAGE> 27
was $1.79 per Mcf compared to an unhedged average gas price of $1.53,
resulting in an increase in natural gas revenues of $5.6 million for the year
ended December 31, 1995.
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 116% from $5.0 million in 1995 to $10.8 million in 1996. On an Mcfe
basis, lease operating expenses increased from $0.23 in 1995 to $0.34 in 1996.
Of the $5.8 million increase in lease operating expenses during 1996, $2.2
million relates directly to properties acquired in the TransTexas Acquisition
at the beginning of the third quarter and includes certain one-time expenses
incurred in taking over operations of these properties, and the remaining $3.6
million reflects higher initial operating costs associated with bringing new
facilities and wells on-line. Severance tax, which is a function of volume and
revenues generated from onshore production, increased 180% from $0.5 million,
or $0.02 per Mcfe, in 1995 to $1.4 million, or $0.04 per Mcfe, in 1996. The
increase in severance tax resulted from the addition of production from the
onshore Charco Field properties combined with an increase in net realized
natural gas prices during the fourth quarter of 1996.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 53% from $22.0 million in 1995 to $33.7 million
in 1996. The increase was attributable to the increase in production during
1996. Depreciation, depletion and amortization expense per Mcfe increased from
$1.01 in 1995 to $1.06 in 1996, primarily as a result of exploratory drilling
which did not add significant new reserves during the period.
General and Administrative Expenses. General and administrative
expenses, net of overhead reimbursements received from other working interest
owners of $1.2 million and $1.0 million for 1995 and 1996, respectively,
increased 77% from $3.5 million in 1995 to $6.2 million in 1996. The Company
capitalized general and administrative expenses directly related to oil and gas
exploration and development activities of $4.1 million and $5.3 million,
respectively, in 1995 and 1996. The increase in net general and administrative
expenses during 1996 is a result of certain one-time expenses incurred in
conjunction with the combination of offshore and onshore operations and an $0.8
million charge taken in conjunction with the IPO for the buyout and termination
of options to purchase Common Stock granted to certain officers and directors
of Brooklyn Union under the Company's 1994 Incentive Plan. On an Mcfe basis,
general and administrative expenses increased from $0.16 in 1995 to $0.20 in
1996, or $0.17 per Mcfe excluding the $0.8 million buyout of the options issued
under the 1994 Incentive Plan.
Nonrecurring Charge. During 1995, the Company incurred a $12.0 million
nonrecurring charge to reflect the amount of remuneration paid to former
employees of FRI. During 1996 the Company did not incur additional charges
related to the remuneration paid to former FRI employees. See "--General" and
Note 11 to the Company's Combined Financial Statements.
Income Tax Provision. Income tax expense increased from a benefit of
$3.8 million in 1995 to an expense of $2.2 million in 1996. Included in the
provision for 1995 was a credit of $4.2 million related to the $12.0 million
nonrecurring charge. For 1996, the primary difference between the Company's
statutory tax rate of 35% and its effective rate of 20% was due to the
utilization of Section 29 credits received for specific onshore properties.
Net Income. The Company's net income increased from a loss of $0.3
million in 1995 to net income of $8.6 million in 1996. Excluding the effects
of the $12.0 million charge ($7.8 million net of tax), the Company's net income
increased 15% from $7.5 million in 1995 to $8.6 million in 1996. The increase
in net income resulted from increased production from newly developed
properties and production from properties acquired in the TransTexas and Soxco
Acquisitions, combined with an increase in realized natural gas prices. Both
lease operating and general and administrative expenses increased from the
prior year due to certain one-time charges and interest expense reflects third
quarter borrowings, which were repaid with proceeds from the IPO.
-27-
<PAGE> 28
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its operations, acquisitions,
capital expenditures and working capital requirements from cash flows from
operations, bank borrowings and, prior to the IPO, capital contributions from
Brooklyn Union. See also "Risk Factors -- Effects of Leverage."
As of December 31, 1997, the Company had a working capital deficit of
$5.4 million (which includes the accrued liability of $8.8 million for the
Soxco minimum deferred purchase price which is payable in shares of Common
Stock during the first quarter of 1998) and $15.4 million of available
borrowing base under its Credit Facility (defined below). Net cash provided by
operating activities for the year ended December 31, 1997 was $97.3 million
compared to $54.1 million for the year ended December 31, 1996. The Company's
cash position was increased during the year ended December 31, 1997 by
borrowings of $79.0 million under the Company's Credit Facility. Funds used in
investing and financing activities consisted of $145.1 million for investments
in property and equipment and principal payments of $31.0 million on long-term
borrowing under the Credit Facility. As a result of these activities, cash and
cash equivalents increased $1.9 million from $2.8 million at December 31, 1996
to $4.7 million at December 31, 1997.
Over the past three years, the Company has spent $390 million
(including $96.9 million expended on the TransTexas and the Soxco acquisitions)
to add 294 Bcfe of net proved reserves, representing a finding and development
cost of $1.33 per Mcfe. The Company's primary sources of funds for each of the
past three years are reflected in the following table:
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------------------------
1995 1996 1997
(in thousands)
<S> <C> <C> <C>
Net cash provided by operating activities . . . . . . . . . . $ 55,778 $ 54,065 $ 97,292
Net borrowings (repayments) under Credit Facility . . . . . . 6,212 (6,862) 48,000
Proceeds from sale of common stock . . . . . . . . . . . . . -- 101,014 297
Capital contributions from Brooklyn Union . . . . . . . . . . 6,873 6,342 --
</TABLE>
The Company's natural gas and oil capital expenditures for each of the
past three years are reflected in the following table:
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------------------------
1995 1996 1997
(in thousands)
<S> <C> <C> <C>
OFFSHORE:
Acquisitions of properties . . . . . . . . . . . . . . . $ 18,236 $ 58,578 $ 30,700
Development . . . . . . . . . . . . . . . . . . . . . . . 32,228 25,399 19,826
Exploration . . . . . . . . . . . . . . . . . . . . . . . 6,355 27,398 42,219
----------- ----------- -----------
56,819 111,375 92,745
ONSHORE:
Acquisitions of properties . . . . . . . . . . . . . . . $ 2,803 $ 59,513 $ 9,920
Development . . . . . . . . . . . . . . . . . . . . . . . 8,935 5,844 39,418
Exploration . . . . . . . . . . . . . . . . . . . . . . . 869 -- 1,900
----------- ----------- -----------
12,607 65,357 51,238
----------- ----------- -----------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . $ 69,426 $ 176,732 $ 143,983
=========== =========== ===========
</TABLE>
The Company's capital expenditure budget for 1998 of $100 million
includes $68 million and $32 million, respectively, for exploration and
development. These amounts include development costs associated with recently
acquired properties and amounts that are contingent upon drilling success. The
Company will continue to evaluate its capital spending plans through the year.
No significant abandonment or dismantlement costs are anticipated through 1998.
Actual levels of capital expenditures may vary significantly due to a variety
of factors, including drilling results,
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<PAGE> 29
natural gas prices, industry conditions and outlook and future acquisitions of
properties. The Company believes cash flows from operations and borrowings
under its Credit Facility will be sufficient to fund these expenditures. The
Company will continue to selectively seek acquisition opportunities for proved
reserves with substantial exploration and development potential both offshore
and onshore. The size and timing of capital requirements for acquisitions is
inherently unpredictable. The Company expects to fund exploration and
development through a combination of cash flow from operations, borrowings
under its Credit Facility, or the issuance of equity or debt securities.
The Company has entered into the Credit Facility (the "Credit
Facility") with a syndicate of lenders led by Chase Bank of Texas, National
Association ("Chase") which provides a maximum loan amount of $150 million,
subject to borrowing base limitations, on a revolving basis. The Credit
Facility has a current borrowing base of $130 million. At December 31, 1997,
$113 million was borrowed and $1.6 million was committed under outstanding
letter of credit obligations. The Credit Facility matures on July 1, 2000.
Advances under the Credit Facility bear interest, at the Company's election at
(i) a fluctuating rate ("Base Rate") equal to the higher of the Federal Funds
Rate plus 0.5% or Chase's prime rate or (ii) a fixed rate ("Fixed Rate") equal
to a quoted LIBOR rate plus a margin between 0.375% and 1.125% depending on the
amount outstanding under the Credit Facility. Interest is due at calendar
quarters for Base Rate loans and at the earlier of maturity or three months
from the date of the loan for Fixed Rate loans. The Credit Facility contains
covenants of the Company, including certain restrictions on liens and financial
covenants which require the Company to, among other things, maintain (i) an
interest coverage ratio of 2.5 to 1.0 of earnings before interest, taxes and
depreciation to cash interest ("EBIDTA") and (ii) a total debt to
capitalization ratio of less than 60%. The Credit Facility also restricts the
Company's ability to purchase or redeem its capital stock or to pledge its oil
and gas properties or other assets. As of December 31, 1997 the Company was in
compliance with all Credit Facility covenants. The borrowing base under the
Credit Facility is determined by Chase in its discretion in accordance with
Chase's then current standards and practices for similar oil and gas loans
taking into account such factors as Chase deems appropriate.
Pursuant to the Credit Facility, the Company may declare and pay cash
dividends to its stockholders provided that (i) no defaults exist and the
Company will not be in default with respect to any financial covenants as a
result of such dividend payment and (ii) the Company continues to have a ratio
of consolidated total debt to consolidated total capitalization of less than
55%. Accordingly, the Company's ability to pay dividends will depend upon such
restrictions and the Company's results of operations, financial condition,
capital requirements and other factors deemed relevant by the Board of
Directors. See "Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters -- Dividends."
The Company intends to seek additional long-term debt financing during
1998 to supplement the Credit Facility. The Company intends to use the
proceeds from such additional debt financing, if successfully completed, to
repay outstanding indebtedness under the Credit Facility and to fund capital
expenditures, including payment of a portion of the purchase price of the
Pending Acquisition, if completed. No assurances can be made that the Company
will be able to successfully complete any such additional debt financing.
The Company utilizes derivative commodity instruments to hedge future
sales prices on a portion of its natural gas production to achieve a more
predictable cash flow, as well as to reduce its exposure to adverse price
fluctuations of natural gas. While the use of these hedging arrangements
limits the downside risk of adverse price movements, they may limit future
revenues from favorable price movements. The use of hedging transactions also
involves the risk that the counterparties will be unable to meet the financial
terms of such transactions. Hedging instruments used are swaps, collars and
options, and are generally placed with major financial institutions that the
Company believes are minimal credit risks. The Company accounts for these
transactions as hedging activities and, accordingly, gains or losses are
included in natural gas and oil revenues in the period the hedged production
occurs. Unrealized gains and losses on these contracts, if any, are deferred
and offset in the balance sheet against the related settlement amounts.
-29-
<PAGE> 30
As of December 31, 1997, the Company had entered into commodity price
hedging contracts with respect to its gas production as listed below. Natural
gas production during the month of December 1997 was 5,533 MMcfe (5,570
MMMBtu).
<TABLE>
<CAPTION>
Fixed Price Swaps Collars Options
---------------------- ------------------------------- ---------------------------------
NYMEX NYMEX Contract Price NYMEX
Volume Contract Volume -------------------- Volume Strike
Period (MMMbtu) Price (MMMbtu) Floor Ceiling (MMMbtu) Price Put/Call
------ -------- -------- -------- ----- ------- -------- ------ --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
January 1998 355 $2.07 1,860 $2.73 $3.88 155 $2.01 Put
February 1998 340 $2.07 1,120 $2.65 $3.16 140 $2.01 Put
February 1998 560 $3.50 Call
March 1998 355 $2.07 930 $2.25 $2.75 155 $2.01 Put
</TABLE>
As of February 5, 1998, the Company had no commodity hedging contracts
extending beyond March 1998. The Company has entered into basis swaps with
respect to more than 50% of the indicated NYMEX hedged volume.
These hedging transactions are settled based upon the average of the
reported settlement prices on the New York Mercantile Exchange (the "NYMEX")
for the last three trading days of a particular contract month (the "settlement
price"). With respect to any particular swap transaction, the counterparty is
required to make a payment to the Company in the event that the settlement
price for any settlement period is less than the swap price for such
transaction, and the Company is required to make payment to the counterparty in
the event that the settlement price for any settlement period is greater than
the swap price for such transaction. For any particular collar transaction,
the counterparty is required to make a payment to the Company if the settlement
price for any settlement period is below the floor price for such transaction,
and the Company is required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price for such
transaction. For any particular floor transaction, the counterparty is
required to make a payment to the Company if the settlement price for any
settlement period is below the floor price for such transaction. The Company
is not required to make any payment in connection with a floor transaction.
For option contracts, the Company has the option, but not the obligation, to
buy contracts at the strike price up to the day before the last trading day for
that NYMEX contract.
The Company periodically enters into basis swaps (either as part of a
particular hedging transaction or separately) tied to a particular NYMEX-based
transaction to eliminate basis risk. Because substantially all of the
Company's natural gas production is sold under spot contracts, that have
historically correlated with the swap price, the Company believes that it has
no material basis risk with respect to gas swaps that are not coupled with
basis swaps.
