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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, 1998
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 77002-5219
(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 $162,321,697 as of March 22, 1999, based on the
closing sales price of the registrant's common stock on the New York Stock
Exchange on such date of $18.875 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 March
22, 1999, 23,895,040 shares of Common Stock were outstanding.
INCORPORATION OF DOCUMENTS BY REFERENCE
Portions of The Houston Exploration Company's definitive proxy statement
relating to the registrant's 1999 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, 1998, are
incorporated by reference into Part III of this Form 10-K.
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This Annual Report on Form 10-K contains "forward-looking statements"
within the meaning of Section 27A This Annual Report on Form 10-K contains
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1993 and Section 21E of the Securities Exchange Act of 1934. The words
"anticipate," "believe," "expect," "estimate," "project" and similar expressions
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 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. If one or more of these risks
or uncertainties materialize, or if underlying assumptions prove incorrect,
actual results may vary materially from those described in this Form 10-K. For
additional discussion of these 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
consolidated 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, South Louisiana, 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. Net proved reserves increased
at a compound annual rate of 41% from 121 Bcfe at December 31, 1993 to 480 Bcfe
at December 31, 1998. Annual production increased at a compound annual rate of
28% from 23 Bcfe in 1994 to 63 Bcfe in 1998. At the close of 1998, daily
production averaged 190 MMcfe per day. Natural gas and oil revenues increased
from $42 million in 1994 to $127 million in 1998. At December 31, 1998, net
proved reserves were 480 Bcfe with a discounted present value of cash flows
before income taxes ("PV-10%") of $413 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, 1998 were natural gas and
approximately 80% were classified as proved developed. The Company operates
approximately 90% of its production.
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 $0.26 per Mcfe
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of production and net general and administrative expenses of $0.10 per Mcfe of
production for the year ended December 31, 1998. 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
offshore natural gas and oil exploration drilling and development operations in
the Gulf of Mexico on behalf of The Brooklyn Union Gas Company ("Brooklyn
Union"). In February 1996, Brooklyn Union reorganized its exploration and
production assets and transferred to Houston Exploration its onshore producing
properties. Subsequent to the reorganization, the Company has expanded its focus
to include lower risk exploitation and development drilling on the onshore
properties transferred, in addition to seeking acquisitions both onshore and
offshore that primarily offer unexploited reserve potential and/or that are
located in existing core operating areas. The Company's current operations focus
offshore in the Gulf of Mexico and onshore in South Texas, South Louisiana, the
Arkoma Basin, East Texas and West Virginia.
In September 1996, the Company completed an initial public offering (the
"IPO") of 7,130,000 shares of Common Stock at $15.50 per share, resulting in net
cash proceeds of $101 million. As of December 31, 1998, THEC Holdings Corp., a
wholly owned subsidiary of Brooklyn Union, owned approximately 64% of the
outstanding shares of Common Stock. In May 1998, Brooklyn Union became a
subsidiary of MarketSpan Corporation, through the combination of Brooklyn
Union's parent company, KeySpan Energy Corporation ("KeySpan"), and Long Island
Lighting Company ("LILCO"). MarketSpan, a diversified energy provider doing
business as KeySpan Energy: (i) distributes natural gas, through its subsidiary
Brooklyn Union, to a customer base of 1.6 million in the New York City and Long
Island areas; (ii) is contracted by Long Island Power Authority ("LIPA") to
manage LIPA's electricity service in the Long Island area; and (iii) through its
unregulated subsidiaries, is involved in gas retailing, power plant management
and energy management services.
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: (i) added 554 Bcfe of
net proved reserves through exploration, acquisitions, and exploitation and
development; (ii) produced a total of 191 Bcfe; (iii) added total net proved
reserves due to extensions, discoveries and revisions equal to approximately
116% of cumulative production; (iv) added total net proved reserves, including
reserves added through acquisitions, equal to approximately 290% of cumulative
production. During 1998, the Company increased production by more than 22%, from
51 Bcfe in 1997 to 63 Bcfe in 1998.
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 10 exploratory wells in the Gulf
of Mexico in 1999. The successful completion of any one of these wells could
substantially increase the Company's reserves. Over the past five years, the
Company has drilled 19 successful exploratory wells and 14 successful
development wells in the Gulf of Mexico, representing a historical success rate
of 65%. 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 86 lease blocks,
representing 439,896 gross (355,129 net) acres, in federal and state waters in
the Gulf of Mexico, of which 27 are currently producing. The Company has a 100%
working interest in 52 of these lease blocks and a 50% or greater working
interest in 19 other lease blocks. The Company anticipates that approximately
$55 million of its $90 million 1999 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 attractive for future
exploration and development activities due to the availability of geologic data,
remaining reserve
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potential and the infrastructure of gathering systems, pipelines, platforms and
providers of drilling services and equipment. Based on 1998 annual production,
the Company's offshore reserves have a reserve to production ratio of 9.3 years.
At the end of 1998, average net production from the Company's Gulf of Mexico
properties was approximately 71 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, South Louisiana, the Arkoma Basin of Oklahoma and Arkansas, East
Texas and West Virginia. These properties account for approximately 61% of its
net proved reserves at December 31, 1998. 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 83 successful
development wells and 7 successful exploratory wells onshore representing a
historical drilling success rate of 78%. The Company has identified an extensive
inventory of more than 150 potential onshore drilling locations, of which
approximately 100 are located in the Charco Field in South Texas. The Company
anticipates that approximately $35 million of its $90 million 1999 capital
expenditure budget (excluding acquisitions) will be spent on onshore projects,
including the drilling of approximately 25 wells. Based on 1998 annual
production, the Company's onshore reserves have a reserve to production ratio of
6.8 years. At the end of 1998, average net production from the Company's onshore
properties was approximately 119 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. Since the acquisition of the Charco
Field in July of 1996, the Company has drilled 40 successful wells, added 79
Bcfe in reserves and produced 56 Bcfe. In April 1998, the Company acquired a new
core area of operations onshore in South Louisiana. The Company believes South
Louisiana is a natural extension from the Company's Gulf of Mexico operations as
the geology and 3-D geophysical applications are similar. In November 1998, the
Company acquired three producing offshore blocks in the Mustang Island area in
the Gulf of Mexico which are in close proximity to the Company's existing areas
of operation and technical expertise. The Company is currently drilling a
development well at Mustang Island A-32 to fully exploit the undeveloped reserve
potential of these recently acquired properties.
High Percentage of Operated Properties
The Company prefers to operate its properties in order to 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 production. Because of the recent sharp decline in
activity in the oil and gas industry and more favorable drilling rig rates, the
Company does not currently have any rigs under long-term contract. 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
$0.26 per Mcfe of production and net general and administrative expense of $0.10
per Mcfe of production for the year ended December 31, 1998.
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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 assembled a library of approximately 3,100 square miles of 3-D
seismic data, covering 3-D seismic surveys on the majority of its offshore lease
blocks and other possible lease and acquisition prospects, and approximately
76,000 linear miles of offshore 2-D seismic data. During 1998, the Company began
processing a 30 square mile block of 3-D seismic data acquired during 1997 and
1998 on acreage in Navarro County in East Texas and in January 1999, began
drilling its first exploratory well on the South Kerens Prospect. The Company
has 15 geologists and geophysicists with a combined average industry experience
of over 25 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 improved the Company's ability to identify exploration
and development prospects in its 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 these regions.
The Company currently operates in six areas of geographic concentration - the
Gulf of Mexico, South Texas, South Louisiana, the Arkoma Basin, East Texas, and
West Virginia - and continues to evaluate and may add additional core areas in
the future. During 1998, the Company added a new core area of operations onshore
in South Louisiana and acquired new offshore producing properties in the Mustang
Island area in close proximity to existing producing platforms and facilities.
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.
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, onshore in South Louisiana and the Company's other onshore
properties:
NET PROVED RESERVES
AS OF DECEMBER 31, 1998
<TABLE>
<CAPTION>
PERCENT OF GAS OIL TOTAL
TOTAL RESERVES (MMCF) (MBBLS) (MMCFE)
-------------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Gulf of Mexico.......................... 39% 183,486 1,016 189,582
Charco Field............................ 29% 136,819 58 137,167
South Louisiana......................... 13% 57,538 434 60,142
Other Onshore........................... 19% 92,604 142 93,456
----------- ----------- -----------
470,447 1,650 480,347
=========== =========== ===========
</TABLE>
RECENT ACQUISITIONS
South Louisiana Acquisition
On April 29, 1998, the Company completed the acquisition of certain
natural gas and oil properties and associated gathering pipelines and equipment,
together with developed and undeveloped acreage, located in South Louisiana. The
properties and acreage acquired are located primarily in the South Lake Arthur
and Lake Pagie Fields, located primarily in Vermilion Parish and Terrebonne
Parish, respectively, and currently contain 57 producing wells. As of December
31, 1998, these properties represented 60 Bcfe of proved reserves. The net
purchase price of $53.2 million was paid in cash, financed with borrowings under
the Company's Credit Facility.
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On October 16, 1998 and November 11, 1998, the Company completed the
acquisition of additional working interests in approximately 25 wells located in
the South Lake Arthur Field. The natural gas and oil properties acquired
consisted solely of incremental working interests in properties in which the
Company had previously acquired a working interest in April 1998. The combined
net purchase price of $24.8 million was paid in cash, financed with borrowings
under the Company's Credit Facility. The Company's working interests in these
South Louisiana properties average between 50% and 60%.
Chevron Acquisition
On November 30, 1998, the Company acquired from Chevron U.S.A. Inc. a 100%
working interest in Chevron's Mustang Island A-31 Field in the Gulf of Mexico.
The Mustang Island A-31 Field is comprised of three adjacent blocks: Mustang
Island A-22, A-31 and A-32. The field has nine producing wells and three
platforms. The properties acquired are in close proximity to five of the
Company's producing blocks in the Mustang Island area. As of December 31, 1998,
these properties represented 69 Bcfe of proved reserves. In addition to existing
operations in the Mustang Island area, the Company holds interests in 19
undeveloped blocks in this same area. The net purchase price of $84.9 million
was paid in cash, financed in part by borrowings under the a revolving credit
facility established with KeySpan. See Note 2 to the Company's Consolidated
Financial Statements.
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GULF OF MEXICO PROPERTIES
The Company holds interests in 86 offshore blocks, of which 27 are
currently producing. The Company operates 21 of these blocks, accounting for
approximately 82% 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 nine largest offshore properties as of December 31,
1998. These properties represent over 90% of the Company's Gulf of Mexico proved
reserves and 70% of its offshore production during 1998:
NET PROVED RESERVES AT DECEMBER 31, 1998
<TABLE>
<CAPTION>
AVERAGE
GAS OIL TOTAL WORKING
FIELD (MMCF) (MBBLS) (MMCFE) INTEREST OPERATOR
- --------------------------------------- ---------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C>
Mustang Island Block A-31/32........... 67,715 159 68,669 100.0% Company
East Cameron Blocks 82/83.............. 36,001 346 38,077 97.8% Company
Mustang Island Blocks 858/868.......... 13,825 237 15,247 79.0% Company
High Island Block 38................... 13,632 82 14,124 40.0% Third Party
West Cameron Blocks 76/77/60/61 Unit... 10,526 72 10,958 10.9% Third Party
Matagorda Island Block 651............. 8,319 5 8,349 79.6% Company
Mustang Island Block 807............... 6,896 19 7,010 100.0% Company
South Marsh Island 252/253............. 5,537 11 5,603 70.0% Company
Mustang Island Block 759............... 4,811 9 4,865 25.0% Third Party
All Other Gulf of Mexico (8 fields).... 16,224 76 16,680
---------- ---------- ----------
Total Gulf of Mexico................... 183,486 1,016 189,582
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</TABLE>
During 1998, the Company drilled two successful exploratory wells and one
successful development well on its Gulf of Mexico properties. During this same
period, the Company drilled five exploratory wells and one development well that
were not successful. Capital spending associated with the Company's Gulf of
Mexico properties during 1998 was $180.6 million, including $55.4 million for
exploratory drilling, $16.0 million for development drilling and $109.2 million
for property acquisitions and leasehold costs. During 1998, the Company acquired
the Mustang A-31/32 field for $84.9 million and additional working interests in
South Marsh Island 252/253 for $1.2 million.
During 1999, the Company intends to focus on exploratory drilling in the
Gulf of Mexico and plans to drill approximately 10 exploratory wells, along with
limited development drilling. The Company's planned exploratory projects are
located in Mustang Island Blocks 859, 842, A-113/114, 990 and 138/139, South
Padre Island Block 1030, Sabine Pass 16, South Timbalier Block 318 and Brazos
Block A-40. As of March 22, 1999, the Company was drilling or participating in
the drilling of one exploratory well, Mustang Island 859; two development wells:
one at West Cameron 76 and the other at Mustang Island A-32, and was
participating in the completion and installation of the production facilities at
Galveston Island 144, which was drilled in 1998. The following is a summary
description of the Company's exploration and development activity during 1998.
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 and two platforms. The Company began
drilling one exploratory well and one development well at the end of 1997. The
exploratory well was drilled to a target depth of 14,500 feet. The well was
logged and determined to be unproductive in January 1998 and was plugged. The
development well was drilled to a total depth of 13,500 feet. The Company was
unable to complete the well due to mechanical problems and the well plugged and
temporarily abandoned in February 1998.
East Cameron Blocks 82/83. The Company holds an average working interest
of 97.8% in East Cameron Blocks 82/83. The property currently has seven
producing wells. East Cameron 82 has three production caissons and East Cameron
83 has one platform and one caisson. During 1998, the Company drilled one
exploratory well, the East Cameron 83 #2 and one development well, East Cameron
83 #3. The East Cameron 83 #2 well began producing at the end of July 1998. The
East Cameron 83 #3 well and new production facilities were installed in the
fourth quarter of
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1998. Initial production began late November 1998; however, mechanical problems
and weather delayed bringing the well up to optimum producing capacity until the
second week of January 1999. Currently, East Cameron 82 and 83 are producing at
a combined rate of approximately 13,600 Mcfe/d, net to the Company's interest.
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 a flow rate of approximately 10,000 Mcfe/d, net to the
Company. In late July of 1998, the well experienced a gravel pack failure and
was shut-in. The operator, Burlington Resources, began a workover in late August
1998. Houston Exploration took over operation of the workover October 1998. The
Company has encountered mechanical difficulties and is currently continuing the
workover effort. If the recompletion of the well is successful, Houston
Exploration will obtain a 100% working interest in the lower productive zone and
will have a 40% working interest in the upper zones; however, the Company cannot
guarantee that it will be successful in the recompletion.
Mustang Island Block A-31/32. The Company began drilling an exploratory
well at Mustang Island A-32 in January 1998. The Company's working interest was
90% and the well was drilled to a total depth of 12,000 feet. The well was
logged in February 1998. The Company decided that completion and installation of
production facilities would be uneconomical and the well was temporarily
abandoned. However, since the completion of the Chevron Acquisition in November
1998, the Company is reconsidering the economics of completion of the well as it
is in close proximity to the newly acquired production facilities. The Mustang
Island A-31/32 complex currently has three platforms and nine producing wells.
Daily production currently averages approximately 30,000 Mcfe/d, net to the
Company's interest. The Company is currently drilling its first development
well, the B-8, from the platform at Mustang Island A-32 to fully exploit the
reserves acquired.
West Cameron Block 174. The Company has a 100% working interest in West
Cameron 174 and drilled one unsuccessful exploratory well during the second
quarter of 1998. The well was drilled to a total depth of 14,300 feet and no
commercially productive amounts of hydro-carbons were discovered.
Galveston Island 144. The Company participated in the drilling of two
exploratory wells at Galveston 144 during 1998. The first well, the #1, in which
the Company has a 33% working interest, was successfully drilled to a total
depth of 14,500 feet in May of 1998. Drilling began on the second well soon
after the #1 well was determined to be successful. The Company's working
interest in the #2 well is 50%. The #2 well reached its targeted objective in
mid-October 1998, but was determined to be unproductive and was plugged and
abandoned. In January 1999, the operator, Mariner Energy, began completion of
the #1 well and installation of the production facilities. Initial production is
expected at the beginning of the second quarter of 1999.
Mustang Island 862-L. The Company has a 100% working interest in Mustang
Island 862-L and drilled one unsuccessful exploratory well during the third
quarter of 1998. The well was drilled to a total depth of 13,000 feet and no
commercially productive amounts of hydro-carbons were discovered
West Cameron 76/77/60/61. The Company holds an average working interest of
10.6% in West Cameron 76/77. The property has two platforms and five producing
wells. The Company participated in the drilling of a deep directional test at
West Cameron 76 during 1998. The exploratory well was successfully drilled to a
total depth of 25,000 feet. The well was completed and tied into existing
production facilities in January of 1999 and is currently producing at a rate of
1,930 Mcfe/d, net to the Company. As soon as the exploratory well was completed,
drilling began on a development well in the same reservoir. The development well
is currently being completed at depth of approximately 16,500 feet. Initial
production is expected at the beginning of the second quarter of 1999.
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ONSHORE PROPERTIES
The Company also owns significant onshore natural gas and oil properties
in South Texas, South Louisiana, the Arkoma Basin of Oklahoma and Arkansas, East
Texas and West Virginia. These properties represent interests in 1,179 gross
(764 net) wells, approximately 84% of which the Company is the operator of
record, and 174,513 gross (125,595 net) acres.
The following table lists the Company's average working interest and net
proved reserves for its core onshore areas of operation as of December 31, 1998,
representing 99% of the Company's onshore reserves:
<TABLE>
<CAPTION>
NET PROVED RESERVES AT
DECEMBER 31, 1998
-------------------------------
AVERAGE
WORKING GAS OIL TOTAL
FIELD INTEREST (MMCF) (MBLS) (MMCFE)
----- -------- ------ ------ -------
<S> <C> <C> <C> <C>
Charco Field (South Texas)................................ 95% 136,819 58 137,167
South Lake Arthur and Lake Pagie (South Louisiana)........ 55% 57,538 434 60,142
Chismville/Massard Field (Arkansas)....................... 73% 50,918 -- 50,918
Wilburton, Panola and Surrounding Fields (Oklahoma)....... 23% 9,200 -- 9,200
Willow Springs and Surrounding Fields (East Texas)........ 53% 10,710 80 11,190
Appalachian Area (West Virginia).......................... 60% 21,776 62 22,148
</TABLE>
During 1998 the Company established a new core area of operations in South
Louisiana. The Company drilled or participated in the drilling of 23 successful
development wells and one successful exploratory wells on its onshore properties
during 1998. During this same period, the Company drilled or participated in the
drilling of four development wells that were not successful. Capital spending
associated with the Company's onshore drilling program during 1998 was
approximately $121.9 million, including $35.0 million for development, $0.2
million for exploration and $86.7 million for property acquisition and leasehold
costs. Onshore property acquisitions during 1998 included $78.0 million for the
entire South Louisiana Acquisition and $1.2 million for four additional wells
and related acreage in the Charco Field.
For 1999 the Company has budgeted funds to drill approximately 15 wells in
the Charco Field, three wells in South Louisiana, four wells in the Arkoma Basin
and two wells in East Texas. 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 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 from TransTexas
Gas Corporation and TransTexas Transmission Corporation. The Company owns a 95%
working interest in the approximately 195 active wells in the Charco Field, all
of which are operated by the Company. 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 running. During 1998 and 1997,
the Company successfully drilled 17 and 22, development wells, respectively, and
drilled a total of eight unsuccessful development wells. At year end 1998, the
Company's Charco Field properties had average production of 76,000 Mcfe/d, net
to the Company. Daily production is expected to increase as new development
wells are brought on-line. The Company is continuing its interpretation of 3-D
seismic data covering 148 square miles of its Charco Field properties.
Subsequent to year end, the Company has successfully drilled and completed two
development wells and is currently drilling two new development wells.