For a description of certain bonding requirements related to offshore
production proposed by the Minerals Management Service, see "Items 1 and 2.
Business and Properties -- Environmental Matters."
ITEM 8. FINANCIAL STATEMENTS
The financial statements required by this Item are incorporated under
Item 14 in Part IV of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
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<PAGE> 31
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item as to the directors and
executive officers of the Company is hereby incorporated by reference from the
information appearing under the captions "Election of Directors" and "Executive
Officers" in the Company's definitive proxy statement which involves the
election of directors and is to be filed with the Securities and Exchange
Commission ("Commission") pursuant to the Securities Exchange Act of 1934
within 120 days of the end of the Company's fiscal year on December 31, 1997.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item as to the management of the
Company is hereby incorporated by reference from the information appearing
under the captions "Executive Compensation" and "Election of Directors -
Director's Meetings and Compensation" in the Company's definitive proxy
statement which involves the election of directors and is to be filed with the
Commission pursuant to the Securities Exchange Act of 1934 within 120 days of
the end of the Company's fiscal year on December 31, 1997. Notwithstanding the
foregoing, in accordance with the instructions to Item 402 of Regulation S-K,
the information contained in the Company's proxy statement under the
sub-heading "Report of the Compensation Committee of the Board of Directors"
and "Performance Graph" shall not be deemed to be filed as part of or
incorporated by reference into this Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item as to the ownership by
management and others of securities of the Company is hereby incorporated by
reference from the information appearing under the caption "Security Ownership
of Certain Beneficial Owners and Management" to the Company's definitive proxy
statement which involves the election of directors and is to be filed with the
Commission pursuant to the Securities Exchange Act of 1934 within 120 days of
the end of the Company's fiscal year on December 31, 1997.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item as to certain business
relationships and transactions with management and other related parties of the
Company is hereby incorporated by reference to such information appearing under
the captions "Certain Transactions" and "Executive Compensation--Compensation
Committee Interlocks and Insider Participation" in the Company's definitive
proxy statement which involves the election of directors and is to be filed
with the Commission pursuant to the Securities Exchange Act of 1934 within 120
days of the end of the Company's fiscal year on December 31, 1997.
-31-
<PAGE> 32
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents Filed as a Part of this Report
1. FINANCIAL STATEMENTS:
<TABLE>
<CAPTION>
PAGE
--------------
<S> <C> <C>
Index to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . . F-2
Combined Balance Sheets as of December 31, 1996 and 1997 . . . . . . . . . . . . . . . . F-3
Combined Statements of Operations for the Years Ended December 31, 1995, 1996 and 1997 . F-4
Combined Statement of Stockholders' Equity for the Period from December 31, 1994
to December 31, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5
Combined Statements of Cash Flows for the Years Ended December 31, 1995, 1996 and 1997 . F-6
Notes to Combined Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . F-7 - F-19
Supplemental Information on Natural Gas and Oil Exploration, Development
and Production Activities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-19 - F-22
Quarterly Financial Information (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . F-23
</TABLE>
All other schedules are omitted because they are not applicable, not
required, or because the required information is included in the financial
statements or notes thereto.
2. EXHIBITS:
Exhibits to the Form 10-K have been included only with the copies of
the Form 10-K filed with the Commission and the New York Stock Exchange. Upon
request to the Company and payment of a reasonable fee, copies of the
individual exhibits will be furnished.
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
-------- -----------
<S> <C>
3.1 -- Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 1997 (File No. 001-11899) and
incorporated by reference herein).
3.2 -- Restated Bylaws (filed as Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 1997 (File No. 001-11899) and incorporated by reference
herein).
4.1 -- Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.1 -- Agreement for Filing Consolidated Federal Income Tax Returns and for Allocation of
Consolidated Federal Income Tax Liabilities and Benefits dated September 1, 1994 between
The Brooklyn Union Gas Company and its subsidiaries (filed as Exhibit 10.19 to the
Company's Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated
by reference herein).
10.2 ** -- Employment Agreement dated July 2, 1996 between The Houston Exploration Company and James
G. Floyd (filed as Exhibit 10.8 to the Company's Registration Statement on Form S-1
(Registration No. 333-4437) and incorporated by reference herein).
10.3 ** -- Employment Agreement dated July 2, 1996 between The Houston Exploration Company and Randall
J. Fleming (filed as Exhibit 10.9 to the Company's Registration Statement on Form S-1
(Registration No. 333-4437) and incorporated by reference herein).
10.4 ** -- Employment Agreement dated July 2, 1996 between The Houston Exploration Company and Thomas
W. Powers (filed as Exhibit 10.10 to the Company's Registration Statement on Form S-1
(Registration No. 333-4437) and incorporated by reference herein).
10.5 ** -- Employment Agreement dated July 2, 1996 between The Houston Exploration Company and James
F. Westmoreland (filed as Exhibit 10.11 to the Company's Registration Statement on Form S-1
(Registration No. 333-4437) and incorporated by reference herein).
</TABLE>
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<PAGE> 33
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
-------- -----------
<S> <C>
10.6 ** -- 1996 Stock Option Plan (filed as Exhibit 10.12 to the Company's Registration Statement on
Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.7 -- Registration Rights Agreement dated as of July 2, 1996 between The Houston Exploration
Company and THEC Holdings Corp. (filed as Exhibit 10.13 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.8 -- Asset Purchase Agreement dated as of July 1, 1996 between The Houston Exploration Company
and Smith Offshore Exploration Company (filed as Exhibit 10.14 to the Company's
Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by
reference herein).
10.9 -- Registration Rights Agreement between The Houston Exploration Company and Smith Offshore
Exploration Company (filed as Exhibit 10.15 to the Company's Registration Statement on Form
S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.10 -- Credit Agreement dated as of July 2, 1996 among The Houston Exploration Company and Texas
Commerce Bank National Association, as Agent, and the other Banks signatory thereto (filed
as Exhibit 10.16 to the Company's Registration Statement on Form S-1 (Registration No. 333-
4437) and incorporated by reference herein).
* 10.11 -- First Amendment, dated August 30, 1996, to the Credit Agreement among The Houston
Exploration Company and Texas Commerce Bank National Association, as Agent, and the other
Banks signatory thereto.
10.12 -- Second Amendment, dated August 4, 1997, to the Credit Agreement among The Houston
Exploration Company and Texas Commerce Bank National Association, as Agent, and the other
Banks signatory thereto (filed as Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the quarterly period ended September 30, 1997 (File No. 001-11899) and incorporated
by reference herein).
10.13 -- Purchase and Sale Agreement dated as of June 21, 1996, among The Houston Exploration
Company, TransTexas Gas Corporation and TransTexas Transmission Corporation (filed as
Exhibit 10.17 to the Company's Registration Statement on Form S-1 (Registration No. 333-
4437) and incorporated by reference herein).
10.14 -- Gas Exchange Agreement dated as of July 2, 1996 between The Houston Exploration Company and
TransTexas Gas Corporation (filed as Exhibit 10.18 to the Company's Registration Statement
on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.15 -- Indemnification Agreement dated as of September 25, 1996 between The Houston Exploration
Company and THEC Holdings Corp. (filed as Exhibit 10.20 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.16 -- Contribution Agreement dated as of February 26, 1996 between The Houston Exploration
Company and Fuel Resources Inc. (filed as Exhibit 10.21 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.17 ** -- Registration Rights Agreement dated as of September 25, 1996 between The Houston
Exploration Company and James G. Floyd (filed as Exhibit 10.22 to the Company's
Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by
reference herein).
10.18 ** -- Supplemental Executive Pension Plan (filed as Exhibit 10.23 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.19 ** -- Deed of Trust, Assignment of Production, Security Agreement and Financing Statement between
The Houston Exploration Company and James G. Floyd (filed as Exhibit 10.24 to the Company's
Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by
reference herein).
10.20 ** -- Contribution Agreement between James G. Floyd and The Houston Exploration Company (filed as
Exhibit 10.25 to the Company's Registration Statement on Form S-1 (Registration No. 333-
4437) and incorporated by reference herein).
10.21 ** -- Employment Agreement, dated September 19, 1996, between The Houston Exploration Company and
Charles W. Adcock (filed as Exhibit 10.26 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1996 (File No. 001-11899) and incorporated by reference herein).
</TABLE>
-33-
<PAGE> 34
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
-------- -----------
<S> <C>
10.22 ** -- Form of Letter Agreement from The Houston Exploration Company to each of James G. Floyd,
Randall J. Fleming, Thomas W. Powers, Charles W. Adcock, James F. Westmoreland and
Sammye L. Dees evidencing grants of Phantom Stock Rights effective as of December 16, 1996
(filed as Exhibit 10.27 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1996 (File No. 001-11899) and incorporated by reference herein).
10.23 ** -- Purchase and Sale Agreement, dated January 1, 1997, between The Houston Exploration Company
and KeySpan Natural Fuel, LLC (filed as Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 1997 (File No. 001-11899) and incorporated
by reference herein).
* 10.24 ** -- Deferred Compensation Plan for Non-Employee Directors.
* 21.1 -- Subsidiaries of the Company.
* 23.1 -- Consent of Arthur Andersen LLP.
* 27.1 -- Financial Data Schedule.
</TABLE>
- -------------
* Filed herewith.
** Management contract or compensation plan.
(b) Reports on Form 8-K:
None
-34-
<PAGE> 35
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.
THE HOUSTON EXPLORATION COMPANY
By: /s/ James G. Floyd
-----------------------------------------
James G. Floyd
Date: February 6, 1997 President 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 in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ JAMES G. FLOYD President, Chief Executive Officer February 6, 1997
- ---------------------------------- and Director (Principal Executive
James G. Floyd Officer)
/s/ JAMES F. WESTMORELAND Vice President, Chief Accounting February 6, 1997
- ---------------------------------- Officer, Comptroller and Secretary
James F. Westmoreland (Principal Financial Officer and
Principal Accounting Officer)
/s/ ROBERT B. CATELL Chairman of the Board of Directors February 6,1997
- ----------------------------------
Robert B. Catell
/s/ GORDON F. AHALT Director February 6, 1997
- ----------------------------------
Gordon F. Ahalt
/s/ RUSSELL D. GORDY Director February 6, 1997
- ----------------------------------
Russell D. Gordy
/s/ CRAIG G. MATTHEWS Director February 6, 1997
- ----------------------------------
Craig G. Matthews
/s/ JAMES Q. RIORDAN Director February 6, 1997
- ----------------------------------
James Q. Riordan
/s/ LESTER H. SMITH Director February 6, 1997
- ----------------------------------
Lester H. Smith
/s/ DONALD C. VAUGHN Director February 6, 1997
- ---------------------------------
Donald C. Vaughn
</TABLE>
-35-
<PAGE> 36
GLOSSARY OF OIL AND GAS TERMS
The definitions set forth below shall apply to the indicated terms as
used in this Annual Report on Form 10-K. All volumes of natural gas referred
to herein are stated at the legal pressure base of the state or area where the
reserves exist and at 60 degrees Fahrenheit and in most instances are rounded
to the nearest major multiple.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
Bbl/d. One barrel per day.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the
production of oil or gas, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
Developed acreage. The number of acres which are allocated or
assignable to producing wells or wells capable of production.
Developed well. A well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or gas
reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of oil or gas in another reservoir or to
extend a known reservoir.
Farm-in or farm-out. An agreement whereunder the owner of a working
interest in an natural gas and oil lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."
Field. An area consisting of a single reservoir or multiple
reservoirs all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid
hydrocarbons.
MBbls/d. One thousand barrels of crude oil or other liquid
hydrocarbons per day.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
G-1
<PAGE> 37
Mcfe. One thousand cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
Mcfe/d. One thousand cubic feet equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids per day.
MMBbls. One million barrels of crude oil or other liquid
hydrocarbons.
MMbtu. One million Btus.
MMMbtu. One billion Btus.
MMcf. One million cubic feet.
MMcf/d. One million cubic feet per day.
MMcfe. One million cubic feet equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
Net acres or net wells. The sum of the fractional working interests
owned in gross acres or gross wells.
Oil. Crude oil and condensate.
Present value. When used with respect to natural gas and oil
reserves, the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date indicated,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expenses or to
depreciation, depletion and amortization, discounted using an annual discount
rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed producing reserves. Proved developed reserves that
are expected to be recovered from completion intervals currently open in
existing wells and able to produce to market.
Proved developed nonproducing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.
Proved reserves. The estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can
be drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required from recompletion.
Recompletion. The completion for production of an existing well bore
in another formation from that in which the well has been previously completed.
G-2
<PAGE> 38
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in a natural gas and oil property
entitling the owner to a share of oil or gas production free of costs of
production.
Undeveloped acreage. Lease acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage contains
proved reserves.
Working interest. The operating interest which gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.
Workover. Operations on a producing well to restore or increase
production.
G-3
<PAGE> 39
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants.................... F-2
Combined Balance Sheets as of December 31, 1996 and 1997.... F-3
Combined Statements of Operations for the Years Ended
December 31, 1995, 1996 and 1997.......................... F-4
Combined Statement of Stockholders' Equity for the Years
Ended December 31, 1995, 1996 and 1997.................... F-5
Combined Statements of Cash Flows for the Years Ended
December 31, 1995, 1996 and 1997.......................... F-6
Notes to Combined Financial Statements...................... F-7
</TABLE>
F-1
<PAGE> 40
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited the accompanying combined balance sheets of The Houston
Exploration Company (a Delaware corporation and an indirect 65%-owned subsidiary
of KeySpan Energy Corporation) as of December 31, 1996 and 1997, and the related
combined statements of operations, stockholders' equity and cash flows for each
of the three years in the period ended December 31, 1997. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the financial position of The Houston
Exploration Company, as of December 31, 1996 and 1997, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York
January 27, 1998
F-2
<PAGE> 41
THE HOUSTON EXPLORATION COMPANY
COMBINED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1996 1997
(IN THOUSANDS)
<S> <C> <C>
ASSETS:
Cash and cash equivalents................................... $ 2,851 $ 4,745
Accounts receivable......................................... 35,845 37,898
Accounts receivable -- Brooklyn Union....................... -- 1,303
Inventories................................................. 992 1,265
Prepayments and other....................................... 924 645
-------- --------
Total current assets.............................. 40,612 45,856
Natural gas and oil properties, full cost method
Unevaluated properties.................................... 60,258 104,075
Properties subject to amortization........................ 468,062 566,868
Other property and equipment................................ 7,308 9,341
-------- --------
535,628 680,284
Less: Accumulated depreciation, depletion and
amortization.............................................. (176,504) (236,546)
-------- --------
359,124 443,738
Other assets................................................ 1,549 1,797
-------- --------
TOTAL ASSETS...................................... $401,285 $491,391
======== ========
LIABILITIES:
Accounts payable and accrued expenses....................... $ 36,650 $ 42,432
Accounts payable -- Brooklyn Union.......................... 1,010 --
Deferred stock obligation................................... -- 8,825
-------- --------
Total current liabilities......................... 37,660 51,257
Long-term debt.............................................. 65,000 113,000
Deferred federal income taxes............................... 56,475 70,741
Other deferred liabilities.................................. 8,850 206
-------- --------
TOTAL LIABILITIES................................. 167,985 235,204
COMMITMENTS AND CONTINGENCIES (SEE NOTE 10)
STOCKHOLDERS' EQUITY:
Common Stock, $.01 par value, 50,000 shares authorized and
23,333
shares issued and outstanding at December 31, 1996 and
23,361
shares issued and outstanding at December 31, 1997..... 233 234
Additional paid-in capital................................ 222,271 221,907
Retained earnings......................................... 10,796 34,046
-------- --------
TOTAL STOCKHOLDERS' EQUITY........................ 233,300 256,187
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY........ $401,285 $491,391
======== ========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
F-3
<PAGE> 42
THE HOUSTON EXPLORATION COMPANY
COMBINED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------
1995 1996 1997
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
REVENUES:
Natural gas and oil revenues.............................. $39,431 $64,864 $116,349
Other..................................................... 1,778 1,040 1,297
------- ------- --------
Total revenues.................................... 41,209 65,904 117,646
OPERATING COSTS AND EXPENSES:
Lease operating........................................... 5,005 10,800 14,146
Severance tax............................................. 463 1,401 4,233
Depreciation, depletion and amortization.................. 21,969 33,732 59,081
General and administrative, net........................... 3,486 6,249 5,825
Nonrecurring charge....................................... 12,000 -- --
------- ------- --------
Total operating expenses.......................... 42,923 52,182 83,285
INCOME (LOSS) FROM OPERATIONS............................... (1,714) 13,722 34,361
Interest expense, net....................................... 2,398 2,875 938
------- ------- --------
Net income (loss) before income taxes....................... (4,112) 10,847 33,423
Provision (benefit) for federal income taxes................ (3,809) 2,205 10,173
------- ------- --------
NET INCOME (LOSS)........................................... $ (303) $ 8,642 $ 23,250
======= ======= ========
Net income (loss) per share................................. $ (0.02) $ 0.49 $ 1.00
======= ======= ========
Net income (loss) per share -- assuming dilution............ $ (0.02) $ 0.49 $ 0.97
======= ======= ========
Weighted average shares outstanding......................... 15,295 17,532 23,337
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
F-4
<PAGE> 43
THE HOUSTON EXPLORATION COMPANY
COMBINED STATEMENT OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
ADDITIONAL TOTAL
COMMON PAID IN RETAINED STOCKHOLDERS'
STOCK CAPITAL EARNINGS EQUITY
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Balance at December 31, 1994....................... $153 $ 86,256 $ 2,457 $ 88,866
Capital contributions from Brooklyn Union(1)..... -- 14,673 -- 14,673
Net loss......................................... -- -- (303) (303)
---- -------- ------- --------
Balance at December 31, 1995....................... $153 $100,929 $ 2,154 $103,236
Capital contributions from Brooklyn Union........ -- 6,342 -- 6,342
8,037 shares of common stock at $15.50(2)........ 80 115,000 -- 115,080
Net income....................................... -- -- 8,642 8,642
---- -------- ------- --------
Balance at December 31, 1996....................... $233 $222,271 $10,796 $233,300
Other(3)......................................... -- (660) -- (660)
28 shares of common stock at $15.50(4)........... 1 296 -- 297
Net income....................................... -- -- 23,250 23,250
---- -------- ------- --------
Balance at December 31, 1997....................... $234 $221,907 $34,046 $256,187
==== ======== ======= ========
</TABLE>
- ---------------
(1) Includes $7.8 million related to the $12.0 million nonrecurring charge, net
of the tax benefit of $4.2 million.
(2) See Note 3 -- Stockholders' Equity.
(3) Non-cash charge relating to the February 1996 Reorganization.
(4) See Note 4 -- Incentive Stock Option Plan.
The accompanying notes are an integral part of these combined financial
statements.
F-5
<PAGE> 44
THE HOUSTON EXPLORATION COMPANY
COMBINED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss)....................................... $ (303) $ 8,642 $ 23,250
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization.............. 21,969 33,732 59,081
Deferred income tax expense........................... 9,632 11,939 13,601
Nonrecurring charge................................... 12,000 -- --
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable......... 977 (10,348) (3,356)
Decrease (increase) in inventories................. 333 217 (273)
Decrease (increase) in prepayments and other....... 416 (29) 279
Decrease (increase) in other assets and
liabilities...................................... 864 909 (62)
Increase in accounts payable and accrued
expenses......................................... 9,890 9,003 4,772
--------- --------- ---------
Net cash provided by operating activities............... 55,778 54,065 97,292
INVESTING ACTIVITIES:
Investment in property and equipment.................... (70,249) (154,125) (145,055)
Dispositions and other.................................. 1,316 1,819 1,360
--------- --------- ---------
Net cash used in investing activities................... (68,933) (152,306) (143,695)
FINANCING ACTIVITIES:
Proceeds from long term borrowings...................... 6,212 76,838 79,000
Repayments of long term borrowings...................... -- (83,700) (31,000)
Proceeds from issuance of common stock, net of offering
costs................................................. -- 101,014 297
Capital contributions from Brooklyn Union............... 6,873 6,342 --
--------- --------- ---------
Net cash provided by financing activities............... 13,085 100,494 48,297
Increase (decrease) in cash and cash equivalents........ (70) 2,253 1,894
Cash and cash equivalents, beginning of period.......... 668 598 2,851
--------- --------- ---------
Cash and cash equivalents, end of period................ $ 598 $ 2,851 $ 4,745
========= ========= =========
Cash paid for interest.................................. $ 4,658 $ 5,708 $ 6,001
========= ========= =========
Cash paid for taxes..................................... $ -- $ -- $ --
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
F-6
<PAGE> 45
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
The Houston Exploration Company ("Houston Exploration" or the "Company"), a
Delaware corporation, was incorporated in December 1985 and began operations in
January 1986 for the purpose of conducting certain natural gas and oil
exploration and development activities for The Brooklyn Union Gas Company
("Brooklyn Union"). Effective September 29, 1997, Brooklyn Union became a
wholly-owned subsidiary of KeySpan Energy Corporation, ("KeySpan"). Prior to the
Company's initial public offering in September 1996 (the "IPO"), the Company was
an indirect wholly-owned subsidiary of Brooklyn Union. Subsequent to the IPO,
Brooklyn Union holds 65% of the Company's outstanding common stock. The
Company's operations focus on the exploration, development and acquisition of
domestic natural gas and oil properties offshore in the Gulf of Mexico and
onshore in South Texas, the Arkoma Basin, East Texas and West Virginia.
Effective February 29, 1996 Brooklyn Union implemented a reorganization of
its exploration and production assets and liabilities by transferring to Houston
Exploration certain onshore producing properties and acreage formerly owned by
Fuel Resources Inc. ("FRI"), another subsidiary of Brooklyn Union. These
combined financial statements have been prepared giving effect to the transfer
of these assets and liabilities from the time of the acquisition of such assets
and liabilities by Brooklyn Union. The transfer of assets and liabilities has
been accounted for at historical cost as a reorganization of companies under
common control in a manner similar to a pooling-of-interests and the 1995
financial statements reflect the combined historical results of Houston
Exploration and the assets and liabilities transferred by Brooklyn Union.
Net Income (Loss) Per Share
In February 1997, the Financial Accounting Standards Board (the "FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings
Per Share." The statement specifies the computation, presentation, and
disclosure requirements for earnings per share ("EPS") and is designed to
improve the EPS information provided in the financial statements by simplifying
the existing computation. Primary EPS has been replaced with Basic EPS which is
calculated by dividing net income by the weighted average number of shares of
common stock outstanding during the year. No dilution for any potentially
dilutive securities is included. Fully diluted EPS is now called Diluted EPS and
assumes the conversion of all potentially dilutive securities. The Company
adopted SFAS No. 128 in its December 31, 1997 financial statements and has
presented Diluted EPS for the years 1996 and 1995 which were previously not
required as the dilutive effect of options and contingent shares was less than
3%. As of December 31, 1997, the Company had 2,333,276 options authorized, of
which 1,640,098 were outstanding, and had an estimated 521,509 contingent shares
of common stock payable to Soxco pursuant to the accrued minimum purchase price
of $8.8 million (see Note 12 -- Acquisitions).
F-7
<PAGE> 46
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Under the requirements of SFAS No. 128, the Company's EPS are as follows:
<TABLE>
<CAPTION>
1995 1996 1997
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Net income (loss)........................................... $ (303) $ 8,642 $23,250
Denominator:
Weighted average shares outstanding......................... 15,295 17,532 23,337
Add: dilutive securities
Options................................................... -- 27 153
Contingent shares......................................... -- 128 538
------- ------- -------
Total weighted average shares outstanding and dilutive
securities................................................ 15,295 17,687 24,028
======= ======= =======
Net income (loss) per share................................. $ (0.02) $ 0.49 $ 1.00
Net income (loss) per share -- assuming dilution............ $ (0.02) $ 0.49 $ 0.97
</TABLE>
Reclassifications and Use of Estimates
The preparation of the combined financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the dates of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. The Company's most significant financial estimates are based
on remaining proved natural gas and oil reserves. See Note 14 -- Supplemental
Information on Natural Gas and Oil Exploration, Development and Production
Activities. Because there are numerous uncertainties inherent in the estimation
process, actual results could differ from the estimates. Certain
reclassifications for prior years have been made to conform with current year
presentation.
Natural Gas and Oil Properties
Natural gas and oil properties are accounted for using the full cost method
of accounting. Under this method of accounting, all costs identified with
acquisition, exploration and development of natural gas and oil properties,
including leasehold acquisition costs, geological and geophysical costs, dry
hole costs, tangible and intangible drilling costs, interest and the general and
administrative overhead directly associated with these activities are
capitalized as incurred. The Company computes the provision for depreciation,
depletion and amortization of natural gas and oil properties on a quarterly
basis using the unit-of-production method. The quarterly provision is calculated
by multiplying the natural gas and oil production each quarter by a depletion
rate determined by dividing the total unamortized cost of natural gas and oil
properties (including estimates of the costs of future development and property
abandonment and excluding the cost of significant investments in unproved and
unevaluated properties) by net equivalent proved reserves at the beginning of
the quarter. Natural gas and oil reserve quantities represent estimates only.
Actual future production may be materially different from estimated reserve
quantities and such differences could materially affect future amortization of
natural gas and oil properties. The Company believes that unevaluated properties
at December 31, 1997 will be fully evaluated within five years.
Proceeds from the dispositions of natural gas and oil properties are
recorded as reductions of capitalized costs, with no gain or loss recognized,
unless such adjustments significantly alter the relationship of unamortized
capitalized costs and total proved reserves.