South Lake Arthur and Lake Pagie Fields. The South Lake Arthur Field is
located primarily in Vermilion Parish and the Lake Pagie Field is located
primarily in Terrebonne Parish, both in South Louisiana. The Company
-9-
<PAGE> 10
acquired the producing properties together with undeveloped acreage initially in
April 1998 and purchased additional interests in South Lake Arthur wells in
October and November 1998. The Company owns interests in 57 producing wells, of
which it operates 13 wells. Working interests in these wells range from 2% to
70% and average 55%. During 1998, the Company participated in one successful
development well with a working interest of 30%, located in Lake Pagie. At the
end of 1998, production from the South Louisiana properties averaged
approximately 12,000 Mcfe/d, net to the Company's interest. Subsequent to year
end 1998, the Company participated in the drilling of one unsuccessful
development well with a working interest of 30% and is currently participating
in the drilling of another development well with a working interest of 60%.
Chismville/Massard Field. The Chismville/Massard Field is located in Logan
and Sebastian Counties, Arkansas. The Company owns working interests in
approximately 154 active wells, of which it operates 80 wells. Working interests
in these wells range from 11% to 100% and average approximately 73%. During
1998, the Company successfully completed 4 gross (1.7 net) development wells and
participated in the drilling of one unsuccessful development well with a working
interest of 95%. Currently the Company is completing one successful development
well with a working interest of 82% and has plans to spud three additional wells
in the first quarter of 1999. At the end of 1998, production averaged 13,500
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 54 active wells, of which
it operates 20 wells. Working interests in these wells range from 3% to 100% and
average approximately 53%. At the end of 1998, production averaged 3,200 Mcfe/d,
net to the Company.
Wilburton, Panola and Surrounding Fields. The Wilburton and Panola Fields
are located in Latimer County, Oklahoma. The Company owns working interest in 48
active wells, of which it operates 15 wells. Working interests in these wells
range from 1% to 63% and average approximately 23%. During 1998, the Company
participated in the successful drilling of one development well in which it had
a working interest of 11%. Currently, the Company is participating in the
drilling of one development well, in which it has a small working interest of
0.8%. At of the year end 1998, 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 669 producing wells, substantially all of
which are operated by the Company. Working interests in these wells range from
6% to 100% and average approximately 60%. At year end 1998, production averaged
5,000 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 298,850 undeveloped gross
(269,346 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 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> 11
NATURAL GAS AND OIL RESERVES
The following table summarizes the estimates of the Company's historical
net proved reserves as of December 31, 1998, 1997 and 1996, and the present
values attributable to these reserves at such dates. The reserve data and
present values as of December 31, 1998 and 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 were prepared by NSA, Miller and Lents,
and Ryder Scott Company ("Ryder Scott").
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------------
1998 1997 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Net Proved Reserves(1):
Natural gas (MMcf)................................ 470,447 330,601 320,474
Oil (MBbls)....................................... 1,650 1,077 1,131
Total (MMcfe)..................................... 480,347 337,063 327,260
Present value of future net revenues before income
taxes(2)........................................... $412,933 $377,065 $577,000
Standardized measure of discounted future net cash
flows(3)........................................... $396,060 $315,380 $452,582
</TABLE>
- ---------------------------
(1) NSA and Miller and Lents prepared reserve data and present values with
respect to properties comprising approximately 68% and 32%, respectively,
of the present values attributable to the Company's proved reserves as of
December 31, 1998, and 73% and 27%, respectively, of the present values
attributable to the Company's proved reserves as of December 31, 1997.
NSA, Miller and Lents and Ryder Scott prepared reserve data and present
values with respect to properties comprising approximately 47%, 30% and
23%, respectively, of the present values attributable to the Company's
proved reserves as of December 31, 1996.
(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, 1998, 1997 and 1996 were $1.83, $2.31
and $3.41, respectively. Average prices per Bbl of oil used in making such
present value determinations as of December 31, 1998, 1997 and 1996 were
$10.65, $17.23 and $22.94, 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.
-11-
<PAGE> 12
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company on
its properties for the years ended December 31, 1998, 1997 and 1996.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------
1998 1997 1996
--------------------- --------------------- ---------------------
GROSS NET GROSS NET GROSS NET
------- -------- -------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
OFFSHORE DRILLING ACTIVITY:
Exploratory:
Productive..................... 2 1.3 6 3.7 6 4.2
Non-Productive................. 5 4.2 3 2.3 4 2.2
------- -------- -------- ------- ------- --------
Total..................... 7 5.5 9 6.0 10 6.4
Development:
Productive..................... 1 1.0 1 0.2 1 0.5
Non-Productive................. 1 0.8 1 0.8 -- --
------- -------- -------- ------- ------- --------
Total..................... 2 1.8 2 1.0 1 0.5
ONSHORE DRILLING ACTIVITY:
Exploratory:
Productive..................... 1 0.3 2 0.1 1 0.1
Non-Productive................. -- -- 2 0.6 3 2.2
------- -------- -------- ------- ------- --------
Total..................... 1 0.3 4 0.7 4 2.3
Development:
Productive..................... 23 18.2 33 29.1 9 6.5
Non-Productive................. 4 3.8 8 7.7 1 1.0
------- -------- -------- ------- ------- --------
Total..................... 27 22.0 41 36.8 10 7.5
</TABLE>
PRODUCTIVE WELLS
The following table sets forth the number of productive wells in which the
Company owned an interest as of December 31, 1998.
<TABLE>
<CAPTION>
COMPANY COMPANY OPERATED WELLS NON-OPERATED WELLS TOTAL PRODUCTIVE WELLS
OPERATED ---------------------- -------------------- ----------------------
PLATFORMS GROSS NET GROSS NET GROSS NET
--------- ------- ------- -------- -------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
OFFSHORE
Gas............ 21 53 39.5 11 2.2 64 41.7
Oil............ -- -- -- 4 0.5 4 0.5
------- ------- ------- -------- -------- -------- ---------
Total.......... 21 53 39.5 15 2.7 68 42.2
======= ======= ======== ======== ======== ======== =========
ONSHORE
Gas............ 986 719 205 54.2 1,175 761.3
Oil............ 2 1.9 2 0.5 4 2.4
------- -------- -------- -------- -------- ---------
Total.......... 988 720.9 207 54.7 1,179 763.7
======= ======== ======== ======== ======== =========
</TABLE>
Productive wells consist of producing wells capable of production,
including gas wells awaiting connections. Wells that are completed in more that
one producing horizon are counted as one well.
-12-
<PAGE> 13
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, 1998. 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 or 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)........... 141,046 85,783 298,850 269,346
Onshore............... 156,314 112,119 18,199 13,476
------------- ------------- ------------- -------------
Total........ 297,360 197,902 317,049 282,822
============= ============= ============= =============
</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. As
is the nature of the exploration, development and production business,
production is normally sold to relatively a small number of customers. However,
based on the current demand for natural gas and oil, the Company believes that
the loss of any of the Company's major purchasers would not have a material
adverse effect on the Company. The Company sold natural gas and oil production
representing 10% or more of its natural gas and oil revenues as follows: for the
year ended December 31, 1998 to H&N Gas Ltd. (27%) and Columbia Energy Services
Corporation (12%); for the year ended December 31, 1997 to H&N Gas Ltd. (38%),
and for the year ended December 31, 1996 PennUnion Energy Services, L.L.C.
("PennUnion")(40%) and H&N Gas Ltd. (27%). During the first three quarters of
1996, PennUnion was an affiliate of Brooklyn Union. The gas sales agreement with
PennUnion was terminated in October 1996 when Brooklyn Union sold its interest
in PennUnion. The gas production sold to PennUnion was sold at market prices,
based upon an index price adjusted to reflect the point of delivery of such
production. The Company believes that the prices at which it sold gas to
PennUnion were similar to those it would have been able to obtain in the open
market.
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
Item 7. "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 the facilities or
due to use 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
- -- Hazard Losses May Not be Insured."
ABANDONMENT COSTS
The Company is responsible for its working interest share of costs to
abandon natural gas and oil properties and facilities. The Company provides for
its expected future abandonment liabilities by accruing for abandonment costs as
a component of depletion, depreciation and amortization as the properties are
produced. As of December 31, 1998, total undiscounted abandonment costs
estimated to be incurred through the year 2010 were approximately $20 million
for properties in the federal and state waters and are not considered
significant for onshore properties. Estimates 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.
-13-
<PAGE> 14
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.
-14-
<PAGE> 15
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in
drilling for, producing and transporting of natural gas and oil. These hazards
and risks include: 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, the Company's natural gas and oil operations located in the Gulf
of Mexico are 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 liability 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 a material 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, 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.
Because such laws and regulations are frequently expanded, amended and
reinterpreted, the Company cannot predict the future cost or impact of complying
with such laws and 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
-15-
<PAGE> 16
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 in certain instances 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 court of appeal,
the cases have generally been completed.
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. The Supreme Court denied a writ of
certiorari of the D.C. Circuit's order.
On remand, in Order No. 636-C, the FERC reaffirmed certain holdings of
Order No. 636 and revised others. In particular, the FERC reaffirmed that
pipelines should be entitled to recover 100 percent of their prudently incurred
GSR costs, but changed the requirement that interruptible customers be allocated
10 percent of a pipeline's GSR costs. Instead, FERC required pipelines to
propose a percentage related to an interruptible customer's individual
circumstances. 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. Finally, FERC reaffirmed its decision to determine downstream customers'
eligibility for an upstream pipeline's small-customer rate on a case-by-case
basis.
In Order No. 636-D, the FERC denied rehearing of Order No. 636-C and
clarified the impact of adopting a five-year cap for the right-of-first-refusal
mechanism. The FERC found that a party seeking relief from a long-term
-16-
<PAGE> 17
contract entered into before Order No. 636-C must show it entered into a longer
term contract because of the twenty- year cap.
Although Order No. 636 does not regulate natural gas producers such as the
Company, the FERC has stated that Order 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 effected by Order No. 636 and its progeny any
differently than other natural gas producers and marketers with which the
Company 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 incentive rates and
negotiated rates for individual shippers of natural gas so long as a
cost-of-service-based rate also is available. In conjunction with the policy
statement on negotiated rates, the FERC also established a separate proceeding
to receive comments on whether it should allow gas pipelines the flexibility to
negotiate the terms and conditions of transportation service with prospective
shippers. The FERC received the requested industry comments, but a final order
in this proceeding is still pending.
In addition, in July 1996 the FERC commenced a reexamination of certain of
its transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate capacity under Order No. 636 for resale
in the secondary markets. The FERC also attempted to establish an experimental
pilot program to permit shippers to release capacity and pipelines to sell
interruptible and short-term firm capacity in certain markets above the
pipeline's maximum tariff rate. The FERC's final evaluation of the secondary
market is still pending.
In July 1998, the FERC initiated a rulemaking proceeding that revisits the
FERC's pending proceedings on negotiated terms and conditions and capacity
release in the secondary markets. Specifically, the rulemaking examines the
regulation of the short-term natural gas transportation services. Based upon an
expressed effort to maximize the competition and efficiency in the short-term
transportation market and prevent the exercise of market power, the FERC
proposed to remove the price cap in the short-term market and implement certain
initiatives. These initiates include establishing an auction process for the
allocation of available short-term firm, interruptible and released capacity,
the segmentation and flexibility in receipt and delivery points, modified
reporting requirements, and permitting purchasers of released capacity to submit
a nomination at the first available opportunity after consummation of the
transaction. In addition, the rulemaking proposes the negotiation of rates and
terms and conditions of service to the extent it is not unduly discriminatory or
degrades existing services. Finally, the rulemaking examines the FERC's
certificate policy. The FERC has held industry workshops on the proposed
pipeline capacity auction process, and extended the deadline for interested
parties to submit comments on the rulemaking.
The FERC also established a companion Notice of Inquiry on the regulation
of interstate natural gas transportation services. In this proceeding, the FERC
is looking at the pricing policies of the long-term market. Specifically, the
FERC is considering whether other methods of cost-based ratemaking (i.e. index
rates, incentive rates) would be more appropriate than the traditional
cost-of-service model, and whether the use of market-based rates for turnback
capacity should be authorized. In addition, the FERC seeks comments relating to
the pricing policies for new capacity. The Company cannot predict what action
the FERC will take on all of these matters, nor can it accurately predict
whether the FERC's actions will achieve the goal of increasing the 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 the Company competes.
The FERC has also issued a policy statement concerning the manner in which
interstate natural gas pipelines 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 is designed to
enhance competition in natural
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<PAGE> 18
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 by either "spun down" to an
affiliate or "spun off" to a non-affiliate) by intestate pipeline companies
after Order No. 636. Specifically, the FERC has approved proposals by a number
of interstate pipelines to spin down or spin off 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 a Company and the Company cannot predict what further
action the FERC will take in this regard.
In September 1998, the FERC initiated two proceedings to streamline its
regulations governing construction applications for natural gas pipelines. In
the first proceeding, the FERC proposed to revise its certificate regulations to
increase the scope of blanket certificates (i.e. temporary compression
stations), facilitate the construction of receipt points, and codify less
cumbersome environmental filing requirements and procedures. In the second
proceeding, the FERC proposed to offer pipelines the option of entering a
voluntary collaborative process with the public and FERC staff to expedite the
processing of certificate applications and to reduce potential conflicts. 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 the Company competes.
In 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. The Commission dismissed
all requests for rehearing of its Policy Statement.
In 1997, the Fifth Circuit Court of Appeals 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.
In 1998, the FERC issued a Notice of Inquiry to assist in responding to
the Fifth Circuit's decision. Specifically, the Inquiry asked parties to comment
and provide information on other methods of regulating Outer Continental Shelf
facilities under the NGA and OGSLA, including alternatives to the current
"primary function" test. The FERC has not issued a final order in the
proceeding. It is not clear, therefore, 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. The Company, however, does not believe that
it will be affected by any action taken materially differently than other
natural gas producers and marketers with which the Company competes.
In Order Nos. 587, 587-B, and 587-C the FERC revised its 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. In particular, the amended regulations provided
standards that required pipelines to conduct business transactions over the
Internet and to provide general information electronically. For example, the
orders established protocols and procedures for exchanging files over the
Internet, adopted standards requiring interstate pipelines to publish certain
information on Internet web pages, and implemented new business practice
standards dealing with nominations and flowing gas. In addition, the FERC
incorporated into its regulations GISB's intra-day nominations standards. In
subsequent orders, the FERC adopted additional standards
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<PAGE> 19
unable to be resolved by GISB that would, inter alia, govern operational
balancing agreements, netting and trading of imbalances, standardization of
communications over the public Internet, and notices of operational flow orders.
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 No. 587, et seq., and an
appeal of Order No. 587 was dismissed before 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 the Company 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
proposal 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 maybe 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 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
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<PAGE> 20
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 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, these 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.
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<PAGE> 21
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.
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
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<PAGE> 22
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.
RISK FACTORS
THE VOLATILITY OF NATURAL GAS AND OIL PRICES MAY AFFECT OUR FINANCIAL
RESULTS.
As an independent natural gas and oil producer, revenues generated from
our operations are highly dependent on the price of, and demand for, natural gas
and oil. Even relatively modest changes in oil and natural gas prices may
significantly change our revenues, results of operations, cash flows and proved
reserves. Historically, the markets for natural gas and oil have been volatile
and are likely to continue to be volatile in the future. Prices for natural gas
and oil are subject to wide fluctuation in response to relatively minor changes
in the supply of and demand for natural gas and oil, market uncertainty and a
variety of additional factors that are beyond our control, such as:
o the level of consumer product demand;
o weather conditions;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political and economic conditions in the Middle East, Asia,
Russia, and South America;
o the foreign supply of natural gas and oil;
o the price of foreign imports; and
o overall domestic and global economic conditions.
We cannot predict future natural gas and oil price movements. If natural
gas and oil prices decline, the amount of natural gas and oil we can
economically produce may be reduced.
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<PAGE> 23
WE MAY INCUR ADDITIONAL WRITEDOWNS IF GAS AND OIL PRICES REMAIN DEPRESSED
Primarily as a result of weak natural gas prices, we were required under
full cost accounting rules to write down the carrying value of our natural gas
and oil properties at December, 31, 1998. We incurred a $130.0 million non-cash
charge, $84.5 million after taxes. As a result of the continued volatility of
natural gas prices during the first quarter of 1999, we may be required to write
down the carrying value of our natural gas and oil assets at the end of the
first quarter of 1999, depending upon natural gas prices at the end of the
quarter and the results of our drilling programs.
WE MAY NOT BE ABLE TO MEET OUR SUBSTANTIAL CAPITAL REQUIREMENTS.
Our business is capital intensive and, to maintain our base of proved oil
and gas reserves, a significant amount of cash flow from operations must be
invested in property acquisitions, development and exploration activities. We
make substantial capital expenditures for the exploration, development,
acquisition and production of natural gas and oil reserves. Historically, we
have financed these expenditures primarily from the following sources:
o cash generated by operations;
o bank borrowings;
o equity and debt offerings; and
o loans and capital contributions from KeySpan.
Our capital expenditure budget for exploration, development and leasehold
acquisitions for 1999 is estimated at approximately $90 million. This budget
excludes potential producing property acquisitions. Our management believes that
we will have sufficient cash provided by operating activities and borrowings
under our bank credit facility and the KeySpan credit facility to fund planned
capital expenditures in 1999. If our revenues or borrowing base under the bank
credit facility decrease as a result of lower natural gas and oil prices,
operating difficulties or declines in reserves, we may not be able to expend the
capital necessary to undertake or complete future drilling programs or
acquisition opportunities. Without continued employment of capital, our oil and
gas reserves will decline. We may not be able to obtain additional debt or
equity financing or generate cash from operations to meet our future capital
requirements.
THE AMOUNT OF OUR OUTSTANDING INDEBTEDNESS IS SUBSTANTIAL AND COULD HAVE
ADVERSE CONSEQUENCES.
Our outstanding indebtedness at December 31, 1998 was $313 million and as
of March 22, 1999 has increased to $320 million. Our level of indebtedness
affects our operations in a number of ways. Our bank credit facility, the
indenture governing our senior subordinated notes and the KeySpan Facility
contain covenants that require a substantial portion of our cash flow from
operations to be dedicated to the payment of interest on our indebtedness.
Accordingly, these funds will not be available for other purposes. Other
covenants in these agreements require us to meet certain financial tests and
establish other restrictions that limit our ability to borrow additional funds
or dispose of assets and may affect our flexibility in planning for, and
reacting to, changes in business conditions. Moreover, future acquisition and
development activities may require us to significantly alter our capitalization
structure, which may alter our indebtedness. Our ability to meet our debt
service obligations and reduce our total indebtedness will depend upon our
future performance. Our future performance, in turn, is dependent upon many
factors that are beyond our control such as general economic, financial and
business conditions. We cannot guarantee that our future performance will not be
adversely affected by such economic conditions and financial, business and other
factors.
ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUE MAY CHANGE.
The estimates of proved reserves of natural gas and oil included in this
document are based on various assumptions. The accuracy of any reserve estimate
is a function of the quality of available data and engineering and geological
interpretation and judgment and the assumptions used regarding quantities of
recoverable natural gas and
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<PAGE> 24
oil reserves and prices for crude oil, natural gas liquids and natural gas.
Actual prices, production, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves will vary from those
assumed in our estimates, and such variances may be significant. Any significant
variance from the assumptions used could result in the actual quantity of our
reserves and future net cash flow being materially different from the estimates
in our reserve reports. In addition, results of drilling, testing and production
and changes in crude oil, natural gas liquids and natural gas prices after the
date of the estimate may result in substantial upward or downward revisions.
WE MAY NOT BE ABLE TO REPLACE RESERVES.
Without successful exploration, development or acquisition activities, our
reserves and revenues will decline over time. Exploration, the continuing
development of reserves and acquisition activities will require significant
expenditures. If our cash flow from operations is not sufficient for this
purpose, we may not be able to obtain the necessary funds from other sources.
The inability to replace reserves could reduce the amount of credit available to
us since the maximum amount of borrowing capacity available under our bank
credit facility is based, at least in part, on the estimated quantities of our
proved reserves.
HAZARD LOSSES MAY NOT BE INSURED.
The natural gas and oil business involves many types of operating and
environmental hazards and risks. We are insured against some, but not all, of
the hazards associated with our business. We believe this is standard practice
in our industry. Because of this practice, however, we may be subject to
liability or losses that could be substantial due to events that are not
insured.