The Company limits the capitalized costs of natural gas and oil properties,
net of accumulated depreciation, depletion and amortization and related deferred
taxes to the estimated future net cash flows from proved natural gas and oil
reserves discounted at ten percent, plus the lower of cost or fair value of
unproved properties, as adjusted for related income tax effects (the "full cost
ceiling"). A current period charge to operating income is required to the extent
that capitalized costs plus certain estimated costs for future property
F-8
<PAGE> 47
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
development, plugging, abandonment and site restorations, net of related
accumulated depreciation, depletion and amortization and related deferred income
taxes, exceed the full cost ceiling.
Other Property and Equipment
Other property and equipment include the costs of West Virginia gathering
facilities which are depreciated using the unit-of-production basis utilizing
estimated proved reserves accessible to the facilities. Also included in other
property and equipment are costs of office furniture, fixtures and equipment
which are recorded at cost and depreciated using the straight-line method over
estimated useful lives ranging between two to five years.
Income Taxes
Deferred taxes are determined based on the estimated future tax effect of
differences between the financial statement and tax basis of assets and
liabilities given the provisions of enacted tax laws. These differences relate
primarily to (i) intangible drilling and development costs associated with
natural gas and oil properties, which are capitalized and amortized for
financial reporting purposes and expensed as incurred for tax reporting purposes
and (ii) provisions for depreciation and amortization for financial reporting
purposes that differ from those used for income tax reporting purposes.
Prior to September 30, 1996, the Company was included in the consolidated
federal income tax return of Brooklyn Union. Under the Company's tax sharing
agreement with Brooklyn Union, the Company received or paid to Brooklyn Union an
amount equal to the reduction or increase in the currently payable federal
income taxes for Brooklyn Union resulting from the inclusion of the Company's
taxable income or loss in the consolidated Brooklyn Union return, whether or not
such amounts could be utilized on a separate return basis. For periods
subsequent to September 1996, the Company is no longer included in the
consolidated federal income tax return of Brooklyn Union and therefore
calculates taxes on a separate return basis.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
Inventories
Inventories consist primarily of tubular goods used in the Company's
operations and are stated at the lower of cost or market value.
General and Administrative Costs and Expenses
The Company receives reimbursement for administrative and overhead expenses
incurred on behalf of other working interest owners of properties operated by
the Company. These reimbursements totaling $1.2 million, $1.0 million and $0.9
million for the years ended December 31, 1995, 1996 and 1997, respectively, were
allocated as reductions to general and administrative expenses. The capitalized
general and administrative costs directly related to the Company's acquisition,
exploration and development activities, during 1995, 1996 and 1997, aggregated
$4.1 million, $5.3 million and $7.2 million, respectively.
Capitalization of Interest
The Company capitalizes interest related to its unevaluated natural gas and
oil properties and certain properties under development which are not currently
being amortized. For the years ended December 31, 1995, 1996 and 1997 interest
costs of $2.9 million, $3.5 million and $5.9 million, respectively, were
capitalized.
F-9
<PAGE> 48
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Gas Imbalances
The Company utilizes the entitlements method to account for its gas
imbalances. Under this method, income is recorded based on the Company's net
revenue interest in production or nominated deliveries. Net deliveries in excess
of these amounts are recorded as liabilities, while net under deliveries are
reflected as assets. Production imbalances are valued using current market
prices. Production imbalances were not material as of December 31, 1996 and
1997.
Hedging
The Company utilizes derivative commodity instruments to hedge future sales
prices on a portion of its natural gas production in order to achieve a more
predictable cash flow and to reduce its exposure to adverse price fluctuations.
These instruments include swaps, costless collars and options, and are usually
placed with major financial institutions that the Company believes are minimal
credit risks. The Company's hedging strategies meet the criteria for hedge
accounting treatment under Statement of Financial Accounting Standards No. 80,
"Accounting for Futures Contracts" ("SFAS 80"). Accordingly, gains and losses
are recognized when the underlying transaction is completed, at which time these
gains and losses are included in earnings as a component of natural gas revenues
in accordance with a hedged transaction. Natural gas revenues were increased by
$5.6 million in 1995, and were reduced by $11.1 million and $9.9 million during
1996 and 1997, relative to these contracts. See Note 8 -- Financial Instruments.
The Company regularly assesses the relationship between natural gas
commodity prices in the "cash" and futures markets. The correlation between
prices in these markets has been well within a range generally deemed to be
acceptable. If correlation ceases to exist for more than a temporary period of
time, the Company accounts for its financial instrument positions as trading
activities and marks-to-market its open positions.
The Company also uses interest rate swaps to manage the interest rate
exposure arising from certain borrowings. Swaps used to hedge debt are
designated as hedges and are matched to the debt as to notional amount and
maturity. The periodic receipts or payments from each swap are recognized
ratably over the term of the swap as an adjustment to interest expense. Gains
and losses resulting from the termination of hedge contracts prior to their
stated maturity are recognized ratably over the remaining life of the instrument
being hedged.
Concentration of Credit Risk
Substantially all of the Company's accounts receivable result from natural
gas and oil sales or joint interest billings to third parties in the oil and gas
industry. This concentration of customers and joint interest owners may impact
the Company's overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. Historically the Company
has not experienced credit losses on such receivables.
New Accounting Pronouncements
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which is effective for years beginning after December 15, 1995.
This statement encourages, but does not require companies to record compensation
expense for stockbased compensation at fair value. The Company has chosen to
continue to account for stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board Opinion ("APB") No. 25,
"Accounting for Stock Issued to Employees," and related Interpretations. Under
APB No. 25, compensation expense is measured as the excess, if any, of the fair
market value of the Company's stock at the date of grant over the price at which
the option was granted. Compensation expense for phantom stock rights is
recorded annually based on the quoted market price of the Company's stock at the
end of the period. See Note 4 -- Incentive Stock Option Plans.
F-10
<PAGE> 49
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
In February 1997, the FASB issued SFAS No. 129, "Disclosure of Information
About Capital Structure," which consolidates the existing requirements to
disclose certain information about an entity's capital structure, for both
public and nonpublic entities. In June 1997, the FASB issued SFAS No. 130,
"Reporting Comprehensive Income," which establishes standards for reporting and
display of comprehensive income and its components. Also issued in June of 1997
was SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information," which specifies and revises guidelines for determining an entity's
operating and geographic segments and the type and level of financial
information about those segments to be disclosed. The Company has adopted the
provisions of SFAS Nos. 129, 130 and 131 in its 1997 financial statements. The
adoption of SFAS Nos. 129, 130 and 131 did not have an effect on results of
operations or the calculation of net income.
NOTE 2 -- LONG-TERM DEBT
Credit Facility. On July 2, 1996, the Company entered into a revolving
credit facility ("Credit Facility") with a syndicate of lenders led by Chase
Bank of Texas, National Association ("Chase"), which provides an aggregate
commitment of $150 million, subject to borrowing base limitations, of which $130
million was the available borrowing base at December 31, 1997. In addition, up
to $5 million of the Credit Facility is available for the issuance of letters of
credit to support performance guarantees. The Credit Facility matures on July 1,
2000 and is unsecured. At December 31, 1997, $113 million was outstanding under
the Credit Facility and $1.6 million was outstanding in letter of credit
obligations.
Interest is payable on borrowings under the Credit Facility, at the
Company's option, at an alternate base rate of the greater of the Federal Funds
rate plus 0.5% or Chase's prime rate or at a margin of 0.375% to 1.125% above a
quoted LIBOR rate. Interest is payable at calendar quarters on base rate loans
and at maturity on LIBOR loans. In addition, a commitment fee of: (i) between
0.20% and 0.375% per annum on the unused portion of the Designated Borrowing
Base, and (ii) 33% of the fee in (i) above on the difference between the lower
of the Facility Amount or the Borrowing Base and the Designated Borrowing Base.
The weighted average interest rate was 6.9%, 6.25% and 6.9%, respectively, for
the years ended December 31, 1995, 1996 and 1997.
The Credit Facility, as amended, contains covenants of the Company,
including certain restrictions on liens and financial covenants which require
the Company to, among other things, maintain (i) an interest coverage ratio of
2.5 to 1.0 of earnings before interest, taxes and depreciation ("EBITDA") to
cash interest and (ii) a total debt to capitalization ratio of less than 60%. In
addition to maintenance of certain financial ratios, cash dividends and/or
purchase or redemption of the Company's stock is restricted as well as the
encumbering of the Company's gas and oil assets or the pledging of the assets as
collateral. As of December 31, 1997, the Company was in compliance with all such
covenants.
NOTE 3 -- STOCKHOLDERS' EQUITY
On September 19, 1996, the Company entered into an underwriting agreement
with respect to the Company's IPO of its common stock at a price of $15.50 per
share. The initial closing of the IPO, in which the Company issued 6,200,000
shares of common stock, was completed on September 25, 1996. The underwriters
delivered notice of the exercise of their over-allotment option on September 30,
1996. The closing of the over-allotment, in which the Company issued an
additional 930,000 shares of common stock, was completed on October 3, 1996. The
Company received net proceeds of approximately $101.0 million from the total of
7,130,000 shares sold in the IPO.
Concurrently with the completion of the IPO, the Company's President
exchanged certain of his after program-payout working interests valued at $2.3
million for 145,161 shares of common stock. In addition, concurrently with the
completion of the IPO, the Company issued 762,387 shares of common stock valued
at $11.8 million to Soxco in connection with the Soxco Acquisition. See Note
12 -- Acquisitions.
F-11
<PAGE> 50
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- INCENTIVE STOCK OPTION PLANS
1994 Incentive Plan
On July 1, 1994, the Company adopted the Long-Term Stock Incentive Plan
(the "1994 Incentive Plan"), and granted options to purchase 247,000 shares of
common stock at $11.22 per share to certain officers and directors of Brooklyn
Union. Options under the 1994 Incentive Plan were nonqualified and had tandem
phantom option shares that gave the option holder the right to receive a cash
payment five years from the grant date provided the Company was a privately held
entity. At completion of the Company's IPO on September 20, 1996, all options
under the 1994 Incentive Plan were canceled in exchange for a cash payment by
the Company of $840,000. The Company recorded the $840,000 charge as
compensation expense.
1996 Incentive Plan
At the completion of the IPO, the Company adopted the 1996 Stock Option
Plan (the "1996 Incentive Plan"), which allows the Company to grant options not
to exceed 10% of the shares of the Company's common stock outstanding from time
to time. On September 20, 1996, the Company authorized 2,333,276 options and
subsequently granted 1,697,238 options. The options granted under the 1996
Incentive Plan expire 10 years from the grant date and vest in one-fifth
increments on each of the first five anniversaries of the grant date. During
1997, employees of the Company exercised 28,140 options at a weighted average
price of $15.50. As of December 31, 1997, 266,188 options were vested and
exercisable. No options were exercisable at December 31, 1996.
During 1997, the 1996 Incentive Plan was amended to allow option grants to
non-employee directors of the Company. Options granted to non-employee directors
vest on the date of grant. During 1997 the Company granted 49,000 options to
non-employee directors at a grant price of $20.813.
Under the 1996 Incentive Plan, 1,048,770 of the options granted are
incentive stock options ("ISOs") and the balance, 648,468 are nonqualified stock
options ("NQSOs"). Common stock issued through the exercise of nonqualified
options will result in a tax deduction for the Company equivalent to the taxable
gain recognized by the optionee. Generally, the Company will not receive an
income tax deduction for ISOs.
The following is a summary of option activity during the years ended
December 31, 1995, 1996 and 1997:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------
1995 1996 1997
----------------- ------------------- -------------------
SHARES PRICE* SHARES PRICE* SHARES PRICE*
<S> <C> <C> <C> <C> <C> <C>
Options at beginning of
year....................... 247,000 $11.22 247,000 $11.22 1,239,638 $15.53
Granted.................... -- 1,239,638 15.53 457,600 19.68
Exercised.................. -- -- (28,140) 15.50
Forfeited.................. -- -- (29,000) 15.50
Canceled................... -- (247,000) 11.22 --
------- --------- ---------
Outstanding at end of year... 247,000 $11.22 1,239,638 $15.53 1,640,098 $16.69
------- --------- ---------
Exercisable at end of year... 247,000 $11.22 -- 266,188
Options available for
grant...................... -- 1,093,638 665,038
Weighted average fair value
of options granted......... $ 7.17 $ 7.60
</TABLE>
- ---------------
* Weighted average exercise price for the year.
F-12
<PAGE> 51
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Phantom Stock Rights
On December 16, 1996, the Company granted key employees of Houston
Exploration 176,470 phantom stock rights ("PSRs") that give the holder the right
to receive a cash payment determined by reference to the fair market value of
one share of the Company's common stock. Twenty percent (20%) of the PSRs are
payable on December 16th of each of the years 1997 through 2001. On each date on
which a PSR is payable, the holder will receive a cash payment equal to (i) the
average of the closing prices per share of the Company's common stock for the
five trading days immediately preceding such payment date multiplied by (ii) the
number of PSRs payable on such date. During 1997, the Company made payments of
$0.8 million for the vested portion of PSRs.
Effective October 1, 1997, the Company adopted an incentive compensation
plan for non-employee, non-affiliated directors under which they may defer
current compensation in the form of phantom stock rights that are tied to the
market price of the Common Stock on the date services are performed. Phantom
stock rights are exchanged for a cash distribution upon retirement.
Fair Value of Employee Stock-Based Compensation
The Company accounts for the Incentive Stock Plans using the intrinsic
value method prescribed under APB No. 25 and accordingly no compensation expense
has been recognized for stock options granted. Had stock options been accounted
for using the fair value method as recommended in SFAS No. 123, compensation
expense would have had the following pro forma effect on the Company's net
income and earnings per share for the years ended December 31, 1995, 1996 and
1997:
<TABLE>
<CAPTION>
1995 1996 1997
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Net income (loss) -- as reported.................... $ (303) $8,642 $23,250
Net income (loss) -- pro forma...................... (303) 8,268 21,499
Net income (loss) per share -- as reported.......... $(0.02) $ 0.49 $ 1.00
Net income (loss) per share -- pro forma............ (0.02) 0.47 0.92
Net income (loss) per share -- pro forma -- assuming
dilution.......................................... (0.02) 0.47 0.89
</TABLE>
The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to awards prior to
1995. The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used
for grants in 1996 and 1997: (i) risk-free interest rate of 6.66% in 1996 and
6.30% in 1997; (ii) expected lives of 5 years; (iii) expected dividends of zero;
and (iv) expected volatility of 41%.
NOTE 5 -- INCOME TAXES
The components of the federal income tax provision (benefit) are:
<TABLE>
<CAPTION>
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
Current.............................................. $(13,441) $(9,734) $(3,428)
Deferred............................................. 9,632 11,939 13,601
-------- ------- -------
Total...................................... $ (3,809) $ 2,205 $10,173
======== ======= =======
</TABLE>
The credit in the current provision for 1997 includes (i) proceeds of $1.2
million received in connection with the sale of Section 29 tax credits to
Brooklyn Union during the first quarter of 1997 (see Note 6 --
F-13
<PAGE> 52
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Related Party Transactions) and (ii) an adjustment to the 1996 tax return.
Amounts received from Brooklyn Union pursuant to the previous tax-sharing
agreement were $14.6 million and $13.7 million in 1995 and 1996, respectively.
No amounts were received in 1997, as effective September 30, 1996, the Company
became a stand alone tax entity and is no longer consolidated with Brooklyn
Union.
The following is a reconciliation of statutory federal income tax expense
(benefit) to the Company's income tax provision:
<TABLE>
<CAPTION>
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
Income (loss) before income taxes..................... $(4,112) $10,847 $33,423
Statutory rate........................................ 35% 35% 35%
Income tax expense (benefit) computed at statutory
rate................................................ (1,439) 3,796 11,698
Reconciling items:
Section 29 tax credits........................... (1,985) (1,401) (1,200)
Percentage depletion............................. (231) (33) (14)
Other............................................ (154) (157) (311)
------- ------- -------
Tax expense (benefit)................................. $(3,809) $ 2,205 $10,173
======= ======= =======
</TABLE>
Deferred Income Taxes
The components of deferred tax assets and liabilities pursuant to SFAS No.
109 for the years ended December 31, 1996 and 1997 primarily represent temporary
differences related to natural gas and oil properties.
NOTE 6 -- RELATED PARTY TRANSACTIONS
Sale of Section 29 Tax Credits
Effective January 1, 1997, the Company entered into an agreement to sell to
a subsidiary of Brooklyn Union certain interests in onshore producing wells of
the Company that produce from formations that qualify for tax credits under
Section 29 of the Internal Revenue Code ("Section 29"). Section 29 provides for
a tax credit from non-conventional fuel sources such as oil produced from shale
and tar sands and natural gas produced from geopressured brine, Devonian shale,
coal seams and tight sands formations. Brooklyn Union acquired an economic
interest in wells that are qualified for the tax credits and in exchange, the
Company (i) retained a volumetric production payment and a net profits interest
of 100% in the properties, (ii) received a cash down payment of $1.4 million and
(iii) will receive a quarterly payment of $0.75 for every dollar of tax credit
utilized. The Company will manage and administer the daily operations of the
properties in exchange for an annual management fee of $100,000. At December 31,
1997, the balance sheet effect of this transaction was a $1.4 million reduction
to the full cost pool for the down payment. The income statement effect for the
year ended December 31, 1997 was a reduction to income tax expense of $1.2
million, representing benefits received from the Section 29 tax credits.
General and Administrative Expense
The Company reimburses Brooklyn Union for certain general and
administrative costs. During the years ended December 31, 1995, 1996 and 1997,
the Company paid Brooklyn Union $0.7 million, $0.6 million and $0.1 million in
general and administrative reimbursements.
F-14
<PAGE> 53
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Gas Sales
In 1992, the Company entered into a term supply agreement with BRING Gas
Services Corp. ("BRING"), an affiliate of Brooklyn Union, at that time. As of
April 1, 1995, this contract was superseded when the Company entered into a term
supply agreement with PennUnion Energy Services, L.L.C. ("PennUnion"), successor
to BRING, and an affiliate of Brooklyn Union. This contract was terminated in
October 1996 with Brooklyn Union's sale of its interest in PennUnion. Under the
terms of the agreement, the Company agreed to sell and PennUnion agreed to buy a
substantial portion of the Company's production at index-related prices. The
agreement contained provisions for both the commitment of gas reserves
subsequently developed or acquired by the Company and the release of gas
reserves sold, traded or exchanged to third parties.
For the years ended December 31, 1995 and 1996 the Company had natural gas
sales of $18.9 million and $26.7 million, respectively, to PennUnion.
Employment Contracts
Prior to the IPO the Company maintained an employment agreement with its
President and Chief Executive Officer which provided him with the option to
participate in up to a 5% working interest in certain prospects of the Company.
During 1995 and 1996, affiliates of the Company's President obtained a 5%
working interest in 144 wells (which includes 142 Charco wells) operated by the
Company pursuant to such agreement. In addition, during 1995, 1996 and 1997,
affiliates of the Company's President paid $0.7 million, $1.4 million and $3.3
million, respectively, in expenses attributable to working interests owned in
properties operated by the Company, and received $0.9 million, $1.6 million and
$3.9 million, respectively, in distributions attributable to such working
interests. See Note 12 -- Acquisitions.
The employment agreement also provided for the assignment to the President
of a 2% net profits interest in all prospects of the Company and a 6.75% after
program-payout working interest. In addition, the employment agreement provided
for the assignment to certain key employees designated by the President of an
overriding royalty interest equivalent in the aggregate to a four percent net
revenue interest in certain properties acquired by the Company. Assignments were
made in two wells during 1995; no assignments were made in 1996 or 1997. Upon
completion of the IPO, the President's employment agreement was terminated and
replaced with a new employment agreement, which does not provide the President
with the option to participate in prospects of the Company or to receive or
grant assignments or after program-payout working interests. In addition to the
Company's President, certain other key employees of the Company entered into
employment agreements upon completion of the IPO.
NOTE 7 -- EMPLOYEE BENEFIT PLANS
401(k) Profit Sharing Plan
The Company maintains a 401(k) Profit Sharing Plan (the "401(k) Plan") for
its employees. Under the 401(k) Plan, eligible employees may elect to have the
Company contribute on their behalf up to 10% of their base compensation (subject
to certain limitations imposed under the Internal Revenue Code of 1986, as
amended) on a before tax basis. The Company makes a matching contribution of
$0.50 for each $1.00 of employee deferral, not to exceed 5% of an employee's
base compensation, subject to limitations imposed by the Internal Revenue
Service. The amounts contributed under the 401(k) Plan are held in a trust and
invested among various investment funds in accordance with the directions of
each participant. An employee's salary deferral contributions under the 401(k)
Plan are 100% vested. The Company's matching contributions vest at the rate of
20% per year of service. Participants are entitled to payment of their vested
account balances upon termination of employment. For the years ended December
31, 1995, 1996 and 1997, Company contributions to the 401(k) Plan were $157,000,
$158,000 and $210,000, respectively.
F-15
<PAGE> 54
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Supplemental Executive Plan
Effective immediately prior to the IPO, the Company adopted an unfunded,
nonqualified Supplemental Executive Retirement Plan (the "SERP") for the benefit
of James G. Floyd, the Company's President and Chief Executive Officer. The SERP
provides that, if the executive remains with the Company until age 65, upon his
retirement on or after age 65, the executive will be paid $100,000 per year for
life. If, after retirement, the executive predeceases his spouse, 50% of the
executive's SERP benefit will continue to be paid to the executive's surviving
spouse for her life. During 1997 the Company accrued $123,000 related to the
SERP and in 1996 no amounts were accrued as required accruals were de minimus.
NOTE 8 -- FINANCIAL INSTRUMENTS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------
1996 1997
---------------------- ----------------------
CARRYING ESTIMATED CARRYING ESTIMATED
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash and cash equivalents........................ $ 2,851 $ 2,851 $ 4,745 4,745
Long-term debt................................... 65,000 65,000 113,000 113,000
Derivative transactions:
Interest rate swap agreements:
In a payable position....................... -- (171) -- (169)
Commodity price and basis swaps:
In a payable position.......................... -- (30,286) -- (516)
</TABLE>
Cash and Cash Equivalents
The carrying amount approximates fair value due to the short maturity of
these instruments.
Long-Term Debt
The carrying amount of borrowings outstanding under the Credit Facility
approximates fair value as the interest rate is tied to current market rates.
DERIVATIVE TRANSACTIONS
Interest Rate Swap Agreements
The fair values are obtained from the financial institutions that are
counterparties to the transactions. These values represent the estimated amount
the Company would pay or receive to terminate the agreements, taking into
consideration current interest rates and the current creditworthiness of the
counterparties. The Company's interest rate swap agreements are off balance
sheet transactions and, accordingly, no respective carrying amounts for these
transactions are included in the accompanying combined balance sheets at
December 31, 1997. At December 31, 1997, the Company had two interest rate swap
agreements to exchange an aggregate notional principal of $80.0 million over
various periods from November 1996 through November 1999 at rates between 5.805%
and 6.025%.
Commodity Related Transactions
The Company uses derivative financial instruments for non-trading purposes
as a hedging strategy to reduce the impact of market volatility and to ensure
cash flows. Gains and losses on these hedging transactions are recorded when the
related natural gas has been produced or delivered. While derivative financial
F-16
<PAGE> 55
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
instruments are intended to reduce the Company's exposure to declines in the
market price of natural gas, the derivative financial instruments may limit the
Company's gain from increases in the market price.
The derivative instruments used to hedge commodity transactions have
historically had high correlation with commodity prices and are expected to
continue to do so. The correlation of indices and prices is regularly evaluated
to ensure that the instruments continue to be effective hedges. In the event
that correlation falls below allowable levels, the gains or losses associated
with the hedging instruments are immediately recognized to the extent that
correlation was lost. In December of 1995, the Company recognized a pretax loss
of $0.7 million due to the loss of correlation of the New York Mercantile
Exchange ("NYMEX") futures market for natural gas with the market price for
natural gas in certain parts of the country. The Company's hedges in place at
December 31, 1996 or 1997 did not experience loss of market correlation.
Commodity Price Swaps
Price swap agreements call for one party to make monthly payments to (or
receive from) another party based upon the differential between a fixed and a
variable price (fixed-price swap) or two variable prices (basis swap) for a
notional volume specified by the contract. The fair value is the estimated
amount the Company would receive or pay to terminate swap agreements at
year-end, taking into account the difference between NYMEX natural gas prices or
index prices at year-end and fixed swap prices. NYMEX natural gas price closed
at $3.61 per MMbtu and $2.68 per MMbtu at December 31, 1996 and 1997,
respectively. At December 31, 1996 and 1997, the Company had fixed-price swap
agreements and basis swap agreements to exchange a total notional volume of
23,278 MMbtu and 5,410 MMbtu, respectively, of natural gas over the period
January 1996 through March 1998. The Company has no hedges in place past March
1998.
The Company is exposed to credit risk in the event of nonperformance by
counterparties to futures and swaps contracts. The Company believes that the
credit risk related to the futures and swap contracts is no greater than that
associated with the primary contracts which they hedge, as these contracts are
with major investment grade financial institutions, and that elimination of the
price risk lowers the Company's overall business risk.
NOTE 9 -- SALES TO MAJOR CUSTOMERS
As is the nature of the exploration, development and production business,
production is normally sold to relatively few customers. However, alternate
buyers are available to replace the loss of any of the Company's major
customers. For year ended December 31, 1995, PennUnion was the only customer for
which natural gas sales exceeded 10% of total revenues and during 1995 sales to
PennUnion comprised 46% of total revenues. For the year ended December 31, 1996,
the Company sold natural gas production representing more than 10% of its total
revenues to PennUnion (40%) and H&N Gas Ltd. (27%). For the year ended December
31, 1997, the Company's only customer to whom sales of natural gas production
represented more than 10% of its total revenues was H&N Gas Ltd. (38%). The
Company believes that prices at which it sold gas to PennUnion were similar to
those it would be able to obtain in the open market. The Company also believes
that the loss of H&N Gas Ltd. as a purchaser would not have a material adverse
effect on the Company's operations. See Note 6 -- Related Party Transactions.