OUR ACQUISITION AND INVESTMENT ACTIVITIES MAY NOT BE SUCCESSFUL.
The successful acquisition of producing properties requires assessment of
reserves, future commodity prices, operating costs, potential environmental and
other liabilities and other factors. These assessments may not be accurate. We
review the properties we intend to acquire in a fashion that we believe is
generally consistent with industry practice. This review typically includes
on-site inspections and the review of environmental compliance reports filed
with the Minerals Management Service. This review, however, will not reveal all
existing or potential problems nor will it permit us to become sufficiently
familiar with the properties to fully assess their deficiencies and
capabilities. Inspections may not always be performed on every platform or well,
and structural or environmental problems may not be observable even when an
inspection is undertaken. Accordingly, we may suffer the loss of one or more
acquired properties due to title deficiencies or may be required to make
significant expenditures to cure environmental contamination with respect to
acquired properties. Even when problems are identified, the seller may be
unwilling or unable to provide effective contractual protection against all or
part of the problems. We are generally not entitled to contractual
indemnification for environmental liabilities and we typically acquire
structures on a property on an "as is" basis.
WE ARE SUBJECT TO RISKS RELATED TO OUR HEDGING ACTIVITIES
Periodically, we enter into hedging arrangements relating to a portion of
our natural gas production to achieve a more predicable cash flow, as well as to
reduce our exposure to adverse price fluctuations of natural gas. Hedging
instruments used are fixed price swaps, collars and options. While the use of
these types of hedging instruments limits the downside risk of adverse price
movements, they are subject to a number of risks, including instances in which:
o the benefit to revenues is limited when natural gas prices
increase; and
o counterparties to our futures contract will be unable to meet the
financial terms of the transaction.
WE MAY INCUR SUBSTANTIAL COSTS TO COMPLY WITH ENVIRONMENTAL AND OTHER
GOVERNMENTAL REGULATIONS.
Environmental and other governmental regulations have increased the costs
to plan, design, drill, install, operate and abandon oil and natural gas wells,
offshore platforms and other facilities. We have expended and continue
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<PAGE> 25
to expend significant resources, both financial and managerial, to comply with
environmental regulations and permitting requirements. Increasingly strict
environmental laws, regulations and enforcement policies thereunder, and claims
for damages to property, employees, other persons and the environment resulting
from our operations, could result in substantial costs and liabilities in the
future.
WE FACE STRONG COMPETITION.
As an independent natural gas and oil producer, we face strong competition
in all aspects of our business. Many of our competitors are large,
well-established companies that have substantially larger operating staffs and
greater capital resources than we do. These 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 our financial and human resources permit.
POTENTIAL CONFLICTS OF INTEREST WITH KEYSPAN.
Conflicts of interest may arise in the future between us and KeySpan, who
owns 64% of our common stock, in a number of areas relating to our past and
ongoing relationships, including the following:
o the payment of dividends;
o acquisitions of natural gas and oil businesses properties;
o transfers of assets;
o insurance matters;
o financial commitments;
o registration rights; and
o issuances and sales our capital stock.
Our Chairman of the Board, Robert B. Catell, is also the Chairman of the
Board of Directors and Chief Executive Officer of KeySpan. In addition, two of
our directors are also affiliated with KeySpan: Craig G. Matthews is President
and Chief Operating Officer of KeySpan and James Q. Riordan is a director of
KeySpan. As a result of KeySpan's ownership of 64% of our common stock, KeySpan
is in a position to control the election of the entire Board of Directors of
Houston Exploration and is able to control the outcome of the vote on all
matters requiring the vote of our stockholders.
EMPLOYEES
As of December 31, 1998, the Company had 111 full time employees, 70 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 46,000 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.
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<PAGE> 26
ITEM 3. LEGAL PROCEEDINGS
The Company is not a party to any material 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, 1998.
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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 January 1, 1997 through December 31,
1998 as reported on the New York Stock Exchange:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997 HIGH LOW
--------- --------
<S> <C> <C>
First Quarter......................................... $ 18.88 $ 11.50
Second Quarter........................................ 16.00 11.88
Third Quarter......................................... 23.19 15.25
Fourth Quarter........................................ 27.25 17.50
YEAR ENDED DECEMBER 31, 1998 HIGH LOW
First Quarter......................................... $ 22.25 $ 15.25
Second Quarter........................................ 24.31 20.19
Third Quarter......................................... 24.25 14.44
Fourth Quarter........................................ 19.88 16.44
</TABLE>
As of March 22, 1999, 23,895,040 shares of Common Stock were outstanding
and the Company had approximately 57 shareholders of record and approximately
1,655 beneficial owners.
DIVIDENDS
The Company has not paid any cash dividends during the two most recent
fiscal years and does not anticipate declaring any dividends in the foreseeable
future. The Company expects that it will retain its cash for the operation and
expansion of its business, including exploration, development and acquisition
activities. The Company's bank credit facility and the indenture governing the
8 5/8% Subordinated Notes contain restrictions on the payment of dividends to
holders of Common Stock. Accordingly, the Company's ability to pay dividends
will depend upon these 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."
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below with respect to the Company's
consolidated statements of operations for each of the five years in the period
ended December 31, 1998 and with respect to the Company's consolidated balance
sheets as of December 31, 1998, 1997, 1996, 1995 and 1994 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 Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's Consolidated Financial
Statements and Notes thereto included elsewhere and incorporated by reference in
this Annual Report on Form 10-K.
-27-
<PAGE> 28
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Revenues:
Natural gas and oil revenues ................ $ 127,124 $ 116,349 $ 64,864 $ 39,431 $ 41,755
Other ....................................... 1,123 1,297 1,040 1,778 467
--------- --------- --------- --------- ---------
Total revenues ........................ 128,247 117,646 65,904 41,209 42,222
Expenses:
Lease operating ............................. 16,199 14,146 10,800 5,005 4,858
Severance tax ............................... 4,967 4,233 1,401 463 486
Depreciation, depletion and amortization .... 79,838 59,081 33,732 21,969 25,365
Writedown in carrying value ................. 130,000 -- -- -- --
General and administrative, net ............. 6,086 5,825 6,249 3,486 3,460
Nonrecurring charge(1) ...................... -- -- -- 12,000 --
--------- --------- --------- --------- ---------
Total operating expenses .............. 237,090 83,285 52,182 42,923 34,169
Income (loss) from operations ................. (108,843) 34,361 13,722 (1,714) 8,053
Interest expense, net ......................... 4,597 938 2,875 2,398 2,102
--------- --------- --------- --------- ---------
Income (loss) before income taxes ............. (113,440) 33,423 10,847 (4,112) 5,951
Income tax provision (benefit) ................ (40,754) 10,173 2,205 (3,809) 597
--------- --------- --------- --------- ---------
Net income (loss) ............................. $ (72,686) $ 23,250 $ 8,642 $ (303) $ 5,354
========= ========= ========= ========= =========
Net income (loss) per share ................... $ (3.05) $ 1.00 $ 0.49 $ (0.02) $ 0.35
========= ========= ========= ========= =========
Net income (loss) per share--diluted .......... $ (3.05) $ 0.97 $ 0.49 $ (0.02) $ 0.35
========= ========= ========= ========= =========
Weighted average shares ....................... 23,768 23,337 17,532 15,295 15,295
Weighted average shares--diluted .............. 23,768 24,028 17,687 15,295 15,295
</TABLE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
CONSOLIDATED BALANCE SHEET DATA:
Property, plant and equipment, net ............ $ 536,582 $ 443,738 $ 359,124 $ 216,678 $ 169,714
Total assets .................................. 569,452 491,391 401,285 247,496 201,678
Long-term debt and notes ...................... 313,000 113,000 65,000 71,862 65,650
Stockholders' equity .......................... 192,530 256,187 233,300 103,236 88,866
</TABLE>
- ----------------------
(1) Represents a nonrecurring non-cash charge incurred in connection with
Brooklyn Union's February 1996 reorganization of its exploration and
production assets. The $12 million non-cash charge represents remuneration
to which certain employees of Fuel Resources Inc. (a subsidiary of Brooklyn
Union) were entitled for the increase in the value of the properties
transferred to Houston Exploration pursuant to the reorganization. See
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
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, 1998. The Company's historical
consolidated 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.
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<PAGE> 29
GENERAL
The Company was incorporated in Delaware in December 1985 to conduct
offshore natural gas and oil exploration drilling and development operations in
the Gulf of Mexico on behalf of The Brooklyn Union Gas Company ("Brooklyn
Union"). In February 1996, Brooklyn Union reorganized its exploration and
production assets and transferred to Houston Exploration its onshore producing
properties. Subsequent to the reorganization, the Company has expanded its focus
to include lower risk exploitation and development drilling on the onshore
properties transferred, in addition to seeking acquisitions both onshore and
offshore that primarily offer unexploited reserve potential and/or that are
located in existing core operating areas. The Company's current operations focus
offshore in the Gulf of Mexico and onshore in South Texas, South Louisiana, the
Arkoma Basin, East Texas and West Virginia. At December 31, 1998, the Company
had net proved reserves of 480 Bcfe, 98% of which were natural gas and 80% of
which were classified as proved developed.
In September 1996, the Company completed an initial public offering (the
"IPO") of 7,130,000 shares of Common Stock at $15.50 per share, resulting in net
cash proceeds of $101 million.. As of December 31, 1998, THEC Holdings Corp., a
wholly owned subsidiary of Brooklyn Union, owned approximately 64% of the
outstanding shares of Common Stock. In May 1998, Brooklyn Union became a
subsidiary of MarketSpan Corporation through the combination of Brooklyn Union's
parent company, KeySpan Energy Corporation ("KeySpan"), and Long Island Lighting
Company ("LILCO"). MarketSpan, a diversified energy provider doing business as
KeySpan Energy: (i) distributes natural gas, through its subsidiary Brooklyn
Union, to a customer base of 1.6 million in the New York City and Long Island
areas; (ii) is contracted by Long Island Power Authority ("LIPA") to manage
LILPA's electricity service in the Long Island area; and (iii) through its
unregulated subsidiaries, is involved in gas retailing, power plant management
and energy management services.
As an independent oil and gas producer, 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 very volatile, as evidenced by the recent
volatility of natural gas and oil prices, and there can be no assurance that
commodity prices will not be subject to wide fluctuations in the future. A
substantial or extended decline in natural gas and oil prices could have a
material adverse effect on the Company's financial position, results of
operations, cash flows, 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, 1998, the Company estimates, using a December wellhead
price of $1.83 per Mcf, that actual capitalized costs of natural gas and oil
properties exceeded the ceiling limitation imposed under full cost accounting
rules by approximately $41.2 million, after taxes. Subsequent to December 31,
1998, natural gas prices continued to decline, such that the Company estimates,
using a February wellhead price of $1.61 per Mcf, that the ceiling limitation
exceeded actual capitalized costs of natural gas and oil properties by
approximately $84.5 million, after taxes. As a result, the Company reduced the
carrying value of its natural gas and oil properties as of December 31, 1998, by
$84.5 million, after taxes. Given the continued volatility of natural gas prices
during the first quarter of 1999, 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 1999, depending upon natural gas prices and the results of the
Company's drilling programs.
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<PAGE> 30
New Accounting Pronouncements. In June 1998, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities." This statement broadens the definition of a derivative instrument
and establishes accounting and reporting standards requiring that every
derivative instrument be recorded on the balance sheet as either an asset or
liability measured at its fair market value. Derivatives that are not hedges
must be adjusted to fair value currently in earnings. If a derivative is a
hedge, depending on the nature of the hedge, special accounting allows changes
in fair value of the derivative to be either offset against the change in fair
value of the hedged asset or liability in the income statement or recorded in
comprehensive income until the hedged item is recognized in earnings. The
Company must formally document, designate and assess the effectiveness of
transactions that are recorded as hedges. The ineffective portion of a
derivative's change in fair value will be immediately recognized in earnings.
The Company plans to adopt SFAS No. 133 effective January 1, 2000. Currently,
the Company cannot estimate the impact of the statement on results of future
operations; however, it believes that the impact will not be material.
Year 2000. Year 2000 issues result from the inability of computer programs
or computerized equipment to accurately calculate, store or use a date
subsequent to December 31, 1999. The erroneous date can be interpreted in a
number of different ways; typically the year 2000 is represented as the year
1900. This could result in a system failure or miscalculations causing
disruptions of operations, including, among other things, a temporary inability
to process transactions, send invoices or engage in normal business.
To ensure Year 2000 compliance, the Company has implemented a plan to
review all financial and operational systems and equipment involving a four
phase process: assessment, remediation and replacement, testing and
implementation. To date, the assessment phase has been fully completed, and the
Company is currently in the remediation phase which is approximately 75%
complete. The Company plans to begin testing systems and equipment during the
first quarter of 1999. Once testing is complete, systems will be ready for
immediate use. The Company expects testing and implementation to be
substantially complete by June 30, 1999. As of December 31, 1998, the Company
had incurred approximately $20,000 in expenses related to its Year 2000
compliance efforts. Year 2000 costs are currently being expensed as they are
incurred. However, in certain instances the Company may determine that replacing
existing equipment would be more efficient and the costs of these replacements
would then be capitalized. The Company currently expects that it will incur an
additional $100,000 in costs or expenses during 1999 to become Year 2000
compliant. The Company believes that total costs to become Year 2000 compliant
will not exceed $500,000 and that such costs will not have a material adverse
effect on the Company's financial condition, operations or liquidity.
The foregoing timetable and assessment of costs to become Year 2000
compliant reflect management's current best estimates. These estimates are based
on many assumptions, including assumptions about the cost, availability and
ability of resources to locate, remediate and modify affected systems and
equipment. Based upon its activities to date, the Company does not believe that
these factors will cause results to differ significantly from those estimated.
However, the Company cannot reasonably estimate the potential impact on its
financial condition and operations if key third parties including, among others,
suppliers, contractors, joint venture partners, financial institutions,
customers, traders, and governments do not become Year 2000 compliant on a
timely basis. The Company is in the process of contacting many of these third
parties to determine the extent to which the Company is vulnerable to those
third parties' potential failure to remediate their own Year 2000 issues. The
Company expects its survey of key third parties to be fully complete by June 30,
1999.
The Company currently has no contingency plans in place in the event it
does not complete all phases of its Year 2000 program. The Company plans to
evaluate the status of completion of the Year 2000 compliance process by the end
of the second quarter of 1999 and determine whether such a contingency plan is
necessary.
In the event the Company is unable to complete the remediation or
replacement of critical computer software and equipment, establish alternative
procedures in a timely manner, or if those with whom the Company conducts
business are unsuccessful in implementing timely solutions, Year 2000 issues
could result in an interruption in, or a failure of certain normal business
activities that could result in a material adverse effect on the Company's
results of operations, liquidity and financial position. The Company's
remediation efforts are expected to reduce the Company's level of uncertainty
about Year 2000 compliance and the possibility of interruption of normal
operations. The Company
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<PAGE> 31
believes that the potential impact, if any, of its systems not being year 2000
compliant should not affect the Company's ability to continue oil and gas
exploration, drilling, production and sales activities. However, there can be no
guarantee that the Company, its business partners, vendors or customers will
successfully be able to identify and remedy all potential Year 2000 problems and
that a resulting system failure would not have a material adverse effect on the
Company.
In a recent Securities and Exchange Commission release regarding Year 2000
disclosures, the Securities and Exchange Commission stated that public companies
must disclose the most reasonably likely worst case Year 2000 scenario. Analysis
of the most reasonably likely worst case Year 2000 scenario that Houston
Exploration may face leads to contemplation of the following possibilities
which, though unlikely in some or many cases, must be included in any
consideration of worst cases: widespread failure of electrical, gas, and similar
supplies by utilities serving the Company; widespread disruption of the services
of communications common carriers; similar disruption to means and modes of
transportation for Houston Exploration and its employees, contractors,
suppliers, and customers; significant disruption to Houston Exploration's
ability to gain access to, and remain working in, office buildings and other
facilities; the failure of substantial numbers of the Company's computer
hardware and software systems, including both internal business systems and
systems (such as those with embedded chips) controlling operational facilities
such as onshore and offshore oil and gas production facilities, gas meters and
pipelines, the effects of which would have a cumulative material adverse impact
on the Company. Among other things, the Company could face substantial claims by
customers or loss of revenues due to service interruptions, inability to fulfill
contractual obligations, inability to account for certain revenues or
obligations or to bill customers accurately and on a timely basis, and increased
expenses associated with litigation, stabilization of operations following
systems failures, and the execution of contingency plans. Houston Exploration
could also experience an inability by customers, traders, and others to pay, on
a timely basis or at all, obligations owed to the Company. Under these
circumstances, the adverse effect on the Company, and the reduction of the
Company's revenues, would be material, although not quantifiable at this time.
Further in this scenario, the cumulative effect of these failures could have a
substantial adverse effect on the economy, domestically and internationally. The
adverse effect on Houston Exploration, and the reduction of the Company's
revenues, from a domestic or global recession or depression is also likely to be
material, although not quantifiable at this time.
-31-
<PAGE> 32
RESULTS OF OPERATIONS
The following table sets forth the Company's historical natural gas and
oil production data during the periods indicated:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
PRODUCTION:
Natural gas (MMcf) ..................... 61,479 50,310 31,215
Oil (MBbls) ............................ 225 171 118
Total (MMcfe) .......................... 62,829 51,336 31,923
AVERAGE SALES PRICES:
Natural gas (per Mcf) realized(1) ...... $ 2.02 $ 2.25 $ 2.00
Natural Gas (per Mcf) unhedged ......... 1.96 2.45 2.35
Oil (per Bbl) .......................... 12.18 18.33 21.53
EXPENSES (PER MCFE):
Lease operating ........................ $ 0.26 $ 0.28 $ 0.34
Severance tax .......................... 0.08 0.08 0.04
Depreciation, depletion and amortization 1.27 1.15 1.06
Writedown in carrying value of
natural gas and oil properties .... 2.07 -- --
General and administrative, net ........ 0.10 0.11 0.20
</TABLE>
- ---------------------------
(1) Reflects the effects of hedging.
RECENT FINANCIAL AND OPERATING RESULTS
COMPARISON OF YEARS ENDED DECEMBER 31, 1997 AND 1998
Production. Houston Exploration's production increased 22% from 51,336
MMcfe in 1997 to 62,829 MMcfe in 1998. The increase in production was
attributable to added production from the continued successful development
drilling program in the Charco Field and the addition of new production from
wells acquired in South Louisiana in April 1998. Seventeen new wells were
brought on-line in the Charco Field during 1998 and daily production, net to the
Company's interest, has increased approximately 52% from an average of 54
MMcfe/d during 1997, to an average of 82 MMcfe/d during 1998. The onshore
production growth, however, was offset by offshore production curtailments
caused by tropical storms Charlie and Frances and hurricanes Earl and Georges
during August and September 1998. In addition to shut-ins for tropical weather,
High Island 38 encountered mechanical problems and was shut-in the first week of
August 1998. High Island 38 came on-line in January 1998 and was producing
approximately 10 MMcfe/d, net to the Company's interest. The combination of
tropical weather, mechanical problems and natural reservoir decline caused
offshore production to drop from an average of 60 MMcfe/d during 1997 to 56
MMcfe/d during 1998.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased 9%
from $116.3 million in 1997 to $127.1 million in 1998 as a result of the 22%
increase in production offset in part by a 10% decrease in average realized
natural gas prices, from $2.25 per Mcf in 1997 to $2.02 per Mcf for the year
ended 1998.
As a result of hedging activities, the Company realized an average gas
price of $2.02 per Mcf for 1998, which was 103% of the $1.96 per Mcf that
otherwise would have been received, resulting in a $3.8 million increase in
natural gas revenues for the year ended December 31, 1998. During 1997, the
average realized gas price was $2.25 per Mcf which was 92% of the unhedged
average gas price of $2.45, resulting in a decrease in natural gas revenues of
$9.9 million for the year ended 1997.
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<PAGE> 33
Lease Operating Expenses and Severance Tax. Lease operating expenses
increased 15% from $14.1 million in 1997 to $16.2 million in 1998. On an Mcfe
basis, lease operating expenses decreased from $0.28 in 1997 to $0.26 in 1998.