NOTE 10 -- COMMITMENTS AND CONTINGENCIES
Litigation
The Company is involved from time to time in various claims and lawsuits
incidental to its business. In the opinion of management, the ultimate liability
thereunder, if any, will not have a material adverse effect on the financial
position or results of operations of the Company.
F-17
<PAGE> 56
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Leases
The Company has entered into certain noncancelable operating lease
agreements relative to office space and equipment with various expiration dates
through 2002. Minimum rental commitments under the terms of the leases are as
follows:
<TABLE>
<CAPTION>
MINIMUM NET MINIMUM
RENTAL SUBLEASE RENTAL
COMMITMENTS RENTALS COMMITMENTS
(IN THOUSANDS)
<S> <C> <C> <C>
1998.......................................... $743 $(246) $497
1999.......................................... 750 (250) 500
2000.......................................... 753 (252) 501
2001.......................................... 513 (84) 429
2002.......................................... 460 -- 460
Thereafter.................................... $877 $ -- $877
</TABLE>
Net rental expense related to these leases was $0.3 million for each of the
years ended December 31, 1997, 1996 and 1995.
NOTE 11 -- NONRECURRING CHARGE
In connection with the February 1996 reorganization in which Brooklyn Union
transferred certain onshore producing properties and acreage to the Company,
certain former employees of FRI, the subsidiary of Brooklyn Union that
previously owned the onshore properties, were entitled to remuneration for the
increase in the value of the transferred properties prior to the reorganization.
The Company incurred a $12 million non-cash charge in the quarter ended December
31, 1995 with respect to the remuneration to which such employees of FRI were
entitled.
NOTE 12 -- ACQUISITIONS
TransTexas
On July 2, 1996, the Company acquired certain natural gas and oil
properties and associated gathering pipelines and equipment located in Zapata
County, Texas (the "TransTexas Acquisition") from TransTexas Gas Corporation and
TransTexas Transmission Corporation (together, "TransTexas"). The Company
acquired a 100% working interest (95% after the exercise by James G. Floyd, the
Company's President and Chief Executive Officer, of his right to purchase a 5%
working interest) in the approximately 142 wells on such properties. The
purchase price of $62.2 million ($59.1 million after giving effect to the
exercise of Mr. Floyd's purchase option) for the TransTexas Acquisition was
reduced by $3.1 million for production revenue and expenses related to the
assets between the May 1, 1996 effective date of the TransTexas Acquisition and
July 2, 1996. The purchase price of the TransTexas Acquisition was paid in cash,
financed with borrowings under the Company's Credit Facility.
The Company loaned Mr. Floyd the $3.1 million purchase price for his
purchase of a 5% working interest in the properties purchased by the Company in
the TransTexas Acquisition. In addition, the Company has agreed to loan Mr.
Floyd, on a revolving basis, the amounts required to fund the expenses
attributable to Mr. Floyd's working interest. Mr. Floyd is required to repay
amounts owed under the loan in the amount of 65% of all distributions received
by Mr. Floyd in respect of such working interest, as distributions are received.
Amounts outstanding under such loan bear interest at an interest rate equal to
the Company's cost of borrowing under the Credit Facility. Mr. Floyd's
obligations under the agreement are secured by a pledge of his working interest
in, and the production from, such properties. As of December 31, 1997, the
outstanding balance owed by Mr. Floyd under the agreement was $3.7 million and
the loan will mature on July 2, 2006.
F-18
<PAGE> 57
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Soxco
On September 25, 1996, the Company acquired substantially all of the
natural gas and oil properties and related assets (the "Soxco Acquisition") of
Smith Offshore Exploration Company ("Soxco"). The natural gas and oil properties
acquired in the Soxco Acquisition consisted solely of working interests in
properties located in the Gulf of Mexico that are operated by the Company or in
which the Company also has a working interest. Pursuant to the Soxco
Acquisition, the Company paid Soxco cash in the aggregate amount of $20.3
million (net of $3.4 million for certain purchase price adjustments), and issued
to Soxco 762,387 shares of common stock with an aggregate value (determined by
reference to the IPO price) of $11.8 million. The cash portion of the purchase
price was funded with the proceeds of the IPO. In addition to the foregoing, the
Company will pay Soxco a deferred purchase price of up to $17.6 million
effective January 31, 1998. The amount of the deferred purchase price will be
determined by the probable reserves of Soxco as of December 31, 1995
(approximately 17.6 Bcfe) that are produced prior to or classified as proved as
of December 31, 1996 and December 31, 1997, respectively, provided that Soxco is
entitled to receive a minimum deferred purchase price of approximately $8.8
million. The amounts so determined will be paid in shares of common stock based
on the fair market value of such stock at the time of issuance. At December 31,
1997, the Company believes it is probable that only the minimum payment will be
required and as a result, $8.8 million has been accrued and reflected in current
liabilities.
Pending Acquisition
On January 12, 1998, the Company entered into a non-binding letter of
intent with respect to the acquisition of natural gas and oil properties located
onshore in South Louisiana, representing 45 Bcfe of net proved reserves (the
"South Louisiana Acquisition"). The average net production in December 1997
attributable to such properties was approximately 14 Mmcfe per day, net to the
Company's interest. The non-binding letter of intent provides for the Company to
pay $60 million for the properties to be acquired. The estimated purchase price
of $60 million is less than 10% of the Company's total assets and income
generated from these properties for the year ended December 31, 1997 was
estimated to be less than 20% of the Company's income from operations.
NOTE 13 -- SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES
The following information concerning the Company's natural gas and oil
operations has been provided pursuant to Statement of Financial Accounting
Standards No. 69, "Disclosures about Oil and Gas Producing Activities." The
Company's natural gas and oil producing activities are conducted onshore within
the continental United States and offshore in federal and state waters of the
Gulf of Mexico. The Company's natural gas and oil reserves were estimated by
independent reserve engineers.
Capitalized Costs of Natural Gas and Oil Properties
As of December 31, 1995, 1996 and 1997, the Company's capitalized costs of
natural gas and oil properties are as follows:
<TABLE>
<CAPTION>
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
Unevaluated properties, not amortized.......... $ 42,286 $ 60,258 $ 104,075
Properties subject to amortization............. 309,378 468,062 566,868
--------- --------- ---------
Capitalized costs.............................. 351,664 528,320 670,943
Accumulated depreciation, depletion and
amortization................................. (137,769) (171,258) (229,776)
--------- --------- ---------
Net capitalized costs................ $ 213,895 $ 357,062 $ 441,167
========= ========= =========
</TABLE>
F-19
<PAGE> 58
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The following is a summary of the costs (in thousands) which are excluded
from the amortization calculation as of December 31, 1997, by year of
acquisition. The Company is not able to accurately predict when these costs will
be included in the amortization base; however, the Company believes that
unevaluated properties at December 31, 1997 will be fully evaluated within five
years.
<TABLE>
<CAPTION>
<S> <C>
1997...................................................... $ 46,546
1996...................................................... 33,168
1995...................................................... 13,097
Prior..................................................... 11,264
--------
$104,075
========
</TABLE>
Costs incurred for natural gas and oil exploration, development and
acquisition are summarized below. Costs incurred during the years ended December
31, 1995, 1996 and 1997 include interest expense, general and administrative
costs related to acquisition, exploration and development of natural gas and oil
properties, of $7.0 million, $8.8 million and $13.1 million, respectively.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition:
Unevaluated(1)................................... $ 9,902 $ 23,317 $ 16,613
Proved........................................... 11,137 94,774 24,007
Exploration costs.................................. 7,224 27,398 44,119
Development costs.................................. 41,163 31,243 59,244
------- -------- --------
Total costs incurred..................... $69,426 $176,732 $143,983
======= ======== ========
</TABLE>
- ---------------
(1) These amounts represent costs incurred by the Company and excluded from the
amortization base until proved reserves are established or impairment is
determined.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Natural Gas and Oil Reserves (unaudited)
The following summarizes the policies used by the Company in the
preparation of the accompanying natural gas and oil reserve disclosures,
standardized measures of discounted future net cash flows from proved natural
gas and oil reserves and the reconciliations of such standardized measures from
year to year. The information disclosed, as prescribed by the Statement of
Financial Accounting Standards No. 69 is an attempt to present such information
in a manner comparable with industry peers.
The information is based on estimates of proved reserves attributable to
the Company's interest in natural gas and oil properties as of December 31 of
the years presented. These estimates were principally prepared by independent
petroleum consultants. Proved reserves are estimated quantities of natural gas
and crude oil which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and future
periods during which they are expected to be produced based on year-end
economic conditions.
F-20
<PAGE> 59
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
2. The estimated future cash flows are compiled by applying year-end
prices of natural gas and oil relating to the Company's proved reserves to
the year-end quantities of those reserves except for those reserves devoted
to future production that is hedged. The estimated future cash flows
associated with such reserves are compiled by applying the reference prices
of such hedges to the future production that is hedged. Future price
changes are considered only to the extent provided by contractual
arrangements in existence at year-end.
3. The future cash flows are reduced by estimated production costs,
costs to develop and produce the proved reserves and certain abandonment
costs, all based on year-end economic conditions.
4. Future income tax expenses are based on year-end statutory tax
rates giving effect to the remaining tax basis in the natural gas and oil
properties, other deductions, credits and allowances relating to the
Company's proved natural gas and oil reserves.
5. Future net cash flows are discounted to present value by applying a
discount rate of 10 percent.
The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's natural gas and oil reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.
The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves is as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows.............................. $418,822 $1,117,058 $ 781,336
Future production costs.......................... (66,458) (153,452) (135,437)
Future development costs......................... (24,803) (67,966) (84,658)
Future income taxes.............................. (74,933) (230,316) (124,510)
-------- ---------- ---------
Future net cash flows............................ 252,628 665,324 436,731
10% annual discount for estimated timing of cash
flows.......................................... (81,169) (212,742) (121,351)
-------- ---------- ---------
Standardized measure of discounted future net
cash flows..................................... $171,459 $ 452,582 $ 315,380
======== ========== =========
</TABLE>
Future cash inflows include the effect of hedges in place at year end
December 31, 1995, 1996 and 1997. At December 31, 1995, 1996, and 1997 the
effect of the hedges in place is a reduction to future cash inflows of $4.4
million, $28.7 million and $0.5 million, respectively.
F-21
<PAGE> 60
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of the year............................. $118,434 $171,459 $ 452,582
Revisions to previous estimates:
Changes in prices and costs..................... 35,497 145,385 (223,169)
Changes in quantities........................... 11,306 (19,132) (23,156)
Changes in future development costs............. 531 (14,068) (20,499)
Development costs incurred during the period...... 8,074 19,594 16,154
Extensions and discoveries, net of related
costs........................................... 51,061 46,616 114,893
Sales of natural gas and oil, net of production
costs........................................... (34,843) (52,663) (97,968)
Accretion of discount............................. 12,815 20,652 57,700
Net change in income taxes........................ (24,720) (89,353) 62,733
Purchase of reserves in place..................... 11,189 251,713 2,463
Sale of reserves in place......................... (19) (723) (608)
Production timing and other....................... (17,866) (26,898) (25,745)
-------- -------- ---------
End of year....................................... $171,459 $452,582 $ 315,380
======== ======== =========
</TABLE>
ESTIMATED NET QUANTITIES OF NATURAL GAS AND OIL RESERVES (UNAUDITED)
The following table sets forth the Company's net proved reserves, including
changes therein, and proved developed reserves (all within the United States) at
the end of each of the three years in the period ended December 31, 1995, 1996
and 1997.
<TABLE>
<CAPTION>
NATURAL GAS CRUDE OIL AND CONDENSATE
(MMCF) (MBBLS)
----------------------------- -------------------------
1995 1996 1997 1995 1996 1997
<S> <C> <C> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:.... 145,945 195,946 320,474 636 889 1,131
Revisions of previous
estimates............. 15,702 (8,665) (18,743) 51 (157) (62)
Extensions and
discoveries........... 45,014 21,445 75,651 254 198 184
Production............... (21,077) (31,215) (50,310) (100) (118) (171)
Purchase of reserves
in place.............. 10,367 143,688 3,778 48 361 1
Sales of reserves in
place................. (5) (725) (249) -- (42) (6)
------- ------- ------- ---- ----- -----
End of year................ 195,946 320,474 330,601 889 1,131 1,077
======= ======= ======= ==== ===== =====
Proved developed reserves:
Beginning of year........ 104,678 162,784 236,544 328 774 1,013
End of year.............. 162,784 236,544 256,632 774 1,013 914
</TABLE>
F-22
<PAGE> 61
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 14 -- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Selected unaudited quarterly data is shown below:
<TABLE>
<CAPTION>
1ST 2ND 3RD 4TH
QUARTER QUARTER QUARTER QUARTER
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
1996
Total revenues.......................... $10,213 $11,574 $19,171 $24,946
Income from operations.................. 1,219 2,661 2,740 7,102
Net income (loss)....................... 976 1,813 1,267 4,586
Net income per share(1)................. $ 0.06 $ 0.12 $ 0.08 $ 0.20
Net income per share -- assuming
dilution............................. $ 0.06 $ 0.12 $ 0.08 $ 0.19
1997
Total revenues.......................... $25,328 $22,220 $29,312 $40,786
Income from operations.................. 8,287 4,337 8,065 13,672
Net income.............................. 5,693 3,442 5,525 8,590
Net income per share.................... $ 0.24 $ 0.15 $ 0.24 $ 0.37
Net income per share -- assuming
dilution............................. $ 0.24 $ 0.14 $ 0.23 $ 0.35
</TABLE>
- ---------------
(1) Quarterly earnings per share are based on the weighted average number of
shares outstanding during the quarter. Because of the increase in the number
of shares outstanding during the third quarter of 1996, the sum of quarterly
earnings per share do not equal earnings per share for the year.