The increase in lease operating expenses during 1998 is attributable to the
continued expansion of operations in the Charco Field, combined with new
offshore producing properties and the addition of the South Louisiana properties
acquired in April 1998 and the effect of higher overall costs in the service
industry. The decrease in the lease operating expenses per Mcfe resulted from
the increase in production during 1998. Severance tax, which is a function of
volume and revenues generated from onshore production, increased 19% from $4.2
million, or $0.07 per Mcfe, in 1997 to $5.0 million, or $0.08 per Mcfe, in 1998.
The increase in both the severance tax expense and the rate per Mcfe is due to
the increase in the Company's onshore production from the Charco Field and the
addition of the onshore South Louisiana properties acquired in April and October
and November 1998.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased 35% from $59.1 million in 1997 to $79.8 million
in 1998. Depreciation, depletion and amortization expense per Mcfe increased 10%
from $1.15 in 1997 to $1.27 in 1998. 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 to higher costs for drilling
goods and services and a higher level of capital spending in 1998 as compared to
1997.
Writedown in Carrying Value of Natural Gas and Oil Properties. At December
31, 1998, the Company was required under full cost accounting rules to write
down the carrying value of its natural gas and oil properties primarily as a
result of weak natural gas prices. The Company incurred a $130.0 million
non-cash charge, $84.5 million after taxes. The Company based its ceiling test
determination on a February 1999 wellhead price of $1.61 per Mcf.
General and Administrative Expenses. General and administrative expenses,
net of overhead reimbursements received from other working interest owners of
$0.9 million and $1.1 million, in 1997 and 1998, respectively, increased 5% from
$5.8 million in 1997 to $6.1 million in 1998. The increase in general and
administrative expense reflects continued growth and expansion of the Company
and its operations. As the Company continues to grow and expand its operations
and workforce, the Company expects aggregate general and administrative expenses
to increase. The Company capitalized general and administrative expenses
directly related to oil and gas exploration and development activities of $7.2
million and $7.5 million, respectively, in 1997 and 1998. The increase in
capitalized general and administrative expense directly corresponds with the
growth of the Company's technical workforce and the continued expansion of
exploration and drilling operations. On an Mcfe basis, general and
administrative expenses decreased 10% from $0.11 in 1997 to $0.10 in 1998. The
lower rate per Mcfe during 1998 reflects the increase in the Company's
production.
Interest Expense, Net. Interest expense, net of capitalized interest,
increased from $0.9 million in 1997 to $4.6 million in 1998. Capitalized
interest increased from $5.9 million in 1997 to $9.8 million in 1998. The
increase in aggregate interest expense was attributable to higher average debt
levels during 1998. Interest expense was greater in 1998 as compared to 1997 due
to with the issuance of $100 million of senior subordinated indebtedness in
March 1998 and borrowings of $80 million on a revolving credit facility
established with KeySpan in November 1998. The Company expects its 1999 average
debt levels to exceed those in 1998 and, accordingly, expects an increase in net
interest expense.
Income Tax Provision. The provision for income taxes decreased from an
expense of $10.2 million in 1997 to a benefit of $40.7 million in 1998. The
expense in 1997 reflects income before taxes of $33.4 million in 1997, compared
to a loss before taxes of $113.4 million in 1998, that was primarily
attributable to the $130.0 million writedown in carrying value of natural gas
and oil properties. The tax benefit from the utilization of Section 29 tax
credits was $1.2 million in 1997 compared to $1.0 million in 1998.
Operating Income (Loss) and Net Income (Loss). Operating income decreased
from income of $34.4 million in 1997 to a loss of $108.8 million in 1998.
Excluding the $130.0 million writedown in natural gas and oil properties,
operating income would have reflected a decrease of 38% from $34.4 million in
1997 to $21.2 million in 1998. Despite a 22% increase in production during 1998,
operating income declined as a result of lower natural gas prices, higher
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<PAGE> 34
operating expenses, primarily depreciation, depletion and amortization expense,
and higher levels of interest expense. Net income decreased from income of $23.3
million in 1997 to a loss of $72.7 million in 1998. Excluding the $84.5 million
after tax effect of the writedown in natural gas and oil properties, net income
would have been $11.8 million for 1998 compared to $23.3 million in 1997, a
decrease of 49%.
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, net to the Company's interest, increased 179%
from approximately 33 MMcfe per day in December 1996 to approximately 92 MMcfe
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 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
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<PAGE> 35
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.
Interest Expense, Net. Interest expense, net of capitalized interest,
decreased from $2.9 million in 1996 to $0.9 million in 1997. Capitalized
interest increased from $3.5 million in 1996 to $5.9 million in 1997. While
aggregate interest expense increased slightly due to higher debt levels in 1997
as compared to 1996, capitalized interest increased due to expansion of the
Company's operations subsequent to the IPO and higher levels of capital spending
during 1997.
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% from
$13.7 million in 1996 to $34.4 million in 1997. 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.
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. On March 2, 1998, the Company issued $100 million of senior subordinated
indebtedness in a private placement to qualified institutional buyers. Net
proceeds of approximately $97 million were used to repay a portion of the
outstanding indebtedness under the Company's revolving bank credit facility (the
"Credit Facility"). In November of 1998, the Company established a $150 million
subordinated revolving credit facility (the "KeySpan Facility") and borrowed $80
million under this facility to fund a portion of the November 30, 1998 Chevron
Acquisition. See "Risk Factors -- The Amount of Our Outstanding Indebtedness is
Substantial and Could Have Adverse Consequences."
As of December 31, 1998, the Company had a working capital deficit of $3.2
million and $16.6 million of borrowing capacity available under the Credit
Facility and $70.0 million of borrowing capacity available under the KeySpan
Facility. Net cash provided by operating activities for the year ended December
31, 1998 was $102.4 million compared to $97.3 million for the year ended
December 31, 1997. The Company's cash position was increased during 1998 by a
net increase in long-term debt of $200 million. The net increase in long-term
debt resulted from the Company's issuance of $100 million of senior subordinated
notes, borrowings of $80 million on the KeySpan Facility and additional
borrowings of $20 million under the Credit Facility. Funds used in investing
activities consisted of $302.7 million for investments in property and
equipment, including the $84.9 million for the Chevron Acquisition and $78.0
million for the entire South Louisiana Acquisition. As a result of these
activities, cash and cash equivalents decreased $0.1 million from $4.7 million
at December 31, 1997 to $4.6 million at December 31, 1998.
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,
---------------------------------------------------
1998 1997 1996
------------- ------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Net cash provided by operating activities............. $ 102,378 $ 97,292 $ 54,065
Net long-term borrowings (repayments)................. 200,000 48,000 (6,862)
Proceeds from sale of common stock.................... 207 297 101,014
Capital contributions from Brooklyn Union............. -- -- 6,342
</TABLE>
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<PAGE> 36
Natural Gas and Oil Capital Expenditures. Over the past three years, the
Company has spent $623 million (including $162.9 million in 1998 for the Chevron
and South Louisiana Acquisitions and $96.9 million in 1996 for the TransTexas
and the Soxco Acquisitions) to add 428 Bcfe of net proved reserves, representing
an average finding and development cost of $1.43 per Mcfe. 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,
-------------------------------------------
1998 1997 1996
---------- ----------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
OFFSHORE:
Acquisitions and leasehold.................. $ 109,209 $ 30,700 $ 58,578
Development................................. 15,983 19,826 25,399
Exploration................................. 55,381 42,219 27,398
---------- ----------- ----------
180,573 92,745 111,375
ONSHORE:
Acquisitions and leasehold.................. $ 86,677 $ 9,920 $ 59,513
Development................................. 35,063 39,418 5,844
Exploration................................. 230 1,900 --
---------- ----------- ----------
121,970 51,238 65,357
---------- ----------- ----------
Total....................................... $ 302,543 $ 143,983 $ 176,732
========== =========== ==========
</TABLE>
Future Capital Requirements. The Company's capital expenditure budget for
1999 of $90 million includes $42 million and $33 million, respectively, for
exploration and development, with the balance reserved for leasehold acquisition
costs. 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 1999.
Actual levels of capital expenditures may vary significantly due to a variety of
factors, including drilling results, 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.
Depending on market conditions and the Company's capital needs, the
Company intends to seek additional equity through a public offering of Common
Stock during 1999. The Company intends to use the proceeds from such equity
offering, if successfully completed, to repay outstanding indebtedness under the
Credit Facility and the KeySpan Facility. Houston Exploration cannot guarantee
that it will be able to successfully complete this additional equity offering.
On March 15, 1999, the Company signed a joint exploration agreement ( the
"KeySpan Joint Venture") with a subsidiary of KeySpan, KeySpan Exploration &
Production, LLC, to explore for natural gas and oil over a term of three years
expiring December 31, 2001. The joint venture may be terminated at the option of
either party at the end of the then current calendar year. Houston Exploration
is joint venture manager and operator. Effective January 1, 1999, KeySpan will
commit approximately $100 million per calendar year and Houston Exploration will
commit its proportionate share of the funds per calendar year necessary to fund
a joint exploration and development drilling program. Houston Exploration will
contribute all of its currently undeveloped offshore leases to the Joint Venture
and KeySpan will receive 45% of Houston Exploration's working interest in all
prospects to be drilled under the program. Revenues will be shared 55% Houston
Exploration and 45% KeySpan. During the term of the KeySpan Joint Venture,
KeySpan will pay 100% of actual intangible drilling costs up to a maximum of
$20.7 million per year. All additional intangible drilling costs incurred during
such year will be paid 51.75% by KeySpan and 48.25% by Houston
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<PAGE> 37
Exploration. In addition, Houston Exploration will receive reimbursement of a
portion of its general and administrative costs during the term of the KeySpan
Joint Venture. The Company plans to drill approximately 8 to 10 offshore
exploratory wells under the terms of the KeySpan Joint Venture during 1999. Both
Houston Exploration and KeySpan obtained separate opinions, each from a
nationally recognized investing banking firm, as to the fairness to the Company
and its noteholders and to KeySpan, respectively, of the KeySpan Joint Venture,
from a financial point of view. A special committee, comprised of outside,
unaffiliated directors, appointed by the Company's Board of Directors has
determined that the joint venture is fair to the Company's stockholders.
Capital Structure. The Company has entered into a revolving credit
facility ("Credit Facility") with a syndicate of lenders led by Chase Bank of
Texas, National Association ("Chase"), which provides a maximum commitment of
$150 million, subject to borrowing base limitations. At December 31, 1998 the
borrowing base was $150 million of which up to $5 million was 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, 1998, $133.0
million was outstanding under the Credit Facility and $0.4 million was
outstanding in letter of credit obligations. Subsequent to December 31, 1998,
the Company borrowed an additional $7 million under the Credit Facility,
bringing outstanding borrowings to $140.4 million as of March 22, 1999.
Interest is payable on borrowings under the Credit Facility, at the
Company's option, at (i) a fluctuating rate ("Base Rate") equal to the greater
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 variable margin of 0.375% to
1.125%, depending on the amount outstanding under the Credit Facility. Interest
is payable 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. In
addition, the Credit Facility requires 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 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 ("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, 1998, the Company was in compliance with all such covenants with
the exception of the debt to capitalization ratio which was 62% rather than 60%.
The Company received a waiver of non-compliance from Chase for the debt to
capitalization ratio covenant.
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
60%. 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."
On March 2, 1998, the Company issued $100 million of 85/8% Senior
Subordinated Notes (the "Notes") due January 1, 2008 in a private placement to
qualified institutional buyers. The Notes bear interest at a rate of 85/8% per
annum with interest payable semi-annually on January 1 and July 1, commencing
July 1, 1998. The Notes are redeemable at the option of the Company, in whole or
in part, at any time on or after January 1, 2003 at a price equal to 100% of the
principal amount plus accrued and unpaid interest, if any, plus a specified
premium if the Notes are redeemed prior to January 1, 2006. Notwithstanding the
foregoing, any time prior to January 1, 2001, the Company may redeem up to 35%
of the original aggregate principal amount of the Notes with the net proceeds of
any equity offering, provided that at least 65% of the original aggregate
principal amount of the Notes remains outstanding immediately after the
occurrence of such redemption. Upon the occurrence of a change of control (as
defined), the Company will be required to offer to purchase the Notes at a
purchase price equal to 101% of the aggregate principal
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<PAGE> 38
amount thereof, plus accrued and unpaid interest, if any. The Notes are general
unsecured obligations of the Company and rank subordinate in right of payment to
all existing and future senior debt, including the Credit Facility, and will
rank senior or pari passu in right of payment to all existing and future
subordinated indebtedness.
On November 30, 1998, the Company entered into a revolving credit facility
with KeySpan (the "KeySpan Facility"), which provides a maximum commitment of
$150 million. The KeySpan Facility ranks subordinate to the Credit Facility and
pari passu to the Senior Subordinated Notes. Borrowings are unsecured. Subject
to the approval of the Company's stockholders, any principal amount that remains
outstanding under the KeySpan Facility at January 1, 2000 will be converted into
common stock of the Company, with the number of shares to be determined based
upon the average of the closing prices of the Company's common stock, rounded to
three decimal places, as reported under "NYSE Composite Transaction Reports" in
the Wall Street Journal during the 20 consecutive trading days ending three
trading days prior to January 1, 2000. Because the market value represents an
average of the Company's common stock over twenty consecutive trading days,
ending three days prior to the maturity date of the loan, the market price may
be higher or lower than the price of the common stock on the conversion date.
Interest is payable monthly and borrowings bear interest at LIBOR plus 1.4%. In
addition, the Company pays a commitment fee of 0.0125% on the unused portion of
the maximum commitment and has incurred an upfront fee of $50,000. As of
December 31, 1998, outstanding borrowings under the facility were $80 million.
For the year ended December 31, 1998, the Company paid a total $0.5 million in
interest and fees to KeySpan. Borrowings were used to finance a portion of the
November 1998 Chevron Acquisition. See Note 11 of the Company's Consolidated
Financial Statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural Gas Hedging. 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.
As of December 31, 1998, 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 January 1999 was 5,738 MMcf (5,906 MMMbtu).
<TABLE>
<CAPTION>
FIXED PRICE SWAPS COLLARS
-------------------- ---------------------------------
NYMEX NYMEX
VOLUME CONTRACT VOLUME CONTRACT PRICE
PERIOD (MMMBTU) PRICE (MMMBTU) FLOOR CEILING
------ -------- --------- -------- -------- ---------
<S> <C> <C> <C> <C> <C>
January 1999 755 $ 2.50 -- -- --
February 1999 -- -- 280 $ 2.40 $ 2.90
</TABLE>
As of March 22, 1999, the Company had no commodity hedging contracts
extending beyond March 31,1999. The Company has entered into basis swaps for 100
MMMbtu/day during the months January 1999 - March 1999.
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
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<PAGE> 39
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 NYMEX price, the Company believes that it has no material
basis risk.
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> 40
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, 1998.
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, 1998. 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 subheading
"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, 1998.
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, 1998.
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<PAGE> 41
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>
Index to Financial Statements.......................................................................... F-1
Report of Independent Public Accountants............................................................... F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997........................................... F-3
Consolidated Statements of Operations for the Years Ended December 31, 1998, 1997 and 1996............. F-4
Consolidated Statement of Stockholders' Equity for the Period from December 31, 1998 to
December 31, 1996.................................................................................... F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996............. F-6
Notes to Consolidated Financial Statements............................................................. F-7
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities F-22
Quarterly Financial Information (Unaudited)............................................................ F-25
</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.
EXHIBITS DESCRIPTION
-------- -----------
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).
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<PAGE> 42
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).
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).
10.7 -- Registration Rights Agreement dated as of July 2, 1996 between
The Houston Exploration Company and THEC Holdings Corp. (filed
as Exhibit 10.13 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 (filed as Exhibit 10.11 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1997
(001-11899) and incorporated by reference herein).
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).
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<PAGE> 43
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).
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 (filed
as Exhibit 10.24 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1997 (File No. 001- 11899) and
incorporated by reference herein).
10.25 -- Indenture, dated as of March 2, 1998, between The Houston
Exploration Company and The Bank of New York, as Trustee, with
respect to the 85/8% Senior Subordinated Notes Due 2008
(including form of 85/8% Senior Subordinated Note Due 2008)
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-4 (No. 333-50235)).
10.26 -- Registration Rights Agreement, dated as of March 2, 1998,
among The Houston Exploration Company, as issuer, and Donaldson,
Lufkin & Jenrette Securities Corporation, Salomon Brothers Inc,
PaineWebber Incorporated, Chase Securities Inc., and Howard,
Weil, Labouisse, Friedrichs Incorporated (incorporated by
reference to Exhibit 4.2 to the Company's Registration Statement
on Form S-4 (No. 333-50235)).
10.27 -- Third Amendment to Credit Agreement among The Houston
Exploration Company and Chase Bank of Texas National
Association, dated February 12,1998 (filed as Exhibit 10.1 to
the Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998 (File No. 001- 11899) and incorporated by
reference herein).
10.28** -- Amended and Restated 1996 Stock Option Plan (filed as Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1998 (File No. 001-11899) and
incorporated by reference herein.
10.29** -- Employment Agreement dated May 1, 1998 between The Houston
Exploration Company and Thomas E. Schwartz (filed as Exhibit
10.2 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1998 (File No. 001-11899) and
incorporated by reference herein.
*10.30 -- Subordinated Loan Agreement dated November 30, 1998 between
The Houston Exploration Company and MarketSpan Corporation d/b/a
KeySpan Energy Corporation.
*10.31 -- Subordination Agreement dated November 25, 1998 entered into
and among MarketSpan Corporation d/b/a KeySpan Energy
Corporation, The Houston Exploration Company and Chase Bank of
Texas, National Association.
*12.1 Computation of ratio of earnings to fixed charges.
*21.1 -- Subsidiaries of the Company.
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Netherland, Sewell & Associates.
*23.3 -- Consent of Miller and Lents.
*23.4 -- Consent of Ryder Scott Company.
*27.1 -- Financial Data Schedule.
- -----------------
* Filed herewith.
** Management contract or compensation plan.
(b) Reports on Form 8-K:
Current Report
Filed on February 9, 1998.
-43-
<PAGE> 44
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: March 22, 1999 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 and Director March 22, 1999
- ------------------------------ (Principal Executive Officer)
James G. Floyd
/s/ James F. Westmoreland Vice President, Chief Accounting Officer, March 22, 1999
- ------------------------------ Comptroller and Secretary (Principal Financial
James F. Westmoreland Officer and Principal Accounting Officer)
/s/ Robert B. Catell Chairman of the Board of Directors March 22, 1999
- ------------------------------
Robert B. Catell
/s/ Gordon F. Ahalt Director March 22, 1999
- ------------------------------
Gordon F. Ahalt
/s/ Russell D. Gordy Director March 22, 1999
- ------------------------------
Russell D. Gordy
/s/ Craig G. Matthews Director March 22, 1999
- ------------------------------
Craig G. Matthews
/s/ James Q. Riordan Director March 22, 1999
- ------------------------------
James Q. Riordan
/s/ Lester H. Smith Director March 22, 1999
- ------------------------------
Lester H. Smith
/s/ Donald C. Vaughn Director March 22, 1999
- ------------------------------
Donald C. Vaughn
</TABLE>
-44-
<PAGE> 45
GLOSSARY OF OIL AND GAS TERMS
The definitions set forth below 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 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 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 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.
Intangible Drilling and Development Costs. Expenditures made by an
operator for wages, fuel, repairs, hauling, supplies, surveying, geological
works etc., incident to and necessary for the preparing for and drilling of
wells and the construction of production facilities and pipelines.
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.
-45-
<PAGE> 46
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
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 nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
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 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.
-46-
<PAGE> 47
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil 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.
Tangible Drilling and Development Costs. Cost of physical lease and well
equipment and structures. The costs of assets that themselves have a salvage
value.
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.