F-23
<PAGE> 62
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
-------- -----------
<S> <C>
3.1 -- Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 1997 (File No. 001-11899) and
incorporated by reference herein).
3.2 -- Restated Bylaws (filed as Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 1997 (File No. 001-11899) and incorporated by reference
herein).
4.1 -- Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.1 -- Agreement for Filing Consolidated Federal Income Tax Returns and for Allocation of
Consolidated Federal Income Tax Liabilities and Benefits dated September 1, 1994 between
The Brooklyn Union Gas Company and its subsidiaries (filed as Exhibit 10.19 to the
Company's Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated
by reference herein).
10.2 ** -- Employment Agreement dated July 2, 1996 between The Houston Exploration Company and James
G. Floyd (filed as Exhibit 10.8 to the Company's Registration Statement on Form S-1
(Registration No. 333-4437) and incorporated by reference herein).
10.3 ** -- Employment Agreement dated July 2, 1996 between The Houston Exploration Company and Randall
J. Fleming (filed as Exhibit 10.9 to the Company's Registration Statement on Form S-1
(Registration No. 333-4437) and incorporated by reference herein).
10.4 ** -- Employment Agreement dated July 2, 1996 between The Houston Exploration Company and Thomas
W. Powers (filed as Exhibit 10.10 to the Company's Registration Statement on Form S-1
(Registration No. 333-4437) and incorporated by reference herein).
10.5 ** -- Employment Agreement dated July 2, 1996 between The Houston Exploration Company and James
F. Westmoreland (filed as Exhibit 10.11 to the Company's Registration Statement on Form S-1
(Registration No. 333-4437) and incorporated by reference herein).
</TABLE>
<PAGE> 63
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
-------- -----------
<S> <C>
10.6 ** -- 1996 Stock Option Plan (filed as Exhibit 10.12 to the Company's Registration Statement on
Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.7 -- Registration Rights Agreement dated as of July 2, 1996 between The Houston Exploration
Company and THEC Holdings Corp. (filed as Exhibit 10.13 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.8 -- Asset Purchase Agreement dated as of July 1, 1996 between The Houston Exploration Company
and Smith Offshore Exploration Company (filed as Exhibit 10.14 to the Company's
Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by
reference herein).
10.9 -- Registration Rights Agreement between The Houston Exploration Company and Smith Offshore
Exploration Company (filed as Exhibit 10.15 to the Company's Registration Statement on Form
S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.10 -- Credit Agreement dated as of July 2, 1996 among The Houston Exploration Company and Texas
Commerce Bank National Association, as Agent, and the other Banks signatory thereto (filed
as Exhibit 10.16 to the Company's Registration Statement on Form S-1 (Registration No. 333-
4437) and incorporated by reference herein).
* 10.11 -- First Amendment, dated August 30, 1996, to the Credit Agreement among The Houston
Exploration Company and Texas Commerce Bank National Association, as Agent, and the other
Banks signatory thereto.
10.12 -- Second Amendment, dated August 4, 1997, to the Credit Agreement among The Houston
Exploration Company and Texas Commerce Bank National Association, as Agent, and the other
Banks signatory thereto (filed as Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the quarterly by period ended September 30, 1997 (File No. 001-11899) and incorporated
by reference herein.
10.13 -- Purchase and Sale Agreement dated as of June 21, 1996, among The Houston Exploration
Company, TransTexas Gas Corporation and TransTexas Transmission Corporation (filed as
Exhibit 10.17 to the Company's Registration Statement on Form S-1 (Registration No. 333-
4437) and incorporated by reference herein).
10.14 -- Gas Exchange Agreement dated as of July 2, 1996 between The Houston Exploration Company and
TransTexas Gas Corporation (filed as Exhibit 10.18 to the Company's Registration Statement
on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.15 -- Indemnification Agreement dated as of September 25, 1996 between The Houston Exploration
Company and THEC Holdings Corp. (filed as Exhibit 10.20 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.16 -- Contribution Agreement dated as of February 26, 1996 between The Houston Exploration
Company and Fuel Resources Inc. (filed as Exhibit 10.21 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.17 ** -- Registration Rights Agreement dated as of September 25, 1996 between The Houston
Exploration Company and James G. Floyd (filed as Exhibit 10.22 to the Company's
Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by
reference herein).
10.18 ** -- Supplemental Executive Pension Plan (filed as Exhibit 10.23 to the Company's Registration
Statement on Form S-1 (Registration No. 333-4437) and incorporated by reference herein).
10.19 ** -- Deed of Trust, Assignment of Production, Security Agreement and Financing Statement between
The Houston Exploration Company and James G. Floyd (filed as Exhibit 10.24 to the Company's
Registration Statement on Form S-1 (Registration No. 333-4437) and incorporated by
reference herein).
10.20 ** -- Contribution Agreement between James G. Floyd and The Houston Exploration Company (filed as
Exhibit 10.25 to the Company's Registration Statement on Form S-1 (Registration No. 333-
4437) and incorporated by reference herein).
10.21 ** -- Employment Agreement, dated September 19, 1996, between The Houston Exploration Company and
Charles W. Adcock (filed as Exhibit 10.26 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1996 (File No. 001-11899) and incorporated by reference herein).
</TABLE>
<PAGE> 64
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
-------- -----------
<S> <C>
10.22 ** -- Form of Letter Agreement from The Houston Exploration Company to each of James G. Floyd,
Randall J. Fleming, Thomas W. Powers, Charles W. Adcock, James F. Westmoreland and
Sammye L. Dees evidencing grants of Phantom Stock Rights effective as of December 16, 1996
(filed as Exhibit 10.27 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1996 (File No. 001-11899) and incorporated by reference herein).
10.23 ** -- Purchase and Sale Agreement, dated January 1, 1997, between The Houston Exploration Company
and KeySpan Natural Fuel, LLC (filed as Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 1997 (File No. 001-11899) and incorporated
by reference herein).
* 10.24 ** -- Deferred Compensation Plan for Non-Employee Directors.
* 21.1 -- Subsidiaries of the Company.
* 23.1 -- Consent of Arthur Andersen LLP.
* 27.1 -- Financial Data Schedule.
</TABLE>
- -------------
* Filed herewith.
** Management contract or compensation plan.
<PAGE> 1
EXHIBIT 10.11
FIRST AMENDMENT TO
CREDIT AGREEMENT AND SECURITY AGREEMENT
This FIRST AMENDMENT TO CREDIT AGREEMENT AND SECURITY
AGREEMENT (this "Amendment"), effective as of August 30, 1996, is entered into
by and among THE HOUSTON EXPLORATION COMPANY, a Delaware corporation (the
"Company'); THEC HOLDINGS CORP., a Delaware corporation (the "Pledgor"); and
TEXAS COMMERCE BANK NATIONAL ASSOCIATION, a national banking association
("TCB"), with offices at 712 Main Street, Houston, Texas 77002, individually and
as Administrative Agent (TCB, in its capacity as Administrative Agent
hereinafter called "Administrative Agent") for itself and such other banks or
lending institutions (collectively the "Banks") which are or hereafter become a
party to the "Credit Agreement" (hereinafter defined).
PRELIMINARY STATEMENTS:
A. The Company, the Administrative Agent, and TCB entered into
that certain Credit Agreement dated as of July 2,1996 (as the same may from time
to time be amended, supplemented, or modified, the "Credit Agreement") under the
terms of which the Banks agreed to make available to the Company a revolving
line of credit not to exceed, in the aggregate, $150,000,000 at any one time
outstanding.
B. Pursuant to the Credit Agreement, the Pledgor and the
Administrative Agent, as Secured Party, entered into that certain Security
Agreement dated as of July 2, 1996 ("Security Agreement").
C. The Company and the Pledgor have requested that TCB and the
Administrative Agent modify certain terms of the Credit Agreement and Security
Agreement, and, subject to the terms and conditions contained herein, TCB and
the Administrative Agent have agreed so to do.
NOW THEREFORE, in consideration of the foregoing the parties
hereto hereby agree as follows:
Section 1. Certain Defined Terms. All capitalized terms used
herein (including in the preliminary statements hereof) and not otherwise
defined shall have the meanings set forth in the Credit Agreement.
<PAGE> 2
Section 2. Amendment to definition of IPO in Credit Agreement.
The definition of IPO in the Credit Agreement is hereby deleted in its entirety,
and the following definition shall be substituted therefor:
"IPO" shall mean the public offering of stock of the Company,
which is scheduled to occur on or before October 1, 1996."
Section 3. Amendment to Section 8.12 of the Security
Agreement. The last sentence of Section 8.12 of the Credit Agreement is hereby
deleted in its entirety, and the following sentence shall be substituted
therefor:
"Upon (i) the closing of the IPO and the prepayment of the
Loans by the Borrower pursuant to Section 2.08(c) of the
Credit Agreement or (ii) the full and final payment of the
Obligations and the compliance by Pledgor with all covenants
and agreements hereof, Secured Party will release, reassign
and transfer the Collateral to Pledgor without any further
action of any kind and regardless of the existence of an Event
of Default; provided, however, if the IPO is not completed
within 90 days after the Closing Date, Secured Party shall
retain the pledge of the Collateral and all of Secured Party's
rights, titles and security interests in the Collateral
conveyed hereby."
Section 4. Ratification. The Company and the Pledgor
acknowledges ratify, respectively, the Credit Agreement and the Security
Agreement as amended hereby, and agree and acknowledge that all the terms
thereof as amended hereby (a) are hereby brought forward for the benefit of the
Banks and the Administrative Agent and (b) shall remain in full force and
effect.
Section 5. Counterparts. This Amendment may be signed in any
number of counterparts, each of which shall be construed as an original, but all
of which together shall constitute one and the same instrument.
Section 6. Choice of Law. This Amendment shall be governed
by, and construed in accordance with, the laws of the State of Texas.
Section 7. Final Agreement of the Parties. THIS AMENDMENT,
THE CREDIT AGREEMENT, THE NOTES AND THE OTHER SECURITY INSTRUMENTS CONSTITUTE A
"LOAN AGREEMENT" AS DEFINED IN SECTION 26.02(A) OF THE TEXAS BUSINESS AND
COMMERCE CODE, AND REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT
BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL
AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE
PARTIES.
<PAGE> 3
IN WITNESS WHEREOF, the parties hereto have caused this
Agreement to be executed by their respective officers thereunto duly authorized
as of the date first above written.
COMPANY:
THE HOUSTON EXPLORATION COMPANY.
By: /s/ Thomas W. Powers
----------------------------------------
Thomas W. Powers
Senior Vice President
PLEDGOR:
THEC HOLDINGS CORP.
By: /s/ Randall J. Fleming
----------------------------------------
Randall J. Fleming
Vice President
TCB AND ADMINISTRATIVE AGENT:
TEXAS COMMERCE BANK NATIONAL
ASSOCIATION, Individually as a Bank
and in its capacity as Administrative Agent
By: /s/ Paul J. Nidoh
-----------------------------------------
Paul J. Nidoh
Vice President
<PAGE> 1
EXHIBIT 10.24
THE HOUSTON EXPLORATION COMPANY
DEFERRED COMPENSATION PLAN
FOR
NON-EMPLOYEE DIRECTORS
<PAGE> 2
THE HOUSTON EXPLORATION COMPANY
DEFERRED COMPENSATION PLAN
FOR
NON-EMPLOYEE DIRECTORS
Table of Contents
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
Section 1 Definitions................................................... 1
Section 2 Administration................................................ 3
Section 3 Participants.................................................. 4
Section 4 Benefits...................................................... 4
Section 5 General Provisions............................................ 7
</TABLE>
-i-
<PAGE> 3
THE HOUSTON EXPLORATION COMPANY
DEFERRED COMPENSATION PLAN FOR
NON-EMPLOYEE DIRECTORS
PREAMBLE
WHEREAS, The Houston Exploration Company (the "Company")
desires to establish The Houston Exploration Company Deferred Compensation Plan
For Non-Employee Directors (the "Plan") to assist the Company in attracting and
retaining highly qualified individuals to serve as members of the Company's
Board of Directors by permitting them to defer all or part of their annual
retainer and meeting fees;
NOW, THEREFORE, the Company does hereby adopt the Plan as set
forth herein, effective as of October 1, 1997.