-47-
<PAGE> 48
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants.............................................................. F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997.......................................... F-3
Consolidated Statements of Operations for the Years Ended December 31, 1998, 1997 and 1996............ F-4
Consolidated Statement of Stockholders' Equity for the Years Ended December 31, 1998, 1997 and 1996 F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996........... F-6
Notes to Consolidated Financial Statements............................................................ F-7
</TABLE>
F-1
<PAGE> 49
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited the accompanying consolidated balance sheets of The
Houston Exploration Company (a Delaware corporation and an indirect 64%-owned
subsidiary of MarketSpan Corporation d/b/a KeySpan Energy Corporation) as of
December 31, 1998 and 1997, and the related consolidated statements of
operations, stockholders' equity and cash flows for each of the three years in
the period ended December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of The Houston
Exploration Company, as of December 31, 1998 and 1997, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York
February 9, 1999
F-2
<PAGE> 50
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------
1998 1997
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
ASSETS:
Cash and cash equivalents ........................................................... $ 4,645 $ 4,745
Accounts receivable ................................................................. 23,050 37,898
Accounts receivable-- Affiliate ..................................................... 137 1,303
Inventories ......................................................................... 915 1,265
Prepayments and other ............................................................... 754 645
--------- ---------
Total current assets ...................................................... 29,501 45,856
Natural gas and oil properties, full cost method
Unevaluated properties ............................................................ 145,317 104,075
Properties subject to amortization ................................................ 828,168 566,868
Other property and equipment ........................................................ 9,464 9,341
--------- ---------
982,949 680,284
Less: Accumulated depreciation, depletion and amortization .......................... (446,367) (236,546)
--------- ---------
536,582 443,738
Other assets ........................................................................ 3,369 1,797
--------- ---------
TOTAL ASSETS .............................................................. $ 569,452 $ 491,391
========= =========
LIABILITIES:
Accounts payable and accrued expenses ............................................... $ 32,743 $ 42,432
Deferred stock obligation ........................................................... -- 8,825
--------- ---------
Total current liabilities ................................................. 32,743 51,257
Long-term debt and notes ............................................................ 233,000 113,000
Subordinated note-- Affiliate ....................................................... 80,000 --
Deferred federal income taxes ....................................................... 31,027 70,741
Other deferred liabilities .......................................................... 152 206
--------- ---------
TOTAL LIABILITIES ......................................................... 376,922 235,204
COMMITMENTS AND CONTINGENCIES (SEE NOTE 10) STOCKHOLDERS' EQUITY: Common Stock,
$.01 par value, 50,000 shares authorized and 23,897 shares issued
and outstanding at December 31, 1998 and 23,361 shares issued and outstanding at
December 31, 1997 ................................................................. 239 234
Additional paid-in capital .......................................................... 230,931 221,907
Retained earnings (deficit) ......................................................... (38,640) 34,046
--------- ---------
TOTAL STOCKHOLDERS' EQUITY ................................................ 192,530 256,187
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ................................ $ 569,452 $ 491,391
========= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
<PAGE> 51
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
1998 1997 1996
--------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
REVENUES:
Natural gas and oil revenues ................................. $ 127,124 $ 116,349 $ 64,864
Other ........................................................ 1,123 1,297 1,040
--------- --------- ---------
Total revenues ....................................... 128,247 117,646 65,904
OPERATING COSTS AND EXPENSES:
Lease operating .............................................. 16,199 14,146 10,800
Severance tax ................................................ 4,967 4,233 1,401
Depreciation, depletion and amortization ..................... 79,838 59,081 33,732
Writedown in carrying value of natural gas and oil properties . 130,000 -- --
General and administrative, net .............................. 6,086 5,825 6,249
--------- --------- ---------
Total operating expenses ............................. 237,090 83,285 52,182
Income(loss) from operations ................................... (108,843) 34,361 13,722
Interest expense, net .......................................... 4,597 938 2,875
--------- --------- ---------
Net income(loss) before income taxes ........................... (113,440) 33,423 10,847
Provision(benefit) from federal income taxes ................... (40,754) 10,173 2,205
--------- --------- ---------
NET INCOME (LOSS) .............................................. $ (72,686) $ 23,250 $ 8,642
========= ========= =========
Net income(loss) per share ..................................... $ (3.05) $ 1.00 $ 0.49
========= ========= =========
Net income(loss) per share-- assuming dilution ................. $ (3.05) $ 0.97 $ 0.49
========= ========= =========
Weighted average shares outstanding ............................ 23,768 23,337 17,532
Weighted average shares outstanding-- assuming dilution ........ 23,768 24,028 17,687
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements
F-4
<PAGE> 52
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED 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, 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(1) .. 80 115,000 -- 115,080
Net income ................................. -- -- 8,642 8,642
------------ ------------ ------------ ------------
Balance at December 31, 1996 ............... $ 233 $ 222,271 $ 10,796 $ 233,300
Other(2) ................................... -- (660) -- (660)
28 shares of common stock at $15.50(3) ..... 1 296 -- 297
Net income ................................. -- -- 23,250 23,250
------------ ------------ ------------ ------------
Balance at December 31, 1997 ............... $ 234 $ 221,907 $ 34,046 $ 256,187
534 shares of common stock at $16.91(4) .... 5 9,024 -- 9,029
Net loss ................................... -- -- (72,686) (72,686)
------------ ------------ ------------ ------------
Balance at December 31, 1998 ............... $ 239 $ 230,931 $ (38,640) $ 192,530
============ ============ ============ ============
</TABLE>
- -------------------
(1) See Note 3 -- Stockholders' Equity.
(2) Non-cash charge relating to the February 1996 Reorganization.
(3) See Note 4 -- Incentive Stock Option Plan.
(4) See Note 3-- Stockholders' Equity. Price represents an average
issuance price during the year.
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
<PAGE> 53
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------
1998 1997 1996
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income(loss) ................................................... $ (72,686) $ 23,250 $ 8,642
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ......................... 79,838 59,081 33,732
Writedown in carrying value of natural gas and oil properties .... 130,000 -- --
Deferred income tax expense(benefit) ............................. (39,714) 13,601 11,939
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable .................... 16,014 (3,356) (10,348)
Decrease (increase) in inventories ............................ 350 (273) 217
Decrease (increase) in prepayments and other .................. (109) 279 (29)
Decrease (increase) in other assets and liabilities ........... (1,626) (62) 909
Increase (decrease) in accounts payable and accrued expenses .. (9,689) 4,772 9,003
--------- --------- ---------
Net cash provided by operating activities .......................... 102,378 97,292 54,065
INVESTING ACTIVITIES:
Investment in property and equipment ............................... (302,685) (145,055) (154,125)
Dispositions and other ............................................. -- 1,360 1,819
--------- --------- ---------
Net cash used in investing activities .............................. (302,685) (143,695) (152,306)
FINANCING ACTIVITIES:
Proceeds from long-term borrowings ................................. 312,000 79,000 76,838
Repayments of long-term borrowings ................................. (112,000) (31,000) (83,700)
Proceeds from issuance of common stock, net of offering costs ...... 207 297 101,014
Capital contributions from Brooklyn Union .......................... -- -- 6,342
--------- --------- ---------
Net cash provided by financing activities .......................... 200,207 48,297 100,494
Increase (decrease) in cash and cash equivalents ................... (100) 1,894 2,253
Cash and cash equivalents, beginning of period ..................... 4,745 2,851 598
--------- --------- ---------
Cash and cash equivalents, end of period ........................... $ 4,645 $ 4,745 $ 2,851
========= ========= =========
Cash paid for interest ............................................. $ 9,452 $ 6,001 $ 5,708
========= ========= =========
Cash paid for taxes ................................................ $ -- $ -- $ --
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
<PAGE> 54
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIEs
Organization
The Company was incorporated in Delaware in December 1985 to conduct
offshore natural gas and oil exploration drilling and development operations in
the Gulf of Mexico on behalf of The Brooklyn Union Gas Company ("Brooklyn
Union"). In February 1996, Brooklyn Union reorganized its exploration and
production assets and transferred to Houston Exploration its onshore producing
properties. Subsequent to the reorganization, the Company has expanded its focus
to include lower risk exploitation and development drilling on the onshore
properties transferred, in addition to seeking acquisitions both onshore and
offshore that primarily offer unexploited reserve potential and/or that are
located in existing core operating areas. The Company's current operations focus
offshore in the Gulf of Mexico and onshore in South Texas, South Louisiana, the
Arkoma Basin, East Texas and West Virginia. At December 31, 1998, the Company
had net proved reserves of 480 Bcfe, 98% of which were natural gas and 80% of
which were classified as proved developed.
In September 1996, the Company completed an initial public offering (the
"IPO") of 7,130,000 shares of Common Stock at $15.50 per share, resulting in net
cash proceeds of $101 million. As of December 31, 1998, THEC Holdings Corp., a
wholly owned subsidiary of Brooklyn Union, owned approximately 64% of the
outstanding shares of Common Stock. Brooklyn Union became a subsidiary of
MarketSpan Corporation in May 1998 through the combination of Brooklyn Union's
parent company, KeySpan Energy Corporation ("KeySpan"), and Long Island Lighting
Company ("LILCO"). MarketSpan, a diversified energy provider doing business as
("d/b/a") KeySpan Energy: (i) distributes natural gas, through its subsidiary
Brooklyn Union, to a customer base of 1.6 million in the New York City and Long
Island areas; (ii) is contracted by Long Island Power Authority ("LIPA") to
manage LILPA's electricity service in the Long Island area; and (iii) through
its unregulated subsidiaries, is involved in gas retailing, power plant
management and energy management services.
Principles of Consolidation
The consolidated financial statements include the accounts of The Houston
Exploration Company and its wholly-owned subsidiary, Seneca Upshur Petroleum
Company (collectively the "Company"). All significant intercompany balances and
transactions have been eliminated.
Reclassifications and Use of Estimates
The preparation of the consolidated 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 13 --
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.
F-7
<PAGE> 55
Net Income Per Share
Basic earnings per share ("EPS") is calculated by dividing net income by
the weighted average number of shares of common stock outstanding during the
period. No dilution for any potentially dilutive securities is included. Diluted
EPS assumes the conversion of all potentially dilutive securities and is
calculated by dividing net income by the weighted average number of shares
common stock outstanding plus all potentially dilutive securities.
Under the requirements of Statement of Financial Accounting Standards
("SFAS") No. 128, the Company's EPS are as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
-------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Net income(loss) ................................ $(72,686) $ 23,250 $ 8,642
Weighted average shares outstanding ............. 23,768 23,337 17,532
Add dilutive securities:
Options ....................................... -- 153 27
Contingent shares ............................. -- 538 128
-------- -------- --------
Total weighted average shares outstanding and
dilutive securities ........................... 23,768 24,028 17,687
======== ======== ========
Net income (loss) per share ..................... $ (3.05) $ 1.00 $ 0.49
Net income (loss) per share-- assuming dilution . $ (3.05) $ 0.97 $ 0.49
</TABLE>
The computation of diluted EPS for the year ended December 31, 1998 did
not assume the conversion of options or any other potentially convertible
securities as their inclusion would have been antidilutive.
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, 1998 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 development, plugging, abandonment and site
F-8
<PAGE> 56
restorations, net of related accumulated depreciation, depletion and
amortization and related deferred income taxes, exceed the full cost ceiling.
As of December 31, 1998, the Company estimates, using a December wellhead
price of $1.83 per Mcf, that actual capitalized costs of natural gas and oil
properties exceeded the ceiling limitation imposed under full cost accounting
rules by approximately $41.2 million, after taxes. Subsequent to December 31,
1998, natural gas prices continued to decline, such that the Company estimates,
using a February wellhead price of $1.61 per Mcf, that the ceiling limitation
exceeded actual capitalized costs of natural gas and oil properties by
approximately $84.5 million, after taxes. As a result, the Company reduced the
carrying value of its natural gas and oil properties as of December 31, 1998, by
$84.5 million, after taxes.
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.
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 on properties
operated by the Company. These reimbursements totaling $1.1 million, $0.9
million and $1.0 million for the years ended December 31, 1998, 1997 and 1998,
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 1998,
1997 and 1996, aggregated $7.5 million, $7.2 million and $5.3 million,
respectively.
F-9
<PAGE> 57
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, 1998, 1997 and 1996
interest costs of $9.8 million, $5.9 million and $3.5 million, respectively,
were capitalized.
Gas Imbalances
The Company incurs certain production gas volume imbalances in the
ordinary course of business and utilized 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, 1998 and
1997.
Financial Instruments
Fair value information is included in the notes to consolidated financial
statements when the fair value of the financial instruments is different from
the carrying or book value. The book value of those financial instruments that
are classified as current assets or liabilities approximate fair value because
of the short maturity of those instruments.
Cash and Cash Equivalents. Cash equivalents are comprised of highly liquid
investments with a maturity of three months or less. Cash equivalents are stated
at cost, which approximates fair value due to the short maturity of these
instruments.
Hedging Contracts. 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. While the use of hedging arrangements limits the downside
risk of adverse price movements, it may also limit future revenues from
favorable price movements. 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. If
hedging instruments cease to meet the criteria for deferral accounting, any
subsequent gains or losses are recognized in revenue. If these instruments are
terminated prior to maturity, resulting gains and losses continue to be deferred
until the hedged item is recognized in revenue. Neither the hedging contracts
nor the unrealized gains or losses on these contracts are recognized in the
financial statements. Natural gas revenues were increased by $3.8 million in
1998, and were reduced by $9.9 million and $11.1 million, respectively, during
1997 and 1996, relative to these contracts. See Note 8 -- Hedging Transactions.
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 over
the term of the swap as an adjustment to interest expense.
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. 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
F-10
<PAGE> 58
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.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities."
This statement broadens the definition of a derivative instrument and
establishes accounting and reporting standards requiring that every derivative
instrument be recorded on the balance sheet as either an asset or liability
measured at its fair market value. Derivatives that are not hedges must be
adjusted to fair value currently in earnings. If a derivative is a hedge,
depending on the nature of the hedge, special accounting allows changes in fair
value of the derivative to be either offset against the change in fair value of
the hedged asset or liability in the income statement or recorded in
comprehensive income until the hedged item is recognized in earnings. The
Company must formally document, designate and assess the effectiveness of
transactions that are recorded as hedges. The ineffective portion of a hedged
derivative's change in fair value will be immediately recognized in earnings.
The Company plans to adopt SFAS No. 133 effective January 1, 2000. Currently,
the Company cannot estimate the impact of the statement on results of future
operations; however, it believes that the impact will not be material.
NOTE 2 -- LONG-TERM DEBT AND NOTEs
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------
1998 1997
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
SENIOR DEBT:
Bank revolving credit facility ................ $ 133,000 $ 113,000
SUBORDINATED DEBT:
8 5/8% Senior Subordinated Notes, due 2008 .... 100,000 --
Subordinated Note--KeySpan .................... 80,000 --
----------- -----------
Total long-term debt and notes ............ $ 313,000 $ 113,000
=========== ===========
</TABLE>
The carrying amount of borrowings outstanding under the Credit Facility
and the Subordinated KeySpan Facility approximates fair value as the interest
rates are tied to current market rates. At December 31, 1998, the quoted market
value of the Company's $100 million of 8 5/8% Senior Subordinated Notes was 98%
of the $100 million carrying value or $98 million.
Credit Facility
The Company has entered into a revolving credit facility ("Credit
Facility") with a syndicate of lenders led by Chase Bank of Texas, National
Association ("Chase"), which provides a maximum commitment of $150 million,
subject to borrowing base limitations. At December 31, 1998 the borrowing base
was $150 million of which up to $5 million was 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, 1998, $133.0 million was
outstanding under the Credit Facility and $0.4 million was outstanding in letter
of credit obligations. Subsequent to December 31, 1998, the Company borrowed an
additional $7 million, bringing borrowings to $140.4 million as of March 22,
1999.
Interest is payable on borrowings under the Credit Facility, at the
Company's option, at (i) a fluctuating rate ("Base Rate") equal to the greater
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 variable margin of 0.375% to
1.125%, depending on the amount outstanding under the Credit Facility. Interest
is payable 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. In
addition, the Credit Facility requires 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
F-11
<PAGE> 59
Designated Borrowing Base. The weighted average interest rate was 6.44%, 6.90%
and 6.25%, respectively, for the years ended December 31, 1998, 1997 and 1996.
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 ("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, 1998, the Company was in compliance with all such covenants with
the exception of the debt to capitalization ratio with was 62% rather than 60%.
The Company received a waiver of non-compliance from Chase for the debt to
capitalization ratio.
Senior Subordinated Notes
On March 2, 1998, the Company issued $100 million of 85/8% Senior
Subordinated Notes (the "Subordinated Notes") due January 1, 2008 in a private
placement to qualified institutional buyers. The Notes bear interest at a rate
of 85/8% per annum with interest payable semi-annually on January 1 and July 1,
commencing July 1, 1998. The Notes are redeemable at the option of the Company,
in whole or in part, at any time on or after January 1, 2003 at a price equal to
100% of the principal amount plus accrued and unpaid interest, if any, plus a
specified premium if the Notes are redeemed prior to January 1, 2006.
Notwithstanding the foregoing, any time prior to January 1, 2001, the Company
may redeem up to 35% of the original aggregate principal amount of the Notes
with the net proceeds of any equity offering, provided that at least 65% of the
original aggregate principal amount of the Notes remains outstanding immediately
after the occurrence of such redemption. Upon the occurrence of a change of
control (as defined), the Company will be required to offer to purchase the
Notes at a purchase price equal to 101% of the aggregate principal amount
thereof, plus accrued and unpaid interest, if any. The Notes are general
unsecured obligations of the Company and rank subordinate in right of payment to
all existing and future senior debt, including the Credit Facility, and will
rank senior or pari passu in right of payment to all existing and future
subordinated indebtedness.
KeySpan Facility.
On November 30, 1998, the Company entered into a revolving credit facility
with KeySpan (the "KeySpan Facility"), which provides a maximum commitment of
$150 million. The KeySpan Facility ranks subordinate to the Credit Facility and
pari passu to the Subordinated Notes. Borrowings are unsecured. Subject to the
approval of the Company's stockholders, any principal amount that remains
outstanding under the KeySpan Facility at January 1, 2000 will be converted into
common stock of the Company, with the number of shares to be determined based
upon the average of the closing prices of the Company's common stock, rounded to
three decimal places, as reported under "NYSE Composite Transaction Reports" in
the Wall Street Journal during the 20 consecutive trading days ending three
trading days prior to January 1, 2000. Because the market value represents an
average of the Company's common stock over twenty consecutive trading days,
ending three days prior to the maturity date of the loan, the market price may
be higher or lower than the price of the common stock on the conversion date.
Interest is payable monthly and borrowings bear interest at LIBOR plus 1.4%. In
addition, the Company pays a commitment fee of 0.0125% on the unused portion of
the maximum commitment and has incurred an upfront fee of $50,000. As of
December 31, 1998, outstanding borrowings under the facility were $80 million.
For the year ended December 31, 1998, the Company paid a total $0.5 million in
interest and fees to KeySpan. Borrowings were used to finance a portion of the
November 1998 Chevron Acquisition. See Note 11--Acquisitions.
F-12
<PAGE> 60
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 with an
aggregate value (determined by reference to the IPO price) of $11.8 million to
Soxco in connection with the Soxco Acquisition. On March 27, 1998 and pursuant
to the Soxco Acquisition, the Company issued 520,777 shares of common stock with
an aggregate value (determined by reference to the average price of the
Company's common stock over a specified period of 20 trading days) of $8.8
million to Soxco in payment of the deferred purchase price. See Note 11 --
Acquisitions.
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 in 1996.
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 as
of December 31, 1998 2,124,438 options had been granted. 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, 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 and are nonqualified.
F-13
<PAGE> 61
Under the 1996 Incentive Plan, 978,750 of the options granted are
incentive stock options ("ISOs") and the balance, 1,145,688 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, 1998, 1997 and 1996:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------------------------------------------------------------
1998 1997 1996
------------------------------ ------------------------------ ------------------------------
SHARES PRICE* SHARES PRICE* SHARES PRICE*
<S> <C> <C> <C> <C> <C> <C>
Options at beginning of year ... 1,669,598 $ 16.67 1,239,638 $ 15.53 247,000 $ 11.22
Granted ....................... 426,700 19.07 458,100 19.69 1,239,638 15.53
Exercised ..................... (13,260) 15.70 (28,140) 15.50 --
Canceled ...................... -- -- (247,000) 11.22
------------- ------------- -------------
Options outstanding at year end . 2,083,038 $ 17.17 1,669,598 $ 16.67 1,239,638 $ 15.53
============= ============= =============
Exercisable at end of year ...... 599,275 $ 16.58 268,788 $ 16.49 --
Options available for grant ..... 208,838 635,538 1,093,638
Weighted average fair value of
options granted ............... $ 8.54 $ 8.71 $ 7.18
</TABLE>
- ---------------------------
* Weighted average exercise price for the year.
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 1998 and 1997, the Company made
payments of $0.6 million and $0.8 million, respectively 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.
F-14
<PAGE> 62
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, 1998, 1997 and
1996:
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------ ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Net income (loss)-- as reported.................................. $ (72,686) $ 23,250 $ 8,642
Net income (loss)-- pro forma.................................... (74,985) 21,499 8,268
Net income (loss) per share-- as reported........................ $ (3.05) $ 1.00 $ 0.49
Net income (loss) per share-- assuming dilution--as reported..... (3.05) 0.97 0.49
Net income (loss) per share-- pro forma.......................... $ (3.15) $ 0.92 $ 0.47
Net income (loss) per share-- assuming dilution-- pro forma...... (3.15) 0.89 0.47
</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 was estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used
for grants in 1998, 1997 and 1996: (i) average risk-free interest rate of 5.97%,
6.30%, and 6.66%, respectively, (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>
1998 1997 1996
---------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Current................................................... $ (1,040) $ (3,428) $ (9,734)
Deferred.................................................. (39,714) 13,601 11,939
---------- --------- ---------
Total........................................... $ (40,754) $ 10,173 $ 2,205
========== ========= =========
</TABLE>
The credit in the current provision represents Section 29 tax credits (see
Note 6 -- Related Party Transactions). During 1996, the Company received from
Brooklyn Union pursuant to the previous tax-sharing agreement $13.7 million. No
amounts were received in 1997 or 1998, as effective September 30, 1996, the
Company became a stand alone tax entity and is no longer consolidated with
Brooklyn Union. As of December 31, 1998, the Company had net operating loss
("NOL") carryforwards for federal income tax purposes of approximately $28
million that may be used in future years to offset taxable income.
F-15
<PAGE> 63
The following is a reconciliation of statutory federal income tax expense
(benefit) to the Company's income tax provision:
<TABLE>
<CAPTION>
1998 1997 1996
---------- --------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Income (loss) before income taxes......................... $ (113,440) $ 33,423 $ 10,847
Statutory rate............................................ 35% 35% 35%
Income tax expense (benefit) computed at statutory rate... (39,704) 11,698 3,796
Reconciling items:
Section 29 tax credits............................... (1,040) (1,200) (1,401)
Percentage depletion................................. (12) (14) (33)
Other................................................ 2 (311) (157)
---------- --------- ----------
Tax expense (benefit)..................................... $ (40,754) $ 10,173 $ 2,205
=========== ========= ==========
</TABLE>
Deferred Income Taxes
The components of net deferred tax liabilities pursuant to SFAS No. 109
for the years ended December 31, 1998 and 1997 primarily represent temporary
differences related to natural gas and oil properties.
NOTE 6 -- RELATED PARTY TRANSACTIONS
Subordinated KeySpan Facility.
On November 30, 1998, the Company entered into a revolving credit facility
with KeySpan (the "KeySpan Facility") which provides a maximum commitment of
$150 million. The KeySpan Facility ranks subordinate to the Credit Facility and
pari passu to the Senior Subordinated Notes. Borrowings are unsecured. Subject
to the approval of the Company's stockholders, any principal amount that remains
outstanding under the KeySpan Facility at January 1, 2000 will be converted into
common stock of the Company, with the number of shares to be determined based
upon the average of the closing prices of the Company's common stock, rounded to
three decimal places, as reported under "NYSE Composite Transaction Reports" in
the Wall Street Journal during the 20 consecutive trading days ending three
trading days prior to January 1, 2000. Because the market value represents an
average of the Company's common stock over twenty consecutive trading days,
ending three days prior to the maturity date of the loan, the market price may
be higher or lower than the price of the common stock on the conversion date.
Interest is payable monthly and borrowings bear interest at LIBOR plus 1.4%. In
addition, the Company pays a commitment fee of 0.0125% on the unused portion of
the maximum commitment and has incurred an upfront fee of $50,000. As of
December 31, 1998, outstanding borrowings under the facility were $80 million.
For the year ended December 31, 1998, the Company paid a total $0.5 million in
interest and fees to KeySpan. Borrowings were used to finance a portion of the
November 1998 Chevron Acquisition. See Note 11--Acquisitions.
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) receives a quarterly payment of $0.75 for every dollar of tax credit
utilized. The Company manages and administers the daily operations of the
properties in exchange for an annual management fee of $100,000. The income
statement effect for the years ended December 31, 1998 and 1997 was a reduction
to income tax expense of approximately $1.0 million and
F-16
<PAGE> 64
$1.2 million, respectively, representing benefits received from the Section 29
tax credits. 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.
General and Administrative Expense
The Company reimburses Brooklyn Union for certain general and
administrative costs. During the years ended December 31, 1998, 1997 and 1996,
the Company paid Brooklyn Union $-0-, $0.1 million and $0.6 million in general
and administrative reimbursements.
Gas Sales
During 1998 and 1997, the Company had no gas sales to related parties.
During the year ended December 31, 1996, the Company had natural gas sales of
$26.7 million, representing 40% of the Company's natural gas and oil revenues,
to a then affiliate of Brooklyn Union, PennUnion Energy Services, L.L.C.
("PennUnion"). The Company's term supply agreement with PennUnion 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 Company believes that prices at which it sold gas to PennUnion were similar
to those it would have been able to obtain in the open market.
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.
In July of 1996 and pursuant to such employment agreement, affiliates of the
Company's President obtained a 5% working interest in the 142 wells acquired by
the Company in the Charco Acquisition (see Note 11 --Acquisitions) and the right
to participate with a 5% working interest in any future wells drilled by the
Company on the Charco acreage acquired. During 1998, 1997 and 1996, affiliates
of the Company's President paid $2.7 million, $3.3 million and $1.4 million,
respectively, in costs and expenses attributable to working interests owned in
properties operated by the Company, and received $4.7 million, $3.9 million and
$1.6 million, respectively, in distributions attributable to such working
interests.
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 4%percent net
revenue interest in certain properties acquired by the Company. No assignments
were made subsequent to the year ended December 31, 1995. 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 15% 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
F-17
<PAGE> 65
of their vested account balances upon termination of employment. The Company
made contributions to the 401(k) Plan of $0.2 million in each of the three years
ended December 31, 1998, 1997 and 1996.
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. The Company accrued $123,000 for each of the years ended
December 31, 1998 and 1997 related to the SERP. In 1996, no amounts were accrued
as required accruals were de minimus.
NOTE 8 -- HEDGING CONTRACTS
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 consolidated balance sheets at
December 31, 1998 and 1997. At December 31, 1998, the Company had one interest
rate swap agreement to exchange the differential between the fixed rate of
6.025% and a market LIBOR rate using an aggregate notional principal of $30.0
million over various 90-day periods from November 1998 through November 1999. As
of December 31, 1998 and 1997, the estimated fair value of the interest rate
swap agreements were $0.4 million and $0.2 million, respectively, both in a
payable position.
Natural Gas Price Swaps, Options and Collars
As of December 31, 1998, the Company had entered into commodity price
hedging contracts with respect to its production for 1999 as follows:
<TABLE>
<CAPTION>
FIXED PRICE SWAPS COLLARS OPTIONS FAIR VALUE
----------------------- ----------------------------- ------------------------------- -------------
NYMEX NYMEX NYMEX
VOLUME CONTRACT VOLUME CONTRACT PRICE VOLUME STRIKE
PERIOD (MMMBTU) PRICE (MMMBTU) FLOOR CEILING (MMMBTU) PRICE PUT/CALL ($ THOUSANDS)
- -------------- -------- -------- -------- ----- ------- -------- ----- -------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
January 1999 755 $ 2.50 -- -- -- -- -- -- $ 534
February 1999 -- -- 280 $ 2.40 $ 2.90 -- -- -- $ 126
</TABLE>
As of December 31, 1997, the Company had entered into commodity price
hedging contracts with respect to its production for 1998 as follows:
<TABLE>
<CAPTION>
FIXED PRICE SWAPS COLLARS OPTIONS FAIR VALUE
----------------------- ----------------------------- ------------------------------- -------------
NYMEX NYMEX NYMEX
VOLUME CONTRACT VOLUME CONTRACT PRICE VOLUME STRIKE
PERIOD (MMMBTU) PRICE (MMMBTU) FLOOR CEILING (MMMBTU) PRICE PUT/CALL ($ THOUSANDS)
- -------------- -------- -------- -------- ----- ------- -------- ----- -------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
January 1998 355 $ 2.07 1,860 $ 2.73 $ 3.88 155 $ 2.01 Put $ 793
February 1998 340 2.07 1,120 $ 2.65 $ 3.16 140 $ 2.01 Put $ 405
February 1998 560 $ 3.50 Call $ 3
March 1998 355 2.07 930 $ 2.25 $ 2.75 155 $ 2.01 Put $ 95
</TABLE>
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
F-18
<PAGE> 66
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 fair value is
calculated using prices derived from NYMEX futures contract prices existing at
December 31 1998 or 1997, as appropriate. NYMEX natural gas price closed at
$2.14 per MMbtu and $2.68 per MMbtu at December 31, 1998 and 1997, respectively.
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 NYMEX price, the Company believes that it has no material
basis risk.
NOTE 9 -- SALES TO MAJOR CUSTOMERS
The Company sold natural gas and oil production representing 10% or more
of its natural gas and oil revenues for the year ended December 31, 1998 to H&N
Gas Ltd. (27%) and Columbia Energy Services Corporation (12%); for the year
ended December 31, 1997 to H&N Gas Ltd. (38%), and for the year ended December
31, 1996 PennUnion (40%) and H&N Gas Ltd. (27%). As is the nature of the
exploration, development and production business, production is normally sold to
relatively few customers. However, based on the current demand for natural gas
and oil, the Company believes that the loss of any of the Company's major
purchasers would not have a material adverse effect on the Company's operations.
Prior to October 1996, PennUnion was an affiliate of Brooklyn Union. The
Company's purchase and sale agreement with PennUnion was terminated in September
1996 with Brooklyn Union's sale of its interest in PennUnion. 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.
Leases
The Company has entered into certain noncancellable 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 (in thousands):
<TABLE>
<CAPTION>
Year ended December 31,
<C> <C>
1999................................................... $ 392
2000................................................... 392
2001................................................... 392
2002................................................... 460
2003................................................... 554
Thereafter............................................. $ 323
</TABLE>
F-19
<PAGE> 67
Net rental expense related to these leases was $0.3 million for each of
the years ended December 31, 1998, 1997 and 1996.
NOTE 11 -- 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, 1998, the
outstanding balance owed by Mr. Floyd under the agreement was $3.5 million and
the loan will mature on July 2, 2006.
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 agreed to pay Soxco a deferred purchase price of up to $17.6 million
effective January 31, 1998. The amount of the deferred purchase price was
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
was entitled to receive a minimum deferred purchase price of approximately $8.8
million. On March 27, 1998, the Company issued 520,777 shares of common stock
with an aggregate value (determined by reference to the average price of the
Company's common stock over a specified period of 20 trading days) of $8.8
million to Soxco in payment of the deferred purchase price.
South Louisiana Acquisition
On April 29, 1998, the Company completed the acquisition of certain
natural gas and oil properties and associated gathering pipelines and equipment,
together with developed and undeveloped acreage, located in South Louisiana (the
"South Louisiana Acquisition"). The properties and acreage acquired are located
primarily in the South Lake Arthur and Lake Pagie Fields, located primarily in
Vermilion Parish and Terrebonne Parish, respectively. The properties purchased
represented interests in 57 producing wells. The net purchase price of $53.2
million was paid in cash, financed with borrowings under the Credit Facility.
F-20
<PAGE> 68
On October 16, 1998 and November 11, 1998, the Company completed the
acquisition of additional working interests in approximately 25 wells located in
the South Lake Arthur Field. The natural gas and oil properties acquired
consisted solely of incremental working interests in properties in which the
Company had previously acquired a working interest in April 1998. The net
purchase price of $24.8 million was paid in cash, financed with borrowings under
the Credit Facility.
Chevron Acquisition
On November 30, 1998, the Company acquired from Chevron U.S.A. Inc.
("Chevron") a 100% working interest in Chevron's Mustang Island A-31 Field in
the Gulf of Mexico (the "Chevron Acquisition"). The Mustang Island A-31 Field is
comprised of three adjacent blocks: Mustang Island A-22, A-31 and A-32. The
field has nine producing wells and three platforms. The net purchase price of
$84.9 million was paid in cash, financed in part by borrowings under the
Subordinated KeySpan Facility.
NOTE 12 -- SUBSEQUENT EVENTS
KeySpan Joint Venture
On March 15, 1999, the Company signed a joint exploration agreement ( the
"KeySpan Joint Venture") with a subsidiary of KeySpan, KeySpan Exploration &
Production, LLC, to explore for natural gas and oil over a term of three years
expiring December 31, 2001. The joint venture may be terminated at the option of
either party at the end of the then current calendar year. Houston Exploration
is joint venture manager and operator. Effective January 1, 1999, KeySpan will
commit approximately $100 million per calendar year and Houston Exploration will
commit its proportionate share of the funds per calendar year necessary to fund
a joint exploration and development drilling program. Houston Exploration will
contribute all of its currently undeveloped offshore leases to the Joint Venture
and KeySpan will receive 45% of Houston Exploration's working interest in all
prospects to be drilled under the program. Revenues will be shared 55% Houston
Exploration and 45% KeySpan. During the term of the KeySpan Joint Venture,
KeySpan will pay 100% of actual intangible drilling costs up to a maximum of
$20.7 million per year. All additional intangible drilling costs incurred during
such year will be paid 51.75% by KeySpan and 48.25% by Houston Exploration. In
addition, Houston Exploration will receive reimbursement of a portion of its
general and administrative costs during the term of the KeySpan Joint Venture.
The Company plans to drill approximately 8 to 10 offshore exploratory wells
under the terms of the KeySpan Joint Venture during 1999. Both Houston
Exploration and KeySpan obtained separate opinions, each from a nationally
recognized investment banking firm, as to the fairness to the Company and its
noteholders and to KeySpan, respectively, of the KeySpan Joint Venture, from a
financial point of view. A special committee, comprised of outside, unaffiliated
directors, appointed by the Company's Board of Directors has determined that the
joint venture is fair to the Company's stockholders.
F-21
<PAGE> 69
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, 1998, 1997 and 1996, the Company's capitalized costs of
natural gas and oil properties are as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------
1998 1997 1996
------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Unevaluated properties, not amortized.......................... $ 145,317 $ 104,075 $ 60,258
Properties subject to amortization............................. 828,168 566,868 468,062
------------ ------------ ------------
Capitalized costs.............................................. 973,485 670,943 528,320
Accumulated depreciation, depletion and amortization........... (438,974) (229,776) (171,258)
------------ ------------ ------------
Net capitalized costs................................ $ 534,511 $ 441,167 $ 357,062
============ ============ ============
</TABLE>
The following is a summary of the costs (in thousands) which are excluded
from the amortization calculation as of December 31, 1998, 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, 1998 will be fully evaluated within five
years.
<TABLE>
<S> <C>
1998......................................... $ 68,931
1997......................................... 34,259
1996......................................... 19,766
Prior........................................ 22,361
----------
$ 145,317
==========
</TABLE>
Costs incurred for natural gas and oil exploration, development and
acquisition are summarized below. Costs incurred during the years ended December
31, 1998, 1997 and 1996 include interest expense, general and administrative
costs related to acquisition, exploration and development of natural gas and oil
properties, of $17.3 million, $13.1 million and $8.8 million, respectively.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------
1998 1997 1996
------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition:
Unevaluated(1)................................................. $ 33,803 $ 16,613 $ 23,317
Proved......................................................... 162,083 24,007 94,774
Exploration costs................................................ 55,611 44,119 27,398
Development costs................................................ 51,046 59,244 31,243
------------ ------------ ------------
Total costs incurred................................... $ 302,543 $ 143,983 $ 176,732
============ ============ ============
</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)
F-22
<PAGE> 70
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.
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.
F-23
<PAGE> 71
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>
A OF DECEMBER 31,
----------------------------------------------
1998 1997 1996
------------- ------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows.................................... $ 878,448 $ 781,336 $ 1,117,058
Future production costs................................ (153,567) (135,437) (153,452)
Future development costs............................... (103,915) (84,658) (67,966)
Future income taxes.................................... (89,032) (124,510) (230,316)
------------- ------------- -------------
Future net cash flows.................................. 531,934 436,731 665,324
10% annual discount for estimated timing of
cash flows........................................... (135,874) (121,351) (212,742)
------------- ------------- -------------
Standardized measure of discounted future net
cash flows........................................... $ 396,060 $ 315,380 $ 452,582
============= ============= =============
</TABLE>
Future cash inflows include the effect of hedges in place at year end
December 31, 1998, 1997 and 1996. At December 31, 1998 the effect of the hedges
in place is an increase of $0.4 million to future cash inflows. As of December
31, 1997, and 1996 the effect of the hedges in place is a reduction to future
cash inflows of $0.5 million and $28.7 million, respectively.
The following table summarizes changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------------
1998 1997 1996
----------- ----------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of the year.................................. $ 315,380 $ 452,582 $ 171,459
Revisions to previous estimates:
Changes in prices and costs.......................... (104,137) (223,169) 145,385
Changes in quantities................................ (4,982) (23,156) (19,132)
Changes in future development costs.................. (6,656) (20,499) (14,068)
Development costs incurred during the period........... 15,891 16,154 19,594
Extensions and discoveries, net of related costs....... 72,333 114,893 46,616
Sales of natural gas and oil, net of production costs.. (105,958) (97,968) (52,663)
Accretion of discount.................................. 37,706 57,700 20,652
Net change in income taxes............................. 44,812 62,733 (89,353)
Purchase of reserves in place.......................... 156,122 2,463 251,713
Sale of reserves in place.............................. (863) (608) (723)
Production timing and other............................ (23,588) (25,745) (26,898)
----------- ----------- ----------
End of year............................................ $ 396,060 $ 315,380 $ 452,582
=========== =========== ==========
</TABLE>
F-24
<PAGE> 72
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,
1998, 1997 and 1996.
<TABLE>
<CAPTION>
NATURAL GAS CRUDE OIL AND CONDENSATE
(MMCF) (MBBLS)
------------------------------------ ----------------------------------
1998 1997 1996 1998 1997 1996
--------- --------- --------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:............... 330,601 320,474 195,946 1,077 1,131 889
Revisions of previous estimates........ (4,656) (18,743) (8,665) (105) (62) (157)
Extensions and discoveries............. 67,272 75,651 21,445 249 184 198
Production............................. (61,479) (50,310) (31,215) (225) (171) (118)
Purchase of reserves in place.......... 139,994 3,778 143,688 665 1 361
Sales of reserves in place............. (1,285) (249) (725) (11) (6) (42)
--------- --------- --------- -------- -------- --------
End of year............................ 470,447 330,601 320,474 1,650 1,077 1,131
========= ========= ========= ======== ======== ========
Proved developed reserves:
Beginning of year...................... 256,632 236,544 162,784 914 1,013 774
End of year............................ 369,931 256,632 236,544 1,498 914 1,013
</TABLE>
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>
1998
Total revenues.............................. $ 33,084 $ 35,511 $ 30,853 $ 28,799
Income (loss) from operations(1)............ 7,208 8,700 3,927 (128,678)
Net income (loss)(1)........................ 4,723 5,306 2,003 (84,718)
Net income (loss) per share................. $ 0.20 $ 0.22 $ 0.08 $ (3.55)
Net income (loss) per share-- fully diluted $ 0.20 $ 0.22 $ 0.08 $ (3.55)
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-- fully diluted........ $ 0.24 $ 0.14 $ 0.23 $ 0.35
</TABLE>
- ---------------------------
(1) Includes a fourth quarter 1998 non-cash charge for the writedown in the
carrying value of natural gas and oil properties of $130.0 million, $84.5
million after taxes, as required under full cost accounting rules. See Note 1--
Natural Gas and Oil Properties.