SECTION 1
DEFINITIONS
For purposes of the Plan, the following terms shall have the
meanings indicated:
1.1 Account means a ledger Account as provided in Section 4.2.
1.2 Beneficiary means the person(s) designated by a Participant, on a form
provided by the Company and filed with the Company's Human Resources
Department, to receive benefits from the Plan in the event of the
Participant's death. A Participant may change his or her beneficiary
designation at any time; provided, however, no such designation or
change in designation shall be effective until received by the Company
during the Participant's life. If no designated Beneficiary survives
the Participant, the Beneficiary shall be the Participant's surviving
spouse or, if none, his or her estate.
<PAGE> 4
1.3 Board means the Board of Directors of the Company.
1.4 Committee means the Compensation Committee of the Board.
1.5 Common Stock means the common stock, par value $.01 per share, of the
Company.
1.6 Compensation means, with respect to a Plan Year, the Participant's
annual retainer for such Plan Year and any meeting fees for each
regular and special meeting and any committee meeting attended by the
Participant during the applicable Plan Year.
1.7 Exchange Act means the Securities Exchange Act of 1934, as amended.
1.8 Fair Market Value, means as of any date, (a) the closing sale price of
the Common Stock on that date (or, if there was no sale on such date,
the next preceding date on which there was such a sale) on the
principal securities exchange on which the Common Stock is listed; or
(b) if the Common Stock is not listed on a securities exchange, the
closing sale price of the Common Stock on that date (or, if there was
no sale on such date, the next preceding date on which there was such a
sale) as reported on the NYSE; or (c) if the Common Stock is not listed
on the NYSE, the average of the high and low bid quotations for the
Stock on that date as reported by the National Quotation Bureau
Incorporated; or (d) if none of the foregoing is applicable, an amount
at the election of the Compensation Committee equal to (x) the average
between the closing bid and ask prices per share of Common Stock on the
last preceding date on which those prices were reported or (y) an
amount as determined by the Compensation Committee in its sole
discretion.
1.9 Non-Employee Director means a member of the Board who is not also an
employee of the Company or a subsidiary thereof.
-2-
<PAGE> 5
1.10 Participant means each Non-Employee Director who elects to participate
in the Plan in accordance with Section 3.
1.11 Payment Date means the Participant's Termination Date or, if elected
pursuant to Section 4.5, the date following such Termination Date on
which payment of the Participant's Account is to be made or begin.
1.12 Phantom Stock means a phantom share of Common Stock. A Participant
shall not possess any rights of a stockholder of the Company with
respect to a share of Phantom Stock.
1.13 Plan means The Houston Exploration Company Deferred Compensation Plan
For Non-Employee Directors as it may be amended from time to time.
1.14 Plan Year means the calendar year, with the initial year being a short
year beginning October 1, 1997.
1.15 Section 16(b) means Section 16(b) of the Exchange Act, and all rules
promulgated thereunder.
1.16 Termination means a Participant's ceasing to be a member of the Board.
SECTION 2
ADMINISTRATION
2.1 Compensation Committee. The Plan shall be administered by the
Compensation Committee. The Compensation Committee shall have the
complete authority and power to interpret the Plan, prescribe, amend
and rescind rules relating to its administration, determine eligible
Participants, determine a Participant's (or Beneficiary's) right to a
payment and the amount of such payment, and to take all other actions
necessary or desirable for the administration of the Plan. All actions
and decisions of the Compensation Committee shall be final and binding
upon all Participants and Beneficiaries.
-3-
<PAGE> 6
SECTION 3
PARTICIPANTS
3.1 Participants. Each person who is a Non-Employee Director shall be
eligible to become a Participant.
SECTION 4
BENEFITS
4.1 Voluntary Deferrals. Before the beginning of each Plan Year (or, with
respect to an individual who first becomes a Non-Employee Director
during a Plan Year, within 30 days of the date on which he or she
becomes a Non-Employee Director), each Non-Employee Director may elect
to have the payment of all or a portion of his or her Compensation for
that Plan Year (or, if applicable, the remainder of the Plan Year)
deferred until his or her Termination. The election shall be
irrevocable and shall be made on a form prescribed by the Company,
which shall govern the amount deferred, the form of its payment
pursuant to Section 4.5 following the Participant's Termination, and
the initial investment of the Participant's Account for such deferred
Compensation pending its payment. A Participant's deferral election
shall apply to Compensation earned during that specified Plan Year or
partial Plan Year, as the case may be, and for all Compensation earned
in subsequent Plan Years, unless the election is changed by the
Participant prior to the beginning of such Plan Year. Notwithstanding
the foregoing, a Participant may change the manner in which the
Participant's Account is to be paid on Termination pursuant to Section
4.5 by filing a new
-4-
<PAGE> 7
election with the Company at any time, provided such new election will
not be given effect unless it is received by the Company at least one
year prior to the Participant's Termination. In addition, a
Participant may completely terminate the Participant's deferral
election at any time by giving written notice thereof to the Company,
provided that such termination shall only be effective for Compensation
earned by the Participant after the date such termination notice is
received by the Company. If a Non-Employee Director has not made a
deferral election with respect to a Plan Year, the Compensation payable
to him or her for that Plan Year shall be paid in accordance with the
Company's normal practices.
In addition to the foregoing deferrals, effective on and after
October 1, 1997, the amounts of Compensation previously deferred by
James Q. Riordan pursuant to a letter agreement with the Company dated
January 23, 1997, shall be governed by, and be credited to the
Participant's Account under, this Plan, which supersedes and replaces
such letter agreement in all respects.
4.2 Accounts. The Company shall establish a ledger or notional account (the
"Account") for each Non-Employee Director who has elected to defer
payment of all or part of his or her Compensation for the purpose of
reflecting the Company's obligation to pay to the Participant (or the
Participant's Beneficiary) the amount credited to such Account as
specified pursuant to Section 4.5.
4.3 Investment of Accounts. Unless, and to the extent, a Participant elects
to invest all or a specified portion of his or her Account in shares of
Phantom Stock as provided below, each Account shall automatically
accrue interest on the amount credited to such Account from the date
such amount is credited to the Account through the date of its
distribution. Such interest
-5-
<PAGE> 8
shall be credited to the Account at the end of each calendar quarter or
at such other times as may be determined by the Committee. The
Committee shall determine, in its sole discretion, the rate of interest
to be credited periodically to the Accounts, which may not be less than
the prime rate of interest from time to time as reported in The Wall
Street Journal; provided that any change in such rate may only be given
effect prospectively.
In lieu of having his or her Account credited with interest, a
Participant may direct that all or a specified percentage of his or her
deferred Compensation be invested in shares of Phantom Stock. In such
event, the Participant's Account shall be credited with whole and
fractional shares of Phantom Stock periodically as of the dates of the
deferrals, and with phantom dividends with respect to the Phantom
Stock, which shall be credited as being reinvested in additional shares
of Phantom Stock. All credits and debits of the Phantom Stock to an
Account shall be made based on the Fair Market Value per share of the
Common Stock on the applicable date. Notwithstanding the foregoing,
however, if the Company's Common Stock ceases to be readily tradeable
on a national securities market, effective therewith all then elections
under the Plan to invest in shares of Phantom Stock, including
elections with respect to existing Account balances, shall be
automatically canceled and all deferrals and Account balances after
such date shall be credited with interest as provided above.
4.4 Change in Investment Elections. Each Participant may elect at any time
or times, in a manner provided by the Company, to change the investment
of his or her future deferrals and/or the current investment of his or
her Account between shares of Phantom Stock and deferred cash credited
with interest. Such election change shall be given effect when
-6-
<PAGE> 9
received by the Company provided such transaction will be an exempt
"discretionary transaction" for purposes of Rule 16b-3.
4.5 Payment of Accounts. Upon a Participant's Termination or, the January 1
specified following such Termination, but not later than the fifth
January 1 subsequent to such Termination, as may be elected by the
Participant on a form received by the Company at least one year prior
to the Participant's Termination (the "Payment Date"), the Company
shall pay to such Participant an amount in cash equal to the balance
then credited to his or her Account as follows:
(a) a lump sum payment; or
(b) in substantially equal annual installments, not to exceed
10; whichever form of payment has been elected by the Participant and,
if in installments, the number of such installments elected by the
Participant. To the extent shares of Phantom Stock are credited to the
Account, "substantially equal" shall be determined by reference to the
number of such shares, not their value.
Payment of Accounts shall commence or be made on or as soon as
reasonably practical following the Participant's Payment Date.
Notwithstanding the foregoing, upon a Participant's death the balance
then credited to the Participant's Account shall be paid in a lump sum
to the Participant's Beneficiary as soon as reasonably practical
following the Participant's death.
-7-
<PAGE> 10
SECTION 5
GENERAL PROVISIONS
5.1 Unfunded Obligation. The amounts to be paid to Participants pursuant to
this Plan are unfunded obligations of the Company. The Company is not
required to segregate any monies from its general funds, to create any
trusts, or to make any special deposits with respect to this
obligation. Title to and beneficial ownership of any investments,
including trust investments, which the Company may make to fulfill
this obligation shall at all times remain in the Company. Any
investments and the creation or maintenance of any trust or notional
accounts shall not create or constitute a trust or a fiduciary
relationship between the Committee or the Company and a Participant,
or otherwise create any vested or beneficial interest in any
Participant or his or her Beneficiary or his or her creditors in any
assets of the Company whatsoever. The Participants (and Beneficiaries)
shall have no claim against the Company for any changes in the value
of any Accounts and shall be general unsecured creditors of the
Company with respect to any payment due under this Plan.
5.2 Incapacity of Participant or Beneficiary. If the Committee finds that
any Participant or Beneficiary to whom a payment is payable under the
Plan is under a legal disability, any payment due (unless a prior claim
therefore shall have been made by a duly appointed legal
representative) at the discretion of the Committee, may be paid to the
spouse, child, parent or brother or sister of such Participant or
Beneficiary. Any such payment shall be a complete discharge of the
obligations of the Company under the provisions of the Plan.
5.3 Nonassignment. The right of a Participant or Beneficiary to the payment
of any amounts under the Plan may not be assigned, transferred, pledged
or encumbered in any manner nor
-8-
<PAGE> 11
shall such right or other interests be subject to attachment,
garnishment, execution or other legal process.
5.4 Termination and Amendment. The Board may from time to time amend or
terminate the Plan, in whole or in part, and if the Plan is suspended
or terminated, the Board may reinstate any or all of its provisions.
The Committee may also amend the Plan; provided, however, it may not
terminate the Plan or substantially increase the obligations of the
Company under the Plan (provided, however, that the addition of new
phantom investments with respect to the Accounts shall not be deemed
an increase in the obligations of the Company under the Plan). No
amendment or termination of the Plan may impair the right of a
Participant or his or her Beneficiary to receive the benefit accrued
hereunder prior to the effective date of such amendment, suspension or
termination.
5.5 Compliance with Securities Laws. It is the intention of the Company
that, so long as any of the Company's equity securities are registered
pursuant to Section 12(b) or 12(g) of the Exchange Act, this Plan shall
be operated in compliance with Section 16(b).
5.6 Applicable Law. Except to the extent preempted by applicable federal
law, the Plan shall be construed and governed in accordance with the
laws of the State of Texas.
-9-
<PAGE> 1
EXHIBIT 21.1
THE HOUSTON EXPLORATION COMPANY
SUBSIDIARIES
Seneca Upshur Petroleum Company
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our report dated January 27, 1998 included in this Annual Report
on Form 10-K of The Houston Exploration Company for the year ended December 31,
1997 in the Registration Statement on Form S-8 of the Houston Exploration
Company (Registration No. 333-36977) filed October 1, 1997.
ARTHUR ANDERSEN LLP
New York, New York
February 6, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE COMBINED
FINANCIAL STATEMENTS OF THE HOUSTON EXPLORATION COMPANY SET FORTH IN THE
COMPANY'S FORM 10-K FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1997 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 4,745
<SECURITIES> 0
<RECEIVABLES> 39,201
<ALLOWANCES> 0
<INVENTORY> 1,265
<CURRENT-ASSETS> 45,856
<PP&E> 680,284
<DEPRECIATION> 236,546
<TOTAL-ASSETS> 491,391
<CURRENT-LIABILITIES> 51,257
<BONDS> 113,000
0
0
<COMMON> 234
<OTHER-SE> 255,953
<TOTAL-LIABILITY-AND-EQUITY> 256,187
<SALES> 116,349
<TOTAL-REVENUES> 117,646
<CGS> 0
<TOTAL-COSTS> 83,285
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<INTEREST-EXPENSE> 938
<INCOME-PRETAX> 33,423
<INCOME-TAX> 10,173
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