F-25
<PAGE> 73
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).
10.3** -- 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).
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).
10.7 -- 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).
</TABLE>
<PAGE> 74
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
-------- -----------
<S> <C>
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 (filed as Exhibit 10.11 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1997
(001-11899) and incorporated by reference herein).
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).
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).
</TABLE>
<PAGE> 75
<TABLE>
<CAPTION>
EXHIBITS DESCRIPTION
-------- -----------
<S> <C>
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 (filed
as Exhibit 10.24 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1997 (File No. 001- 11899) and
incorporated by reference herein).
10.25 -- Indenture, dated as of March 2, 1998, between The Houston
Exploration Company and The Bank of New York, as Trustee, with
respect to the 85/8% Senior Subordinated Notes Due 2008
(including form of 85/8% Senior Subordinated Note Due 2008)
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-4 (No. 333-50235)).
10.26 -- Registration Rights Agreement, dated as of March 2, 1998,
among The Houston Exploration Company, as issuer, and Donaldson,
Lufkin & Jenrette Securities Corporation, Salomon Brothers Inc,
PaineWebber Incorporated, Chase Securities Inc., and Howard,
Weil, Labouisse, Friedrichs Incorporated (incorporated by
reference to Exhibit 4.2 to the Company's Registration Statement
on Form S-4 (No. 333-50235)).
10.27 -- Third Amendment to Credit Agreement among The Houston
Exploration Company and Chase Bank of Texas National
Association, dated February 12,1998 (filed as Exhibit 10.1 to
the Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998 (File No. 001- 11899) and incorporated by
reference herein).
10.28** -- Amended and Restated 1996 Stock Option Plan (filed as Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1998 (File No. 001-11899) and
incorporated by reference herein.
10.29** -- Employment Agreement dated May 1, 1998 between The Houston
Exploration Company and Thomas E. Schwartz (filed as Exhibit
10.2 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1998 (File No. 001-11899) and
incorporated by reference herein.
*10.30 -- Subordinated Loan Agreement dated November 30, 1998 between
The Houston Exploration Company and MarketSpan Corporation d/b/a
KeySpan Energy Corporation.
*10.31 -- Subordination Agreement dated November 25, 1998 entered into
and among MarketSpan Corporation d/b/a KeySpan Energy
Corporation, The Houston Exploration Company and Chase Bank of
Texas, National Association.
*12.1 -- Computation of ratio of earnings to fixed charges.
*21.1 -- Subsidiaries of the Company.
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Netherland, Sewell & Associates.
*23.3 -- Consent of Miller and Lents.
*23.4 -- Consent of Ryder Scott Company.
*27.1 -- Financial Data Schedule.
</TABLE>
- -----------------
* Filed herewith.
** Management contract or compensation plan.
<PAGE> 1
EXHIBIT 10.30
Subordinated Loan Agreement
Dated as of November 30, 1998
Between
The Houston Exploration Company
and
MarketSpan Corporation d/b/a KeySpan Energy
Borrower: The Houston Exploration Company ("Houston
Exploration"), a publicly-traded Delaware
corporation.
Guarantors: All Significant Subsidiaries of the Borrower
which may execute a Guaranty Agreement. (There
are currently no Significant Subsidiaries.)
Lender: MarketSpan Corporation d/b/a KeySpan Energy
(the "Lender").
Type of Facility: Subordinated Loan which will be a six month
Revolving Credit Facility.
Total Commitment Amount: $150,000,000
Purpose: Proceeds of the Facility will be utilized to
temporarily finance hydrocarbon acquisitions.
Maturity Date: All outstanding principal, unpaid accrued
interest and fees will be repaid at maturity,
January 1, 2000. Any principal amount that
remains outstanding subsequent to the Maturity
Date will be converted into equity (the number
of shares to be issued to the Lender will be
determined based upon the average of the closing
prices of Houston Exploration's common stock,
rounded to three decimal places, as reported
under "NYSE Composite Transactions Reports" in
the Wall Street Journal during 20 consecutive
trading days ending three days prior to January
1, 2000. Because the market value represents an
average of Houston Exploration's common stock
over twenty consecutive trading days, ending
three days prior to maturity, the market price
may be higher or lower than the price of the
common stock on the conversion date). The total
amount converted to equity shall not exceed the
Total Commitment Amount. Any unpaid accrued
interest or fees that remain outstanding
subsequent to the Maturity Date will be paid in
cash.
Security: Unsecured. The Borrower provides a negative
pledge on unencumbered assets.
Availability: The borrowings may be repaid and reborrowed in
minimum amounts of $5 million (or increments of
$1 million in excess thereof) under the
Facility. Subject to the provisions of Section 3
of the Subordination Agreement (see Schedule
II).
Optional Commitment
Reductions: The Revolving Credit commitment may be
permanently reduced upon 3 days notice from the
Borrower in minimum amounts of $5 million (and
integral amounts of $5 million) subject to
Prepayments below, provided that any amounts
outstanding which would exceed the total
commitment
<PAGE> 2
as reduced, must be prepaid together with
interest thereon and any relevant costs. Subject
to the provisions of Section 3 of the
Subordination Agreement (see Schedule II).
Optional Prepayments: Borrowings may be prepaid, along with associated
interest, subject to one business day notice to
the Lender. Subject to the provisions of Section
3 of the Subordination Agreement (see Schedule
II).
Mandatory Prepayments: Upon any default of payment of interest or fees,
property sales, or casualty losses, the Borrower
shall make a Mandatory Repayment in the amount
of such excess amount. Subject to the provisions
of Section 3 of the Subordination Agreement
(see Schedule II).
Interest Rates: See Schedule 1.
Fees: See Schedule 1.
Interest Periods: The one month LIBOR rate will be set on
the date of each drawndown, as quoted in that
day's Wall Street Journal (which reflects the
previous business day's market rates). The rate
will be effective until the rate is reset on the
first business day of each month.
Notification Schedule: The Borrower must provide notice prior to the
proposed date of borrowing, in accordance with
the following schedule:
Amounts greater than $10 million - 5 business
days Amounts equal to, or less than, $10 million
- 3 business days
Default Interest Rate: Default interest will be 2% in excess of the
LIBOR Rate, plus margins referred to in Schedule
1, subject to applicable law. Interest shall
accrue at the post-default rates stated above on
amounts which remain unpaid after they become
due and payable.
Conditions to Lending: This Agreement shall be come effective on the
date hereof, if this Agreement shall have been
executed by the Borrower and the Lender, and the
Lender shall have received on or before the
effective date:
a) A Promissory Note payable to the order
of the Lender;
b) A counterpart of this Agreement duly
executed by the Borrower and the Lender,
which shall constitute the valid and
legal binding obligation of the
Borrower, legally enforceable in
accordance with its terms. Accompanied
by legal opinions of the Borrower's
counsel, certificates of the Borrower
and other supporting documents as the
Lender may reasonably request.
c) A certificate of the Secretary or an
Assistant Secretary of the Borrower
certifying copies (i) of the resolutions
of the Board of Directors of the
Borrower approving such Agreement, (ii)
of all documents evidencing other
necessary corporate action and
approvals, and (iii) that all lenders
and other parties in privity with the
Borrower whose consents are, or with
reasonable certainty may be,
prerequisite to the consummation of the
Facility or of the transactions
contemplated hereunder, shall have
consented to the same.
2
<PAGE> 3
d) A certificate of an officer of the
Borrower certifying the names and true
signatures of the officers of the
Borrower authorized to sign this
Agreement and the other documents and
instruments to be delivered hereunder
and thereunder.this Agreement and each
this Agreement and the other documents
and instruments to be delivered
hereunder and thereunder.
e) All fees and costs required under the
Agreement to be paid by the Closing Date
shall have been paid in full. Subject to
the provisions of Section 3 of the
Subordination Agreement (see Schedule
II).
f) Since September 30, 1998, there shall
not have occurred any material adverse
change in the financial condition,
business, properties or results of
operations of the Borrower.
g) After consummation of this financing and
after giving effect to the transactions
contemplated hereunder, such
consummation and transactions will not
violate any other material agreement or
contractual obligation of the Borrower
or its subsidiaries.
h) Written certification of the completion
of the Chevron acquisition for total
consideration of no more than $86
million.
Representations and
Warranties: The Borrower hereby represents and warrants to
the Lender, on and as of the date hereof, and
after giving effect to this Agreement
a) Corporate authority;
b) Execution, delivery and performance of
Loan Documents do not violate existing
law or existing agreements or require
consents;
c) No material litigation;
d) No material adverse change in the
financial condition or results of
operations;
e) Accuracy of financial statements;
f) Material compliance with ERISA;
g) No material environmental issues;
h) Legality, validity, binding effect and
enforceability of this Agreement;
i) Solvency
j) Compliance with laws;
k) Not an investment company or a "holding
company" within the meaning of the
Public Utility Holding Company Act of
1935, as amended; and
l) Title to properties.
3
<PAGE> 4
Financial Covenants: So long as any Note shall remain unpaid or the
Lender shall have any commitment hereunder, the
Borrower will not, without the written consent
of the Lender:
a) permit the total debt to capitalization
ratio to exceed 60%. Total Debt shall be
defined as (a) all borrowed money, (b)
trade debt which is past due, c)
liabilities under any bond, note,
security, letter of credit (other than
L/C's issued hereunder for trade credit
but including L/C's issued hereunder as
performance guarantees) or acceptance
financing, (d) guarantees, (e) capital
lease obligations and (f) all Hedging
Agreement obligations once such
obligations become "debt"; and
b) permit the interest Coverage Ratio
(EBITDA / Interest Expense) to be
greater than or equal to 2.5x.
Covenants: Customary for transactions of this nature,
including but not limited to, the following:
a) Reporting requirement;
b) Negative pledge of unencumbered assets;
c) Limitation on additional indebtedness;
d) Limitation on liens except permitted
liens;
e) Restriction on mergers, consolidations
and sale of oil and gas properties in
excess of $500,000;
f) Use of proceeds;
g) Maintenance of insurance;
h) Maintenance of books and records;
i) Visitation rights;
j) Material compliance with all laws and
payment of taxes;
k) Maintenance of title;
l) Limitations on Dividends;
m) Transactions with affiliates on an arms
length basis;
n) Limitations on creation of Subsidiaries;
and
o) Hedging limited to 70% of projected
production and may not exceed beyond 2
years.
4
<PAGE> 5
Events of Default: The events of default that follow are
subordinate to the Subordination Agreement
(Schedule II):
a) Failure to pay principal when due; and
interest and fees within three business
days of when due;
b) Representations and Warranties
materially incorrect;
c) Failure to comply with covenants (with
notice and cure periods as applicable);
d) Cross-default to payment defaults on
principal aggregating $500,000 or to
default or event if the effect is to
accelerate principal aggregating
$1,000,000;
e) Bankruptcy / insolvency;
f) Unsatisfied judgment or order in excess
of $1,000,000;
g) ERISA; and
h) Direct or indirect Brooklyn Union Gas
corp. ownership of the Borrower of at
least 60%.
Governing Law: State of New York
Indemnification: Borrower will indemnify the Lender and its
officers, directors, shareholders, employees,
agents and attorneys (the "Indemnitees") against
all costs, expenses (including fees and
disbursements of counsel) and liabilities
arising out of or relating to the Facilities and
the transactions contemplated thereby, including
consequences of their own negligence, provided
that none of the indemnitees will be indemnified
for the consequences of its gross negligence or
willful misconduct.
MARKETSPAN CORPORATION D/B/A KEYSPAN ENERGY
BY: /s/ Robert R Wieczorek
----------------------------------------
Robert R. Wieczorek
Vice President, Secretary and Treasurer
One Metrotech Center
Brooklyn, New York
THE HOUSTON EXPLORATION COMPANY
BY: /s/ Thomas W. Powers
----------------------------------------
Thomas W. Powers
Senior Vice President
1100 Louisiana, Suite 2000
Houston, Texas 77002
5
<PAGE> 6
Schedule I
Subordinated Loan Agreement
Dated as of November 30, 1998
Between
The Houston Exploration Company
and
MarketSpan Corporation d/b/a KeySpan Energy
Total Commitment Amount: $150,000,000
Interest Rate and Fees: Interest Rate & Fee Margins
--------------------------------------------------------
LIBOR 140 bps
--------------------------------------------------------
Commitment Fee 12.5 bps on unused portion of the Total
Commitment Amount
--------------------------------------------------------
Upfront Fee $50,000
--------------------------------------------------------
Initial Interest Period: November 30, 1998 through January 4, 1999.
Interest Periods: The one month LIBOR rate will be set on
the date of each drawndown, as quoted in that
day's Wall Street Journal (which reflects the
previous business day's market rates). The rate
will be effective until the rate is reset on the
first business day of each month.
Interest Payment Dates: In arrears, on the first business day following
the end of each calendar month.
Payments and
Computations: The Borrower shall make each payment hereunder
to the Lender, on the day when due, in lawful
money of the United States of America in same
day funds, by wire transfer to the Lender's
account (provide wire instructions) not later
than 12:00 noon (New York City time).
Computations of the LIBOR rate, commissions, and
fees shall be made by the Lender on the basis of
a year of 360 days for the actual number of days
(including the first day but excluding the last
day) elapsed.
Whenever any payment to be made hereunder shall
be stated to be due, or whenever the last day of
any Interest Period would otherwise occur, on a
day which is not a Business Day, such payment
shall be made, and the last day of such Interest
Period shall occur, on the next succeeding
Business, and such extension of time shall in
such case be included in the computation of
interest, commission or fee, as the case may be.
6
<PAGE> 7
Maturity Date: All outstanding principal, unpaid accrued
interest and fees will be repaid at maturity,
January 1, 2000. Any principal amount that
remains outstanding subsequent to the Maturity
Date will be converted into equity (the number
of shares to be issued to the Lender will be
determined based upon the average of the closing
prices of Houston Exploration's common stock,
rounded to three decimal places, as reported
under "NYSE Composite Transactions Reports" in
the Wall Street Journal during 20 consecutive
trading days ending three days prior to January
1, 2000. Because the market value represents an
average of Houston Exploration's common stock
over twenty consecutive trading days, ending
three days prior to maturity, the market price
may be higher or lower than the price of the
common stock on the conversion date). The total
amount converted to equity shall not exceed the
Total Commitment Amount. Any unpaid accrued
interest or fees that remain outstanding
subsequent to the Maturity Date will be paid in
cash.
MARKETSPAN CORPORATION D/B/A KEYSPAN ENERGY
BY: /s/ Robert R. Wieczorek
---------------------------------------
Robert R. Wieczorek
Vice President, Secretary and Treasurer
One MetroTech Center
Brooklyn, New York
THE HOUSTON EXPLORATION COMPANY
BY: /s/ Thomas W. Powers
---------------------------------------
Thomas W. Powers
Senior Vice President
1100 Louisiana, Suite 2000
Houston, Texas 77002
7
<PAGE> 1
EXHIBIT 10.31
Schedule II
SUBORDINATION AGREEMENT
THIS SUBORDINATION AGREEMENT (this "AGREEMENT"), dated as of November
25, 1998, is entered into by and among MARKETSPAN CORPORATION d/b/a KEYSPAN
ENERGY CORP. ("SUBORDINATED CREDITOR"), THE HOUSTON EXPLORATION COMPANY
("DEBTOR") and CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, as agent ("AGENT") for
itself and each of the other banks or lending institutions (the "BANKS") that is
now or hereafter becomes a party to the Credit Agreement (hereinafter defined).
PRELIMINARY STATEMENTS:
A. The Debtor, the Agent and the Banks are parties to that certain
Credit Agreement dated as of July 2, 1996, as amended by a First Amendment to
Credit Agreement and Security Agreement dated as of August 30, 1996, a Second
Amendment to Credit Agreement dated as of August 4, 1997, a Third Amendment to
Credit Agreement dated as of February 12, 1998 (and as further amended from time
to time, the "CREDIT AGREEMENT") under the terms of which the Banks agreed to
make available to the Debtor a revolving line of credit not to exceed, in the
aggregate, $150,000,000.00 at any one time outstanding.
B. Debtor is indebted to Subordinated Creditor and/or may become
indebted to Subordinated Creditor. All indebtedness now owing, and all other
indebtedness, liabilities or obligations of Debtor to Subordinated Creditor, now
or hereafter existing (whether created directly or acquired by assignment or
otherwise; whether evidenced by a note or otherwise; whether absolute or
contingent; whether joint, several or independent; whether arising by operation
of law or otherwise), including, without limitation, that certain loan from
Subordinated Creditor to Debtor in the original principal amount of up to
$150,000,000.00, as same may be renewed, consolidated, amended, extended, or
otherwise modified plus interest and premiums, if any, thereon and other amounts
payable in respect thereof are hereinafter referred to as the "SUBORDINATED
DEBT" of Subordinated Creditor; and
WHEREAS, it is a condition precedent to the consent by the Banks to the
creation of the Subordinated Debt that Subordinated Creditor and Debtor shall
have executed and delivered this Agreement to Agent.
NOW, THEREFORE, in consideration of the premises and in order to induce
the Banks to consent to the creation and existence of the Subordinated Debt,
Subordinated Creditor and Debtor hereby agree as follows:
SECTION 1. 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.
SECTION 2. Agreement to Subordinate. Subordinated Creditor and Debtor agree that
the payment of the principal of, and interest on, and all other amounts owing in
respect of the Subordinated Debt is and shall be hereby expressly subordinated,
to the extent and in the manner hereinafter set forth, to the prior payment in
full of all indebtedness, liabilities and obligations of the Debtor arising
under or in conjunction with the Credit Agreement, Notes, Letter of Credit
Agreements or any other document or instrument executed in connection therewith
(collectively the "LOAN DOCUMENTS") whether now or hereafter existing, whether
for principal, interest (including without limitation interest accruing after
the commencement of any proceeding referred to in Section 3), or whether fees,
expenses or otherwise (all such obligations being the "SENIOR INDEBTEDNESS").
SECTION 3.A No Payment on the Subordinated Debt. (a) No payment shall be made by
Debtor, directly or indirectly, in respect of the principal of, or interest
(except as provided in 3.B) or premium on, or otherwise owing in respect of, the
Subordinated Debt, and Subordinated Creditor shall not ask, demand, sue for,
take any action to enforce, take or receive, directly or indirectly, in cash or
other property, by sale, set-off or in any
8
<PAGE> 2
other manner whatsoever any amounts owing in respect of the Subordinated Debt,
unless and until all Senior Indebtedness has been paid in full and no commitment
is in existence to advance or create Senior Indebtedness; and (b) in the event
that, notwithstanding the provisions of the preceding subsection (a) of this
Section 3.A, Debtor shall make any payment on account of the principal of, or
interest on, or amounts otherwise owing in respect of, the Subordinated Debt
while Senior Indebtedness has not been paid in full or while a commitment is in
existence to advance or create any Senior Indebtedness, such payment shall be
segregated from other funds and property of Subordinated Creditor and held by
the Subordinated Creditor, in trust for the benefit of, and shall forthwith be
paid over and delivered to, Agent (with any necessary endorsement) for
application pro rata to the payment of all Senior Indebtedness remaining unpaid
to the extent necessary to pay all Senior Indebtedness or held as collateral in
the case of non cash property for the payment of the Senior Indebtedness. B.
INTEREST ON SUBORDINATED DEBT PRIOR TO DEFAULT. NOTWITHSTANDING ANYTHING TO THE
CONTRARY CONTAINED IN 3.A SO LONG AS THERE SHALL EXIST NO DEFAULT UNDER THE
SENIOR INDEBTEDNESS OR EVENT OF DEFAULT AS DEFINED IN ANY OF THE LOAN DOCUMENTS,
DEBTOR MAY MAKE, AND SUBORDINATED CREDITOR MAY RECEIVE AND RETAIN FOR ITS OWN
ACCOUNT, REGULARLY SCHEDULED ACCRUED INTEREST PAYMENTS AS AND WHEN SUCH INTEREST
PAYMENTS ARE DUE ON THE SUBORDINATED NOTE, AND EACH OF DEBTOR AND SUBORDINATED
CREDITOR SHALL MAINTAIN RECORDS WITH RESPECT TO SUCH INTEREST PAYMENTS AND UPON
THE HAPPENING OF ANY EVENT OF DEFAULT AND DURING THE EXISTENCE OF ANY DEFAULT,
DEBTOR SHALL HAVE NO RIGHT TO MAKE, AND SUBORDINATED CREDITOR SHALL CEASE TO
HAVE THE RIGHT TO RECEIVE AND RETAIN SUCH INTEREST PAYMENTS.
SECTION 4. In Furtherance of Subordination. (a) Upon any distribution of all or
any of the assets of Debtor (whether in connection with the dissolution, winding
up, liquidation, arrangement, reorganization, adjustment, protection, relief or
composition of Debtor or its debts or whether in any bankruptcy, insolvency,
arrangement, reorganization, receivership, relief or similar proceedings or
whether upon an assignment for the benefit of creditors or otherwise) the
following provisions shall apply: (i) Agent shall first be entitled to receive
payment in full of the principal thereof, premium, if any, and interest
(including post-petition interest) due thereon before Subordinated Creditor or
the holder of the Subordinated Debt is entitled to receive any payment on
account of the principal of or interest on or any other amount owing in respect
of the Subordinated Debt; (ii) any payment, dividend or distribution of assets
of Debtor of any kind or character, whether in cash, property or securities to
which Subordinated Creditor or the holder of the Subordinated Debt would be
entitled except for the provisions of this Agreement, shall be paid by the
liquidating trustee or agent or other person making such payment or
distribution, whether a trustee in bankruptcy, a receiver or liquidating trustee
or other trustee or agent, directly to Agent, to the extent necessary to make
payment in full of all Senior Indebtedness remaining unpaid; (iii) in any such
proceeding, Agent is hereby irrevocably authorized and empowered (in the name of
Subordinated Creditor or otherwise), but shall have no obligation, to demand,
sue for, collect and receive every payment or distribution referred to in
clauses (i) and (ii) of subsection (a) above and given acquittance therefor and
to file claims and proofs of claim and take such other action (including,
without limitation, voting the Subordinated Debt or enforcing any security
interest or other lien securing payment of the Subordinated Debt) as it may deem
necessary or advisable for the exercise or enforcement of any of the rights or
interests of Agent; (iv) in any proceeding, Subordinated Creditor shall duly and
promptly take such action to the extent, and only to the extent as Agent may
expressly request: (A) to collect the Subordinated Debt for the account of Agent
and to file appropriate claims or proofs of claim in respect of the Subordinated
Debt; (B) to execute and deliver to Agent such powers of attorney, assignments,
or other instruments as it may request in order to enable it to enforce any and
all claims with respect to, and any security interests and other liens securing
payment of, the Subordinated Debt; and (C) to collect and receive any and all
payments or distributions which may be payable or deliverable upon or with
respect to the Subordinated Debt; and (v) in any such proceeding, Subordinated
Creditor shall not have any right to setoff against the Subordinated Debt any
indebtedness owned by Subordinated Creditor to Debtor (including, without
limitation, any right of setoff under Section 553 of the Bankruptcy Code), and
Subordinated Creditor hereby irrevocably agrees, to the fullest extent permitted
by law, that it will not exercise (and herein waives) any right of setoff. If
the foregoing waivers are adjudicated unenforceable by a court of competent
jurisdiction, then Subordinated Creditor agrees that, in the event that
Subordinated Creditor exercises any right of setoff in any such proceeding,
Subordinated Creditor will pay directly to Agent, an amount equal to the amount
of Subordinated
9
<PAGE> 3
Debt which was so setoff, for application to such Senior Indebtedness until all
such Senior Indebtedness shall have been paid in full; (b) in the event that,
notwithstanding the foregoing provisions of this Section 4, any payment or
distribution of assets of Debtor of any kind or character, whether in cash,
property or securities, shall be received by Subordinated Creditor on account of
principal or interest on Subordinated Debt before all Senior Indebtedness is
paid in full, or effective provision shall have been made for its payment, such
payment or distribution shall be received shall be paid over to Agent, for
application to the payment of such Senior Indebtedness until all such Senior
Indebtedness shall have been paid in full; and (c) Agent is hereby authorized to
demand specific performance of this Agreement, whether or not Debtor shall have
complied with any of the provisions hereof applicable to it, at any time when
Subordinated Creditor shall have failed to comply with any of the provisions of
this Agreement applicable to it. Subordinated Creditor hereby irrevocably waives
any defense based on the adequacy of a remedy at law, which might be asserted as
a bar to such remedy of specific performance.
SECTION 5. Subordination of all Liens. Subordinated Creditor agrees that it will
not hold any lien or security interest in any real or personal property as
security for the Subordinated Debt unless the Agent has given its prior written
consent to the creation thereof. In the event any Subordinated Creditor shall
acquire any lien or security interest as security for Subordinated Debt,
regardless of whether such lien or security interest is permitted or prohibited
by this Agreement or the Loan Documents, the Subordinated Creditor will hold
such lien or security interest for the benefit of the Agent and shall enforce
such lien or security interest in accordance with the written instructions of
the Agent. Any cash or other property received on account of any lien or
security interest securing the Subordinated Debt shall be delivered to the Agent
and, in the case of cash, applied to, or, in the case of other property, held as
collateral for, the Senior Indebtedness. To the extent that any Subordinated
Debt is now or hereafter secured by a lien or security interest (a "SUBORDINATE
LIEN") against any real or personal property that is also subject to a lien or
security interest securing the Senior Indebtedness (a "SENIOR LIEN"), the
Subordinated Creditor agrees that such Subordinate Lien shall be second, junior
and subordinate to such Senior Lien and such Senior Lien shall be first and
prior to such Subordinate Lien. It is further agreed that the priorities
specified in the preceding sentence are applicable irrespective of the time or
order of attachment or perfection of liens and security interests, or the time
or order of filing of liens and security interests, or the time or order of
filing of financing statements, or the giving or failure to give notice of the
acquisition or expected acquisition of purchase money or other security
interests.
SECTION 6. No Commencement of Any Proceeding. Subordinated Creditor agrees that,
so long as any of the Senior Indebtedness shall remain unpaid, it will not
commence, or join with any creditor other than Agent in commencing, any
proceeding referred to in Section 3(a).
SECTION 7. Rights of Subrogation. Subordinated Creditor agrees that no payment
or distribution to Agent pursuant to the provisions of this Agreement shall
entitle Subordinated Creditor to exercise any rights of subrogation in respect
thereof until the Senior Indebtedness shall have been paid in full.
SECTION 8. Subordination Legend; Further Assurances. Subordinated Creditor and
Debtor will cause each instrument evidencing Subordinated Debt to be endorsed
with the following legend:
"The indebtedness evidenced by this instrument is subordinated to the
prior payment in full of the Senior Indebtedness (as defined in the
Subordination Agreement hereinafter referred to) pursuant to, and to
the extent provided in, the Subordination Agreement effective as of
November 25, 1998, by the maker hereof and payee named herein in favor
of the Agent referred to in such Subordination Agreement."
Subordinated Creditor and Debtor each will further mark its books of account in
such a manner as shall be effective to give proper notice of the effect of this
Agreement and will, in the case of any Subordinated Debt which is not evidenced
by any instrument, upon Agent's reasonable request, cause such Subordinated Debt
to be evidenced by an appropriate instrument or instruments endorsed with the
above legend. Subordinated Creditor and Debtor each will, at its expense and at
any time and from time to time, promptly execute and deliver all further
instruments and documents, and take all further actions, that may be necessary
or desirable,
10
<PAGE> 4
or that Agent may reasonably request, in order to protect any right or interest
granted or purported to be granted hereby or to enable Agent to exercise and
enforce its rights and remedies hereunder.
SECTION 9. No Change in or Disposition of Subordinated Debt. Subordinated
Creditor shall not: (a) Cancel or otherwise discharge any of the Subordinated
Debt or subordinate any of the Subordinated Debt to any indebtedness of Debtor
other than the Senior Indebtedness; (b) Sell, assign, pledge, encumber or
otherwise dispose of any of the Subordinated Debt (and any attempted action in
violation of this paragraph (b) shall be void); or (c) Permit the terms of any
of the Subordinated Debt to be changed in such a manner as to have an adverse
effect upon the rights or interests of the Agent.
SECTION 10. Agreement by the Debtor. Debtor agrees that it will not make any
payment of any of the Subordinated Debt, nor take any other action, in
contravention of the provisions of this Agreement.
SECTION 11. Senior Indebtedness Hereunder Not Affected. All rights and interests
of Agent and the Banks, and all agreements and obligations of Subordinated
Creditor and Debtor under this Agreement, shall remain in full force and effect
irrespective of: (i) any lack of validity or enforceability of all or any
portion of this Agreement; (ii) any change in the amount of interest rate
accruing on, time, manner or place of payment of, or in any other term of, all
or any of the Senior Indebtedness, or any other amendment or waiver of any
consent to departure from any of the Loan Documents, including, without
limitation, changes in the terms of disbursement of the proceeds of the Loans or
repayment thereof, modifications, extensions or renewals of payment dates,
changes in interest rate or the advancement of additional funds by the Banks in
their discretion; (iii) any exchange, release or non-perfection of any
collateral or any release or amendment or waiver of or consent to departure from
any guaranty, for all or any of the Senior Indebtedness; or (iv) any other
circumstance in respect of this Agreement which might otherwise constitute a
defense available to, or a discharge of, Debtor or any guarantor of or in
respect of the Senior Indebtedness or the Subordinated Creditor.
SECTION 12. Reinstatement. This Agreement shall continue to be effective or be
reinstated, as the case may be, if at any time any payment of any of the Senior
Indebtedness is rescinded or must otherwise be returned by Agent upon the
insolvency, bankruptcy or reorganization of Debtor or otherwise, all as though
such payment had not been made.
SECTION 13. Waivers. Subordinated Creditor hereby waives promptness, diligence,
notice of acceptance, notice of intention to accelerate, notice of acceleration
and any other notice with respect to any of the Senior Indebtedness and this
Agreement and any requirement that Agent protect, secure, perfect or insure any
security interest or lien or any property subject thereto or exhaust any right
or take any action against Debtor or any other person or entity or any
collateral. Subordinated Creditor waives any right or benefit of any notice of
any action, event or circumstance relating to the Senior Indebtedness, including
but not limited to the incurrence, modification, default, exercise of remedies,
compromise or release of or with respect to Senior Indebtedness.
SECTION 14. Representations and Warranties. (a) Debtor hereby represents and
warrants as follows: (i) the Subordinated Debt now outstanding (true and
complete copies of any instruments evidencing which having been furnished to the
Agent) has been duly authorized by Debtor, has not been amended or otherwise
modified and constitutes the legal, valid and binding obligation of Debtor
enforceable against Debtor in accordance with its terms; (ii) there exists no
default in respect of any such Subordinated Debt; (iii) Debtor is a corporation
duly organized, validly existing and in good standing under the laws of the
jurisdiction of its incorporation as set forth on the first page hereof; and
Debtor has all requisite corporate power and authority to execute, deliver and
perform this Agreement; and (iv) The execution, delivery and performance by
Debtor of this Agreement have been duly authorized by all necessary corporate
action and do not and will not contravene its articles, charter or bylaws; and
(b) Subordinated Creditor hereby represents and warrants as follows: (i)
Subordinated Creditor owns the Subordinated Debt now outstanding free and clear
of any lien, security interest, charge or encumbrance or any rights of others;
(ii) The execution, delivery and performance by Subordinated Creditor of this
Agreement do not and will not contravene any law or governmental regulation or
any contractual restriction binding on or affecting Subordinated Creditor or any
of its properties,
11
<PAGE> 5
and do not and will not result in or require the creation of any lien, security
interest or other charge or encumbrance upon or with respect to any of its
properties; (iii) This Agreement is a legal, valid and binding obligation of
Subordinated Creditor, enforceable against Subordinated Creditor in accordance
with its terms except as limited by bankruptcy, insolvency or other laws of
general application relating to the enforcement of creditors' rights and by
general equitable principles; and (iv) There exists no default in respect of any
Subordinated Debt.
SECTION 15. Amendments, Etc. No amendment or waiver of any provision of this
Agreement nor consent to any departure by Subordinated Creditor or Debtor
therefrom shall in any event be effective unless the same shall be in writing
and signed by Agent, and then such waiver or consent shall be effective only in
the specific instance and for the specific purpose for which given.
SECTION 16. Expenses. DEBTOR AGREES TO pay, upon demand, to Agent the amount of
any and all reasonable expenses, including the reasonable fees and expenses of
its counsel, which Agent may incur in connection with the exercise or
enforcement of any of the rights or interests of the holders of Senior
Indebtedness hereunder.
SECTION 17. Addresses for Notices. All communications from any party to any
other shall be in writing (including telegraphic and telecopy communication).
Communications to any party shall be delivered to another party by certified or
registered mail, return receipt requested, or sent by private overnight courier
or telegraphed, or telecopied, addressed to it at the address of such party
specified next to its signature in this Agreement. Any party may designate a
different address for receipt of communications by written notice to the other
parties. All communications shall be effective when received and if receipt is
refused, either three (3) business days after deposit in the mail or the date of
attempted delivery as confirmed by private courier service, telegraph company or
telecopy operator.
SECTION 18. No Waiver, Remedies. No failure on the part of Agent to exercise,
and no delay in exercising, any right hereunder shall operate as a waiver
thereof; nor shall any single or partial exercise of any right hereunder
preclude any other or further exercise thereof or the exercise of any other
right. The remedies herein provided are cumulative and not exclusive of any
remedies provided by law.
SECTION 19. Continuing Agreement; Transfer of Notes. All warranties,
representations and covenants made by Subordinated Creditor or Debtor herein or
in any certificate or other instrument delivered by it or on its behalf shall be
considered to have been relied upon by Agent and shall survive execution and
delivery of the Loan Documents regardless of any investigation by or on behalf
of any thereof. This Agreement is a continuing agreement and shall:(i) remain in
full force and effect until the Senior Indebtedness shall have been paid in
full; (ii) be binding upon Subordinated Creditor, Debtor and its successors and
assigns and any subsequent holder of Subordinated Debt; and (iii) inure to the
benefit of and be enforceable by Agent and its successors, transferees and
assigns. Without limiting the generality of the foregoing clause (iii), any Bank
may assign or otherwise transfer its Note or any other evidence of any Senior
Indebtedness held by it to any other person or entity, and such other person or
entity shall thereupon become vested with all the rights in respect thereof
granted to such Bank herein or otherwise.
SECTION 20. GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS.
SECTION 21. Counterparts. This Agreement may be separately executed in any
number of counterparts and by different parties hereto in separate counterparts,
each of which when so executed shall be deemed to constitute one and the same
Agreement.
SECTION 22. Section Headings. Headings are for convenience only and shall be
given no substantive meaning or significance in construing this Agreement.
12
<PAGE> 6
SECTION 23. THIS AGREEMENT EMBODIES THE ENTIRE AGREEMENT AND UNDERSTANDING
BETWEEN AND AMONG THE PARTIES WITH RESPECT TO THE SUBJECT MATTER HEREOF AND
SUPERSEDES ALL PRIOR AGREEMENTS CONSENTS AND UNDERSTANDINGS RELATING TO SUCH
SUBJECT MATTER 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.
IN WITNESS WHEREOF, Debtor and Subordinated Creditor have caused this
Agreement to be duly executed and delivered by their officers thereunto duly
authorized as of the date first above written.
SUBORDINATED CREDITOR
KEYSPAN ENERGY CORP.
By: /s/ Robert R. Wieczorek
-----------------------------------------------
Name: Robert R. Wieczorek
Title: Vice President, Secretary and Treasurer
Address: One MetroTech Center
Brooklyn, New York 11201-3850
DEBTOR
THE HOUSTON EXPLORATION COMPANY
By: /s/ Thomas W. Powers
-----------------------------------------------
Thomas W. Powers, Senior Vice President
Address: 1100 Louisiana, Suite 2000
Houston, Texas 77002
AGENT
CHASE BANK OF TEXAS, NATIONAL ASSOCIATION
By: /s/ Paul J. Nidoh,
-----------------------------------------------
Paul J. Nidoh, Vice President
Address: 712 Main Street,
Houston, Texas 77002
13
<PAGE> 1
EXHIBIT 12.1
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Gross interest expense $ 14,414 $ 6,811 $ 6,365 $ 5,297 $ 3,597
Interest portion of rent expense 39 32 29 25 20
--------- --------- --------- --------- ---------
14,453 6,843 6,394 5,322 3,617
EARNINGS:
Income (loss) before taxes (113,440) 33,423 10,847 (4,112) 5,951
Plus: fixed charges 14,453 6,843 6,394 5,322 3,617
Less: capitalized interest (9,817) (5,873) (3,490) (2,899) (1,495)
--------- --------- --------- --------- ---------
$(108,804) $ 34,393 $ 13,751 $ (1,689) $ 8,073
RATIO OF EARNINGS TO FIXED CHARGES N/M 5.0x 2.2x N/M 2.2x
</TABLE>
<PAGE> 1
EXHIBIT 21.1
SUBSIDIARIES OF THE HOUSTON EXPLORATION COMPANY
Seneca Upshur Petroleum Company
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
We hereby consent to the references to Arthur Andersen LLP in this
Annual Report on Form 10-K of The Houston Exploration Company for the year ended
December 31, 1998.
ARTHUR ANDERSEN LLP
Houston, Texas
March 22, 1999
<PAGE> 1
EXHIBIT 23.2
CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.
We hereby consent to the references to us under captions "Part I, Item
1 and 2. Business and Properties Natural Gas and Oil Reserves" in this Annual
Report on Form 10-K of The Houston Exploration Company for the year ended
December 31, 1998.
NETHERLAND, SEWELL & ASSOCIATES, INC.
Houston, Texas
March 22, 1999
<PAGE> 1
EXHIBIT 23.3
CONSENT OF MILLER AND LENTS, LTD.
We hereby consent to the references to us under captions "Part I, Item
1 and 2. Business and Properties Natural Gas and Oil Reserves" in this Annual
Report on Form 10-K of The Houston Exploration Company for the year ended
December 31, 1998.
MILLER AND LENTS, LTD.
Houston, Texas
March 22, 1999
<PAGE> 1
EXHIBIT 23.4
CONSENT OF RYDER SCOTT COMPANY
We hereby consent to the references to us under captions "Part I, Item
1 and 2. Business and Properties Natural Gas and Oil Reserves" in this Annual
Report on Form 10-K of The Houston Exploration Company for the year ended
December 31, 1998.
RYDER SCOTT COMPANY
Houston, Texas
March 22, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
FINANCIAL STATEMENTS OF THE HOUSTON EXPLORATION COMPANY SET FORTH IN THE
COMPANY'S FORM 10-K FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1998 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-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 4,645
<SECURITIES> 0
<RECEIVABLES> 23,187
<ALLOWANCES> 0
<INVENTORY> 915
<CURRENT-ASSETS> 29,501
<PP&E> 982,949
<DEPRECIATION> 446,367
<TOTAL-ASSETS> 569,452
<CURRENT-LIABILITIES> 32,743
<BONDS> 313,000
0
0
<COMMON> 239
<OTHER-SE> 192,291
<TOTAL-LIABILITY-AND-EQUITY> 569,452
<SALES> 127,124
<TOTAL-REVENUES> 128,247
<CGS> 0
<TOTAL-COSTS> 237,090
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,597
<INCOME-PRETAX> (113,440)
<INCOME-TAX> (40,754)
<INCOME-CONTINUING> (72,686)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (72,686)
<EPS-PRIMARY> (3.05)
<EPS-DILUTED> (3.05)
</TABLE>
